1 EXECUTIVE SUMMARY ......................................................................................................................... i 1.1 1.2 1.3 1.4 1.5 1.6 1.7 1.8 1.9 1.10 1.11 1.12 1.13 1.14 1.15 2 The Purpose of the Plan ............................................................................................................. i Interaction with Corporate Objectives, Business Plans and Business Processes ..................... i Date Completed and Period to Which the Plan Relates............................................................ ii Stakeholder Interests ................................................................................................................. ii Asset Management Processes .................................................................................................. ii Assets Covered by the AMP ......................................................................................................iii Service Levels .......................................................................................................................... iv Risk Management ..................................................................................................................... iv The Impact of the Christchurch Earthquakes ........................................................................... vi Demand and Growth................................................................................................................. vi Development Plan ....................................................................................................................vii Maintenance and Renewals Plan ............................................................................................ viii Asset Management Improvement............................................................................................ viii Variance Analysis ..................................................................................................................... ix Financial Summary .................................................................................................................... x BACKGROUND AND OBJECTIVES ..................................................................................................... 1 2.1 2.2 Scope ......................................................................................................................................... 1 Purpose ..................................................................................................................................... 2 2.2.1 Role of Asset Management................................................................................................................................ 2 2.2.2 Role of Asset Management Plan ....................................................................................................................... 2 2.3 2.4 2.5 2.6 2.7 2.8 Period Covered .......................................................................................................................... 2 Asset Management Plan Linkages ............................................................................................ 2 Stakeholders .............................................................................................................................. 4 Accountabilities and Responsibilities......................................................................................... 5 Asset Management Drivers ....................................................................................................... 7 Asset Management Systems ..................................................................................................... 8 2.8.1 Integrated Management System ........................................................................................................................ 8 2.8.2 Asset Management Information Systems .......................................................................................................... 9 2.9 Asset Management Processes ................................................................................................ 11 2.9.1 System Gaps Identified .................................................................................................................................... 12 2.9.2 Funding Strategy.............................................................................................................................................. 13 3 ASSET DESCRIPTION ........................................................................................................................ 14 3.1 3.2 3.3 Introduction .............................................................................................................................. 14 MPNZ Network Summary ........................................................................................................ 14 North Canterbury Network (including Kaikoura) ...................................................................... 14 3.3.1 Distribution Area .............................................................................................................................................. 14 3.3.2 Load Characteristics ........................................................................................................................................ 17 3.3.3 Major Customers and Characteristics .............................................................................................................. 17 3.4 Wigram Network ...................................................................................................................... 18 3.4.1 Distribution Area .............................................................................................................................................. 18 3.4.2 Load Characteristics ........................................................................................................................................ 18 3.4.3 Major Customers and Characteristics .............................................................................................................. 18 3.5 Transpower Grid ...................................................................................................................... 18 3.5.1 Overview .......................................................................................................................................................... 18 3.5.2 Transpower 220 kV System ............................................................................................................................. 18 3.5.3 Transpower 66 kV System ............................................................................................................................... 19 3.5.4 Historical Development .................................................................................................................................... 19 3.5.5 Transpower Grid Exit Points ............................................................................................................................ 19 3.6 MPNZ Network Assets............................................................................................................. 21 3.6.1 Overview .......................................................................................................................................................... 21 3.6.2 Sub-transmission – 66 kV Overhead Lines, 33 kV Overhead Lines and Underground Cables ....................... 22 3.6.3 Zone Substations ............................................................................................................................................. 24 3.6.4 Zone Substation Transformers ........................................................................................................................ 24 3.6.5 Switchgear ....................................................................................................................................................... 27 3.6.6 Distribution – 22 kV and 11 kV Overhead Lines and Underground Cables ..................................................... 29 3.6.7 Distribution Kiosks and Substations................................................................................................................. 31 3.6.8 Distribution Transformers................................................................................................................................. 32 3.6.9 Local Reticulation – 400V Overhead Lines and Underground Cables ............................................................ 33 3.6.10 Ripple Injection Systems (Load Control).......................................................................................................... 34 3.6.11 Street Light Control .......................................................................................................................................... 35 3.6.12 SCADA ............................................................................................................................................................. 35 3.6.13 Communications .............................................................................................................................................. 35 3.6.14 Protection and Metering Systems .................................................................................................................... 36 3.6.15 Power Factor Correction Plant ......................................................................................................................... 36 3.6.16 Embedded / Distributed Generation................................................................................................................. 36 3.6.17 Mobile Substations and Generators................................................................................................................. 36 3.6.18 Property and Buildings ..................................................................................................................................... 37 3.7 Asset Justification .................................................................................................................... 37 3.7.1 Introduction ...................................................................................................................................................... 37 3.7.2 Historical Development .................................................................................................................................... 37 3.7.3 Supply Reliability and Quality .......................................................................................................................... 38 3.7.4 Capacity and ODV Network Optimisation ........................................................................................................ 38 4 SERVICE LEVELS ............................................................................................................................... 39 4.1 4.2 Introduction .............................................................................................................................. 39 Service Level Definition ........................................................................................................... 40 4.2.1 Reliability.......................................................................................................................................................... 40 4.2.2 Quality .............................................................................................................................................................. 40 4.2.3 Safety ............................................................................................................................................................... 40 4.2.4 Customer Service ............................................................................................................................................ 40 4.2.5 Environment ..................................................................................................................................................... 41 4.2.6 Economic Efficiency ......................................................................................................................................... 41 4.3 4.4 4.5 Service Level Measures .......................................................................................................... 41 Service Level Targets .............................................................................................................. 43 Justification for Target Levels of Service ................................................................................. 44 4.5.1 Strategic Outcomes ......................................................................................................................................... 44 4.5.2 External Environment....................................................................................................................................... 44 4.5.3 Customer Demand for Service......................................................................................................................... 45 4.5.4 Setting Reliability Targets ................................................................................................................................ 46 4.5.5 Setting Capacity Targets.................................................................................................................................. 47 4.5.6 Setting Power Quality Targets ......................................................................................................................... 48 4.5.7 Setting Safety Targets ..................................................................................................................................... 48 4.5.8 Setting Customer Service Targets ................................................................................................................... 49 4.5.9 Setting Environmental Targets......................................................................................................................... 49 4.5.10 Setting Economic Efficiency Targets ............................................................................................................... 50 5 RISK MANAGEMENT .......................................................................................................................... 51 5.1 5.2 Introduction .............................................................................................................................. 51 Risk Management Practice ...................................................................................................... 51 5.2.1 Introduction ...................................................................................................................................................... 51 5.2.2 Risk Management Practice, Processes and Methods ..................................................................................... 51 5.3 Exposure to Natural Disaster Risk........................................................................................... 51 5.3.1 Transpower GXP Stations ............................................................................................................................... 52 5.3.2 Sub-transmission and Distribution Systems .................................................................................................... 52 5.3.3 Zone Substations ............................................................................................................................................. 53 5.3.4 Kiosks and Building Substations ...................................................................................................................... 54 5.3.5 Cabling Systems .............................................................................................................................................. 55 5.3.6 Communications / Control Systems ................................................................................................................. 55 5.3.7 The Impact of the 4 September 2010 Greendale Earthquake ......................................................................... 55 5.4 5.5 Exposure to Physical Risk ....................................................................................................... 56 Exposure to Asset Failure Risk ............................................................................................... 57 5.5.1 Zone Substations ............................................................................................................................................. 57 5.5.2 33kV Sub-transmission System ....................................................................................................................... 59 5.5.3 Distribution System .......................................................................................................................................... 59 5.5.4 Main Towns ...................................................................................................................................................... 59 5.5.5 Communications / Control Systems ................................................................................................................. 60 5.5.6 Audit of Asset Failure Recovery Systems ........................................................................................................ 60 5.5.7 Transpower ...................................................................................................................................................... 61 5.5.8 Roading Authorities.......................................................................................................................................... 61 5.6 Risk Mitigation Measures......................................................................................................... 61 5.6.1 Introduction ...................................................................................................................................................... 61 5.6.2 Specific Development Projects to Mitigate Risk............................................................................................... 62 5.6.3 Specific Maintenance Programmes to Mitigate Risk........................................................................................ 62 5.6.4 ISO 14001 and 9001 Policies .......................................................................................................................... 62 5.6.5 Health and Safety ............................................................................................................................................ 63 5.6.6 Emergency Response Plans............................................................................................................................ 63 5.6.7 Network Contingency Plans ............................................................................................................................. 63 5.6.8 Business Continuity Plan ................................................................................................................................. 64 5.6.9 Insurance ......................................................................................................................................................... 64 6 DEMAND AND GROWTH .................................................................................................................... 65 6.1 6.2 Introduction .............................................................................................................................. 65 Factors Influencing Demand .................................................................................................... 65 6.2.1 Population ........................................................................................................................................................ 65 6.2.2 Land Use Changes .......................................................................................................................................... 66 6.2.3 Known Major Load Developments ................................................................................................................... 66 6.2.4 Historical Data.................................................................................................................................................. 67 6.1 Impacts of Non-Network Solutions (Demand Management) ................................................... 70 6.1.1 Ripple Injection systems .................................................................................................................................. 70 6.1.2 Time of Use Metering....................................................................................................................................... 70 6.1.3 Demand Side Management ............................................................................................................................. 70 6.2 6.3 Embedded / Distributed Generation ........................................................................................ 71 Forecasting Method ................................................................................................................. 71 6.3.1 Summary .......................................................................................................................................................... 71 6.3.2 Medium Growth Scenario ................................................................................................................................ 72 6.3.3 High Growth Scenario ...................................................................................................................................... 72 6.3.4 Low Growth Scenario....................................................................................................................................... 73 6.3.5 Accuracy .......................................................................................................................................................... 73 6.4 Load Forecasts ........................................................................................................................ 73 6.4.1 North Canterbury Load Forecast (including Kaikoura) .................................................................................... 73 6.4.2 GXP Load Forecast ......................................................................................................................................... 73 6.4.3 Sub-transmission Load Forecast ..................................................................................................................... 77 6.4.4 Zone Substation Load Forecast ....................................................................................................................... 77 6.4.5 Wigram Network Load Forecast ...................................................................................................................... 78 6.5 Network Constraint Identification and Analysis ....................................................................... 78 6.5.1 GXP Constraints .............................................................................................................................................. 78 6.5.2 Sub-transmission Constraints .......................................................................................................................... 78 6.5.3 Zone Substation Constraints............................................................................................................................ 78 7 NETWORK DEVELOPMENT PLAN .................................................................................................... 80 7.1 7.2 7.3 7.4 7.5 7.6 7.7 7.8 Introduction .............................................................................................................................. 80 Planning Criteria and Assumptions ......................................................................................... 80 Network Development Practice ............................................................................................... 80 Reliability and Security ............................................................................................................ 80 Lost Customer Minutes Fund .................................................................................................. 82 Voltage Regulation .................................................................................................................. 83 Fault Levels ............................................................................................................................. 83 System Modelling .................................................................................................................... 84 7.8.1 Investment Modelling ....................................................................................................................................... 84 7.8.2 Power Flow Modelling ...................................................................................................................................... 84 7.9 7.10 Network Voltage Optimisation ................................................................................................. 84 Capacity Determination ........................................................................................................... 84 7.10.1 Conductors and Cables ................................................................................................................................... 84 7.10.2 Transformers .................................................................................................................................................... 85 7.10.3 Overload Ratings ............................................................................................................................................. 85 7.11 7.12 Process and Criteria for Prioritising Network Development .................................................... 85 Non Network Solution Development Plan (Demand Management) ........................................ 86 7.12.1 Policies ............................................................................................................................................................. 86 7.12.2 Planned MPNZ Developments......................................................................................................................... 86 7.12.3 Other Developments ........................................................................................................................................ 87 7.13 Embedded / Distributed Generation Development Plan.......................................................... 87 7.13.1 Introduction ...................................................................................................................................................... 87 7.13.2 Policies for Connection .................................................................................................................................... 87 7.13.3 Planned MPNZ Developments......................................................................................................................... 88 7.13.4 Other Developments ........................................................................................................................................ 88 7.13.5 Impact on Development Plan ........................................................................................................................... 89 7.14 Network Development Plan ..................................................................................................... 89 7.14.1 Transpower Transmission................................................................................................................................ 89 7.14.2 GXP Station Development ............................................................................................................................... 90 7.14.3 MPNZ Sub-transmission and Zone Substation Development.......................................................................... 93 7.14.4 Distribution Development ................................................................................................................................. 99 7.15 8 Total Capital Expenditure 2012-2021 .................................................................................... 105 MAINTENANCE AND RENEWALS PLAN ........................................................................................ 107 8.1 8.2 Introduction ............................................................................................................................ 107 Planning Criteria and Assumptions ....................................................................................... 107 8.2.1 Maintenance Practice .................................................................................................................................... 107 8.2.2 Maintenance and Renewal Policies and Programmes .................................................................................. 109 8.3 Sub transmission, Distribution and LV Overhead Lines ........................................................ 111 8.3.1 Poles .............................................................................................................................................................. 111 8.3.2 Conductors ..................................................................................................................................................... 112 8.3.3 Cross Arms .................................................................................................................................................... 113 8.3.4 Line Hardware ................................................................................................................................................ 114 8.3.5 Overhead Lines Inspection, Maintenance and Renewal Programmes .......................................................... 114 8.3.6 Lines Forecast Expenditure ........................................................................................................................... 115 8.4 Sub-transmission, Distribution and Low Voltage Underground Cables ................................ 115 8.4.1 Underground Cables Inspection, Maintenance and Renewal Programmes .................................................. 115 8.5 Zone Substations ................................................................................................................... 116 8.5.1 Zone Substation Transformers ...................................................................................................................... 116 8.5.2 Substation Compounds.................................................................................................................................. 117 8.5.3 Batteries ......................................................................................................................................................... 117 8.5.4 Protection Relays ........................................................................................................................................... 117 8.5.5 Zone Substations Inspection, Maintenance and Renewal Programmes ....................................................... 117 8.6 Switchgear ............................................................................................................................. 119 8.6.1 Circuit Breakers, Reclosers, and Sectionalisers ............................................................................................ 119 8.6.2 Ring Main Units.............................................................................................................................................. 119 8.6.3 Air Break Switches ......................................................................................................................................... 120 8.6.4 Switchgear Inspection, Maintenance and Renewals Programmes ................................................................ 120 8.7 Distribution Substations and Transformers ........................................................................... 121 8.7.1 Distribution Kiosks and Substations............................................................................................................... 121 8.7.2 Distribution Transformers............................................................................................................................... 121 8.7.3 Distribution Substations and Transformers Inspection, Maintenance and Renewal Programmes ................ 121 8.8 Other ...................................................................................................................................... 122 8.8.1 Vegetation ...................................................................................................................................................... 122 8.8.2 Ripple Injection Systems (Load Control)........................................................................................................ 122 8.8.3 Communications ............................................................................................................................................ 122 8.8.4 Other Asset Inspection, Maintenance and Renewal Programmes ................................................................ 123 8.8.5 Life Cycle Maintenance Expenditure ............................................................................................................. 123 8.9 9 Total Operational Maintenance Expenditure ......................................................................... 125 PERFORMANCE EVALUATION ....................................................................................................... 126 9.1 9.2 9.3 9.4 9.5 9.6 Financial Performance Variance Analysis ............................................................................. 126 Capital expenditure ................................................................................................................ 126 Operational expenditure ........................................................................................................ 126 Historical Expenditure ............................................................................................................ 126 Service Level Performance.................................................................................................... 127 Reliability Performance Variance Analysis ............................................................................ 127 9.6.1 Capacity Performance Variance Analysis ...................................................................................................... 129 9.6.2 Quality Performance Variance Analysis......................................................................................................... 130 9.6.3 Safety Performance Variance Analysis.......................................................................................................... 131 9.6.4 Customer Service Performance Variance Analysis ....................................................................................... 131 9.6.5 Environmental Performance Variance Analysis ............................................................................................. 133 9.6.6 Economic Efficiency Performance Variance Analysis.................................................................................... 133 9.7 10 Asset Management Practice Improvement............................................................................ 135 APPENDICES .................................................................................................................................... 136 10.1 10.2 10.3 10.4 10.5 10.6 10.7 Glossary of Terms ................................................................................................................. 136 Cross Reference Table .......................................................................................................... 137 Information Disclosure Requirement 7(2) .............................................................................. 138 Operational Objectives 2012-13 ............................................................................................ 141 Load Control Time, Price and Load Shifting Channels ......................................................... 142 Asset Management Practice Improvement Log .................................................................... 143 Photographs of Key Assets ................................................................................................... 146 1
EXECUTIVE SUMMARY
1.1
The Purpose of the Plan
The primary purpose of the asset management process at MainPower New Zealand Limited (“MPNZ”)
is to: “deliver the required level of service to customers in an economically efficient manner that meets
the expectations of stakeholders”. This Asset Management Plan (“AMP”) forms an integral part of the
asset management processes at MPNZ. The primary purpose is to systematically document the asset
management programmes established by MPNZ to ensure the levels of service meet customer
expectations consistent with MPNZ’s Vision and Corporate Organisational Goals and Objectives.
A secondary purpose is to achieve compliance with regulatory disclosure requirements.
1.2
Interaction with Corporate Objectives, Business Plans and Business Processes
The overall direction of MPNZ is guided by its Vision and Corporate Organisational Goals and
Objectives. These are implemented by the specific plans and targets contained in the Statement of
Corporate Intent (SCI) which are embodied in the AMP and operationalised in the annual Business
Plan and Budget as illustrated below.
Corporate Vision
Organisational
Objectives and
Goals
Statement of
Corporate Intent
Stakeholder
Drivers
Strategy
Code of
Sustainable
Practice
Targets
Asset
Management Plan
Annual Business
Plan and Budget
Figure 1 Asset Management Plan Linkages
MPNZ is owned by the MainPower Trust on behalf of electricity customers as defined in the
MainPower Trust Deed.
The business direction of MPNZ is guided by its Vision and Values:
“MainPower will be recognised by its community as a leading regional electricity distribution
and electricity supply company”
Our Values are: Safety First, Teamwork, Loyalty, Pride, Fairness and Integrity.
i
The Corporate Organisational Objectives consistent with the Vision are:

“MainPower will carry out its business activities in accordance with commercial and
industry best practice and will give particular emphasis to safety, superior customers
service, sustainability, and value creation”;

“MainPower will continue to operate and make available to its customers, a safe, secure
and reliable electricity distribution network”;

“MainPower will ensure, through the management and operation of its electricity
distribution network, technical support and field services contracting capability, a level of
security and reliability of electrical supply that places MainPower in the upper quartile
when compared to other regional line companies in New Zealand”;

“MainPower will be recognised within the electricity industry for the implementation of
Smart Grid Technologies”.
The Statement of Corporate Intent (“SCI”) is approved by the MainPower Trust and is a statement of
MPNZ’s overall intentions and objectives agreed between the Board and the Trustees for MPNZ for
the financial year commencing 1 April 2012 and the two succeeding financial years. The SCI is used
to establish MPNZ’s corporate strategy with regard to governance, asset management, the operating
environment, major projects and reviews, and financial performance. The SCI contains objectives on
providing network capacity, safety, reliability and pricing, and includes targets for the first three years
of the AMP planning period. Thus the SCI provides a strategic framework for the AMP.
The AMP is therefore the tool by which MPNZ meets its corporate objectives, specifically in the areas
of network availability, capacity, security and meeting regional growth and associated demand for
electricity.
In addition to the SCI, an Annual Business Plan and Budget is prepared based on the capital
expenditure projects and the network operations and maintenance activities outlined in the AMP. The
AMP and SCI are also consistent with MPNZ’s Code of Sustainable Practice.
1.3
Date Completed and Period to Which the Plan Relates
The AMP documents the likely development, maintenance and replacement requirements of the
network assets over the next ten years, from 1 April 2012 to 31 March 2022, with a focus on specific
projects that have been identified in the next five years.
The plan was completed for asset management purposes in March 2012 and has been approved by
the Board of Directors at the 3rd April meeting of the Board.
1.4
Stakeholder Interests
The main drivers of the Corporate Vision, Strategic Objectives, SCI and ultimately the AMP are the
interests of the key stakeholders, expressly the MainPower Trust, Electricity Consumers and Retailers.
The interests of additional stakeholders such as contractors, government, insurers, landowners,
employees, property developers, territorial local authorities, Transit NZ and Transpower are also
considered in developing the AMP.
1.5
Asset Management Processes
Asset management information systems have been developed at MPNZ to support all asset
management processes, with asset management based around a continuous improvement cycle as
depicted in Figure 2 overleaf.
ii
Establish business needs
& Define levels of service
Forecast Demand
Existing Asset information
Requirements Analysis
Maintenance Plan
Systems/Support Analysis
Replacement Plan
Development Plan
Financial Forecasts
Performance Monitoring
Figure 2 Asset Management Systems
1.6
Assets Covered by the AMP
MPNZ owns and operates electricity networks in North Canterbury (including Kaikoura) and Wigram
located in Christchurch. The North Canterbury network covers areas immediately south of the
Waimakariri River through to Rakautara north of Kaikoura and west to the Lewis pass, Lees Valley
and the Waimakariri Gorge. The North Canterbury network is connected to two Transpower 66kV lines
at Southbrook supplied from Transpower’s Islington substation, and two 220kV connections at each of
Waipara and Culverden These lines supply six Grid Exit Point (“GXP”) stations at Southbrook,
Kaiapoi, Ashley, Waipara, Culverden and Kaikoura. MPNZ distributes electricity from these stations
through a 66kV and 33kV overhead sub-transmission network, a number of zone substations, a
complex 22kV and 11kV distribution system, and distribution transformers; supplying customers from
a low voltage network. The small Wigram network is an underground network operated at 11kV,
taking supply from the Orion New Zealand network and supplying customers at low voltage.
The following table summarises the asset types, quantities and values for the entire MPNZ network.
Asset Category
Sub-transmission Lines and Cables
Sub-transmission Switchgear
Zone Substations
Distribution Lines 22kV
Distribution Cables 22kV
Distribution Lines 11kV
Distribution Cables 11kV
MV Switchgear
Distribution Transformers
Distribution Substations
LV Reticulation
Customer Service Connections
Other System Fixed Assets
Total
Unit
km
Number
Number
km
km
km
km
Number
Number
Number
km
Number
Quantity
283
22
18
578
23
2741
212
8548
7481
7501
1088
34422
ODRC ($Million)
12.067
0.024
21.230
11.460
3.305
40.347
23.424
7.666
25.206
14.159
33.287
5.072
7.928
205.176
Table 1 Summary of Assets for the Year Ended 31 March 2011
iii
1.7
Service Levels
A key objective of asset management planning is to match the level of service provided by the assets
to the expectations of customers and other stakeholders. This is consistent with MPNZ’s Vision and
Corporate Organisational Objectives and Goals. Target levels of service for the planning period are
set following consideration of the overall vision and corporate objectives, and following consultation
with customers and other stakeholders. For the purpose of the AMP, the key service criteria are:

Reliability of supply

Capacity of the network

Quality of supply

Safety

Customer service

Environmental protection

Economic efficiency.
Service targets are used in the following ways:

to inform customers of the proposed service standards,

to develop asset management strategies appropriate to that level of service,

as benchmarks against which performance will be measured,

to identify the costs and benefits of the service options assessed and offered, and

to enable customers to assess the suitability, affordability and equity of the services offered.
The setting of level of service targets reflects MPNZ’s commitment to continual improvement. The
levels of service will increasingly reflect changing customer expectations as further information on
customers’ and other stakeholders’ preferences and regulatory requirements are used to identify
targets. Table 2 overleaf shows the service level forecast for the period 1 April 2012 – 31 March 2022.
1.8
Risk Management
The objectives of risk management include:

ensuring MPNZ is able to meet its service level targets

safeguarding public and employee safety

protection and continuity of electricity supply

fulfilment of legal obligations

efficient protection and operation of assets

protection of shareholder and commercial interests

preparation of contingency plans for foreseeable emergencies.
MPNZ first conducted a study of its exposure to major risks in 1997. The study focused on natural
hazards, asset failure and compliance with the Resource Management Act. In 2005 a second,
external study considered network risk assessment and network asset failure recovery. These studies
have enabled MPNZ to put in place effective risk mitigation procedures and policies consistent with
the objectives outlined above.
iv
Strategic Outcome Measures
SAIDI
SAIFI
CAIDI
Faults/100km total
Reliability
Faults/100km 66kV
Faults/100km 33kV
Faults/100km 22kV
Faults/100km 11kV
Faults/100km SWER
Total Interruptions
Quality
Number of proven voltage complaints
Number of public injuries on MPNZ facilities
Safety
Number of OSH notifiable accidents
Number of employee injuries
Average rating from customer survey
Customer
Deliverables
Service

Overall Satisfaction

Number of excessive noise complaints
Number of environmental complaints from
staff or public
Percent of SF6 gas lost
Environmental
Number of uncontained oil spills
Number of breaches of resource consents
Load Factor
Capacity Utilisation Factor
Loss Ratio
Economic
Capital cost per km
Efficiency
Capital cost per ICP
Operating cost per km
Operating cost per ICP
2012-13
2013-14
2014-15
2015-16
2016-17
2017-18
2018-19
2019-20
2020-21
2021-22
125
1.6
85
4.67
1.49
2.48
4.95
4.95
2.00
600
<20
0
0
0
124
1.59
85
4.62
1.47
2.45
4.90
4.90
2.00
600
<20
0
0
0
124
1.58
85
4.57
1.46
2.43
4.85
4.85
2.00
600
<20
0
0
0
123
1.58
85
4.53
1.44
2.40
4.80
4.80
2.00
600
<20
0
0
0
123
1.57
85
4.48
1.43
2.38
4.75
4.75
2.00
600
<20
0
0
0
122
1.56
85
4.44
1.41
2.35
4.71
4.71
2.00
600
<20
0
0
0
121
1.55
85
4.40
1.40
2.33
4.66
4.66
2.00
600
<20
0
0
0
121
1.54
85
4.35
1.38
2.31
4.61
4.61
2.00
600
<20
0
0
0
120
1.54
85
4.31
1.37
2.28
4.57
4.57
2.00
600
<20
0
0
0
119
1.53
85
4.27
1.36
2.26
4.52
4.52
2.00
600
<20
0
0
0
8.0
4.2
0
8.0
4.2
8.0
4.2
8.0
4.2
8.0
4.2
8.0
4.2
8.0
4.2
8.0
4.2
8.0
4.2
8.0
4.2
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
<1 %
0
0
71.1%
21.5%
5.6%
$2,933
$384
$2,340
$306
<1 %
0
0
71.1%
21.3%
5.6%
$3,485
$451
$2,348
$304
<1 %
0
0
71.1%
21.1%
5.6%
$2,891
$370
$2,345
$300
<1 %
0
0
71.1%
20.9%
5.6%
$2,341
$298
$2,375
$302
<1 %
0
0
71.1%
20.7%
5.6%
$2,193
$277
$2,378
$300
<1 %
0
0
71.1%
20.5%
5.6%
$2,027
$254
$2,364
$297
<1 %
0
0
71.1%
20.4%
5.6%
$2,227
$278
$2,359
$294
<1 %
0
0
71.1%
20.3%
5.6%
$2,158
$268
$2,354
$292
<1 %
0
0
71.1%
20.2%
5.6%
$2,218
$274
$2,349
$290
<1 %
0
0
71.1%
20.1%
5.6%
$2,149
$264
$2,344
$287
Table 2 Service Level Forecast 2012 to 2021
v
1.9
The Impact of the Christchurch Earthquakes
Earthquake Facts

At its peak 7964 Kaiapoi customers off, 1,050 Hawarden and 892 at Woodend.

18 known HV cable faults.

Cable faults due to shear forces and stretching – damage often over several meters around the
ground rip.

One case of a cable termination pulling 500mm clear of its switchgear.

Several cases of cables pulling tight against their terminations.

Traditional cable fault finding and repair soon proved to be fruitless.

3.5km of 11kV cable replaced.

Two ground substations require rebuilding.

One switchgear replaced.

Minimal LV cable damage – possible issues later.

1,100 homes red zoned for future demolition and a redesign of the network around the red zones will
be required.

Overhead line network stood up well and faster to repair.

Initial faults due to conductor clashes.

Some poles leaning severely – two transformer poles tipping over at Kairaki.

A number of heavy concrete poles and transformer substation poles sunk.

Approx one month of work to rectify.
Lessons Learned

To make contact with families of all staff following a major event (earthquake, snow storm etc),

Provision of a phone number for use only by Staff families.

Closer monitoring of staff field locations.

Provision of water reserves for Staff.

Daily meeting of all staff to discuss outage area, customers affected, Network priorities for restoration,
priorities for the day, hazards that may be encountered, Supervisors to allocate resources to each
area, discuss any family issues, monitoring of work hours and fatigue, and monitoring stock levels.
1.10 Demand and Growth
The AMP forecasts likely demand at each GXP, zone substation and sub-transmission circuit over the
next 10 years as a basis for planning future investment needs. These forecasts reflect consideration of
historical growth trends, forecast economic activity and population growth, non network solutions such as
demand management and potential embedded generation developments.
This information, combined with target levels of service and asset life cycle planning, is used to determine
the development plan. The AMP recognises that there is more certainty with short term projections, up to
five years, and that significant individual load developments are difficult to predict and as a result, in some
cases, they must be accommodated as they occur.
The major growth in the region continues to come from new irrigation demand and dairy farm conversions
in the Culverden and Rangiora west areas. The Waimakariri District Council is predicting rapid growth in
the vicinity of Rangiora and Woodend as a result of the Christchurch earthquakes, and also a large
redistribution of the load in Kaiapoi from earthquake affected areas to new subdivisions in the north and
vi
west. The load will shrink with “Red Zoning” in the Kaiapoi east and beach areas. Some rural residential
developments in the neighbouring areas are also being fast tracked. MPNZ expects residential growth at
Wigram to be static with some commercial load increase due to the Museum expansion.
North Canterbury Forecast Load
160
140
120
Peak Load (MW)
Actual
100
Forecast
80
Summer
Winter
USI Coincident
60
40
20
0
2006
2008
2010
2012
2014
2016
2018
2020
2022
Figure 3 North Canterbury Forecast Load
The current trend of high levels of growth is predicted to continue throughout the forecast period as
illustrated above. This will continue to require new assets to be developed well before they are due for
renewal or refurbishment. Accordingly MPNZ expects that demand growth and capacity upgrades will
continue to drive the lifecycle management plan with the core focus being development projects.
1.11 Development Plan
Network development planning is undertaken to identify asset enhancement and development
programmes required to meet target levels of service, and is based on analysis of maximum demands,
network power flows, specific customer requests and demographic estimates. Sub-transmission planning
emphasises long range objectives associated with system expansion and increases in zone substation
and GXP capacity to meet projected demand. It also takes into account key issues associated with
reliability and security of supply. Distribution planning emphasises short run objectives associated with
new customer connections, power quality improvement (such as voltage regulation and power factor
correction), loss reduction and operating improvements.
The key components of the development plan are:

Transpower upgrade of the Kaiapoi GXP switchboard in 2012-2013 to provide additional higher rated
feeders.

Transpower upgrade of the Ashley GXP in 2013-14 to provide additional capacity to for Rangiora,
Loburn, and Ashley areas.

Development of a high level response from Transpower on the provision of additional 66kV feeders
out of Southbrook.

Construction of a new GXP at Rangiora East in 2015-16 depending on growth uptake at the Pegasus
and Ravenswood developments.

Completion of the 66kV upgrade of the Waipara-Kaikoura sub-transmission circuit by 2013.

The upgrade of the 33kV sub-transmission to 66kV in the Swannanoa, Cust, Oxford and Bennetts
areas over the period 2012-2014 to meet projected demand. The associated substation construction.
vii

Distribution development is driven by the need for additional capacity and security across the region
and includes network reinforcement in a number of areas. Significant projects include the completion
of a new switching station at Kaiapoi North during 2011-12, creation of two new Kaiapoi GXP feeders
in 2012 and 2013, a new Oaro 22kV line in the Kaikoura area by 2013, the construction of an 11kV
link between John Street substation and the Rangiora West switching station in 2012-13. The further
rebalancing of load between Oxford, Bennetts, Swannanoa and Cust zone substations during 201214 including further 22kV conversion in this area.

Conversion of overhead lines to underground reticulation throughout the region where high social
dividends are achieved.

Distribution automation investment throughout the planning period to ensure network reliability targets
are met.

Investments required to meet the demand for new connections throughout the planning period.
A summary of the development plan forecast expenditure is included at the end of this Executive
Summary.
1.12 Maintenance and Renewals Plan
Maintenance and renewal planning seeks to achieve the desired levels of service required by customers,
while optimising the costs over the asset lifecycle. The main drivers of the maintenance and renewal plan
are the results of asset condition surveys, condition based maintenance assessments, asset renewal
programmes, asset obsolescence, safety considerations and regulatory compliance. In addition network
development in response to growth helps to replace old technology by replacing assets that are not
intelligent enough or assets that have their ratings exceeded. Over time there has been a significant
contribution to the renewal of the system from the alterations needed to accommodate additional
customer requirements or to meet changing customer needs.
The Maintenance and Renewal Plan involves the following activities:

Reactive maintenance or repair on breakdown

Time based preventative maintenance

Condition based maintenance

Reliability based maintenance.
MPNZ maintains excellent data about the quantity, condition and performance of its assets. This has
been compiled from historical construction records, asset inspections, testing and field work. Asset
failures and recurring fault causes are investigated and measures to eliminate or mitigate the problems
are built into the maintenance plan. This information and the associated inspection and testing processes
provide the basis for the maintenance and renewals plan.
A summary of the maintenance and renewals plan forecast expenditure is included at the end of this
Executive Summary.
1.13 Asset Management Improvement
MPNZ’s asset management practices will follow a continuous improvement cycle in order to strive to
achieve best practice, consistent with our corporate vision. Previous AMPs have been independently
reviewed and a number of the recommendations have been incorporated into this current plan. The
following major initiatives have been identified for improvement in the current plan:

Implement a performance planning module in TechnologyOne to improve customer pricing and work
management.

Upgrade of SCADA system
viii
1.14 Variance Analysis
The table below illustrates the actual asset management expenditure compared to the planned
expenditure for the twelve month period ending 31 March 2011. The September and February
earthquakes had a major impact on expenditure and reliability. Actual customer connections reduced
significantly due to uncertainty over land and insurance. Fault and Emergency Maintenance,
Refurbishment and Renewal Maintenance, and Reliability, Safety and Environmental work all increased
due to earthquake repairs and replacements.
Budget
Actual
Year Ending
31 March 2011
($Million)
Year Ending
31 March 2011
($Million)
Variance (%)
Capital Expenditure
Customer Connections
4.379
2.622
-40.1%
System Growth
3.211
3.269
1.8%
Reliability, Safety and Environment
1.026
1.531
49.2%
Asset Replacement and Renewal
3.020
3.098
2.6%
Asset Relocations
0.000
0.159
Subtotal - Capital Expenditure on Asset Management
11636
10.679
-8.2%
Routine and Preventative Maintenance
2.400
2.323
-3.2%
Refurbishment and Renewal Maintenance
0.053
0.071
34.0%
Fault and Emergency Maintenance
0.746
1.070
43.4%
Subtotal - Operational Expenditure on Asset Management
3.199
3.464
8.3%
14.835
14.143
-4.7%
0.610
0.725
18.8%
Operational Expenditure
Total Direct Expenditure on Distribution Network
Overhead to Underground Conversion Expenditure
Table 3 Variance between Actual 2010 Expenditure and Budget
In addition, key service targets and the regulatory thresholds set by the Commerce Commission for
reliability service levels were not met. This represents a very large one off event.
Index
SAIDI (minutes/customer)
2011 Target
97.00
Commerce Commission Threshold
(5 year average
for base period 1999 - 2003)
147.24
2011 Actual
337.8
SAIFI (interruptions/customer)
1.07
1.71
2.90
CAIDI (minutes/interruption)
90.65
n/a
116.51
Table 4 SAIDI, SAIFI and CAIDI Performance
ix
1.15 Financial Summary
The asset management expenditure forecast for the period 1 April 2012 through to 31 March 2022 is shown below in Table 5 by key expenditure category, in real
terms.
Ten yearly Forecasts of Expenditure ($Million)
Capital Expenditure
Customer Connections
System Growth
Reliability, Safety and Environment
Asset Replacement and Renewal
Asset Relocations
Total ‐ Capital Expenditure on Asset Management
2012‐2013 2013‐2014 2014‐2015 2015‐2016 2016‐2017 2017‐2018 2018‐2019 2019‐2020 2020‐2021 2021‐2022
6.57
7.28
3.22
0.88
0.00
17.94
6.40
9.75
2.71
1.65
0.00
20.51
6.40
7.95
2.76
0.70
0.00
17.81
6.01
4.52
3.32
0.95
0.00
14.80
5.75
4.07
3.22
1.10
0.00
14.14
5.28
3.34
3.22
1.05
0.00
12.89
5.03
4.84
3.22
0.75
0.00
13.84
5.03
4.54
3.22
0.75
0.00
13.54
5.03
4.84
3.22
0.75
0.00
13.84
5.03
4.54
3.22
0.75
0.00
13.54
2.05
0.06
0.68
2.79
3.12
0.17
0.68
3.97
3.13
0.17
0.68
3.98
3.29
0.17
0.68
4.15
3.33
0.17
0.68
4.18
3.34
0.17
0.68
4.19
3.34
0.17
0.68
4.19
3.34
0.17
0.68
4.19
3.34
0.17
0.68
4.19
3.34
0.17
0.68
4.19
20.73
24.48
21.79
18.95
18.32
17.08
18.03
17.73
18.03
17.73
0.25
0.40
0.40
0.60
0.45
0.45
0.45
0.45
0.45
0.45
Operational Expenditure
Routine and Preventative Maintenance
Refurbishment and Renewal Maintenance
Fault and Emergency Maintenance
Total ‐ Operational Expenditure
Underground Conversion
Table 5 Capital and Operational Expenditure Forecast 2012-2022
x
2
BACKGROUND AND OBJECTIVES
2.1
Scope
This AMP covers all MPNZ distribution assets and associated systems which transport power delivered at
Transpower points of supply to customers within the service area shown on the location map below. The
AMP also covers MPNZ’s assets located in the Christchurch Wigram area.
Figure 4 MPNZ Supply Area
In addition to MPNZ distribution network assets, this AMP also considers Transpower’s transmission
system and development programme where it impacts on service level objectives.
The AMP documents the likely development, maintenance and replacement requirements of the network
assets over the next ten years, from 1 April 2012 to 31 March 2022.
Developments identified in the latter half of the planning period should be considered indicative only, and
are likely to be subject to changing market conditions and trends in customer demand. This AMP is not,
in itself, an approved programme for specific work but summarises the general programmes and specific
projects that MPNZ believes will be required. Although it is a valid indication of requirements based on
current knowledge, actual projects and programmes will inevitably differ from this plan, particularly where
they are driven by specific customer requirements. This AMP does not represent an authorisation by
MPNZ to commit expenditure, nor does it represent a commitment to proceed with any of the specific
projects or programmes. Authorisation will result from approval of the annual budget by the Board and
from specific project approvals. MPNZ’s approach to capital budgeting is set out in Section 7.
A summary of the assets included in this AMP and their associated regulatory asset value (using the
Commerce Commission’s Indexed ODV Roll Forward Valuation Methodology) is shown below as at
31 March 2011.
1
Asset Category
Sub-transmission Lines and Cables
Sub-transmission Switchgear
Zone Substations
Distribution Lines 22kV
Distribution Cables 22kV
Distribution Lines 11kV
Distribution Cables 11kV
MV Switchgear
Distribution Transformers
Distribution Substations
LV Reticulation
Customer Service Connections
Other System Fixed Assets
Total
Unit
km
Number
Number
km
km
km
km
Number
Number
Number
km
Number
Quantity
283
22
18
578
23
2741
212
8548
7481
7501
1088
34422
ODRC ($Million)
12.067
0.024
21.230
11.460
3.305
40.347
23.424
7.666
25.206
14.159
33.287
5.072
7.928
205.176
Table 6 Summary of Assets
2.2
Purpose
2.2.1 Role of Asset Management
The primary purpose of the asset management process at MPNZ is to: deliver the required level of
service to customers in an economically efficient manner that meets the expectations of stakeholders.
2.2.2 Role of Asset Management Plan
This AMP forms an integral part of the asset management processes of MPNZ, and the primary purpose
is to systematically document the asset management programmes established by MPNZ to ensure levels
of service meet customer expectations, consistent with MPNZ’s Vision and Corporate Organisational
Goals and Objectives. A secondary purpose of the AMP is to achieve compliance with regulatory
disclosure requirements.
The AMP is based on present understanding of customer requirements and of existing asset conditions
and clearly establishes an improvement plan for progressive development of best practice asset
management.
Requirement 7 of the Electricity Distribution (Information Disclosure) Requirements, 2008 (“the
Requirements”) states that line owners must disclose an AMP in relation to their works. Chapter 4 of the
Commerce Commission’s Information Disclosure Handbook provides guidance on the information to be
disclosed. In some instances the section titles and the location of information in this AMP differ from
Chapter 4 of the Handbook for editorial reasons. A cross reference table included in the appendices to
the AMP reconciles the content of this AMP and the mandatory disclosure requirements.
2.3
Period Covered
The AMP documents the likely development, maintenance and replacement requirements of the network
asset over the next ten years, from 1 April 2012 to 31 March 2022, with a focus on specific projects that
have been identified in the next five years. The plan was completed for asset management purposes in
December 2011 and has been approved by the Board of Directors at the February 2012 meeting of the
Board.
2.4
Asset Management Plan Linkages
The overall direction of MPNZ is guided by its Vision and Corporate Organisational Goals and Objectives.
These are implemented by the specific plans and targets contained in the Statement of Corporate Intent
which are embodied in the AMP and operationalised in the annual Business Plan and Budget as
illustrated below.
2
Corporate Vision
Organisational
Objectives and
Goals
Statement of
Corporate Intent
Strategy
Code of
Sustainable
Practice
Stakeholder
Drivers
Targets
Asset
Management Plan
Annual Business
Plan and Budget
Figure 5 Asset Management Plan Linkages
MPNZ is owned by the MainPower Trust on behalf of electricity customers as defined in the MainPower
Trust Deed. The business direction of MPNZ is guided by its Vision set out below:
“MainPower will be recognised by its community as a leading regional electricity distribution
and electricity supply company”
Our Values are: Safety First, Teamwork, Loyalty, Pride, Fairness and Integrity.
The MainPower Trust also requires MPNZ to act as a responsible corporate citizen.
The Corporate Organisational Goals and Objectives consistent with the Vision are:

MPNZ will continue to own and make available to its customers a safe, secure and reliable
electricity distribution network and will make this network available to all electricity retailers
for the conveyance of electricity;

MPNZ will establish, operate and own renewable electricity generation in order for the region
to become 75% self sufficient in meeting the energy needs of the region, and will establish
and operate a successful electricity retailing business.
The Statement of Corporate Intent (“SCI”) is approved by the MainPower Trust and is a statement of
MPNZ’s overall intentions and objectives agreed between the Board and the Trustees for MPNZ for the
financial year commencing 1 April 2012 and the two succeeding financial years. It contains the Vision
and Corporate Goals and Objectives as well as a summary of the environment that MPNZ will be
operating in and the nature and scope of its activities and values. This is used to establish MPNZ’s
corporate strategy with regards to governance, asset management, the operating environment, major
projects and reviews and financial performance. The SCI contains objectives on providing network
capacity, safety, reliability and pricing and includes targets for the first three years of the AMP planning
period (consistent with those contained in Section 4 of this AMP). Thus the SCI provides a strategic
framework for the AMP.
3
The SCI also includes operational policies and objectives in relation to Governance, Risk Management,
Health and Safety Management, Human Resource Management, Quality Management, Environmental
Management and Social Responsibility. MPNZ’s operational objectives for 2011 are included as
Appendix 10.4 to this AMP.
The AMP is therefore the tool by which MPNZ meets its corporate objectives, specifically in the areas of
network availability, capacity, security and meeting regional growth and associated demand for electricity.
The AMP is developed after consideration of the Vision and Objectives outlined above, and the specific
targets contained in the SCI. The remainder of this document sets out MPNZ’s plans consistent with
these objectives and targets where they are relevant for asset management.
In addition to the SCI, an Annual Business Plan and Budget is prepared based on the capital
expenditure projects and the network operations and maintenance activities outlined in the AMP. The
Business Plan’s key outflows are an annual financial work budget and detailed work plan consistent with
the strategic and operational objectives of MPNZ from the SCI and AMP.
MPNZ has developed a Code of Sustainable Practice that drives sustainability practices into three key
strategic areas; economic strategy, environmental strategy and social strategy. The SCI and the AMP
reflect plans and objectives which are consistent with these strategies for example the environmental
service performance targets and economic efficiency targets set out in Section 4 of the Plan.
Finally, MPNZ has initiated annual Strategic Reviews to consider company performance against targets
and performance of other electricity lines businesses in New Zealand. MPNZ has established a range of
key performance measures following an independent review of best practice asset management across
New Zealand and international companies and systems. The key performance measures identified for
use at MPNZ are detailed in the service level section, and cover system reliability, quality, customer
complaints, financial performance, delivery of the annual business plan and safety measures. The results
of the reviews are fed back and factored in when setting targets each year. The results are also
conveyed to stakeholders via the company’s annual report or annual sustainability report.
2.5
Stakeholders
The main drivers of the Corporate Vision, Objectives and Goals, SCI and ultimately the AMP are the
interests of the key stakeholders, expressly the MainPower Trust, Electricity Consumers and Retailers.
Feedback from all stakeholders through surveys, direct communication and the complaints process is
used to establish objectives, plans and specifically target levels of service. MPNZ also enters into
contracts with end use customers that determine level of service drivers for this AMP. The MainPower
Trust agrees MPNZ’s overall intentions and objectives with the MPNZ Board of Directors and agrees on
performance targets and other measures in relation to its objectives through the SCI process.
The AMP recognises the following stakeholders with interests in MPNZ’s asset management:
Stakeholder
Contractors
Electricity Customers and Retailers
Government (Ministry of Economic
Development, Commerce
Commission, Electricity Commission)
Insurers
Landowners
MPNZ Employees
Property Developers
Shareholders
Territorial Local Authorities
Transit NZ
Transpower
Interests
Contractors have an interest in asset management to the extent that it sets out network policy,
standards and criteria and impacts on physical work undertaken on the system.
Delivery of a safe, reliable, efficient and sustainable supply of electricity at minimum cost.
Legislate and control compliance of statutory requirements and economic efficiency.
MPNZ maintains a self insurance fund for the majority of the MPNZ assets, however major zone
substations are insured with Marsh.
Landowners with MPNZ assets on their property have interests in safety, easements and access
requirements.
MPNZ employees have interests in health and safety and career opportunities.
Property developers wish to ensure that connection policies and costs are fair and that network
expansion plans are timely.
Achievement of an adequate return on investment and good corporate citizenship.
Territorial authorities have interests in minimising environmental impacts, development of underground
power systems, local economic development and in the control of assets in road reserves.
Transit NZ are interested in controlling assets in road reserves.
MPNZ relies on the Transpower grid and six Transpower GXP stations to deliver electricity through to
the MPNZ network and Transpower relies on the MPNZ network to deliver the electricity to end use
customers.
Table 7 Stakeholder Interests
4
Stakeholder interests have been identified and accommodated in the asset management practices of
MPNZ through the following processes:

The MainPower Trust and Board of Directors agree to an annual Statement of Corporate Intent which
details corporate strategy with respect to asset management planning.

Corporate Organisational Goals and Objectives support the establishment and completion of asset
management projects consistent with corporate vision.

Meetings and discussions with customers, developers and landowners help to establish asset
management policy and practices in regards to levels of service, charging regimes and network
planning including the price/quality trade-off.

Regular surveys of Residential, Commercial, and Large User Customers provide valuable feedback
on security and reliability of supply which assists in network planning, and on the price-quality tradeoff.

Government and Territorial Authority legislation provides a key input into the way that asset
management work is designed, planned and undertaken.

Customer complaints provide valuable feedback on quality of supply and influence the development
plan.

Consultation with interested parties over specific projects ensures that they are included in the AMP
as early as possible to allow sufficient planning to be undertaken.

Project performance reporting is provided to the Board of Directors on a monthly basis and includes
contractor performance, project management performance and financial performance. This is used to
establish future AMP programmes and to compare progress against targets in each annual AMP.
Any conflicting stakeholder interests are managed by systems that ensure that appropriate levels of
separation, accountability and authority are in place. Decisions are normally made based on the asset
management drivers detailed in the following section, in order of priority as listed below. If these criteria
fail to provide a solution, a decision is made by the Board.
2.6
Accountabilities and Responsibilities
The organisational structure of MPNZ is shown in Figure 6 (below). The MainPower Trust holds shares
in the Company on behalf of the electricity customers who are the trust beneficiaries. The Trust is made
up of seven trustees who are elected by the electricity customers. The Trust has the role of appointing
the Board of Directors of the Company and to approve the Statement of Corporate Intent. The Trust also
feed back valuable information to MPNZ from discussions they have with customers on matters such as
quality and performance.
Figure 6 Organisation Structure
5
The Board of Directors is responsible for the overall corporate governance of MPNZ. The Board guides
and monitors the business and affairs of MPNZ on behalf of the shareholder the MainPower Trust, to
whom it is accountable. MPNZ has seven Directors on the Board including a Managing Director.
Company performance is monitored by an audit committee made up of three Directors.
MPNZ operates within several governance policies, including a Delegated Authority policy, Treasury
policy, an internal audit and management review programme and an SCI. All policies and procedures
have been approved by either the MPNZ Board of Directors or the MainPower Trustees as required.
An annual strategy planning meeting is held between the Board and the Executive Management around
December each year where new developments and changes to asset management methodologies are
discussed and agreed. This establishes a framework for the new AMP for the following year. The Board
approves the annual AMP, Business Plan and Budgets, and ensures they are consistent with the SCI.
Progress against the AMP is reported to the Board on a monthly basis. Reporting of actual financial
performance against budget is analysed monthly by senior management.
The Management Team has responsibility for the day to day management of the Company, delivering the
AMP and for achieving operational objectives. Each divisional manager is also responsible for human
resources within their division including individual employment contracts, training, succession planning,
and health and safety systems.
The Engineering Manager is responsible for producing and delivering on the AMP and for ensuring that
best practice asset management is deployed so that the MPNZ network continues to satisfy customer
requirements. The Engineering Manager is responsible for achieving the work identified in the annual
Business Plan and for ensuring cost performance against budget. Asset management outcomes are
reported to the Board of Directors every month with a more detailed report every six months, and a
revised and updated AMP each year. Project progress reports are prepared fortnightly, identifying all
budget and schedule variances, and all significant project issues and risks.
All network planning, design and operations are carried out by MPNZ Engineering Staff. Some major
projects are designed by external consultants but conceptual design and project management is
maintained within the network team. Planning and design responsibilities include the optimisation of
network performance and investment through effective strategic planning, investment and network
modelling. Key accountabilities include the development of the AMP, network performance, technical
standards, maintenance, capital investment optimisation and implementation of the capital work plan.
The majority of works contracts are undertaken by MPNZ’s Engineering Field Services staff. Work
initiated by customers or from within MPNZ will be designed and planned by the Engineering Assets staff
with help from Field Services Supervisors and Customer Planners. The Engineering Projects section
project coordinators will set up the job and liaise with Field Services Supervisors to resource and
schedule the work prior to Field Services staff undertaking the work. Project management and
coordination of the various works will be carried out by a number of selected staff from relevant groups
depending on the size of the project. External contractors are used from time to time generally on large
projects where a tender has been released due to insufficient internal resources, or on smaller jobs to
help fill in times of high work loads. Monitoring of the performance of field workers whether they be Field
Services staff or external contractors, is given high priority. This includes health and safety performance,
work quality performance and work delivery performance.
More detailed information on how field services are managed is provided later in this section.
6
The level of delegated authority within the Company is shown in the following table.
Purchase or Sale of Goods or Services
Group Managing Director
Group Finance Manager
Group Managing Director - Secretary
Engineering Manager
Network Manager - Development
Network Manager - Assets
Network Manager - Operations
Network Manager - Field Services
Network Manager - Projects
Commercial Manager
Human Resources Manager
Information Technology Manager
Generation Manager
Other Engineering Staff
Managing Director’s
Approval in Writing
Any amount with prior Board
approval
200,000
200,000
200,000
200,000
200,000
200,000
Approved
Budget
500,000
100,000
2,500
100,000
50,000
50,000
50,000
50,000
50,000
100,000
100,000
100,000
100,000
2,500
Table 8 Delegated Authority
2.7
Asset Management Drivers
The objectives of MPNZ’s AMP are outlined above, consistent with its Corporate Vision, Goals and
Objectives and the needs of its Stakeholders. A balancing of the asset management drivers are required
to achieve these objectives. The key drivers have been identified as follows:
Driver
Safety
Measurement

Contractor safety

Customer safety

General public safety
Economic Efficiency


Service
Performance



Risk Management



Environmental
Management

Level of investment per service performance
output
Operating and maintenance costs per
service performance output
Reliability of supply (number and duration of
faults)
Capacity of supply (ability to meet the
demand for load)
Quality of supply (voltage levels, waveform
quality, momentary fluctuations)
Loss of supply from natural disaster or asset
failure
Transpower failure to supply
Shortfall in the provision of capacity or
reliability
Retention of the ISO 14001 standard in
Environmental Management
Asset Management Solution

Asset design

Maintain existing assets to be safe

Operate assets according to safe industry codes of practice
and regulation

Ensure that MPNZ’s contractors and employees commit to
active participation in safety training, safe work practices,
hazard identification and prompt reporting of near misses
and incidents

Cost-benefit analysis.

Tender processes for major projects

Maximising utilisation of assets

Robust maintenance and renewal plans

Determine what level of service customers require through
customer enquiry and feedback and provide service options
(where possible) and associated costs

Develop, implement and test Business Continuity Plan


Avoid the discharge of contaminants into the environment
Consideration of the environment when purchasing new
assets e.g. SF6 gas switchgear
Mitigate against visual pollution when planning new
infrastructure
Ensure compliance with relevant regulatory requirements in
all asset management solutions

Regulatory
Compliance






Commerce Act 1986
Electricity Act 1992
Electricity Regulations 1997
Electricity (Hazards from Trees) Regulations
2003
Electrical Codes of Practice
Resource Management Act 1991

Table 9 Asset Management Drivers
7
2.8
Asset Management Systems
MPNZ utilises a management philosophy driven by continued certification to international standards in
quality management, environmental management and in health and safety that underpins the total asset
management operation. A number of information management tools are also utilised to help deliver
relevant information to the decision makers. During 2010 & 2011 MPNZ introduced a new software
platform to improve asset management by integrating asset information, works management and financial
information and providing business intelligence.
2.8.1 Integrated Management System
MPNZ has integrated quality, environmental and health and safety management into a single group-wide
business management system referred to as the Integrated Management System (“IMS”). The IMS is
used to proactively manage the business; comply with the laws, regulations, and customer requirements;
prevent pollution; ensure worker and public safety and support continuous improvement. The IMS has
been designed on two levels:

MPNZ Group - information and management processes that are common to every company within
the MPNZ Group; and

Operation Specific - information and operational processes which are specific to individual companies
within the MPNZ Group.
For example quality, health and safety and environmental management directly impact on asset
management processes in the following ways:
Quality Management - MPNZ maintains an ISO9001 certified quality assurance programme and
continues to develop, implement and internally audit the programme in accordance with this commitment.
Relevant standards for asset management planning include design, purchasing, document and record
management and environmental management.
Environmental Management - MPNZ supports the principle of a sustainable planet and is committed to
caring for the environment while delivering energy and energy-related products and services to our
customers. MPNZ is also committed to an ISO14001 certified environmental management programme.
In relation to the AMP, this includes:

Promoting pollution prevention through employee/contractor training and education.

Exceeding environmental legislation and developing a co-operative relationship with territorial
regulatory authorities.

Adopting a responsible role in managing all hazardous substances. MPNZ has a transformer oil
containment programme in use at major substations and for emergencies. MPNZ is aware of the
issues involved in the use of SF6 gas in its network equipment and has developed procedures for its
safe handling and disposal. MPNZ has also been a cooperative partner in recent work undertaken by
Transpower in the safe handling and disposal of SF6.

Promoting energy efficiency and conservation through efficient design and customer education.

Considering environmental issues when establishing new extensions to the network or reconstructing
existing network.
Health and Safety - MPNZ has established the following Strategic Goals for Public and Employee health
and safety.

To provide a safe and healthy work environment for staff, contractors, visitors and the public with a
zero tolerance for unsafe acts or omissions.

To encourage staff, contractors and visitors to ‘think and act safely’ at all times.

To measure and continually improve our Health and Safety performance by setting objectives aimed
at the elimination of work related injury and illness.
8

To make Health and Safety planning and accident prevention an integral part of all (short and long
term) planning processes so that all practicable steps are taken to prevent accidents and harm to
people and property.

To benchmark our performance and practices against the best in the business in New Zealand.

To comply with New Zealand Health and Safety legislation, industry regulations, codes of practice
and safe operating procedures.
MPNZ has achieved certification to the NZS4801 Health and Safety Management standard.
Figure 7 illustrates the interaction of these key MPNZ Group management processes and their
relationship to operational processes:
Figure 7 Interactions of MPNZ Group Processes
2.8.2 Asset Management Information Systems
Asset Management Information Systems have been developed at MPNZ to support the asset
management processes. Table 10 below provides a description of each system.
AMIS
Accounting
Systems
Description

Capital and maintenance expenditure is managed using a comprehensive financial system.

Capital expenditure relates to the purchase of fixed assets, or to an increase in the output or service capacity of
a fixed asset.

Expenditure to maintain or recapture the existing output or service capacity of the network is expensed.

Historically MPNZ’s accounting systems and budgets have collated renewals and asset replacement with
maintenance.
9
AMIS
Geographic
Information System
(“GIS”)
Asset SQL
Databases
Works Management
System
SCADA and Load
Management
Systems
AutoCAD
Customer
Information System
(“CIS”)
Communication
Systems
Human Resource
Systems
Inventory Systems
Outage
Management
System
Description

The accounting system has been recently modified to separately capture renewals from maintenance.

During 2010 the old NCS financial software platform was replaced with an integrated TechnologyOne financials,
works and assets software.

MPNZ uses a GE Network Solutions Geographical Information System (GIS) for the management of spatial
asset information.

A number of GIS based applications have been developed covering outage management, maintenance
reporting, load flow analysis, and mobile GIS for field staff .

GIS provides a primary data source for asset valuations, a reference system for all work, a reference system for
roads, properties, easements, and geographic representation of assets.

The TechnologyOne software has been integrated with the existing GIS system.

A web based GIS viewer provides the primary user interface to asset information for network operators,
engineering and maintenance staff.

Further development of the outage management and load flow applications will be advanced once the
TechnologyOne platform is fully bedded down.

MPNZ employs global positioning satellite (GPS) technology for positioning key assets (transformer poles, tap
off poles, switch locations) on the geographical platform.

Information about other assets (including in between poles) is also gathered to ensure accurate location and
identifier information in the GIS and associated equipment databases.

All field asset information for transformers, switchgear and equipment, cables and conductors is stored in
TechnologyOne. This system supports a SQL database back end and a dot net front end.

Information is maintained from as-built field information.

MPNZ’s hardware and server software is continually updated consistent with modern high capacity hardware
platforms.

Information security management includes maintaining backup facilities for stored information for protection
from a security breach or disaster.

The works management system issues and tracks jobs through the TechnologyOne software. It also maintains
cost and quality information.

A comprehensive job reporting system provides managers with detailed information progress of the work plan,
work hours and cost against budget.

MPNZ’s Invensys Wonderware “Intouch” SCADA (supervisory control and data acquisition) system:
- displays voltage, current, & status information in real time from remote points on the network
- receives instantaneous information on faults
- remotely operates equipment from the control centre.

MPNZ operates Landis and Gyr ripple injection plants and On Demand load management software to control:
- customer water heaters to limit system peak loads and area loading constraints (mainly during winter
months)
- street lighting
- electricity retailer tariffs.

Detailed substation plans, standard construction drawings and many subdivision plans are prepared and stored
in AutoCAD

Where applicable, these are linked to the TechnologyOne assets.

Network details such as cable locations in trenches, boundary offsets, GPS location etc are stored in AutoCad
to be viewed without complicating the GIS system.

This database is used to issue and maintain installation control points (ICPs) with retailers.

It also manages customer information, lines tariff and consumption data.

Outage information is imported from the Outage Management System and stored against each customer.

The CIS is linked to the GIS for customer location information.

The CIS is maintained daily from event changes notified by Retailers and new connections.

The CIS is an important tool for MPNZ’s revenue protection.

Voice radio system for communication to field staff.

Digital radio network for communicating with zone substations and other field equipment

Sophisticated telephony system for general land based and mobile communication.

MPNZ’s human resource information will be transferred to the new TechnologyOne platform during 2011. This
will include Employment Contracts, competency and skillset information and safety and training records. A
succession plan exists within each section.

All stock and supply chain details are managed through the TechnologyOne software platform as a single
entity.

MPNZ maintains a separate storage facility for its own stock.

Single large item purchases are occasionally purchased direct by MPNZ Engineers where a technical
specification or long lead times are involved.

The outage management system is GIS based, with all planned shutdowns managed with traces across the
GIS to identify all affected customers and switching points.

For unplanned outages, all relevant fault information is entered into the GIS after the event.

Reports are run from the GIS to generate outage statistics as required.
Table 10 Asset Management Information Systems
10
2.9
Asset Management Processes
Figure 8 illustrates the main steps currently undertaken in asset management at MPNZ. These are
replicated throughout the relevant Sections of this AMP as illustrated on the diagram.
Section 2 – Establish Business Needs
▪
▪
Section 3 – Establish Existing Asset Information
Business needs are determined by MPNZ’s
operating environment and reflect corporate,
community, environmental, financial, legislative,
institutional and regulatory factors together with
stakeholder expectations
Manage asset management processes including
accounting quality, health and safety and asset
management systems
Existing information on the existing assets and network
configuration including:
▪ Description
▪ Capability/Capacity
▪ Utilisation and Performance
▪ Asset Age and Condition
▪ Asst Justification
Section 4 – Define Levels of Service
Section 5 – Risk Management
Identification of appropriate levels of service to meet
business needs.
▪ Define Key Drivers
▪ Describe current levels of service and identify
gaps in performance
▪ Set future service level targets
▪
▪
▪
▪
▪
▪
Context
Identification
Analysis
Evaluation
Mitigation
Monitoring and review
Section 6 – Forecast Demand
Details of growth forecasts which determine network
development and capital investment requirements.
▪ Factors influencing demand including usage
patterns and major developments
▪ Non-Asset Solutions (Demand management)
▪ Forecasting Method
▪ Load forecasts and growth scenarios
▪ Network constraint identification
Requirements Analysis
Identify potential asset and non-asset solutions using the following decision tools:
▪ Financial and economic modelling
▪ Network modelling
▪ Predictive modelling
▪ Lifecycle costing
▪ Optimised renewal modelling
Section 7 – Development Planning
Development plan aspect of lifecycle management
plan
▪ Planning criteria and assumptions
▪ Prioritisation methodology
▪ Sub-transmission planning
▪ Distribution planning
▪ Financial forecasts
Section 8 – Maintenance & Renewal Planning
Maintenance, Renewal and Disposal aspects of
lifecycle management plan
▪ Planning criteria and assumptions
▪ Operations and Maintenance planning
▪ Renewal and replacement planning
▪ Disposal planning
▪ Financial forecasts
Section 9 – Performance Evaluation
Planning for monitoring the performance of the Asset
Management Plan and systems used by MPNZ:
▪ Progress against development and lifecycle
plans
▪ Industry Performance
▪ Evaluation of asset management practices
Figure 8 Asset Management Plan Structure and Processes
11
Key asset management processes are:

Data Flow - the flow of energy consumption data, customer information, and installation details into
the customer CIS database from retailers and the new connections process.

Flow of Asset Information - the flow of asset information into the GIS system and TechnologyOne
SQL databases from as-built information and maintenance inspection programmes.

Key Outputs include all Field Services and external contractor work issued through the
TechnologyOne works management system - all work is issued through a work order in the works
management system. Multiple work orders can be issued to a project and work cost breakdowns can
be reported by labour, materials, transport and creditors.

MPNZ’s Shareholder Registry - MPNZ as a Trust maintains information on customer or shareholder
transactions or events in the CIS; i.e. when customers vacate a connection or shift into a new
connection.

MPNZ Revenue Protection - this process produces a customer created invoice of the amount owed to
MPNZ from Electricity Retailers for the provision of line function services based on customer energy
consumption and tariff reported from the CIS.

Asset Valuations - a frozen asset dataset taken at the beginning and end of each year is generated
from the asset SQL databases and GIS system, and any changes are related back to a work order in
the works management system. Standard Commerce Commission asset multipliers are stored in the
GIS system and standard value tables are used in valuation reports driven from the SQL databases.

Supply Chain Management - all stock is managed in the TechnologyOne system.

Managing Routine Asset Inspections and Network Maintenance - asset maintenance and renewal is
generated from asset information held in TechnologyOne and the GIS. Maintenance work is based on
asset condition following inspection, preventative maintenance methods, asset reliability analysis, and
on reactive maintenance systems. The asset databases contain asset history, inspection information,
and asset lifecycle management data. Poles are identified for mechanical load failure testing in any
particular year based on a report of asset information systems looking at asset age and last
maintained date and a condition based maintenance required date estimate. Estimates of cost are
applied in GIS and an Excel spreadsheet is used to refine the final annual lines maintenance based
on what is economic and practical. The 5 year forward work plan for line maintenance is also viewed
graphically via the GIS to enable optimisation of work packages. Any GIS user can view the
maintenance priority of any line so that other related capital or operational work can be properly
coordinated. Pole test data is managed in PDAs and software provided by the manufacturer of the
pole tester. All other inspections are managed through mobile computers and in-house developed
software.

Planning and Implementing Network Development Processes - Large project management
milestones, details and contract management are monitored using Excel spreadsheets in addition to
the works management system. SCADA stored history data is used for analysis of feeder history and
for load forecasting. An in-house developed sag tension programme is used to calculate the
tensioning of lines under construction. SINCAL loadflow analysis software is used and it is planned to
develop this software in conjunction with the customer metering information to calculate power flows
and fault ratings more accurately within the distribution network.

Measuring Network Performance - MPNZ employs in-house developed outage management software
to calculate and disclose system reliability and system security indices. SCADA helps to compare
real-time feeder loadings with forecasts. From 2011 the new TechnologyOne software will provide
increased business intelligence for use in reporting key performance indicators. A SQL network
operational events register has been developed with an Access front end to report on customer
complaints, environmental issues, and operational issues.
There are several quality control steps involved in processing information, with overnight error checking
deployed in the GIS system to ensure connectivity and data integrity. Most customer information and
network extension information is received in electronic form and is checked manually for accuracy.
2.9.1 System Gaps Identified
Detailed information has been kept on sub-transmission and distribution conductors, poles and cables for
many years and more recently this information is being improved following pole inspections and cable
12
testing. MPNZ has also built up comprehensive information on zone substation transformers from
inspections and maintenance programmes.
“As built” information is collected during installation for underground low voltage cables so this information
has been well maintained and is accurate. Conversely fifteen years ago the overhead low voltage was
only recorded in hard copy drawings and this information was difficult to use.
However, there are a small number of areas set aside for further improvement where asset information is
incomplete or inaccurate. These include:

Information on ages of switchgear used prior to 1984 is scarce and a programme to capture more
accurate information on these switches is underway.

Low voltage overhead systems including pole and conductor information remains inaccurate in part
and during 2010 a programme was initiated to further improve this information. This is continuing.

The history of assets that have been replaced is not retained and as a result information about
historical assets is not easily accessed. The TechnologyOne asset system will capture asset history
going forward.

MPNZ continually corrects errors in asset data when they are identified, usually as a result of
inspections, faults or maintenance activities.

MPNZ is intending to capture more information on the actual measurement of the impact on
investment in improved reliability such as live line techniques.

MPNZ has now started using the TechnologyOne software platform for asset management planning.
This has helped to identify further information gaps some of which have been addressed but others
will require more detailed data collection over the next few years.
2.9.2 Funding Strategy
The AMP broadly establishes the capital and maintenance expenditure programmes for the next ten
years, focussing on the first five years of this period. Annual budgets are prepared in more detail and
subsequently reviewed by senior management and approved by the MPNZ Board of Directors as part of
the annual business planning cycle. Projects identified within this AMP do not proceed until they are
approved by MPNZ. Approval of an individual project requires project justification prepared in
accordance with established capital budgeting procedures and guidelines.
MPNZ adopt the following capital budgeting procedures for evaluation of projects identified in the process
of maintenance and development planning:

The need for the project is justified in terms of its need for meeting load growth, improving reliability,
maintaining supply standards or other established criteria.

Project alternatives are identified. The least cost solution amongst the project alternatives is
confirmed by comparing lifecycle cost estimates.

All costs and benefits associated with the project are determined and quantified wherever possible.
In many instances, benefits are more difficult to quantify, particularly where reliability improvements
are concerned (entailing consideration of measures such as “demand not served”).
MPNZ returns to Qualifying Customers, in the form of monthly rebates credited to power accounts, all
revenues that the Board considers surplus to the requirements of the business. The Board’s budgetary
process recognises that sufficient net revenues must be retained by the business; i.e. not distributed in
the form of rebates, to fund its total operation including the investment in new capital development.
Following a review of strategic direction in December 2009 the Board of MPNZ concluded that while
“MainPower will ensure that its line service charges are in the lower half when compared with the charges
of other line companies” it would also recognize that MPNZ had financial constraints with respect to
liquidity and therefore agreed that the funding of all capital and maintenance expenditure from retained
earnings was no longer appropriate. As a result a funding arrangement was put in place that would allow
MPNZ draw down as and when the company’s liquidity position necessitated additional short term
support.
13
3
ASSET DESCRIPTION
3.1
Introduction
An overview of the MPNZ service area, the location of key assets and a description of the main network
asset categories is provided in this section. Transpower’s transmission system and GXP stations are
also included to illustrate MPNZ’s dependence on the national grid.
3.2
MPNZ Network Summary
The MPNZ network consists of 66 kV and 33 kV sub-transmission circuits, a large distribution system
comprising both 22 kV and 11 kV voltages, and a low voltage system.
The MPNZ network delivered electricity to customers in the North Canterbury (including Kaikoura) and
Wigram areas over the 2010-2011 year as follows:
Network
North Canterbury (including Kaikoura)
Wigram
Total
Peak Instantaneous
Demand (MW)
91
1
92
Electricity
Delivered (GWh)
568
4
572
Table 11 Network Load Summary
System Measure
Peak Load
Energy Entering the System
Loss Ratio
Load Factor
Customers
Zone Substation Capacity
Distribution Transformer Capacity
Distribution Transformer Capacity Utilisation
92 MW
572 GWh
5.6 %
71 %
34,247
159.9 MVA
419 MVA
21.5 %
Table 12 Asset Utilisation System Statistics 2010
3.3
North Canterbury Network (including Kaikoura)
3.3.1 Distribution Area
Maps of the northern and southern sections of the North Canterbury network region shown overleaf,
illustrate GXPs, zone substations and sub-transmission and distribution circuits. The capacity of
distribution circuits is shown on the maps based on the ratings applied by the Commerce Commission’s
2004 ODV Valuation Handbook for EDBs.
The supply area incorporates a small part of the Christchurch City Council region in the south, moving
north through the Waimakariri District Council, the Hurunui District Council and the Kaikoura District
Council areas respectively.
The southern-most boundary lies a short distance south of the Waimakariri River and takes in the small
urban area of Kainga and the rural area of Coutts Island. The northern boundary lies approximately 25
kilometres north of Kaikoura town at the small coastal settlement of Rakautara. The supply area follows
the coastline in the east, and its western-most region includes Lees Valley, Lake Sumner and the Boyle
area in the Lewis Pass.
14
Figure 9 MPNZ North Canterbury Network (North)
Figure 10 MPNZ North Canterbury Network (South)
Figure 11 below shows the MPNZ Network schematic diagram incorporating Transpower grid exit points,
and MPNZ subtransmission feeders, zone substations and distribution feeders.
MPNZ also supplies the urban area of Wigram located in west Christchurch. This is geographically
separated from the remainder of the network and is located approximately 15 kilometres south of the
main MPNZ North Canterbury area of supply.
15
Figure 11 MainPower Network Schematic Diagram
16
3.3.2 Load Characteristics
The North Canterbury load is increasingly dominated by dairy farming and associated irrigation load
particularly in Culverden, Waipara and Southbrook from loads along the fringes of the Waimakariri river.
Kaiapoi, Kaikoura and Wigram areas currently maintain the typical urban winter peaking load profile
which is levelled off at times of low residential demand by substantial commercial and small industrial
load. The Ashley GXP supply is dedicated to the adjacent fibreboard mill which has a very level and
constant load profile throughout the year. Table 13 below shows the Summer and Winter peaks on each
zone substation.
Summer
08 Am ps
1037
Southbrook
129
Cust
285
Sw annanoa
286
Bennetts
312
Oxford
272
Rangiora North
348
Kaiapoi S1
217
Am berely
102
MacKenzies Rd
71
Greta
103
Cheviot
38
Leader
306
Ludstone Rd
Mouse Point 22 334
159
Hanm er
4
Lochiel
126
Haw arden
NA
Rangiora West
NA
Pegasus
Substation
09
09 MVA Am ps
19.8
1006
2.5
164
5.4
309
5.4
303
5.9
300
5.2
270
6.6
364
4.1
234
1.9
99
1.4
62
2.0
112
0.7
61
5.8
307
12.7
355
3.0
153
0.1
6
2.4
129
NA
273
NA
NA
10
10 MVA Am ps
19.2
1087
3.1
165
5.9
318
5.8
302
5.7
371
5.1
288
6.9
297
4.5
208
1.9
120
1.2
71
2.1
119
1.2
51
5.8
293
13.5
379
2.9
152
0.1
6
2.5
146
5.2
325
NA
25
Winter
11
09
10
11
Peak
MVA Am ps MVA Am ps MVA Am ps MVA
20.7
1278
24.3
1334
25.4
1363
26.0
Winter
3.1
95
1.8
119
2.3
152
2.9
Summer
6.1
157
3.0
225
4.3
168
3.2
Summer
5.8
104
2.0
188
3.6
212
4.0
Summer
7.1
203
3.9
270
5.1
204
3.9
summer
5.5
339
6.5
333
6.3
374
7.0
Winter
5.7
442
8.4
466
8.9
405
7.7
Winter
4.0
302
5.8
310
5.9
332
6.3
Winter
2.3
107
2.0
94
1.8
145
2.8
Winter
1.4
68
1.3
56
1.1
55
1.0
Summer
2.3
93
1.8
92
1.8
95
1.8
Summer
1.0
15
0.3
52
1.0
25
0.5
Summer
5.6
311
5.9
337
6.4
347
6.6
Winter
14.5
110
4.2
238
9.1
127
4.8
Summer
2.9
258
4.9
252
4.8
249
4.8
Winter
0.1
7
0.1
7
0.1
7
0.1
Winter
2.8
103
2.0
116
2.2
105
2.0
Summer
6.2
NA
NA
387
7.4
444
8.5
Winter
0.5
NA
NA
26
0.5
84
1.6
Winter
Table 13 Zone Substation Summer and Winter Peaks
3.3.3 Major Customers and Characteristics
The operation of the networks in areas supplying major customers gives special consideration of these
customers for security of supply and maintenance reasons. Alternative supply options have been
constructed where possible to provide security consistent with the needs of these major customers,
however some of them are located in rural areas where this is not always economic. In addition a list of
high priority customers has been developed where power supply is an essential service for reasons of life
support, major regional employer and scale of loss, so that higher levels of service can be provided where
needed. GIS systems alert system controllers when high priority customers’ power supplies have been
interrupted or are planned to be shut down. MPNZ’s major customers are:

the Daiken NZ medium density fibreboard mill at Ashley. The mill is supplied from a wholly dedicated
Ashley GXP via four 11 kV feeders which provide reasonable levels of security. The Daiken
controllers have a facility to disconnect the power supply during emergencies, and maintenance is
scheduled by MPNZ to coincide with Daiken maintenance programmes or times of low production.

the Heller Meats plant at Kaiapoi. The site has undergone rapid growth and the total load is able to
be switched between two MPNZ 11 kV feeders in the area. They have two main supply points where
approximately half the plant can be maintained from each. They have also installed a backup
generator for critical items.

the Patience and Nicholson tool manufacturing plant in Kaiapoi. This plant can be supplied from
either of two 11kV supplies from the Kaiapoi switching station, and one of these can also be swapped
to an independant backup feeder.
17

the McAlpines sawmill at Southbrook. Recently the mill has been transferred onto a new high
security duel feeder supplied switchboard which has reduced the risk of power interruptions to the
mill.

the Mitre 10 megastore plant at Southbrook. This site is planned to be supplied from two alternative
11kV feeders over the next couple of years.

the Belfast timber kilns at Coutts Island. This plant is connected near the end of a spur 11kV
overhead line in a rural farming landscape. No alternative supply is available at the site. Line
maintenance is scheduled to coincide with plant maintenance programmes.

several large supermarkets and other commercial businesses scattered over Rangiora, Kaiapoi and
Kaikoura. The transformers for each of these are part of ringed feeders with RMU’s allowing rapid
switching of supply to an unfaulted feeder.
3.4
Wigram Network
The Wigram network located in Christchurch is not electrically contiguous with MPNZ’s other networks.
3.4.1 Distribution Area
MPNZ owns a small 11 kV and low voltage network located in the Wigram area. MPNZ takes supply from
the Orion network at 11 kV and there is an 11 kV circuit breaker and associated 11 kV metering at this
connection point. Network design and equipment employed on this network is very similar to other parts
of the MPNZ network. The network is totally underground and the total lengths of 11 kV and low voltage
cables are 2.8km and 8.2km respectively. This network has backup supply from Orion at the connection
point however an 11 kV ring, and therefore an alternative supply has not yet been established within the
Wigram development.
3.4.2 Load Characteristics
The Wigram load characteristic is dominated by residential customers with a typical winter peak and
summer low. A small amount of commercial load levels off the bottom of the daily profile.
3.4.3 Major Customers and Characteristics
The major customer is Air Force World, which operates a museum with a large heating load in winter.
3.5
Transpower Grid
3.5.1 Overview
3.5.2 Transpower 220 kV System
The 220 kV South Island transmission network is owned and managed by Transpower. The configuration
and performance of this system has a major effect on MPNZ in terms of system reliability and security to
MPNZ’s customers, embedded generation and future costs for the network.
Four 220 kV circuits supply Transpower’s Islington substation from southern generators. Double circuit
and single circuit tower lines from Tekapo, Ohau and Benmore follow different routes to Islington.
A single circuit tower line also travels between Livingston and Islington. The prudent planning capacity at
Islington is now 1141 MW at N-1 winter security. Maximum demand at Islington in 2008 was 1072 MW.
The double circuit tower line CHH-TWZ A was first commissioned in 1975, the single circuit tower line
ROX-ISL A was commissioned in 1956, and BEN-ISL A was commissioned in 1962.
Kikiwa is supplied from Islington by two 220 kV circuits on two tower lines, one tower line having single
circuit capability and the other having double circuit capability.
18
Figure 12 Transpower Network
3.5.3 Transpower 66 kV System
The 66 kV North Canterbury transmission system is also owned and managed by Transpower. One
double circuit tower line runs from Islington 66kV to Southbrook, and 220 kV interconnection at Waipara
supplies a second double circuit to Southbrook. The location and routes of these lines are shown in
Figure 12 above. MainPower is currently finalising the purchase of the Culverden – Kaikoura 66kV pole
line and the Kaikoura substation from Transpower.
3.5.4 Historical Development
The past decade has seen considerable capital investment by Transpower in network enhancement.
Several major projects aimed at supplying additional capacity have been completed including:

Transpower GXP station transformer upgrades

Construction of a third North Canterbury 66 kV circuit (from Islington) – now redundant

Construction of a third 220 kV Islington – Kikiwa circuit, involving removal of the third North
Canterbury 66 kV circuit, a new 220/66 kV connection at Waipara to supply the highly loaded
southern region using the two Transpower Waipara-Southbrook 66 kV circuits and a new 220/33 kV
connection at Culverden.
3.5.5 Transpower Grid Exit Points
Details of Grid Exit Point (“GXP”) transformers and connections are presented below in Figure 13. The
single line schematic shows the 220 kV interconnections at Culverden and Waipara along with
transformer ratings, connection configurations and the ownership boundary between Transpower and
MainPower. MainPower has initiated planning of the highlighted Ashley upgrade, and is investigating
options for the future Rangiora East GXP.
19
Transpower Grid Exit Point - Security
Southbrook
40
Ashley
Kaiapoi
40
38
38
10
2014
10
(40)
(40)
Proposed
Rangiora East
40
2015
40
~
22
22
~
MainPower
Waipara
80
80
Culverden
30
30
Kaikoura
~
16
13
MainPower
9
Legend
~
6
16
6
~
Figure 13 Transpower Grid Exit Points
Table 14 summarises the configuration of each of Transpower’s GXPs supplying MPNZ’s network.
GXP
Kaiapoi
Southbrook
Ashley
Description
Location
Transformer Capacity
Firm Capacity
Configuration
Supply to MPNZ
Location
Transformer Capacity
Firm Capacity
Configuration
Supply to MPNZ
Location
Transformer Capacity
Firm Capacity
Configuration
Supply to MPNZ
Waipara
Culverden
Kaikoura
Location
Transformer Capacity
Firm Capacity
Configuration
Supply to MPNZ
Location
Transformer Capacity
Firm Capacity
Configuration
Supply to MPNZ
Location
Transformer Capacity
Firm Capacity
Configuration
Supply to MPNZ
North western edge of Kaiapoi
76 MVA
38 MVA
Two 40 MVA 66/11 kV three phase transformer banks
Eight 11 kV circuit breakers
South side of Rangiora, adjacent to MPNZ’s Southbrook zone substation
80 MVA
40 MVA
Two dual-rated 30/40 MVA 3-phase transformer banks
Two 33 kV circuit breakers
Ashley rural area, 500m from Daiken NZ.
This GXP is dedicated to the supply of the mill.
20 MVA
10 MVA
Two 10 MVA banks of single phase transformer units.
Four 11 kV circuit breakers and an emergency circuit breaker if required for the
local area.
Northern edge of the Waipara township.
160 MVA
80 MVA to the 66 kV bus
Two 80 MVA 220/66 kV transformer banks directly connected to the IslingtonKikiwa 220 kV circuits. The 66 kV supply from these transformer banks feed a
single 66/33 kV dual-rated 10/16 MVA 3-phase transformer bank.
Two 33 kV and one 66 kV feeder circuit breakers and one 66kV load plant
circuit breaker.
7 kilometres north of Culverden township
60 MVA
30 MVA to the 33 kV bus.
Two 30MVA 220/33 kV transformer banks directly connected to the IslingtonKikiwa 220 kV circuits. A 10/20 MVA 33/66 kV step-up regulating transformer
rated at 13.09 MVA with no fans has been installed to maintain the 66 kV
supply to Kaikoura.
33 kV via two feeder circuit breakers and cables.
North-west edge of the Kaikoura urban area
9 MVA
No firm capacity to the 33 kV bus
Single 66/33 kV dual rated 10/16 MVA 3-phase transformer bank.
33 kV via two feeder cables to the Ludstone Road zone substation and also
33 kV supply south to Cheviot.
Table 14 Transpower Grid Exit Points
20
3.6
MPNZ Network Assets
3.6.1 Overview
This section provides an overview and description of the key features of MPNZ’s electricity distribution
network. Asset valuations included in Table 15 represent the Optimised Replacement Value at 31 March
2011. Existing assets that were commissioned prior to 31 March 2004 have been included at the audited
ODV value as at that date, together with indexation at movements in the Consumer Price Index (“CPI”)
through to 31 March 2011. Corrections to the asset base at 31 March 2004 have also been indexed at
CPI from this date, including the financial year ended 31 March 2005. Optimisation of assets in place at
31 March 2004 also forms part of this indexed valuation. Assets commissioned since 31 March 2004 are
included in table 15 at their historical cost and indexed at CPI accordingly. No further optimisation has
been applied. Distribution System Network and Substation Buildings were re-valued to Fair Value as at
the 31st March 2011. Additions to the Distribution System Network and Substation Buildings are recorded
at cost. Depreciation is determined on the Fair Value revaluation plus any additions during the year.
Description
Overhead
km
Underground
km
Total Quantity
(count or km)
Valuation
($) Adjusted
66 kV
53.4
53.4
1,558,847
33 kV
227.0
3.0
230.0
10,531,938
22 kV
576.0
0.1
576.1
14,765,709
11 kV
2,741.0
212.0
2,953.0
63,771,114
257.0
831.0
400/230V
33,287,158
Zone Substations
21,230,055
Distribution Substations
7,501.0
14,159,427
Distribution Transformers
7,481.0
25,205,551
MV Switchgear
Customer Connections
Other System Fixed Assets
7,665,963
5,991.0
28,431.0
34,422.0
5,071,878
7,927,963
$205,175,603
Table 15 MPNZ Asset Summary
21
3.6.2 Sub-transmission – 66 kV Overhead Lines, 33 kV Overhead Lines and Underground Cables
Asset Description, Capacity/Performance
MainPower Sub-Transmission System
66kV
33kV
Kaikoura GXP
Ludstone Road
Hanmer Springs
Oaro
Lochiel
Marble Point
Mouse Point
Culverden GXP
Leader
Cheviot
Hawarden
Greta
McKenzies Road
Waipara GXP
Amberley
Ashley GXP
Oxford
Bennetts Cust
Rangiora
North
Southbrook
Southbrook GXP
Swannanoa
Kaiapoi GXP
Figure 14 MPNZ Subtransmission Network
This section contains asset descriptions and their capacity and performance. A summary of the 66 kV
and 33 kV lines by type and length is shown below in table 16. Circuits are listed with capacities
appropriate for the season of the load peaks. Some circuits are limited by available protection settings.
All circuits have less than 75% of capacity utilised. In some instance the circuits may be unable to
transmit their full rated capacity due to end of line voltage drop.
Circuit
Voltage Load Capacity Utilisation Length
(kV)
(MVA) (MVA)
(%)
(km)
Conductor
type
Predominant
Line
Pole type
Construction
Southbrook – Cust
33
8.5
23
37%
17.8
Neon
Wood
Horizontal
Cust – Oxford
33
6.5
12.5
52%
19.6
Mink
Concrete
Horizontal
33/ 66
11.5
23
50%
31
Neon
Concrete
Delta
Southbrook – Rang.North
33
6.5
12.5
52%
7.2
7/12Cu/Mink
Wood
Delta
Rang.North – Amberley
33
7
12.5
56%
23
7/12Cu
Wood
Delta
Southbrook – Bennetts
Amberley – Waipara
33
7.5
12.5
60%
12.9
7/12Cu
Wood
Delta
Waipara – Hawarden
33
2.6
10
26%
24.9
Ferret
Wood
Horizontal
Waipara – Cheviot
66
9.5
38
25%
52.8
Hyena
Wood
Horizontal
Cheviot – Kaikoura
33
7
7
100%
65.9
Mink
Wood and Steel
Horizontal
Culverden – Hanmer
33
5.5
10
55%
26.8
Ferret/Mink
Wood
Horizontal
Table 16 Sub-transmission Assets
22
Table 17 below provides key information about each of the sub-transmission circuits.
Circuit
Southbrook – Cust
Cust - Oxford
Description
 Runs from Southbrook to Tallots Rd via Fernside with a short tee section to Cust.
 Historically the only supply to the Cust and Oxford substations.
 Normally supplies Cust and Oxford.
 This line has been recently upgraded to Tallots Rd with “Neon” conductor with a
summer thermal rating of 460A at 60degC and protection at 420A.


Continues from Tallots Rd to Oxford via the Bennetts substation.
Largely unchanged from the original concrete pole line with “Mink” conductor.

The 66 kV “Neon” concrete pole line (currently operated at 33kV) was constructed in
2002 between Southbrook and Bennetts via Swannanoa and Tram Road. Protection is
set at 420A.
The line normally supplies the Bennetts and Swannanoa substations.
There is a “Neon” tie link line along Tallots Rd to the Southbrook- Cust circuit.
Southbrook – Bennetts



Southbrook – Waipara




Waipara–Hawarden
66 kV / 33 kV
Waipara–Kaikoura

A light radial 33 kV line feeding a small remote load at Hawarden.

Supplies the Cheviot zone substation approximately equidistant from Kaikoura and
Waipara and also a number of smaller substations along its route.
Kaikoura is normally supplied from a 66 kV line fed from Culverden via the Inland
Road. The Waipara – Kaikoura line is used to supply Kaikoura via a 16 MVA 66-33 kV
step-down transformer installed at Cheviot when the main supply from Culverden is out
of service for maintenance
This line has very high voltage drop when supplying Kaikoura and its capacity is
constrained by the thermal rating of in line voltage regulators at Claverley and fixed tap
transformers along the Oaro coast.
Currently 90% reinsulated for 66 kV between Cheviot and Kaikoura.



Culverden–Hanmer
This 1939 wooden pole line interconnects Southbrook and Waipara GXP’s with tee off
connections for Rangiora North and Amberley.
This line normally supplies Amberley from Waipara and the northern area of Rangiora
from Southbrook.
The section between Amberley and Rangiora North substations is currently used only
as a back-up line.
There is no phase shift between Southbrook and Waipara so this is an important link
for transferring load during faults or maintenance.
Southbrook's northern Rangiora load is transferred onto Waipara or Waipara’s local
and western load is transferred onto Southbrook in these circumstances.



A light radial 33 kV line supplying Marble Point, Lochiel and Hanmer zone substations.
The unregulated Marble Point and Lochiel substations and two 33kV/240V
transformers along the line constrain the available capacity for Hanmer.
There is no back-up capability into the Hanmer region.
Table 17 Sub-transmission Circuit Description
Asset Condition
The subtransmission system is a mixture of old hardwood pole lines and newer predominantly concrete
pole lines. The older lines in particular are the focus of ongoing testing and renewal. Conductors used
on the newer lines are in good condition and have plenty of remaining life. Some conductor vibration
damage has been recorded on the Southbrook-Bennetts line and vibration dampers will be fitted and
remediation work carried out during the 2012 calendar year. Cables used on the sub-transmission
system are all XLPE and are expected to last at least 45 years.
Detailed information has been kept on all sub-transmission conductors, poles and cables for many years
and is frequently reviewed and updated following pole inspections and cable testing.
Figure 15 shows the pole age profile for all 66 kV and 33 kV overhead lines. A systematic programme of
testing and renewal, as described in Section 8 is focussed on the assets with the lowest remaining life.
Capital line upgrades from 33kV to 66kV over the next 5 years will accelerate the replacement of older
hardwood poles and most will be replaced by 2030.
23
66kV & 33kV Poles
450
100%
Tower
90%
Pine
400
Larch
350
80%
Hardwood
Concrete
300
70%
Cumulative %
60%
Quantity
250
50%
200
40%
150
30%
100
20%
50
10%
0
0%
1
6
11
16
21
26
31
36
Age (yrs)
41
46
51
56
61
66
71
Figure 15 Age Profile - 66 kV and 33 kV Poles
Figure 16 shows the age profile for all 66 kV and 33 kV cables and it is expected that they all have at
least 15 years remaining life.
66 kV & 33 kV Cables
Length (km)
2
100%
1.8
90%
1.6
80%
1.4
70%
1.2
60%
1
50%
0.8
40%
0.6
30%
0.4
20%
0.2
10%
0
0%
1
6
11
16
21
Age (yrs)
26
31
36
41
46
Figure 16 Age Profile - 66 kV and 33 kV Cables
3.6.3 Zone Substations
A summary of key information and statistics for each zone substation is set out in Table 18. Details of
zone substation assets are covered by asset class in subsequent sections, including transformers;
switchgear; property and buildings; other secondary assets.
The location of MPNZ’s zone substations is shown in Figure 14, MPNZ Subtransmission Network.
3.6.4 Zone Substation Transformers
Asset Description, Capacity and Performance
The majority of zone substation transformers have on load tap-changers to regulate the bus voltages and
the majority of loads applied to them over their lives to date have been below the manufacturer ratings.
These transformers have been subject to normal and typical urban and commercial load curves and
cyclic loading. Table 18 highlights the historical lack of redundant capacity in MPNZ’s substation
transformer capacity. Current security standards require 100% backup capacity for substations supplying
urban communities or important loads where practical. The series of capacity upgrades over the next 5
years will provide backup capacity to most customers.
24
Asset Condition
MPNZ has built up comprehensive information on zone substation transformers over many years of
maintenance and upgrades and the information is continually checked for accuracy during routine
inspections.
Figure 17 shows the age profiles for zone substation transformers. Zone substation transformers are
expected to last at least 60 years. This is based on a history of sound maintenance programmes as
detailed in Section 8. Any maintenance requirements noted during inspection have always been
addressed in a timely manner. Most major zone substation transformers have been replaced with larger
ones as high growth has dictated upgrades. Thus many of the zone substation transformers are relatively
young. The age profile indicates that even the older transformers could be expected to last another 20
years, and monitoring information indicates these are continuing to perform well. The Cumulative MVA %
line in the profile also indicates that the older transformers are typically small units in rural areas. Load
growth is continuing to cause transformer upgrades and in the process releases system spares for the
remaining old units.
SubstationTransformers
6
100%
90%
Quantity
Cumulative %
Cumulative MVA %
5
4
80%
70%
Quantity
60%
3
50%
40%
2
30%
20%
1
10%
0
0%
1
3
5
7
9
11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43 45 47 49 51 53 55
Age (yrs)
Figure 17 Age Profile Zone Substation Transformers
25
Transformers
Capacity (MVA)
Transformer
capacity after a
single fault
Capacity available
after switching
Remote Control
Number of
Feeders
Capacity (MVA)
Oil Containment
Seismic Restraint
Switchgear
Type
+
44
22
24
Yes
6
2 x 16/22
Yes
Yes
Indoor
Sub-transmission
Security of Supply
Level
Zone Substation
2011 Peak Load
(MVA)
General
Feeder Circuit Breakers
Southbrook
26
2
Cust
3.1
2
11
0
4
Yes
3
7.5/11
Yes
Yes
Outdoor
Bennetts
5.8
2
8
4
5
Yes
3
2 x 3/4
Yes
Yes
Indoor
3 Holec vacuum solid dielectric
Oxford
7.1
1
8
0
2
Yes
3
8
Yes
Yes
Indoor
3 Reyrolle (2x oil, 1x Vacuum)
Swannanoa
6.1
2
11
0
3
Yes
4
7.5/11
Yes
Yes
Indoor
4 Tamco vacuum
7
0
3
Yes
3
5/7
Yes
Yes
Outdoor
3 Nulec SF6
Rangiora North
7
2
-
6 Reyrolle vacuum
3 Nulec SF6
Amberley
6.3
2
8
4
6
Yes
3
2 x 3/4
Yes
Yes
Indoor
3 Reyrolle oil
MacKenzies Rd
2.8
2
4
0
2
Yes
3
2/4
Yes
Yes
Outdoor
3 Nulec SF6
Greta
1.4
2
-
4
0
0.5
Yes
3
2/4
Yes
Yes
Outdoor
3 Nulec SF6
Cheviot
2.3
2
4
0
1.5
Yes
3
2/4
Yes
Yes
Outdoor
3 Nulec SF6
Leader
1.2
2
2
0
1
Yes
3
1/2
Yes
Yes
Outdoor
3 Nulec SF6
Oaro
0.3
2
0.5
0
0
No
1
0.5
No
No
Outdoor
1 ME KFE vacuum
Kaikoura
6.6
2
12
6
6
Yes
4
2 x 4/6
Yes
Yes
Indoor
4 South Wales oil
Hawarden
2.8
1
4
0
2.5
Yes
3
3/4
Yes
Yes
Outdoor
2 GPC oil, 1 Nulec SF6
Mouse Point
14.5
2
26
13
15
Yes
4
2 x 13
Yes
Yes
Outdoor
4 W&B SF6
Marble Quarry
0.1
1
0.2
0
0
No
1
0.2
No
No
Outdoor
1 GPC oil
Lochiel
0.1
1
0.2
0
0
No
1
0.2
No
Yes
Outdoor
1 Nulec SF6
Hanmer
4.8
1
6
0
2.5
Yes
2
4/6 + 2.5
Yes
Yes
Indoor
Colour Key:
1
22
+
2
Less than 75% of capacity utilised
75-100% of capacity utilised
2 South Wales SF6
Over 100% of capacity utilised
A single fault will cause a loss of supply.
Two subtransmission lines supply to near the substation but a short single spur line completes the circuit.
A faulted line can be bypassed by manually switching to an alternative line.
A faulted line will be bypassed by automatic switching to an alternative line without loss of supply.
Table 18 Zone Substation Assets
26
3.6.5 Switchgear
Asset Description, Capacity and Performance
Circuit Breakers, Reclosers and Sectionalisers - There are a number of different types of circuit
breakers and reclosers on the system, including oil, SF6 or vacuum types. Figure 18 shows the age
profile for substation circuit breakers. Many of the existing 11 kV GPC, 33 kV OKW3 and South Wales
bulk oil type outdoor circuit breakers are approaching their expected total life of 40 years. Some are
beginning to experience minor breakdowns (mainly mechanical) which impact on system reliability and
are therefore targeted for replacement over the next ten years, as set out in Section 8.
Of the remaining outdoor circuit breakers the next oldest are 11 kV Reyrolle OYT oil type that employ
relatively coarse and unreliable protection systems. These will also be replaced over the next ten years.
The remaining outdoor circuit breakers are either vacuum or SF6 type and are performing reliably in their
early to middle economic life. Recent circuit breaker purchases have been of SF6 types and require very
little maintenance. MPNZ has minimised its use of SF6 gear because of its potential harm to the
environment and will continue to investigate other means of arc quenching and insulation within circuit
breakers. Future circuit breaker purchases are likely to be non SF6.
Indoor circuit breakers are mainly vacuum or SF6 and are very reliable with only occasional minor
problems occurring. The economic life of this group of circuit breakers is around 45 years and only a few
are approaching this. High numbers of circuit breakers have been purchased since 1975, a reflection of
feeder growth and the replacement programme for older circuit breakers. Most of the remaining indoor
Reyrolle LMT oil circuit breakers will be replaced in 2014 in conjunction with the Rangiora West area 66
kV upgrade.
Substation Circuit Breakers
25
100%
WHIPP & BOURNE GVR
TAMCO VH2
SOUTH WALES EO2
SOUTH WALES D4XD
SCHNEIDER FLUAIR
REYROLLE LMVP
REYROLLE LMT
NULEC N36
NULEC N27
NULEC N12
MCGRAW EDISON KFE
MCGRAW EDISON KF
LONG AND CRAWFORD
JAPAN AE POWR NVBOA
HOLEC NVS
ENGLISH ELECT OKW3
AEI GPC
ABB EDF 72 SK 1-1
Cumulative %
20
Quantity
15
10
5
90%
80%
70%
60%
50%
40%
30%
20%
10%
0
0%
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
Age (yrs)
Figure 18 Age Profile – Substation Circuit Breakers
27
Rural Circuit Breakers
25
100%
WHIPP & BOURNE GVR
SOUTH WALES D6XD
REYROLLE OYT
REYROLLE LMT
NULEC N36
NULEC N27
NULEC N12
mesa MXSP-24
MCGRAW EDISON KFE
MCGRAW EDISON KF
MCGRAW EDISON H2
MCGRAW EDISON GN3E
MCGRAW EDISON GH
LONG AND CRAWFORD
GEC KAC
33kV HV CB
Cumulative %
20
Quantity
15
10
90%
80%
70%
60%
50%
40%
30%
20%
5
10%
0%
0
0
2
4
6
8
10
12
14
16
18
20
22
24
26
28
30
32
34
36
38
40
Age (yrs)
Figure 19 Age Profile – Rural Circuit Breakers
Ring Main Units - The use of ring main units commenced around 1950 with Long and Crawford and BTH
equipment. During the 1970’s and 1980’s ABB’s SD range of oil ring main units were used, followed in
the 1990’s by a change to air-insulated Holec (Magnefix) type switchgear. Large purchases of ring main
units were made during the 1990s reflecting the high growth in subdivisions at this time. The Holec Xiria
sealed air insulated range has also been used since 2000. Ring Main switchgear has an expected life of
40 years however the early ABB SD switchgear and the older L&C and BTH oil switchgear have
maintenance issues and increasing concerns regarding their operational safety as they age and system
fault levels increase. Knowledge of the location and age of pre 1990 switchgear is poor as can be seen
by the large spike in the Figure 20 age profile. This will be addressed in 2012 and a replacement
program developed.
Ring Main Switchgear
210
100%
TOLLEY TX
180
90%
L&C J4
80%
L&C GF3
Holec Xiria
150
70%
Holec MD4
60%
GEC DA4
120
Quantity
BTH JB721
50%
ABB SD
90
ABB SAFELINK
40%
Cumulative %
30%
60
20%
30
10%
0
0%
0
2
4
6
8
10
12
14
16
18
20
22
24
26
28
30
32
34
36
38
40
42
Age (yrs)
Figure 20 Age Profile – Ring Main Switchgear
Disconnectors - Most of the air break switches installed during the period 1950 to 1980 were Canterbury
Engineering types 955, DA2, DA27, NL7 and NG10. More recently, Dulmison and Schneider’s integrated
spar mounted air break switches, and Electropar EPS2 switches have been used. The number of new
distribution line installations is stable as more live-line work and increasing feeder circuit breakers offset
28
the requirements of network growth. Additional switches are still being installed for isolation of large
customer loads e.g. irrigation supplies. Outdoor distribution disconnectors are expected to have a 35
year life. The age profile below highlights the lack of quality installation data for switches with most
shown being installed in 1984. This information should improve substantially over the next few years.
After data correction there will still be a large number of disconnectors around the end of their expected
life. Conversion of irrigation areas to 22kV and the switchgear renewal program should result in approx.
30 old switches being replaced each year. This should remove this maintenance wave over a 5 year
period.
Disconnectors
100%
210
Stanger
Schneider PLJ
180
90%
Schneider ISW-LK
Schneider IRW-NL7
80%
Schneider IRW-NG10
150
Schneider IRW-DA87R
70%
Schneider IRW-DA27
Schneider IRW-DA26R
Quantity
120
60%
Schneider IRW-960
Schneider IRW-955
50%
Schneider IDW-AF
90
Electropar EPS2
40%
Dulmison Morlyn HSB
22kV Disconnector
60
30%
11kV Disconnector
Cumulative %
20%
30
10%
0
0%
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
Age (yrs)
Figure 21 Age Profile – Disconnectors
3.6.6 Distribution – 22 kV and 11 kV Overhead Lines and Underground Cables
Asset Description
Large numbers of hardwood poles were used in the earliest part of distribution lines network construction.
Larch poles impregnated with creosote were used in the late 1950s and through the 1960s in combination
with hardwoods. The ageing distribution level hardwood and larch pole population has been the biggest
single renewal issue for MPNZ, however regular testing and subsequent renewal of poles now has this
well under control. Treated corsican pine poles were used from 1973 and concrete poles were also
purchased from the mid 1970s. The main pole types used today are treated radiata pine and concrete.
Standard 11 kV construction uses a 2.4 metre 100 x 75 hardwood cross arm on a wood or concrete pole.
Designs comply with the Electricity Regulations and the relevant New Zealand Standards and Codes of
Practice. New overhead lines are designed to AS/NZS7000:2010. The majority of the high voltage
underground systems use either 95 mm or 185 mm cables although more recently 300mm has been used
for major urban feeders. Smaller sizes are being employed for rural customer spurs. Around five percent
of the total 11 and 22 kV systems are underground, typically located in the larger urban areas.
Over the past ten years a large number of lines have been converted from 11 kV to 22 kV by re-insulating
the lines. This has largely been undertaken in rural areas experiencing new irrigation demand and
conversion of farms to dairying. Areas converted so far are all of Culverden including Leslie Hills, Mouse
Point and Balmoral, and the Rockford, Burnt Hill and Thongcaster Road areas around Oxford. Figures 9
and 10 in section 3.3 show the lines that are operating at 22 kV.
29
Asset Capacity/Performance
One of the key criteria for distribution development planning is voltage. The current methods used to
monitor voltage performance are SCADA using voltage measurements brought back from field
equipment, load flow analysis results, manual voltage checks in normal and abnormal configuration and
from investigations into power quality customer complaints.
Some town feeders are approaching peak loading levels where it is becoming more difficult to transfer
load during fault restoration. These include transferring load to Rangiora West from the Rangiora Borough
or Rangiora East feeders, transferring load between the two Hanmer town feeders, and between
Kaikoura’s Town and Churchill Street feeders. A study of options to improve these operational
weaknesses has already started and some improvement work has already been completed but further
additional linking of priority feeders will occur over the next year to mitigate more of these problems.
There are likely to be rapid changes to the load distribution around Rangiora and Kaiapoi in response to
the Red Zoning of Kaiapoi and Christchurch properties and subsequent fast tracked subdivision
development. MPNZ is trying to anticipate this in its feeder development program and the timing of GXP
upgrades however there is a lot uncertainty over the speed and scale of the changes.
Asset Condition
The information available to MPNZ on its distribution lines and cables is extensive and accurate following
the rigorous testing and inspection regimes that have been employed over the past 15 years.
The ageing hardwood and larch poles are mechanically pole tested every 10 years to ensure they have
adequate remaining strength. Any weak poles are replaced and all crossarms, stays and other hardware
is checked and replaced as required. Treated pine and concrete poles are generally in very good
condition and are inspected and hardware maintained, but not yet mechanically tested. Conductors in the
MPNZ region are in very good condition and are not prone to accelerated deterioration due to
atmospheric conditions except in a few coastal areas. Figure 22 below shows the age profile for the pole
population used to support 22kV and 11 kV overhead lines. All hardwood and larch poles over 40 years
old have been tested and by 2015, this will reduce to 35 years.
22kV & 11kV Poles
1800
100%
Tower
1600
90%
Pine
80%
Larch
1400
HW
70%
1200
Concrete
60%
Cumulative %
Quantity
1000
50%
800
40%
600
30%
400
20%
200
10%
0%
0
1
6
11
16
21
26
31
36
41
46
51
56
61
66
71
76
81
86
91
Age (yrs)
Figure 22 Pole Age Profile 22 kV and 11 kV
Cables used in more recent times are in good condition and have plenty of remaining life. Three quarters
of the cables used on the MPNZ system are XLPE types and are expected to perform for at least 45
years. The remaining third are PILC types which are expected to perform for at least 70 years. Figure 23
30
below show the age profile for 22 kV and 11 kV underground cables. Most of the older PILC are in
central urban areas. Network planning has focused on increasing the number of distribution circuit
breakers to shorten the length of line and number of customers exposed to future cable faults and shorten
restoration times.
22 kV & 11 kV Cables
20
100%
18
Cu XLPE
90%
16
Cu PILC
80%
14
Al XLPE
70%
Al PILC
Length (km)
12
60%
Cumulative
%
10
50%
8
40%
6
30%
4
20%
2
10%
0
0%
1
3
5
7
9
11
13
15
17
19
21
23
25
27
29
31
33
35
37
39
41
43
45
47
Age (yrs)
Figure 23 Age Profile Underground 22 kV and11 kV
3.6.7 Distribution Kiosks and Substations
Asset Description, Capacity/Performance
Some of the early distribution substations within the towns of Rangiora and Kaiapoi were constructed as
buildings or large substation rooms providing ample space and they were usually constructed of poured
concrete and stucco exteriors. These buildings usually had an internal overhead 11kV busbar attached
on the walls with dropout style fuses off the bus protecting the transformer. Some included older style
11kV ringmains with circuit breaker protection for the transformer. Low voltage panels were established
in these buildings using HRC open style low voltage fusing. Most of the old style overhead bus systems
have long since been replaced with cable and ringmain systems.
From the 1960s onwards smaller steel kiosks were used to house the transformers and switchgear. Over
the years there have been a number of design changes to these steel boxes to improve ventilation and to
allow for changes in low voltage fuseways across manufacturers. Ringmains were used with an 11kV
HRC fuse protecting the transformer. The box design allowed for a maximum transformer size of 500
kVA, however these had to be derated because of poor cooling. Low voltage panels were typically the
open style Lucy HRC fuse and were manufactured in-house.
In more recent times the trend has been to establish outdoor style transformers with cable boxes and
separate outdoor cabinets for the ringmains and low voltage panel. This design allows much more
flexibility in changing transformer sizes and for accessibility as well as allowing the full rating of the
transformer to be utilised. MPNZ has historically established ground mounted substations away from the
road reserve on private property through land ownership or easements, and this has been a local Council
requirement. Distribution substations in rural areas are typically pole mounted for transformers up to 200
kVA and ground mounted above this or where required by the customer. Pole transformers are protected
with drop out 11kV fuses and low voltage HRC fuses where practical.
Asset Condition
Information on distribution substations is very accurate due to the high levels of maintenance undertaken
at these sites. All distribution substations are expected to last at least 45 years. Building substations and
kiosks have been well maintained over the years and are in very good condition. Where major upgrades
have occurred in distribution substation buildings the structure has usually also been seismically
strengthened.
31
3.6.8 Distribution Transformers
Asset Description, Capacity/Performance
MPNZ has over 7500 distribution transformers. A variety of these have been purchased over the years,
including Tyree, ABB, Astec, Tolley and Wilsons. Large quantities of transformers were purchased
between 1967 and 1973 due to the growth in the distribution network at this time. Many of these were in
the range of 10 to 30 kVA.
Mainly 22 kV distribution transformers are currently being purchased due to expansion of the 22 kV
network. 11 kV transformers that are replaced due to the 22 kV expansion project are reused in other
parts of the network.
Asset Condition
Historically distribution transformers have been tracked by numbering the site as well as the transformer
with separate numbers, thus enabling a transformer to be tracked in and out of a site due to maintenance
or upgrading. This system of tracking has meant that the distribution transformer information is very
accurate.
The majority of distribution transformers are expected to last at least 45 years. Distribution transformers
200 kVA and greater however are expected to perform for at least 55 years recognising a history of
inspecting these sites on an annual basis and undertaking remedial maintenance where necessary.
Figures 24 and 25 show the age profiles for single phase and three phase distribution transformers. The
high level of irrigation growth and subdivision development has lead to more, larger three phase
transformers being installed over the last 10 years. Over a similar period the conversion of irrigation areas
to 22kV has also meant that many small transformers have also been replaced. Many of the recovered
transformers are in excess of 30 years old, small, have high losses, and are uneconomic to reuse. These
are scrapped along with those with any significant defects which may be uneconomic to rectify. Newer
and larger recovered transformers are reused in 11kV areas. This means that the average age of
transformers in 11kV areas is rising significantly as few new 11kV transformers are being purchased
except larger sizes for subdivisions and commercial developments. The failure rate of even 60 year old
distribution transformers is very low and MPNZ has many spares. Overall the wave of near end of life
high loss transformers is being replaced by low loss (MEPS1) transformers.
Single Phase Transformers
100%
200
180
50 kVA
90%
160
30 kVA
80%
<= 15 kVA
140
70%
Quantity
Cumulative %
120
60%
100
50%
80
40%
60
30%
40
20%
20
10%
0%
0
1
3
5
7
9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43 45 47 49 51 53 55 57 59
Age (yrs)
Figure 24 Age Profile - Single Phase Distribution Transformers
32
Three Phase Transformers
200
100%
1000 kVA
180
500 kVA
300 kVA
160
200 kVA
100 kVA
140
90%
80%
70%
50 kVA
Quantity
120
<= 30 kVA
Cumulative %
100
60%
50%
80
40%
60
30%
40
20%
20
10%
0
0%
1
3
5
7
9
11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43 45 47 49 51 53
Age (yrs)
Figure 25 Age Profile - Three Phase Distribution Transformers
3.6.9 Local Reticulation – 400V Overhead Lines and Underground Cables
Asset Description, Capacity/Performance
About half of MPNZ’s low voltage system is underground cables. These are used typically around the
larger urban areas and can vary in size from 6 mm for street lights through to 300 mm for heavy
distribution. Most are aluminium types. The overhead low voltage systems are used in the small rural
towns and in the rural farming areas to enable a number of customers to be supplied from the one
transformer. Most overhead low voltage conductors are bare or covered copper.
Asset Condition
“As built” information has been collected during installation for underground low voltage cables so this
information has been well maintained with accurate type information and less accurate age information.
Conversely fifteen years ago the overhead low voltage was only recorded in hard copy drawings and this
information was difficult to use. Over the last ten years the urban overhead low voltage information has
been recorded electronically and is now considered to be reliable. Small corrections will continue to be
made to this information as inspections and work is done at these sites. Rural low voltage overhead data
is still substantially incomplete. I t is being captured in conjunction with maintenance work on the
associated medium voltage network.
All low voltage cables are of the new XLPE or older PVC types that have been used since the late 1960s.
Failure rates on these cables have been very low and we believe them to be in good condition. There is
little available information on the practical useful life of low voltage cables. Based on the high reliability of
existing cables up to 40 years old, MPNZ assigns PVC low voltage cables an expected useful life of 60
years.
Low voltage overhead systems are included in the MPNZ pole testing regime. Where significant numbers
of LV only poles require replacement in urban areas, consideration is given to underground conversion.
Where District Councils are renewing underground services, consideration is also given to bringing
forward overhead renewal expenditure and cost sharing underground conversion. Regular meetings are
held with the councils to underground programmes.
33
Figure 26 below shows the age profile for the underground low voltage system.
Low Voltage Cables
100%
160
S/L
140
90%
LV
80%
Cumulative %
120
70%
Length (kM)
100
60%
50%
80
40%
60
30%
40
20%
20
10%
0%
0
1
3
5
7
9
11
13
15
17
19
21
23
25
27
29
31
33
35
37
39
41
43
Age (yrs)
Figure 26 Age Profile - Underground Low Voltage
3.6.10 Ripple Injection Systems (Load Control)
Asset Description, Capacity/Performance
MPNZ owns all ripple injection plants and receiving relays used on the network. MPNZ employs Landis &
Gyr SFU-G and SFU-K ripple injection plant using Decabit code for load control and tariff switching. The
plants operate at an injection frequency of 283 Hz and are listed below.
Location
Mouse Point
Kaikoura
Southbrook
Kaiapoi
Waipara
Commissioned
1993, 2005
2008
1995
1995
2007
Voltage
33 kV
33 kV
33 kV
11 kV
66 kV
Maximum Load
30 MVA
30 MVA
60 MVA
30 MVA
60 MVA
Table 19 Ripple Injection Assets
The Southbrook load plant was upgraded to a 60 MVA capacity plant during 2002 due to the large growth
being experienced on that site. The Waipara 33 kV load was replaced with a 66 kV plant in conjunction
with the conversion of the Waipara to Kaikoura circuit to 66 kV in 2008. The Mouse Point plant was
replaced in 2006 with a more modern equivalent due to a failure of the old plant. All plants are GPS
synchronised.
The majority of the receiver relays are Zellweger RM3 installed between 1993 and 1997. The remainder
are the later Landis & Gyr RC5000 series. MPNZ now purchases RO type relays.
The load control plant is used for tariff switching, for controlling the peak loads at Transpower GXP and to
manage load constrained areas of the network. The load management drivers of time, price and load
shifting channels for the load management system are shown in Appendix 10.5.
Asset Condition
Designs and physical structures of injection plants has been well documented and are regularly
maintained and tested. Relay records have been well maintained for all installations and are very
accurate. All injection plants and relays are modern and have been reliable in operation with low failure
rates. The injection plants are expected to perform for at least 20 years before requiring replacement.
The installation of a smart metering system with load control functionality is likely to supersede the ripple
plant systems within the remaining life of the plants.
34
3.6.11 Street Light Control
Asset Description, Capacity/Performance
Most streetlights are controlled by ripple relays located at local low voltage distribution substations and
the relays receive a signal by ripple injection initiated from a light level sensor. Dedicated street light
supply cables loop around a number of lights from each control point. A small number of lights are
controlled from local photocell sensors. Streetlights are not metered but consumption is assessed based
on the loading characteristic of each light.
Asset Condition
All streetlight control points are well documented. Streetlight relays are modern and reliable and
extremely low failure rates have been reported. Their age is consistent with the ripple plant age.
3.6.12 SCADA
Asset Description, Capacity/Performance
The present SCADA system is based on Invensys “Wonderware Intouch” software running on standard
hardware. Installed in 1998, there are two operating master stations in MPNZ’s control centre. The
operating software has both DNP3 and Modbus drivers.
The older sites were fitted with remote terminal units (RTUs) communicating with Conitel protocol and a
number of these have now been changed to more modern DNP3 RTUs. All remote sites are now
communicating via the DNP3 protocol. Work is proceeding on new field devices, including intelligent
circuit breakers, line fault indicators and power quality devices with remote communication facilities and
this can be seen by the budgeted expenditure allocated to switchgear and SCADA in the capital reliability
budget. MPNZ is committed to using the latest distribution automation technologies to improve system
performance and fault response times.
Asset Condition
SCADA equipment is assigned a useful total life of 15 years. The SCADA software and hardware has
been very reliable to date, but as it is near its end of life, options have been considered during 2010 for its
replacement. The decision has recently been made to upgrade the existing Intouch software to its latest
Archestra version, and this will now occur during the last quarter of the 2012 financial year and the first
quarter of 2013. The decision has also been made to upgrade to modern server based hardware and hot
standby systems.
3.6.13 Communications
Asset Description, Capacity/Performance
Data Communications - A data radio network was established during 1999 to cover the eastern region.
The system is capable of supporting DNP3 and Modbus protocols at data rates up to 9600bps. It is a full
duplex hot carrier backbone network which provides data gateways at Mt Cass, Beltana and Kaikoura
communicating with the SCADA network hosted in Rangiora. A data-radio link was also established in
2002 between Mt Grey and Wallace Peak creating a western wireless link through North Canterbury.
DNP3 information from Hanmer, Mouse Point, Balmoral, and Hawarden is received directly at the
gateway at Wallace Peak and sent back to Rangiora via Mt Grey. A fibre optic cable has been installed
between Transpower’s Culverden site and MPNZ’s Mouse Point site so that loading levels can also be
brought back to Rangiora via the new link. A fibre optic cable is similarly employed between the
Transpower site at Kaikoura and MPNZ’s Ludstone zone substation. A data radio repeater was also
installed at Mt Grey to provide coverage of MPNZ’s southern area with DNP3.
Voice Communication - MPNZ employs a Tait FM E band system for vehicle communications which
consists of a base station located at Rangiora and five other repeaters sited at Mount Thomas in the
southern region, Mount Cass in the Waipara area, Mount Beltana in the Cheviot area, Wallace Peak in
the Hanmer area and Williams Spur in the Kaikoura area. This network provides five separate channels
covering the company’s distribution area and a sixth simplex channel for vehicle to vehicle
communication. A seventh channel is used to scan channels 1-6 from any repeater station. Portable
handheld radios have been connected to each field contractor vehicle offering greater flexibility of use
within distances of 300m from the vehicle. An emergency button on each portable radio enables the
contractor to send an SOS to the control centre during an emergency.
35
Asset Condition
MPNZ communications systems are well documented. Communications equipment is assigned a total
useful life of 15 years. Both data and voice communications systems are modern and reliable having only
been replaced in the last few of years.
3.6.14 Protection and Metering Systems
Asset Description, Capacity/Performance
MPNZ owns metering systems installed at all Transpower GXPs to monitor load for load management
purposes and for revenue protection. All have Ion type meters, installed after 2000. All modern zone
substations use Areva, SEL or Siemens electronic protection systems. Older substations have GEC
electromechanical relays which are still reliable but have limited setting ranges and functionality. A
number of individual relays in these substations have been replaced in conjunction with circuit breaker
replacements.
Asset Condition
Protection and metering systems are well documented. Modern protection systems log system events
locally for lengthy periods and also log on SCADA central master station software. Metering records are
maintained on SCADA SQL database. The total useful life assigned to protection and metering systems
is 40 years. Historically this equipment has been extremely reliable and is monitored frequently.
3.6.15 Power Factor Correction Plant
MPNZ has no system power factor correction installations of its own, however, the Daiken NZ mill at
Ashley has two 11 kV capacitor banks of power factor correction and Transpower have installed power
factor correction for voltage support on the 66 kV bus at Southbrook.
3.6.16 Embedded / Distributed Generation
Asset Description, Capacity/Performance
There is no major embedded generation on the MPNZ network. MPNZ is planning to construct a 60MW
wind farm on Mt Cass near Waipara, and the resource consent for the wind farm has been approved.
MPNZ is also investigating several other potential wind and small hydro generation opportunities.
Asset Condition
The wind monitoring equipment is monitored on a monthly basis and has been performing well.
3.6.17 Mobile Substations and Generators
Asset Description, Capacity/Performance
MPNZ has invested in a diesel mobile generation plant to assist with reducing the number of planned
interruptions. The plant is rated at 275 kVA and is able to be used for low voltage supply directly off the
generator or at 11-22kV supply via a transformer. The plant has been fitted on a tandem axle truck along
with the transformer, protection systems and connecting leads. The generator is used during planned
work to maintain the supply to customers and it has enough capacity to supply an average load off an
urban transformer kiosk, or can be connected to long lengths of overhead lines at 11 or 22 kV supplying
up to 100 customers.
Asset Condition
A good history of operational information has been maintained including loading information and running
costs. The diesel generator truck is now four years old and is well maintained. Use and operation of the
generator truck is controlled by MPNZ Operations staff.
36
3.6.18 Property and Buildings
Asset Description, Capacity/Performance
MPNZ owns substation buildings, office and administration buildings and contractors’ operational
buildings. Substation buildings are assigned a nominal useful life of 50 years. .
Asset Condition
All MPNZ buildings are well maintained. Buildings have been inspected following the recent earthquakes
and there has been no significant damage. The main office building has been design reviewed by
independent consultants and found to be significantly below current code requirements. A decision has
been made to abandon this building and for MPNZ to relocate its head quarters to another site. Planning
is in progress for this.
3.7
Asset Justification
3.7.1 Introduction
The main justification for the assets employed by MPNZ to deliver electricity to customers is that they are
the minimum required to provide electricity of sufficient capacity and reliability to all customers,
accommodating reasonable growth forecasts, consistent with MPNZ’s Corporate Organisational
Objectives and Goals and the targets specified in the SCI.
3.7.2 Historical Development
Table 20 outlines the historical development of the MPNZ system.
Date
1916
onwards
1928
onwards
1930s
onwards
Major Development

The Public Works Department constructed a double circuit 11 kV line from Belfast across the
Waimakariri River to supply a flour mill in Ohoka and the Kaiapoi Borough.

The distribution voltage chosen for Kaiapoi and the surrounding Eyre district was 3.3 kV.

Shortly after an 11 kV feed was extended to Rangiora and that district was also distributed at 3.3
kV.

Over the next few years the 11 kV feed was extended to the Oxford, Ashley and Kowhai districts
with the Kowhai district taking supply at 6.6 kV.

In 1928 the North Canterbury Electric Power Board (NCEPB) was formed from the
amalgamation of the districts excluding the Rangiora and Kaiapoi boroughs.

The main engineering task at the time was to coordinate the differing voltages across the district.

The 1927 Electricity Supply Regulations reduced the ground clearance for 11 kV overhead
systems, so it was decided to standardise at 11 kV throughout the district since it was low cost
due to the existing poles.

The 11 kV system catered for growing load in the district for many years.



1960s
onwards




1990s
onwards


In the early 1930s Waipara, Cheviot and Amuri counties sought access to the NCEPB’s supply
and a 33 kV line was constructed from Southbrook to Waipara.
The northern counties were distributed at 11 kV although some of the lines were rated for 33 kV
to cater for future growth allowing for the large distances involved.
33 kV sub-transmission and 11 kV distribution voltages prevailed as the system developed as
both voltages were able to cater for the slower rates of growth experienced through the war
years and up to the 1970s.
A 33 kV link between Waipara, Cheviot and Kaikoura was created in the 1960s to supply the
growing load at Kaikoura, the link had previously been running at 11 kV.
In the 1970s the NCEPB took over the Kaikoura District Council’s electricity system, comprising
33 kV sub-transmission and 11 kV distribution.
A new 66 kV line was built by Transpower to supply Kaikoura from Culverden, with a 66 / 33 kV
GXP station constructed at Kaikoura.
The NCEPB constructed a 33 / 11 kV zone substation beside the GXP to supply the local 11 kV
system.
Strong urban residential growth was backed up by the dairy farming boom from the mid 990s
requiring supply to large irrigation and milking shed load.
Zone substations capacity was increased and critical areas were upgraded to 22 kV as the 11 kV
systems ran out of voltage regulation or thermal rating.
37
Date
2000
onwards
Major Development

Residential and dairy growth continued and then the Christchurch earthquakes caused a major
shift in urban load centres and load growth pattern in the Waimakariri district.

A new 66 kV rated subtransmission circuit was built to Bennetts via Swannanoa. Conversion of
the Waipara to Kaikoura 33 kV line to 66 kV was undertaken.

Planning commenced to convert the Rangiora west area from a 33/11 kV to 66/22 kV network.

A new strategy for meeting urban growth developed using 66 kV sub-transmission and 11 kV
distribution networks, a level of transformation voltage which is optimal for large residential load
centres.
Table 20 Historical Development
The continuing trend of high growth requires new asset development well before assets are due for
renewal or refurbishment. MPNZ expects that demand growth and capacity upgrades will continue to
drive the lifecycle management plan with the main focus being continued development projects.
3.7.3 Supply Reliability and Quality
The existing network assets are required to provide a reliable supply of electricity at a suitable quality that
meets the service target levels adopted by MPNZ. The performance of the network compares well
against the reliability thresholds set by the Commerce Commission for SAIDI and SAIFI in 2003 (based
on the average of the 5 years prior) and were only exceeded in 2003, 2004, and 2006 due to extreme
events. New thresholds have now been recalculated to apply from 2010 based on the performance over
the period 2004-2009. The new value for SAIDI is 128.55 minutes (reduced from 147.24), and the new
value for SAIFI is 1.6 interruptions (reduced from 1.71). Although MPNZ is an exempt Electricity
Distribution Business (“EDB”) it is still necessary to calculate and maintain the data for disclosure and
comparison with other EDBs and for use in setting targets for reliability. Long-term trends of reliability
indices show that the network assets are being utilised more effectively to provide an increasingly more
reliable supply, as described in Section 4 in respect of service level performance and targets.
3.7.4 Capacity and ODV Network Optimisation
As shown by Commerce Commission’s 2004 regulatory valuation optimisation investigation, the MPNZ
network is close to the minimum necessary to provide the required capacity. An indication of potential
over design in the network is the amount of optimisation that was applied to assets in the most recent
audited valuation undertaken in 2004. The optimisation process examined stranded assets, excess
capacity and over-engineering. The valuation was undertaken in accordance with the Commerce
Commission’s ODV Handbook and was audited by PricewaterhouseCoopers. The current valuation
required no optimisation.
38
4
SERVICE LEVELS
4.1
Introduction
A key objective of asset management planning is to match the level of service provided by the assets to
the expectations of customers and other stakeholders. This is consistent with MPNZ’s vision and
corporate organisational objectives and goals as specified in Section 2 of the AMP. MPNZ’s SCI contains
specific target service levels for the first three years of the planning period which have been set following
consideration of the overall vision and corporate objectives, and following consultation with customers
and other stakeholders. The SCI objectives are consistent with the AMP target service levels for the first
three years of the plan.
MPNZ has initiated annual strategic reviews of actual performance against target (contained in Section 9
for the year ending 31 March 2011 period), and this combined with industry benchmarking and
consultation with interested stakeholders contributes to how service performance targets are set each
year.
For the purposes of this AMP, the key service criteria are listed below. These are consistent with the
asset management drivers, outlined in Section 2, and are also used to manage conflicting stakeholder
objectives as previously explained in that section of the plan.

Reliability of supply

Quality of supply

Safety

Customer service

Environmental protection

Economic efficiency.
These service criteria are used in the following ways:

to inform customers of the proposed service standards

to develop asset management strategies appropriate to that level of service

as benchmarks against which performance will be measured

to identify the costs and benefits of the service options assessed and offered

to enable customers to assess the suitability, affordability and equity of the services offered.
For the purpose of this plan, primary customers are electricity retailers and direct network customers.
Electricity retailers, together with customers, provide information directly to MPNZ to enable service
targets to be specified. In recognition of the fact that retailers cannot necessarily communicate levels of
service required by end-customers, particularly residential and commercial consumers, MPNZ also
engages directly with those customer groups.
The levels of service identified in this AMP also reflect current industry standards and legislative
requirements. Legislation establishes minimum mandatory levels of service (for example, health and
safety legislation) and service level reporting requirements. The strategic and corporate objectives of
MPNZ establish the scope of services offered and the extent to which service level targets exceed
mandatory minimums, where they exist.
Setting service level targets reflects MPNZ’s commitment to continual improvement, however service
level improvement is likely to plateau once the majority of customers are satisfied with service level
delivery. The levels of service will reflect changing customer expectations as further information on
customer and other stakeholders’ preferences emerges and in response to changing regulatory
requirements.
39
4.2
Service Level Definition
The key service level performance measures for the MPNZ network are defined in this section.
4.2.1 Reliability
Network reliability is determined by the quantity and duration of power supply interruptions.

System Average Interruption Frequency Index (SAIFI) measures the number of times that a customer
can expect the supply to go off.

System Average Interruption Duration Index (SAIDI) measures the number of minutes that a
customer can expect to be without supply each year.

Customer Average Interruption Duration Index (CAIDI) is a measure of the average duration in
minutes of supply interruption.
The Commerce Commission conducts a five yearly review of the quality thresholds for electricity lines
businesses. The SAIDI and SAIFI thresholds were last set in 2004 based on the average of the five
years prior (1999–2003), and apply to the 12 month periods through to 2010. Although MPNZ is no
longer subject to these thresholds from 1 April 2010, MPNZ will continue to monitor its performance as if it
were. The new reliability threshold targets from 1 April 2010 to 31 March 2015 will be a SAIDI of 128.55
minutes (reduced from 147.24), and a SAIFI of 1.6 interruptions (reduced from 1.71). These reflect a new
approach to setting reliability and include normalisation for extreme and normal variation in reliability
performance, based on the 2005 – 2009 reference period. Whilst there is no threshold measure for CAIDI
MPNZ still monitors CAIDI closely as CAIDI equals SAIDI divided by SAIFI.
4.2.2 Quality
Supply quality relates to the voltage delivered at the customer’s installation control point over the range of
loads that the customer has contracted for. Targets are specified in the Electricity Regulations and in
various industry codes of practice. The key parameters are voltage magnitude, level of harmonic
distortion and the level of interference. The performance measure for quality of supply is the number of
proven complaints originating from the MPNZ network.
4.2.3 Safety
Operating and maintaining an electrical network is inherently hazardous. Prioritising safety means
providing a safe reliable network and a healthy work environment. This will be achieved by ensuring
close working relationships between managers and staff through a high level of interaction, site visits,
positive feedback to staff, targeted contact for good behaviour, and by targeting those behaviours to be
reduced or increased. MPNZ also participates in industry related benchmarking of safety incidents to
provide a basis for measurement of our performance.
MPNZ uses four measures to monitor safety performance:
 the number of injuries to the public as a result of the MPNZ network

the number of injuries to MPNZ staff and monitored by rolling lost time injury frequency rates

the number of notifiable injuries in any one year

the number of near misses to MPNZ staff.
4.2.4 Customer Service
Since 2004, customer surveys have been undertaken annually which assess MPNZ’s performance from a
customer perspective. This information is used to develop an understanding of MPNZ's customers’
willingness to pay for improved reliability which is used when determining service level targets and
assessing alternative development options.
Customer service levels are measured as follows:

customer surveys which cover overall customer service and satisfaction and network reliability and
quality of supply

notification and response times to system interruptions
40

call centre availability.
4.2.5 Environment
Environmental performance reflects the number of environmental issues identified through the year and
the number of environmental complaints received from customers and the public.
Environmental performance measures used include:

the number of complaints of excessive noise from substation and distribution transformers

the number of environmental complaints from staff, the public, customers and other stakeholders

the amount of SF6 gas lost (as a percentage of total volume) if any

the number of uncontained oil spills

the number of times that the requirements of resource consents or territorial authority is exceeded.
4.2.6 Economic Efficiency
Economic efficiency reflects the level of asset investment required to provide network services to
customers, and the operational costs associated with managing the assets.
MPNZ discloses the following statistics annually in accordance with the Electricity Distribution
(Information Disclosure) Requirements 2008.

Load Factor = Electricity entering the system / Maximum demand x 365 x 24. This is a measure of
the average load compared with the maximum load over a year but is averaged over all GXP’s so
does not recognise the impact of high winter loads in one part of the system and high summer loads
in another

Utilisation factor = Maximum demand / Transformer capacity. This is a measure of how well the
assets employed on the system are utilised but calculated over all GXP’s and so averages the impact
of high winter loads in one part of the system and high summer loads in another. It also does not
recognise the reduction in low voltage distribution assets achieved by installing additional transformer
capacity

Loss ratio = Electricity losses / Electricity entering the system. Electricity losses represent physical
losses in lines and transformers, losses caused by un-metered or inaccurately metered supplies, and
errors due to the meter reading and billing reconciliation process. They are inevitable but MPNZ
considers that it is environmentally and economically responsible to ensure that system losses are
kept as low as reasonably practical.
The level of operational cost associated with managing the assets is indicated by operating costs per
circuit kilometre and operating costs per customer, or Installation Control Point (“ICP”). This is
supplemented by similar ratios for asset investment; capital costs per circuit kilometre and capital costs
per customer. These measures are industry standard measures disclosed by lines companies each year.
This allows MPNZ to benchmark its operational and capital costs against all lines companies in New
Zealand. MPNZ’s objective is to minimise expenditure while meeting the other service targets noted
above.
4.3
Service Level Measures
Table 21 overleaf summarises the service level measures defined by MPNZ for the purpose of assessing
asset management and electricity distribution quality of service consistent with each aspect of service as
defined above. The service targets are for the MPNZ network and exclude Transpower activities and any
associated Transpower service levels that may impact on MPNZ’s service performance. Service level
targets for the preceding 12 months are included in the table for reference. Actual performance against
the target is summarised in Section 9.
The remaining sections in this chapter set out the target levels of service for each measure for the
planning period, 1 April 2012 – 31 March 2021 and the justifications for the targets.
41
Strategic
Outcome
Reliability
Quality
Safety
Customer
Service
Environment
Economic
Efficiency
Measure
SAIDI
SAIFI
CAIDI
Faults/100km total
Faults/100km 66kV
Faults/100km 33kV
Faults/100km 22kV
Faults/100km 11kV
Faults/100km SWER
Total Interruptions
Number of proven complaints for:

Voltage

Waveform

Interference
Number of public injuries on MPNZ facilities
or due to MPNZ network issues
Number of OSH notifiable accidents
Number of near misses
Number of employee injuries
Average rating from customer survey

Deliverables

Overall Satisfaction
Number of complaints of excessive noise
from substation/distribution transformers
Number of environmental complaints from
staff or public
Percent of SF6 gas lost
Number of uncontained oil spills
Number of breaches of resource consent
requirements
Load Factor
Capacity Utilisation Factor
Loss Ratio
Capital Cost per km
Capital Cost per ICP
Operating Cost per km
Operating Cost per ICP
Measurement
Process
Network outage records
2012
Target
125
1.6
85
4.67
1.49
2.48
4.95
4.95
2.0
550
Complaints
SCADA records
Data loggers
Network and contractor
operational events
databases
< 20
<4
< 20
0
Based on service level drivers, past performance,
regulatory requirements, customer feedback for targeted
improvement, planned development and maintenance
programmes, climate and industry benchmarking. SAIDI
and SAIFI targets are approx 70% of the 2011 median
results for the industry.
Based on past performance, network standards,
benchmarking and customer feedback
Zero is the only acceptable target
0
0
0
Annual Survey
Complaints
Considerations When Setting Target
8.0
4.2
0
Based on past performance, regulatory requirements to
consult with customers and security standards
Zero is the only acceptable target consistent with the Code
of Sustainable Practice.
0
Gas pressure measurements
Reported incidents
Reported incidents
Power billing system
Financial records
<1 %
0
0
71.1%
21.5%
5.6%
$2,933
$384
$2,340
$306
Target is consistent with good industry practice
Based on past performance and benchmarking, consistent
with MPNZ’s Code of Sustainable Practice.
Table 21 Defining Levels of Service
42
4.4
Service Level Targets
Future service level targets are shown in the following table for the planning period, 1 April 2012 to 31 March 2022. It is expected that these targets are
achievable by MPNZ (with the exception of the impact of unanticipated extreme events such as a major storm or further earthquakes). Justification for each of
the targets is set out in the following section.
Strategic Outcome Measures
SAIDI
SAIFI
CAIDI
Faults/100km total
Reliability
Faults/100km 66kV
Faults/100km 33kV
Faults/100km 22kV
Faults/100km 11kV
Faults/100km SWER
Total Interruptions
Quality
Number of proven voltage complaints
Number of public injuries on MPNZ facilities
Safety
Number of OSH notifiable accidents
Number of employee injuries
Average rating from customer survey
Customer
Deliverables
Service

Overall Satisfaction

Number of excessive noise complaints
Number of environmental complaints from
staff or public
Percent of SF6 gas lost
Environmental
Number of uncontained oil spills
Number of breaches of resource consents
Load Factor
Capacity Utilisation Factor
Loss Ratio
Economic
Capital cost per km
Efficiency
Capital cost per ICP
Operating cost per km
Operating cost per ICP
2012-13
2013-14
2014-15
2015-16
2016-17
2017-18
2018-19
2019-20
2020-21
2021-22
125
1.6
85
4.67
1.49
2.48
4.95
4.95
2.00
600
<20
0
0
0
124
1.59
85
4.62
1.47
2.45
4.90
4.90
2.00
600
<20
0
0
0
124
1.58
85
4.57
1.46
2.43
4.85
4.85
2.00
600
<20
0
0
0
123
1.58
85
4.53
1.44
2.40
4.80
4.80
2.00
600
<20
0
0
0
123
1.57
85
4.48
1.43
2.38
4.75
4.75
2.00
600
<20
0
0
0
122
1.56
85
4.44
1.41
2.35
4.71
4.71
2.00
600
<20
0
0
0
121
1.55
85
4.40
1.40
2.33
4.66
4.66
2.00
600
<20
0
0
0
121
1.54
85
4.35
1.38
2.31
4.61
4.61
2.00
600
<20
0
0
0
120
1.54
85
4.31
1.37
2.28
4.57
4.57
2.00
600
<20
0
0
0
119
1.53
85
4.27
1.36
2.26
4.52
4.52
2.00
600
<20
0
0
0
8.0
4.2
0
8.0
4.2
8.0
4.2
8.0
4.2
8.0
4.2
8.0
4.2
8.0
4.2
8.0
4.2
8.0
4.2
8.0
4.2
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
<1 %
0
0
71.1%
21.5%
5.6%
$2,933
$384
$2,340
$306
<1 %
0
0
71.1%
21.3%
5.6%
$3,485
$451
$2,348
$304
<1 %
0
0
71.1%
21.1%
5.6%
$2,891
$370
$2,345
$300
<1 %
0
0
71.1%
20.9%
5.6%
$2,341
$298
$2,375
$302
<1 %
0
0
71.1%
20.7%
5.6%
$2,193
$277
$2,378
$300
<1 %
0
0
71.1%
20.5%
5.6%
$2,027
$254
$2,364
$297
<1 %
0
0
71.1%
20.4%
5.6%
$2,227
$278
$2,359
$294
<1 %
0
0
71.1%
20.3%
5.6%
$2,158
$268
$2,354
$292
<1 %
0
0
71.1%
20.2%
5.6%
$2,218
$274
$2,349
$290
<1 %
0
0
71.1%
20.1%
5.6%
$2,149
$264
$2,344
$287
Table 22 Service Level Targets 2012 - 2021
43
4.5
Justification for Target Levels of Service
4.5.1 Strategic Outcomes
MPNZ’s key business drivers are the desire to deliver superior service, ensuring security and reliability of
supply, and taking every opportunity to ensure that the Company is managed effectively and efficiently in
the best interests of customers and stakeholders. This is consistent with MPNZ’s overall corporate vision
to be the leading regional energy company in New Zealand. MPNZ places a high value on its relationship
with its customers and its local communities. MPNZ recognises that these relationships will be
strengthened through maintaining high levels of service.
MPNZ’s Corporate Organisational Objectives and Goals, previously outlined in Section 2 are consistent
with these strategic drivers and provide the framework for establishing service level targets in relation to
asset management. In this respect MPNZ determines its service targets consistent with these overall
objectives by considering the environment in which it operates and the wishes of customers.
4.5.2 External Environment
MPNZ’s wider operating environment is established by upstream electricity supply and transmission
delivery and relevant Government Policy Statement and regulatory bodies including the Electricity
Commission and the Commerce Commission.
Demand for electricity in New Zealand will continue to grow requiring new investment in generation.
MPNZ has been granted a resource consent for a wind farm at Mt Cass, and is investigating a mini hydro
site at Browns Rock on the Waimakariri and other wind and small hydro opportunities. MPNZ believes
there is scope to enhance local generation through adopting a more integrated perspective on network
asset management. Priority will also continue to be given to MPNZ’s warm homes programme and
energy audits for customers to manage demand.
The Electricity Industry Reform Amendment Act 2001 implemented a targeted form of regulation to be
applied to lines businesses under Part 4A of the Commerce Act 1986. Under this regime the Commerce
Commission sets price path and quality thresholds. The price path threshold applied to MPNZ from 1
April 2004 prevented line charges from increasing any higher than CPI-2% per annum when averaged
out. From 31 March 2010 MPNZ no longer falls under the Commerce Commission’s pricing and quality
threshold regime and is now allowed to self regulate due to its customer owned status.
MPNZ’s price path going forward will reflect the following objectives. MPNZ is a community/consumer
owned lines business and continues to determine its revenue requirement and therefore its line services
charges on the basis that lines revenue collected from its customers by way of these charges will be
sufficient to cover its operating costs and capital development, and to maintain its capital and/or revenue
resources at a level considered appropriate by the Board without recourse to term debt.
Line services revenues collected from customers under this policy that are considered to be surplus to
MPNZ’s revenue requirements are returned to customers in the form of rebates credited to their power
accounts.
MPNZ continues to adopt uniform line services charges for all customer categories within a particular
customer group, irrespective of customer density, the location of the nearest Transpower point-of-supply,
the configuration of and investment in MPNZ’s sub-transmission and distribution network, or other load
characteristics. Variable distribution and variable transmission line services are charged by way of a
uniform per kilowatthour charge in each customer group.
Similarly the quality threshold was set equal to the network SAIDI and SAIFI for the five year period
1999 – 2003 and required no deterioration against this historical benchmark. The regulatory reliability
threshold levels set for MPNZ through this period were 147.24 (149) SAIDI and 1.71 (1.75) SAIFI. These
also expired on 31 March 2010. Although exempt from the quality threshold from 1 April 2010, MPNZ has
assessed its quality limit, based on the Commission’s revised approach (which includes normalisation for
normal and extreme variation across the reference period 1 April 2005 – 31 March 2009) as 128.55 SAIDI
and 1.6 SAIFI.
44
4.5.3 Customer Demand for Service
While MPNZ strives to accommodate the expectations of its customers in its asset management
practices, there is limited information available on the value to customers of reliability, quality and
customer service, and in particular how these values can be incorporated into asset management
practices.
Since 2004 MPNZ has conducted annual customer surveys to assess service performance and to
improve MPNZ’s understanding of customers’ preferences, particularly in respect of the price-quality
trade-off. The 2011 survey was undertaken by an independent professional organisation and the key
focus of the survey was to ascertain among the various customer segments the following information:

the most important deliverable for customers

how customers rated the delivery of the most important deliverable

attitudes towards power interruptions

MPNZ’s performance in responding faults

the price versus quality trade off.
The survey is targeted at linking customer responses to asset management drivers. The number of
customers surveyed was 613. This survey was almost certainly influenced by the recent earthquakes, a
mid-August ‘polar blast’, the global economic downturn, and the impending rugby word cup.
Recommendations from the 2011 survey of customers’ views in respect of asset management planning
include:

MPNZ performed well during the recent external events and should continue to concentrate on
reliability and security, especially for commercial and major users.

The near 50/50 split in line charge preference for uniform versus segmented tariffs indicates more
due diligence and community discussion should take place before contemplating any change from the
status quo (uniform charging).

The loss of supply created by external events and the high profile restoration process has created an
environment where increased expenditure on network security would be more readily accepted.
Overall Customer Survey Results

The importance of reliability and quick response increased in 2011 with a subsequent decrease in
price being recorded.

Statistically significant increases in performance were recorded in five out of ten deliverables
measured, with no statistically significant decreases.

A small increase was recorded for overall satisfaction with MPNZ, with results trending towards very
satisfied.

Despite significant increases in both the frequency and duration of outages for the year, the increases
in outage satisfaction and with restoration time suggest customer awareness of the impact of
environmental factors and the ability to separate them from MPNZs performance.

An increase in MPNZ being recalled as the electricity fault service provider has been recorded over
the 2009 to 2011 period.

A small increase was recorded amongst those wanting an increase in reliability, and also amongst
those willing to pay more for it.

Preference was very slightly greater for uniform charging over user pays. This varied considerably by
customer group.

Increases were recorded from 2009 to 2011 in those definitely not willing to accept poorer quality for
a discount.

A small decrease was recorded in those recalling MPNZ safety messages although awareness within
the commercial rural group of tree trimming messages was still high.
45
MPNZ interprets the results from the 2011 survey as follows:

Current levels of power quality and reliability of supply are adequate in meeting the majority of
customers’ expectations however MPNZ should investigate any opportunity to improve reliability and
security at modest cost.

Current power quality and the associated level of complaints are acceptable

The majority of respondents are happy with the current levels of pricing

Although improvements in supply have been perceived by customers over the past 12 months,
Network investments via the Asset Management Plan (AMP) should continue to focus on addressing
issues of reliability and determining the level of reliability MPNZ will provide to each customer
segment.

If ongoing improvements in satisfaction levels are to be made, these should be quantified based on
the deliverables that will be improved/enhanced and the actions/initiatives that will be embarked on to
address them.

Communication of network upgrades and initiatives to maintain continuity and quality of supply should
continue to be undertaken on a customer segment by segment basis.
MPNZ offers the same line charges for similar customers across its North Canterbury network including
similar customers located in both urban and rural areas. The costs of supply however are greater for rural
areas, where Customer density is lower. This implies a level of cross subsidisation between urban and
rural customers. This is offset by the higher quality of service able to be supplied to urban customers
(due to network configuration and shorter response times) and the benefits to the wider community of
maintaining affordable supply in rural areas. In addition it is also noted that due to the interconnected
features of electricity networks it is almost impossible to provide differing levels of service to customers
located on the same part of the network. Thus accommodating individual customer needs (with the
exception of large industrial and commercial consumers with dedicated supplies) is not possible.
Alternative supply options have been constructed where possible to provide security consistent with the
needs of major customers. In addition, high priority customers are monitored, for example, where power
supply is essential for reasons of life support and higher levels of service are provided in these instances.
The majority of MPNZ’s supply area has experienced significant growth over the past ten years, much of
this due to residential subdivision, dairy farming and associated irrigation developments. This demand
growth has been met by MPNZ by investing in new or larger distribution feeders, new or larger zone
substations and larger Transpower GXPs. Inherent in this upgrade work is significant improvements in
system reliability, security of supply and quality of supply for a large proportion of MPNZ’s existing
customers. MPNZ also recognises that some specific customer segments have some concern over
system reliability and key initiatives have been planned over the next five years which are detailed in
Section 7.14.4.1.
4.5.4 Setting Reliability Targets
Reliability performance targets are derived from a combination of historical performance, network
analysis, benchmarking with other lines companies and customer consultation. In 2002 and 2006 MPNZ
experienced heavy snow events which gave rise to much higher than average SAIDI and SAIFI levels. In
2010 the Canterbury earthquakes caused even more outages. The intervening years have been fairly
consistent.
MPNZ benchmarks industry information on reliability to help establish future service level targets. Table
23 below shows MPNZ’s relative ranking for SAIDI and SAIFI against other like New Zealand lines
companies (those with 10 or less customers per km) for reliability performance for 2009, 2010 and 2011.
Even after the earthquakes, MPNZ’s 4 year average ranked it fourth for SAIDI and second for SAIFI.
Recent customer surveys have highlighted price and reliability as the key MPNZ deliverables and MPNZ
is comfortable with the levels of reliability through a period of high network growth with associated
planned outage requirements. Consistent with MPNZ’s vision to be a leading regional energy company in
New Zealand, MPNZ is committed to maintaining this level of reliability.
46
SAIDI
Alpine Energy
Buller Electricity
Centralines
Eastland Network
Electricity Ashburton
Horizon Energy
MPNZ
Marlborough lines
Network Waitaki
Northpower
Scanpower
The Lines Company
The Power Company
Top Energy
Westpower
SAIFI
2009
2009
Rank
2010
2010
Rank
2011
2011
Rank
2009
2009
Rank
2010
2010
Rank
2011
2011
Rank
201
249
199
243
337
133
146
250
69
254
6
9
5
8
12
2
3
10
1
11
332
302
133
312
186
140
140
284
64
132
13
11
3
12
6
4
5
9
1
2
4
3
13
10
7
6
2
5
1
9
2.2
2.2
2.3
3.5
1.5
2.4
1.8
2.8
1.5
2.4
5
5
7
13
1
8
3
11
1
8
14
7
14
13
293
210
463
279
10
7
14
8
7
9
5
13
8
4
12
14
1
3
2
10
6
15
11
1.7
1.5
4.9
3.4
2.3
2.2
1.3
2
1.1
3.3
285
210
915
383
226
289
192
341
263
177
338
423
61
135
104
297
209
440
331
4.3
4.1
10.9
3.1
12
11
14
8
2.6
2.9
4.2
2
10
12
14
4
1.7
2.1
4.7
3.5
2.1
2.4
2.9
2.8
0.8
2.3
1.6
3.7
3.2
4.9
3.7
3
4
14
11
4
7
9
8
1
6
2
12
10
15
12
Table 23 SAIDI and SAIFI for Like Lines Companies (<= 10 customers/km)
Individual feeder reliability history has been used as an indicator of expected future reliability. A five year
average is used to try to balance out the effect of one off events which would otherwise cause different
feeders to be the worst performing ones each year. The extensive feeder reconfiguration due to load
growth over 5 years plus the impact of previous reliability improvement measures makes historical data
useful as only one input to the assessment regime. MPNZ also calculates a feeder reliability index based
on the length of line, number of connected customers, line size, and downstream protection elements.
This helps identify those lines which are likely to be poor performers. This index, combined with the
historical data, is used to target expenditure on asset management improvements. These include
improved tree clearance, strengthening lines for higher snow loadings, the creation of shorter feeders with
fewer customers per circuit breaker, improvements to recurring problems such as opossum faults or bird
clashes and the relocation of poles to reduce the risk of vehicle accidents.
A majority of customers have indicated in annual surveys undertaken since 2004 that they do not want
reduced reliability in exchange for lower prices or improved reliability with higher prices. In 2011 there
was more willingness to pay for increased reliability. MPNZ has reported significant improvements in
system reliability due to the inherent effects of MPNZ’s capital works programme which, as noted above,
has largely been driven by growth.
Customers are generally not aware of this improvement because often the work occurs without their
knowledge and the improvements occur gradually over a long period of time. The potential impact of
upgrade projects and system reconfiguration on reliability is outlined with each project.
The reliability targets which are shown in Table 22 reflect gradual improvements over the next 10 years.
MPNZs main focus in the short term is in security. This is consistent with consumers’ current levels of
awareness of the need for security power supply following the earthquakes, but recognises the inherent
improvements in reliability of the distribution network which will occur as MPNZ completes its network
capacity and security upgrade programmes in response to new demand.
4.5.5 Setting Capacity Targets
The provision of capacity in the upper network is driven by historical customer load growth coupled with
maintaining MPNZ’s security level standards, (shown in the network development plan in section 7 of this
plan). MPNZ monitors the capacity of GXP stations and zone substations against their peak loadings and
also monitors the ratings of feeders against peak load.
The targets are set to ensure that sufficient capacity is always available over the entire forecast period,
consistent with customers’ expectations. Many zone substations have adequate capacity to meet
customer demand but not to comply with MPNZ desired security standards. Rectifying this is factored
into MPNZ’s expenditure programme. In order to meet this requirement and ensure sufficient capacity is
available MPNZ undertakes detailed demand forecasts on an annual basis, as set out in Section 6.
47
4.5.6 Setting Power Quality Targets
Power quality objectives are concerned with matching the performance of assets with the performance
customers expect and are willing to pay for. Quality targets reflect industry standards for acceptable
levels of voltage and harmonic distortion. Momentary fluctuations include surges, spikes, sags and dips
in supply voltage. MPNZ uses industry forums, historical experience and customer complaints to
determine what is acceptable or tolerable.
MPNZ aims to supply all customers with supply quality that meets or exceeds the regulatory standards
consistent with our vision to be the leading regional energy company in New Zealand. In order to achieve
this MPNZ designs and develops the network to maintain the voltage within the allowable +/- 6% at the
point of customer connection under all loading conditions. MPNZ employs monitoring equipment at some
of the zone substations to provide information on voltage and waveform fluctuations. MPNZ has initiated
a programme to also monitor harmonics at zone substations. Normal system switching operations
involving transfers of load are controlled so that system fluctuations are minimised.
A large proportion of power quality complaints are associated with problems in the customer’s own
installation. Voltage complaints are generally due to undersized customer service mains or installation
cables. Waveform problems are generally associated with harmonics being generated on a customer’s
installation by electronic equipment. While these are outside of MPNZ’s control, the code of practice on
limitation of harmonics can be used to ensure that other customers are not adversely affected. In recent
times MPNZ has carefully monitored the level of harmonics arising from new irrigation pump motors fitted
with electronic variable speed drives(VSD’s). These are a known cause of harmonic distortion in the
waveform. MPNZ has recently changed its connection standards to limit the harmonic currents of VSD’s
to less than 10% THD in an effort to maintain the system harmonic voltages within the code requirements.
An audit programme on irrigation pump motors will be commenced during 2012 to identify harmonic
generation and incorrect power factor correction applied.
Quality targets are set to reflect the impact of network investments over the planning period which may
have an associated impact on power quality, even if this is not the main driver for the investment. In
addition customer requirements and external influences are considered. The 2009 to 2011 customer
surveys sought customers’ views on the quality of their voltage, were their lights dim at night or were they
constantly popping light bulbs. Recent feedback from irrigator customers that their pumps are tripping out
has usually been proven to be due to undersized cables in their own installations.
Given customer surveys continually rate price and reliability above power quality concerns, MPNZ is not
targeting improved levels of power quality during the forecast period, other than those which emerge from
investments driven by other needs, and by controls on harmonic polluting loads as mentioned above.
The number of voltage complaints is expected to remain low even with the expected load growth.
4.5.7 Setting Safety Targets
MPNZ became certified to NZS 4801 standard in health and safety management in 2009. This initiative
has lead to the development of a number of additional safety systems for staff and the public and has
made MPNZ focus on the safety culture within the business at a practical level.
During 2010 MPNZ Field Services Staff participated in an industry wide Electricity Engineers’ Association
(EEA) safety culture pilot study which sought Staff impressions on criteria that affect their work safety.
These included staff training, provision of equipment and tools, communication, work planning and
Company policy. An action plan has been developed following the Staff feedback sessions which calls for
improvements in two way communication, job planning, hazard management, traffic management at work
sites, staff training initiatives, lone worker safety, drug and alcohol policies, and refinements to the
Company’s disciplinary process. A second follow up Staff survey was undertaken in late 2010 to measure
improvement.
Section 61A of the Electricity Act now states that by 2012 MPNZ must operate and have audited a Safety
Management System (SMS) that requires all practicable steps to be taken to prevent the electricity supply
system from presenting a significant risk to a member of the public or to property. Every SMS must
comply either with the requirements of NZS 7901 Safety Management Systems, or Electricity (Safety)
Regulations 49 and 50. MPNZ is accredited to NZS 4801 Health and Safety Management, ISO 9001
Quality Management, ISO 14001 Environmental Management, and ACC. An audit of these systems in
2010 also looked at MPNZ’s compliance with Electricity (Safety) Regulations 49 and 50 which set out the
48
requirements relating to operating an SMS, MPNZ passed this audit and intends to meet the more
detailed requirements provided by NZS 7901 by 2013.
The 2011 Customer survey included a section on safety which received the following responses.

Across all groups 46% of all respondents indicated they were aware of MainPower safety messages.
This is slightly below the 50% achieved in 2010.

Most respondents indicated they recalled these safety messages via signage, newspapers or through
mail/ with the power bill.

Across all groups most respondents stated that levels of safety messages were about right now,
noticeably, those not aware of the safety messages indicated that more could be done.

There are varying levels of awareness among groups of the responsibility to trim trees on their
property that are close to or touching overhead power lines.
MPNZ has interpreted this result as follows:

Continued focus on informing customers of tree trimming responsibilities is required as increased
efforts in the last year have not significantly changed results.

Safety messages should, at a minimum, continue at current levels. Additional and multiple channels
of communication should be considered for this exercise.
Our safety targets are set at no injuries, accidents or near misses. Although our historical performance
has not always achieved these targets, they are consistent with our objectives for zero tolerance of
unsafe work practices across the MPNZ organisation and for those with access to the equipment on our
network.
4.5.8 Setting Customer Service Targets
MPNZ’s connection agreement sets out the terms and conditions for delivery of line services to customers
for the conveyance of electricity. MPNZ uses customer feedback to ensure that customers’ needs are
reflected in service standards. MPNZ’s commitments to customers’ are to:

Treat customers with courtesy and respect, to listen to their views and at all times act reasonably in
dealings with them

Use all reasonable efforts to supply electricity that complies with all legislative requirements. The
supply of electricity and network services is subject to the Electricity Act 1992 (as amended) and any
regulations made under that Act

Inform customers of any interruptions necessary for planned maintenance or repairs to the network at
least 48 hours before by telephone, notice in writing, a notice in a local newspaper, or a combination
of these methods.
Consistent with customer feedback from surveys and direct engagement with customers during planned
or unplanned work or in response to queries, customer service targets are set to maintain the existing
level of service across the entire planning period.
Customers have indicated in customer surveys on power reliability that current levels of system reliability
are acceptable. MPNZ uses industry benchmarked security of supply guidelines in system planning and
design of the power system. More detail on the levels of security of supply is presented in section 7.4.
4.5.9 Setting Environmental Targets
Consistent with MPNZ’s Code of Sustainable Practice the only acceptable target for MPNZ for
environmental incidents is zero incidents. MPNZ has maintained certification to the international standard
ISO 14001 in environmental management for over ten years without any major corrective actions being
required. Therefore based on past monitoring of these systems and the development of environmental
design and monitoring policies over this period MPNZ is confident that a zero target for environmental
incidents is achievable. MPNZ has also adopted accepted industry standards for oil leakage and SF6
gas leakage.
49
4.5.10 Setting Economic Efficiency Targets
Economic efficiency targets are reflective of MPNZ’s network and load characteristics which are unique to
this network. The network reflects a balance of urban and rural customers spread out over a long and
narrow area with an even spread of farming and commercial customers, and pockets of high summer
irrigation load. The summer peak load is very similar to the winter peaks load but occurs in different parts
of the network. This means that while the average load factor is very good, the area load factors are not
and this has a large effect on global economic measures like transformer utilisation. The economic
efficiency targets are based on an extrapolation of historical performance along with industry
benchmarking to ensure that MPNZ at least maintains and if possible improves its relative industry
position against other similar lines companies. The achievement of these objectives is partly dependent
on the performance of other lines businesses.
MPNZ’s economic efficiency performance is therefore compared directly to other like electricity lines
businesses and targets are derived to place MPNZ in the top performing quartile of these lines
businesses.
50
5
RISK MANAGEMENT
5.1
Introduction
MPNZ has developed its risk management approach to ensure that risks associated with all asset
management processes are identified and managed in a systematic manner. This initiative is reflected in
the improvement plan set out in Section 9.
5.2
Risk Management Practice
5.2.1 Introduction
Risk management is central to effective asset stewardship and is particularly significant for the
management of an ageing asset.
The objectives of risk management include:

ensuring MPNZ is able to meet its service level targets

safeguarding public and employee safety

protection and continuity of electricity supply

fulfilment of legal obligations

efficient protection and operation of assets

protection of shareholder and commercial interests

preparation of contingency plans for foreseeable emergencies.
5.2.2 Risk Management Practice, Processes and Methods
MPNZ has conducted risk studies and analysed its exposure to major risks – focusing on natural hazards,
asset failure and compliance with the RMA. These studies have included co-operative efforts in
association with Environment Canterbury’s lifelines risk analysis, independent expert risk analysis and
internal analysis of risk from an operational perspective. In addition MPNZ’s IMS recognises the
Company’s responsibility for protecting the organisation, its people, assets and profits against the
adverse consequences of events and actions, by methodically addressing all risks surrounding our
activities, past, present and particularly future, with a view to ensuring that the group’s business
objectives are met. A strategic goal is to reduce or control liability arising from strategic risks, operational
risk, compliance risk, technology risk, financial risk and the effects of natural events.
An overview of these studies and risk assessments follow.
5.3
Exposure to Natural Disaster Risk
This section identifies MPNZ’s areas of major exposure to natural disaster within the North Canterbury
region. It provides detailed information on specific hazards and establishes a rating system to identify
those areas most at risk. Mitigation measures are included for identifying ways of managing the impact
for such risk.
Natural Disaster Hazards Identified
This study identifies a number of natural hazards with the potential to damage the major network assets
that affect the most customers, namely the 33 kV substations and the 33 kV transmission systems. While
the probability (frequency) of natural events such as flood and meteorological hazards far exceed that of
earthquake, it is the consequences of the risk of earthquake that most threatens the assets of MPNZ.
The events of 2010-2011 have focused community attention on these risks. Therefore the mitigation of
earthquake risk merits greatest consideration under this Asset Management Plan. The effects of climate
change on asset failure have also been considered and determined to be minor compared to earthquake.
51
Sea level rise along the east coast is not expected to cause major disruption to the electricity network.
Changing weather patterns may affect overhead line design policies with respect to the frequency of
snow storms and the variability of where snow may fall. However, the consequential damage is
considered to be minor and manageable.
5.3.1 Transpower GXP Stations
MPNZ is supplied by Transpower GXP stations at Kaiapoi, Southbrook, Ashley, Waipara, Culverden and
Kaikoura. No independent assessment of the exposure of these sites to natural hazards has been
completed. However, in relation to the risk of earthquake damage, Transpower has completed an
extensive programme of seismic damage mitigation. The September 2010 Greendale Earthquake has
provided MPNZ with some confidence that Transpower’s transmission system including towers and
stations can withstand earthquakes of the order of magnitude experienced in the Kaiapoi region during
the Greendale series of earthquakes.
5.3.2 Sub-transmission and Distribution Systems
A qualitative study on the impact of natural disasters on MPNZ’s sub-transmission and distribution
systems has been undertaken. This study identified earthquake as being of greatest risk to the subtransmission system. Three earthquake scenarios were considered for the network in their respective
zones of earthquake intensity.
A summary of the Average Damage Ratios derived is shown below, which represents a percentage of the
full replacement value of the assets.
1: 500 years
Line Asset
Subtransmission network
Distribution Network
Average Damage Ratio %
6.22
17.00
1: 200 years
Line Asset
Subtransmission network
Distribution Network
Average Damage Ratio %
3.21
9.82
1: 100 years
Line Asset
Subtransmission network
Distribution Network
Average Damage Ratio %
1.20
4.11
Table 24 Summary of Average Damage Ratios
While several sections of each system were assessed at a ratio above 10% under certain earthquake
scenarios, overall damage to the sub-transmission and distribution systems does not exceed 6.3% and
17.0% respectively under any of the three earthquake scenarios.
It is worth noting that during the September 2010 Greendale earthquake MPNZ had to replace
approximately 3km of distribution underground cabling in Kaiapoi representing less than 10% of the total
underground network in this area.
52
Table 25 below provides an assessment of other hazards to the sub transmission and distribution
systems. This reflects observations from publications such as the Canterbury Regional Council’s report
“Natural Hazards in Canterbury” reviewed against MPNZ’s overhead line design criteria”.
Hazard
Flood
Windstorm
Electrical
storms
Snow storms
Tsunami
Observations

The risk to overhead lines from flood hazard is very limited

Damage is restricted to isolated damage caused by
landslips and/or subsidence or damage to individual poles
sited within the normal course of a river.

Minimal damage is likely to be sustained even in a 100 year
flood event.

A 500 year event would result in extensive flooding of some
urban areas and subsequent damage to ground mounted
distribution equipment.

Damage to overhead lines is routinely caused by high winds

Historically this results in minor and isolated damage.

MPNZ’s design criteria meet or exceed the requirements for
a 50 year return period event as per AS/NZS7000:2010.

The most severe winds are orographical reinforced winds
from the north-west and these occurred in 1945, 1964, 1975
and 1988.

The peak wind speed of 193km/hr recorded in August 1975
exceeded the 100 year recurrence interval.

Average recorded wind speeds in Christchurch approach
45% of design speed on 54 days a year and 66% on only
three days a year.

Only four significant tornado events have been reported in
Canterbury in the last 25 years and none of these were
located in MPNZ’s distribution area.

Electrical storms are relatively infrequent in most areas of
the Canterbury region.

Over the plains there is an average of less than five thunder
days per year, increasing to twenty near the Alps.

Highest frequencies occur from September to March on the
plains and also occur in April and May inland.

Canterbury occasionally experiences weather bombs which
deposit heavy wet snow on overhead lines.

Higher inland areas can be subject to ice build up with
coincident wind loading which puts high loads on poles,
wires, aerials etc.

Isolated sections of overhead lines may also be exposed to
a theoretical risk of avalanche.

Tsunami hazards are uncertain; however it is recognised as
realistic for Canterbury.

There is a potential significant hazard at the mouth of both
the Waimakariri and Ashley Rivers, at Leithfield Beach,
Motunau, and at Kaikoura where the narrow continental
shelf and presence of submarine canyons makes this area
particularly susceptible, especially Goose Bay and Oaro.

The majority of overhead lines are not generally exposed to
this hazard.
Probability/Consequence

Probability Low

Consequence Low


Probability High
Consequence Low


Probability Moderate
Consequence Low

Probability
Moderate/High
Consequence Low



Probability Remote
Consequence
Insignificant
Table 25 Hazard Identification to Sub-transmission and Distribution Systems
5.3.3 Zone Substations
The following qualitative assessment techniques have been applied principally to measure natural hazard
exposures to zone substation assets. The assessment adopted a weighting factor to recognise the
relative strategic importance of individual sites. This was based on asset value, peak load and switching
diversity options.
The measures used to define risk factors and risk priorities are:
‘Probability’ (years recurrence) x ‘Consequence’ (% damage) = ‘Risk Factor’
‘Risk Factor’ x ‘Weighted Strategic Importance’ = ‘Risk Priority’
53
The assessment clearly identified earthquake hazard as a greater (comparative) risk. It is also
noteworthy that the overall (all risks) ‘Risk Factor’ is highest at those stations where no seismic damage
mitigation or upgrading programme has been completed to date.
MPNZ has had a programme in place to install seismic restraints at zone substations for a number of
years. Only the Marble Quarry (four pole platform substation), zone substation does not have appropriate
seismic restraint fitted and Marble Quarry supplies less than 10 ICP’s, has several spare transformers
available, and has been deemed unnecessary to restrain. Oaro will either be removed or upgraded
during 2014. Restraints are designed to the specification for Seismic Resistance of Engineering Systems
in Buildings NZS 4219 and its related Code of Practice for General Structured Design and Design
Loadings for Buildings NZS 4203 1992. A safety factor is built into designs so that equipment remains
functional in the advent of a natural disaster of this type. Table 26 shows details of the seismic restraint
programme to date.
Substation
Southbrook
Rangiora north
Cust
Oxford
Lochiel
Mouse Point (Culverden)
Amberley
Hanmer
Kaikoura
Hawarden
Cheviot
Greta
Leader
Oaro
MacKenzies Road (Waipara)
Marble Quarry
Bennetts
Swannanoa
Type
Pad mounted
Pad mounted
Pad mounted
Pad mounted
Pad mounted
Pad mounted
Pad mounted
Pad mounted
Pad mounted
Pad mounted
Pad mounted
Pad mounted
Pad mounted
Pad mounted
Pad mounted
4 pole structure
Pad mounted
Pad mounted
Seismic Restraints Status
Completed
Completed
Completed
Completed
Completed
Completed
Completed
Completed
Completed
Completed
Completed
Completed
Completed
Scheduled
Completed
Not Required
Completed
Completed
Schedule
2002
1994
2003
2002
1989
2003
2002
1996
1999
2010
2007
2007
2008
2014
2006
N/A
2001
2008
Table 26 Seismic Restraint Programme
For zone substations, flood also represents an identified hazard, certainly in terms of probability.
Generally due to the location and/or the resiliency of design zone substations are not rated as at risk of
significant damage, even possibly in very serious (1 in 500 year) flood events. Other hazards including
various meteorological events have comparatively high probabilities but are generally of insignificant or
only modest consequence when assessed as a risk to zone substations as summarised above.
5.3.4 Kiosks and Building Substations
The transformers installed within kiosk (steel) type substations prior to 1988 have not been bolted down
historically and are hard to retrofit due to difficulty in accessing their mountings. Transformer damage
during shock will be reduced due to its inability to move. It is likely that they will survive a moderate
earthquake satisfactorily because they are connected to flexible high voltage and low voltage cabling
systems and restrained from moving far by the sides of the kiosk housing. All transformers in building
substations and those installed in kiosks after 1985 are bolted down.
Building substations generally have free cable in cable trenches so that relative ground movement
between the building and the surrounding ground will can cause the cable to pull, and possibly fail, with
damaging the HV equipment. Kiosks and Berm mounted configurations often have the HV cables exiting
directly from the ground up to the equipment bushings. Any relative ground movement could cause the
HV bushings to be heavily stressed and fail. This is generally true for LV cables and switchgear also.
The transformers installed within kiosk (steel) type substations prior to 1988 were typically not bolted
down and are hard to retrofit due to difficulty in accessing their mountings. All transformers in building
substations and those installed in kiosks after 1985 are bolted down.
54
5.3.5 Cabling Systems
Experience following the impact of the September 2010 Greendale earthquake on the Kaiapoi region
shows that up to 10 % of the HV underground distribution cables were badly affected. Cables were
generally stretched and in some cases pulled apart by the ground shaking liquefaction style earthquake.
All of the cables damaged were older paper insulated lead sheathed types and it is expected that the
more modern cross linked polyethylene would fare better under these circumstances.
5.3.6 Communications / Control Systems
MPNZ’s voice and data networks have radio sites located at Mt Grey, Mt Cass, Mt Thomas, Mt Beltana,
Wallace Peak and Williams Spur. Mt Grey and Wallace Peak in particular are often exposed to heavy
snow. Snow can cause aerial damage and also loss of power. The sites have limited battery backup and
can sometimes fail before access is available for fault repair or battery replacement. MPNZ holds spare
equipment (including a voice repeater) for such emergencies; however, it is likely that it would take up to
a day to restore communications.
If the data network fails SCADA information is not available but, more importantly, load control ability,
which could be very important during a cold period, is also lost. In the worst scenario, if the public
telecommunications system including the cellular network has failed, then MPNZ could utilise a mobile
simplex voice frequency that exists between vehicles. Communications can be established by relaying
information through the simplex channel by strategically located vehicles and staff. MPNZ holds sufficient
local staff at or near remote sites to be able to manually operate the Company’s load management
system following simple instruction from the control centre. Without SCADA and communications, local
staff would take responsibility for operating and for restoring supply to customers via the Company’s
feeder circuit breakers.
The Company’s control centre is located on the first floor of the main office complex at High Street,
Rangiora. The office building was constructed in 1964 and has a number of internal reinforced concrete
columns that support the floors and ceilings. The control centre is strategically located away from the
daily operations on a south west wing. Detailed modelling of the seismic performance of the building has
revealed that it is significantly below current code requirements. This represents a significant risk to staff
and to the operational security of the power system. MPNZ has abandoned the building and relocated to
temporary accommodation on the same site. Plans are being prepared for a new head office site with
control facilities designed to exceed the new standards.
5.3.7 The Impact of the 4 September 2010 Greendale Earthquake
Major damage occurred to the MPNZ network in the Kaiapoi region following the 4 September 2010
Greendale earthquake. This earthquake registered magnitude 7.1 and was 12km deep centred around
the Greendale area. The earthquake affected power supply to 7,964 customers and at the end of the
power restoration work, 110 houses had been de-energised and 51 houses had been decommissioned.
Further earthquakes in 2011 have led to 860 houses being “Red Zoned” for demolition in Kaiapoi and a
further 80 in the neighbouring Pines and Kairaki Beaches. Much of the Kaiapoi commercial area has also
been closed. In early 2012 parts of the Rangiora commercial area have also been closed. The impact of
these closures and demolitions will be felt for years and add a large degree of uncertainty as to future
load growth and its location.
The damage occurred due to land movement and liquefaction. Fifteen 11kV 95Al PILSWA and two 185Al
PILSWA cable faults were sustained. Almost all high voltage cables in the worst affected areas are Al
PILSWA-PVC sheathed. The cable faults occurred due to sideways forces and stretching caused by the
land movement and often damage is seen over several metres around the immediate fault. One cable
failed on open circuit with no protection operation. Once it was ascertained that cable damage was
distributed and widespread and mainly in locations where significant ground movement had occurred, the
decision was made to completely replace sections of cable rather than fix faults. Approximately 3 km of
11kV cable has been replaced over eleven cable sections.
Several cables had been pulled back from the RMU switchgear they terminate on and had to be
excavated and eased, or reterminated. In one case the cable termination pulled 500mm clear of the
switchgear terminals while still alive and the consequential arcing damage required replacement of the
switchgear. Two ground mounted transformer pads also moved significantly putting excessive stress on
HV and LV cables. These required full replacement.
55
Low voltage cable damage has been minimal with approx. 100m requiring replacement. This was due to
breaks in two cores and this section also had direct joined service connections which reduced the repair
options.
The overhead network generally stood up well and was much faster to repair. Initial faults were due to
conductor clashes, poles leaning severely, two 100kVA transformer poles tipping over at Kairaki Beach,
conductors off insulators, and fuses broken. The majority of customers supplied from these overhead
lines had power restored on the 4th with the remainder on the following day. A number of heavy poles
including concrete poles and wooden transformer poles sunk in the ground and required immediate or
short term rectification. There was ongoing work for the next month straightening and repositioning lines
in areas of significant ground movement but this did not affect customer supplies other than for short
planned outages required for the work.
There has been continual work over the last 15 years upgrading zone substation transformer seismic
restraints. This was influenced by knowledge gained from the Edgecumbe earthquake. Mutual Aid
agreements between Lines Companies had been strengthened following earlier snow storms, and this
meant that MainPower was able to utilise additional staff, cable fault location equipment, and generators
from these companies.
The Kaiapoi HV cable network is well ring fed however the large number of faults in a relatively small area
meant that many adjacent sections were damaged and power could only be restored by using multiple
generators until much of the cable replacement was completed. Some of these were required for up to
fourteen days. Whilst power was restored to Kaiapoi reasonably quickly, the system security was
significantly affected for some months until all the main feeds into Kaiapoi were repaired. Relatively fine
weather and the significantly reduced load in the worst affected areas contributed to enabling
comparatively weak alternative feed arrangements being used to restore supply early.
A number of lessons have been learned from our restoration process following the earthquake and these
have been developed through staff debriefing sessions. These lessons will also be included in MPNZ’s
Business Continuity Plan. The lessons are as follows:
To make contact with families of all staff following a major event (earthquake\snow storm etc);
Provision of a phone number for use only by staff families;
Closer monitoring of staff field locations;
Provision of water reserves for staff;
Daily meeting of all staff to discuss outage area, customers affected, Network priorities for restoration,
priorities for the day, hazards that may be encountered, Supervisors to allocate resources to each area,
discuss any family issues, monitoring of work hours and fatigue, and monitoring stock levels.
5.4
Exposure to Physical Risk
An assessment of the major physical risks that the sub-transmission and distribution systems are
exposed to was carried out by an independent expert during 2005. The assessment identified the top
forty most significant physical risks using the methodology of NZS 4360: 1999. This study looked at
many risks including built environment hazards including accidental excavation, telemetry failure, water
ingress, vehicle impact, explosion and breaks in electrical connection. It also looked at potential risk from
wilful human behaviour and those from naturally occurring hazards including above and below ground
level rot, fire and plant and animal activity. The study assigned probability of occurrence scores and
consequence of occurrence scores that consider loss of supply, personal injury, damage to MPNZ or third
party property, environmental impact and over-run Transpower peaks.
The results from the study show the highest risk score of 308 to be from vehicle impact on a 33 kV pole in
the pole line feeding the Rangiora North zone substation, and the fortieth score of 168 to be vehicle
pollution affecting the Oaro zone substation. Comparing these risk scores with that of four other Lines
Businesses using the same methodology, MPNZ has the lowest risk score profile by a large margin.
MPNZ’s comparatively large number of GXPs and the small size of zone substations contribute to this low
risk score.
Of the top forty risks identified, seventeen had a risk score greater than 200. During 2007 a number of
these have been studied and reduced or mitigated and only eight having a risk score greater than 200
56
now remain. These are not risks MPNZ is able to readily manage. The top eight physical risks are
shown in Table 27.
Risk
Asset
Hazard
1
2
3
4
5
6
7
8
Rangiora North tee line (917)
Kaiapoi #3 (Hilton)
Kaiapoi #2 (Fuller)
Southbrook S17 (Flaxton)
Culverden GXP - Hanmer line (1222)
Culverden GXP - Hanmer line (1222)
Ludstone - Oaro line
Motunau - Omihi line
Vehicle impact
Accidental excavation
Accidental excavation
Vehicle impact
Gradual erosion of land
Landslip
Plant or animal activity
Vehicle impact
Risk Score
308
308
308
272
270
270
210
204
Table 27 Highest Ranked Physical Risks
5.5
Exposure to Asset Failure Risk
Asset failure can occur from age, wear, accident, inappropriate maintenance programmes and defective
equipment. Section 8 Maintenance and Renewals Plan details the routine testing, inspection and
maintenance of assets to mitigate the risk of failure and the Network Development Plan details capital
works aimed at improving reliability and rectifying identified issues. The following sections provide details
of the most likely causes of failure for different types of assets on the MPNZ network and systems in
place to reduce the impact of asset failures.
5.5.1 Zone Substations
The most likely types of asset failure in MPNZ’s zone substations would arise from protection failure, tapchanger contact faults, circuit breaker failure, bus-work failure and transformer failure, in that order.
Table 28 overleaf provides a discussion on each type of asset and how the impact of failure is further
mitigated.
57
Asset Failure
Protection
Tap-changer
contacts
Issues
 Typically caused by complex
under/over voltage protection and
transformer buchholz and intertrip
systems that are present on older
sites.
 Protection failure during paralleling of
feeders.
 Battery failure
 Tap changers have moving parts that
suffer from wear.
Circuit
Breakers
 Old circuit breakers and reclosers are
approaching their end of life and
become increasingly unreliable.
Bus-work
 Buswork can suffer from broken
insulators, fault current deterioration
and external influences.
 Sudden loss of a transformer bank
due to internal explosion.
Transformers
Mitigation
 These systems are simplified or removed when
convenient. There is an extremely low risk of damage
occurring to a transformer or to customer equipment
due to an under/over voltage event.
 Additional precautions and cross checks are now made
before any load transfer switching is undertaken.
 Routine monthly inspections of battery voltage are
made.
 Tap-changers are inspected regularly. Tap position and
voltage is continually monitored by the Company’s
SCADA system and in the event of a tap-changer fault
occurring staff can be deployed very quickly to fix the
problem. Spare contact parts are maintained on stock
for such an emergency.
 A replacement programme is underway on old circuit
breakers. All zone substations that have two or more 11
kV feeders have the ability to bypass one faulty circuit
breaker if necessary. In the event that a circuit breaker
fails at the remaining smaller rural sites, then it is a
simple procedure to bypass the faulted circuit breaker
as a temporary measure to restore power. The
sophisticated adjustable protection systems on new
circuit breakers mean that one spare circuit breaker can
be retained for multiple sites.
 Split bus systems and double banked transformers help
to provide some redundancy.
 A few spare emergency power transformers are kept on
stock for transformer failures. Some larger sites (i.e.
GXP’s, Southbrook, Kaikoura and Culverden have dual
transformer banks providing redundancy. Designs allow
for transfer of load between zone substations to provide
additional redundancy. One of the two 4/6 MVA
transformer banks at Kaikoura can also be removed for
use as an emergency spare on a short term basis.
Additional initiatives would be employed under a civil
emergency, neighbouring companies would be
contacted for spare transformers and diesel generation
sets would be employed where appropriate.
 Planned upgrade projects will improve cover for this
event.
Table 28 Zone Substation Asset Failure Mitigation
An additional mitigating technique is load control, which will be employed in the first instance using
MPNZ’s Decabit injection system. The reduction in load at zone substations during peak load or at critical
times will be employed in the first instance. Table 29 shows the amount of load control available on each
GXP station.
GXP
Southbrook
Kaiapoi
Ashley
Waipara
Culverden
Kaikoura
Available Load Control
assuming Water Heating on all day
5.3 MW
2.6 MW
1.3 MW
0.74 MW
0.74 MW
Available Load Control
assuming Water Heating off for 3 hrs
16.5 MW
8.1 MW
4 MW
2.3 MW
2.3 MW
Table 29 Available Load Control by GXP
In addition, during emergencies or network constraints in summer time, irrigation pumps are also
controlled and can be tripped to avoid total shutdowns.
58
5.5.2 33kV Sub-transmission System
The 33kV sub-transmission system between Southbrook and Waipara and between Waipara and
Kaikoura is capable of being used to transfer load either way and so offers an alternative supply to major
and minor zone substations located along this route. The same now also applies to the two 33 kV subtransmission circuits between Southbrook and Bennetts. For this reason any asset failure on these line
routes would only cause a short duration interruption while power is switched from the other supply.
Spare parts are carried in sufficient quantity to cover the most likely cause of asset failure including
conductor, insulators, poles and hardware.
All 33 kV radial lines to other substations do not have alternative supply, however, there are typically a
smaller number of customers involved and asset failures can be rectified quickly due to the availability of
spares. The Waipara Hawarden 33 kV line can be backed up by a 22 kV supply from Mouse Point for
most of the year.
5.5.3 Distribution System
Major 22 and 11 kV feeders are backed up by alternative supply routes. Where more than two major
feeders supply an area, generally each feeder is designed to carry a maximum of 75% of its rating. This
allows some spare capacity for backup. Where only two feeders are available then designs are based on
maximum loadings of 50% of their rating.
Major low voltage networks are designed on a similar basis to the distribution system. In urban areas low
voltage networks can generally be linked in emergencies so that supply can be maintained. Minimum
quantities of spares are held to cover faults and emergencies on the distribution network. This includes
critical larger items such as distribution transformers, switchgear, and poles. The most likely cause of
asset failure for overhead systems has been terminations and cross-arms and these are being addressed
in the maintenance plan.
Likely causes of asset failure in underground systems are termination and joint problems and excavation
damage. MPNZ has an ongoing plan for mitigating damage due to excavation which includes educating
contractors and the public about the existence of underground cables and free cable location services.
5.5.4 Main Towns
Supply to the main urban areas of North Canterbury, Kaikoura and Wigram is noted here because higher
numbers of customers can be affected by asset failure in these more densely populated areas. In the
event of asset failure alternative supply is employed to maintain supply to customers.
Town
Rangiora
Kaiapoi
Amberley
Cheviot
Culverden
Hanmer
Supply Options
 There is a high level of interconnection between all 6 feeders.
 Two feeders from Southbrook are capable of 9MW each, one 8MW, and one 7MW
 The two feeders from Rangiora North are capable of 4MW each.
 At peak times the network is capable of meeting load with one feeder out from each of
Southbrook and Rangiora substations.
 All 4 feeders have a high degree of interconnection and are capable of supplying 4 MW each.
 At peak times the system is capable of meeting the load requirements with one feeder out of
operation.
 Supplied from a combination of both the Broomfield and Balcairn feeders, using tie-points at
Douglas Rd and Greys Rd.
 Load can be shifted to MacKenzies Road and Rangiora North substation to ensure backup is
available.
 The town feeder can be supplied wholly from the North feeder through a tie-switch outside the
Cheviot substation.
 Currently has two main supply options via 22 kV supply from two feeders out of Mouse Point
substation
 Another 22 kV supply can be provided from Hawarden Substation to the south.
 Supplied from either of the Argelins or Scarborough feeders at all but the most heavily loaded
periods (typically winter holiday weekends).
 During these times heavy load controlling would be required to maintain supply to all customers.
 A new paralleling point to the east of the town gives greater supply security to the business
district.
59
Town
Kaikoura
Oxford
Woodend
Supply Options
 The Ludstone substation has four feeders that can supply into the Kaikoura town.
 The North and South feeders are lightly loaded, and can back each other up, or either of the two
town feeders.
 The Churchill Street and Town feeders are more heavily loaded, and require a combination of
feeders to take over supply without overloading a remaining feeder during peak times.
 There are multiple paralleling points and enough capacity in each feeder that the town can be
supplied from many combinations of circuits, with load control unnecessary.
 Most of the 11 kV distribution system in Oxford town is overhead so a fault can easily be isolated
and supply quickly restored to customers.
 All three feeders from the Oxford substation can be used to take over the town supply if
necessary.
 There is also an alternative supply available from Bennetts substation which can supply the town
area, however this is dependent upon the system loading which is high in summer due to
irrigation load.
 The main alternative supply is via the Waikuku feeder out of Southbrook substation.
 Woodend town can also be supplied during emergencies from the Kaiapoi substation but this
involves a phase shift across the Southbrook and Kaiapoi GXP stations.
Table 30 Supply Alternatives
5.5.5 Communications / Control Systems
Data radio, Voice radio, SCADA and load management systems have all been replaced or upgraded over
the last six years to modern software, hardware and system components with good parts availability, and
in some cases service contracts have been entered into with suppliers and service organisations. Critical
elements are held as spares in case of emergency.
5.5.6 Audit of Asset Failure Recovery Systems
During 2005 MPNZ’s asset failure recovery systems were studied by an independent expert for
soundness. The study considered the eight biggest asset failure scenarios based on impact on
customers and included zone substation transformer failure, feeder cable failure, major circuit breaker
failure and major line failure. Procedures to restore assets following failure are documented and remain
robust, however a number of recommendations were identified and are shown in Table 31. An action
plan to accommodate the recommendations has been developed and is included below.
Recommendations
Procure oil spill kits for any sites that do not yet have them if the risk is
considered great enough.
Action Plan
Oil spill kits have been put onto
contractor vehicles.
Ensure that the spare 33/11 kV transformers and one of the two
Kaikoura transformers remain available for stand-by use. Consider
moving the spare transformer to the sub most at risk of failure.
Spare transformers kept on stock
Spare 2.5 MVA transformer now located
at Hanmer
Consider constructing extra transformer pad and bus-work at remote
single transformer subs to fit dimensions of spare transformer.
The portable generator truck provides a
better backup facility.
Ensure sufficient spare lengths of 66 kV and 33 kV single-core XLPE
cable are stored at Rangiora – suggest minimum of 3 lengths each of
10m, along with 2 complete sets of jointing kits, 2 complete termination
kits, 6 jointing sleeves, 6 termination lugs and compression tool.
Jumper cable sets made up and stored
at Keir Street
Ensure sufficient spare lengths of 11 kV single-core XLPE cable are
stored at Rangiora – suggest minimum of 3 lengths each of 10m, along
with 2 complete sets of jointing kits, 2 complete termination kit, 6 jointing
sleeves, 6 termination lugs and compression tool.
Jumper cable sets made up and stored
at Keir Street
Ensure three spare 33 kV poles and arms are stored at each of Mouse
Point or Culverden GXP, Bennetts or Oxford, and Cheviot.
Minimum quantities of spares maintained
at Rangiora, some items stored at depots
Ensure spare 33 kV breaker and a reasonable array of spares for all
makes are held at Rangiora.
Spare 11, 22 and 33 kV CB held at
Rangiora
60
Recommendations
Ensure access is secured to 4x4 line trucks with Palfinger, hydraulic
post-hole borer and elevated platform.
Action Plan
All equipment owned by MPNZ and its
subsidiaries
Ensure cable fault location equipment is maintained in full working order
and is always available – possibly arrange with Connetics.
Contracted to Connetics
Prepare switching plans for restoring supply in the event of faults on
Cable S13 – S421, Fuller, Hilton, Waipara – Cheviot and Kaikoura –
Waipara lines. Include consideration of protection settings and any
phase differences.
This has been developed as refresher
training programmes for controllers
Secure access to an excavator to assist exposing faulted cables – could
be helpful to pre-arrange services with local contractors.
MPNZ owns sufficient excavators
Table 31 Recommended Risk Reduction Measures
5.5.7 Transpower
Transpower’s risk management plans for all of the North Canterbury Transpower GXP stations are shown
in Table 32. Recent upgrades has meant that MPNZ now has four 66 kV circuits supplying into the
southern region, two from Islington to Southbrook and two from Waipara down to Southbrook. This has
improved MPNZ’s security of supply into the largest load area.
Syste
m No
T3/T5
Site
Ashley
Culverden
Cooling
2 x 10 MVA 1Ø
ONAN
2 x 30 MVA 3 Ø
1 x 10/20 MVA 3 Ø
2 x 40MVA 3 ø
ONAN
ONAN
ONAN
OFAF
ONAN
ONAF
220/33
66/33
66/11
66/33
Nil (can interchange transformer with Waipara)
Kaikoura load can be supplied from Waipara via
MP network
ONAN
OFAF
ONAN
ONAF
66/33
Nil
66/33
Nil (can interchange transformer with Kaikoura)
Waipara load can be supplied from Southbrook
or Kaikoura via MP network
Kaikoura
T1
T1
T2
T1
Southbrook
T1/T2
1 x 10/16 MVA 3 Ø
Note: fans removed
Installed rating is
10MVA
2 X 30/40 MVA 3 Ø
Waipara
T3
1 x 10/16 MVA 3 Ø
Kaiapoi
Ratio
(kV)
66/11
Installed Capacity
Contingency Plans
Unit change procedure.
Kaiapoi spare transportation/installation plan
Spare bank at Islington
Nil
Table 32 Transpower Contingency Plans
5.5.8 Roading Authorities
Vehicle accidents on roads involving network assets are reported to Transit New Zealand or the
controlling road authority. In some cases of repeated problems in a particular area the controlling
authority has implemented physical roading changes to reduce the likelihood of accidents and in the
process reduce the risk of asset failure for MPNZ. MPNZ has also opted to relocate equipment at times.
MPNZ strives to place poles as far away as possible from the road verge to minimise risk to the public,
but this often conflicts with landowners who are not prepared to grant easements to overcome aerial
trespass caused by the lines overhanging their properties.
5.6
Risk Mitigation Measures
5.6.1 Introduction
Sizeable risks in today’s business environment are those that contravene the Resource Management Act,
the Health and Safety in Employment Act, and those risks that affect business continuity. During 1997
MPNZ achieved certification to ISO 14001 “Environmental Management Systems” and ISO 9001 “Quality
Systems for Production and Installation” standards. These management systems have encouraged
61
MPNZ to be active in ensuring legislative compliance is met and to seek continual improvement in our
systems.
MPNZ Directors put considerable emphasis on risk and continually monitors the Company’s exposure to
risk. Risk management and compliance is a permanent item on the agenda of the monthly meeting of
Directors. An audit committee made up of non executive Directors have well established and specific
duties of governance including looking at oversights of compliance with statutory responsibilities relating
to financial disclosure, and monitoring corporate risk assessment and the internal controls by annually
reviewing such things as accounting policies, treasury management policy, delegated authorities, and
appointment of external auditors.
Legal risk responsibility is assumed by Management using a comprehensive statutory compliance
checklist which is signed off on a quarterly basis. This is enhanced by having Bell Gully as legal counsel.
Political risk is identified as risk from Local Authority and Government Policy, and the electricity sector
has been subject to significant levels of regulation which is likely to continue. The appointment of a
Business Development Manager to the Company has ensured that MPNZ maintains a closer relationship
with local and Government policy, and are able to contribute to industry forums, submissions and help
guide decision makers in a better way.
5.6.2 Specific Development Projects to Mitigate Risk
The most important development strategy to mitigate risk has been the introduction of an integrated
management system comprising certification to ISO standards in Environmental Management and Quality
Management and certification to NZS 4801 in Health and Safety Management. Practical outcomes of the
work done on this system so far include:

A higher level of understanding of best practice management with line managers and the introduction
of additional staff training programmes focused on personal and public safety.

The introduction of dual certification on all applications for the livening of plant to ensure that all prelivening tests have been carried out.

A work completion certificate has also been introduced to ensure that all plant is in a condition to
operate safely and correctly.

A new regime of staff competency requirements has been introduced incorporating a higher level of
attainment required by MPNZ prior to staff being allowed to access MPNZ plant.

New programmes of regular staff refresher training on MPNZ work specifications and policies have
been introduced. Familiarisation training on equipment such as switchgear and protection systems
has been stepped up and is now incorporated into staff competency requirements.

Introduction of a Public Safety Management System.

Participation in the EEA staff safety culture pilot programme.
5.6.3 Specific Maintenance Programmes to Mitigate Risk
All of MPNZ’s maintenance programmes mitigate risk to various degrees, however worthy of mention in
particular is the maintenance programmes undertaken on those assets that would affect the greatest
number of customers following a single event. The details of the maintenance programmes are contained
in Section 8.
5.6.4 ISO 14001 and 9001 Policies
MPNZ maintains ISO systems in environmental and quality management, and these systems are
important for providing the following directions for management:

Policy

Legislative compliance

Sound planning and the establishment of Objectives and Targets

Responsibilities are assigned
62

Stakeholders are sufficiently trained or made aware

Staff are competent

Effective communication is maintained with stakeholders and interested parties

Operational control is maintained

Document control is maintained

Business continuity is maintained

Corrective action systems are maintained, monitored and measured

Audits are undertaken to ensure continual improvement

Management reviews are carried out.
5.6.5 Health and Safety
MPNZ maintains certification to NZS 4801 Health and Safety Management. Safety is determined by a
combination of:

Good asset design

Maintaining the assets to a safe level of condition

Safe operating and work practices.
The Health and Safety in Employment Act, the Electricity Regulations, the Building Act and the Resource
Management Act contain the framework for MPNZ’s safety related asset management. Incorporating
safety into asset design and asset maintenance is attained through the drivers outlined in earlier sections.
Safe operating and safe work practices are achieved in several ways.

MPNZ employ an authorisation system for personnel wishing to access network asset. This system
involves contractors and operations staff attaining a prescribed level of competency through training
and examination before being able to hold any access or entry authorisation. Competency and
certification is refreshed every two years.

As part of the network’s environmental and quality management system all employees are given six
monthly training in network hazards, legislative compliance, emergency procedures and health and
safety.

All work on MPNZ’s network is controlled using advance application systems and access requests.
This ensures that the work zone is correctly identified, sufficient notice is given to customers of supply
interruption, switching schedules are developed and checked, and that there is sufficient time
available for ensuring the safety of contractors.

Contractor work procedures are approved and monitored.

All health and safety incidents and issues are recorded in a corrective action database system and
monitoring is carried out to ensure that investigations are carried out where required, mitigation
techniques are employed where necessary and authorities are informed.
5.6.6 Emergency Response Plans
MPNZ has a number of emergency control procedures that have been developed over time. New
emergency control procedures will be developed and added to this library as we become aware of them;
an example of this has been the development of a pandemic influenza emergency control procedure.
Other emergency control procedures include for fire, earthquake, severe storm, flood, robbery intruders
and bomb threat, oil spill, hazardous or toxic substance release, and health and safety. MPNZ also has
control plans in place for many hazards which staff encounters in their daily work.
5.6.7 Network Contingency Plans
MPNZ has established contingency plans for electricity system asset failure and for failure of information
technology (IT) systems. Risk of asset failure is reduced through the provision of alternative backup
power supplies and in maintaining an emergency stock of spares. MPNZ’s maintenance programmes
also reduce the potential of asset failure through replacement and monitoring programmes. A portable
63
generator truck has been constructed to help provide an alternative power supply where a backup power
supply is not available through normal electrical configurations. Risk of failure to MPNZ’s IT systems has
been reduced through backup plans and systems. MPNZ staff can re-establish work from a number of
different sites employing backup IT systems.
5.6.8 Business Continuity Plan
MPNZ developed a business continuity plan in 2003 that helps to ensure minimal disruption following a
disaster. MPNZ has identified its critical business activities and processes and the types of events that
can cause interruption to them. The plan has assessed major risk arising from poor communications,
information technology systems, restoration of electricity supply during a natural disaster and following
asset failure, maintaining systems and staff resources during a pandemic and legislative non-compliance.
Included in the plan are the conditions and responsibilities for activating the plan, along with detailed
recovery procedures covering Civil Defence response, electricity distribution network recovery,
information system recovery and recovery from a pandemic disaster. The plan also includes a number of
appendices housing emergency control procedures, contact lists, emergency stock, operating
procedures, vital records and fallback procedures for load control, SCADA and communications. The
Plan is tested every twelve months to ensure that critical systems are reinstated successfully.
5.6.9 Insurance
MPNZ insures to reduce the financial effects of damage to assets following a major disaster. MPNZ
currently operates with the following insurances relevant to the network operation:

Public liability insurance of $20 million

Materials damage of $14.2 million on stations including zone substations, load plants and contained
structures

The remaining sub-transmission and distribution systems fall under MPNZ’s own self insurance
scheme.
64
6
DEMAND AND GROWTH
6.1
Introduction
This plan forecasts likely demand, at GXP and zone substation level over the next 10 years, recognising
that there is more certainty associated with projections in the short term. The AMP also recognises that
significant individual load developments are hard to predict and, in many cases, have to be
accommodated as they occur.
MPNZ’s approach to forecasting demand involves spreadsheet analysis of historical demands together
with knowledge of likely future developments. More complex mathematical models to forecast demand
have not been employed as MPNZ considers that the forecasting approach must balance the needs for
accuracy against the competing needs for reliability and usability.1
The strong growth in MPNZ’s size over the past 10 years reflects growing demand from households and
businesses, especially for new connections and line extensions for subdivisions, lifestyle blocks, irrigation
and dairying, in what has been one of the fastest growing regions of New Zealand. With the Canterbury
region accounting for around 15% of New Zealand’s total economic activity, second only to the Auckland
region, it has a significant impact on the national economy.
North Canterbury and Kaikoura, where MPNZ operates, may experience faster growth than some other
parts of the region with continued migration into these areas from Christchurch city as “Red” zoned areas
are vacated.
6.2
Factors Influencing Demand
The key sources of information used by MPNZ for demand forecasting are:

Population and household projections obtained from Statistics New Zealand and Local District
Scheme and Community Plans

Notified changes in land use designations

Known commercial, residential and industrial developments

Historical electrical demands

Non network solutions (such as demand management)

Extreme movements in temperature and rainfall where this impacts on peak demand

Changing economic climate.

Commodity prices (e.g. milk solids)
MPNZ generates low, medium and high demand growth projections. The impact of the factors listed
above on these projections is noted in the following paragraphs.
6.2.1 Population
Population statistics and forecasts for the period 2001 through to 2021 are shown for each District
Council in Table 33. Expected populations are based on Statistics NZ medium growth projections.
1
Forecast complexity needs to balance accuracy versus reliability and usability, with the risk of a complex forecast model becoming
unusable due to difficulty in data preparation and interpretation. A balance is also required between return and effort, and a forecast
of the next 24 hours should be more accurate than one for the next 10 years. In this situation the model is intended for long term
planning and a less complex model is adequate.
65
2001 Census
2006 Census
2011
2016
2021
% Change 2001-21
% Average annual 2001-11
Waimakariri
36,900
42,834
46,100
48,900
51,600
35.2 %
1.8%
Hurunui
9,885
10,476
10,900
11,200
11,400
12.9%
0.7%
Kaikoura
4,401
4,884
5,751
7,720
8,270
137.4%
6.1%
Table 33 Forecast Population Growth
The Waimakariri District Council includes the Oxford, Cust, Rangiora, Woodend and Kaiapoi areas. It is
estimated that by 2016, 75% of all residents will live in the eastern part of the district within easy
commuting distance from Christchurch. Rangiora, Kaiapoi, Woodend and Oxford are being encouraged
to expand in the District Scheme Plan. Statistics New Zealand expects the population in the Waimakariri
District to reach 51,600 by 2021 or an average annual growth of 1.8 %. The Council’s planners believe
that, given a number of known proposed developments following the earthquakes, the district’s population
is likely to track well above the medium projections and to reach 50,000 by 2013, and 60,000 by 2022.
The Hurunui District Council covers Ashley in the south to Conway Flat in the north and the Lewis Pass in
the west. The main population centres are Amberley, Cheviot, Waipara, Waikari, Hawarden, Culverden,
Waiau and Hanmer Springs. Main growth areas are Hanmer Springs, which is a well known tourist and
holiday location, and the area south of Amberley town down to Ashley. There are an increasing number
of vineyards being developed in the Waipara and Amberley region along with associated tourist activities.
Statistics New Zealand expects the population in the Hurunui District to reach 11,400 by 2021or an
average annual growth of 0.65%.
The Kaikoura District Council encompasses the areas north of the Conway River (except Conway Flats)
up to Kekerengu and west to the Inland Kaikoura Range. The main population centre is Kaikoura town
with smaller settlements dotted along the eastern coastline at Oaro, Goose Bay, Puketa, and Rakautara.
Growth is occurring in the Kaikoura town, Puketa, Oaro and Goose Bay driven predominantly by tourism
and holiday homes. Tourism in the Kaikoura region is growing at around 8% per annum. Statistics New
Zealand believes that the population in the Kaikoura District will reach 8,270 by 2021, which equates to
an average annual growth of 6.9 %. This seems quite optimistic.
6.2.2 Land Use Changes
MPNZ monitors land use changes by receiving notification of all territorial plan changes. Recent major
land use changes include rural land around Rangiora, Woodend and Kaiapoi being rezoned as
residential; and residential land at Amberley town being rezoned to commercial. The extent of higher
density residential development allowed by the district plan around Mandeville has also been recently
notified.
6.2.3 Known Major Load Developments
The economic downturn has slowed developments and subdivisions at the start of last year, however
earthquake replacement housing in around Rangiora and Kaiapoi has been ramping up through the year
and is expected to peak over the next two years. New irrigation and downstream dairy farming continue
to provide growth along the Waimakariri River.
The Pegasus township development of approximately 2,000 lots located between the coast and Woodend
has now been almost completed apart from the last few stages of the development. Whilst the downturn
slowed Pegasus during 2010, growth has started to pick up again post earthquake. Completion of the
residential areas of Pegasus is expected in 2013. The rate at which these lots are built on and the extent
of any commercial development is highly uncertain.
ECAN’s clean air policies in Rangiora and Kaiapoi have been expected to cause a rapid change in
heating loads to the GXPs. Their slow delayed implementation has meant and the changing social
attitude to heating has meant that many homes have been installing heat pumps for the last 5 years and
there is unlikely to be a sudden surge in the future. The Red Zoning of much of the older part of Kaiapoi
66
has removed these as potential load increases due to conversion. The new housing in Rangiora and
Kaiapoi will be predominantly electrically heated but with the advances in housing energy efficiency, the
after diversity maximum demand for a house is not expected to increase. MPNZ now expects these
policies to have minimal impact on loads and have not factored such increases into MPNZ’s demand
forecasts.
Irrigation development continues to ensure high rural growth for the Waimakariri District Council area.
The conversion of the Eyrewell Forest area to dairy farms will have a significant impact on MPNZ capacity
provision in this area over the next ten years. Lifestyle block subdivisions throughout the Waimakariri and
Hurunui Districts have picked up following the downturn.
A new town centre plan for Amberley based around a supermarket could have a significant impact on
Waipara over the next 3 years, although load will be transferred from Waipara GXP to Ashley GXP over a
similar period.
Irrigation is also continuing in the Culverden basin and the conversion of the Balmoral Forest area to
dairying will maintain this growth.
The Kaikoura and Hanmer regions have not experienced the expected significant growth in for 2011 due
to the economic downturn. Housing construction has slowed considerably in these areas. No specific
additional future developments for these regions are included in the demand forecast scenarios; however
additional load growth associated with the recent developments is factored into the high scenario.
There are no other major load developments included in the demand forecasts under any of the
scenarios.
6.2.4 Historical Data
The sales of energy to MPNZ’s customers has increased 5 % per annum on average since 2000 (Figure
27). In order to meet this demand significant investment has been made in additional capacity on the
MPNZ network. The graph excludes electricity sales to the Daiken MDF plant at Ashley which typically
purchases a further 65 GWh’s.
Annual Energy Sales (ex Daiken)
500,000
450,000
MWhrs
400,000
350,000
300,000
250,000
2000-01 2001-02 2002-03 2003-04 2004-05 2005-06 2006-07 2007-08 2008-09 2009-10 2010-11
Year
Figure 27 Historical Yearly Electricity Consumption
67
The following charts illustrate the historical daily demands at each GXP station from 2000 onwards and
demonstrate the extent to which load growth is a factor at each GXP. This is the primary source of data
used for the medium scenario demand forecast.
Kaiapoi GXP Daily Peak Demand (1 Jan 2000 to 31 December
2011)
Kaiapoi has a classic winter peaking load
profile dominated by urban areas.
There has been strong historical growth on
the Kaiapoi GXP until the 2010/11
earthquakes. The fall in load from “Red
Zoned” and damaged houses and
businesses has been offset by the transfer
of some load area from Southbrook. More
load will be transferred in 2012 and new
fast tracked subdivisions will continue to
grow the load for the next 5 years.
25000
23000
21000
Peak Demand (kW)
19000
17000
15000
13000
11000
9000
7000
5000
Date
Figure 28 Kaiapoi GXP Daily Load Peaks
Southbrook GXP Daily Peak Demand (1 Jan 2000 to 31 December
2011)
42000
38000
Peak Demand (kW)
34000
30000
26000
22000
18000
14000
10000
Date
Figure 29 Southbrook GXP Daily Load Peaks
Ashley GXP Daily Peak Demand (1 Jan 2000
to December 2011)
The Ashley GXP is dedicated to the
Daiken NZ fibre board mill and demand
has been falling since the late 1990s.
MPNZ proposes to upgrade this GXP and
supply additional regional load from winter
2014. This will also provide more security
for Daiken.
12000
10000
Peak Demand (kW)
The Southbrook load profile is still winter
peaking but a clear smaller summer peak
is filling in the troughs. The apparent fall in
load in 2011 is due to the transfer of some
load area to Kaiapoi and a very wet mild
start to summer. Urban growth is expected
to accelerate for the medium term as
subdivisions are fast tracked to provide
housing for earthquake displayed people.
Irrigation related growth is approx 750 kVA
per annum. The planned Rangiora West
66kV conversion will reduce GXP load
from 2015.
8000
6000
4000
2000
0
Date
Figure 30 Ashley GXP Daily Load Peaks
68
Waipara 33 Daily Peak Demand (1 Jan 2000 to 31 December
2011)
Since December 2007 the Waipara 33kV
bus has only supplied the Amberley and
Hawarden areas. These areas have
traditionally had low growth. There has a
small amount of irrigation load growth
north of Hawarden.
14000
Peak Demand (kW)
12000
10000
8000
6000
4000
2000
0
Date
Figure 31 Waipara 33kV GXP Daily Load Peaks
Waipara 66 Daily Peak Demand (1 Jan 2000 to 31 December
2011)
14000
From December 2007 the Waipara 66 kV
feeder has supplied the Cheviot 66 kV line
heading north including the MacKenzies
Road substation. There has been little
growth recorded in this area except for
small irrigation developments.
Peak Demand (kW)
12000
10000
8000
6000
4000
2000
0
Date
Figure 32 Waipara 66kV GXP Daily Load Peaks
Culverden GXP Daily Peak Demand (1 Jan 2000
to December 2011)
20000
18000
16000
Peak Demand (kW)
14000
12000
10000
8000
The Culverden GXP has been
experiencing some winter growth from
Hanmer and continual summer growth
from dairy farming and associated
irrigation. Irrigation related growth is
expected to continue at approx. 750 kVA
per annum for the next 5 years.
6000
4000
2000
0
Date
Figure 33 Culverden GXP Daily Load Peaks
69
Kaikoura GXP Daily Peak Demand (1 Jan 2000 to December
2011)
The Kaikoura GXP has also had low but
steady growth caused by tourism and
commercial growth in the district however
the global economic downturn has
curtailed this. The Leader and Claverley
areas have also been switched to the
Waipara GXP in recent years.
10000
9000
8000
Peak Demand (kW)
7000
6000
5000
4000
3000
2000
1000
0
Date
Figure 34 Kaikoura GXP Daily Load Peaks
Zone Substation and distribution feeder loadings have been captured by MPNZ’s SCADA system since
1997. This data is useful in assessing the actual instantaneous peaks, whereas the metered energy data
from the GXPs measures an average sum of demands over the half hour. In practice the instantaneous
peak can be substantially higher than the half hour values.
6.1
Impacts of Non-Network Solutions (Demand Management)
6.1.1 Ripple Injection systems
MPNZ owns five static ripple injection plants and all of the receiving relays located at customer
installations. MPNZ uses these systems to manage peak demand to maintain acceptable voltage, to
alleviate network constraints, to defer capital investment and to reduce transmission charges. Other
initiatives under consideration are tariff restructuring to encourage night load. Irrigation load can also be
controlled during emergencies or at times of system constraints.
The recent introduction of the Upper South Island load control system has resulted in Transpower having
a very flat load profile for the upper South Island. It has also meant that overall MPNZ has required less
controlled time off to reduce transmission charges.
Additional constraints are being added to ensure that individual GXP and zone substation peaks are also
managed. In particular the Southbrook Zone substation load will be actively managed from winter 2012
onwards to maximise security (managed to achieve N-1 loading whenever possible). The Kaikoura load
is also limited with load control during maintenance outages of Transpowers 66 kV line. At these times
MPNZ’s 66 kV / 33 kV coastal backup line is unable to transmit the normal daily peaks.
6.1.2 Time of Use Metering
The introduction of time-of-use metering for residential customers will encourage customers to shift their
demand when electricity prices are high at times of system peak or system constraint. MPNZ will
continue to encourage Electricity Retailers to install time of use metering however for the purpose of the
demand forecast historical trends are the primary source of information and no adjustment is made for
any potential material impact on future demand as a result of time of use metering initiatives.
6.1.3 Demand Side Management
Demand side management involves measures to alter the electrical load of a power system in order to
operate it in a more efficient and economical way. In 2004, MPNZ embarked on a programme to
implement a number of demand side management initiatives.
70
To date, the benefits of implementing this programme have included:

Reduction in peak loads on the network

Reduction in costs associated with Transpower peak charges and network capital avoided costs

Providing customers with opportunities to reduce their energy costs

Demonstrating a commitment to energy efficiency

Making a contribution to the local community

Raised awareness of MPNZ in the community.
MPNZ’s demand side management programmes are summarised below.
Programme
Warm Homes
Energy Audits
Eco Light Bulbs
Education
2005-06
152 retrofits
60,500
-
2006-07
73 retrofits
1 customer
9,300
-
2007-08
161 retrofits
-
2008-09
121 retrofits
6 customers
Nil
4
2009-10
255 retrofits
8 customers
Nil
-
2010-11
100 retrofits
Nil
-
2011-12
100 retrofits
2 customers
Nil
6
Table 34 Summary of Demand Management Programmes
Details of MPNZ’s planned demand management initiatives are summarised in Section 7. The initiatives
undertaken to date have impacted on peak loads at each GXP. It is expected that these trends will
continue for the purpose of the demand forecasts.
6.2
Embedded / Distributed Generation
MPNZ has had its resource consent application for an approx. 60 MW wind farm on Mt Cass approved.
The final size of the wind farm will depend on the financing arrangements and the optimisation of
purchasing and construction costs. Several turbine options are possible. It is expected that any output will
be grid connected at the Waipara GXP and is assumed to have no impact on MPNZ’s future demand.
Smaller staged embedded connection options may be considered.
Up to 8 MW of hydro at Browns Rock off the Waimakariri River is likely to be developed by 2014. This will
be mainly winter generation and have little effect on the network capacity which is currently being
strengthened for the summer peaks.
Meridian is investigating several options for generation off the Waiau river which again will not be
coincident with the network peaks.
6.3
Forecasting Method
6.3.1 Summary
The following is a summary of the methodology adopted to forecast peak electricity demand at each GXP
to 2021, measured in kW.
Historical growth trends in peak demand are used and are extrapolated to the future. The primary sources
of data are the daily peak loads and loads at 4 am, 10 am and 6 pm, from 1 January 2000 to
31 December 2011. Existing policies and historical trends for population growth, economic activity,
climatic conditions, demand side initiatives and zoning developments are inherent in the historical load
data. Thus to the extent that these are consistent with future expectations they form the most appropriate
basis for projecting future demand. The impact of known major future developments and planned
transfers of load between GXPs are estimated and incorporated as documented in the plan. The
population forecasts provided by Statistics New Zealand provide a sense check on the forecast outcomes,
although the rapidly changing post earthquake environment limits the validity of these forecasts.
The three demand scenarios considered for the purpose of asset management planning purposes are:
71

The Medium Growth forecast, based on historical demand trends which include worst-case cold spells
by extrapolating from a base period which includes the cold winters of 2001, 2006, and 2011.

The High Growth forecast adopts all of the assumptions of the Medium Growth scenario plus
additional major expected new load developments.

The Low Growth forecast adopts all of the assumptions of the Medium Growth forecast but applies
reduced rates of growth reflecting potential sector wide economic downturn.
The load forecasts assume that existing future network planning is included where these reflect planned
changes to the network configuration and transfers of load to manage identified network constraints.
6.3.2 Medium Growth Scenario
The Medium Growth Scenario takes into account historical trends and projects them to the end of the
planning period, adjusting for load switching where relevant. Particular features of this scenario are:

The Kaiapoi GXP has also taken over supplying some of the Woodend region over the past two years.
A further 2 MW will be transferred from Southbrook 11 kV in 2012 and 2 MW in 2013.

4 MW of load is planned to be transferred from Southbrook 11 kV to an upgraded Ashley GXP before
winter 2014.

A new GXP is planned to be built at Rangiora East and commissioned in 2016 under medium growth
predictions and supplying the Woodend region. It will take 2.5 MW of load off the Southbrook 33kV
and another 5 MW from Kaiapoi 11kV in 2016. The timing of this project is highly dependent on load
growth within Pegasus and the surrounding Woodend area which has been very difficult to predict and
is subject to many external factors.

Southbrook GXP and Kaiapoi GXP peak load figures mainly occur during winter evenings. It is
assumed most of the growth will be from residential and commercial customers consistent with this
load profile.

There were mild winters between 2001 and 2005, and for Southbrook 33 kV and Kaiapoi 11 kV this
resulted in slower growths than underlying increases in peak demand due to economic activity or
demographics, which is critical for forecasting for network planning. Extrapolated growth rates are
therefore based on average increases between the comparable winters between 2001, 2006, and
2011.

The Ashley GXP is currently a sole-supply to the Daiken NZ manufacturing plant. The peak loads
reflect levels of production at Daiken NZ. The current trend is slightly downwards but for forecasting
purposes the extrapolated growth rate is assumed to be zero.

Culverden 33 kV and Waipara 33 kV & 66 kV loads peak during summer. It is assumed load growth
contributed by irrigation customers will continue to dwarf that of residential and commercial customers,
consistent with this seasonal load profile.

Kaikoura 33 kV peak load figures are spread across all seasons and mainly occur in mid mornings. It
is assumed growth will be primarily contributed by commercial customers due to tourism, consistent
with this load profile.
6.3.3 High Growth Scenario
The High Growth scenario incorporates known proposed major development projects in addition to the
assumptions incorporated in the Medium Growth scenario. Particular additional features of this scenario
include:

New housing construction in the Pegasus town development has been slower than originally
anticipated. There is still an expectation that Pegasus will introduce 7 MW of load into the MPNZ
network at some stage. Between 2012 and 2016, it is assumed that there will be 1 MW of new load
each year from Pegasus, supplied from the Kaiapoi GXP. From 2016 onwards, it is assumed the new
Rangiora East GXP will take the total 5 MW for Pegasus from Kaiapoi. The further 3 MW load from
Pegasus expected to be introduced between 2016 and 2022 will be supplied from Rangiora East.
72
6.3.4 Low Growth Scenario
The Low Growth scenario modifies the Medium Growth predictions to reflect potential sector wide
economic downturn. It is assumed that any GXPs dominated by residential load will reduce their rate of
growth by 25% compared to the Medium Growth scenario. For GXPs dominated by non residential
demand, the rate of growth is reduced by 50% compared to the Medium Growth scenario.
6.3.5 Accuracy
The forecasting methods employed are valid for use in determining upper network capacities, i.e.,
transmission, GXP substations, sub-transmission and zone substations. Generally this level of planning is
adequate to provide sufficient spare capacity for expected growth and customer driven projects that are
less than 0.5 MW. Typically where customer driven projects greater than 0.5 MW occur, system
reinforcement is required on the 11 kV network and occasionally at the zone substation, especially in rural
networks. Therefore customer initiated projects that add large loads and that are for the most part
unpredictable have the greatest impact on the impact of future load forecasts and requirements for system
reinforcement.
The variability of the weather can also affect the accuracy of any forecast. North Canterbury appears to
experience an extreme cold winter or dry summer every 5 years. To the extent these have already been
reflected in historical demands, they are reflected in the forecasts. Unforeseen future trends are not.
MPNZ’s historical demand data measured at the GXP level is reliable, as half hourly demands have been
accurately measured at these sites for many years. The historical trends collected from 11 kV feeders will
contribute towards more accurate load forecasting over time.
6.4
Load Forecasts
6.4.1 North Canterbury Load Forecast (including Kaikoura)
MPNZ will control individual GXPs during periods of network constraint and for system emergencies
however the upper South Island peak load is now being used by Transpower to calculate transmission
charges. The charges are based on MPNZ’s coincident GXP loads at the time that the upper South Island
is running a peak. This pricing methodology, introduced in 2008, means that MPNZ is also interested in
controlling the North Canterbury peak load as a total load rather than by individual GXPs for the purpose
of minimising transmission charges. Table 35 shows the forecast North Canterbury total system peak
loads for the planning period. Actual peaks recorded at the time of upper South Island system peak will
be lower due to higher levels of load control to be used at these times, and the natural level of load
diversity amongst the participating networks. These loads assume severe winter and dry summer
conditions.
Summer
Winter
2012
2013
North Canterbury Forecast Peak Load (MW)
2014
2015
2016
2017
2018
2019
2020
2021
2022
97
101
101
104
105
110
130
128
136
131
140
134
144
137
109
114
114
119
118
122
125
125
Table 35 North Canterbury Forecast Load
6.4.2 GXP Load Forecast
The following charts illustrate the expected demands at each GXP until the end of the planning period
under each of the High, Medium and Low Growth scenarios.
73
Peak Demand Forecast for Kaiapoi
35
Peak Demand (MW)
30
High
Growth
25
Medium
Growth
20
New Rangiora East GXP with
reversal of Woodend & Pegasus
transfer
Woodend & Pegasus
load transfer from Sbk.
15
Low
Growth
10
5
2022
2020
2018
2016
2014
2012
2010
2008
2006
2004
2002
2000
0
Year
Figure 35 Demand Forecasts for Kaiapoi
The Kaiapoi GXP requires a feeder circuit breaker upgrade to allow the full Woodend and Pegasus loads
to be picked up.
Peak Demand Forecast for Southbrook 33 kV
50
45
40
High
Growth
Peak Demand (MW)
35
30
Medium
Growth
Woodend load transfer
to Kaiapoi
Low
Growth
25
Rangiora West
66kV commissioned
20
Loburn load transfer
to Ashley
15
10
5
2022
2020
2018
2016
2014
2012
2010
2008
2006
2004
2002
2000
0
Year
Figure 36 Demand Forecasts for Southbrook
The Southbrook GXP has reached the full load of one bank. Load will be reduced over the next 2 years
by transfer to Kaiapoi, and then greatly reduced by the conversion of the Rangiora West 33kV to 66kV.
74
Peak Demand Forecast for Ashley
25
Peak Demand (MW)
20
Medium
Growth
15
Low
Growth
Load transfer from
Rangiora North
10
5
2022
2020
2018
2016
2014
2012
2010
2008
2006
2004
2002
2000
0
Year
Figure 37 Demand Forecasts for Ashley
The Ashley GXP is to be upgraded by 2014 to supply the surrounding Ashley, Loburn and Balcairn areas
currently supplied from Southbrook and Waipara.
Peak Demand Forecast for Waipara 33 kV & 66 kV
12
Load transfer to Ashley
High Growth
33kV
8
Medium
Growth 33kV
6
Low Growth
33kV
4
Medium
Growth 66kV
2022
2020
2018
2016
2014
2012
2010
2008
2006
2004
0
2002
2
2000
Peak Demand (MW)
10
Year
Figure 38 Demand Forecasts for Waipara
75
Peak Demand Forecast for Culverden
30
Peak Demand (MW)
25
High
Growth
20
Medium
Growth
15
Low
Growth
10
5
2022
2020
2018
2016
2014
2012
2010
2008
2006
2004
2002
2000
0
Year
Figure 39 Demand Forecasts for Culverden
Peak Demand Forecast for Kaikoura
8
Peak Demand (MW)
7
6
High
Growth
5
Medium
Growth
4
Low
Growth
3
2
1
2022
2020
2018
2016
2014
2012
2010
2008
2006
2004
2002
2000
0
Year
Figure 40 Demand Forecasts for Kaikoura
The Kaikoura GXP is being purchased by MPNZ on 1st April 2012 and will become a MPNZ zone
substation fed from the Culverden GXP. There will be some diversity between the two however the
Culverden GXP load is likely to exceed the rating of one bank before the end of the planning period.
The MPNZ system losses will also increase.
76
6.4.3 Sub-transmission Load Forecast
Table 36 contains MPNZ’s 33 kV and 66 kV line capacities and forecast demands for the next 10 years
under the Medium Growth scenario. As demonstrated below, at the end of the planning period, all sub
transmission circuits are projected to have sufficient capacity to meet projected demand in their normal
supply configuration. Where circuits provide backup in the event of another line outage, the required
capacity including backup is also listed.
Load Forecast in normal configuration (MW)
Capacity
(MVA)
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
Line
Config.
23
8.5
21.0
10.7
23.2
10.9
24.0
11
24.8
11.3
25.5
11.5
26.1
11.6
26.4
11.7
26.6
11.8
26.8
11.9
27.0
12
27.2
Normal
Backup
12.5
6.5
12.5
7.5
12.7
8
12.9
8.2
13.1
8.4
13.3
8.6
13.5
8.6
13.7
8.7
13.9
8.7
14.1
8.8
14.3
9
14.5
Normal
Backup
23
11.5
21.0
11.4
23.2
12
24.0
12.6
24.8
13
25.5
13.4
26.1
13.5
26.4
13.6
26.6
13.7
26.8
13.8
27.0
13.9
27.2
Normal
Backup
Southbrook to Rangiora North
12.5
7
13.1
7
13.1
7
13.1
7
11.3
7
11.4
7
11.6
7
11.9
7
12.1
7
12.2
7
12.4
7
12.6
Normal
Backup
Rangiora North to Amberley
12.5
0
7
0
7
0
7
0
7
0
7
0
7
0
7
0
7
0
7
0
7
0
7
Normal
Backup
Amberley to Waipara
12.5
7.5
13.1
7.5
13.1
7.5
13.1
5.5
11.3
5.7
11.4
5.9
11.6
6.2
11.9
6.4
12.1
6.6
12.2
6.8
12.4
7
12.6
Normal
Backup
Waipara to Hawarden
10
2.6
4
3.1
4
3.3
4
3.5
4
3.6
4
3.7
4
3.8
4
3.9
4
4
4
4.1
4
4.2
4
Normal
Backup
Waipara to Cheviot
38
5.3
4
5.4
4
5.5
4
5.7
4
5.9
4
6
4
6.2
4
6.4
4
6.6
4
6.8
4
6.9
4
Normal
Backup
Cheviot to Kaikoura
7
0.7
6.7
0.7
6.8
0.7
6.9
0.7
7.0
0.7
7.1
0.7
7.2
0.7
7.3
0.8
7.4
0.8
7.5
0.8
7.6
0.8
7.7
Normal
Backup
Culverden to Hanmer
10
5.5
5
5.1
5.2
5.3
5.4
5.5
5.6
5.7
5.8
5.9
Normal
Sub-transmission Line
Southbrook to Cust
Cust to Oxford
Southbrook to Bennetts
Colour Key:
Less than 75% of capacity utilised
To be upgraded to 66kV between 2012 and 2014.
75-90% of capacity-utilised
Over 90% of capacity
Table 36 Sub-transmission Demand Forecast
6.4.4 Zone Substation Load Forecast
Table 37 shows details of the capacity and Medium Growth forecast peak load in MW at each zone
substation for the next ten years. As illustrated below, before the end of the planning period a number of
zone substations will require additional capacity in order to meet required projected demand and provide
required security of supply. Southbrook substation is designed to run within the rating of a single bank
and hence its utilisation is based on this.
Zone
Substation
Summer
/ Winter
Peaking
Load Forecast (MVA)
Capacity
MVA
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
Southbrook *
Winter
2 x 16/22
23.9
22.0
21.6
23.1
19.8
20.5
21.2
21.9
22.6
23.4
24.2
Rangiora North
Winter
5/7
7.0
7.0
7.0
7.0
7.0
7.0
7.0
7.0
7.0
7.0
7.0
Oxford
Summer
8
7.1
7.3
7.6
7.9
8.4
8.4
8.6
8.8
9.0
9.2
9.4
Bennetts
Summer
2 x 3/4
5.8
6.1
6.4
6.7
7.0
7.3
7.5
7.7
7.9
7.9
7.9
Swannanoa
Summer
7.5 / 11
6.1
7.1
7.5
7.7
7.9
8.1
8.2
8.3
8.4
8.5
8.6
Cust
Summer
7.5 / 11
3.5
4.0
4.3
4.5
4.7
4.9
5.1
5.3
5.5
5.7
5.9
Amberley
Winter
2 x 3/4
6.3
6.4
6.5
6.6
5
5
5.2
5.3
5.4
5.5
5.5
Summer
4
2.8
2.9
3.0
3.2
3.3
3.4
3.4
3.5
3.6
3.6
3.7
Winter
4
1.3
1.4
1.5
1.5
1.5
1.6
1.6
1.7
1.7
1.8
1.8
Cheviot
Summer
4
2.4
2.5
2.6
2.7
2.7
2.8
2.8
2.9
2.9
3.0
3.0
Hawarden
Summer
4
2.5
2.7
2.8
2.9
3.0
3.1
3.2
3.3
3.4
3.5
3.6
MacKenzies Rd
Greta
77
Summer
/ Winter
Peaking
Zone
Substation
Kaikoura
Leader
Oaro
Load Forecast (MVA)
Capacity
MVA
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
Winter
2 x 4/6
6.0
6.2
6.4
6.5
6.5
6.6
6.6
6.6
6.7
6.8
6.8
Summer
2
1.2
1.4
1.6
1.7
1.7
1.9
1.8
1.9
2.0
2.2
2.3
Winter
0.5
0.4
0.4
0.4
0.4
0.4
0.4
0.5
0.5
0.5
0.5
0.5
Summer
2x13
14.5
15.2
15.7
16.4
17.1
17.8
18.3
18.8
19.3
19.6
19.9
Hanmer
Winter
4/6 + 2.5
4.8
4.9
5.0
5.1
5.2
5.3
5.4
5.5
5.6
5.7
5.8
Lochiel
Winter
0.3
0.2
0.2
0.2
0.2
0.2
0.2
0.2
0.2
0.2
0.2
0.2
Marble Quarry
Winter
0.2
0.1
0.1
0.1
0.1
0.1
0.1
0.1
0.1
0.1
0.1
0.1
Mouse Point
Colour Key:
< 75% of capacity utilised
75-90% of capacity-utilised
Substations to be upgraded before summer 2014/15
>90% of capacity utilised
* Southbrook capacity is based on a single bank (i.e. N-1 criteria).
Table 37 Zone Substation Demand Forecast
6.4.5 Wigram Network Load Forecast
MPNZ expects growth at Wigram to flatten off except for a step increase with the completion of the Air
Force Museum expansion in 2012.
6.5
Network Constraint Identification and Analysis
As a result of the forecast load growth, the following particular constraints have been identified.
6.5.1 GXP Constraints
Southbrook loading at 33kV has reached the rating of one transformer bank. The transfer of load to
Kaiapoi and more targeted load control will reduce this load in the short term and the conversion of the
Rangiora West area to 66 kV for 2015 will substantially reduce the loading on the transformer bank.
The Kaiapoi GXP is constrained by the number and rating of feeder circuit breakers. An upgrade is
required to enable significantly more capacity to be distributed from the GXP.
The Culverden GXP is likely to approach the 30 MVA rating of one bank towards the end of the planning
period.
6.5.2 Sub-transmission Constraints
Following upgrades of the two 33 kV circuits Southbrook to Cust and Southbrook to Swannanoa in 2010
the total summer peak load is marginally manageable with an outage of one circuit. MPNZ has installed
emergency control on irrigation loads in this region to provide security of supply until the circuits are
upgraded. MPNZ is upgrading this area to 66 kV over the next 3 years. More details are provided in
Section 7.
The Cheviot to Kaikoura circuit is limited by voltage drop and the capacity of in line voltage regulators at
Claverley. It can only marginally supply Kaikoura during an outage of the normal Transpower 66 kV
supply, even with the maximum available load control.
6.5.3 Zone Substation Constraints
The Southbrook zone substation ran above the rating of one bank for significant times during 2011 and
peaked several MVA higher during the very cold August snows. A number of measures are being put in
place to reduce the peak load to less than the 22 MVA single transformer rating for most of the planning
period.
The Rangiora North substation operates up to its full rated load and will continue to do so over the
planning period. The network development plans include configuration changes to limit any load growth.
78
The Oxford and Bennetts zone substations will be approaching full load over the next few years and have
very limited alternative supply provisions in the event of a single transformer failure. The Rangiora West
upgrade project to greatly increase capacity and security for these areas begins in 2012.
The Amberley zone substation is approaching full load. This is acceptable in the short term as it is double
banked and there are reliable alternative supplies from other zone substations to supply most of this area.
In the medium term (2014) this site will be de-loaded following the establishment of distribution level
supply out of Transpower’s Ashley GXP.
All the remaining zone substations have adequate capacity throughout the planning period.
79
7
NETWORK DEVELOPMENT PLAN
7.1
Introduction
Network development planning is undertaken to identify asset enhancement and development
programmes required to meet target levels of service and MPNZ’s security standards. It is based on
analysis of maximum demands, network power flows, specific customer requests and demographic
estimates.
Planning criteria for the development of the network are presented in the following sections, defining the
constraints and limits applied to individual network components and the overall policies to which the
development plan must conform. The definition of planning criteria ensures:

Consistent evaluation of development options

A benchmark against which policy changes can be assessed

Transparency of operating margins.
For the purposes of this AMP, a distinction is made between transmission, sub-transmission and
distribution planning.
The upgrade programme for the 220 kV transmission system owned and managed by Transpower will
depend to some extent on Transpower policy. A review of local transmission development is included for
completeness as it has a major impact on the security and reliability of the MPNZ system.
Sub-transmission planning emphasises long range objectives associated with system expansion and
required increases in zone substation and GXP capacity to meet peak demand. It also takes into account
key issues associated with reliability and security of supply.
Distribution planning emphasises more short run objectives associated with new customer connections,
power quality improvement (such as voltage regulation and power factor correction), loss reduction and
operating improvements.
7.2
Planning Criteria and Assumptions
Planning criteria describe the limits placed on system elements that network development must conform
to. MPNZ has adopted specific planning criteria to ensure consistent evaluation of the alternatives and
that appropriate operating margins exist across its entire network.
7.3
Network Development Practice
The principal drivers of network development planning are:

Knowledge of new growth, derived from knowledge of new connections and specific developments

Knowledge derived from load forecasting models

Knowledge of historical trends of substation and feeder loadings.
7.4
Reliability and Security
Although there is no universally accepted definition of power reliability, the number and duration of service
interruptions are of primary interest from the customers’ point of view as specified in Section 4. MPNZ
uses reliability statistics to identify if and where system improvement is needed.
Defining an acceptable level of service to customers, given the cost of reliability improvement, is a more
difficult question to answer. MPNZ selects system options on the basis of the lowest through life cost
design required to improve current levels of reliability.
80
MPNZ uses its GIS system to evaluate the likely reliability of feeders. The GIS system traces the feeders
and reports the length of heavy, medium and light conductors between downstream circuit breakers, and
the number of ICP’s in each section. Lighter conductors are assigned a higher failure rate. A resultant
overall reliability index is calculated. In figure 41 below the different colours within a bar represent the
contribution to the index between each circuit breaker in the feeder. Feeder R47 is clearly likely to have
the poorest reliability. This table is used to rank feeders for reliability related upgrades. Any year’s outage
statistics are unlikely to match this very closely however it is representative of the average over 5 years.
Calculated SAIFI Index
3500
3000
Relative SAIFI Index
2500
2000
1500
1000
500
R47
Y23
P45
S15
K7
H31
SW64
S13
C40
U26
Y43
X28
BN24
C20
X38
P25
U36
P35
N34
T42
T43
K6
H21
K24
W21
Y33
T41
W23
X48
SW62
U46
G33
K4
P55
H41
G31
BN25
K1
G32
S14
L51
SW65
N44
SW63
R27
S36
BN23
U56
W22
O76
L52
S16
E80
R37
K18
C30
L53
K15
S34
S35
K19
0
Feeder ID
Figure 41 Feeder calculated reliability index
Security of supply is the ability of the network to meet customer demand without suffering an interruption
in the first instance, and secondly, where an interruption develops it is the ability to restore power quickly
via alternative supply or backup options. MPNZ’s security guidelines generally look to provide an
alternative backup supply where practical, however this is seldom done in isolation and is often coupled
with parallel studies of:

the network’s load profile

the ability to economically duplicate network assets to provide additional security

asset utilisation

the different risks associated with different equipment types

response times.
The EEA guideline for security of supply in New Zealand electricity networks adopts a reasonable level of
security of supply standards. The security guidelines for restoration of supply following a single fault
adopted by MPNZ for the planning period are shown in Table 38. These are not less than the EEA
“Guidelines for Security of Supply in New Zealand Electricity Networks” and also accommodate MPNZ’s
own experiences and needs. MPNZ defines an urban area for security of supply purposes as town with a
peak load greater than 10 MW.
Class of Supply Description
Rural radial feeders
Demand Range (MW)
0 – 1.5
Rural feeders with alternative supply
0–5
Urban feeders
0–8
Zone substations – Rural single bank
Zone substations – Urban single bank
0.2 – 7
1–7
Zone substations – Double bank
1 – 10
GXP stations – Single bank
1 – 10
GXP & Zone substations – Double bank
10 – 30
Time to Meet Demand
Repair time
3 hours for 50% demand
6 hours for 100% demand
3 hours for 50% demand
6 hours for 100% demand
Repair time for 100% demand
8 hours for 100% demand
3 hours for 50% demand
Repair time for 100% demand
8 hours for 100% demand
1.5 hours for 50% demand
8 hours for 100% demand
Table 38 Security of Supply Guidelines
81
Rangiora and Kaiapoi are the only urban areas within the context of the security guidelines however
MPNZ’s customers have consistently placed high importance placed on security of supply.
Where smaller communities can practically be given a similar level of security, upgrading to achieve this is
a priority.
The towns of Kaikoura, Culverden, Waipara, Amberley and Woodend all have security similar to urban
areas.
Planned upgrades will bring Oxford, Cust, Ashley, Leithfield and Cheviot up to a similar standard within
the planning period.
Hanmer and Hawarden are notable exceptions as they are both supplied from single subtransmission
circuits with little or no interconnection to other parts of the system. For Hanmer in particular, non network
solutions may be able to provide at least partial backup in the future.
In the case of an adverse event (such as, but not limited to, snow storms, high winds, lightning, floods and
earthquakes), MPNZ will use its best endeavours to restore electricity delivery as soon as practicable.
The changing rural land use to increased dairying has also brought increased dependence on the power
supply for the operation of many farms and drastically increased the overall economic impact to society of
outages. The recent earthquakes have further raised awareness of security and reliability, even at some
increased cost, and hence rural network development has also been focused on strengthening security
which has been eroded by rapid load growth. This is particularly evident in the Rangiora West and
Culverden areas.
7.5
Lost Customer Minutes Fund
The reliability performance of MPNZ is judged according to the number of customer interruptions (SAIFI)
and customer minutes lost (SAIDI) per connected customer. The number of customer minutes lost is
generally perceived to be the most significant measure of supply quality and capital investment in this area
will often include appraisals of the cost per customer minute lost rescued.
One of the main difficulties in developing a distribution value for customer minutes lost rescued is the
perceived difference in standards between customer groups. Rural customers are better prepared than
urban customers to deal with interruptions because they have more of them and are generally better
equipped to handle them. For example, they may have alternative ways to provide room heating, heat
water and cook. Commercial customers in town centres or industrial customers with continuous
processes can often have requirements significantly greater than the average. For example many
commercial customers are badly affected by even a short interruption, some industrial customers cannot
cope with long lasting interruptions and most domestic customers are relatively unconcerned about deep
night power cuts. As discussed in 7.4 the sensitivity of rural customers is also increasing with changing
land use. There is no consensus in New Zealand as to the values to be used or how they are to be used.
For the time being MPNZ has decided to, within the confines of its business processes, apply a monetary
value to lost customer minutes so that a sum of money can be allocated in the budget each year to avoid
or lessen the impact of power interruptions. This is not a payout to customers based on perceived losses;
it is a management and funding tool for internal use to help reduce power disruptions to customers.
MPNZ places a value of 7 cents per customer minute of interruption on planned interruptions and
20 cents per customer minute of interruption on unplanned interruptions or faults. These values are used
to budget for the following initiatives:

Expenditure to reduce outages from planned interruptions to provide temporary supply options using:
-

Live-line technology
Interrupter cables
Mobile generation.
Expenditure to reduce outages resulting from faults to provide permanent supply options using:
82
-
Improved response times through mobile communication technology
Installation of automation schemes
Splitting feeders or creating new feeders from a zone substation to reduce the number of
customers affected by a fault.
Based on current levels of interruptions this means that MPNZ is willing to spend approximately $120,000
each year on planned interruption initiatives to prevent them from occurring, and approximately $400,000
each year to reduce system faults and hence lost customer minutes. This is in keeping with the results of
the 2009, 2010 and 2011 customer surveys which identified that reliability of supply; i.e. how many
interruptions customers are experiencing, is one of the most important issues for customers. Over time
MPNZ will monitor the levels of funding applied to the reduction of interruptions by the above means and
compare this against any real improvement.
These funds are evident in the cost of employing live line techniques, running the mobile generator truck
in place of planned shutdowns and the installation of additional circuit breakers and new feeders. It is
however more difficult to determine the precise allocation of funds to improved response times as the
outcomes of these improvements is not currently measured. The TechnologyOne software platform
includes a mobility solution which will be developed to monitor response times in the future.
7.6
Voltage Regulation
The objective of voltage regulation is to stay within the statutory voltage limits. Voltage regulation is
generally set to control in the band 100% to 102% of nominal voltage at sites with 1.25% tap steps.
Where either line drop compensation or 2.0% tap-changers are employed, the voltage regulation is set to
control in the band 11000 – 11299V. Line drop compensation is rarely used because of the large
customer spread along the distribution lines.
Selection of the most appropriate means of voltage regulation depends on current demand, demand
forecasts, network configuration, cost and amount of correction required. The allowable voltage drop of
12% to the network connection point is generally allocated as shown in Table 39.
Regulated Bus range
MV Distribution System
Transformer
Low Voltage System
Urban
1.5%
2.5%
2.0%
6.0%
Rural
1.5%
5.0%
2.5%
3.0%
Table 39 Voltage Regulation Guidelines
In rural situations the actual MV distribution system voltage drop will depend on the distance of the
customer from the voltage controlled supply point. Generally, network design aims for the distribution
transformer to be as close as possible to the customer to remove the need for long low voltage (400V)
circuits.
Systems are generally designed to have less than 10% total voltage drop to the network connection point
to allow for additional voltage drop when the system is being supplied in an abnormal configuration e.g.
during and equipment outage.
Transpower or MPNZ system switching or sudden large customer load changes may cause momentary
fluctuations outside the 12% range. The voltage regulators will usually correct for these changes within a
few minutes.
7.7
Fault Levels
All MPNZ equipment is sufficiently rated to withstand the existing fault levels (the resultant current that
flows during network short circuit faults). An increasing issue for MPNZ is that coupled with transformer
upgrades at Transpower GXPs, the fault levels increase.
83
Most MPNZ equipment is sufficiently rated to withstand the increased fault ratings resulting from the
planned upgrades. As fault levels decreases with distance from the GXP, most equipment located a
reasonable distance from the GXP will be rated sufficiently.
Some equipment located in close proximity to GXPs will in future not withstand the higher fault levels,
where three-phase or single-phase-to-ground fault levels may increase to over 200MVA. In particular,
light sheaths on underground cables will not cope and some drop out fuse links on overhead lines will fail.
Where it is likely that fault levels will go above 200 MVA, a combination of improvements will be made
ranging from cable upgrades and fuse upgrades through to the fitting of neutral earthing resistors and
reactors on supply transformers.
7.8
System Modelling
7.8.1 Investment Modelling
Network extension projects are evaluated using a financial model to determine their economic viability.
The customer is asked to contribute towards any uneconomic shortfall associated with the project. Where
there is a requirement to upgrade existing 3 phase network to a higher capacity MPNZ uses a higher level
investment model that takes account of revenue streams from multiple customers through line charges.
7.8.2 Power Flow Modelling
MPNZ employs Seimens Sincal power flow analysis software to investigate and review capacity, security
and voltage performance of its network.
7.9
Network Voltage Optimisation
While 33 kV has been a useful sub-transmission voltage for MPNZ over the years, high growth
experienced in a number of rural areas is clearly indicating the end of 33 kV as a sub-transmission
voltage. It is also recognised that 66 kV sub-transmission and 11 kV distribution are the most optimum
voltages to use in urban areas or areas with high customer density. 22 kV distribution is rapidly being
deployed as the best solution for rural areas experiencing growth from dairy farming and irrigation.
MPNZ’s southern region which includes the towns of Rangiora, Kaiapoi and Woodend is experiencing
very high levels of growth. All of the existing distribution systems in Rangiora, Kaiapoi and Woodend are
11 kV, with the vast majority of them underground. This system would be extremely difficult to upgrade to
a higher voltage, therefore it is simpler and more economic to upgrade the sub transmission level voltage
and to install more 66/11 kV transforming stations to meet increased demand. It is also convenient to
continue to use Transpower’s existing 66 kV circuits where possible. As 66 kV sub transmission systems
develop throughout North Canterbury MPNZ will consider options for direct ownership of the existing
Transpower systems.
7.10 Capacity Determination
7.10.1 Conductors and Cables
High-percentage-steel conductors are used in heavy snow areas and low load areas. All aluminium
conductors are preferred for use in salt contaminated areas near coastal regions. The minimum
conductor size used is ferret for all main lines above minor service line level. Squirrel conductor is
gradually being removed from service due to its low strength especially in snow areas. All jumpers are
now sized at ferret as a minimum or the line conductor size where this is larger.
All new lines are designed to AS/NZS7000:2010 and the appropriate electricity regulations and codes of
practice.
The informative snow and ice loadings recommended in AS/NZS7000 are being used although these are
still being reviewed for their appropriateness in MPNZ’s area.
The following conditions have been assumed when calculating the thermal rating of overhead conductors:
84
 Winter:
Wind of 0.5m/sec, solar radiation of 1000 W/m2, “black” conductor, 50 degC temperature rise
from 10°C ambient
 Summer: No wind, solar radiation of 1000 W/m2, “black” conductor, 30 degC temperature rise from
30°C ambient
Cables are purchased to AS/NZS4026:2008.
7.10.2 Transformers
Power transformers are operated to the limits allowable under BS 7735-1994 Guide to Loading of Oil
Immersed Power Transformers and BS EN 60076-1 Power Transformers General and Temperature 1997.
Transformer utilisation can be misleading as it is often cheaper in rural networks to erect a 15 kVA
transformer for a new customer rather than install 150m of low voltage to the next nearest transformer.
This tends to reduce the overall utilisation factor yet also reduces the amount of investment in network
assets per customer.
7.10.3 Overload Ratings
MPNZ uses high load alarm settings based on a maximum of 90 percent of the protection settings on
incomers and feeders in zone substations to alarm system controllers via SCADA. Where the thermal
capacity of the immediate downstream network is lower, these ratings are used.
7.11 Process and Criteria for Prioritising Network Development
Projects are prioritised based on evaluation of the level of risk to MPNZ from not doing the work or
delaying the work. The level of risk is measured with a simple five by five level matrix approach for each
of the consequences and likelihood of each project or action. Factors considered in the evaluation
include:

The risk of non-supply to customers

The identified areas for service level improvement to customers

Cost benefit analysis

Other benefits e.g. benefits of co-ordination with road authorities or Transpower.
After considering the issues associated with a particular project a total score is obtained by averaging the
scores in a balanced scorecard approach to derive a single score for a particular project. This score is
then compared with other projects to determine project priorities.
In general terms projects are prioritised as follows:

Priority 1
Addressing significant health, safety and environmental issues

Priority 2
Customer driven projects for new connections or upgrades

Priority 3
Addressing statutory voltage and power quality issues

Priority 4
Providing for load growth

Priority 5
Meeting reliability targets (where not addressed in Priorities 1-4)

Priority 6
Renewals.
During January each year following the identification of the proposed work for the next five years,
consultation with engineers and construction staff determines the relative priorities of the work. Inputs to
the process will be determination of the main driver, the impact on customers should the project not
proceed or be deferred, any seasonal requirements, and then last the cost and funding implications.
85
7.12 Non Network Solution Development Plan (Demand Management)
MPNZ is committed to exploring non network solutions to manage demand and system constraints.
7.12.1 Policies
MPNZ has developed a number of energy efficiency programmes to ensure that customers are aware of
the personal and community benefits of using energy efficiently and are encouraged to take up the options
to use energy efficient techniques. MPNZ has created a set of values which are part of its forward vision
and these are included in the Company’s SCI. The values include protection of the environment and
natural resources for the sustainable benefit of the region and research for innovative opportunities.
MPNZ will continue to offer energy efficiency programmes to its customers. MPNZ will also explore nonnetwork alternatives when considering investments in new network infrastructure.
Several criteria have been established by which demand side management development options are
evaluated including:

Load savings, total and peak

Resulting network capacity avoided cost (at industry standard $100/kVA)

Transpower capacity credit reductions

Lost distribution revenue

Net cash flow to MPNZ

Customer cash flow.
When a customer requests a new connection or where MPNZ is faced with an upgrade to meet forecast
requirements the opportunity is taken to consider the above criteria. This happens when the Network
Manager Development reviews the connection details of significant proposals.
7.12.2 Planned MPNZ Developments
Section 6 summarised MPNZ historical demand side management programmes implemented to date.
A more detailed description of each programme is presented below.
Programme
Warm Homes
Makeover
Large User
Energy Audits
Replacement
of Residential
Incandescent
Light Bulbs
with Compact
Fluorescent
Bulbs (CFLs)
High School
Energy
Education
Description
 Installation of a range of home energy efficiency measures into low-income homes
 Includes ceiling insulation, under-floor insulation, door draught-stopping and hot water cylinder
wraps/hot water pipe-lagging
 1000 homes retrofitted to date
 Aim to support the Energy Efficiency and Conservation Authority (EECA) Warm up New
Zealand Heat Smart programme through sponsorship arrangements to subsidise the retrofit of
low income homes in the MPNZregion.
 Auditing of 12 large energy consumers to date – McAlpines, Southern Chicks, Heller Tasty,
Rangiora New World, Cart Holt Harvey, Weston Animal Nutrition, Kaiapoi Working Men’s Club,
Patience and Nicholson, Wigram Air Force, Karadean Court, HW Hendriks, MPNZ
 Identified savings with payback period of 3 years or less have ranged from 3.3 to 44% of energy
consumption, averaging 10.6%
 Auditing of 8 small tourism type businesses as part of the Government’s STAR programme – to
date Hanmer Thermal Pools and Spa, Karikaas Natural Dairy Products, Nor’Wester Café,
Activity Hanmer, Pete’s Farm Stay, Wayside Motel, Greenacres Chalets and Townhouse,
Fontainebleau B&B
 Audit undertaken at Hellers to incorporate their new manufacturing and cool store business
 Undertaken in 2005 in association with the Electricity Commission
 Replaced 59,000 incandescent light bulbs in customer’s homes with CFL bulbs.
 CFLs use only 20-25% of the energy of conventional bulbs and are a significant contributor to
the reduction in peak electricity loads on the network.
 Based on a statistical sample, this project is estimated to reduce the network peak load by 1.5
MW in winter, and provides customers with annual total electricity savings of 4GWhs
 Teaching manual and resource kit of 6 lessons on electricity offered to teachers for Year 9 – 10
high schools students in MPNZ region
 Modules comprised heat and fuses, measuring power consumption, three wire system,
86
Programme
Primary
School
Energy
Education
Irrigation
Efficiency
Description
electrical safety, energy efficiency and paying for electricity
 Currently developing teaching activity book for primary school teachers
 Modules to be included are energy efficiency, electrical safety and renewable energy
 The objective is to encourage the safe and efficient use of energy in households and raise the
awareness of energy efficiency options

The objective is to encourage reduced energy consumption in schools

Energy consumption monitoring being undertaken at Ashgrove Primary School

Development of a case study on reducing energy consumption by changing attitudes and
behaviours of staff and students in schools

The 5Es of Energy developed to teach and encourage energy efficiency, renewable energy
opportunities and electricity safety
 A minimum of four schools visited each year with the programme
 The objective is to improve efficiency through well designed irrigation infrastructure, with
consideration given to energy efficiency
 Joint sponsorship of Irrigation New Zealand’s development of Code of Practice for Irrigation, in
conjunction with Orion and Electricity Ashburton
Table 40 Demand Side Management Programmes
7.12.3 Other Developments
There are no other known major non-network solution projects being undertaken by external developers
within MPNZ’s supply area.
7.13 Embedded / Distributed Generation Development Plan
7.13.1 Introduction
Increasing the capacity of Distributed Generation (“DG”) in constrained networks has the potential to avoid
or defer network or line upgrades due to the resulting reduction of power transfer through the distribution
network. It also has the potential to avoid or reduce Transpower Interconnection and Connection Charges
which can then be passed on to consumers via reduced line charges. Benefits can include:

increased utilisation of the local network

reduced electrical losses resulting from the lower levels of power transfer

improved security of supply and network reliability

provision of voltage support in outlying areas

provision of the timeliest and the most cost-effective solutions for supply reinforcement or supply
quality problems compared to other larger options

greater diversification of power supply options through using various types of fuel or energy resources

additional local supply capacity to assist with demand-side management initiatives through better
control of local loads and reduced variations in peak demand

provision of greater diversity allowing better management of local load profiles

overall reduction in supply costs passed onto consumers through lower tariffs

reduction in peak demand for the distribution and transmission systems especially where capacity
factors are constrained

potential provision of carbon credits if Renewable Energy Resources are used.
7.13.2 Policies for Connection
MPNZ has been involved with numerous generation initiatives in the past and several projects are in
feasibility and planning stages at present. Embedded generation development is likely to provide mutual
benefits to MPNZ and the following factors are therefore evaluated for the purpose of network planning:

The need to install new or upgrade network assets
87

The ability of the embedded generation to defer investment in the sub-transmission and distribution
networks

The reduction in Transpower transmission charges as a result of reduced energy drawn from the
national grid.
MPNZ has an open access policy to distributed generation and welcomes the connection of all forms of
distributed generation to its network. MPNZ will comply with the Electricity Governance (connection of
distributed generation) regulations 2007 in this respect. Prior to the connection of new distributed
generation it is necessary to study what will happen to the network at the point of connection when the
generator operates. In some cases there can be asset overloads, voltage rise and even voltage
disturbance creating interference for other connected customers. Operation of the generator under
network fault conditions and isolation of the generator for network maintenance also need to be
understood and managed. MPNZ requires specific information on under and over voltage and frequency
protection afforded by the generator. In some cases especially when larger than 1 MW, the DG may
require new dedicated lines or the upgrade of existing lines to provide adequate power transfer capability.
Many forms of DG can also have a detrimental effect on the power factor at the GXP by lowering real
power flows and increasing VAR flows. MPNZ is required to maintain a good power factor at the GXP
level.
MPNZ has provided a distributed generation policy for customers who wish to generate their own
electricity. Generally customers will fill out an initial application form and provide a technical specification
so that MPNZ engineers can determine any issues associated with the connection. From here MPNZ
would request a final application be made in writing and following approval of this application by MPNZ
engineers, the connection would proceed.
7.13.3 Planned MPNZ Developments
Known DG schemes that are expected to be developed on MPNZ’s network include up to 8 MW of hydro
at Browns Rock off the Waimakariri River and up to 36 MW of wind farm which has been consented at Mt
Cass near Waipara.
The Browns Rock hydro scheme would require a 33 kV line to be built between the hydro station and
MPNZ’s Bennetts zone substation if it proceeded immediately, however the 33 kV in this area is being
upgraded to 66 kV and the Bennetts substation replaced by a new Burnt Hill substation. The full capacity
of the hydro scheme may be able to be connected at 22 kV after the upgrade. This will require further
study as the proposal progresses..
The Mt Cass scheme will require direct connection to the Waipara GXP at 66 kV, which in practice will be
a short new line between the GXP and Mt Cass for the wind farm, and potentially for Kate Valley DG.
7.13.4 Other Developments
Landfill gas generation has been proposed at the Kate Valley land fill site. The site is also being
investigated for wind generation. The existing single phase galv steel distribution lines in the area have
very limited capacity for generation. Staged upgrades are required for Kate Valley loads and small scale
generation. MPNZ is in close discussion with all parties to ensure that any upgrade work is appropriate
given the likely developments.
Meridian is investigating an “Amuri Project” for 38 MW of hydro generation from the Waiau. This is in the
early stages and would take some years to come to fruition; however there is some potential to offset
network development as the Culverden GXP and MPNZ’s Mouse Point substation are likely to be reaching
capacity in the second half of the planning period.
Meridian Energy had been trying to consent a potential wind farm sites at Omihi but plans for this have
recently been dropped.
The introduction of smart networks combining distributed local generation, energy efficiency, smart
metering and the impact of electric vehicles will be studied more closely by MPNZ engineers over the next
year. A project this year will also look at how smart networks could be employed in areas of the MPNZ
network that are facing constraints such as will appear for the Hanmer region over time where there is
88
growing demand and no back up supply. It will also look at how ICP level control from smart meters
could improve the security of supply to critical loads.
7.13.5 Impact on Development Plan
Both the proposed MPNZ and Meridian generation projects have been omitted from the development plan
forecasts as none of the projects have yet been confirmed. At such time, the development plan will be
amended to reflect the deferred network investment which is likely to result from these projects.
7.14 Network Development Plan
This section gives an overview of ratings and loadings of network elements and describes the constraints
that are projected to occur on the network within the planning period. The options and preferred solution
for removing or mitigating any constraints are also presented.
7.14.1 Transpower Transmission
Transpower 220 kV Transmission Development
The 220 kV South Island transmission network owned and managed by Transpower consists of four 220
kV circuits bringing power from the Waitaki basin to supply load to Canterbury, Tasman, Marlborough and
the West Coast in the top half of the South Island. This system supplies significant load over
comparatively long distances from the Waitaki and Twizel power stations.
Over the past few years, during transmission or generation plant outages, the grid’s capacity to supply
power to Christchurch and the upper South Island has been constrained. Major factors contributing to this
include:

thermal capacities

voltage instability due to heavy circuit loading

thermal instability due to long distances between generation and the point of demand.
Accordingly Transpower is improving the dynamic voltage support and reactive power management in the
region, and the upper South Island by installing a new static var compensator (SVC) at Islington, and a
reactive power controller in the Christchurch area.
The upper South Island load control scheme, which MPNZ is a part of, also includes targets based on
Transpower’s security limits to ensure fast response to changes in available capacity. This has the effect
of better profiling the loads to delay Transpower upgrade expenditure.
Transpower’s system operator and all lines businesses affected by these constraints are in close
communication with each other to deploy every possible option to prevent customers from losing power
supply.
66 kV Transmission Development
MPNZ has four 66 kV feeds into the main southern load centres and a dual 220 kV / 33 kV supply into the
Culverden region. Kaikoura continues to be supplied from a 66 kV circuit from Culverden but this is now
supplied from a 33/66 kV step-up transformer at Culverden. The 66 kV circuits supplying the southern
region comprise the two Islington-Southbrook 66 kV circuits and the two Southbrook-Waipara 66 kV
circuits that are supplied from the Waipara end and supply back down to Southbrook. Figure 42 shows
transmission line ratings in MVA for the transmission system in North Canterbury and Kaikoura.
89
Figure 42 Transpower 66 kV Transmission Circuit Ratings
Within two years MPNZ plans to request that Transpower upgrade the capacity of their two 66 kV
transmission circuits running between Southbrook and Waipara to a similar rating as the IslingtonSouthbrook circuits, around 65 MW. This could be achieved by re-sagging the conductor or increasing the
ground clearance. As the load grows in the southern region, stronger feeds from Waipara will be required
in the event of the loss of an Islington-Southbrook circuit. Other options include the installation of
distributed generation in the southern region.
7.14.2 GXP Station Development
MPNZ has a goal to include all GXP stations on the MPNZ SCADA and has requested that Transpower
provide SCADA data from the Kaikoura, Ashley and Kaiapoi GXPs for this purpose. Transpower have
responded that these will be available from a central server in the future and for the meantime will not
provide direct connections to their RTUs at this stage.
90
Planned GXP developments are outlined below:
Kaiapoi GXP
Projected work
Justification
11kV switchboard extension.
MPNZ has built an 11 kV switchboard to the north side of Kaiapoi to provide capacity and security to the
rapidly developing new subdivisions in the area. These have been accelerated by the recent earthquakes.
The new switchboard also provides dedicated feeder circuit breakers for Woodend to enable the Woodend
and Pegasus town loads to be transferred from Southbrook to Kaiapoi. The capacity of the switchboard is
limited by the 400A rating of the old circuit breakers at the GXP. These cannot be upgraded and the only
way to release more capacity is to extend the GXP switchboard with higher rated equipment. The
immediate vicinity of the GXP is also being converted to a large subdivision which will require an
additional feeder as the existing ones are all loaded over 65% of their capacity.
The Weatherall feeder to the rural area south west of the GXP is one of MPNZ’s poor performing feeders
with a large number of customers, long length of line (refer section 7.4 figure 41), and poor voltages at the
extremities. Splitting this feeder in two, together with some conductor upgrades, is seen as the best
option currently available to service this growing rural life style area. Achieving the above requires the
addition of at least two higher capacity circuit breakers to the GXP switchboard.
Status
MPNZ’s Southbrook zone substation was overloaded in 2011 (refer section 3.6.4 table 18) and has
substantial load growth. Options are to upgrade Southbrook (very expensive and possibly triggering a
GXP upgrade as well), or to transfer some Southbrook load elsewhere. Kaiapoi is the only neighbouring
substation with any real capacity and is also approximately equi-distant to the Woodend / Pegasus load
base. It can be configured to take over the load without any loss of reliability and security. A third option
which has been investigated with a design report from Transpower is the creation of a new Rangiora East
GXP. This solution would be far more expensive and take several years to implement. The GXP
switchboard extension, in conjunction with the Kaiapoi North work is the most cost effective solution in the
medium term.
Transpower has produced a high level options report for review and is now proceeding with more detailed
design of the preferred option.
Project completion is planned for winter 2013.
Southbrook GXP
Projected work
Addition of two 66 kV feeders.
Justification
MPNZ is upgrading the Rangiora West area from primarily 33 kV / 11 kV distribution to 66 kV / 22 kV
distribution to cater for the high level of irrigation related development (refer Rangiora West 66 kV below)
The two 33 kV overhead lines supplied from MPNZ’s zone substation are to be converted to 66 kV and a
new 66 kV feeder is required on each side of the Southbrook 66 kV bus.
Status
Transpower has produced a high level options report for review and are now proceeding with more
detailed design of the preferred option.
Project completion is planned for summer 2014/15.
Ashley GXP
Projected work
Justification
Replace the two 10 MVA transformers with 40 MVA units, the same as Kaiapoi. Add six 11 kV
feeder circuit breakers. MPNZ will have some ancillary work associated with this project e.g.
installing a ripple plant and reconfiguring feeders.
The Rangiora North zone substation which supplies the rural areas Loburn, Ashley, Balcairn and the north
side of Rangiora town is at full capacity. There is significant load growth on the north side of Rangiora and
the alternative supply point of the Southbrook zone substation is also at full capacity (refer 3.6.4 table 18).
The upgrade will allow the transfer of the load on the north side of the Ashley river to the Ashley GXP and
release the full capacity of the Rangiora North substation to supply Rangiora. It also removes the
dependence of the Loburn and Ashley areas on the Ashley river crossing which has been washed away
several times in floods over the last 20 years.
The Amberley substation to the north has two small transformers but the peak load is now such that it
cannot be supplied from a single bank with backup from neighbouring substations (refer 3.6.4 table 18).
Amberley town is not large enough to qualify as an urban centre but is nonetheless a significant rural town
and growing. MPNZ’s security criteria require provision of similar to urban standard security to such towns
where reasonably practical.
The upgrade will allow much of the southern area fed from Amberley to be transferred to Ashley and
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strengthen backup interconnections.
The rural feeders supplying Loburn, Ashley, Balcairn and Leithfield are amongst the poor performing
feeders with a large number of customers, long length of line (refer 3.6.4 figure 41) and poor voltages at
the extremities. The upgrade will allow these areas, currently serviced by 3 feeders, to split over 5 feeders
with the source more centrally located to the load base.
The reduction in load on the Amberley substation and the removal of the rural areas from Rangiora North
will significantly reduce the load on the Southbrook to Waipara 33 kV subtransmission circuit when it is
required for backup purposes (refer table 36). This will enable an alternative supply to continue to be
available to the Hawarden area in the event of an outage of the single 66/33 kV transformer bank at the
Waipara GXP.
Status
Waipara GXP
Projected work
Justification
Status
The Daiken MDF plant has a peak load of 11 MVA and currently has to reduce load during a maintenance
outage of one transformer. The upgrade will remove this constraint.
This upgrade has been brought forward following the decision to defer the construction of a new Rangiora
East GXP. Transpower is actively preparing a high level report on the upgrade options. Completion is
expected in 2014.
Addition of one or two 66 kV feeders.
MPNZ has a resource consent for a wind farm on Mt Cass which would require a 66 kV connection if fully
developed. The timing of any construction is unknown at this stage.
Towards the end of the planning period it may be necessary to upgrade the Amberley substation from
33/11 kV to 66/11 kV with increased capacity. This could be triggered by load growth, or the requirement
to decommission the existing 33 kV line around Rangiora. This is not likely in the short to medium term
but is flagged here as a possibility in the longer term.
Possible timing 2016+.
Culverden GXP
Projected work
The forecast load growth would require a capacity upgrade by the end of the planning period. This
assumes continuing irrigation development and also could be mitigated by some DG proposed for
the area. There is no capacity upgrade plan currently proposed for Culverden.
MPNZ is purchasing the Kaikoura GXP and Culverden – Kaikoura 66 kV transmission line from
Transpower. This will require some minor operational changes at Culverden and increase the load
as reported for the Culverden GXP from 2012 onwards.
Kaikoura GXP
Projected work
Modify for connection of upgraded Cheviot to Kaikoura 66 kV line
Justification
MPNZ has been converting the Waipara - Kaikoura subtransmission line from 33 kV to 66 kV to increase
its capacity so that it can continue to provide a backup supply to Kaikoura in the event of an outage or
maintenance on the normal Culverden – Kaikoura line or the 66/33 kV transformer. The Waipara to
Cheviot section is now running at 66 kV and the Cheviot to Kaikoura section mainly converted with the
notable exception of the Rakanui block across the hills above the tunnels south of Kaikoura.
Status
Completion of the work has been held up pending agreement with the land owner regarding the details of
the upgrade. These negotiations have been protracted due to protracted change of ownership
arrangements for the land.
The configuration of the connection has not been finalised and this will now be reviewed again following
MPNZ’s purchase of the substation in 2012. Possible construction 2015.
92
Rangiora East GXP
Projected work
Construction of a new GXP.
Justification
The Southbrook zone substation secure 11 kV capacity is fully utilised and Southbrook operated above
the rating of one transformer for significant periods in 2011. The 11kV capacity cannot be increased
without largely rebuilding the substation and the long term plan is for Southbrook to become a 66 kV to
11 kV GXP with no 33 kV. The first stage of this will be complete with the conversion of the Rangiora
West feeders to 66 kV.
There is rapid growth predicted for the Rangiora urban area and the Woodend / Pegasus area. MPNZ is
managing this constraint by more rigorous application of load control, the transfer of load to the Kaiapoi
GXP, and the upgrade of the Ashley GXP to allow the Rangiora North substation to be fully committed to
Rangiora. The urban feeders are being strengthened to redirect the all available Southbrook 11 kV
capacity to Rangiora town. This will be sufficient to maintain security and reliability for a number of years.
Ultimately as the load base at Woodend develops it will become too large to be supplied from Kaiapoi. At
this stage the combined Woodend and Rangiora load will be approaching 40 MVA with much of it remote
from the Southbrook site. The Southbrook site could be upgraded to 60+ MVA at 11 kV, or a new
Rangiora East GXP constructed nearer the load base. This is the preferred option as it would provide
more security and scope for appropriate feeder development into the future.
The rate at which the load will grow is highly unpredictable especially with recent projections of migration
of earthquake displaced Christchurch residents to the area.
The earthquakes have caused rapid changes in the forecast rate of subdivision development and the
WDC projections for the location of the developments are also very fluid. One forecast is for the
accelerated completion of the Pegasus town, the rapid development of the neighbouring Ravenswood
block, and continued subdivision around the existing Woodend town boundaries. This could create a load
of more than 15 MW in the vicinity of Woodend which would be very difficult to supply from Southbrook.
Extensive future subdivision is also likely to occur east from Rangiora towards Woodend. With such a
large shift in the concentration of load a new GXP more central to the area would be required.
Status
There is a very large degree of uncertainty over these projections and the load growth may not occur as
rapidly, or may as the WDC suggest in their latest estimates, be more focused on Rangiora. In such
circumstances it may be more prudent to upgrade the Southbrook site. The deferment projects planned
will be more cost effective in the short to medium term and allow time for the nature of the growth to
become evident.
Transpower has completed a detailed design review and costing for a new GXP and MPNZ is looking to
purchase a suitable site in 2012. The budget is based on an early GXP completion in 2015.
GXP Substation Work Programme
Table 41 shows the forecast capital expenditure at each GXP station over the next ten years. It is
expected that MPNZ will enter into new investment agreements with Transpower which allows the cost to
MPNZ to be spread over 20 years for these assets.
Description
($Million)
2012-13
Kaiapoi GXP
2013-14
2014-15
2015-16
2016-17
2017-18
2018-19
2019-20
2020-21
2021-22
0.7
Ashley GXP
0.1
4.0
Southbrook GXP
0.12
4.0
Purchase Kaikoura
2.7
Waipara GXP
Rangiora East GXP
10
Table 41 Forecast Expenditure – GXP Development
7.14.3 MPNZ Sub-transmission and Zone Substation Development
This section outlines projected work for each of MPNZ’s subtransmission systems.
The location of MPNZ’s subtransmission lines and zone substations are shown in the network diagram
Figure 14 in Section 3. In addition Tables 16 and 18 in Section 3 shows the peak loads, security of
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supply, firm capacity and utilisation of capacity for each system. Tables 36 and 37 of section 6 show the
10 year demand forecasts.
The projected works are designed to alleviate the constraints identified in the tables above and where
possible raise the security to supply to meet MPNZ’s security of supply guidelines (table 38 section 7).
Waipara Kaikoura 66 kV
Projected work
Upgrade the 33kV subtransmission line from Waipara to Kaikoura to 66 kV, including the zone
substations along the route. Remove zone substations where practical.
Justification
The Kaikoura GXP is supplied from Culverden via a single wood pole line which is backed up, during
faults or annual week long maintenance outages, from Waipara on MPNZ’s coastal 33 kV line. The load
at Kaikoura exceeded that which could be backed up and MPNZ is in the process of upgrading the coastal
line to 66 KV.
Currently Waipara to Cheviot operates at 66 kV and Cheviot to Kie Kie just south of Kaikoura has been
reinsulated for 66 kV. The Leader substation has been replaced with a new 66 kV substation operation at
33 kV. This also supplies Claverley and the Claverley zone substation has been decommissioned. The
upgrade to Cheviot has enabled irrigation load growth along the coastal route whilst still improving the
capacity and stability of the line when supplying Kaikoura. The line is still constrained by the rating of
regulators at Claverley and the voltage drop at Oaro and fixed tap distribution transformers between Oaro
and Kaikoura. The line connection at the Kaikoura substation also has to be reconfigured for operation at
66 kV.
A number of large projects in the Kaikoura area have been put on hold with the recent economic downturn
and load growth has been lower than projected allowing the Kaikoura backup to be managed with the
delayed construction and partially completed upgrade. With this low growth there are options to provide a
small capacity increase using capacitors which may be implemented in 2013/14.
The Oaro substation would need to be rebuilt at 66 kV to complete the project. An alternative solution of
extending the Kaikoura distribution across the hills in conjunction with the 66 kV upgrade is preferred.
This would allow the Oaro substation to be decommissioned which would be more cost effective and
eliminate potential load control issues. This is also dependent on land owner agreement.
Status
An additional capacity charge has been incorporated into the pricing of new connections in the Kaikoura
District to help make the 66 kV upgrade economic.
MPNZ is negotiating with landowners on the remainder of the route to allow completion of the upgrade,
particularly across the hills between Goose Bay and Kaikoura. All line work except for this will be
completed in 2012. It is planned to complete the hill section in 2013/14 and upgrade the substation end in
2014/15. MPNZ’s acquisition of the Kaikoura GXP in 2012 may alter the design of the substation
termination.
Rangiora West 66 KV
Projected work
Upgrade the 33 kV subtransmission lines to the west of Rangiora to 66 kV. Replace the existing
four 33 kV / 11 kV zone substations with two 66 kV /22 kV zone substations with a secure capacity
of 20 MVA each. Convert the surrounding areas to 22 kV as required to meet the current load
demands.
Justification
The peak load on the Southbrook GXP has reached the rating of one transformer. In order to keep within
MPNZ’s security standard either the transformer capacity must be upgraded or the 33kV load reduced.
The peak load on the 33 kV subtransmission lines to Swannanoa, Cust, Bennetts and Oxford now
exceeds the 20 MW rating available with one circuit out of service. Supply can be maintained to most
customers by the demand control of irrigation customers but the potential economic impact is high.
The annual increase in the connected capacity of irrigation motors in the area has been very consistent for
the last 8 years averaging 800 kW. The load growth expected from this is approximately 1 MVA per year
including the capacity for associated dairies, pivots, cottages, and general growth. The planned
conversion of the Eyrewell forest area, which has already started, means this growth rate is unlikely to
decrease in the next 5 years. The likelihood of requiring significant load curtailment for a single fault is
increasing. A small amount of subtransmission capacity increase could be achieved by installing
capacitors at the zone substations but growth would overtake this within a few years.
94
The Oxford substation has a peak load approaching 7 MVA and is on a spur line with a single transformer.
This makes it MPNZ’s highest loaded low security zone substation. The most readily available backup
transformer is in Kaikoura, replacement would take 36 hours, and the replacement would be fully loaded
with the 2011 loads.
The Bennetts substation has two transformers but requires the full capacity of both at peak load. Both
Cust and Swannanoa are single transformers. Installing two new 66 kV / 22 kV transformers at
Swannanoa and continuing operation at 33 kV / 11 kV would free up the existing Swannanoa transformer
to be installed at Oxford to extend its capacity and make the Oxford transformer available as a larger more
general purpose spare. These incremental options still only extend the capacity for a couple of years and
do little to improve security.
The 11 kV distribution in the area is at full capacity and in most cases cannot provide a backup supply with
extending the load curtailment to a much wider area.
The Oxford transformer is switchable to 33 kV/ 22 kV as a direct replacement for the Mouse Point
transformers. The Mouse Point peak load now exceeds the rating of one transformer and it is appropriate
to release the Oxford transformer as a spare.
The Southbrook Cust 33 kV line is a 46 year old wooden pole line. Significant maintenance benefits will
also be realised from its rebuild for 66 kV.
Planned upgrade
MPNZ plans to convert the Rangiora West area from 33 kV / 11 kV to 66 kV / 22 kV. This will provide
double the existing capacity with some options for further increases, and remove the Rangiora West load
from the Southbrook GXP 33 kV transformers. It will require the construction of a new 66 kV / 22 kV zone
substation at Burnt Hill to supply the Oxford and Bennetts areas and the upgrade of Swannanoa to 66 kV /
22 kV. Both will have dual 20 MVA transformers.
The Southbrook – Swannanoa – Bennetts 33 kV line was originally constructed for 66 kV, as was the
Swannanoa substation. This substantially decreases the overall upgrade cost and time frame. The
existing 33 kV lines will be upgraded to 66 kV, rerouted and extended to provide a dual feed to both
substations. The existing Cust, Bennetts, and Oxford transformers will be decommissioned. The
Bennetts substation 22 kV switchgear will be utilised as a remote switching point and the substation site
held for future expansion. The Oxford 11 kV switchgear will also continue to be utilised in the medium
term. The surrounding distribution system will be converted to 22 kV.
The Burnt Hill site was chosen for the new substation as it is central to the load base, allows the creation
of a high number of feeders (up to 8), and has good access routes for two 66 kV circuits. This site is in
sparsely populated dry farmland with no near neighbours.
Status
The option of upgrading the existing Oxford site was discarded as the site was small and located in the
Oxford township urban area with immediately adjacent residential housing. It would have been very
difficult to extend two 66 kV circuits to the site without extensive underground 66 kV. The environmental
effects of the larger site would also have been very difficult to mitigate. The Oxford site did not offer the
same opportunities for sufficient feeders to supply the required area without compromising reliability and
security, and is much less central to the load area.
Land is being purchased for the Burnt Hill substation and planning for the 66 kV line construction is
underway. Consultation with affected land owners and consent applications will begin early in 2012.
Transpower is preparing proposals for the addition of 66 kV feeders from Southbrook.
Upgrade of the Swannanoa substation will be largely completed in 2012/13 with the delivery of
transformers and commissioning occurring winter 2013. Construction and commissioning of the Burnt Hill
substation is expected before the summer of 2014/15. Completion of the second 66 kV circuit to Burnt Hill
will be March 2015. Conversion of key areas of the distribution system to 22 kV will be ongoing through
this period, and continue in the following years as required by growth.
95
Figure 43 Rangiora West 66 kV and 22 kV
Southbrook Waipara 33 kV
Projected work
Partial underground conversion.
New Amberley substation.
Justification
The eastern side of Rangiora through which the line passes is subject to intensive residential subdivision.
It is anticipated that MPNZ will be approached by developers to underground part of the line to improve
property values. This would be chargeable to the developers. MPNZ has no requirement to upgrade or
underground the line which will probably become redundant in 10 to 15 years.
The Rangiora North zone substation will remain as existing until it is decommissioned beyond the planning
period. The highly loaded Amberley zone substation will have its load reduced by upgrades to the Ashley
GXP and may require upgrading towards the end of the planning period. The Ashley GXP upgrade will
introduce a phase shift between Ashley and Amberley which will reduce flexibility for normal operational
switching. The Amberley substation would probably be upgraded as a 66 kV / 11 kV substation supplied
either off the Transpower 66 kV circuits, or from the 33 kV line upgraded to 66 kV and redirected to Ashley
GXP at the southern end.
Status
Consideration has been given to upgrading the Ashley GXP to 22 kV to supply the Amberley area in
conjunction with an upgraded MacKenzies Rd substation to the north. This would allow the
decommissioning of the existing substation and the 33 kV line (as Rangiora North is decommissioned at a
similar time). This was found to be less economic and provide lower security and future growth potential
for the Amberley community.
Budget provision has been made for a new Amberley substation build between 2018 and 2020.
No developer has yet approached MPNZ regarding the underground conversion.
Waipara Hawarden 33 kV
Projected work
Stage 1 upgrade the 33 kV conductor
Stage 2 convert the line and Hawarden substation to 66 kV
Justification
This is a radial 33 kV line feeding a remote load of approximately 2.8 MVA at Hawarden which is expected
to grow to only 3.6 MVA by 2021. This line will cope with the expected load growth but will have high
96
losses due to its “Ferret” conductor. The “Ferret” conductor does not comply with the AS/NZS7000:2010
design snow loading requirements for a distribution line. MPNZ expects a higher level than this even for a
rural spur subtransmission line.
The future development of the Hurunui water project would be a significant contributor to growth in the
Hawarden and Waipara areas and is expected to require an additional 8 MVA of capacity if it proceeds,
and trigger a major upgrade to the line. Mini and micro hydro generation from new irrigation schemes
would also be considered as an alternative to any upgrade should the final loading requirements of the
Hurunui Water Project be smaller than expected.
MPNZ is also investigating wind generation sites in the area which would have a significant impact on the
capacity of the line.
Consideration would be given to converting the line to 66 kV and building a 66/22-11 kV zone substation
at Hawarden if load and / or generation increased significantly.
Status
If this line and the Hawarden zone substation was removed and the area supplied from Mouse Point and
MacKenzies Road zone substations at 22 kV studies show that regulation voltage could not be
maintained. These substations do not have the spare capacity either.
No detailed planning has been completed.
For planning purposes MPNZ has assumed that a conductor strengthening upgrade will be undertaken in
2016/17 and that conversion to 66 kV may be required in 2017/18.
Culverden Hanmer 33 kV
Projected work
Upgrade the 33 kV conductor.
Justification
Peak load is approximately 5.0 MVA and is expected to be 6.0 MVA by 2021. The Hanmer load duration
curve has a steep profile indicating only small numbers of half hours at peak usually experienced during
winter holiday periods when people reside in their many baches and holiday homes in the area. Demand
control targeted at reducing the Hanmer peaks can significantly reduce the peak load and work is being
done to improve this. Peak reduction could defer any capacity upgrade requirements for many years.
The “Ferret” conductor does not comply with the AS/NZS7000:2010 design snow loading requirements for
a distribution line. MPNZ expects a higher level than this for a rural spur subtransmission line, particularly
where the load exceeds 5 MVA with no backup. Conductor upgrading will start in 2018 from the Lochiel
end of the line and working back south. The Lochiel to Hanmer section has shorter spans with larger
“Mink” conductor. The first 3 km north from Mouse Point was also upgraded in 2011 due to the low fault
current rating of “Ferret causing conductor failure.
This line has been highly maintained over the years and therefore has high reliability except in major snow
events. It could eventually be upgraded to 66 kV, however this will be outside the AMP planning period
and will be after the Culverden GXP is upgraded.
Hanmer will require a source of back up supply over the longer term and outside of this plan as load grows
and security standards are breached. The cost and difficulties involved in a second line route are such
that alternative options are preferred. Alternative options to be considered are the promotion and
installation of distributed generation in the Hanmer region, the provision of standby generation sets at
Hanmer to reduce peak loads, a study on the impact of smart grids and smart metering on peak reduction.
The Hanmer zone substation transformer is rated at 6 MVA (with a backup 3 MVA) and is unlikely to
require upgrading within the planning period. The Hanmer substation has only two feeders and the peak
load is exceeding the capacity of one. Within the next 10 years it will be necessary either to increase the
existing feeder capacities, add a third feeder, or install several MVA of DG capacity to maintain security.
In either case a protection upgrade will also be required. The Lochiel substation may require secondary
voltage regulation added as load grows.
Status
The Lochiel zone substation is unregulated. As the load at Hanmer grows the voltage fluctuations at
Lochiel will become excessive and secondary voltage regulation will be required.
No detailed planning has been completed.
For planning purposes MPNZ has assumed that the Lochiel regulator will be installed in 2015, the Hanmer
feeder in 2017, and the conductor strengthening will be undertaken starting 2018.
97
Major Zone Sub Upgrade
Budget provision has been allowed to rebuild one zone substation at the end of the planning period. This
could be Hawarden, Mouse Point, Kaikoura, or MacKenzies Rd depending on load growth.
Miscellaneous Minor Work
In addition to the above work, a budget provision has been allowed for minor works. This includes the
gradual phasing out of old induction disc protection systems and the oil filled substation circuit breakers to
improve reliability and staff and public safety.
Installation of smoke alarms in all substation buildings and temperature monitoring systems on substation
transformers will continue to be progressed over 2012-2013 as part of MPNZ’s risk management
programme.
66 kV and 33 kV Sub-transmission and Zone Substation Work Programme
Table 42 contains the forecast capital expenditure on the 66 and 33 kV sub-transmission systems and
Zone substations over the next ten years. All estimates are at 2012 values.
Description
($Million)
Waipara Kaikoura
2012-13
2013-14
0.2
1.45
Kaikoura substation
2014-15
2015-16
0.5
0.5
Waipara Hawarden
2016-17
2017-18
0.5
0.5
2018-19
2019-20
2.5
2.5
0.5
0.5
2020-21
2021-22
3.0
3.0
Waipara Southbrook
New Amberley substation
Culverden Hanmer
Lochiel Substation
0.1
Hanmer substation
0.3
Southbrook Burnt Hill
2.47
Bennetts Burnt Hill
2.2
Swannanoa substation
0.63
Burnt Hill substation
2.47
2.2
3.0
2.5
0.15
Zone Substation Rebuild
Misc minor work
Total
3.03
0.2
0.2
0.2
0.2
0.2
0.2
0.2
0.2
0.2
8.55
6.0
0.95
0.7
1.0
3.2
3.2
3.2
3.2
Table 42 Forecast Expenditure – Sub-transmission Development
The projects to be progressed within the coming year comprise:

Waipara Kaikoura 66 kV – This will complete all work except for the Rakanui Hill section awaiting
easements and the Kaikoura substation termination.

Rangiora West 66 kV – Bennetts to Burnt Hill section via South Eyre Rd. Work will focus on
completing this section in however if there are any delays or work is completed early, focus will shift to
the second Bennetts to Burnt Hill route via Woodstock Rd

Rangiora West 66 kV – Upgrade Swannanoa substation to a double banked 66 kV substation. The
purchase, installation and commissioning of the new transformers is scheduled for April/May 2013.
These will run as 33 kV / 11 kV until the remaining project stages are completed.
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7.14.4 Distribution Development
Distribution development is largely based on the planning assumptions set out in this plan, the results of
load flow analysis on the 11 kV and 22kV systems and local knowledge of the load development in each
area. Key initiatives over the next five years will to be:

Feeder development as a result of zone substation and switching station upgrades.

Splitting out urban or rural urban customers from customers on rural lines to improve reliability where
customer density is higher.

Creating, where warranted, more feeders out of substations, or rebalancing feeders, to reduce the
number of customers and length of line on low reliability feeders.

Splitting up of long feeders with circuit breakers to help reduce lost customer minutes of power supply.

Strengthening under rated lines in snow regions up to the requirements of AS/NZS7000:2010.

Improving power restoration times following system faults. MPNZ has purchased remotely operated
gas switches for testing, with a view to placing them into various positions in the network.

Taking opportunities to build in links to provide alternative supply or back up supply for local regions,
providing the cost benefit breakpoint of doing so is not reached.
Key development projects are discussed below with objectives and options where appropriate.
Kaiapoi North Switching Station and Cabling
Projected work
Install a new, secure, distribution switchboard on the north side of Kaiapoi with six feeders to the
surrounding areas. Extend two cables 1.7 km north to S.H.1 to provide independent feeds to
Woodend / Pegasus.
Justification
The northern Kaiapoi area has been growing rapidly due to the Moorecroft subdivision and more recently,
the Sovereign Palms subdivision. The recent earthquakes have accelerated the rate of development.
There will be approximately 900 lots in the two subdivisions.
Historically the area has been supplied on a semi rural radial overhead feeder of limited capacity. The
switchboard will have two incoming cables from an upgraded Kaiapoi GXP (refer 7.14.2) to provide a high
security and capacity distribution point local to the subdivision and allows meshing of the subdivision
reticulation to provide security and allow switchgear maintenance without extensive outages. This will
substantially improve the reliability of supply to these areas. The switchboard also has provision for future
subdivision in the area. A separate feeder will supply the original overhead area and provide a backup
connection to the main Kaiapoi urban area.
Status
As outlined under the Kaiapoi GXP upgrade, the Southbrook zone substation has reached full capacity
and the optimal way to manage this is to transfer load from Southbrook to Kaiapoi. Two feeders are being
cabled from Kaiapoi North to S.H. 1 to allow up to 10 MVA of load from the Woodend / Pegasus areas to
be supplied from Kaiapoi with provision for backup and no loss of security or reliability.
This project is nearing completion with the 4 km of two incoming cables installation complete and the
distribution substation due for completion in May 2012. The feeder cabling should be completed and
ready for commissioning about the same time. Transfer of load from Southbrook to Kaiapoi will occur
before the 2012 winter peak load period. Completion of the subdivision mesh network is integral with the
subdivision development but is likely to occur before 2014.
Rangiora Eastern Feeder
Projected work
Reconfigure the supply from the existing Southbrook zone substation Waikuku feeder circuit
breaker to supply to the eastern side of Rangiora.
Installation of a high capacity cable from the Southbrook zone substation to Boys road,1.5 km
north on the east side of Rangiora. Provision for a second high capacity cable. Extension of the
urban underground feeder from Boys road back to Mitre 10 at Southbrook including Kiosks,
switchgear, and low voltage undergrounding along the route.
Justification
The Rangiora Borough and East feeders are too highly loaded to provide substantial backup for each
other in the event of a fault. There is major subdivision development occurring on the east side of
Rangiora with approximately 250 lots developed over the last few years and a further 400 expected over
the next 5 years. Some of the Rangiora urban fringe is already supplied from the Waikuku rural feeder to
alleviate this high loading but the capacity for this is limited and it exposes the urban area to rural faults.
99
The Kaiapoi GXP project and the Kaiapoi North substation and cabling project remove load from the
Southbrook zone substation Woodend feeder and allow this feeder to be used to supply Waikuku. The
Waikuku feeder circuit breaker can than then be reconfigured to allow the capacity released by the load
transfer to Kaiapoi to be redirected to the east side of Rangiora to meet the growth and allow loading on
the existing Rangiora East feeder to be reduced. This then provides more security in the event of a fault
on the Borough or East feeders and increases the reliability by rebalancing the length of cable and
number of customers on each feeder. There is increased security for Waikuku and no reduction in
reliability.
Status
A further budget provision has been made in 2015/16 to extend this feeder from Kippenberger Av to the
north end of Rangiora and create ties to the East and Borough feeders.
Initial route planning has begun but easements are still to be obtained and final design undertaken.
Completion is targeted for 31 March 2013.
Rangiora West 22 kV Conversion
Projected work
This is the 22 kV conversion and feeder reconfiguration for the Rangiora West 66 kV project.
The distribution upgrade and conversion work will continue for 5 years, with further work beyond
this as required by load growth.
The first stage is the Horrelville area to be completed by September 2012.
Kaiapoi GXP Feeder Upgrades
Projected work
The work covers the feeder reconfiguration work associated with the Kaiapoi GXP Upgrade. This
includes reconfiguring the terminations of the existing 300mm cables to the Kaiapoi North
switching station, installing a new 300mm feeder cable north 1 km, and approximately 2 km of
cabling for the start of the Wetherall feeder, splitting it into two feeders.
This work would be partially funded by the Silverstream subdivision developer and is dependent
on progress with the Silverstream subdivision.
Justification
The scope also includes extending a higher capacity supply south on Island Rd and linking this
with the existing K4 feeder.
The existing feeders are too light to allow the increased capacity of the Kaiapoi GXP to be utilised and still
meets MPNZ’s security guidelines. These upgrades allow more capacity to be securely delivered from the
GXP.
Johns Road Link
Projected work
Install a 650m 11 kV cable link between sites 2156, 8395 and 8392 in Johns Road Rangiora.
Underground the existing HV and LV distribution for 300m.
Justification
The Rangiora Borough feeder is very highly loaded and cannot be backed up from neighbouring feeders
at peak load. The new cable will provide a strong link between the Rangiora West switching station and
the Borough feeder allowing backup for a fault in the first 2/3rds of the feeder. It will allow better load
balancing between the Rangiora West switching station feeders improving reliability and also substantially
improving their capacity to provide backup for a fault in the last 1/3rd of the Borough feeder. This is the
third stage of a 3 year upgrade project.
Status
This project, in conjunction with the Rangiora Eastern Feeder project is designed to improve the reliability
of supply to the Rangiora urban area and to meet MPNZ’s security guideline of 100% restoration of an
urban feeder with 6 hours.
No planning started. Completion March 2013.
Wetherall Feeder Upgrade.
Projected work
Upgrade conductor for 2.5 km in Giles Rd Kaiapoi and 1.5 km on Tram Rd Ohoka
Justification
The loading is such that the voltage falls to the regulatory limits at peaks load times with no scope for
alternative feed arrangements during faults. This is primarily due to the small conductor in Giles Rd near
to the start of the feeder, and the very small conductors towards the extremities. The installation of
capacitors and / or voltage regulators are possible but this is a high growth lifestyle development area with
high year round loads. Capacitors and regulators only provide a short term high loss solution in these
circumstances. Further upgrades to the very small main line conductors in the Mandeville east area will
100
Status
be required in the near future. The larger conductors will also be physically stronger, compliant with
AS/NZS7000:2010 snow loadings, and more reliable.
No planning started. Completion March 2013.
Waipara Amberley Link
Projected work
Complete the 2.2 km of new line and 2 km of line upgrade required to link Amberley town direct to the
MacKenzies Rd substation
Justification
Amberley substation is highly loaded and cannot be backed up for much of the year. This breaches
MPNZ’s security criteria. The stronger link to MacKenzies Rd will enable backup at high loads for several
years until the Ashley GXP upgrade further deloads the Amberley substation. It also introduces an
alternative supply route to the northern part of Amberley town significantly improving reliability.
Status
Planning is 90% complete and construction will be 50% complete by 31 March 2012.
Final completion by end of May 2012.
Mouse Point P55 Upgrade
Projected work
Upgrade two weak sections of the P55 feeder in the River Rd and Leslie Hills Rd area
Justification
This is the last stage of the conversion of the Leslie Hills area to 22 kV and the removal of the Leslie Hills
substation to provide a higher capacity supply to the Leslie Hills area and an alternative supply to Waiau.
It also reduces the size of the very large P45 feeder supplying Waiau and Rotherham. The ability to
supply significant power east beyond River rd is constrained by a short section of galvanised steel
conductor and a short section of Magpie conductor. The galvanised steel conductor will be replaced. Part
of the Magpie conductor will be replaced and part bypassed by a small length of new line on a more
accessible route without easement and maintenance constraints.
Status
No planning started. Completion September 2012.
Mouse Point P25 Upgrade
Projected work
Upgrade 2 km at the start of the P25 feeder from “Helium” to “Neon” conductor.
Justification
The feeder is becoming voltage limited at peak load times. It has adequate thermal capacity. This
upgrade reduces the peak load voltage drop at the end of the feeder. There are a number of short lengths
of light conductor in the main line of the feeder which are planned to be upgraded as necessary to
maintain supply quality. This will be dependent on future load growth but is likely to occur over the next 5
years.
Status
The first 2 km passes through a farm which may require the line to be rerouted to allow for irrigation. The
upgrade is on hold pending resolution with the land owner over development plans. It is expected this will
proceed in the 2012/13 financial year.
Cheviot Greta Link
Projected work
Install 3 km of new 22 kV line on the north side of the Hurunui river to link the Greta and Cheviot
substations.
Justification
During 2009-10 the line south of Cheviot through Tormore was upgraded to 3 phase mink conductor due
to increased irrigation load.
There is now only a small gap to be filled between the two substations. Filling the gap, in conjunction with
a 22 kV step up transformer, will allow Greta and Leader substations to back up Cheviot between them
lifting the security to near urban standard as discussed in the security guidelines.
Status
This is budgeted for 2016/17
Medbury 22 kV Conversion
Projected work
Conversion of the reticulation between the Waitohi and Hurunui rivers to 22 kV, and supplying
from the H41 feeder rather than the H31 feeder.
Justification
The load in this area is growing, mainly from irrigation and dairying. The reticulation is very light,
historically very lightly loaded, and distant from the substation. The irrigation development represents a
large load increase. The feeder is long and is among the MPNZ’s worst ten configurations for reliability.
Status
The neighbouring H41 feeder reliability profile is four times better and it has much higher capacity
operating at 22 kV. Converting the area and transferring feeders is the most cost effective way to provide
increased capacity and reliability for new irrigation loads. Load growth in 2011 was lower than expected.
This work will be driven by customer load growth and is expected to be required by the end of 2015.
Kaikoura Undergrounding
Projected work
Over the next five years the 11 kV and low voltage distribution along parts of the Esplanade,
Churchill Street and Beach Road will be undergrounded where it coincides with Council or
101
Justification
Status
customer driven work.
This work will be partially customer funded and is a RS&E project.
The timing will be dependent on the Kaikoura District Council and other customers. Funding provision for
this is expected in the upcoming Kaikoura Long Term Regional Plan.
Kaikoura Peketa to Oaro 22 kV Conversion
Projected work
Install a 11 kV / 22 kV auto transformer near the start of the Inland road and convert the remainder
of the Peketa spur and Oaro distribution to 22 kV
Justification
This is part of the Waipara Kaikoura 66 kV project. It is required to provide a 22 kV supply with sufficient
capacity to feed Oaro and allow the removal of the existing Oaro substation.
Status
Timing will be dependent on completion of the 66 kV and 22 kV line build across the “Rakanui” hills from
the Kahutara river to Kie Kie stream.
Kaikoura SWER Upgrades
Projected work
Any further requests for additional capacity in PuhiPuhi will involve upgrading the first half of the
line to three phase and relocating the isolation transformer, or alternatively investment in peak
load trimming DG.
Justification
The Puhi Puhi SWER system has reached 20 amps and the rating of its isolation transformer.
MPNZ has had enquiries for higher capacity along the SWER section of the Inland road and it is expected
that an upgrade to 3 phase will be required in the medium term.
Status
Both of these projects will be customer driven and at this stage budget provision has been made for the
2015/16 and 2017/18 years.
Ashley Feeder Establishment
Projected work
The GXP is being upgraded from solely supplying the Daiken MDF plant , to supplying the
surrounding Loburn, Ashley and Balcairn areas.
Justification
Status
Initially four feeders will be required, two of these can terminate onto the existing overhead line
outside the GXP, and two will be cabled 600m to the Upper Sefton Road intersection. A new ripple
injection plant will probably be required and remote control facilities. An alternative load control
option using long wave radio will be investigated and may prove economic for this project in
conjunction with the requirements for load control for the Rangiora East 66 kV upgrade. As the
load continues to grow more feeders will be required towards the end of the planning period.
This is the distribution work associated with the Ashley GXP upgrade.
Completion of the load plant and the first two feeders is expected in 2013/14 with the second two in the
following year. Budget provision has been made for the increasing conductor sizes near the substation as
required in the following years with the last two feeders installed in 2020/2021.
Woodend Distribution Development
Projected work
Stage 1 - Join the two cabled spurs in Gibbs Drive together to form a ring feed with RMU’s.
Recover three ABS’s.
Future stages – Upgrade conductors and install cables and switchgear as required to integrate the
fragmented Woodend supply into the surrounding network.
Justification
The distribution system for the old parts of Woodend town comprises of a number of spurs off S.H.1.
These are mainly old light overhead lines. New underground subdivisions form the north end of town. As
Pegasus and other planned subdivisions develop the old town will be almost completely surrounded by
new subdivision. The existing distribution will need to be rationalised and integrated into the surrounding
underground network in order to maintain reliability. Stronger feeds will also be required through the old
sections to supply the new subdivision areas.
Budget provision has been allowed for this throughout the planning period.
Status
Stage 1 will be completed in 2012
Kaiapoi Earthquake Work
Projected work
Some redevelopment of the network will be required to provide a reliable solution for the future
Justification
The Red Zoning of large areas of Kaiapoi has left a lot of uncertainty over the reticulation in those areas,
and the future of roads and feeders throughout the Red Zone. It is likely that new roading patterns will be
developed to suit the remaining housing areas. Leaving the old potentially weakened infrastructure in
place, much of it redundant through the Red Zone would lower reliability and potentially pose hazards to
the public.
Status
Budget provision has been allowed for reconfiguration work although the timing and nature of this will be
dependent on the Council and government authorities.
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General Underground Conversion
MPNZ has a close relationship with the councils in its area and where possible integrates its network
development with council activities. MPNZ has a commitment to the communities it serves to optimise
environmental, safety and reliability outcomes. MPNZ staff regularly exchange long term works programs
with councils and seek opportunities to minimise the cost of undergrounding and maximise the community
benefit through shared works. Often this is driven by the council water pipe upgrade program as they are
generally laid in similar locations to power cables. These works are usually identified a year or more in
advance but some also come up at short notice.
MPNZ has a number of small community urban situations (e.g. a number of beach towns) where the
existing overhead reticulation is very old and requires large scale replacement.
Whenever 11 kV and 230/400V overhead lines are maintained in urban areas, consideration is given to
the technical, environmental, social and economic factors involved in conversion to underground.
Generally lines with reasonable remaining life will not be considered for undergrounding. MPNZ has
decided that as part of its corporate responsibility to the community it will fund underground conversion
work each year in areas returning a high social dividend. Examples of this have been the underground
conversion of Southbrook Road and Percival Street in Rangiora, Conical Hill Road in Hanmer, Williams
Street South in Kaiapoi and parts of The Esplanade in Kaikoura. In a small number of cases, the driver for
underground conversion can be growth. For the majority of projects, the driver is social responsibility.
Generally there are fewer technical benefits than would ever outweigh the cost of underground
conversion.
MPNZ has established a higher community profile in recent years due to a strategic decision to place high
value on the wellbeing of our community. Most underground conversion work therefore meets MPNZ’s
community objectives as do our energy efficiency programmes.
All underground conversion projects require special approval after consideration of the long term benefits.
A general budget provision has been allowed for such work through the planning period.
General 22 kV Conversion
MPNZ is of the view that, in the absence of very substantial growth in DG, distribution capacity upgrades
for most of our rural areas will be achieved by conversion to 22 kV. There are exceptions to this. Where
existing conductors are too light for potential snow loadings, larger conductors will also bring increased
reliability and safety. Voltage regulators are always an option for long spurs where the growth is slow or a
“one off” development occurs.
The 22 kV conversion process has a number of other benefits including the reduction in line losses, the
reduction in transformer losses due to modern MEPS transformers replacing old ones, and the renewal of
aging transformer assets. Some of the newer recovered 11 kV transformers can be reused in 11 kV areas
although towards the end of the planning period the potential for this will decrease as more of the system
operates at 22 kV.
A general budget for future 22 kV conversion has been allocated which increases as planned conversion
projects taper off.
Rangiora East GXP Feeder Development.
Projected work
Install cables to Pegasus Switching Station.
Construct a Rangiora East switching station and cable.
Strengthen local overhead feeders.
A further switching station may be required on the west side of Woodend as the area is developed.
Justification
When a new Rangiora East GXP is constructed to relieve loading constraints on the Southbrook zone
substation and the Kaiapoi North switching station, substantial feeder changes will be required.
Two 300mm cables will be required to connect to the Pegasus switching station which will supply the
Pegasus town, and part of Woodend. The existing overhead lines can supply the remainder of Woodend
and Waikuku initially but may require some fault level strengthening. One or two 300mm cables would
need to be extended to a new switching station on the east side of Rangiora to provide feeders and
capacity for the new subdivisions. As development progresses in the following years, further feeder
103
Status
development will be required.
Budget provision has been allowed for this work staring in the year prior to GXP commissioning. As
discussed under GXP Station Development, the timing of this work is highly dependent on real growth and
may be significantly delayed from the budgeted time frame.
DG Related Upgrades
A number of distributed generation proposals have been mooted in MPNZ’s area including several being
investigated by MPNZ. It is unknown when or if any of these will eventually be completed although
MPNZ’s Mt Cass wind farm has been consented. This would be probably be grid connected but a general
budget provision has been allowed for network development related to this and other schemes.
The provision does not necessarily reflect the full cost of such work but is an attempt to recognise the
reality that some significant costs will be incurred, possibly in the first half of the planning period.
Substation Resonant Earthing
Budget provision has been made for the installation of resonant earthing systems at substations beginning
in 2016. MPNZ recognises the potential of the systems for improving safety and reliability. There are a
number of challenges in introducing such systems particularly where grounded auto transformers are used
for 22 kV / 11 kV conversion. All new substations will be designed to be compatible with their future
installation.
Distribution System Automation
Budget provision has been made for future distribution automation initiatives starting in 2015. More
products are coming onto the market for reducing outage times and improving power quality. MPNZ is
participating in proposals to roll out smart metering with its associated communications network. This may
provide the communications infrastructure for future automation.
Load Management Relays
Every year MPNZ purchases new load management control relays for use on new customer connections.
MPNZ also installs a water heater control relay on each residential connection containing an electric water
heater, and on irrigation pump motors to turn them off during network system constraints or emergencies
to improve system reliability. Forecasts are consistent with the assumptions underpinning new
connections over the forecast period.
The cost of ripple injection plants is associated with the relevant GXP or Zone Substation. MPNZ is
involved with smart metering proposals that may replace most relays. MPNZ is also reviewing the
economics and benefits of long wave radio load management. This would require similar relays but would
require a peak expenditure in the start up phase of conversion. Neither of these proposals have been
included in the budget provision which assumes a continuation of the status quo.
Customer Network Extensions
This is the budget provision for capital work associated with network connections for new customers,
subdivisions, irrigation etc.
Some new connections are straightforward where a connection point has been allowed for and usually
involve connecting the customer’s service main cable into a MPNZ service box fuse. Other new
connections can involve an upgrade to the network or an extension to the network system to
accommodate the additional capacity requirement and/or the connection location. In respect of network
development, large subdivisions are also classified as network extensions involving multiple customer
connections. All new customer connections attract a customer capital contribution charge which is equal
to the cost of the uneconomic portion of the work being done.
This budget provision includes the full cost of work including any uneconomic component funded by
customer capital contributions.
104
Miscellaneous Distribution upgrades
This is the budget provision for unidentified upgrade work. This provision increases through the planning
period as the detail of planned work reduces. Most expenditure under this heading will be a response to
specific load growth with less than 5 years advance planning.
Distribution System Work Programme
Table 43 shows the expected levels of upgrade work on the MPNZ distribution system over the next ten
years. Projects identified in the 5-10 year period are less certain from a cost and timing perspective.
This does not include system maintenance and renewal.
Description
($Million)
Kaiapoi North Switching Station
and Cabling
Rangiora Eastern Feeder
Rangiora West 22 kV Conversion
2012-13
2013-14
2014-15
2015-16
0.450
2.2
1.3
1.3
0.075
0.075
0.150
Johns Rd Link
0.25
Wetherall Feeder Upgrade
0.14
Waipara Amberley Link
0.12
Mouse Point P55 Upgrade
0.07
Mouse Point P25 Upgrade
0.075
.5
Cheviot Greta Link
.5
.5
.5
0.05
0.05
0.05
0.1
0.1
2019-20
2020-21
2021-22
0.05
0.05
0.05
0.3
0.05
0.025
0.025
Peketa Oaro 22 kV Conversion
0.4
0.35
Kaikoura SWER upgrades
0.3
Ashley feeder establishment
0.35
0.15
0.25
Woodend Dist. Development
0.1
0.1
Kaiapoi Earthquake Work
0.1
0.1
0.1
0.1
General Underground Conversion
0.5
0.375
0.375
0.2
0.2
1.0
1.2
Rangiora East GXP Feeder Dev.
DG Related Upgrades
1.0
Distribution system Automation
0.1
6.5
0.3
0.1
6.5
0.4
0.4
0.4
0.4
0.4
0.4
0.3
0.3
0.3
0.5
0.5
0.5
1.25
0.25
0.5
0.5
0.4
0.4
0.4
0.4
0.4
0.4
0.25
0.25
0.25
0.25
0.25
0.25
0.25
0.08
5.6
0.07
5.6
0.07
5.1
0.07
5.1
0.07
5.1
0.07
5.1
0.07
5.1
Substation Resonant Earthing
0.1
6.5
0.3
0.1
General 22 kV Conversion
Customer Network Extensions
2018-19
0.35
Medbury 22 kV conversion
Load Management Relays
2017-18
0.3
Kaiapoi GXP Feeder Upgrades
Kaikoura Undergrounding
2016-17
0.395
Miscellaneous Dist. Upgrades.
0.10
0.10
0.15
0.20
0.90
0.90
0.90
0.90
0.90
0.90
Total Distribution Projects
11.23
9.03
9.85
11.23
10.77
9.12
7.97
7.67
7.97
7.67
Table 43 Forecast Expenditure – Distribution System Work Programme
7.15 Total Capital Expenditure 2012-2021
The following table summarises all the planned capital expenditure outlined in this section, for the period
2012-2021. This table includes expenditure on asset renewals which will be capitalised in part and are
discussed in the maintenance section following. The detailed discussion and budgets for renewals are
included in the following Section 8 – Maintenance and Renewal Plan. They have been included in Table
44 below to meet the Commerce Commission’s information disclosure requirements introduced in October
2008.
105
Capital Expenditure by Asset Type
$25
Trees and Other
SCADA & Comms
$20
Services
$ (Millions)
LV Distribution
LV Switchgear
$15
Distribution Transformer
Distribution Substation
HV Distribution
$10
HV Switchgear
Zone Substation
Subtransmission
$5
$0
2012/13 2013/14 2014/15 2015/16 2016/17 2017/18 2018/19 2019/20 2020/21 2021/22
Table 44 Total Capital Expenditure (inc Renewal) 2012- 2021
106
8
MAINTENANCE AND RENEWALS PLAN
8.1
Introduction
Maintenance and renewal planning seeks to achieve the desired levels of service required by customers,
while optimising the costs over the asset lifecycle. This objective is consistent with the service level
targets previously outlined in Section 4, specifically the targets for reliability, quality, safety, customer
service (i.e.: fault response times), environmental and economic efficiency.
Information relevant to management of the asset lifecycle is included throughout this AMP as follows:

Background data is provided in Section 3 for each asset class and includes:
–
–
–

The Network Development Plan, provided in Section 7, which includes:
–
–
–
–
–

A description of the assets, value, capacity and performance
Asset condition
Historical data and source of data including that derived from inspections and maintenance
activities.
Planning criteria and assumptions
Prioritisation methodology
Non-network solution developments
Embedded generation developments
A discussion of alternative development options, the development programme and forecast
expenditure.
A description of asset management systems and information management is provided in Section 2.
This section outlines the Maintenance and Renewal Plan for network assets and includes a discussion of
the planning criteria and processes used by MPNZ for each asset class. The Maintenance and Renewals
Plan covers operations and maintenance, renewals and replacements, and disposals. It includes forecast
expenditures for each activity.
8.2
Planning Criteria and Assumptions
8.2.1 Maintenance Practice
Optimising lifecycle costs across the life of long-lived assets requires assessment of an asset’s expected
performance, the consequences and probability of failure and the level of expenditure necessary to avoid
such failures. The costs of maintaining an asset vary significantly over its life and in the case of many
distribution assets, maintenance works can account for many times the initial cost of an asset.
MPNZ recognises that lifecycle costs are a key component in the economic appraisal of capital projects
and in the formulation of development and maintenance programmes. To enable effective cost analysis,
information systems must capture cost information across all phases of the asset lifecycle. An asset
management system employing GIS and SQL software has been developed that includes all network
asset data. All maintenance and renewal activity is recorded on this system.
In order to compare the costs of ongoing maintenance with the cost of new or replacement assets the
following items are considered:

Risk of asset failure

Asset maintenance and operating costs

Asset disposal cost

Asset purchase value.
107
Where there are significant risks to system reliability, safety or the environment, specific project economic
analysis may not be undertaken. The main drivers of the maintenance and renewal plan therefore are the
results of asset condition surveys, condition based maintenance assessments, asset renewal
programmes, asset obsolescence, safety considerations and regulatory compliance.
It is MPNZ’s view that overhead lines can be operated, maintained and renewed on an ongoing basis
consistent with their original service potential such that the probability of failure is held constant. The
performance of the system and the monitoring process together provide an ongoing indication of the
health of the network and the basis for the matching of maintenance, renewal and capital expenditure to
stakeholder expectations and service level targets.
Asset-age profiles are important in determining the relative overall economic performance of each asset
and to avoid any peaks in equipment failures that closely follow the asset age profile. However there are
other factors besides age profile that affect the timing of an asset’s replacement. These are:

historical reliability

strategic importance

ability to accommodate new technology and information system requirements

whether the asset can perform to levels of service above the targets set or meet the security
standards that apply.
In practice, on MPNZ’s network, most replacements are decided by natural upgrades of systems due to
growth or change in fault level and more frequently now by the requirement to have additional intelligence
or performance at a site.
MPNZ does not expect to see a major shift in electricity network technology in the foreseeable future that
would have a significant impact on network component performance or redundancy. Expected
technology gains are expected to be minor and complimentary to the existing assets.
Network development in response to growth helps to replace old technology by replacing assets that are
not intelligent enough or assets that have their ratings exceeded. Over time there has been a significant
contribution to the renewal of the system from the alterations needed to accommodate additional
customer requirements or to meet changing customer needs. Other activities that contribute to ongoing
asset renewal include underground conversion of overhead lines, line relocations for land development or
road alterations and replacements of damaged assets from vehicle collisions. MPNZ is increasing the
percentage of concrete pole used for new extensions and maintenance. Underground extensions use
modern reliable cabling systems. These will both deliver reduced maintenance in the longer term.
The mode of maintenance of the system is now primarily condition based whereby individual components
are renewed when their condition and serviceability has deteriorated to the point that it creates an
unacceptably high risk of failure.
The Maintenance and Renewal Plan reflects:

Routine and preventative maintenance

Renewals and refurbishment.
Both of these aspects of the Maintenance and Renewal Plan involve the following activities:

Reactive maintenance or repair on breakdown.

Time based preventative maintenance

Condition based maintenance

Reliability based maintenance
We address each of these aspects in the following sub-section.
108
A computerised works management system is used to schedule and control the maintenance
programme. The effects and costs of maintenance are tracked to reliability and a two yearly external
review forms part of the production of maintenance and replacement strategies.
Renewals are primarily full component based replacements such as pole and cross arm replacements
without capturing any betterment or upgrade. Generally replacement of smaller sub assembly
components such as tapchanger contacts or air break switch contacts is treated as maintenance.
All equipment must be fit for its intended purpose. Each decision to replace unreliable equipment will
consider the following:

Cost of repair versus cost of replacement or renewal

Can the item be re-used in a less strategic position where it can work reliably, eg, an older circuit
breaker that has longer clearing times due to wear may co-ordinate better at an alternative site

Availability of spares.
8.2.2 Maintenance and Renewal Policies and Programmes
MPNZ’s maintenance strategy is based on the reconciliation of efficient maintenance activities with
maximum system availability and selects an appropriate maintenance technique for each asset class.
MPNZ seeks to improve reliability and life cycle profitability through investigating whether existing reactive
and preventative maintenance can be replaced by condition and reliability based maintenance regimes.
Whilst condition assessments are not appropriate for equipment that does not have a dominant age
related failure mode, the bulk of distribution assets can be subjected to worthwhile condition based
maintenance, although the often high costs of condition assessment needs to be carefully assessed
against other methods.
Lifecycle renewals are ongoing under the inspection and maintenance regime that MPNZ is operating.
As most assets have few or no moving parts, end of life is determined by age based degradation of
materials such as insulation breakdown, metal fatigue or rusting and timber rot. More technical items
such as protective relays, switchgear and software systems are renewed for reasons of obsolescence
rather than wear. For those items that do reach end of life in service there can be significant variation of
age at end of life. This means that the time profile for replacement of a particular asset does not have the
same time profile as the initial installation. As mentioned previously other factors such as local
redevelopment, asset relocations and unplanned events can also have a significant effect on this. The
overall effect is a significant flattening of the original installation profile for renewal.
Reactive Maintenance
Reactive maintenance is the response to an asset failure following a fault. Not all asset failures are
predictable or preventable so this programme is reactive involving field staff response to each event as it
occurs. MPNZ’s control centre is notified of a system fault either through its field supervisory systems or
through individual customer calls. Fault staff are directed to respond to system faults immediately
following the first notification. Often repairs made following a fault may constitute either premature
maintenance or premature renewal. If an asset is completely replaced during a repair the activity is
treated as a renewal. Typical fault repair activities include poles damaged by vehicles, excavated cables,
tree faults on lines caused by high wind, asset failures and damage from storms.
Time Based Preventative Maintenance
Preventative maintenance is a planned programme of maintenance to attempt to prevent failure from
occurring as a fault. This programme is aimed at maintaining the existing service potential of an asset
rather than enhancing its life. Typical preventative maintenance activities are vegetation control,
transformer kiosk inspection and cleaning, zone substation inspection and cleaning, oil replacement in
circuit breakers and tapchangers, tightening line hardware and rebinding conductors. Preventative
maintenance programmes are often recommended by the equipment manufacturers.
Condition Based Maintenance
Condition based maintenance focuses on undertaking tests to establish the condition of equipment, and,
if necessary, undertaking corrective or restorative maintenance. MPNZ has many examples of condition
based maintenance programmes including pole testing, tests made to assess the internal condition of
109
large transformers, and thermal imaging to find system hot spots. A recent addition to MPNZ’s condition
based maintenance is the partial discharge testing key underground cables to ascertain any insulation
breakdown issues.
Reliability Based Maintenance
Reliability based maintenance involves analysis of reliability statistics, including the frequency, duration,
location and causes of power faults to identify particular patterns or issues. This includes for example
analysis of fault history to determine whether a particular line has a problem with bird contact and if
greater line-separation would avoid future problems occurring. Other typical reliability based
maintenance programmes are the renewal of corroded conductors in coastal areas, tree trimming work
carried out following repeated tree issues, and alterations to structure clearances following repeated bird
problems.
Inspection Programmes
MPNZ’s inspection programme is an essential part of the preventative and condition based maintenance.
Each asset category has an inspection policy to determine maintenance or renewal requirements. The
following table summarises the inspection programme. More specific details for each category of asset
are included in the following sections.
Asset
Cycle
Inspection Guidelines
Poles
Pole test every 10 years ( 5 years for
subtransmission)
Mechanical wood pole test based on design
strength, drill where necessary, visual check of
degree of spalling concrete poles.
Brief visual check for safety issues eg clearances,
trees, damaged or broken hardware.
Visual inspection for rot, mould, splits, slogged out
insulator holes, loose nuts
Visual inspection for rot, binder fatigue, incorrect
sag
Visual inspection for rust, rot, transformer
temperature and loadings, graffiti and weeds
Thermal imaging, visual inspection
Gas pressure, oil condition, thermal imaging of
line CB terminations, partial discharge of
terminations on underground systems,
Magnefix contact inspection, oil inspection and
replacement, termination inspection
Visual inspection, thermal image of connections,
usually replacement with refurbished AIR BREAK
Switches every 10 years
External consultant
Line safety inspection every 5 years
Pole cross arms and
hardware
Conductors
During pole test and line survey
Transformer kiosks
Inspection every year
HV Switchgear
LV panel inspection every year
Circuit breakers every year
During pole test or line survey
RMU’s
Air break switch every ten years
Zone substations
Transformer DGA oil analysis every 2
years
Compound bus and buildings every 2
months
Batteries every 2 months
Protection every 5 years
Cables
Test of critical cables every 2 years
Trees
Every 2 years
Load Control
Every 2 years
Visual inspection for weeds, rust, rot, fences
Some on SCADA, remainder have cell tests
Injection tests for accuracy of non digital relays
only
Partial discharge testing, thermal imaging of cable
terminations
Trees inspection by dedicated inspector, trees cut
by feeder on two yearly rotation
Inspection and tests by supplier
Table 45 Inspection Programme
The following sections provide discussions on each asset category which includes background and
historical issues. The inspection, maintenance and renewal programme for each asset category is
provided in table form followed by the forecast expenditure for each asset category disaggregated by
maintenance type.
110
8.3
Sub transmission, Distribution and LV Overhead Lines
8.3.1 Poles
A comprehensive lines database is maintained for High Voltage lines recording the original construction
date for each pole, maintenance history, pole test data, condition comments and other physical and
location attributes. The age profile for poles is included in Section 3. Less is known about low voltage
pole lines therefore a two year project was initiated during 2010 to capture this information and maintain it
going forward. Work on this has been delayed due to lack of resources but good progress is expected in
2012. Once this information is updated, low voltage pole lines will be maintained in the same way as high
voltage lines. Rural low voltage pole lines are currently maintained at the same time as high voltage lines
they relate to. Urban low voltage poles are maintained separately. An annual budget of $50,000 has
historically been assigned to low voltage pole line maintenance.
During the annual budget review a prioritised list of all high voltage lines requiring inspection within the
next eight years is produced. The estimated cost of the work required is based on the total number of
poles to be visited, the age and number of tested and untested hardwood and larch poles in the mix, and
the expected number of cross arm replacements.
Once the annual budget is approved a line surveyor inspects and tests the poles and produces a
construction plan of the work that is required on each line to bring it up to standard. The survey involves
a mechanical pole test to assess the condition of each pole. Line gangs carry out the maintenance and
renewal work required, usually within 1-3 months of the original survey and pole test.
Concrete poles purchased since the mid 1970s and have shown no deterioration or reduction in strength
during this time. We expect these poles to last a minimum of 70 years and only minor monitoring for
cracking or flaking will be required before 2030. Older Kaikoura concrete poles were manufactured with
poorer quality aggregate and variable cover over the reinforcing. Many of these are failing visual
inspections at about 50 years of age.
CCA treated Corsican and Radiata pine poles have been used since 1973 and have been supplied along
with strength rating test certificates from 1990. Current purchases of these poles include supplier
guarantees of 60 years life. It is therefore envisaged that no testing will be required on Corsican pine
poles until around the year 2020 unless visible deterioration occurs. Sample testing will occur during this
time to monitor these poles.
Lines which have been pole tested and contain hardwood or larch poles are flagged for inspection or
testing again after 10 years. Lines may also be given an earlier maintenance required date following
routine inspection or feedback from lines staff, typically following fault responses. Poles that fail the
assessment are tagged red, yellow or blue depending on the severity of their condition and are then
recorded in the database for renewal.
The pole inspection, maintenance and renewals programme is summarised in section 8.3.5.
The recent history of pole condition and maintenance includes:

Over the past fourteen years around 14,500 hardwood and larch poles have been replaced due to
failed pole tests. Over the years it has become apparent that hardwood, and in particular larch poles
will rot out long before a treated pole and are in general much older. These pole types are the current
focus for the pole testing regime.

All sub-transmission lines have been inspected and pole tested over the last seven years and this
year sees the continuation of a second cycle of sub-transmission line pole testing in the Waipara to
Kaikoura section.

During 1997 and 1998 we identified that Corsican pine poles were twisting resulting in lines becoming
unregulated. An investigation in association with the suppliers and Forest Research identified the
problem as being due to the poles being harvested too young. We are currently asking the suppliers
to deliver poles with a minimum of thirteen rings at the top of the pole.

During early 2007 a treated pine pole installed in the 1980s was found to have rotted below ground.
Following a study of the pole by the supplier the rot was categorised as brown rot, a very infrequent
111
occurrence. Sample testing of treated pine poles was started to monitor this condition and no further
brown rot has been found.

Some softwood poles have developed surface cracking with some loss of effective diameter.
Investigations will be carried out into the practical loss of strength and likely residual strength of these
poles.
Planned Pole Maintenance on 11 kV and 22 kV
Table 46 below shows the quantities for each pole type used in the MPNZ 22 kV and 11 kV network. The
maintenance plan for these poles is focussed on the rotting wood problem associated with the ageing
hardwood and larch poles. These two pole types account for 10027 poles in total with 6668 of these being
over 40 years of age. We know from experience that if, on an annual basis, we replace around 500 of the
oldest poles that have failed their strength test, we can then avoid large waves of maintenance in any one
year and at the same time avoid endemic system failure during wind and snow storms.
We expect a successful pole test extend a poles life by 10 years and have planned on a 10 year return
period for lines with hardwood or larch poles, and 15 years for the remainder. The next 5 years will see
many of the older hardwood and larch poles being removed from the system with only the most durable of
the population left. The renewal work required per km tested is expected to fall and the number of km
tested increase. This may allow the return period to be reduced to 8 years with a similar annual
expenditure.
CCA treated Corsican and Radiata pine pole use commenced in the 1978 and they were used in far
greater quantities than the earlier hardwoods and larches due to the greater growth that was occurring in
the region (refer 3.6.6 fig.22). Testing of 40 year old Corsican pine poles in the network have shown that
the poles are still in good condition and so mechanical pole testing of this pole population will not
commence until they are 50 years of age or show statically significant failure rates. This means that we
may commence testing the older CCA treated pine poles around 2020 but that the larger numbers
mentioned from 1978 will not come up for testing till 2028 onwards. We fully expect most of these poles to
last 80 years based on supplier guarantees and on experience thus far.
Quantity of Poles
Quantity > 40 yrs age
Concrete
3,902
826
Hardwood
6,994
4,810
Larch
3,034
1,858
CCA Pine
30,315
480
Total
44,245
7,974
Table 46 Quantities of 11kV and 22kV Poles by Type
Planned Pole Maintenance on 33kV and 66kV
The table below shows pole information for 33kV and 66kV sub transmission lines. There are 1,227
poles greater than 40 years of age made up predominantly from hardwood poles and a few larch poles.
We have a 5 year return period test plan for these poles given that they are higher priority than the 22 and
11 kV poles as they affect more customers if they fail. The very high level of subtransmission capital work
over the next 3 years means that the test period may extend to 6 or 7 years. This capital work will also
have a direct impact on maintenance with the replacement of about 150 of the older hardwood poles. On
average over the next 10 years we expect to renew around 75 hardwood poles annually. Maintenance on
the Culverden Kaikoura 66 kV line being purchased from Transpower will be additional to this.
66 kV & 33 kV
Quantity of Poles
Quantity > 40 yrs age
Concrete
1,515
8
Hardwood
1,558
1,215
Larch
10
4
CCA Pine
41
0
Total
3,124
1,227
Table 47 Quantities of 66 kV and 33 kV Poles by Type
8.3.2 Conductors
Overhead line conductors in use on the network are copper, ACSR or all aluminium. Conductors are
purchased according to manufacturers specifications, and generally meet internationally accepted criteria.
New Zealand standards are referred to where applicable. The climate in the MPNZ area is such that
there has not been any noticeable deterioration of conductors due to corrosion except in those lines
within a few hundred meters of the coast.
112
A number of issues have affected the performance of overhead lines, as follows:

The use of squirrel conductor was widespread during the 1970s and 1980s; however, we have found
that this size conductor fails badly under snow loading. Squirrel is now being progressively replaced
with minimum magpie, ferret or flounder in snow prone areas. All new designs comply with the
minimum snow loading recommended in AS/NZS7000:2010.

During 2004 we identified a potential problem with a number of conductor make offs used on
overhead conductors. These make offs were found to be rated to only 65% of the conductor UTS
and were letting the conductor slip on higher tensioned lines. This was highlighted during the 2006
snow storm where six percent of faults were due to slipping make offs caused by the additional snow
loading on conductors. These make offs are being replaced in snow prone areas and where higher
tensions are used due to larger spans. Design for higher snow loadings will also help minimise this.

Badly corroded or highly loaded (above 3 Amps) No.8 galvanised steel conductor is replaced with
aluminium equivalents at time of line maintenance.

There is still a reasonable quantity of 3-104 galvanised steel (3/12GS) conductors in most regions,
more so in the northern areas. This conductor is generally on radial lines and in good condition
showing little sign of corrosion. In many circumstances 3-104GS will be left in place even following a
pole and hardware replacement.

Before undertaking any line maintenance, a survey is carried out to identify where design
improvements can be made. This often leads to clearance improvements being made, poles being
better located, provision being made for future 3-phase conductors, and allowance made for
improving conductor joints and terminations.

MPNZ has replaced three 1 km sections of overhead 11 kV conductor in the last ten years. These
were at the coastal sites of Amberley Beach and Hurunui Mouth, and South Bay Kaikoura.
Replacement in both cases was due to rot. Closer inspection of coastal lines will help us understand
the level of rot in these areas.

In some cases MPNZ has replaced the open wired low voltage systems used to reticulate small rural
towns and beach areas with aerial bundled cable systems to improve safety and visual appeal.
Generally this is only where high voltage systems exist as well.

Some conductor vibration damage has been noted on the Tram Rd 66 kV circuit. This has Neon
AAAC conductor with low self damping and was strung with higher tensions than recommended in
AS/NZS7000:2010. Monitoring has been undertaken and vibration dampers are being installed in
2012. Further investigation will be carried out to establish if other lines are being affected.
The conductor inspection, maintenance and renewals programme is summarised in section 8.3.5.
8.3.3 Cross Arms
The cross arm service life can vary from between 20 to 40 years with an average service life of around 30
years. Cross arms are generally renewed due to slogging out of insulator bolt holes through movement
from high wind and ingress of moisture. Standard cross arms are of section 100 x 75 mm and are fitted
to the pole on the 100 mm face thereby providing the strongest support for the downward force of the
conductors. This also minimises the build up of moss and lichen on the narrower top face of the cross
arm and possibly increases its service life. Cross arms are purchased according to their strength rating.
A number of issues have affected the historical performance of cross arms:

Older lines were constructed with the narrow 75 mm face of the cross arm against the pole face
making for a weaker construction, more susceptible to lichen build up and rot.

Slogging of insulator bolt holes in cross arms has been a problem in earlier years, eventually causing
the ends to come out of the cross arm. This has been mitigated since 1994 by using insulators with
larger diameter bases against the arm, larger square washer, and spring washers with double lock
nuts on all bolts through cross arms, and re-tightening pole hardware during maintenance.

Through the 1970s and 1980s many cross arms were changed regardless of their condition, which
has increased the overall average condition of cross arms.
113
As poles are tested every 10 years and cross arms generally last for around 30 years, there is at least
three occasions when the cross arm will therefore be inspected in conjunction with the pole.
The cross arm inspection, maintenance and renewals programme is summarised in section 8.3.5.
8.3.4 Line Hardware
Most line hardware is of galvanised steel or porcelain that has proved to have a long life in the North
Canterbury region. Items included are insulators, strain insulators, aerial and ground stay wires and
ground anchors, cross arm braces, and fuses. All hardware is purchased according to their strength and
voltage rating.
A number of issues have affected the historical performance of cross arms:

The use of kidney porcelain strain insulators over the years has resulted in high levels of failure and
radio interference.

Pacific type glass 11 kV fuses are unreliable and they are being replaced with drop out style fuses
whenever they are found during line maintenance. Most have now been replaced.

11 kV Dominion dropout fuses of the two piece insulator type with the galvanised steel mounting bar
cemented into the insulator have been known to develop cracked insulators following the ingress of
moisture into the cement region and the formation of ice.

Band clamp mount type Dominion 11 kV dropout fuses were also purchased and soon developed
loosening of the band resulting in mechanical damage to the unit. These have now all been replaced.
The line hardware inspection, maintenance and renewals programme is summarised in section 8.3.5.
8.3.5 Overhead Lines Inspection, Maintenance and Renewal Programmes
Component
Poles
Maintenance type
Asset Inspection/Condition Assessment
Routine and Preventative
Refurbishment and Renewal
Fault and Emergency
Conductors
Asset Inspection/Condition Assessment
Routine and Preventative
Refurbishment and Renewal
Fault and Emergency
Cross arms
Asset Inspection/Condition Assessment
Routine and Preventative
Refurbishment and Renewal
Fault and Emergency
Line hardware
Asset Inspection/Condition Assessment
Routine and Preventative
Refurbishment and Renewal
Fault and Emergency
Action
 10 yearly pole test
 5 yearly line survey and visual inspection
 Maintenance determined on condition and number
of customers affected
 Derived from age profile and inspection and testing
results to maintain overall line standard
 Fault response
 Reactive repair
 Visual inspection during pole test or line survey for
corrosion, binder fatigue, incorrect sag
 Maintenance is driven by the results of the pole
test or lines survey
 Conductor condition assessed during 10 yearly
pole maintenance and replaced if required.
 Fault response
 Reactive repair
 Visual inspection during pole test and line survey
 Checked during line maintenance
 Renewal if visual assessment failure of with any
pole renewal or line maintenance.
 Fault response
 Reactive repair
 Visual inspection during pole test and line survey
 Checked during line maintenance, all mounting
bolts tightened.
 Kidney insulators replaced whenever lines are reconductored or re-poled
 Driven by line upgrade
 Fault response
 Reactive repair
Table 48 Overhead Lines Inspection, Maintenance and Renewal Programmes
114
8.3.6 Lines Forecast Expenditure
The Waipara-Kaikoura line has received significant maintenance as a result of its capital upgrade to 66
kV. The Southbrook Oxford line will be repoled for 66 kV over the next three years. This is expected to
contribute to lower levels of sub-transmission renewal expenditure in future years. MPNZ is purchasing
the Transpower Culverden Kaikoura 66 kV wooden pole line and this has been factored into future years
expenditure, with some delay due to the high level of subtransmission capital project work in the first
three years.
Table 49 shows the summary forecast lines maintenance and renewal expenditure for the period
2012-2021.
Description
($Million)
2011-12
2012-13
2013-14
2014-15
2015-16
2016-17
2017-18
2018-19
2019-20
2020-21
Subtransmission
0.235
0.585
0.585
0.660
0.735
0.735
0.735
0.735
0.735
0.735
HV Distribution
1.88
1.88
1.88
2.40
2.40
2.40
2.40
2.40
2.40
2.40
LV Distribution
0.10
0.10
0.10
0.10
0.10
0.10
0.10
0.10
0.10
0.10
Total
2.215
2.565
2.565
3.16
3.235
3.235
3.235
3.235
3.235
3.235
Table 49 Forecast Expenditure - Lines Maintenance and Renewals 2012– 2021
8.4
Sub-transmission, Distribution and Low Voltage Underground Cables
The underground cable network is generally in very good condition. Care is taken at time of installation to
ensure proper bedding and cables are rarely operated outside of conservative loading limits. Partial
discharge testing over the past four year has established a benchmark or footprint of the condition of the
most important cables. Cables have required low levels of maintenance in the past, any such work mainly
arising from excavation damage. New cables are tested prior to commissioning and any poor test results
require the cable to be replaced. Cables are purchased to the Australian Standard AS 4026 and cables
are installed according to MPNZ specifications.
There have been a concerning number of joint failures over the years and these have mostly resulted
from ingress of moisture into the joint. These have been repaired when identified.
The Greendale earthquake of September 2010 caused large numbers of high voltage cable faults in parts
of Kaiapoi Town. Approximately four kilometres of damaged cable has been replaced in this area and the
opportunity was taken to install larger cables than those damaged to improve capacity. There have been
few subsequent faults however it is expected that many cables will have been stressed by the earthquake
and the incidence of failures is likely to be higher in the quake affected areas for the next 10 years.
8.4.1 Underground Cables Inspection, Maintenance and Renewal Programmes
Underground Cables
Maintenance Type
Asset Inspection/Condition
Assessment
Routine and Preventative
Refurbishment and Renewal
Fault and Emergency
Actions
 2 yearly partial discharge testing on 33kV cables and critical
feeder cables and thermal imaging of cable terminations
 Maintenance is driven by cable condition monitoring
 Due to low failure rate no renewals are scheduled during the
planning horizon
 Fault response
 Reactive repairs
Table 50 Underground Cables Inspection, Maintenance and Renewal Programmes
The projects to be completed within the coming year comprise:
 Partial discharge testing of Daiken 11kV feeders

Partial discharge testing of Priority town feeders at Rangiora and Kaiapoi

Partial discharge testing of priority 11kV switchgear.
115
Cheviot T2 (Main)
Southbrook T2 (Main)
Southbrook T2 (OLTC)
Swannanoa T1 (Main)
Swannanoa T1 (OLTC)
Southbrook T2 (Main)
Southbrook T2 (OLTC)
Swannanoa T1 (Main)
Swannanoa T1 (OLTC)
Southbrook T1 (Main)
Southbrook T1 (OLTC)
Southbrook T1 (OLTC)
Rangiora North T1 (OLTC)
Rangiora North T1 (OLTC)
Southbrook T1 (Main)
Oxford T1 (OLTC)
Rangiora North T1 (Main)
Oxford T1 (OLTC)
Rangiora North T1 (Main)
Mouse Point T2
Leader T1 (OLTC)
Leader T1 (Main)
Ludstone Rd T2 (OLTC)
Ludstone Rd T2 (Main)
Ludstone Rd T1 (OLTC)
Ludstone Rd T1 (Main)
Hawarden T1 (OLTC)
Hawarden T1 (Main)
Hanmer T2 (OLTC)
Hanmer T2 (Main)
Hanmer T1 (OLTC)
Hanmer T1 (Main)
Greta T1 (OLTC)
Greta T1 (Main)
Cust T1 (OLTC)
Cust T1 (Main)
Cheviot (ET1)
Cheviot T2 (OLTC)
Cheviot T2 (Main)
Cheviot T1 (OLTC)
Cheviot T1 (Main)
Bennetts T2 (OLTC)
Bennetts T2 (Main)
Bennetts T1 (OLTC)
Bennetts T1 (Main)
Amberley T2
Amberley T1
Oxford T1 (Main)
0
Oxford T1 (Main)
5
Mouse Point T1
10
Mouse Point T2
15
MacKenzies Road T1 (OLTC)
20
Mouse Point T1
25
MacKenzies Road T1 (OLTC)
30
Lochiel T1
Acid Threshold
MacKenzies Road T1 (Main)
Zone Substation Transformer Acid Number 2011
Lochiel T1
40
MacKenzies Road T1 (Main)
Leader T1 (OLTC)
Leader T1 (Main)
Ludstone Rd T2 (OLTC)
Ludstone Rd T2 (Main)
Ludstone Rd T1 (OLTC)
Ludstone Rd T1 (Main)
Hawarden T1 (OLTC)
Hawarden T1 (Main)
Hanmer T2 (OLTC)
Hanmer T2 (Main)
Hanmer T1 (OLTC)
Hanmer T1 (Main)
Greta T1 (OLTC)
Greta T1 (Main)
Cust T1 (OLTC)
Cust T1 (Main)
Cheviot (ET1)
Cheviot T2 (OLTC)
35
Cheviot T1 (OLTC)
Cheviot T1 (Main)
Bennetts T2 (OLTC)
Bennetts T2 (Main)
Bennetts T1 (OLTC)
Bennetts T1 (Main)
Amberley T2
Amberley T1
Acid Number (mgKOH/g)
Moisture Concentration in Oil (ppm)
8.5
Zone Substations
8.5.1 Zone Substation Transformers
Zone substations are generally in very good condition and most have robust seismic restraints and oil
containment systems. High growth has led to most zone substations being relatively new due to
upgrades or additions made over the past 15 years. Transformers are not generally taken past their
loading rating. MPNZ has now built up sufficient oil test data history on each zone substation transformer
to provide early indication of transformer degradation.
Transformer oil analysis has resulting in the following observations and maintenance actions:

Amberley T1 (Transformer 1) and T2 have had new gaskets fitted on the tank lids and bushings
which has prevented the previous moisture ingress. Moisture levels dropped to 10 ppm in 2010 and
are now at safe levels.

Hanmer T1 will have further moisture removed from the main tank and tapchanger tank this year.
Acid will be further monitored.

OLTC oil filters have been installed at Mouse Point at ABB’s recommendation.
Figure 44 shows the results of zone substation transformer oil analysis undertaken during 2011.
40
Zone Substation Transformer Oil Moisture Content 2011
35
Moisture Threshold
30
25
20
15
10
5
0
Figure 44 Substation Transformer Assessments
116
The zone substation transformer inspection, maintenance and renewals programme is summarised in
section 8.5.5.
8.5.2 Substation Compounds
There have been a number of outdoor bus connection issues and these have been fixed with a
replacement programme with new high fault rated shot type connectors coupled with a monitoring
programme of inspection and thermal imaging of outdoor bus for hot spots.
The Oaro, Cust, Bennetts and Oxford zone substations are planned to be removed over the next five
years.
The zone substation compound inspection, maintenance and renewals programme is summarised in
section 8.5.5.
8.5.3 Batteries
There are a number of old style battery chargers and battery banks still remaining at Cust, Cheviot and
Hanmer. They require regular visits to check their condition and battery banks are often exposed, or on
the floor of compound buildings. These will be replaced within 5 years.
The remaining battery chargers and batteries at zone substations are now modern intelligent electronic
chargers and sealed lead batteries. These battery chargers provide SCADA alarms following the
detection of low voltage levels or open circuit breakers at the battery bank.
The zone substation battery inspection, maintenance and renewals programme is summarised in section
8.5.5.
8.5.4 Protection Relays
The protection relays used are a mixture of older electro-mechanical and electronic devices. Electromechanical relays have been reliable over many years and there have been no failures but are generally
replaced due to being obsolescent. The electronic relays offer much greater functionality within the one
unit than the electro-mechanical type can deliver and are self monitoring. The substations constructed or
rebuilt since 1990 have electronic relays installed.
The zone substation protection relay inspection, maintenance and renewals programme is summarised in
section 8.5.5.
8.5.5 Zone Substations Inspection, Maintenance and Renewal Programmes
Component
Transformers
Maintenance Type
Asset Inspection/Condition
Assessment
Routine and Preventative
Refurbishment and Renewal
Compounds
Asset Inspection/Condition
Assessment
Routine and Preventative
Refurbishment and Renewal
Batteries
Asset Inspection/Condition
Assessment
Actions
 3 monthly inspection including visual inspection,
tap change operation count, battery test, oil
containment inspection, alarm flaggings, oil levels
and silica gel breather test
 Impedance (excitation) tests on larger
transformers every 5 years
 Annual earth testing
 Maintenance is based on biannual oil analysis,
the number of tap changer operations and results
from the two monthly inspection
 Dependent on oil monitoring results, no renewals
forecast during planning horizon
 3 monthly buildings and property inspection
 Annual thermal imaging to detect hot spots
 Maintenance driven by results of inspection
 Driven by upgrade requirements to increase
capacity
 Real time SCADA monitoring of electronic
chargers and sealed lead batteries
117
Component
Maintenance Type
Routine and Preventative
Refurbishment and Renewal
Protection relays
Asset Inspection/Condition
Assessment
Routine and Preventative
Refurbishment and Renewal
Actions
 3 monthly testing of voltage and specific gravity
on non-monitored banks and chargers
 Annual testing of rural circuit breaker batteries
 Analysis of results of testing to detect any
potential failure
 Replacement based on reported condition or after
5 years
 2 yearly annual protection test
 NA
 Upgrade of electro-mechanical relays at Hanmer
substation to be replaced by electronic relays
during 2013-14
Table 51 Zone Substation Inspection, Maintenance and Renewal Programmes
The projects to be completed within the coming year comprise:
Scheduled Maintenance Item
Amberley Oil Change/CB Maintenance
OLTC Oil Filters Mouse Point T1 & T2
Budget $
2,080
12,160
Substation Containment Checks/Repairs/Clean
7,200
Ludstone Rd Sub General & ABS/Sw itchgear Maintenance
5,200
DGA Tests
5,480
Greta Sub Landscaping Improvements
4,580
Check Substation Fire Extinguishers
5,680
Lochiel Sub General & ABS Maintenance (Including Transformer Foundation)
2,820
PD Tests & Sub Compliance Inspection
OLTC Maintenance Mouse Point T2
13,250
3,880
Kaikoura GXP General Maintenance
6,200
Hanmer N14 & ABS Maintenance
3,560
Haw arden 33 kV Structural Repairs
9,080
DGA Tests
5,480
Kaiapoi S1 CB/Sw itchboard Maintenance
3,700
Rangiora North Sub ABS Maintenance
3,960
PDC Test Cheviot T2
5,580
Impedance/Excitation Tests Cheviot T2
1,680
Protection Test All Marble Point Electromechanical Relays
1,380
Protection Test Mouse Point Load Plant Protection
1,380
DGA Tests
5,480
Protection Test All Ludstone Electromechanical & Load Plant Relays
2,960
Impedance/Excitation Tests Southbrook T1 & T2
1,720
Impedance/Excitation Tests Amberley T1 & T2
1,920
Impedance/Excitation Tests Haw arden T1
1,380
Add Oxidation Inhibitors to Various Transformers
3,120
General Scheduled Maintenance
9,300
Miscellaneous Battery Replacements
13,000
Miscellaneous Protection Changes
3,000
Substation Security Improvements
3,900
Zone Sub Building Maintenance
4,400
154,510
Table 52 Zone Substation Maintenance Projects
118
8.6
Switchgear
8.6.1 Circuit Breakers, Reclosers, and Sectionalisers
New circuit breakers are purchased to international standards for insulation and protection and with due
regard to fault rating. The older oil circuit breakers receive the most maintenance as the contact
mechanism is accessible and the oil can be replaced easily. More modern SF6 and vacuum types are
generally sealed units and perform well up to around 50,000 operations before replacement
Autoreclosers are employed throughout the rural network to help reduce the number of customers
affected during a fault. The oldest of these are Reyrolle OYT reclosers which do not have the ability to
disable the autoreclose function during live line work and so have become obsolete. These have mostly
been replaced over the past ten years. A number of McGraw Edison type KF and KFE vacuum reclosers
were installed on the network during the 1970s, and more recently Nulec SF6 reclosers have been used.
History of renewals and replacements:

Twelve GPC outdoor oil circuit breakers at zone substations have been progressively replaced over
the past twelve years as they have become unreliable through old age. Most of the issues have
arisen from the chain and weight autoreclosing systems employed. Only one remains on MPNZ’s
smallest substation.

During late 1999 ultrasonic testing was carried out on 11 kV metal clad switchgear and Magnefix
systems, however lack of confidence in the results caused this type of testing to be discontinued.

Reyrolle OYT autoreclosers are being progressively replaced because they do not have an
autoreclose disable function.

A small number of faults have occurred on the 33 kV indoor SF6 Schneider circuit breaker
switchboard at the Southbrook substation. These have included cable termination faults due to work
quality, a voltage transformer failure resulting in an explosion of carbon dust particles throughout the
board, and some breakdown of the insulation on the buswork and resultant tracking failure.

33 kV type OKW3 circuit breakers have been employed at many zone substations over the years.
A number of mechanical failures have occurred on some of these units in recent years and
subsequently they will be replaced over the next five years as their condition deteriorates.
The circuit breaker, recloser and sectionaliser inspection, maintenance and renewals programme is
summarised in section 8.6.4.
8.6.2 Ring Main Units
MPNZ has many ABB SD series 2 ring main oil switches in service, all purchased since 1975. All
switches are identified as requiring maintenance based on their last maintained date and work
instructions are sent to contractors. A maintenance checklist is returned by the contractor to the
Distribution Engineer and this information is entered into the appropriate database.
During 2004-2005 a number of faults appeared with the ABB SD ring main oil switches. Subsequent
investigations have showed that a combination of poor quality bushing manufacture coupled with cold
shrink termination kits allows moisture to enter the termination and this eventually tracks to earth.
A change has now been made to hot shrink termination kits and bushings are checked and altered where
necessary. This equipment is no longer purchased and the early SD series 1 equipment which has public
and staff safety issues is being targeted for replacement over the next three years.
Three old Isopont style resin cast switchgear have been replaced over the last five years with new
Magnefix switchgear. The last remaining units are in the Kaiapoi earthquake “Red Zone” and will be
removed as this area is upgraded or decommissioned.
Most of the remaining Long & Crawford switchgear is at the Daiken MDF plant. This has safety issue
requiring very restrictive operational constraints. It will all be replaced over the next 3 years.
The ring main unit inspection, maintenance and renewals programme is summarised in section 8.6.4.
119
8.6.3 Air Break Switches
Air break switches can suffer from lack of use, climatic factors and increasing rural loading of lines
causing termination and contact failures. Future asset management planning for air break switches
includes a move to a simple contained gas or vacuum switches with virtually no maintenance requirement
during their life.
During the 1980s a manufacturing fault in the insulators used on Canterbury Engineering’s DA2 style air
break switch was found where insulators were splitting in half at the top of the holding pin when the air
break was operated. An extensive replacement plan was initiated to replace all insulators. In addition to
this, the old Canterbury Engineering 200 Amp air break switches had a braided connecting jumper
between the moving middle terminal and the load side terminal. Recent failure of the braid on one of
these switches under medium level fault currents has caused the introduction of inspections on these
types of switches and planning for the retirement of these and older 955 switches with priority to high fault
level areas.
The air break switch inspection, maintenance and renewals programme is summarised in section 8.6.4.
8.6.4 Switchgear Inspection, Maintenance and Renewals Programmes
Switchgear
Circuit breakers,
reclosers and
sectionalisers
Maintenance Type
Asset Inspection/Condition
Assessment
Routine and Preventative
Refurbishment and Renewal
Fault and Emergency
Ring main units
Asset Inspection/Condition
Assessment
Routine and Preventative
Refurbishment and Renewal
Fault and Emergency
Air break switches
Asset Inspection/Condition
Assessment
Routine and Preventative
Actions
 Ongoing monitoring of operations count, maintenance
history, battery and earthing details, visible numbering
and line connections
 Annual partial discharge of high priority circuit breakers
and terminations
 Annual thermal imaging of autorecloser terminations
 Maintenance of circuit breakers is based on how many
trips since last service, the local fault level and the
manufacturer’s recommendations
 Annual oil maintenance and gas pressure checks for
circuit breakers and autoreclosers
 11 kV Reyrolle OYT and 33kV OKW3 circuit breakers
removed from the system and replaced over next eight
years
 The remaining GPC autorecloser will be retired from
service as it becomes unreliable
 Fault response
 Reactive repair
 Annual monitoring of ABB SD ring main switches
 10 yearly internal inspection of ABB SD ring main
switches
 Maintenance scheduled according to date of last
maintenance
 10 yearly drain and fuse resistance testing on ABB SD
ring main switches
 7 yearly surface cleaning and contact inspection of
Magnefix ring main switchgear (5 yearly in Kaiapoi)
 ABB/Andelect series one units are scheduled for
replacement over the next three years
 Replacement of old Long & Crawford switchgear due to
safety issues
 Fault response
 Reactive repair
 Thermal imaging during summer peak and winter peak
 7 to 10 yearly exchange servicing
 Maintenance priority based on if the switch is an open
point in the system, how many customers are
connected beyond the switch and how frequently the
switch is operated
120
Switchgear
Maintenance Type
Refurbishment and Renewal
Fault and Emergency
Actions
 Replacement when history of poor operational
reliability, high failure rate or progressively higher
maintenance costs
 25 switches per year will be replaced under
maintenance for the next 5 years
 Fault response
 Reactive repair
Table 53 Switchgear Inspection, Maintenance and Renewals Programmes
The projects to be completed within the coming year comprise:
 Periodic rural circuit breaker and recloser checks

Periodic Ring main inspections and maintenance

Daiken MDF plant RMU replacement

Targeted air break switch maintenance and replacement
8.7
Distribution Substations and Transformers
8.7.1 Distribution Kiosks and Substations
All kiosks and building substations are constructed away from the road reserve on private land using
easements or separate land title. This reduces graffiti and risk from vehicular accidents. In the 1960s a
large number of substations and kiosks were constructed with low voltage panels utilising Lucy type
fuses. When the fuse carrier is not in place live terminals are exposed, especially where paralleling links
are left out. This is now considered to be a safety issue and a programme has been initiated to better
insulate these live terminals with insulating panels.
Thermal Imaging is now used on a regular basis to detect “hot spots” in the electrical equipment housed
in substations. The benefits of this technique are that assets can be tested without affecting supply to the
customer or interfering with the asset. The use of micro-ohm-meter testing of low voltage connection
points is now used during new commissioning work.
The distribution kiosk and substation inspection, maintenance and renewals programme is summarised in
section 8.7.3.
8.7.2 Distribution Transformers
A small number of distribution transformers fail each year due to lightning storms and overloading caused
by unknown load increase by customers. MPNZ experienced a number of faults on early round tank
Tyree transformers up to 30 kVA rating, where the tank lid would leak when rain was present.
The distribution transformer inspection, maintenance and renewals programme is summarised in
Section 8.7.3.
8.7.3 Distribution Substations and Transformers Inspection, Maintenance and Renewal
Programmes
Asset Type
Distribution Kiosks
and Substations
Maintenance type
Asset Inspection/Condition
Assessment
Routine and Preventative
Refurbishment and Renewal
Actions
 Annual visual inspection for rust, rot, weeds and graffiti
 Annual LV panel visual inspection and thermal imaging
 Additional check of critical substations during peak load
periods
 Weather proofing as identified by annual inspection
 No refurbishment program
 Renewal occurs as required from inspections or during
upgrades
121
Asset Type
Maintenance type
Fault and Emergency
Actions
 Reactive repairs from weather or third party damage
Distribution
Transformers
Asset Inspection/Condition
Assessment
 Annual earth test on earth return and zone substation
transformers
 10 yearly earth test on all other transformers
 Minimal maintenance required and limited to when
transformers are removed from service or exchanged for
line maintenance or upgrade
 Full oil test and follow up oil filter/change if required when
being exchanged or replaced
 External inspections and touching up of surface rust
 Required only during line maintenance or upgrade
Routine and Preventative
Refurbishment and Renewal
Fault and Emergency
 Fault response
 Reactive repairs
Table 54 Distribution Substations and Transformers Inspection, Maintenance and Renewal Programmes
The projects to be completed within the coming year comprise:
 Building and kiosk substation checks

Targeted substation thermal imaging
8.8
Other
8.8.1 Vegetation
MPNZ meets the requirements of the new Hazards from Trees Regulations and has introduced a formal
tree owner notification and administration system to help meet these requirements. MPNZ employs a full
time Vegetation Control Manager to liaise with customers and land owners and to uphold the Regulations.
There are a number of known issues with vegetation control including:

A large number of MPNZ overhead lines traverse private property where trees are more likely to be
grown as shelter.

Lifestyle blocks have been popular in the Waimakariri and Hurunui Districts for many years and
generally these have higher vegetation density than larger blocks.

Lifestyle block owners usually plant tree species with high growth rates such as poplars, willows and
radiata pine.
The vegetation inspection and maintenance programme is summarised in section 8.8.4.
8.8.2 Ripple Injection Systems (Load Control)
The Kaikoura SFUG ripple injection plant had experienced a number of faults on the electronic injection
unit over the past five years and so it was decided to replace this unreliable unit with a new SFUK
injection system and to keep the SFUG plant as a spare to cover the remaining older injection plants at
other sites. All old Zellweger and Rotec injection plants were replaced in the mid to late 1990s with
modern Landis and Gyr plants. Relay failure rates are monitored but these have been extremely low
since the new plant was installed in the late 1990s.
The load control inspection, maintenance and renewals programme is summarised in section 8.8.4.
8.8.3 Communications
MPNZ’s voice and data communications systems are new and are maintained by the system suppliers.
During 2008 a portable handheld voice radio was added to contractor vehicles to improve
communications flexibility for contractors, and at the same time an emergency SOS style action facility
was added to each portable radio. Over the past few years the old SCADA Conitel RTUs have been
122
replaced with modern DNP3 types and the last of the zone substations to be converted across has now
been completed.
The communications inspection, maintenance and renewals programme is summarised in section 8.8.4.
8.8.4 Other Asset Inspection, Maintenance and Renewal Programmes
Other
Vegetation
Ripple injection
systems
Communications
Maintenance Type
Asset Inspection/Condition
Assessment
Routine and Preventative
Actions
 2 yearly inspection by dedicated MPNZ inspector
Refurbishment and Renewal
Fault and Emergency
Asset Inspection/Condition
Assessment
Routine and Preventative
Refurbishment and Renewal
Fault and Emergency



Asset Inspection/Condition
Assessment







Embedded and mobile
generation
Routine and Preventative
Refurbishment and Renewal
Fault and Emergency
Asset Inspection/Condition
Assessment
Routine and Preventative






Refurbishment and Renewal
Fault and Emergency



Trees trimmed by feeder on two yearly rotation or
more regularly in high growth areas
NA
Reactive vegetation control
2 yearly inspection and testing by Landis and Gyr
Maintenance identified by yearly inspection
No renewals scheduled during the planning horizon
Fault response
Reactive repairs
Voice communications monitored and maintained
by Mount Campbell Communications
Data communications maintained by Radata
Systems Limited
As above
No renewals planned during planning horizon
As above
Ongoing feedback data observation and annual
inspection of embedded generation sites
Specialist operator ensures maintenance
programme for truck and generator are followed
Minor maintenance of embedded generation
undertaken during annual inspection
No renewals scheduled during the planning horizon
Fault response
Reactive repairs
Table 55 Other Asset Inspection Maintenance and Renewal Programmes
8.8.5 Life Cycle Maintenance Expenditure
Table 56 below shows the annual life cycle expenditure estimate. This is expected to be consistent
throughout the planning period. Large renewal items like ABS and RMU renewal are usually managed as
separate projects in the annual budget. The scheduled maintenance represents routine inspections,
asset condition assessment and planned preventative maintenance, refurbishment and renewals.
The fault section represents only work requiring immediately fault repairs following an outage, high risk of
immanent outage, or immediate safety issue.
Other work not identified at budget time and fault issue is grouped as unscheduled maintenance. This
represents less than 15% of the operational work excluding renewal as it is expected that most
discretionary work will be part of a management plan known at budget time.
123
Annual Life Cycle Expenditure Estimate
Renewal Maintenance
Total
Operations - Scheduled Maintenance
Testing
Testing
Testing
Scada & Communications
Scada & Communications
Load Control
Metering
Subtransmission - Overhead Lines
Subtransmission - Zone Subs
Subtransmission - Zone Subs
Subtransmission - Zone Subs
Subtransmission - Zone Subs
Distribution O/H Lines
Distribution O/H Lines
Distribution U/G Systems
Distribution U/G Systems
LV Underground Systems
Tree Management
Earth Testing
Partial Discharge
Pow er Factor and Harmonics
Scada
Voice
Thermovision
Thermovision
Sub Checks
Sub Maintenance
Sub Grounds
CB's
ABS's
Kiosk inspections & Maintenance
RMU Maintenance
0
0
0
0
0
0
0
0
0
0
0
0
0
269,460
0
100,000
0
0
369,460
11,800
11,800
11,800
23,320
9,830
41,430
3,120
22,320
11,970
25,150
154,510
23,210
11,630
118,070
107,690
159,340
9,600
950,000
1,706,590
11,800
11,800
11,800
23,320
9,830
41,430
3,120
22,320
11,970
25,150
154,510
23,210
11,630
387,530
107,690
259,340
9,600
950,000
2,076,050
0
0
0
0
0
0
0
0
0
0
0
0
0
0
17,854
15,047
17,364
1,676
1,573
4,144
40,825
277,013
8,250
44,215
126,960
74,763
54,394
684,079
17,854
15,047
17,364
1,676
1,573
4,144
40,825
277,013
8,250
44,215
126,960
74,763
54,394
684,079
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
9,785
3,400
2,198
31,742
4,524
10,787
12,842
12,842
67,884
17,890
7,098
68,065
18,535
55,795
22,445
12,477
4,384
5,390
18,493
14,357
8,250
25,765
4,125
439,072
9,785
3,400
2,198
31,742
4,524
10,787
12,842
12,842
67,884
17,890
7,098
68,065
18,535
55,795
22,445
12,477
4,384
5,390
18,493
14,357
8,250
25,765
4,125
439,072
Operations - Faults
Scada & Communications
Load Control
Subtransmission Overhead Lines
Subtransmission Overhead Lines
Subtransmission - Zone Subs
Subtransmission Underground
Distribution Overhead Lines
Distribution Overhead Lines
Distribution Overhead Lines
Distribution Underground Systems
LV Overhead Systems
LV Underground Systems
Streetlighting
Line Faults
Sw itchgear
Zone Subs
Cable Faults
Sw itchgear Faults
Line Faults
Distribution Sub Faults
Operations - Unscheduled Maintenance
Testing - Voltage Complaints
Load Control
Metering
Subtransmission Overhead Lines
Subtransmission Overhead Lines
Subtransmission Overhead Lines
Subtransmission - Zone Subs
Subtransmission Underground
Distribution Overhead Lines
Distribution Overhead Lines
Distribution Overhead Lines
Distribution Overhead Lines
Distribution Overhead Lines
Distribution U/G Systems
Distribution U/G Systems
Distribution U/G Systems
Distribution U/G Systems
Distribution U/G Systems
LV Overhead Systems
LV Overhead Systems
LV Overhead Systems
LV Underground Systems
LV Underground Systems
Subtrans Sw itching
Transpow er sw itching
O/H Lines
Zone Subs
Cable Faults
11KV Sw itching
Sw itchgear
Safety Isolations
Mobile Generator
Dist O/H Lines General
Transformer Maintenance
Kiosk Maintenance
Sw itchgear Maintenance
11kV Ground Subs
Dist U/G Systems General
LV Sw itching
LV Safety isolations
LV OH Systems Lines
Cable Locations
LV U/G Systems General
Table 56 Life Cycle Maintenance Expenditure
124
8.9
Total Operational Maintenance Expenditure
The following table shows the total operational maintenance expenditure for the period 2012-2021
grouped by asset type.
Operating Expenditure by Asset type
$5.0
Trees and Other
$4.5
SCADA & Comms
$4.0
Services
LV Distribution
$ (Millions)
$3.5
LV Switchgear
$3.0
Distribution Transformer
Distribution Substation
$2.5
HV Distribution
$2.0
HV Switchgear
$1.5
Zone Substation
Subtransmission
$1.0
$0.5
$0.0
2012/13 2013/14 2014/15 2015/16 2016/17 2017/18 2018/19 2019/20 2020/21 2021/22
Table 57 Total Operational Maintenance Expenditure 2012-2021
125
9
PERFORMANCE EVALUATION
9.1
Financial Performance Variance Analysis
The financial progress made against the plan for the 2010-2011 period is summarised in the following
table:
BUDGET
ACTUAL
Year Ending 31 March 2011
Year Ending 31 March 2011
($Million)
($Million)
Variance
(%)
Capital Expenditure
Customer Connections
4.379
2.622
-40.1%
System Growth
3.211
3.269
1.8%
Reliability, Safety and Environment
1.026
1.531
49.2%
Asset Replacement and Renewal
3.020
3.098
2.6%
Asset Relocations
0.000
0.159
11.689
10.679
-8.2%
Routine and Preventative Maintenance
2.400
2.323
-3.2%
Refurbishment and Renewal Maintenance
0.053
0.071
34.0%
Fault and Emergency Maintenance
0.746
1.070
43.4%
Subtotal - Operational Expenditure on Asset Management
3.199
3.464
8.3%
Total Direct Expenditure on Distribution Network
14.835
14.143
-4.7%
Overhead to Underground Conversion Expenditure
0.548
0.725
32.0%
Subtotal - Capital Expenditure on Asset Management
Operational Expenditure
Table 58 Variance between Actual Expenditure and Budget
9.2
Capital expenditure
Most capital projects associated with capacity and reliability were completed during the year. Actual
customer connections were greatly reduced due to post earthquake conditions. Earthquake repairs
included $636,000 of 11 kV cable replacement through what is now “Red” zoned land. An underground
conversion project undertaken in conjunction with Transit on S.H.1 went significantly over estimates.
9.3
Operational expenditure
Operational expenditure for the period was 8.3% over budget. Routine and preventative maintenance
expenditure was slightly below forecast due to resourcing issues. Refurbishment and renewal expenditure
and fault and emergency both ended above forecast due to earthquake response and repairs.
9.4
Historical Expenditure
The following table demonstrates the high level of investment on the network, both capital and
maintenance, undertaken over the past decade. Historically all renewal work was considered to be
maintenance unless it was a major project of over $50,000 in value, however since 2007 it has been
classified as capital. Capital contributions from customers covering the uneconomic portion of any
customer extension or subdivision are shown separately from 2004-05 onwards.
Description
($Million)
2000-01
2001-02
2002-03
2003-04
2004-05
2005-06
2006-07
2007-08
2008-09
2009-10
2010-11
Capital
2.51
5.27
4.49
3.97
4.82
8.88
6.30
9.7299
10.02
9.56
10.68
Maintenance
Capital
Contribution
2.49
1.89
2.11
2.42
3.21
2.56
3.83
1.87
3.61
3.66
3.46
3.90
4.16
4.37
5.02
5.15
3.71
3.05
Total
5.00
11.93
15.60
14.49
16.61
18.8
16.93
17.19
7.16
6.61
6.39
Table 59 Historical Financial Performance
126
Capital over the early part of the past decade was fairly consistent at around $2.5 million per year.
Towards the middle and latter part of the period capital expenditure increased due to a number of special
upgrade projects reflecting the need to reinforce the network and meet escalating demand, particularly
from irrigation and dairy conversions. Maintenance over the same period has been steady at around
$2.5 million per year, with a couple of higher years due to major storm damage. Renewals have been
added into capital since the 2007-8 year and subtracted from maintenance
9.5
Service Level Performance
MPNZ’s strategic review process assesses actual service performance delivered against targets and
looks at industry benchmarking and customer feedback to then establish targets for future plans. Actual
service level performance against target for the year ending 31 March 2011 is summarised below.
Strategic Outcome
Reliability
Capacity
Quality
Safety
Customer Service
Environmental
Economic Efficiency
Measures
SAIDI (Threshold 147.24)
SAIFI (Threshold 1.71)
CAIDI
Faults/100km total
Faults/100km 66kV
Faults/100km 33kV
Faults/100km 22kV
Faults/100km 11kV
Faults/100km SWER
Total Interruptions
Locations where the load exceeds the firm capacity and
equipment ratings at GXPs, zone substations, subtransmission circuits and distribution feeders
Number of proven voltage complaints
Number of public injuries on MPNZ facilities or due to
MPNZ network issues
Number of OSH notifiable accidents
Number of Employee injuries LTIFR
Average rating from customer survey

Deliverables

Customer Satisfaction
Number of complaints of excessive noise from
substation/distribution transformers
Number of environmental complaints from staff/public
Percent of SF6 gas lost
Number of uncontained oil spills
Number of breaches of resource consent requirements
Load Factor
Capacity Utilisation Factor
Loss Ratio
Capital Cost per km
Capital Cost per ICP
Operating Cost per km *
Operating Cost per ICP *
2010-11
Target
97.0
1.07
90.65
2.00
0.00
0.65
2.12
2.12
0.76
280
0
<20
2010-11
Actual
337.8
2.90
116.51
5.90
0.00
2.60
4.86
6.66
1.65
601
Ashley GXP firm
capacity is
exceeded.
6
0
0
0
0
0
20.11
>8
>4.2
8.2
4.32
0
0
<1 %
0
0
70.4%
22.6%
5.7%
$2982
$392
$867
$114
0
0
0.6 %
0
0
71%
21.6%
5.6%
$2659
$356
$2206
$295
Table 60 Service Level Performance
* The basis of MPNZ’s assessment of operating costs has been realigned to the industry standard since last year’s targets were
set.
9.6
Reliability Performance Variance Analysis
MPNZ’s service level targets and the regulatory threshold level set for SAIFI and SAIDI were exceeded
during 2010-11.
There were 376 planned shutdowns out of a total of 601 interruptions on the MPNZ network during 2011.
Earthquakes were directly responsible for 47% of CAIDI, 25% of SAIFI, and contributed to other faults
later. A wind storm in the days immediately following the September earthquake increased SAIDI by 30
min over the previous year. There were also a high number of line contacts by machinery. Planned work
outages were also high but 10 minutes lower than last years. A loose current transformer wiring
127
connection caused a protection fault at the main Southbrook substation affecting a very large number of
customers for a short duration.
The following figures show the causes of the faults experienced on the MPNZ network over the past year
and the impact of each fault category on the customers affected. The major causes of faults are tree
related faults, vehicle accidents, wind storms and machinery contact. MPNZ has progressively increased
its tree management budget over the past ten years and introduced greater consideration of vehicle
accidents, bird strike and climatic conditions into line designs. The high level of growth and network
development including 33 kV to 66 kV conversion and 11 kV to 22 kV conversion continues to keep
planned outage statistics high despite maximising the use of portable generators and live line work.
SAIDI by Cause
180
Work Quality
160
unknown
Switching Error
Customer Minutes
140
Planned
120
Natural Disaster
100
Extreme Conditions
External Interference
80
Asset Failure
60
40
Wind
Work Quality
Vehicle accident
Trees
Unknown
Tree Cutter
Testing
Transformer
Switching Error
Rodent
Protection error
Cause
Protection Failure
Overloading
Livestock
Insulator
Lightning
Generator
Fuse Failure
Fire
Flood
Crossarm
Earthquake
Connection
Conductor
Birds
Cable
Binder
ABS
Arrestor
Planned
0
Machinery …
20
Figure 45 Causes of Faults by Duration 2010-2011
SAIFI by Cause
0.8
Work Quality
unknown
0.7
Switching Error
Planned
Natural Disaster
0.5
Extreme Conditions
External Interference
0.4
Asset Failure
0.3
0.2
Work Quality
Wind
Unknown
Vehicle accident
Trees
Tree Cutter
Transformer
Testing
Switching Error
Rodent
Protection error
Overloading
Livestock
Protection Failure
Cause
Lightning
Insulator
Generator
Fuse Failure
Fire
Flood
Earthquake
Crossarm
Connection
Conductor
Birds
Cable
Binder
Arrestor
ABS
0
Machinery…
0.1
Planned
Customer Interruptions
0.6
Figure 46 Causes of Faults by Number of Interruptions 2010-2011
128
Figure 47 shows the trend and forecast targets for faults per 100km of class B and C type faults by
voltage.
Faults per 100km (Class B and C)
7
11kV
6
22kV target
5
11kV target
Faults/100km
33kV
22kV
4
Total target
22kV
11kV
3
33kV target
Total
2
66kV
SWE target
SWE
1
0
Total
66kV target
SWE
2003
2.97
2004
2.18
2005
1.66
2006
2.92
2007
5.56
66kV
2008
2.40
2009
3.61
2010
4.48
2011
5.90
2012
2013
2014
2015
2016
2017
2018
2019
2020
5.90
4.67
4.62
4.57
4.53
4.48
4.44
4.40
4.35
4.31
1.89
1.89
1.89
0.00
1.49
1.47
1.46
1.44
1.43
1.41
1.40
1.38
1.37
0.97
1.95
0.41
2.60
2.48
2.45
2.43
2.40
2.38
2.35
2.33
2.31
2.28
3.10
3.80
2.04
4.86
4.95
4.90
4.85
4.80
4.75
4.71
4.66
4.61
4.57
2.52
3.88
5.36
6.66
4.95
4.90
4.85
4.80
4.75
4.71
4.66
4.61
4.57
0.86
0.88
1.70
1.65
2.00
2.00
2.00
2.00
2.00
2.00
2.00
2.00
2.00
Total target
66kV
66kV target
33kV
0.00
0.35
4.00
3.24
1.30
1.94
33kV target
2.60
22kV
22kV target
11kV
4.86
3.23
2.01
1.48
3.06
5.86
11kV target
SWE
6.66
SWE target
1.65
Figure 47 Faults per 100km (Class B and C)
To help reduce the occurrence and impact of supply fault interruptions MPNZ will continue to:

Analyse fault causes to help to understand how they can be avoided or prevented.

Undertake regular reviews of system protection settings and coordination
9.6.1 Capacity Performance Variance Analysis
MPNZ has been able to accommodate every request for a new connection over the past year. This has
been achieved without customers having to wait for lengthy periods. MPNZ’s capital expenditure and
development programme over the past decade has been the largest MPNZ has ever experienced. All
zone substation transformers are now loaded at lower than their maximum rating and good voltage
regulation is maintained on all distribution systems. There are no sub-transmission or distribution feeders
loaded above their ratings.
MPNZ will endeavour to make sufficient capacity available to cater for all existing and new customers.
Small loads under 100 kW can generally be connected following a short approval process, larger loads up
to 0.5 MW may require some upgrade work to be done prior to connecting and the length of time taken
will depend on the size of the load. Loads larger than 0.5 MW will generally require 11 kV distribution
system upgrades and in some cases zone substation upgrades. MPNZ will continue to monitor the peak
loadings on equipment ratings and strive for zero locations where the load exceeds the firm capacity or
equipment ratings as our target for the remainder of the planning period.
Most zone substations do not have sufficient transformer capacity to supply all customers with one
transformer out of service even after switching to transfer load to other substations where possible. This
is required by the MPNZ security standards for urban areas and major loads. Planned upgrades will
129
improve this over the next five years. In future MPNZ will monitor the percentage of customers are able
to be supplied following a single transformer fault at their source substation. This will be a security
performance indicator.
9.6.2 Quality Performance Variance Analysis
The number of proven power quality complaints has been decreasing since 2000.
Proven Voltage Complaints
30
Number
25
20
15
10
5
2010/11
2009/10
2008/09
2007/08
2006/07
2005/06
2004/05
2003/04
2002/03
2001/02
2000/01
0
Figure 48 Power Quality Complaints
Figure 49 shows the power quality complaints by actual found cause. A number of voltage complaints
are actually the result of undersized customer service mains.
The number of power quality complaints in any year is highly variable and while some years are well
under the targets set by MPNZ, other years are not. MPNZ will continue to monitor customer
expectations to assess performance in this area.
Across all customers in the 2011 survey (figure 49) who indicated a desire for quality improvement, 67%
stated that any price increase to facilitate improvement would be too much. Over the 2010-2011 period, a
14% decrease was recorded in
Willingness to Pay Extra for Power quality Improvement
100
90
80
70
Mean %
60
50
40
30
20
10
0
Residen Residen Residen
Comme Comme Comme
Residen Residen Residen Residen Residen Residen
Comme Comme Comme Comme Comme Comme
tial
tial
tial
rcial
rcial
rcial
tial
tial
tial
tial
tial
tial
rcial
rcial
rcial
rcial
rcial
rcial
Remote Remote Remote
Remote Remote Remote
Urban Urban Urban
Rural
Rural
Rural
Urban Urban Urban
Rural
Rural
Rural
Rural
Rural
Rural
Rural
Rural
Rural
Total
Total
Total
An extra $300 / year
0.00
0.00
0.00
0.00
0.00
1.40
0.00
0.00
0.00
0.00
0.00
0.00
0.00
6.70
0.00
15.40
0.00
0.00
3.40
0.60
1.00
An extra $200 / year
0.00
0.00
1.80
0.00
1.70
0.00
6.70
0.00
3.70
16.70
0.00
0.00
11.00
0.00
0.00
7.70
7.70
0.00
2.90
1.20
1.00
An extra $100 / year
1.80
2.60
5.50
6.80
1.70
8.20
10.00
4.30
7.40
0.00
16.70
33.30
0.00
0.00
12.00
7.70
15.40
23.10
16.00
12.60
21.90
An extra $50 / year
25.00
5.10
23.60
14.90
16.70
19.20
13.30
17.40
25.90
0.00
16.70
16.70
11.10
13.30
24.00
7.70
15.40
23.10
16.00
12.60
21.90
Any increase unacceptable
73.20
92.30
69.10
78.40
80.00
71.20
70.00
78.30
63.00
83.30
66.70
50.00
77.80
80.00
64.00
61.50
61.50
61.50
72.30
81.40
67.20
Figure 49 Willingness to Pay for Power Quality Improvements
130
9.6.3 Safety Performance Variance Analysis
MPNZ suffered six employee lost time safety incidents during 2010. These were a Line Mechanic who
fell from a height while attempting to free a line pulling rope and spraining a leg, a Utility Worker falling
into an open trench and receiving a bruised hip, a Vegetation worker receiving a strained back while
assisting on a cable laying job, a Faultman strained his wrist while pulling a cable, a Line Mechanic
strained his back while moving poles, and another Line Mechanic tore his Achilles tendon climbing into a
truck.
9.6.4 Customer Service Performance Variance Analysis
Deliverable Means - by Customer Group
10
9
Mean Rating
1=lowest (poor)
10=highest (good)
8
7
6
5
4
3
2
1
0
Residential Remote
Commercial Urban
Rural
Residential Urban
Residential Rural
Faultmen
8.58
8.73
8.63
Easy to get hold of for faults
8.24
8.22
7.67
Commercial Rural
Commercial
Remote Rural
Major Users
8.00
8.18
8.00
8.83
8.56
7.24
8.18
8.21
7.30
8.10
Total
How quickly power is restored
8.39
8.26
8.25
8.28
8.22
8.00
6.92
8.25
Number of times power goes off
8.83
8.27
8.31
7.74
7.98
7.55
6.83
8.33
Keeping power fluctuations to a minimum
8.44
8.03
7.61
7.26
7.80
7.83
7.00
8.02
Speed of response
8.40
8.32
8.25
7.39
8.10
7.97
6.90
8.24
Notifying of planned outages
8.31
8.43
8.35
7.53
8.68
8.43
8.67
8.38
Length of time power is off
8.28
8.09
7.96
7.68
8.04
7.76
6.83
8.07
Keeping dimmimg light to a minimum
8.38
8.06
7.62
7.79
7.86
8.19
6.82
8.05
Limiting momentary loss of power
8.31
8.00
7.70
7.16
7.98
7.81
6.75
7.98
Figure 50 Deliverable Means – by Customer Group
As presented in Figure 50 above, across all deliverables, customer ratings trended toward a positive level
of satisfaction. Some minor variations between customer segments and deliverables occurred. Across the
total number of respondents in 2011, the area given the lowest rating was limiting momentary loss of
power (7.98) and the highest was Faultmen (8.56).
When looking at response by consumer group, the two lowest ratings of 6.75 and 6.82 were both given by
the Major Users group to limiting momentary loss of power, and keeping dimming light to a minimum
respectively. The two highest ratings of 8.83 each were given by the Residential Urban group to the
number of times power goes off and Major Users to Faultmen.
Across all groups and areas, means ratings were between 7.98 and 8.56 indicting a fairly high to high
level of performance.
The 2011 survey of overall satisfaction trended towards very satisfied and demonstrated a small but
statistically significant increase over the 2010 figure. Levels of satisfaction in 2011 varied slightly by
customer group; with the major users customer group recording a large decrease over the 2010-2011
period, however this can be attributed to the small sample size of this segment. Similarly, a decrease in
satisfaction was recorded for the commercial urban group. This may be attributed to the increased
frequency and duration of outages in 2011 caused by external events that may have impacted greater on
commercial customers, through loss of business / productivity than residential customers.
131
Overall Satisfaction - by Customer Group
5
4
Mean
3
2
1
0
-1
Residential Urban
Residential Rural
Residential Remote
Rural
Commercial Urban
Commercial Rural
Commercial Remote
Rural
Major Users
Total
2009
4.24
4.19
4.24
4.32
4.29
4.24
4.33
4.23
2010
4.29
4.11
4.24
4.42
4.02
4.14
4.53
4.2
2011
4.29
4.35
4.39
4.16
4.35
4.31
3.67
4.32
10-11 Gap
0.00
0.24
0.14
-0.26
0.33
0.17
-0.86
0.12
Scale: 1=Very dissatisfied, 2=Somewhat dissatisfied, 3= Neutral, 4=Somewhat satisfied, 5=Very satisfied
Figure 51 Overall Satisfaction –by Customer Groups
Between 2009 and 2011, increases in the levels of satisfaction have been recorded amongst all groups
except the Commercial Urban and Major Users groups.
Across all customers in the 2011 survey (figure 52), satisfaction with the number of outages was recorded
as being ‘satisfied’, demonstrating a small but statistically significant gradual increase over the 2009-2011
survey period. This increase in outage satisfaction, after the effects of external events and increase in
outage frequency is an indication of MainPower’s high performance in extreme circumstances. Increases
in satisfaction over the 2010-2011 surveys were recorded for all customer groups with the exception of
the residential urban group where a small decrease was recorded and the major users group, where a
larger decrease was recorded.
Outage Satisfaction - by Customer Group
5
4
Mean
3
2
1
0
-1
Residential Urban
Residential Rural
Residential Remote
Rural
Commercial Urban
Commercial Rural
Commercial Remote
Rural
Major Users
Total
2009
3.86
3.63
3.72
4.08
3.67
3.63
3.5
3.72
2010
4.15
3.86
3.97
3.8
3.72
3.65
3.47
3.91
2011
4.07
3.9
4.01
3.89
3.86
3.88
2.83
3.94
10-11 Gap
-0.09
0.05
0.04
0.09
0.14
0.23
-0.63
0.03
Scale: 1=Very dissatisfied, 2=Somewhat dissatisfied, 3= Neutral, 4=Somewhat satisfied, 5=Very satisfied
Figure 52 Outage Satisfaction –by Customer Group
132
9.6.5 Environmental Performance Variance Analysis
Consistent with our targets, during the 2011 year MPNZ reported no environmental problems and there
were no corrective actions generated by SGS New Zealand Limited as a result of the external audit of
MPNZ’s environmental management systems. MPNZ will continue to maintain certification to ISO 14001
Environmental Management.
9.6.6 Economic Efficiency Performance Variance Analysis
The asset investment efficiency measures of load factor, utilisation factor and loss factor are shown in
Figure 53. Targets for the planning period are also shown. The system load factor can be variable due to
the characteristics of customer load type and weather in the MPNZ area and therefore MPNZ has limited
control over the system load factor other than by winter peak load control. A summer season with high
rainfall will cause the irrigation consumption to be abnormally low and therefore reduce the load factor, as
occurred in 2003.
MPNZ has changed the method of peak load control to now manage peak loads at GXPs against the
upper South Island peak load at the time. This has been driven by a change in the Transpower pricing
methodology. This means that we may not necessarily be controlling the normal peak load at individual
GXPs as low as previously was the case. This has the effect of decreasing the load factor. Future
forecasting of this factor is therefore unreliable. MPNZ’s 2011 load factor at 71% is quite a way higher
than the national average of 59.4%. MPNZ’s load is still winter peaking, so increasing irrigation load
improves the load factor while reducing the utilisation factor.
MPNZ’s utilisation factor has trended up and down over the past few years and this has largely been due
to the effects of time variations in installing capacity and gaining growth in maximum demand, the latter
sometimes affected by the coldness of the winter experienced by customers. The reduction in utilisation
factor since 2001 and in future targets reflects the high number of transformers dedicated to irrigation
summer peaking load, which is not coincident with MPNZ’s traditional winter maximum demand. Also
rural customers tend to have a dedicated transformer each rather than running extensive low voltage
systems between them, because this is dictated by the larger distances between customers living in rural
areas. This has the effect of removing the opportunity for diversity gained from customers sharing
transformers and hence having a lower overall transformer installed capacity and utilisation factor. As a
result MPNZ’s utilisation factor for 2011 is significantly below the national average of 32.1%.
MPNZ’s loss ratio result for 2011 was close to the national average of 5.1%
80.0
70.0
60.0
Percent %
50.0
load factor
utilisation factor
40.0
loss ratio
30.0
20.0
10.0
0.0
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
68.8
63.8
62.0
69.7
70.8
69.7
66.2
68.8
69.0
71.0
71.1
71.1
71.1
71.1
71.1
71.1
71.1
71.1
71.1
71.1
71.1
utilisation factor 27.3
26.5
28.3
24.0
22.8
22.4
23.5
23.1
22.3
21.6
21.6
21.5
21.3
21.1
20.9
20.7
20.5
20.4
20.3
20.2
20.1
loss ratio
5.9
5.4
4.6
5.5
5.1
5.1
5.4
5.4
5.6
5.6
5.6
5.6
5.6
5.6
5.6
5.6
5.6
5.6
5.6
5.6
load factor
5.8
2021
year
Figure 53 Economic Efficiency Performance
MPNZ’s relative position against other New Zealand Lines Companies can be judged in general terms by
comparing capital and operating expenditure per kilometre and per Installation Control Point (“ICP”).
These measures, although not comprehensive and necessarily directly comparable, are useful as a
133
general guide to comparative company performance. The following Figures 54 and 55 show MPNZ’s
level of capital expenditure and operating expenditure per km of line and per ICP forecast, and
comparison against other like lines companies for the year ending 31 March 2011.
$4,000
Capital cost per km
$3,500
Capital cost per ICP
Operating cost per km
$3,000
Operating cost per ICP
$ Cost
$2,500
$2,000
$1,500
$1,000
$500
$0
200708
200809
200910
201011
201112
201213
201314
201415
201516
201617
201718
201819
201920
202021
202122
Capital cost per km
$3,312
$3,529
$2,989
$2,659
$2,982
$2,933
$3,485
$2,891
$2,341
$2,193
$2,027
$2,227
$2,158
$2,218
$2,149
Capital cost per ICP
$440
$467
$400
$356
$392
$384
$451
$370
$298
$277
$254
$278
$268
$274
$264
Operating cost per km
$1,640
$2,032
$1,963
$2,206
$2,300
$2,340
$2,348
$2,345
$2,375
$2,378
$2,364
$2,359
$2,354
$2,349
$2,344
Operating cost per ICP
$218
$269
$262
$295
$300
$306
$304
$300
$302
$300
$297
$294
$292
$290
$287
year
Figure 54 Forecast Capital and Operating Expenditure Measures
The graph indicates that MPNZ’s capital expenditure is mid range and this would be lower if it were not
for the high growth rates in MPNZ’s rural network. MPNZ’s operating expenditure targets in table 65 were
not calculated in accordance to the industry standard. This has been corrected for the current forecasts.
Disclosed operational expenditure is slightly below the average, and given MPNZ’s high levels of system
reliability this highlights good efficiency in maintenance techniques.
900
$ / Customer
800
700
600
Capex / Cust.
Opex / Cust
6000
5000
Capex / km
Opex / km
500
4000
3000
400
$ / kilometer
1000
2000
300
200
1000
100
0
0
Figure 55 Comparison of 2011 Expenditure with other like New Zealand Line Companies
134
9.7
Asset Management Practice Improvement
The main initiative for asset management improvement over the next year will be the introduction of new
mobile computing solutions that integrate to the Company’s recently installed TechnologyOne integrated
works, assets and financials asset management software. The mobile solution will provide field staff with
immediate access to asset information and will improve works management.
In addition, MPNZ Engineers will be installing a new SCADA system during 2012 which will provide latest
open platform technology and improved data analysis.
135
10 APPENDICES
10.1 Glossary of Terms
Term
Description
AMP
Asset Management Plan
CAIDI
Customer Average Interruption Duration Index, the
average minutes lost per customer interrupted.
DG
Distributed Generation
Fault Levels
The resultant current that flows during network short
circuit faults (faults between all three phases,
between a single phase and ground)
GXP
Grid Exit Point
A substation connecting the MPNZ
network to the Transpower National Grid
ICP
Installation Control Point
Customer
MPNZ
MainPower New Zealand Limited
SAIDI
System Average Interruption Duration Index, the
average minutes lost for total customers.
A measure of customer interruptions and
system reliability
SAIFI
System Average Interruption Frequency Index, the
average number of interruptions for total customers.
A measure of customer interruptions and
system reliability
2011
References to years refer to years beginning 1 April
(the financial year of 2011-2012)
SCI
Statement of Corporate Intent
SFUG/K
Static Frequency Unit
A measure of customer interruptions and
system reliability
Landis and Gyr model of plant
136
10.2 Cross Reference Table
Reconciliation
Electricity Information Disclosure Requirements 2008 Requirement 7(1) and Handbook (Chapter 4)
(a)
Summary of the Asset Management Plan
(b)
(c)
(d)
(e)
(f)
(g)
(h)
(i)
Background and Objectives, including:
Purpose of the plan
Description of the interaction between those objectives and other corporate goals, business
planning processes and plans
The period covered by the plan and the date approved by the board of directors
Description of stakeholder interests
Description of accountabilities and responsibilities for asset management
Details of asset management systems and processes, including asset management
systems/software and information flows
Details of assets covered, including:
A high-level description of the distribution area
A description of the network configuration
A description of the network assets by category, including age profiles and condition
assessment
Justification for the assets
Details of proposed levels of service, including:
Consumer oriented performance targets
Other targets relating to asset performance, asset efficiency and effectiveness, and the
efficiency of the line business activity
Justification for target levels of service based on consumer, legislative, regulatory,
shareholder and other considerations.
Details of network development plans, including:
Description of the planning criteria and assumptions
Description of the prioritisation methodology adopted for development projects
Details of demand forecasts, the basis on which they are derived, and the specific network
locations where constraints are expected due to forecast load increases
Policies on distributed generation
Policies on non-network solutions
Analysis of the network development options available and details of the decisions made to
satisfy and meet target levels of service
Description and identification of the network development programme (including distributed
generation and non-network solutions) and actions to be taken, including associated
expenditure projections
Details of lifecycle asset management plans, including:
Description of maintenance planning criteria and assumptions
Description and identification of routine and preventative inspection and maintenance
policies, programmes, and actions to be taken for each asset category, including associated
expenditure projections
Description of asset renewal and refurbishment policies
Description and identification of renewal or refurbishment programmes or actions to be
taken for each asset category, including associated expenditure projections
Asset replacement and renewal expenditure
AMP Reference
1
2.1, 2.2
2.3
2.3
2.5
2.5
2.8, 2.9
3.2
3.5, 3.6
3.5, 3.6
3.7
4.1. 4.2, 4.4, 4.5
4.1. 4.2, 4.4, 4.5
4.3, 4.4
7.1 – 7.10
7.11
6.1 – 6.7
7.13
7.11
7.14
7.14, 7.15
8.1, 8.2
8.3 – 8.13
8.1, 8.2
8.3 – 8.13
8.9
Details of risk policies, assessment and mitigation, including:
Methods, details, and conclusions of risk analysis
Details of emergency response and contingency plans
5.1 – 5.6
5.6
Details of performance measurement, evaluation, and improvement, including:
Review of progress against plan, both physical and financial
Evaluation and comparison of actual performance against targeted performance objectives
Gap analysis and identification of improvement initiatives
9.1, 9.2, 9.3
9.1, 9.2, 9.3
9.4
Expenditure forecasts and reconciliations consistent with the Handbook Appendix A
1.14, 9.1
137
10.3 Information Disclosure Requirement 7(2)
The Electricity Distribution (Information Disclosure) Requirements 2008, gazetted in October 2008
introduced a new requirement in relation to AMP information. In addition to the information to be included
in the AMP, as prescribed in the Electricity Information Disclosure Handbook, dated 31 March 2004 and
amended 31 October 2008, MPNZ is required to disclose the following information. This Appendix
comprises MPNZ’s disclosure in accordance with this Requirement.
(a) all significant assumptions, clearly identified in a manner that makes their significance understandable
to electricity consumers, and quantified where possible;

Existing external regulatory and legislative requirements are assumed to remain unchanged
throughout the planning period. Thus the external drivers which influence reliability targets and
design, environmental, health and safety standards and industry codes of practice are constant
throughout the AMP period.

All projections of expenditure are presented in real New Zealand dollar terms, that is 1 April 2012
values. In reality over time input costs (including those sourced from outside of New Zealand) for
asset management activities will change at rates greater or less than the rate of general inflation.
As expenditure forecasts are updated annually, this approach is acceptable and consistent with
that prescribed.

Transpower continues to provide sufficient capacity to meet MPNZ’s requirements at the existing
GXPs and undertakes the additional investment required to meet additional future demand, as
specified in the Development Plan section of this AMP.

The existing Vision and Corporate Objectives and Policies of MPNZ continue for the planning
period.

The results of future annual customer surveys of customer satisfaction and willingness or
otherwise to pay for improved reliability are consistent with those undertaken since 2004.

Neither the MPNZ network nor the local transmission grid is exposed to a major natural disaster
during the planning period.

The MPNZ network is exposed to normal climatic variation over the planning period including
temperature, wind, snow and rain variances consistent with its experiences since 2000.

Demand growth at each GXP is predicted to continue throughout the planning period at a rate
consistent with the historical rate of growth from 2000.

Seasonal load profiles remain consistent with recent historical trends.

No new embedded generation is commissioned during the planning period.

Zoning for land use purposes remains unchanged during the planning period.
(b) a description of changes proposed where the information is not based on the Distribution Business’s
existing business;
No changes are proposed to the existing business of MPNZ, and thus all prospective information has
been prepared consistent with the existing MPNZ business ownership and structure.
(c) the basis on which significant assumptions have been prepared, including the principal sources of
information from which they have been derived;
The basis on which the assumptions have been prepared is described in detail in Section 6 Demand
Forecasts of the AMP. The principal sources of information from which they have been derived are:

MPNZ’s Strategic Planning documents including the 2010-11 Statement of Corporate Intent and
the 2010-11 Annual Business Plan and Budgets.

MPNZ’s 2010-11 Business Continuity Plan
138

Annual MPNZ Customer Surveys (2004 – 2011)

Maximum electricity demand, at each GXP, for the period 2000 – 2011

Regional population data and forecasts sourced from Statistics New Zealand and the
Waimakariri, Hurunui and Kaikoura District Councils.

Interaction with customers and the community in relation to possible future developments within
the network region.
(d) the factors that may lead to a material difference between the prospective information disclosed and
the corresponding actual information recorded in future disclosures;
Factors which may lead to a material difference between the AMP and future actual outcomes
include:

Regulatory requirements may change, requiring MPNZ to achieve different service standards or
different design or security standards. This could also impact on the availability of funds for asset
management.

MPNZ’s ownership could change, and different owners could have different service and
expenditure objectives than those embodied in the AMP.

Customers could change their demands for reliability or their willingness to pay for different levels
of service.

The network could experience major natural disasters such as an earthquake, flood, tsunami or
extreme wind, rain or snow storms.

The rate of growth in demand could significantly accelerate or decelerate within the planning
period.

Within each region, load patterns could change resulting in a movement from summer to winter
peaks and vice versa.

Significant embedded generation capacity may be commissioned within the network supply area.

Significant land zoning changes may be implemented within the region.

Significant new loads may require supply.

MPNZ’s largest customers may significantly reduce load.

There could be major unforeseen equipment failure requiring significant repair and possible
replacement expenditure.

More detailed asset management planning undertaken over the next 3 – 5 years may generate
development and maintenance requirements which significantly differ from those currently
provided for.
139
(e) the assumptions made in relation to these sources of uncertainty and the potential effect of the
uncertainty on the prospective information.
The assumptions made in relation to these sources of uncertainty are listed in (a) above. The
potential effect of each on the prospective information is:
Source of Uncertainty
Potential Effect of Uncertainty
Regulatory
Requirements
It is unlikely that any of the Requirements will reduce, thus the
most likely impact is an increase in forecast expenditure to meet
possible increased standards. It is not possible to quantify this
potential impact.
Different owners could have different service and expenditure
objectives than those embodied in the AMP, resulting in either
higher or lower service targets and associated expenditures
Customers could change their demands for service and
willingness to pay resulting in either higher or lower service
targets and associated expenditures
Equipment failure and major repairs and replacements required
which are not currently provided for
Ownership
Customer Demands
Natural Disaster
Demand Growth
Load Profile
Land Use Zoning
New Loads
Load Reductions
Equipment Failure
Further Detailed
Planning
Higher or lower demands require greater or lesser capacity
across the system as currently projected. Potential high and
low demand scenarios are contained in Section 6 of the AMP.
The most likely implication is that the existing expenditure
forecast is either accelerated or delayed in response. The
magnitude of this potential shift is unlikely to be more than 3-5
years either way.
Seasonal shifts in demand could require planned capacity
upgrades to be accelerated or delayed. The magnitude of this
potential shift is unlikely to be more than 3-5 years either way.
Zone changes will impact on demand growth. The implications
of uncertainty for demand growth are noted above.
New loads will impact on demand growth. The implications of
uncertainty for demand growth are noted above. Specific new
investments may also be required to meet large new loads.
Reduction in load from large customers provides additional
capacity for the remainder of the network. Thus existing
expenditure projections may be deferred.
Equipment failure and major repairs and replacements required
which are not currently provided for.
Development and maintenance requirements differ from those
currently predicted for the later five years of the planning period,
particularly for the 22kV, 11kV and 400V networks.
Potential Impact of the
Uncertainty
Low
Medium
Medium
Low, Medium, High
depending on
severity
Low
Low
Low
Low
Low
Low due to Business
Continuity Planning
Low (applies mainly
to years 6 – 10 of the
AMP)
140
10.4 Operational Objectives 2012-13
Health and Safety
MainPower will maintain a safe and healthy work environment and promote a positive ‘Safety First’
culture that encourages employees to be involved in the continual improvement of workplace health
and safety practices.
Customer Service
MainPower will continue to operate and make available to its customers, a safe, secure and reliable
electricity distribution network.
MainPower will ensure, through the management and operation of its electricity distribution network,
technical support and field services contracting capability, a level of security and reliability of electrical
supply that places MainPower in the upper quartile when compared to other regional line companies
in New Zealand.
Community
MainPower will continue to take a leadership role in the North Canterbury and Kaikoura Communities.
Sustainable Practice
MainPower will consistently balance the economic, environmental, social and corporate governance
needs of the business with a view to understanding and protecting the potential needs of future
generations.
Regulatory
MainPower will monitor, assess business requirements and implement change to ensure we continue
to meet or exceed legislative and regulatory obligations/compliance.
Human Resources
MainPower will provide employees with a fair and supportive work environment where the highest
levels of competency are maintained and personal development encouraged.
Integrated Management System
MainPower will fully integrate the company’s management systems in order to reflect its new
business model and will continually improve these systems and supporting processes consistent with
industry best practice.
Asset Management
MainPower’s asset management processes will deliver the required level of service to customers in
an economically efficient manner that meets their expectations.
Generation
MainPower will develop, either solely or in collaboration with others, Renewable Generation
opportunities that support and move MainPower’s Electricity Retail business towards 75% selfsufficiency in electricity supply within 10 years.
MainPower will, either on its own account or in collaboration with others, become a preferred retailer
of electricity to its electricity distribution network customers.
Financial
MainPower will continually strive to optimise the value to the shareholder in the provision of regulated
lines services and to achieve a full commercial return from its investment in the provision of
unregulated lines services.
Technology
MainPower will be recognised within the electricity industry for the implementation of Smart Grid
Technologies.
141
10.5 Load Control Time, Price and Load Shifting Channels
Driver
Time
Price
Load Shift
Time/Load Shift
(Agreed Times)
Standard Load Control
(Anytime)
Control Type
Streetlight Control
(Anytime)
Master Codes
Preferential Load (Priority 1)
MainPower
Kaiapoi Electricity
Code
109
109
MainPower
Kaiapoi Electricity
Code
110
112
MainPower
Kaiapoi Electricity
Code
106
107
Waterheating Load (Priority 2)
MainPower
100
Kaiapoi Electricity
100
Area Codes
MainPower
Kaikoura
Culverden
Waipara
Southbrook
Kaiapoi
Code
45
46
47
48
49
Kaiapoi Electricity
49
Nil
MainPower
Kaikoura
Culverden
Waipara
Southbrook
Kaiapoi
Code
00
01
02
03
04
Kaiapoi Electricity
05
MainPower
Kaiapoi Electricity
Code
10-17
21-28
Channel Codes
Description
MainPower
Kaiapoi Electricity
Private
Code
40-41
42
44
MP KE
Supply
Code Code On
Off
Residential
+/-0030 +/-0300
Night Saver
50
60 2300
0700
Day/Night Saver 52
62 2300
0700
Day/Night Boost 55
65 (1400 (1600
(2300 (0700
Other Supply
51
61 2300
0700
Night Saver
63 2300
0700
Day/Night Saver 53
Industrial
54
64 2300
0700
Storage Heating
59
69 (1100 (1500
(2300 (0700
142
10.6 Asset Management Practice Improvement Log
1998 Performance Review

During 1998 a full external review of MPNZ’s Asset Management Plan was undertaken to
appraise the suitability of the plan for purpose, identify strengths and weaknesses and to make
recommendations for improvement. The effectiveness of asset management systems and their
implementation at MPNZ were also assessed.

The key findings were that the 1998 Plan had the following particular strengths:

The development options and circumstances of specific assets were well identified and
described.

The underpinning environmental and quality processes were supported by detailed procedures
and ISO accreditation.

Risk factors were described in detail and assessed together with mitigating measures.

At the same time the review recommended that improvement was needed in some areas. It is
recognised that the programme for development of MPNZ’s asset management practice to meet
best practice will follow a continuous improvement cycle. The following improvement work has
been carried out since the review was initiated.

The AMP was again reviewed by independent appraisal during 2003 and a number of review
recommendations have been incorporated into this current plan.

During 2005 the AMP was audited by the Commerce Commission and a number of
recommendations from that audit have been included in this plan.
1998 Improvement
 Service levels and associated targets were identified.

A description of information systems was included in the Plan.

The overall maintenance strategy and rationale for selection of maintenance methods was
detailed.

More detailed financial projections and associated programmes of work were established.

The document was redrafted to comply with revised regulatory disclosure requirements.

1999 Improvement

The GIS information system was improved with the addition of an outage manager and an object
manager. This enabled improved interruption statistics management and to tag photographs,
equipment instructions, design drawings and customer correspondence to screen objects.
Linking of the customer to transformers by low voltage links was completed. Greater use was
made of the system by internal staff and contractors.

Customer level of service targets were monitored against actual.

Supply security standards were integrated with maintenance and planning. This was achieved by
planning to spend an amount each year on maintenance by applying a cost to a lost customer
minute in order to avoid having them.
2000 Improvement
 An automated GIS based load flow analysis tool was developed by driving the PSSU load flow
software from asset information in the GESmallworld environment.

The process for dealing with complaints was improved taking into account the general trends
emerging from the work done through the Electricity Complaints Commission.

A customer awareness programme was carried out during 2001-2002 informing customers on
risk of damage to appliances caused by power surges and other power system events.
143

During 2001-2002 improvement was made in cable testing, jointing and termination methods as a
result of research into historical procedures, test records and cable faults.

A better understanding of oil test results from zone substation transformers was developed
following expert advice on the interpretation of results.
2001 Improvement
 A bi-directional link between GIS and PSSU load flow was created to automate load flow analysis
studies for the power network.

Application of a customer guarantee scheme for loss of supply was examined and other company
initiatives examined.

A customer awareness programme detailing the risks involved in customers not protecting their
sensitive electronic appliances and equipment was undertaken.

Better asset condition based data was recorded to assist with maintenance planning. This
ranged from signature testing of cables to improved oil test analysis.

Options for replacing the Company’s financial software were investigated during the year, driven
by the need to introduce a more sophisticated works management system and processes.
2002 Improvement
 All outages down to the customers low voltage connection on the outage manager software
application were recorded.

A business continuity plan was developed, implemented and tested.

A customer survey was used to engage with customers on service issues and price versus
reliability trade offs. In conclusion, customers generally know of and are satisfied with MPNZ as
their electricity supply provider. MPNZ will measure customers’ satisfaction on a frequent basis
and act on the results appropriately. The limitations found in the survey were a low response rate
despite follow-up, and a lack of data to quantify the Return on Investment (ROI) of problem
prevention. The following communications initiatives will be developed to increase our profile with
our customers:

Field visits to customer sites by personnel.

Periodic mailings to customers.

Advertising to explain service policies or updates on interruptions etc.

Developing customer service brochures.

Holding workshops with large user and commercial customers who are concerned with Power
Quality.

Work commenced on reliability monitoring of individual feeders and the application of priorities to
those feeders based on customer type.

A new works management system was commissioned.
2003 Improvement
 Several new generation initiatives have been developed over the past year.

Introduction of an intelligent switching schematic generated from the base GIS information.

A new diesel generator mounted on a truck has been purchased and constructed over the past
year and will help to reduce the amount of customers affected by planned shutdowns.

Development of a new trees database and trees monitoring regime has been completed in line
with the new trees regulations.

A second customer survey was undertaken to better engage with customers on service issues. In
conclusion it has been noted that customer awareness of the Company seems to be lessening
144
over time, and that it is important to MPNZ to ensure that this does not continue. Thought will be
given to formalising a communication plan.
2004 Improvement
 An annual plan for customer engagement has been developed based on undertaking discussions
with large customers and customer represented groups, surveying a sample of small customers,

Reliability and quality expenditure assessment: Development of a causal analysis of outages or
economic ranking of potential projects by marginal benefit

More definition around maintenance policy and renewal decisions.

A better framework for benchmarking asset management practice.

Review of demand forecasting.

It was noted that an area of growing concern to the wider community is that of electromagnetic
fields. MPNZ will explore how best to address this issue in a proactive and responsible manner.
2005 Improvement
 Good progress has been made on refining and formalising MPNZ’s customer engagement
practice. In practice this has meant continuation of the customer survey initiated in 2003 and
increased large account management practice. A formal customer communication plan will be
developed for inclusion in next year’s AMP.

A reliability assessment has been undertaken during the past year using a causal analysis of
outages to rank potential projects by marginal benefit. One outcome has been the consideration
of line circuit breaker positioning in dealing effectively with keeping the most customers on during
interruptions.

This plan now includes more definition around maintenance policy and renewal decisions
including detailed maintenance policies and strategies for each major asset class.

MPNZ engineers had last year proposed to develop a better framework for benchmarking asset
management practice. The new requirements for AMP disclosure put out by the Commerce
Commission in March 2006 will assist this process, therefore it was decided to postpone this
review for a year.

A study of demand forecasting at MPNZ has been undertaken. The results of this study are now
included in this plan.

MPNZ has developed a policy fact sheet on Electromagnetic fields based on the New Zealand
interagency report commissioned by the Government. This has proved useful when responding to
customer enquiries.
2006 Improvement
 A public relations consultant has been engaged to assist in developing a communication plan with
the community.

Contractors training, competency levels and work practices have come under the radar this past
year. New training systems have been established incorporating regular refresher training and
familiarisation training. New higher levels of competency are required to be achieved by
contractors before they are allowed to access the network. New work completion certificates have
been introduced along with a new livening request notice which requires sign off by at least two
contractors that the work has had the required tests carried out prior to livening. A Contractor
auditor has also been appointed to monitor contractor practices in the field.

A mobile computing system for field contractors has been developed and tested over the past
year utilising the company’s existing voice wireless systems. The system will be rolled out over
the next year.

A review of the Company’s Health and Safety systems was carried out and a new integrated
management system has been developed based on a combined ISO audited Quality,
145
Environmental, and Health and Safety Management system. The new systems will be
implemented over the next year.
2007 Improvement
 New financial codes and allocations for monitoring renewals and replacements against capital
and maintenance expenditure have been developed.

A formal customer communication plan has been developed.

An auditor has been appointed to monitor Contractors work practices.

Field Contractors have been provided with handheld voice radios for greater flexibility in the field
and the radio incorporates an emergency button for sending an SOS back to base. The next step
is to roll out mobile computing via the voice radio network.

MPNZ has now been certified to NZS 4801 Health and Safety Management and has developed
an overall integrated management system incorporating quality, environmental, and health and
safety.

MPNZ now identifies main causes of unplanned network interruptions and possible mitigation
measures to improve levels of service and monitors the least reliable feeders to help prioritise
maintenance expenditure.
2008 Improvement
 A number of integrated asset management, financial management and works management
software solutions were studied and TechnologyOne was selected to investigate further through a
business research study approach.
2009 Improvement
 A business research study was performed with TechnologyOne as a solutions partner.

In keeping with the MPNZ group strategy of providing the best performance possible from our
core business power system for the community, MPNZ has developed a business restructuring
plan which will remove the business subsidiary status of MainPower Contracting Limited and will
focus on providing improved service to customers and improved performance from the MPNZ
power system.
2010 Improvement
 MPNZ has purchased and installed the TechnologyOne integrated asset management, financials
and works management software solution.

MPNZ has created a new works section in the Engineering division of the Company.
2011 Improvement
 MPNZ has integrated TechnologyOne with its GIS system and business workflows.

The SCADA upgrade has been deferred due to IT servicer changes required following the
earthquakes and relocation of staff from MPNZ’s head office building.
10.7 Photographs of Key Assets
MPNZ retains photographs of key assets in its information system. These have been excluded from this
document due to their file size. If you wish to view these photographs please contact MPNZ directly.
146