Scanpower Asset Management Plan 2013/2023 Scanpower Asset

Transcription

Scanpower Limited
Asset Management Plan
1st April 2013 – 31st March 2023
Page 1 of 193
Table of Contents
Ref 1.0 1.1 1.2 2.0 2.1 2.2 2.3 2.4 2.5 2.6 2.7 2.8 2.9 3.0 3.1 3.2 4.0 4.1 4.2 4.3 5.0 5.1 6.0 6.1 6.2 6.3 6.4 6.5 6.6 7.0 7.1 7.2 7.3 7.4 7.5 7.6 7.7 7.8 7.9 Description TERMS OF REFERENCE Date Complete and Period Covered
Directors’ Declaration EXECUTIVE SUMMARY Purpose of the Plan Introduction to Scanpower Overview of Scanpower’s Asset Management System
Asset Management Definition Organisational Capability Strategic Overview Network Development Planning Summary
Summary of Life Cycle Management Approach used by Scanpower
Network Expenditure Forecasts THE ASSET MANAGEMENT SYSTEM
Background to the Asset Management Planning Process
Asset Management Plan Design Compliance
ASSET MANAGEMENT STRATEGY
Scanpower’s Strategic and Asset Management Planning Process
Stakeholder Analysis and the Commercial Environment
Corporate Level Strategy Formulation
PERFORMANCE OBJECTIVES AND SERVICE STANDARDS
Asset Management Objectives ASSET KNOWLEDGE SET Service Area Large Customers
Load Characteristics Energy Supplied and Demand Network Configuration Justification for Assets ASSET INFORMATION SYSTEMS CableCAD Geographic Information System
NCS Customer / ICP Database National Electricity Registry SCADA System Records Proprietary Asset Databases Linkage Between Data Systems and Asset Management Processes
Asset Management Information Systems Review
Improvement Priorities Technical Standards and Guidelines
Page
6
6
6
7
7
7
11
12
12
12
14
15
16
18
18
19
21
21
23
27
31
31
35
35
36
37
38
40
47
48
48
48
48
48
49
49
49
50
51
Page 2 of 193
Table of Contents continued
Ref 7.10 8.0 8.1 8.2 8.3 8.4 9.0 9.1 9.2 9.3 9.4 9.5 9.6 10.0 10.1 10.2 10.3 10.4 10.5 10.6 10.7 11.0 11.1 11.2 11.3 11.4 11.5 11.6 11.7 11.8 12.0 12.1 12.2 12.3 12.4 12.5 APP A APP B Description Maturity of Information (AMMAT)
ORGANISATIONAL CAPABILITY Accountabilities and Responsibilities
Developing Asset Management Organisational Capability
Competency Requirements Communication and Participation
RISK MANAGEMENT Introduction to Risk Management
Corporate Risk Management Insurance Asset Management Related Risk Management Process
Significant Assumptions Business Model Risk NETWORK DEVELOPMENT PLANNING
Network Development Plan Summary
Planning Objectives Policies and Standards Planning Methodology Network Gap Analysis Automation and Protection Development Plan
Network Development Plan Budget and Forecast Expenditure
LIFE CYCLE MANAGEMENT Summary of Life Cycle Management
Introduction to Life Cycle Management
Asset Information by Category Asset Age Profiles Drivers for Maintenance Planning
Maintenance Driver Analysis by Asset Category
Maintenance Strategy and Practice
Operating Budgets (Maintenance and Routine Capital Expenditure)
EVALUATON OF PERFORMANCE Review of Progress Against Plan Review of Service Delivery Against Targets
Review of Planning Process Objectives
Performance Gap Analysis Public Safety Management APPENDIX A – AMMAT REPORT PREPARED BY UTILITY CONSULTANTS LTD
COMPLIANCE ASSESSMENT MATRIX / REVIEW
Page
51
54
54
57
57
58
60
60
61
68
69
74
74
76
76
77
77
83
84
126
137
139
139
139
140
142
153
156
169
171
180
180
183
185
185
191
192
193
Page 3 of 193
Table of Figures
Ref 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 Description Graphical Representation of 10 Year Network Expenditure Forecast
The PAS 55 Asset Management System
The Asset Management Hierarchy
Scanpower Business Planning Process
Scanpower Stakeholder Analysis Scanpower Area of Supply Scanpower Load Profile Curves (Dannevirke and Woodville POS)
Typical Daily Consumption Profile
Consumption by Feeder as at 5 March 2013
National Grid Configuration (Central North Island)
Scanpower Geographic Lay Out of 11kV Distribution Lines
Information Systems / Flow Schematic
Asset Management Competency Framework
Scanpower Organisational Chart Risk Management Framework Conceptual Risk Assessment Process
Risk Treatment / Risk Characteristics Matrix
Maximum Loadings by Feeder Contingent Capacity for Dog Conductor at 11kV
Conceptual Asset Age Profile Curves / Interval Setting
High Voltage Pole Age Profile by Material Type
11kV Overhead Conductor Age Profile (Length and Type by Year of Installation) 11kV Underground Cable Age Profile (Length and Type by Year of Installation) LV Overhead Conductor Age Profile (Length and Type by Year of Installation) LV Underground Cable Age Profile (Length and Type by Year of Installation)
Small Transformer (<75kVA) Age Profile – Number Installed per Year by Capacity Large Transformer (<50kVA) Age Profile – Number Installed per Year by Capacity Air Break Switch Age Profile (Quantity by Year of Installation)
Performance and Condition Factors – Conceptual Model
Risk Based Analysis and Justification Model
Tree Risk Assessment Tool Graphical Representation of 10 Year Network Expenditure Forecast
SAIDI Monthly Performance Trend 2011/2012
SAIFI Monthly Performance Trend 2011/2012
Summary of Fault Cause Analysis
Page
17
18
19
22
24
35
38
39
40
41
42
49
54
56
60
70
71
85
86
143
145
146
147
148
149
150
151
152
154
155
166
178
184
184
187
Table of Tables
Ref 1 2 3 4 5 6 7 8 Description Scanpower High Level Network Metrics
Scanpower Key Network Data as at 31 March 2012
Scanpower Key Financial Data as at 31 March 2012
Scanpower Key Organisational Data at Present Date
Summary Corporate Strategy Map
10 Year Network Expenditure Forecast (all Categories)
Business Planning Document Summary
Summary of Stakeholder Interests
Page
8
10
10
11
13
16
23
25
Page 4 of 193
Table of Tables continued
Ref 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 Description Summary Corporate Strategy Map
Asset Management Objectives and Policies
Scanpower Major Customer Details
Dannevirke Feeder Data Woodville Feeder Data Scanpower AMMAT Review Recommendations
Scanpower Corporate Risk Register
Insurance Cover Summary Asset Management Related Risk Summary
Scanpower Security Standard Contingent Capacity Calculations by Feeder
Load Growth Forecast Assumptions
Load Growth Forecasts by Feeder
Reassessment of Feeder Capacity Across Reconfigured Network
Summary of Security Strategy for Significant ICPs
Revised Load / Capacity Forecast Under NDP Conditions
Feeder Statistics and Technical Comparison
Fuse Saver Deployment Summary (North Feeder)
Fuse Saver Deployment Summary (Mangatera Feeder)
Fuse Saver Deployment Summary (Weber Feeder)
Asset Values by Category Asset Quantity by Asset Category and ODV Handbook Description
Hardwood HV Poles Maintenance Driver Summary
Hardwood HV Poles Maintenance,Prioritisation, Risk Scoring and Forecast Timing Hardwood LV Poles Maintenance Driver Summary
Hardwood LV Poles Maintenance,Prioritisation, Risk Scoring and Forecast Timing Small Transformers – Maintenance Policy, Criticality, Risk and Gap Analysis
Large Transformers – Maintenance Policy, Criticality, Risk and Gap Analysis
Air Break Switch – Maintenance Policy, Criticality, Risk and Gap Analysis
Tree Management and Maintenance – Drivers, Objectives, Policies and Strategies Historic Tree Cutting Statistics Forecast Tree Cutting Statistics HV Line Inspection Maintenance Strategy and Practice
Below Ground Pole Inspections Strategy and Practice
LV (Roadside) Inspections Maintenance Strategy and Practice
LV Service Lines Maintenance Strategy and Practice
HV Switchgear Visual Ground Inspections Strategy and Practice
Ground Mounted Substations Strategy and Practice
Pole Mounted Distribution Substations Strategy and Practice
Tree Trimming Maintenance Strategy and Practice
10 Year Maintenance Expenditure Budget by Activity / Maintenance Type
10 Year Capital Expenditure Budget
10 Year Network Expenditure Forecast (All Categories)
2011/2012 Actual vs Budget Capital Expenditure by Asset and Expenditure Type 2011/2012 Actual vs Budget Maintenance Expenditure by Expenditure Type
2011/2012 SAIDI and SAIFI Reliability Performance (Actual vs Target)
Page
29
31
36
38
39
53
62
68
71
80
87
89
92
107
112
116
127
133
134
135
137
140
141
156
157
158
159
160
161
163
164
167
168
169
169
169
170
170
170
171
171
172
175
178
180
182
183
Page 5 of 193
1.
TERMS OF REFERENCE
1.1
Date Complete and Period Covered
Scanpower’s Asset Management Plan relates to the period 1st April 2013 to 31st March
2023. The plan was completed in March 2013 and approved by Scanpower’s Board of
Directors on 31th March 2013, prior to public disclosure on 1st April 2013. The plan is
reviewed and restated on an annual rolling basis. The next plan will be available by 1st April
2014 and will cover the period 1st April 2014 to 31st March 2024.
1.2
Directors’ Declaration
FORM 2 – CERTIFICATE FOR ASSET MANAGEMENT PLANS
Pursuant to Requirement 11(2)
We, Allan Benbow and Christine Donald, directors of Scanpower Limited certify that, having
made all reasonable enquiry, to the best of our knowledge, the attached asset management
plan of Scanpower Limited prepared for the purposes of requirement 7(1) of the Commerce
Commission’s Electricity Distribution (Information Disclosure) Requirements 2008 complies
with those Requirements.
Allan Benbow
Christine Donald
Dated: 31st March 2013
Page 6 of 193
2.
EXECUTIVE SUMMARY
2.1
Purpose of the Plan
The purpose of this asset management plan is to document the processes, objectives,
systems and performance measures employed by Scanpower Limited in the management of
the company’s electricity distribution network assets. It also aims to document processes
that ensure that Scanpower’s asset management strategy considers customers’ needs in
terms of price and quality as required by the Commerce Act (Electricity Lines Thresholds)
Notice 2003. Specifically, the asset management systems and processes documented
herein, and undertaken in practice, are designed to ensure that:

The network assets meet customers’ electricity supply requirements, both in terms of
quality and cost.

Assets are maintained on a sustainable and long term basis.

Network performance targets are achieved.

Operational and efficiency improvements are achieved over time.
Scanpower is required to produce and disclose this document annually in accordance with
the Electricity Information Disclosure Requirements 2004, the Revised Information
Disclosure Requirements 2006, and the Revised Electricity Distribution (Information
Disclosure) Requirements 2008 published by the Commerce Commission.
2.2
Introduction to Scanpower
The primary business activity of Scanpower Limited is the ownership and operation of
electricity distribution assets. These assets include overhead power lines, underground
cables, transformers, switchgear, voltage regulators and peripheral communications and
load control systems.
The company’s network connects to the national electricity transmission grid operated by
Transpower at two locations (Woodville and Dannevirke substations) and distributes
electricity, on behalf of electricity retailers, to customer installations over a geographic area
of ~2,500 square kilometres in the Southern Hawkes Bay / Northern Tararua region of New
Zealand. The company’s head office is based at Oringi Business Park, Dannevirke.
Scanpower was established during the 1920s and was known at that time as the
“Dannevirke Electric Power Board”. Construction of the company’s distribution assets
commenced at this time and has continued to develop and grow ever since.
Following the Energy Companies Act 1992, the “Dannevirke Electric Power Board” was
corporatised, having operated as a municipal / local body entity for the preceding seventy
years. Scanpower Limited was established with shares being issued to the Scanpower
Customer Trust, a body of five elected trustees who hold the investment in trust on behalf of
the wider community. The beneficiaries of the trust are defined as any consumer connected
to the Scanpower electricity network.
Page 7 of 193
It is of key strategic significance to note that the company’s customers are also its owners
via the trust ownership structure. Customers elect trustees on a triennial basis to represent
their interests and to drive the direction of the company via a Statement of Corporate Intent
(SCI). The SCI is produced annually in consultation between the Board of Directors of
Scanpower Limited and the Trustees of the Scanpower Customer Trust. It details such
things as the scope of the company’s operations and establishes targets in relation to
financial performance, network reliability and network pricing. The annual Statement of
Corporate Intent can be viewed by any interested parties via Scanpower’s website.
Scanpower has a natural monopoly on electricity distribution in the geographic area in which
it operates and therefore, as with the other twenty nine regional distribution companies in
New Zealand, is subject to scrutiny and regulation from the Commerce Commission. Whilst
Scanpower is exempt from certain aspects of this regulation by virtue of its customer-owned
status, it is still obligated to make certain information disclosures relating to matters such as
network pricing, asset management planning documentation, and general technical and
financial disclosures.
Of the twenty nine electricity distribution companies in New Zealand, Scanpower is relatively
small and operates in a predominantly rural area. The following table highlights the scale of
the company’s operations relative to other industry participants.
Table 1 – Scanpower High Level Network Metrics
Measure
Scanpower
Industry Median
Ranking of 29
6,787
28,170
28th
7
9
16th
Energy Density (kWh / ICP)
11,993
15,014
26th
Demand Density (kW / km)
15
28
25th
System Circuit Length (km)
1,039
3,505
26th
$32.9m
$286.5m
27th
Connections (ICPs)
Connection Density (ICPs / km)
Value of System Fixed Assets (ODV)
As is evident from the data above, in physical terms the Scanpower network is amongst the
smallest in the country. In addition to this, both energy and demand density are also
comparatively low.
Since 1992 the electricity distribution sector has seen numerous mergers and acquisitions,
resulting in the number of network companies falling from over fifty to the current twenty
nine, although this kind of activity has tailed off in the past five or so years. Over this time,
whilst a range of options has been considered, the owners of Scanpower have indicated a
strong preference for continued local ownership and representation of customer / owner
interests at a local level. For this reason, both the Trust and Company remain committed to
the current ownership structure and are confident that despite its size, Scanpower can
operate as a stand-alone utility and deliver levels of service and cost that meet or exceed the
expectations of its key stakeholders.
Page 8 of 193
A review undertaken by the Trust in 2011, including a survey of all customers, returned a
98% approval rating for continuation of the existing ownership structure. With this
background in mind, to achieve economies of scale in terms of administration and
overheads, and to provide business growth, since 2000 Scanpower has actively pursued a
strategy of diversifying into new areas of business with some success. In addition to the
core network business, the company is now involved in the following activities:

Industrial scale cold storage

Property development and leasing

Power line contracting

Plumbing and electrical contracting

Supply and installation of solar water heating systems

Meter reading

Tree and vegetation contracting

Manufacturing of knitwear (via a third share in a joint venture company)
For the financial year ending 31 March 2012, approximately 50% of the company’s revenue
was derived from these interests, with the balance coming via the electricity network
business.
The diversity in the portfolio of Scanpower’s business activities is pertinent from a strategic
perspective as correspondingly corporate level strategy has two distinct components:

Corporate level network strategy

Corporate level strategy for unregulated / new business ventures
As this document is concerned with the electricity distribution assets of Scanpower, the
remainder of this discussion of corporate strategy will focus on that relevant to the network
business.
By way of further background to the organisation, the tables below provide a summary of key
network information, financial metrics and other company data.
Page 9 of 193
Table 2 – Scanpower Key Network Data as at 31 March 2012
Measure
Quantity / Details
2,500km2
Geographic area covered
Customer connections (ICPs)
Main centres / townships supplied
6,787
Dannevirke, Woodville, Norsewood, Weber, Ormondville, Kumeroa
Connections to National Grid
2
GXP Locations of grid connections
Dannevirke, Woodville
Maximum coincident system demand
17MW
Electricity volumes carried
87GWh
Length of overhead 11kV lines
843km
Length of underground 11kV cables
11km
Length of overhead low voltage lines
122km
Length of underground low voltage cables
64km
Total system length
1,040km
Installed transformer capacity
65MVA
Average age of system fixed assets
24 years
Average expected life of system assets
52 years
Average age as a % of expected life
46%
% of assets within 10 years of total life
18%
Table 3 – Scanpower Key Financial Data as at 31 March 2012
Measure
Quantity / Details
Total operating revenue
$13,225,000
Network line revenue
$6,737,000
Earnings before interest, customer discounts & tax
$2,437,000
Customer discounts paid
$1,336,000
Total assets
$38,505,000
Shareholders’ equity
$27,543,000
Regulatory value of network assets (DRC)
$33,162,000
Page 10 of 193
Table 4 – Scanpower Key Organisational Data at Present Date
Measure
Quantity / Details
Total staff numbers
83
Office / depot locations
Oringi Business Park, Dannevirke (Head Office)
Gordon Street, Dannevirke (Customer Services)
Feilding (External Contracting Depot)
Paraparaumu (External Contracting Depot)
2.3
Overview of Scanpower’s Asset Management System
Scanpower has developed an asset management system based on the BSI PAS 55: 2008
standard for the management of the electricity distribution assets that constitute its core
business. This standard is considered by Scanpower as ‘best practice’ and a comprehensive
methodology for compliance with the Asset Management Plan (AMP) disclosure
requirements. This document is structured around both the core elements of PAS 55 and
regulatory prescription. A cross-reference between the AMP and the prescription is provided
in Appendix B.
This document is structured with the following core elements:

A description of the asset management system itself including a description of
information systems, the organisation’s structure and capability, and a statement of the
maturity of systems and processes.

Derivation of the asset management objectives, service standards, and KPIs starting
from Scanpower’s corporate level strategic objectives.

A more detailed overview of the network assets, their configuration and the
characteristics of the consumers/load they serve than outlined in the introduction
above.

Detail of the company’s risk management processes and their follow-on down to asset
management practices.

A comprehensive analysis and derivation of the Network Development Plan. This is
essentially the planning activity Scanpower undertakes to ensure its network is
capable of meeting consumer needs and company objectives into the future. It
documents the processes for optimal solution selection and a forecast of resulting
development expenditure.

The details of Scanpower’s asset life cycle management policies, objectives and
practices. This includes the derivation of maintenance strategies, operating practices,
and asset renewal programs. The budgets associated with various work programs are
presented in this section.
Page 11 of 193

2.4
Asset management is a quality management process and as such closes the cycle off
with a review of performance against the plan. This is the final section of the AMP but
it also is an input into the next cycle. For example, it includes an analysis of fault
causes, which is used to identify key performance issues and target associated key
assets.
Asset Management Definition
Asset Management is defined by BSI PAS 55:2008 as:
The systematic and coordinated activities and practices through which an organisation
optimally and sustainably manages its assets and asset systems, their performance, risks
and expenditures over their lifecycles for the purpose of achieving its organisational strategic
plan.
2.5
Organisational Capability
In addition to adopting the PAS 55 standard as the basis of its asset management practices,
Scanpower has also:

Established a NZS 7901: 2008 compliant Public Safety Management System.

Improved coordination of asset management and safety systems with its ISO 31000
risk management processes.

Restructured its staffing and resources to create a Network Division which includes its
own field crews to maintain focus on the core business and prevent distraction from
external contracting activity. Scanpower has also increased the tree cutting resources
available to the community.
2.6
Strategic Overview
Consistent with the PAS55 approach, Scanpower’s asset management policies, strategies,
plans and implementation are driven directly by the organisation’s corporate level strategy.
The details of the over-arching corporate strategy are presented in the strategy map below.
It is this corporate strategy that feeds into the asset management planning process, setting
the high level objectives and expectations of the network business.
By following this process Scanpower aims to ensure that the organisation’s corporate level
strategy, or strategic intent, flows through all asset management activities.
Page 12 of 193
Table 5 – Summary Corporate Strategy Map
Company Vision (What we aspire to achieve)
Delivering more to our community by providing a high quality electricity distribution network and promoting economic growth. Company Mission (Our fundamental purpose)
To provide our region with a reliable, safe, cost‐effective and sustainable electricity distribution network, whilst using our innovation and skills to develop new business and employment opportunities within our local communities. Strategic Objective 1 ‐ To deliver a reliable and safe supply of electricity to our customers
Detailed Objective Target / KPI
To achieve SAIDI and SAIFI results within the top  Use of industry benchmarking studies quartile of industry performance.  SAIDI < 90 customer minutes  SAIFI < 1 customer interruption Maintain supply voltages within regulatory /  Supply voltage maintained within +/‐ 5% appropriate levels. tolerance levels  Number of customer voltage complaints Provide a level of security of supply appropriate to  Appropriate security standards established and various connection groups / sizes maintained Maintaining and replacing assets on a sustainable and  PAS 55 asset management methodology adopted best practice basis  AMP feedback from Commerce Commission review and industry ranking relative to other companies  Planned capital and maintenance activities completed within time and financial budgets  Total asset life cycle management approach adopted Operating a compliant and effective public safety  Scanpower PSMS achieves Telarc certification for management system (PSMS) compliance  Zero harm caused to members of the public Forecasting and responding to load growth with  Capacity exists to accommodate all reasonably network development initiatives that ensure foreseeable growth within appropriate community and customer needs are met into the timeframes whilst maintaining quality standards. future.  Network development adopts lowest cost, effective solutions including consideration of distributed generation and demand side solutions. Strategic Objective 2 ‐ To provide a cost effective supply of electricity to our customers
For Scanpower customers to pay lines charges  Use of industry benchmarking and pricing studies (excluding transmission costs) that having taken into  Distribution revenue per ICP (post discounts) account annual discounts are in the lowest quartile in  Cents per kWH (post discounts) the country when compared to other networks.  Annual cost for 8,000 kWH pa consumer To maintain financial performance in terms of  Use of industry benchmarking and pricing studies operating expenditure that supports this pricing  Operational expenditure per ICP per annum objective and is better than the industry average. Page 13 of 193
Table 5 continued – Summary Corporate Strategy Map
Strategic Objective 3 ‐ To earn a commercially appropriate return on our assets
Achieve a return on investment from our network  Return on Investment (prior to discounts) of assets that is consistent with the expectations of ~7.5% on regulatory asset base value. shareholders and commercially appropriate relative to the industry in which we operate. Strategic Objective 4 ‐ To deliver financial benefits to our community via the network discount
To return a level of financial benefit to the customer  Annual discount payment equal to, or greater shareholders on an annual basis using the network than, $1.5m per annum, equating to $255 each discount mechanism that is consistent with the for typical residential customers. expectations of the Customer Trust. 2.7
Network Development Planning Summary
This section of the asset management plan details the process of assessing the Network’s
future development requirements in order to deliver on Scanpower’s long term business
objectives. It records the asset management strategy and planning component of the Asset
Management Conceptual Model. That is, it is the Network Division’s Strategic Plan as
applied to the assets on which the core business is based. It is referred to as the Network
Development Plan.
The key features of the existing network with regard to its strategic planning environment
are:

The network has no sub-transmission system which means it is capacity and voltage
constrained. While peak load can be managed to these constraints, load growth
results in longer duration of constraints being experienced by consumers.

The network has minimal interconnection capability particularly in the urban LV
networks. No part of the network meets an N-1 security standard.

Some of the more significant differentiators of this network to its peers are; it has very
little single phase distribution and its protection/switching is largely still HV expulsion
fused based. That is, the network is a traditional, predominantly overhead, manually
operated, lineman orientated asset.
In a nutshell, the Development Plan seeks to minimise the amount of traditional line
orientated development associated with the legacy centralised grid connected power supply,
that is becoming increasingly less competitive with the alternative distributed energy systems
approach now being quite rapidly enabled by technology. Scanpower seeks to re-align and
re-optimise its network over the next 10 years for operation in a distributed energy
environment.
More specifically:
Page 14 of 193

Provide and distribute capacity sourced from the grid on a just in time basis. The
investment environment is becoming shorter relative to the longevity and lumpiness of
traditional line asset development.

Avoid investment in transmission and sub-transmission asset (lines solutions) in favour
of Distributed Generation, Smart Grid, etc. (non-line alternative solutions).

Shift its network development towards the consumer end i.e. the LV network and its
interconnection in order to make it ready to receive PV and EV connection in
particular.

Develop its network as a platform from which it can offer distributed generation and
energy brokering services.
The key development projects determined by this planning process are:

Development of 11kV bussing points with indoor switchboards and sub-feeders with
improved interconnection at 4 key locations in the network: Matamau, Dannevirke
North, Dannevirke South, and Oringi.

Application of voltage correction via regulators and/or capacitors at the bussing points
and other optimal locations.

Improving contingent
interconnection.

Targeted security provision via generation embedded at the load.

Improved systems engineering of protection and automation systems.
capacity
through
increased
substation
density
and
This program amounts to approximately $3.5m of expenditure over the next 5 years.
2.8
Summary of Asset Life Cycle Management Approach used by Scanpower
Scanpower does not have a significant population of any specific category of asset that is
considered critical in terms its primary service delivery objectives – keeping the lights on.
The bulk of its asset is an 11kV/400V pole mounted electricity distribution network. The age
and condition related replacement of hardwood poles in this network is the primary focus of
Scanpower’s life cycle management activity. This plan has improved the targeting of
replacements of assets and network segments where condition is driving performance.
Analysis indicates that more attention/pace is warranted on the LV network which has
passed the optimal point for renewal (but does not affect regulatory performance
benchmarking).
The transformer population is approaching its optimal service life and because it is relatively
expensive to renew, it will be pre-emptively replaced via opportunistic renewal policies as
part of other work programmes in order to spread replacement over a wider time period.
Page 15 of 193
Service line condition and the need for its replacement, is an issue that affects Scanpower’s
costs although these are not assets it owns. The industry is still in the process of determining
how it will respond to this issue.
Tree management is currently a significant non-asset but performance driving issue currently
on Scanpower’s network. Forestry outside the regulatory clearances is the main contributor.
Scanpower has established major resourcing capacity to address these issues. Tree
trimming funded by the network is a major component of life cycle costs and this will
continue for several cycles until cost responsibility has been transferred to tree owners.
While the current pole renewal program continues for another 8 years, life cycle
management expenditure will remain reasonably constant at approximately $1.7m p.a.
excluding tree trimming.
2.9
Network Expenditure Forecasts
Total network expenditure for the coming ten year period is summarised in the table below,
and is broken down into Maintenance expenditure, Routine capital expenditure and Network
Development capital expenditure
Table 6 – 10 Year Network Expenditure Forecast (all Categories)
Type 2013 2014 2015 2016 2017 $477,849 $447,852 $447,855 $447,858 $447,861 Routine Capital $1,250,845 $1,250,845 $1,210,000 $1,210,000 $1,210,000 Network Development $1,243,449 $869,194 $592,245 $314,946 $515,947 Total $2,972,143 $2,567,891 $2,250,100 $1,972,804 $2,173,808 Type 2018 2019 2020 2021 2022 $436,314 $436,317 $436,320 $436,323 $436,326 $1,210,000 $1,210,000 $1,132,762 $545,325 $545,325 $89,248 $46,749 $46,750 $131,751 $25,752 $1,735,562 $1,693,066 $1,615,832 $1,113,399 $1,007,403 Maintenance Maintenance Routine Capital Network Development Total The expenditure trends are plotted in the chart below. As is evident, network development
capital expenditure is relatively significant for the first five years of the current planning
horizon (most notably in the years commencing 2013 and 2014) as projects are completed
to ameliorate foreseeable constraints on the network. Thereafter, network development
expenditure tails off. Through to 2020, routine capital expenditure on asset replacement
remains relatively consistent at ~$1.2m per annum. Similarly however, this also tails off
towards the latter end of the planning period, primarily as a result of changing out hardwood
poles on the network.
In terms of maintenance expenditure, it is anticipated that selective technology adoption and
ongoing progress with the tree management programme will produce some degree of
savings over time.
Page 16 of 193
Figure 1 – Graphical Representation of 10 Year Network Expenditure Forecast
Page 17 of 193
3.
THE ASSET MANAGEMENT SYSTEM
3.1
Background to the Asset Management Planning Process
As part of an on-going process to improve the company’s asset management practices, over
the past year Scanpower has decided to adopt the PAS 55 approach to physical asset
management. “PAS 55 – Optimal Management of Physical Assets” is a publicly available
specification issued the British Standards Institution. It provides guidance and a 28 point
requirements checklist of good practices in physical asset management, and is relevant to
industries such as gas, electricity and water utilities, road, air and rail transport systems, and
the natural resources sector.
PAS 55 is now emerging as a de facto, world-wide best practice specification for businesses
seeking to demonstrate a high level of professionalism in whole life cycle management of
their physical assets. It is on this basis that Scanpower has decided to adopt such an
approach, and during the past year both the Chief Executive and Network Manager have
attended PAS 55 training courses endorsed by the UK Institute of Asset Management and
delivered by an approved training organisation, AMCL (Asset Management Consulting
Limited).
The figure below illustrates the conceptual PAS 55 asset management model. As is evident,
the key driver of asset management strategy and planning is the organisational strategic
plans.
Figure 2 – The Asset Management System
Page 18 of 193
It is a key feature of the PAS 55 model that asset management strategy is driven by the
organisational strategic plan. This enables the establishment of a “strategic line of sight” that
is evident at all levels of the organisation, and pervades all asset management activity as per
the conceptual diagram below.
Figure 3 – The Asset Management Hierarchy
3.2
Asset Management Plan Design Compliance
This document has been structured to directly reflect the core elements of the PAS55 Asset
Management Conceptual Model presented above. Scanpower has adopted PAS55 as a
“best practice”. The AMP design is intended to comply with this standard in the first instance
but it also attempts to interpret and align content to display clear intent to meet disclosure
prescription.
It is sectioned with the following core elements:

Asset Management Strategy – detailing the process of deriving asset management
strategy, objectives and policy from corporate strategy and company objectives.

Asset Knowledge – description of assets, information systems, and processes.

Organisational Capability – description of the people enablers, organisational
structure, and the processes for assessing need and developing capability
Page 19 of 193

Asset Performance Objectives and Service Standards – derivation of performance
standards from strategy objectives.

Risk Assessment – detail of the risk management reviews and plans at corporate and
network levels.

Network Development Planning – detail of the planning process and derivation of the
plan for meeting future demand and sustaining delivery on objectives.

Life Cycle Management – detail of maintenance and renewal programs, reliability,
quality and safety improvements.

Evaluation of Performance – review of progress against plan as closure to the asset
management continuous improvement quality circle.
The AMP serves an additional regulatory role of formally disclosing Scanpower’s asset
management capability and performance. The content of this plan is targeted directly at
meeting prescribed disclosure. To demonstrate this and assist readers with identifying
disclosure compliance the follow cross reference table is provided.
Appendix B provides a table cross referencing AMP Disclosure Prescription in the
Commerce Act (Electricity Distribution Disclosure) to the structure of this AMP document
which follows a PAS55 framework.
Page 20 of 193
4.0
ASSET MANAGEMENT STRATEGY
4.1
Scanpower’s Strategic and Asset Management Planning Process
Scanpower operates a rolling ten year, organisational level, strategic planning cycle with
reviews undertaken by the Board of Directors and Executive Management team on an
annual basis. During these reviews, a variety of strategic management techniques are used,
including:

Assessment of current strategy and historical performance.

Internal organisational analysis (strengths and weaknesses).

External organisational analysis (opportunities and threats).

Environmental scanning
environmental).

Stakeholder analysis / customer needs assessment.

Portfolio analysis of the mix of the company’s business activities.

Confirmation / revision of the organisation’s vision and mission.

Confirmation / revision of the organisation’s strategic intent and key goals.

Strategy formulation and selection.

Scenario planning.

Establishment of key performance metrics.

Identification of critical success factors and risks.
(political,
economic,
social,
technological,
legal,
Following the annual review, the ten year strategic plan is summarised in the form of a
document called the Statement of Corporate Intent. This details high level aspects of the
organisational strategy such as:

Company vision, mission and strategic objectives.

The nature and scope of the company’s activities (industries, markets etc).

Capital structure and dividend policies.

Significant accounting policies.

Acquisition / investment procedures.

Key performance indicators and associated targets.
Page 21 of 193
The Statement of Corporate Intent is submitted by the Scanpower Limited Board of Directors
to the Trustees of the Scanpower Customer Trust for comment, amendment and ultimately
approval. It is notable that the Trustees, as advocates of both investor and customer
interests, have the authority of final approval (or otherwise) over the key aspects of
organisational level strategy.
Following approval of the Statement of Corporate Intent, and associated key organisational
level strategic drivers, by the Trustees of the Scanpower Customer Trust, the Executive
Management team has responsibility for preparing business plans aimed at delivering the
strategic objectives of the company. This includes annual tactical plans and budgets. The
Board of Directors approve these plans and budgets, and monitor progress on a monthly
basis.
At the end of each year, company performance against annual business plans and budgets
is reviewed, and this feeds back into the annual review of the ten year strategic plan. A
diagrammatic representation of the overall planning process is provided below.
Figure 4 – Scanpower Business Planning Process
The table below summarises the key components of the overall business planning process
with details of the review frequency.
Page 22 of 193
Table 7 – Business Planning Document Summary
Planning Document
Planning Horizon
Review Frequency
Organisational Strategic Plan
10 years
Annual
Asset Management Plan
10 years
Annual
various – typically 5 years
Annual
3 years
Annual
1 year
Monthly
Non-Network Division Strategic Plans
Statement of Corporate Intent
Divisional Business Plans & Budgets
4.2
Stakeholder Analysis and the Commercial Environment
As the conceptual diagram of the PAS 55 on page 8 illustrates, key inputs / drivers of the
organisational strategy setting process are:

Customer requirements.

Legislative requirements (including regulatory factors).

Investor requirements.

Influencing factors from the external commercial environment
Customers, investors and legislators / regulators are stakeholders in Scanpower Limited
whose requirements can be examined using a stakeholder analysis process. The influence
of the broader commercial environment is best analysed using strategic management tools
such as PESTLE (political, economic, social, technological, legal, environment) analysis,
scenario planning and observation of general electricity related trends.
To identify the range of key stakeholders in Scanpower Limited, the company has
considered questions such as:

Who are the purchasers of the company’s services?

With whom does the company have a contractual relationship?

Who owns the company?

To whom does the company have a contractual, ethical or social obligation?

To whom does the company have a statutory or regulatory reporting obligation?

Where are the company’s assets located?
Page 23 of 193

Who may directly or indirectly come into contact with the company’s assets?

Who are the company’s key suppliers, contractors and customers?

Which customers / agencies rely most heavily on the company’s services?

What regulatory / industry bodies does the company interact with?

To whom does the company have a safety management obligation?

What key pieces legislation is the company bound to adhere to?
A review of the key stakeholders in Scanpower’s electricity distribution business identified
the groups illustrated in the diagram below.
Figure 5 – Scanpower Stakeholder Analysis
Having identified these stakeholder groups it is necessary to ascertain the particular
interests of each, and consider these in the strategy formulation process. These are
summarised as follows:
Page 24 of 193
Table 8 – Summary of Stakeholder Interests
Stakeholder
Nature of Interest / Desired Outcomes

A reliable supply of electricity with few or no interruptions.

A quality supply of electricity in terms of stable voltage and availability
of hot water (where electric).
Customers

A safe supply of electricity.
Connected Electricity Consumers
& Consumer Advocacy Groups

Timely response to service requests / issues / enquiries.

Competitive level of network charges relative to others.

Receipt of a meaningful annual network discount payment.

Readily available information on network matters.

Ease of access to the network in contractual terms.

Network charges are clear and understood.

Information requests responded to in a timely manner.

Line losses are minimised to the extent possible.

Network billing is timely, accurate and compliant.

Compliance with regulatory information disclosure and reporting
requirements.

Legislative requirements are understood and adhered to.
EGCC

A general expectation of improving performance over time.
Legislature

Expectation of participation in industry consultation processes.

Value of investment in Scanpower Limited is protected and growing
over time.

Shareholders receive a meaningful annual return via the network
discount mechanism.

Scanpower performs to the targets set by the Trust in the annual
Statement of Corporate Intent.
Investors

Scanpower Customer Trust &
Connected Customer
Shareholders / Trust
Beneficiaries
Material business risks are identified and mitigated over the long term,
in particular technology / obsolescence risk.

Scanpower exhibits responsible corporate behaviours and governance
practices.

Assets are maintained on an appropriate and sustainable basis over
time.

Regular reporting on performance and communication with the
company.

Ownership and control are retained locally.

Scanpower generally outperforms industry norms in key areas.
Customers
Electricity Retailers
Regulatory Bodies
Commerce Commission
Electricity Authority
Page 25 of 193
Table 8 continued – Summary of Stakeholder Interests
Stakeholder
Nature of Interest / Desired Outcomes

A healthy and safe working environment.

Training and development opportunities.
Other Stakeholders

Fair levels of remuneration.
Employees

Appropriate equipment and tools provided.

Absence of undue work related stress.

Scanpower is resourced at an appropriate level.

Personal safety as it relates to electricity assets.

Effective emergency response procedures are functioning.

Scanpower is easy to contact / interact with.

Aesthetic impact of electricity assets is minimised, within reasonable
cost boundaries.

Land access rights are respected and procedures observed.
Other Stakeholders

Easement rights are documented appropriately.
Land and Tree Owners

Tree regulations are communicated clearly and understood.

Tree related processes and work practices comply with regulations.

As a utility operator, Scanpower participates in regional civil defence
and emergency preparedness planning.

Scanpower has appropriate disaster recovery and business continuity
plans in place.

Documentation such as outage planning and asset management plans
are readily available.
Other Stakeholders

District and regional council plans are complied with.
Regional Authorities

Cooperation with other utilities (water, roading etc).
Other Stakeholders
General Public
Other Stakeholders
Disaster Recovery Agencies /
Emergency Services
Whilst no formal weighting has been attributed to each of the stakeholder groups, the
customer shareholders must rank highly as both the owners of the company and the
purchasers of its services. From this perspective, the key needs arising from this analysis
are therefore:

A high quality, reliable supply of electricity

A competitive service in terms of pricing and underlying cost structures

A safe supply of electricity

Responsive service and ease of access for interacting with the company
Page 26 of 193
In terms of the investor stakeholders, the Trustees of the Scanpower Customer Trust, the
key needs arising are:

The value of the investment in Scanpower Limited is protected and grown over the
long term.

The investment achieves an appropriate rate of return and the relationship between
network pricing and annual customer discounts is balanced in a way acceptable to the
Trust.
These factors, and other issues arising from the above analysis, are taken forward into the
strategy formulation stage documented below.
4.3
Corporate Level Strategy Formulation
Having taken into account the key needs arising from the stakeholder analysis, the explicitly
stated details of Scanpower’s corporate level strategy (as approved by both the Scanpower
Limited Board of Directors and the Trustees of the Scanpower Customer Trust) are detailed
below.
4.3.1
Company Vision
At the top of the strategic hierarchy is the company vision statement; this is intended to
encapsulate the type of organisation that Scanpower aspires to be and how it wishes to be
seen. Scanpower’s vision statement is as follows:
“Delivering more to our community by providing a high quality electricity distribution
network and promoting economic growth”
4.3.2
Company Mission
The company vision is followed by its mission statement. This intended to be a more explicit
statement of the company’s fundamental purpose and its high level objectives. Scanpower’s
mission statement is as follows:
“To provide our region with a reliable, safe, cost-effective and sustainable electricity
distribution network, whilst using our innovation and skills to develop new business
and employment opportunities within our local communities”
4.3.3
Company Strategy
The corporate level strategy cascades down further into a more explicit set of high level
organisational goals / strategic objectives. These are detailed below:
1.
To deliver a reliable and safe supply of electricity to our customers.
2.
To provide a cost effective supply of electricity to our customers.
Page 27 of 193
3.
To earn a commercially appropriate rate of return on our assets.
4.
To generate additional earnings from other commercial activities.
5.
To deliver financial benefits to our community via the network discount.
6.
To add value to our region through our operating practices and community
initiatives.
4.3.3
Company Strategic Objectives
Clearly it is necessary to take each of these strategies and both clarify and quantify (where
possible) what the specific terms mean and what constitutes success in achieving them. For
example, in the case of the first strategy relating to reliability and safety of supply, this can
be broken down further into the following constituent detailed objectives:

Achieving a network reliability performance in terms of SAIDI and SAIFI that is
consistently within the top quartile of industry performance when ranked against other
lines companies.

Maintaining supply voltages that are within regulatory / appropriate levels throughout
the network.

Providing a level of security of supply that is appropriate to connection groups on the
network.

Maintaining and replacing assets on a sustainable and best practice basis.

Operating a compliant and effective public safety management system.

Forecasting and responding to load growth with network development initiatives that
ensure community and customer needs are met into the future.
By expanding each of the strategies into a set of objectives in this manner, and attributing
performance measurement criteria or key performance indicators to each, it is possible to
present the consolidated corporate level strategy as per the “strategy map” provided as
Table 9 below.
It should be noted that for the purposes of this asset management plan, strategies (4) and
(6) which relate to development of other business opportunities and community initiatives
have been omitted. This is on the basis that they relate primarily to Scanpower’s nonregulated / non-network business activities and therefore are of limited relevance to this
document.
The network related strategies are further developed into specific asset management
objectives with associated performance standards in the following section of this document.
Page 28 of 193
Table 9 – Summary Corporate Strategy Map
Company Vision (What we aspire to achieve)
Delivering more to our community by providing a high quality electricity distribution network and promoting economic growth. Company Mission (Our fundamental purpose)
To provide our region with a reliable, safe, cost‐effective and sustainable electricity distribution network, whilst using our innovation and skills to develop new business and employment opportunities within our local communities. Strategic Objective 1 ‐ To deliver a reliable and safe supply of electricity to our customers
To achieve SAIDI and SAIFI results within the top  Use of industry benchmarking studies quartile of industry performance.  SAIDI < 90 customer minutes  SAIFI < 1 customer interruption Maintain supply voltages within regulatory /  Supply voltage maintained within +/‐ 5% appropriate levels. tolerance levels  Number of customer voltage complaints Provide a level of security of supply appropriate to  Appropriate security standards established and various connection groups / sizes maintained Maintaining and replacing assets on a sustainable and  PAS 55 asset management methodology adopted best practice basis  AMP feedback from Commerce Commission review and industry ranking relative to other companies  Planned capital and maintenance activities completed within time and financial budgets  Total asset life cycle management approach adopted Operating a compliant and effective public safety  Scanpower PSMS achieves Telarc certification for management system (PSMS) compliance  Zero harm caused to members of the public Forecasting and responding to load growth with  Capacity exists to accommodate all reasonably network development initiatives that ensure foreseeable growth within appropriate community and customer needs are met into the timeframes whilst maintaining quality standards. future.  Network development adopts lowest cost, effective solutions including consideration of distributed generation and demand side solutions. Strategic Objective 2 ‐ To provide a cost effective supply of electricity to our customers
For Scanpower customers to pay lines charges  Use of industry benchmarking and pricing studies (excluding transmission costs) that having taken into  Distribution revenue per ICP (post discounts) account annual discounts are in the lowest quartile in  Cents per kWH (post discounts) the country when compared to other networks.  Annual cost for 8,000 kWH pa consumer To maintain financial performance in terms of
 Use of industry benchmarking and pricing studies operating expenditure that supports this pricing  Operational expenditure per ICP per annum objective and is better than the industry average. Page 29 of 193
Table 9 continued – Summary Corporate Strategy Map
Strategic Objective 3 ‐ To earn a commercially appropriate return on our assets
Achieve a return on investment from our network  Return on Investment (prior to discounts) of assets that is consistent with the expectations of ~7.5% on regulatory asset base value. shareholders and commercially appropriate relative to the industry in which we operate. Strategic Objective 5 ‐ To deliver financial benefits to our community via the network discount
To return a level of financial benefit to the customer  Annual discount payment equal to, or greater shareholders on an annual basis using the network than, $1.5m per annum, equating to $255 each discount mechanism that is consistent with the for typical residential customers. expectations of the Customer Trust. It is this corporate strategy that feeds into the asset management planning process, setting
the high level objectives and expectations of the network business. The next stage is to take
this high level strategy and translate it into appropriate:

Asset management policies

Asset management strategies

Asset management objectives

Asset management plans
By following this process Scanpower aims to ensure that the organisation’s corporate level
strategy, or strategic intent, flows through all asset management activities. This is covered
in the next section of this document.
Page 30 of 193
5.0
PERFORMANCE OBJECTIVES AND SERVICE STANDARDS
This section of the AMP describes the service and performance targets for the strategic
objectives set for Scanpower’s electricity lines business that are directly relevant to the
management of the Network Division’s assets.
There are four strategic business objectives derived in Section 4 of this Plan. Three are
financial objectives and therefore not directly related to the management of physical assets
deployed in the field. However, they are all influenced by the cost efficiency with which
assets are managed over their life cycle and are dependent on the sustainability issues
associated with continual development of the network to ensure the asset base itself is fit for
purpose and efficient.
The primary strategic objective related directly to the physical assets and their service
delivery is:
“To deliver a reliable and safe supply of electricity to our customers”
5.1
Asset Management Objectives
The subordinate asset management objectives associated with this business unit level
objective are summarised in the table below. Also included in each case is the justification
for each subordinate objective, a description of the associated asset management policies
and targets / key performance indicators.
It should be noted that targets applied at the planning stage are leading KPIs. Monitoring of
subsequent outcomes is a lagging KPI.
Table 10 – Asset Management Objectives and Policies
Asset Management Objective To achieve SAIDI and SAIFI results in the top quartile of industry performance
JUSTIFICATION  These metrics are primary measures by which consumers can compare service with other companies and countries. ASSET MANAGEMENT POLICIES  To constrain all outages to under 6500 CML (customer minutes lost ‐ equating to 1 SAIDI minute), through application of work practice innovation and technology deployment where justified.  Security and reliability initiatives will be tested against an assessment of the Value of Lost Load (VoLL). PERFORMANCE TARGETS / KPIs  Achieve upper quartile performance per industry benchmarking studies.  SAIDI < 90 customer minutes.  SAIFI < 1 customer interruption. Page 31 of 193
Table 10 continued – Asset Management Objectives and Policies
Asset Management Objective To maintain supply voltages within regulatory and appropriate quality levels
JUSTIFICATION  The network is becoming constrained and modern power electronics in consumers installations is affecting power quality so more active monitoring and management is desirable. ASSET MANAGEMENT POLICIES  To maximise acceptable 11kV input voltage able to be delivered via Transpower’s voltage control equipment at GXPs – Scanpower has none of its own.  To utilise and develop Load Management Systems, Special Protection Schemes, and DSM (demand side management).  To require consumers to meet PFC, harmonic, and service line volt drop standards.  To minimise conductor upgrade and new line construction in favour of voltage control and DG. PERFORMANCE TARGETS / KPIs  Supply voltage maintained within +/‐ 5% tolerance levels at the consumers POS (point of supply).  Number of customer voltage complaints. Asset Management Objective To provide a level of security of supply appropriate to various customer connection groups / sizes
JUSTIFICATION  Standards need to be meaningful to end users if they are to add value. This is primarily considered an issue of competiveness for local business.  NOTE: Industry standards are based on load densities higher than those that bear any relevance to Scanpower’s load densities. That is, there is no part of Scanpower’s network that can justify N‐1 security on the basis of load density. Consequently Scanpower has re‐defined its standard on the basis economic impact such as CML which provides drivers for improving response times and establishing contingency provisions. ASSET MANAGEMENT POLICIES  To address security and contingency provisions for large users on a case by case basis.  To develop LV interconnection in urban areas and contingent transformer and cable capacity.  To increase the sectionalising capability into smaller network segments to achieve parity with other networks. PERFORMANCE TARGETS / KPIs  Appropriate security standards established and maintained. Page 32 of 193
Asset Management Objective To maintain and replace assets on a sustainable and best practice basis
JUSTIFICATION  This objective is fundamental to the on‐going viability of Scanpower’s core business. ASSET MANAGEMENT POLICIES  PAS 55 asset management methodology adopted.  Total asset life cycle management approach adopted. PERFORMANCE TARGETS / KPIs  AMP feedback from Commerce Commission review and industry ranking relative to other companies.  Planned capital and maintenance activities completed within time and financial budgets. Asset Management Objective To operate a compliant and effective public safety management system (PSMS)
JUSTIFICATION  This is a relatively new regulatory requirement which needs continued focus until systems have been adequately proven effective and the routine continuous improvement process adequate. ASSET MANAGEMENT POLICIES  To be integrated with the workplace OSH SMS. PERFORMANCE TARGETS / KPIs  Scanpower PSMS achieves Telarc certification for compliance.  Zero harm caused to members of the public.  The PSMS has additional targets and KPI’s by virtue of the fact it is a TQM system in its own right. Asset Management Objective To forecast and respond to load growth with network development initiatives
JUSTIFICATION  The design limitations of 11kV distribution is on the horizon. In addition technology risk threatens the competitiveness of core grid supply. Economic conditions are volatile. The pace of change in the strategic environment exceeds the life‐cycle of traditional line solutions. Higher planning vigilance is needed to ensure the customer needs are met when they need them. ASSET MANAGEMENT POLICIES  Formalise planning via the Network Development Plan (NDP) and include directors in the review process.  Present detail in the AMP to establish the opportunity for public scrutiny and input .  Annually review NDP to ensure projections align with experience.  Establish load growth trigger points for initiating developments that require lead times exceeding 12 months.  Maintain excess capacity to for new load, switching contingencies and development headroom. Page 33 of 193
PERFORMANCE TARGETS / KPIs  Capacity exists to accommodate all reasonably foreseeable growth within appropriate timeframes whilst maintaining quality standards.  Network development adopts lowest cost, effective solutions including consideration of distributed generation and demand side solutions. Demonstrated for capital expenditure sanctions. Page 34 of 193
6.0
ASSET KNOWLEDGE SET
6.1
Service Area
Scanpower’s supply area of 2,000km2 is the area broadly bounded by the Manawatu River
to the North, and again to the South, whilst stretching to the Ruahine Ranges to the West
and to Wimbledon in East. This area can be described as the Northern half of the Tararua
District, and includes the towns of Dannevirke, Woodville, and the settlements of
Norsewood, Ormondville and Kumeroa.
Figure 6 – Scanpower Area of Supply
Total connections number 6,789 and for the year ended March 2011 88 GWh was injected
into the network with an overall average loss factor of 6.8%. Population numbers in the
Tararua District have shown a slowly declining trend in recent years.1 Furthermore the
projected population is forecast to follow a similar trend, reducing by 2% through to 2016.
Contrary to this trend however, ICP numbers have increased over past years from 6,692 in
2007 to 6,789 as at March 2011, a rise of 1.5%. This increase has come from a continuing
high level of dairy conversions in the region in addition to several new residential
subdivisions. Change in land use, the associated shift in load centres and changing peaking
and diversity results in constraints on feeders and specific network locations without
necessarily being visible in system demand profiles or revenue/energy volume growth.
1
Source: Statistics NZ: http://www.stats.govt.nz/products-and-services/hot-off-the-press/subnational-populationestimates/subnational-population-estimates-jun06-hotp.htm?page=para016Master
Page 35 of 193
A single new load, of say 70kVA, may not be large in terms of national averages, but added
to a 1.5MVA load represents 5% of its of its peak and can be 35% of the local distribution
transformer and LV network. Adding a larger customer of say 300kVA can result in wide
ranging upgrade requirements.
6.2
Large Customers
The Scanpower network area is predominantly rural and hence the economy is largely
based on agricultural activities, such as sheep and beef farming. Dairying and forestry are
other viable local land uses.
On an annual basis, 22.03% of total electricity distributed is used by the six largest industrial
/ commercial customers. These are:

One meat processing/freezing works (Alliance, Dannevirke)

A large scale cold storage business (Oringi Cold Stores, Dannevirke)

A timber mill (Kiwi Lumber, Dannevirke)

A textiles yarn and dye plant (Godfrey Hirst, Dannevirke)

One supermarket (New World, Dannevirke)

Kordia (a regional broadcasting repeater site)
The electricity consumption and maximum demands associated with these sites (for the
twelve months to March 2011) were as follows:
Table 11 – Scanpower Major Customer Details
Customer
Consumption
GWh
GWh % of Total
Peak Demand
MVA
Peak Demand %
of Annual Peak
Alliance Freezing Works
6.1
6.93%
1.36
8.6%
Godfrey Hirst Carpets
3.0
3.41%
0.75
4.7%
Kiwi Lumber Mill
2.8
3.12%
1.00
6.3%
Kordia
2.8
3.12%
0.35
2.2%
Oringi Cold Stores
3.7
4.20%
0.64
4.0%
New World Supermarket
1.1
1.25%
0.18
1.1%
19.5
22.03%
4.28
26.9%
TOTAL
The next tranche of customers (in terms of size) below these are relatively small (including
KFC, McDonalds, local swimming pool, etc.).
Page 36 of 193
The closure of Alliance Freezing Works, Godfrey Hirst, Kiwi Lumber, Oringi Cold Stores or
the New World would have less of an impact on asset management priorities for the
planning period covered by this plan than any one of them increasing their load by a
relatively modest amount.
Loss of load may result in some plans being deferred for a few years but with no subtransmission the risk of stranding assets is low. Excess capacity in the 11kV network is kept
at a more conservative level because it is able to be developed relatively quickly. The risk of
new load appearing more quickly than planned or at a higher demand than assumed is that
some plans will need to be bought forward and this creates a peak in demand for financial
resources and organisational capacity. This is because the sites are either on the
Dannevirke town mesh (Alliance, Godfrey Hirst, New World) or on feeder sections that are
currently in good condition (Kiwi Lumber, Oringi Cold Stores, Kordia).
In general, at Scanpower’s scale of operation, the impact of the closure of one or more of the
six largest sites would be financial (due to lost revenue). At this point, the company would
face the decision of either accepting lower profits / returns, or increasing prices across the
remaining customers to ensure that status quo financial objectives are met.
6.3
Load Characteristics
The graph below illustrates the consolidated load profile characteristics for the Dannevirke
and Woodville points of supply (summer and winter weekdays), these being the two key
parts of the network.
As can be seen from the load profile curves, day time load is reasonably constant in both the
Dannevirke and Woodville areas, and significant load displacement would be necessary to
reduce the peaks. The curves already reflect Scanpower’s existing load control protocols
(primarily to water heating load) and therefore without impacting adversely on the quality of
service provided to customers, there is limited potential to achieve further load displacement
benefits.
The network is winter peaking but dairy and irrigation loads are capable of catching this
peak; particularly in dry years.
Page 37 of 193
Figure 7 – Scanpower Load Profile Curves (Dannevirke and Woodville Points of Supply)
6.4
Energy Supplied and Demand
The following table summarises the key details of each of Scanpower’s 11kV feeders
supplied by Transpower CBs at the Dannevirke GXP:
Table 12 – Dannevirke Feeder Data
Feeder Name
kWh pa
Description
Rating
Max
Load
Pacific
6,855,332
Rural feeder, mainly servicing industrial load
4.4MW
1.4MW
Weber
9,836,839
Long Rural feeder servicing eastern extremity
4.4MW
2.0MW
Adelaide Rd
9,342,636
Urban feeder into Dannevirke
4.4MW
2.8MW
14,723,894
4.4MW
2.3MW
Central
9,802,961
4.4MW
3.1MW
Mangatera
9,980,728
Rural area feeder supplying Ormondville
4.4MW
1.9MW
Te Rehunga
4,031,379
Southern rural area feeder
4.4MW
1.1MW
North
7,792,784
Rural area feeder supplying Norsewood
4.4MW
1.9MW
East
Three 11 kV feeders radiate from the Woodville point of supply.
summarises the key details of each of these:
The following table
Page 38 of 193
Table 13 – Woodville Feeder Data
Feeder Name
kWh pa
Description
Rating
Max Load
Town 1
4,920,112
Urban feeder into Woodville / Eastern rural area
5.0MW
1.1MW
Town 2
4,424,594
Urban feeder into Woodville/Western rural area
5.0MW
1.1MW
Country
3,316,656
Rural feeder to north of Woodville
5.0MW
0.9MW
Figure 8 below provides the typical daily consumption profiles for the Dannevirke and
Woodville points of supply across both winter and summer periods.
Figure 8 – Typical Daily Consumption Profile (Dannevirke and Woodville – Summer / Winter)
Daily peaks are created by morning and evening residential load. The morning peak is larger
because there is less diversity in its start-up and it is coincident with commercial and retail
activity.
Figure 9 below provides a snapshot, as at 5 March 2013, of the daily consumption profile by
feeder.
Page 39 of 193
Figure 9 – Consumption by Feeder as at 5 March 2013
Feeders with dairy load display very peaky load profiles at milking times. These feeders lack
load diversity which limits load control options.
6.5
Network Configuration
6.5.1
Grid Exit Points
Scanpower’s network serves two main urban areas; Dannevirke and Woodville, and the
surrounding rural areas. Bulk supply is taken from Transpower’s 110kV Bunnythorpe /
Fernhill lines via 110/11kV substations at Dannevirke and Woodville. The Dannevirke
Transpower point of supply is approximately 6km SW of the Dannevirke and has parallel
110/11kV 20 MVA transformers, giving a firm supply of 20 MVA compared with a maximum
demand of 14 MW. Circuit breakers are remotely switched from Transpower’s Regional
Control Centre. Eight 11 kV feeders radiate from the Dannevirke point of supply.The
transformer windings have tapping provisions to allow them to be reconnected as 110/33kV
units should a significant load appear that requires sub-transmission support.
Woodville’s Transpower point of supply is 3km west of Woodville and has parallel 110/11kV
10MVA transformers, giving an N-1supply of 10 MVA compared with a maximum demand of
3 MW. Woodville is also the generation injection point for the Te Apiti Wind farm and
switching node in the regional 110kV network. Details of energy flow in grid under various
generation and contingency scenarios are described in Transpower’s Annual Planning
Report.
Page 40 of 193
Figure 10 – National Grid Configuration (Central North Island)
6.5.2
Sub-transmission
The Scanpower network has no 33kV sub transmission system. Its distribution lines operate
at 11kV and 230/400V. The company has no zone substation assets.
There is no N-1 security provision on any part of Scanpower’s network beyond the
Transpower POS transformers.
Without sub-transmission Scanpower’s network is limited to feeder loads in the order of 23MW maximum. The thermal rating of Dog conductor is 4.4MW but the distance of load from
the POS limits load due to voltage constraints. Consequently, any major new load exceeding
these limits will need dedicated 11kV feeders to be developed back to the GXP with
additional 11kV CBs provided by Transpower. Planning for such new load would therefore
necessarily involve Transpower and be subject to their grid upgrade processes and time
lines.
6.5.3
Distribution 11kV Overhead and Underground Lines
Scanpower’s core assets constitute an electricity distribution network of predominantly
overhead/pole mounted 11kV lines/assets with historic maximum demand in the range of 15
- 16MW and a total system length of 1,038 kilometres.
The following map illustrates the geographic layout of the network.
Page 41 of 193
Figure 11 – Scanpower Geographic Lay Out of 11kV Distribution Lines
Scanpower is ~50% through a life cycle renewal of the original hardwood pole population
with concrete pole replacements. This program will continue for another 10 years before
softwood poles will be targeted. It standardises on Dog, Ferret, and Gopher ACSWR
conductor but will continue to have a significant amount of copper and steel conductor types
remaining over the term of this plan.
One of the less typical features of Scanpower’s network is that it has very little single phase
network and it has been historical practice to connect loads predominantly as 3 phase
supplies in the rural areas. Consequently, it has a lot of very small 3 phase rural loads that
cannot be rationalised to single phase installations without equipment upgrades and/or
service line upgrades. This practice is the result of a need to minimise conductor size and
capacity for economic reasons. It has a down-side in terms of efficient transformer utilisation.
The economics of remote supply is shifting away from grid supply with the decline in the cost
of alternatives. The new balance point will be determined by consumers as they
renew/upgrade/modernise their installations.
Page 42 of 193
6.5.4
Transformers
As at 31st March 2012 Scanpower has a distribution transformer population of 1,373 units
(excluding spares) ranging from 2kVA to 1,000kVA capacity. At that date the total installed
capacity was 65 MVA with a capacity utilisation rating of 24.6%. The transformers are all
standard oil immersed 11kV/400V units, with the majority (1053) rated at 30kVA or less.
Urban areas are supplied by larger transformers feeding LV reticulation. Distribution subs
are typically ground mounted with a 200-300kVA transformer in a kiosk of various designs.
Transformer HV pole-mounted fusing is usually provided at the point of connection to the HV
network. There is only one 11kV ring main unit on Scanpower’s street distribution network
reflecting the fact that there is very little interconnection of the underground HV cable
network – interconnection and switching is achieved via the overhead network.
Rural areas have predominantly pole mounted transformers which supply a more limited
group of ICP’s given the distance limitations of LV reticulation. Very few transformers in the
rural area are over 100kVA.
There is a set of voltage regulators on the North feeder at Matamau. In accordance with the
Network Development Plan (refer later for more detail) these are in the process of being
upgraded to larger units with a balanced 3 phase configuration. These larger units were
recovered from the Pacific feeder where they are no longer needed since the Oringi Meat
Works ceased operations.
6.5.5
Low Voltage System Overhead / Underground
The 400V network system consists of 185.7 km of lines, 63.4 km of which have now been
installed underground.
All customers on the network take supply at 400V with the exception of two (Oringi Cool
Stores and Kiwi Lumber) which take supply at 11kV.
There is a very low level of LV interconnection and consequently very little excess or
contingent capacity has been designed into the LV network. It is now policy and practice to
improve interconnection and cable capacity by installing intermediate substation sites as
transformer and cable capacities become constrained. Without LV interconnection, faults on
transformers and HV feeder cables result in high CML (Customer Minutes Lost) figures while
repairs are undertaken.
Scanpower has a relatively high number of ICPs per transformer in urban residential areas.
Consumption per ICP is low and actual ADMD (After Diversity Maximum Demand) is below
1kW indicating that diversity and load factor at system level is high. This is considered to be
largely the result of gas and wood fuel penetration into the domestic hot water and space
heating market.
It is viable for residential installations to fully meet their relatively low daily electricity
consumption from PV (Photo Voltaic) installation.
Page 43 of 193
The peaky nature of this generation and the extent of its non-availability at night and low
performance during winter, presents a load management issue as it will unbalance the
existing capacity provision relative to load diversity. It is likely that Scanpower will need to
introduce energy storage capability into the LV network should PV uptake become wide
spread. Viable solutions for storage are currently new to the market and quite limited.
The company no longer pursues a policy of undergrounding in the urban Dannevirke and
Woodville areas. This policy was abandoned as rising costs and reduced cooperation from
other utilities reduced the viability of the work. Some undergrounding continues as
opportunity presents and circumstances make good practice with regard to long term
outcomes.
6.5.6
Distribution Equipment
A legacy feature of Scanpower’s network that differentiates it from an operational
perspective is that it has retained its HV branch and group fusing and it uses its fusing as its
primary means of switching and isolating. It has been late to take up distribution automation
and supersede HV fusing with recloser and sectionalising equipment. It has not yet achieved
optimal configuration at a system level and the density of isolation equipment for
sectionalising the network into small segments is not as developed as its peers.
Consequently it has a low density of ABSs. These are limited to locations where 3 phase
load breaking is desirable.
There are 18 Electropar automated load break rated ABSs on the network. These are
proving unacceptably unreliable and are to be changed with better performing technology as
the network’s system automation is developed.
These issues have been analysed and an Automation and Protection Development Project
is an output of this Plan. Scanpower’s preferred solution is the enhance branch and group
fusing via the deployment of Fuse Saver technology new to the market in 2012. Fuse Savers
are placed in series with expulsion fuses and function as a one shot sectionaliser, able to
clear transient faults before the fuse operates thus reducing the number of trippings caused
by things other than network asset failure.
6.5.7 Secondary Assets
Scanpower installed and commissioned its own private radio network during 2005/06.
Vehicle radio communication operates via VHF mobiles and SCADA/Ripple communication
is via UHF radio links. In 2012 it developed a new repeater at Ahiweka to improve coverage
issues east of the Puketoi ranges and it has retained the Poupouatua repeater which better
serves town and the valley between the Ruahine and Puketoi ranges.
The standard life for this equipment is 15 years indicating that its replacement will be
required within the forecast period of this plan. However, it is likely to reach technical
obsolescence before age becomes an issue and therefore it is not known what it might be
replaced with or what this will likely cost. The communication platform of smart metering
(owned by others), for example, may provide an alternative to running a private radio
system.
Page 44 of 193
In 2006 Scanpower installed and commissioned a new 283Hz Enermet ripple injection plant
at the Dannevirke substation to replace the existing Zellweger static plant. Correspondingly,
all ripple relay receivers at customer premises have now been upgraded to operate from this
new system.
In 2010 the existing plant at Woodville was replaced with a new 283 Hz and all relays
changed. This project was undertaken in conjunction with a major upgrade of the GXP
substation by Transpower.
The SCADA system is used to operate and monitor equipment on the network including
circuit breakers, sectionalisers and remote control switches. The system provides real time
load data and fault status information. It is also used for receiving data from Transpower’s
feeder circuit breakers at the Dannevirke and Woodville substations. At present Scanpower
is not able to operate the breakers remotely via the SCADA system, but this can be done by
Transpower on request.
6.5.8
Non Works
Scanpower operates HV service lines as an integral component of the distribution network
and meets obligations as an operator for these assets but not as the asset owner. It
acknowledges that it is not the owner of these assets and they do not form part of its
regulatory defined “works”. The regulatory responsibilities and associated rights applied to
works do not extend to service lines. Specifically:




Access and land use.
Public safety
Tree management
Compliance
Scanpower adopts a ‘notify and make safe’ policy with regard to any non-compliance it
discovers during the course of its operations. It does not undertake enforcement duties on
behalf of the regulator. Scanpower incurs cost operating service line assets, for example
responding to faults, but it does so on a discretionary basis and ‘average-costs’ these
services into its larger asset base.
6.5.9
Other Assets
Street Lighting
Scanpower owns the street lighting network that is embedded into its infrastructure with
exclusion of the light fittings and dedicated street light columns. It also owns and operates
the control equipment. All costs and maintenance associated with fittings and columns are
undertaken by an external contractor for TDC. These contractors (and Chorus contractors)
therefore access network assets.
Policy with regard to cost sharing during undergrounding projects is ad hoc. In a Scanpower
initiated project it may opt to install street light cables and columns in exchange for footpath
reinstatements.
Page 45 of 193
Oringi
Scanpower owns and operates the Ex-Oringi Meat Processing Plant as an industrial park. It
has inherited the 11kV and 400V distribution associated with that site. This includes an 11kV
switchboard of GEC oil filled CB’s which it plans to reconfigure as a bussing point feeding
out to the surrounding rural network. There is sizeable refrigeration and water supply
pumping assets owned by Scanpower at this site.
Land
With no zone sub-stations the majority of Scanpower’s assets are located within road
reserve or on land with use rights established under the Public Works Act. There has not
been significant new network built on private land since this time. Scanpower does not
require easements for new supplies for individual customers and it does not assert land use
rights on their behalf. It does not claim ownership of service line assets and/or require their
gifting to the network.
Tree Cutting Plant and Equipment
The district lacks resources for tree cutting services. This has created some challenges for
Scanpower and tree owners with regard to managing trees clear of lines for both safety
purposes and outage performance objectives. Consequently Scanpower has made a
significant investment in plant to support a tree service business it operates called
Treesmart. The Network has a direct role in the use and funding of this asset.
Live Line Plant and Equipment
Scanpower has a significant investment in Glove Barrier and Hot Stick “live lining” plant and
equipment. This shared by both the field staff of its network crews and external HV
contracting crews. The Live Line crew itself is drawn from both divisions and the costs, such
as training, are shared. The Network requires this capability to meet its performance targets
therefore it has a direct role in the use and funding of this asset.
Mobile Supply Equipment
Scanpower currently does not own and operate any mobile substations or standby
generation.
6.5.10 Other Generation
There is currently no significant generation on the system, just one small microgeneration
scheme (capacity not exceeding 10kW).
Scanpower itself has an 11kW PV array on its offices but these are embedded behind its
network connection and of insufficient size to ever inject back onto the network.
Page 46 of 193
6.6
Justification for Assets
Scanpower meets the service levels required by its customers by carrying out a number of
activities on its network assets (such as those detailed in Section 6), and including the initial
step of actually creating / building these assets. Certain assets are required to deliver
greater service levels than others, and the level of investment required will generally reflect
the magnitude and nature of the demand being met.
Matching the level of investment made in assets to the current and forecast service levels
required necessitates consideration of factors such as:

An understanding of how asset ratings and configurations create service levels such
as capacity, security, reliability and voltage stability.

An understanding of the asymmetric nature of under-investment and over-investment;
i.e. over-investment creates the capability to meet service levels before they are
required, whilst under-investing can lead to service failures and interruptions.

A recognition that the existing network has been built over an 80 year period via a
series of incremental investment decisions that were probably optimal at the time, but
when taken in aggregate in the present may have been sub-optimal.

A need to accommodate future growth (noting that the ODV Handbook now prescribes
the number of years ahead that such growth can be accommodated).
In theory an asset would be justified if the service level it creates is equal to the service level
required. In a practical world of asymmetric risks, discrete component ratings, non-linear
behaviour of materials and uncertain future growth rates, we consider an asset to be justified
if its resulting service level is not significantly greater than that required subject to allowing
for reasonable demand growth and discrete component ratings.
The most recent regulatory ODV revaluation exercise was undertaken as at the year-end 31
March 2004 for financial reporting and regulatory compliance purposes. The basis for this
valuation was the draft ODV Handbook issued by the Commerce Commission and current at
this date. The total replacement cost of Scanpower distribution assets at this date was
$40,443,825 and the depreciated replacement cost (DRC) was $19,823,274.
A key practical measure of justification is the ratio of Scanpower’s ODRC to DRC which, per
our most recent ODV Report, is 0.9992. There were no in service assets deemed to be
surplus to requirements at the time of the valuation and therefore there was no optimisation
adjustment to this value. The Scanpower assets that required an optimising adjustment at
that time were some older network spares that have now been scrapped.
Economic value testing of the assets, performed at the time of that regulatory ODV report, by
way of discounted cash flow analysis suggested there was no impairment or EV adjustment
necessary, hence the optimised deprival value of the assets was calculated to be the same
as the DRC at $19,823,274.
Page 47 of 193
7.0
ASSET INFORMATION SYSTEMS
7.1
Cablecad Geographic Information System (GIS)
This is a geographic information system that provides an electronic, graphical representation
of the Scanpower network. Its main utility is a connectivity model of the network which
allows datasets to be extracted on the basis of their electrical connection to other assets. It
includes assets such as transformers, distribution boxes, poles, lines, switches, cables and
isolating fuses.
The system is used to draw/record network plans for capital replacement and maintenance
works, including overhead line replacement and laying of underground cables. It is also used
to store the age and condition of network assets using the results reported from the relevant
assets inspection program.
A support agreement is in place with Enghouse in Canada and on-site technical support is
provided from Auckland.
7.2
NCS (Napier Computer Systems) customer/ICP information database
This system is the main financial recording system for Scanpower. It also stores customer
connection information, and is used to generate ICP numbers for new connections.
Technical support is provided by Napier Computer Systems.
7.3
ECR (Electricity Commission Registry)
This is the national system through which all electricity connections (ICP’s) are recorded and
reconciled. It also records the current energisation status of ICPs on the network (e.g.
energised, de-energised, or decommissioned), the network connected to and the retailer
supplying them.
7.4
SCADA System Records
The SCADA system is licensed from Abbey Systems and is operated / located in the
Network Control Room at Oringi. It is used for real time monitoring of the network, including
feeder loadings, operation of remote control equipment on the network and load control
information.
Technical support is provided by FMS Ltd from Palmerston North who also maintains the
radio communications network.
During 2012, remote laptop access to the Master Station was established for duty controllers
to operate from home during after-hours. A back-up control room was established in
Scanpower’s plumbing and electrical business located in Gordon St. Dannevirke.
Page 48 of 193
7.5
Proprietary asset databases
This category of information systems refers to a suite of proprietary asset databases,
created in Microsoft Excel. These often serve as intermediary stages in the data collection or
reporting of financial accounting, tax accounting, ODV and other information disclosure
requirements.
7.6
Linkage between Data Systems and Asset Management Processes
The asset information systems store and provide data that assists Scanpower in planning
which capital and maintenance works to undertake so as to ensure network objectives are
met. A diagram showing information flow and systems is below.
Figure 12 – Information Systems / Flow Schematic
7.7
Asset management Information Systems Review
During 2012 the Networks Asset Management Information Systems (AMIS) were reviewed.
External support by way of assessment and advice was obtained from Asset Man Ltd. A
needs analysis was undertaken by the Network Manager to provide a strategic benchmark
against which Scanpower’s existing AMIS elements and datasets were assessed with regard
to:

Continued development and enhancement of existing systems.

Reassessment/confirmation of the current development path specifically with regard to
change in staffing structures and associated work processes.
Page 49 of 193

An assessment of the market with regard to the competing leading solutions and their
fit to Scanpower’s needs i.e. what applications are developed, implemented and
proven in NZ power companies.
The conclusions of this review were:

Scanpower’s CableCad GIS is currently proving an adequate repository for asset
records. Whilst GIS is a legacy system that is likely to be replaced by alternative
platforms in the future, Scanpower has other priority AMIS developments to address.

Scanpower has terminated its development of EMS Basix – it did not fit sufficiently to
Scanpower’s needs analysis, priorities or development cost/time performance
requirements. The incompatibility for EMS Basix to integrate with the legacy
CableCAD GIS was a primary issue. The alternative market solutions also shared this
issue.

Scanpower has invested in EXO (a new financial IS replacing the NCS platform and
has an added job costing module) primarily for its external contracting activity. This
however has sufficient capability to be adapted for AMIS functionality as an alternative
EMS Basix. Scanpower’s restructuring of its field staff, such the Network directly
manages its own work crews dedicated to internal network activity, has facilitated the
use of EXO.

EXO is to be loaded with standard assemblies and this will be applied to AM cost
planning. It allows the accumulation of historic actual cost records such that average
unit costs can be derived. It also allows actual costs to applied to reconciled with
monthly budgets. That is no contracting profit margins to cover the overheads of a
contracting environment - contractor management, tendering costs, etc. However, the
internal works crews can be benchmarked against the productivity of external
contracting work crews to demonstrate the efficiency of this structure for Scanpower’s
operation (size and location).

EXO will be adapted to provide a platform for a Works Order (WO) process.
Scanpower does not have a need for contract pricing and approval – EXO will deliver
an estimate of cost, field staff are directly managed.
With regard to AMIS priorities such as a Maintenance Management System (MMS) it was
determined that existing RDMS platforms were adequate to meet Scanpower’s relatively
simple needs. These can be enhanced with a scheduling tool to systemise the work flow
process.
7.8
Improvement Priorities
Scanpower’s needs with regard to AM data it currently does not have include:

Pole structure design tool and pole strength records – it is proposed to acquire a
design tool such as Poles n Wires and to apply ultrasonic pole testing techniques to
determine remaining pole strength.
Page 50 of 193

Scanpower has an electrical analysis model of its network developed in Digsilent. This
model is applied by external engineering expertise. With the network reaching a period
of voltage constraint, driving the need for more detailed analysis, it is proposed to
develop this capability in-house.

It is proposed to migrate from paper based data capture process to electronic capture
in the field.

Installation of smart metering at key network nodes and an enhanced Load
Management System on Scanpower’s SCADA are also priority objectives for
developments its AMIS.
7.9
Technical Standards and Guidelines
Several of Scanpower’s management processes – safety, asset management, risk
management, etc – are by definition and regulatory requirement, Total Quality Management
(TQM) systems. These systems are built on a foundation of standards and procedures.
Managing this documentation in a small organisation such Scanpower is becoming a
significant operational overhead. Consequently it is proposed to move the document
management and TQM record keeping processes to an electronic platform.
Scanpower has a variety of technical standards and practice guidelines that it has largely
adopted from other industry participants. Its involvement in the industry and contracting for
other networks makes this a pragmatic solution to a lack of capacity in this area –
Scanpower is simply not large enough to justify the expertise and resources needed.
7.10
Maturity of Information (AMMAT)
This document is the first attempt by Scanpower to apply a PAS55 compliant asset
management system. As such there are a few circumstances where it has been discovered
that knowledge lacks sufficient detail, consistency or accuracy to allow assessment of legacy
issues and what affects these have on existing whole of life cycle analysis. This is
predominantly uncertainty about the use of second hand materials in the original build, their
subsequent re-cycle and the cost-benefits associated with those early decisions.
There are also inconsistencies between this year’s plan and its predecessor that are a result
from the change in methodology and the timing of when various new policies and practices
have been bought into effect. That is, in the first year there are limited benchmarks against
the benefits of a proposed new practice can be assessed as there are established trends.
To ensure Scanpower has had an objective assessment of the maturity of its Asset
Management Systems, consistent with assessments made on other networks, an external
assessor, Utility Consultants Ltd., has undertaken the “Schedule 13 AMMAT” assessment
process. The regulatory templated schedules can be viewed in Appendix A.
Page 51 of 193
7.10.1 AMMAT Summary
The following is an extract from Utility Consultants report (NB: This assessment was made
on the previous 2012-2022 asset management plan):
Introduction
Schedule 13 of the Electricity Distribution Information Disclosure Determination 2012
requires all EDB’s to complete an assessment of the maturity of their asset management
practices using a prescribed template derived from PAS 55. This requires each EDB to score
the maturity of each identified asset management element between 0 and 4 using prompts,
and it is expected that the assessment will be repeated at regular intervals as part of the
Asset Management Plan disclosure process.
This report is intended only as a summary of the Schedule 13. Readers should refer to the
full Schedule 13 in regard to compliance with the Determination.
Assessment methodology
Scanpower engaged Utility Consultants to assist with compiling the AMMAT (Schedule 13).
The assessment methodology included discussions with the following people:

Ken Mitchell – Network Manager.

Lee Bettles – Chief Executive.

Ben van der Spuy – Company Accountant.
The assessment also included inspections of various documents including:

2012 – 2022 Asset Management Plan.

Working papers for the PAS 55 implementation.

Various board papers.

Board agendas.

Design and construction standards.

Faults database.

Network development plan.

Network automation strategy.

PSMS certificate.
Page 52 of 193

Emergency preparedness plan
Summary of ScanPower’s assessment
The assessment process resulted in scores from 1 to 3, with most elements scoring a 3.
Those elements that scored only a 1 or 2 should easily progress to a 3 as Scanpower
implements PAS 55. Key areas identified for possible improvement along with suggested
priorities are:
Table 14 – Scanpower AMMAT Review Recommendations
Question(s)
Suggested
priority
Recommendation
3
Low
Develop a specific AM Policy that visibly links to the Strategic Objectives.
31
Low
Continue developing HR Plans and assessing competency requirements,
possibly also develop a long-term funding plan if the network funding
requirements are expected to change.
45
Low
Implement firmer quality controls for the few AM activities that are out-sourced.
59
Low
Continue with the IS gap analysis work, and more clearly document the
interaction of key AM IS.
63, 64
High
Continue the current data integrity improvement work.
69, 79
High
Include the proposed improved asset lifecycle criticality and risks in the 2013 –
2023 AMP.
82
Medium
Consider performing a comprehensive legislative and regulatory compliance
review, and from that compile various checklists and calendars for each manager
to implement.
113
Medium
Continue implementing PAS 55, which will embed continual performance, risk
and cost assessments.
Page 53 of 193
8.0
ORGANISATIONAL CAPABILITY
Organisational structure deliberately reflects AM’s “strategic line of sight” described in
section 4 from governance, to corporate management, to divisional management, to asset
management, right through to field operatives and establishes clear lines of accountability for
delivery on company objectives.
The roles within the various layers of the structure reflect the asset management
competency framework illustrated below.
Figure 13 – Asset Management Competency Framework
8.1
Accountabilities and Responsibilities
A current organisational chart is provided in Figure 14 below.
The Chief Executive reports to a Board of five Directors, currently; Allan Benbow
(Chairman), Peter Clayton, Christine Donald, Bob Henry and Rodney Wong. The Directors,
in turn, are employed by, and ultimately report to, the Trustees of the Scanpower Customer
Trust (currently Rowena Bowie, Keith Cammock, Jim Crispin, Stuart Smith and Noel
Galloway).
Ultimate responsibility for the management of Scanpower’s network assets lies with the
Board of Directors, who are appointed by the Board of Trustees. The Trustees are elected
on a tri-annual basis by consumers. The Board of Directors appoints the Chief Executive
who is responsible for day to day management of the company and its assets. However, the
Chief Executive is required to:
Page 54 of 193

Obtain Board approval on an annual basis for the Asset Management Plan and related
capital and operating budgets.

Report to the Board on a monthly basis on actual company performance relative to the
objectives documented within the Asset Management Plan including:

-
Monthly financial performance (capex/opex) relative to budget, including
appropriate variance analysis and commentary where required.
-
Monthly network reliability performance (SAIDI and SAIFI) relative to target,
with supporting commentary on the level and nature of network outages
occurring during the month.
-
A general commentary on monthly progress on network capital and
maintenance activities.
Obtain Board approval for any material deviation from the initiatives planned per the
AMP (for example deferral of a particular project, or implementing an unplanned
project with a value greater than $250,000).
Scanpower operates an in-house network engineering/asset management team which
includes network dedicated field crews. Field resources can be supplemented from the line
contracting division. The Network Manager is responsible for day to day running of the
Network Division. The Network Manager is also the “responsible person” as defined by the
Public Safety Management System.
The current organisational structure is shown in Figure 14 below. There are two network
orientated groups within the team; Network and contracting each with approximately 15
FTEs. Scanpower also operates a Plumbing and Electrical Business and a large Cold Store
operation. These 2 businesses represent approximately half of the total staffing
establishment. Safety systems are necessarily coordinated across the entire organisation.
The Network Division is responsible for maintaining accurate asset information, both in terms
of installation and condition survey data, and using this as a basis for asset management
planning, decision making on the entire life cycle management of the network business
assets and delivering on divisional business objectives.
The Treesmart business, while operating as its own profit centre, has the managerial
oversight of the Network Manager. Their rationale for existence is to meet the Networks
resourcing requirements for tree management which is a major cost to the network
operation.
The Contracting Division undertakes work for external clients, including customers, property
developers and other networks. Where Network requires additional resourcing for its work
programmes it sources this from the Contracting Division in the first instance. Whilst the
majority of line work is undertaken by the in-house teams, Scanpower occasionally uses
external contractors for certain specialised work.
Separation of the field crews between Network and Contracting Divisions is intended to
prevent external work reducing focus on core network requirements.
Page 55 of 193
Figure 14 – Scanpower Organisational Chart
Page 56 of 193
8.2
Developing Asset Management Organisational Capability
PAS55 requires the resourcing and capability of the organisation to be assessed for its
capacity to deliver on the AMP and associated business objectives.
Scanpower has undertaken a review in 2012 of its staffing structure with regard to:

The skill sets it will need to implement development plans which require a higher level
of technology application.

The adequacy of resourcing levels necessary to managed safety, environment and
quality systems including the management of training programmes and record
keeping.

The adequacy resourcing levels with respect to tree trimming demand in the district.

The coordination of resources with the Contracting Division to meet the Networks
servicing requirements, the private work of network connected customers, and the
external work for other network companies.
In addition to the findings of this review, there has been several personnel changes in the
staff managing contracting activity which has created opportunity for the changes
determined to be desirable.
This has resulted in the staffing structure above which brings some of the field crews directly
under the Network divisions control and management. The Contracting division will
concentrate on consumer chargeable and external work. The network will also draw on
contracting resource for its more sizable work packages that can be projectised.
This new structure has evolved throughout 2012/13 and is a significant change to that of
previous AMPs. The lines of sight and accountability have more clarity and therefore this
restructuring is considered to be an improvement to organisational AM capability.
8.3
Competency Requirements
8.3.1
Training and Equipment Certification
The Electricity Industry has highly developed and formalised competency processes that
impact on the organisation company wide, affecting all roles within the organisation. In order
to work in the industry whether in regard to Scanpowers network, its customer base, external
networks/customers or partners in other sectors (e.g. Transpower), the ability to maintain
and be able to demonstrate competency is a necessity. Like-wise, the plant and equipment
used, is required to have current certifications of various types.
Trade level competencies and equipment certification is managed by the Contracting
Division utilising the assistance of ESITO. Industry specific safety rules and the related
competency framework are included in this scope. Management processes include regular
review of needs with respect to customer requirements and staff development programs.
Page 57 of 193
The continuing development programs of tertiary qualified staff are self-managed by the staff
concerned but with the input of divisional managers with regard to company needs. The
Network team for example, determines what specialist engineering capability it will outsource
or whose role gaining a specific skill set might best match.
Other training requirements are managed at corporate level – both the Strategic Plan and
Risk Management Plans address mission critical training and capability requirements. Safety
management systems, information systems, and quality systems are addressed at this level
– for example, training internal auditors.
8.3.2
Specialist Resources
Both Network and Contracting share a requirement to sustain capability with regard to
specialist resourcing and for cost efficiency share the tasks of assessing need and funding
training. Specifically:

Tree management

Live Line capability – Glove barrier and Hot Stick

Cable Jointing

Electrician prescribed work

After-hour fault crews
8.4
Communication and Participation
Disseminating the information derived in AM planning processes throughout the Line of Sight
and receiving feedback from staff, participants and stakeholders has been achieved by the
following actions:

The Network Development Plan has been presented in detail to the executive
management team and subsequently the Directors. The forecast capability and
capacity resourcing issues of the wider organisation have been considered.

AMP budgets have been prepared by a collaborative effort involving the CEO, Network
Manager, and Contracting Manager.

Company organisational restructuring has followed a consultative process where input
has been canvassed and then decisions presented and discussed with staff
collectively.

Asset management staff are allocated their tasks, projects, and budgets from the AMP.

The completed AMP is then communicated to field staff at two levels. Firstly the
Network Manager presents the detail of the development projects and other initiatives,
explains why they are necessary and explains the choice of solutions. Secondly, staff
in asset management roles, who directly manage work crews, advise the work
Page 58 of 193
programme assumptions and the associated productivity assumptions in the AMP and
budgeting.

Weekly, planning meetings are held with all field staff, as a forum for discussing all
operational matters. Network operational management is in daily contact with the
foremen of the work crews. Network field staff facilities, offices, and the control room
are all located on a single site at Oringi. 90% of the network is located within a 20km
radius of Oringi.
Page 59 of 193
9.0
RISK MANAGEMENT
9.1
Introduction to Risk Management
Scanpower manages through its business risks in accordance with the principles and
processes defined by ISO 31000.
Figure 15 – Risk Management Framework
Risk Management Framework is a TQM system that is integrated into every step of asset
management continuous improvement cycle:

Risk is addressed discretely and separate to the AMP at a corporate level;

And at the network divisional level;

And further, risk assessments are inherent in asset criticality determinations,
performance assessments and associated gap analysis against standards and AM
objectives.
It is also integrated and coordinated with the other TQM processes Scanpower operates for
safety management and quality management. The integral nature of risk management is
directly evident in the ISO risk management principles listed below.
Risk management:
Page 60 of 193

Creates and protects value

Is an integral part of all organisational processes

Is part of the decision making

Explicitly addresses uncertainty

Is systematic, structured and timely

Is based on the best information available

Is tailored

Takes human and cultural factors into account

Is transparent and inclusive

Is dynamic, iterative and responsive to change

Facilitates continual improvement of the organisation
However in terms of asset management, it specifically focuses on the network assets, work
practices, and the local operating environment. Scanpower’s broader business activities
have their own risk management policies and practices.
9.2
Corporate Risk Management
The higher level corporate type risks with respect to Business Continuity, IT Security,
Insurance, Treasury Policy, etc. are managed at that level in the organisation. Some
Emergency Response and Preparedness Plans also need be inclusive of the entire
organisation (for example, in its company-wide Safety Management Systems).
As can be seen in the corporate level risk assessment detailed below, the network, as
Scanpower’s core business, features predominantly in the risk management “line of sight”
starting at governance and executive management level. This assessment is reviewed
annually between the CEO and Directors.
Table 15 below summarises the 19 most significant corporate level risks as identified at a
recent risk management exercise undertaken between the executive management team and
the Scanpower Limited board of directors. The risks are not presented in any particular
order of significance or severity. Each has been assigned a series of potential impacts on
the organisation, and a corresponding set of mitigation or monitoring strategies.
Page 61 of 193
Table 15 – Scanpower Corporate Risk Register
Corporate Risk 1 Inadequate network asset planning and management (short and/or long term)
POSSIBLE IMPACTS  Potential public and staff safety issues including exposure to injury or death.  Increased unplanned outages, deterioration in reliability performance and lost revenue.  Creation of increasing backlog of capital and maintenance work that is hard and expensive to recover.  Failure to adopt best practice and new technologies results in company falling behind other industry participants.  Development opportunities are lost, potentially to competing companies, resulting in lost revenue.  Exposure to legal and regulatory action on grounds of negligence / sub standard asset management RISK MITIGATION / MONITORING STRATEGY
 Ensuring annual asset management planning is completed and results of external assessments reviewing and considered.  Ensuring annual capital and maintenance works are completed according to plan.  Board members periodically visit work sites and physically verify works are being completed.  Periodic external reviews / health checks by appropriately qualified consultants. Corporate Risk 2 Impact on value and profitability of company as a result of sector regulation POSSIBLE IMPACTS  Price or rate of return control limits earning potential of company and hence the long term value of the business.  Increased reporting and disclosure requirements add cost into the business.  Company’s already low prices are locked in over the medium term (as happened 2004 to 2009). RISK MITIGATION / MONITORING STRATEGY
 Continue to participate in Electricity Networks Association industry group and submissions.  Maintain strong and positive relations with the Trust to allow continuance of current exemption from price control.  Set pricing on a realistic basis and pre‐emptive basis. Corporate Risk 3 Inadequate compliance with industry regulations and requirements POSSIBLE IMPACTS  Reputational loss.  Fines for non‐compliance.  Potential exposure to liability issues if the non‐compliance is safety related. RISK MITIGATION / MONITORING STRATEGY
 Prepare a schedule / calendar of annual compliance requirements and advise board.  Report back to the board on adherence (or otherwise) with compliance requirements.  Continue to comply with Energy Safety Service, Electricity & Gas Complaints Commission, and National Registry audits. Page 62 of 193
Table 15 continued – Scanpower Corporate Risk Register
Corporate Risk 4 Network operational risk and staff / public safety POSSIBLE IMPACTS  Incorrect switching, work practices, asset failures lead to serious accident or death.  Damage to customer premises and property.  Damage to network assets. RISK MITIGATION / MONITORING STRATEGY
 Ensure network control room is functioning effectively.  Ensure network operational procedures are in place and adhered to.  Ensure network operations are staffed appropriately. Corporate Risk 5 Major natural disasters and hazards POSSIBLE IMPACTS  Catastrophic damage to assets and associated interruption of electricity supply.  Long term revenue loss.  Failure to meet the civil defence needs of the community and other agencies. RISK MITIGATION / MONITORING STRATEGY
 Ensure effective disaster recovery and business continuity plans in place.  Ensure compliance with Public Safety Management Systems.  Ensure ongoing liaison with regional civil defence planning. Corporate Risk 6 Inadequate revenue management and pricing POSSIBLE IMPACTS  Inadequate cash flows to meet the long term needs of the business.  Profitability and returns to customer diminish over the long term.  Deterioration in financial performance and increasing stakeholder dissatisfaction.  Lack of funding for necessary asset replacement and development. RISK MITIGATION / MONITORING STRATEGY
 Make pricing decisions on an objective rather than emotive basis.  Undertake short and medium term revenue and cash flow analysis.  Consider pricing relative to peer group companies. Page 63 of 193
Corporate Risk 7 Diversion of attention from core network business POSSIBLE IMPACTS  A disproportionate amount of board and management time is devoted to non‐core business activities, resulting in degradation of the core network business over time.  Directors fail to accumulate knowledge relating to the core business over time resulting in poor governance performance.  Resources are dedicated to non‐relevant activities.  Company pursues activities in which it has little or no expertise.  Development opportunities in core areas are missed. RISK MITIGATION / MONITORING STRATEGY
 Regular (at least annual) strategic planning sessions.  Appropriate time, consideration and resources are applied to core business activities and closely related activities.  Board to maintain focus on core / critical activities. Corporate Risk 8 Lack of contract management expertise POSSIBLE IMPACTS  Legal and financial exposure where acting as the contractor.  Failure to control contractors effectively where acting as the principal. RISK MITIGATION / MONITORING STRATEGY
 Appropriate use of company solicitors to establish pro forma contracts.  Use of company solicitors to review major contracts.  Staff training on rudimentary contract law issues.  Policies in place regarding staff ability to amend or change contracts. Corporate Risk 9 Data management risk / loss of data POSSIBLE IMPACTS  Loss of intellectual capital inherent in company data and corresponding deterioration in business performance.  High costs associated with restructuring or recapturing lost data.  Potential safety issues around loss of installation specific electricity data. RISK MITIGATION / MONITORING STRATEGY
 Ensure that appropriate information technology architecture is in place, with storage redundancy.  Ensure that regular back up procedures are established and followed.  Ensure that a copy of back ups is held at off‐site location. Page 64 of 193
Corporate Risk 10 Inadequate strategic planning POSSIBLE IMPACTS  Lack of coherent understanding between Directors, management and trustees as to the objectives and long term direction of the company.  Lack of clear direction leads to inertia or time and resources being applied to strategically incompatible activities.  Over the long term, company performance suffers. RISK MITIGATION / MONITORING STRATEGY
 Establish an annual process for strategic planning, including annual board session.  Consider behaviours and apparent strategies of other industry participants.  Consider training for directors and staff on strategic planning. Corporate Risk 11 Lack of security of supply management POSSIBLE IMPACTS  Lack of network supply contingency options in the event of significant failure.  Extended loss of supply to large sections of the network (if not all).  Associated revenue and safety issues arising from widespread outages. RISK MITIGATION / MONITORING STRATEGY
 Ensure contingency / back up supply options are in place as appropriate to load.  Ensure appropriate security of supply is in place where necessary.  N‐1 security in place at grid exit points. Corporate Risk 12 New business venture failure POSSIBLE IMPACTS  Adverse financial implications of new business failure.  Flow on impact on core business activities (e.g. cash flow shortage).  Reputational damage.  Negative response from owners / trustees and loss of faith. RISK MITIGATION / MONITORING STRATEGY
 Set maximum investment levels where new business activity is outside core.  Prohibit investments outside of core or related activities.  Ensure appropriately experienced and qualified staff are recruited for new ventures. Page 65 of 193
Corporate Risk 13 Inadequate business continuity planning POSSIBLE IMPACTS  Business fails to recover quickly (or at all) following an adverse incident.  Associated revenue, reputational and safety issues.  Long term value is destroyed. RISK MITIGATION / MONITORING STRATEGY
 Ensure effective business continuity, disaster recovery, emergency management and data management plans in place.  Periodic “rehearsal” and testing of disaster recovery procedures. Corporate Risk 14 Failure of Transpower or electricity generators to deliver POSSIBLE IMPACTS  Loss of supply of electricity at generation or transmission level triggers regional emergency and significant loss of income to Scanpower.  Typical of a “dry winter” as seen in recent years. Additional costs incurred participating in “national energy savings” campaign.  Medically dependent customers exposed.  Damage to customer property (e.g. frozen goods etc).  Failure of security systems, water and sewage infrastructure etc. RISK MITIGATION / MONITORING STRATEGY
 Participate in industry wide supply management forums.  Ensure load shedding processes are in place with well understood priorities and protocols.  Ensure customer communication plan is in place for such an event. Corporate Risk 15 Loss of key staff POSSIBLE IMPACTS  Loss of intellectual capital and long term organisational knowledge.  Recruitment costs associated with sourcing replacement staff.  Potential shortages or lack of suitable replacement staff.  6‐12 month plus disruption to operations and strategy implementation. RISK MITIGATION / MONITORING STRATEGY
 Retention focused remuneration structures.  Remuneration is at least at market (or better) levels.  Structured staff reviews and feedback opportunities. Page 66 of 193
Corporate Risk 16 Inadequate insurance cover POSSIBLE IMPACTS  Financial exposure to claims not covered by insurers.  Policy conditions result in non‐coverage by insurers.  Substantial potential exposure through Oringi Cold Stores division. RISK MITIGATION / MONITORING STRATEGY
 Engage appropriately qualified and experienced insurance advisors.  Board level review of policy cover on an annual basis.  Utilise contractual mechanisms to limit liability where appropriate or possible.  Consider alternative corporate and ownership structures to isolate areas of high potential liability Corporate Risk 17 Technological advances in distributed generation threaten / compete with the network business POSSIBLE IMPACTS  Traditional electricity supply over lines displaced by new technologies as they become more cost effective (e.g. photovoltaic solar, solar water heating, fuel cell technologies).  Slow erosion of revenue with no corresponding reduction in costs leads to sharp decline in profitability and cash flows to the point the business cannot be sustained without dramatic price increases (thereby exacerbating the problem).  “Creeping” revenue decline is not addressed before it is too late. RISK MITIGATION / MONITORING STRATEGY
 Develop a longer term strategy around broader energy solutions services.  Build organisational competencies and knowledge of new technologies over time.  Resources dedicated to external environmental scanning (attending courses, seminars, conferences etc).  Consider entering those industries which are in direct competition with electricity networks.  Avoid the “Kodak moment”.  Diversification into other industries. Corporate Risk 18 Staff fraud / collusion POSSIBLE IMPACTS  Staff theft on an isolated or sustained basis.  Adverse financial impacts. RISK MITIGATION / MONITORING STRATEGY
 Management in conjunction with Audit Committee undertakes an assessment of potential sources of fraud / theft.  Continue to review findings of annual audits by Audit NZ and ensure recommendations are responded to.  Effective internal controls and policies are in place to minimize the threat of fraud or theft. Page 67 of 193
Corporate Risk 19 Sudden / significant change in board of directors and / or trustees POSSIBLE IMPACTS  Significant loss of accumulated organisational knowledge and experience impacts on performance.  Extended learning curve / recovery period arising from lack of succession planning.  Loss of strategic impetus.  Increased potential for conflict and sudden shift in strategic focus. RISK MITIGATION / MONITORING STRATEGY
 Succession planning and management in place to the best extent possible.  Continued close communication between the Board and Trust. 9.3
Insurance
As part of the company’s approach to risk management, Scanpower maintains material
damage insurance on certain elements of the network asset base and on peripheral but
strategically significant non-network assets such as key buildings including the head office
and control room areas.
Scanpower engages insurance experts JLT on a consultancy basis to provide general risk
management and insurance advice, and to secure cover in the insurance market on the
company’s behalf. This is done on an annual basis.
Due to the nature and configuration of Scanpower’s network asset base (i.e. no
subtransmission system or zone substations), in value terms the asset is spread over a wide
geographic area; with a replacement cost of $50m across 2,000km2 the average value per
square kilometre is $25,000. Correspondingly, there are no major concentrations of asset in
terms of value that you mind find in other networks (e.g. substations).
Discussions with insurers over the years have highlighted unwillingness on their part to
insure the entire asset base, and even if they were it is anticipated that the cost would be
prohibitive. Therefore Scanpower only insures the following:
Table 16 – Insurance Cover Summary
Asset
Insured Value
Basis of Insurance
Dannevirke GXP Ripple Injection Plant
$350,000
Replacement
Woodville GXP Ripple Injection Plant
$350,000
Replacement
Poupouatua Radio Comms Repeater
$300,000
Replacement
$2,400,000
Functional Replacement
$850,000
Replacement
Network Office Building / Control Room
Network Related Software / SCADA / GIS
Page 68 of 193
In relation to other network assets such as poles, conductors, switchgear, transformers and
so on, Scanpower has opted to self insure these assets. Scanpower’s material damage
policy (which includes cover for non-network related assets such as the company’s cold
storage business) is underwritten by NZI (47.5%), Vero (27.5%) and QBE (25%). We are
not aware of any further reinsurance undertaken by these parties.
In deciding to self-insure network assets beyond those specified above, Scanpower took into
consideration factors such as:

Historical trends in both material damage incidents and costs.

The company’s financial ability to meet these costs.

Exposure to large scale loss events.
In the past ten years, the most significant natural fault events were extremely heavy snow
falls in 2003 and the Manawatu floods of 2004. In both cases the asset repairs and
replacement necessitated by these events were met from operating cash flow, and the cost
of neither was in excess of $150,000.
In terms of Scanpower’s ability to fund asset replacement in the event of a large scale loss,
the company has the following options / reserves:

Each year Scanpower makes a discretionary network discount payment ranging from
between $1.5m and $2.0m. This cash flow could be redirected to fund asset
replacement if necessary.

Scanpower has a flexible financing facility in place with BNZ with a current limit of
$5m. Whilst this balance fluctuates from time to time, there is $2.3m funding available
as at the date of this asset management plan.

Taking into account the above facility, Scanpower has no other significant long term
liabilities, and given total assets (as at 31 March 2012) of $38.5 the company is not
very highly geared. This provides substantial further borrowing capacity of at least
$10m should the situation require it.
Taking these historical factors and the company’s financial position, the Board of Scanpower
is of the view that the company can adequately self-insure those network assets not
otherwise covered by the material damage policy.
9.4
Asset Management Related Risk Management Process
Specifically with regard to network assets and asset management systems risk has the
following definition:
Risk = Likelihood of an Adverse Event x Consequences (cost and/or performance)
Page 69 of 193
Practically, Scanpower assesses risk and determines appropriate risk management actions
by taking a typical 5x5 matrix qualitative approach to assessing the factors of which is
consistent with its safety management system risk assessment process.
Figure 16 – Conceptual Risk Assessment Process
Scanpower does not have many assets that are categorised as critical, its network is
generally robust, and its public relatively tolerant. This places most risk issues in the
tolerable region and therefore most risk management actions follow an ALARP (As Low As
Reasonably Practical) strategy. ALARP is actually a prescribed approach for SMS and it
conforms with the PAS55 standard.
The risk management strategies selected depend on the nature risk. In Scanpower’s case
most risks are low probability low consequence risks that do not impact company objectives
significantly so do not justify much expenditure to eliminate. At the other end of risk scale,
the risks that are in the Intolerable high consequence high probability range are normally
safety risks and therefore have necessarily been eliminated and/or mitigated. Consequently
where they are predictable the AM and operating practices are relatively mature in terms of
established contingency, mitigation, quality, and other improvements. Unpredictable risks
are addressed with improved SCADA providing timely information and visibility and
automation to speed response.
Risk is also managed after an event through Contingency Plans, Disaster Recovery Plans
(critical spares), and contingency provisions such as generators for security sensitive
installations. Scanpower applies a VoLL (Value of Lost Load) analysis to determine the merit
of funding enhanced security. This is undertaken as part of the Network Development Plan
where security standards are reviewed and issues addressed at system engineering/design
level.
Page 70 of 193
Figure 17 – Risk Treatment / Risk Characteristics Matrix
The asset management risks that have been identified by drilling down from corporate risk
identification are summarised in Table 17 below (nb: risk is quantified in terms of the 10 year
planning period of this plan):
Table 17 – Asset Management Related Risk Summary
Asset Management Risk 1
Stranding of line assets due to lower cost of supply technology options for consumers i.e. DG LIKELIHOOD  Low CONSEQUENCE  High RISK  Medium ALARP STRATEGY  Minimise investment in transmission development and line upgrades in favour of DG where possible. Asset Management Risk 2
Loss of a large customer LIKELIHOOD  Medium CONSEQUENCE  Medium RISK  Medium ALARP STRATEGY  Support with customised efficiency, security and quality of supply measures Page 71 of 193
Table 17 continued – Asset Management Related Risk Summary
Voltage constraints caused b changing load demographics LIKELIHOOD  High CONSEQUENCE  Medium RISK  High ALARP STRATEGY  Increased monitoring and more proactive planning. Asset Management Risk 4
Loss of load control capability LIKELIHOOD  Medium CONSEQUENCE  Medium RISK  Medium ALARP STRATEGY  Enhance load control system functionality and take lead on smart meter / smart grid developments. Asset Management Risk 5
Consumer driven developments occurring faster than the network plan/design/build cap LIKELIHOOD  High CONSEQUENCE  Medium RISK  High ALARP STRATEGY  Maintain sufficient headroom in Network Development Plan to pre‐empt developments and bring actions forward as necessary. Asset Management Risk 6
Technology capability and resourcing inadequate to meet demand of non‐lines solutions to development needs LIKELIHOOD  Medium CONSEQUENCE  Medium RISK  Medium ALARP STRATEGY  Recruit appropriate engineering staff and bring more technical design/planning in house. Page 72 of 193
Table 17 continued – Asset Management Related Risk Summary
Age profile of field crews LIKELIHOOD  High CONSEQUENCE  Medium RISK  High ALARP STRATEGY  Recruit trainees and develop existing staff with the key skills that may be lost to retirements. Asset Management Risk 8
Development of dairying/intensive load in areas more than 20km from a GXP LIKELIHOOD  Medium CONSEQUENCE  High RISK  Medium ALARP STRATEGY  R & D on dairy shed energy balance with solar hot water, PV, and biomass. Asset Management Risk 9
Condition of consumer owned lines driving up network operating costs LIKELIHOOD  High CONSEQUENCE  Medium RISK  High ALARP STRATEGY  Undertake inspections and notify consumers. Asset Management Risk 10
Maturing plantations on land converted to forestry over‐whelming tree fault statistics LIKELIHOOD  High CONSEQUENCE  High RISK  High ALARP STRATEGY  Increase sectionalising automation and line relocations where not practical to increase clearances. Page 73 of 193
9.5
Significant Assumptions
Scanpower’s AMP is based on the following assumptions:

Significant intensive farming (such as dairying east of the Manawatu River) does not
develop more than 20km from a GXP. Specifically no major irrigation development that
would support this intensification.

Wind generation on the Puketoi Ranges requiring transmission support does develop
within the planning horizon of this plan. Note: there is a very large amount of
generation consented by 3 different retailers on this range. Projects are on hold for
lack of a transmission solution at this time which currently places the likelihood of
these developments beyond the planning horizon of this plan.

Oil is not discovered in commercially viable volumes in the District driving the
development of a large scale new industry in the region. This information is closely
guarded commercial information and therefore Scanpower is unable to assess its
planning implications. However, consents for drilling have been issued at 2 locations
approximately 15Km east of Dannevirke.

Growth in dairying, population, and other econometric influences remains consistent.
These are the major growth drivers in the NDP (Network Development Plan) forecasts
and therefore an optimistic assumption is applied.

PV does not develop at a rate faster than the network can economically support with
storage, capacity, and voltage management. PV is highly likely to reach the economic
trigger point for mass market up-take in the next 10 years. Network planning has a
high sensitivity to this pivot point.

Major customers remain viable and operating. They are all exporters and so remain
sensitive to the global economy and pricing risks.

No new industries and/or major customers emerge with intensive energy requirements.
This would require a greenfield planning response – the size of Scanpower’s network
is relatively small to the potential size of a major user. For example the development of
a dairy factory, cement plant, etc.
Further detail on planning criteria assumptions can be found in the Network Development
Plan section of this document.
9.6
Business Model Risk
In terms of the AMP prescription, this describes:
“A description of significant factors that may lead to a material difference between the
prospective information disclosed and the corresponding actual information recorded in
future disclosures”
Change issues that may affect the continuity of the AMP from year to year include:
Page 74 of 193

Change in polices resulting from reassessment of asset management practices
following alignment to PAS 55.

The associated change in work practices.

The restructuring of Network and Contracting Divisions.

The associated restructuring of the staffing establishment and resources.

The associated alignment of budgets
Page 75 of 193
10.
NETWORK DEVELOPMENT PLANNING
10.1
Network Development Plan Summary
This section of the AMP details the process of assessing the Network’s future development
requirement in order to deliver on Scanpower’s long term business objectives. It records the
asset management strategy and planning component of the AM Conceptual Model. That is,
it is the Network Division’s Strategic Plan as applied to the assets on which the core
business is based. It is referred to as the Network Development Plan.
The key features of the existing network with regard to its strategic planning environment
are:

The network has no sub-transmission system which means it is capacity and voltage
constrained. While peak load can be managed to these constraints, load growth
results in longer duration of constraints being experienced by consumers.

The network has minimal interconnection capability particularly in the urban LV
networks. No part of the network meets an N-1 security standard.

Some of the more significant differentiators of this network to its peers are; it has very
little single phase distribution and its protection/switching is largely still HV expulsion
fused based. That is, the network is a traditional, predominantly overhead, manually
operated, lineman orientated asset.
In a nutshell, this Development Plan seeks to minimise the amount of traditional line
orientated development associated with the legacy centralised grid connected power supply,
that is becoming increasingly less competitive with the alternative distributed energy systems
approach now being quite rapidly enabled by technology. Scanpower seeks to re-align and
re-optimise its network over the next 10 years for operation in a distributed energy
environment.
More specifically:

Provide and distribute capacity sourced from the grid on a just in time basis. The
investment environment is becoming shorter relative to the longevity and lumpiness of
traditional line asset development.

Avoid investment in transmission and sub-transmission asset (lines solutions) in favour
of Distributed Generation, Smart Grid, etc. (non-line alternative solutions).

Shift its network development towards the consumer end i.e. the LV network and its
interconnection in order to make it ready to receive PV and EV connection in
particular.

Develop its network as a platform from which it can offer DG and energy brokering
services.
This strategy is justified by the high cost path and high risk of traditional line only network
development. Technology is changing the life cycle cost and performance drivers.
Page 76 of 193
The network must be adaptable to change because technology change outstrips our vision
of the future. Scanpower seeks to pre-empt change and adapt its asset base to this future.
The key development strategy is to reconfigure the network with a number of 11kV bussing
points to which voltage correction can be applied if necessary and from which sub-feeders
with smaller load blocks and higher interconnection can be developed.
10.2
Planning Objectives
The specific objectives of the planning process include;

To forecast load growth to ensure sufficient capacity is available for local economic
development.

To forecast voltage and capacity constraints and identify shortfalls against
Scanpower’s quality standards.

To forecast contingent capacity constraints and identify shortfalls against Scanpower’s
security standards.

To identify the expected timing and/or trigger points of any network development
necessary to sustain standards and service delivery triggered by load growth and/or
change in the load demographics.

To determine the optimal solutions, with regard to cost efficiency, affordability, and
service delivery, for resolving development issues.

To formulate solutions into a coordinated plan that provides for a sustainable and
flexible development path.

To demonstrate the network capacity to connect new load, meet new service
expectations associated with that new load, and provide an indication of the
responsiveness with which network can be developed.

To determine the preferred options/solutions for addressing foreseeable issues raised
by forecasts.

To identify the level of investment and expenditure timetable necessary to cover each
foreseeable issue.

To develop associated policy necessary to manage risks and forecast fundraising
demands.
10.3
Policies and Standards
10.3.1 Voltage Quality
Page 77 of 193
Scanpower will upgrade supply as necessary to meet the following voltage quality
obligations:

Scanpower maintains nominal system voltage delivered at point of connection of the
customers assets to its network at +/-6%. Scanpower has no sub-transmission system
with automatic voltage control equipment. Its voltage management capability is largely
limited to fixed tap settings on distribution transformers. Accordingly, line load voltage
regulation must be limited to within the 5% voltage range of is transformers. Regulation
over relatively long 11kV lines is the primary constraint issue on Scanpower’s network.

Transient voltage dips and flicker that present on the network as the result of large
loads stopping and starting can cause disruption/annoyance and affect industrial
production which in some instances can have more adverse outcomes than a longer
outage. Scanpower addresses this by requiring installation design to comply with
AS2279. Voltage disturbance is limited by requiring the Point of Common Coupling to
be located where the network has sufficient strength to suppress the disturbance to
acceptable levels (as defined in its Connection Standard). For large loads this may
require dedicated supplies back to bussing points within the 11kV network. In some
instances the Network Development Plan will need to establish suitable bussing and/or
voltage control points in key locations.

Harmonics are an issue on networks with increasing industrial, dairy and irrigation.
Harmonics cause increased heating in electrical plant and equipment and reduce the
life of network assets like transformers. Scanpower’s Connection Standard requires
compliance with ECP 36 however addressing issues arising has been reactive
process. The EEA has drafted a new standard for more proactive management of
harmonic levels on networks – Scanpower has adopted this standard. It is expected
that there will be a number of legacy issues to be addressed as a result of changing
the standard. Better monitoring is an expected benefit of smart meter deployment.

Power Factor and losses are related issues to voltage and power quality. These are
addressed as part of the assessment of upgrade options. There is very limited
economic merit in addressing these issues on a standalone basis.
10.3.2 Security Standard
Scanpower has reviewed its Security Standard and concluded that the industry practice of
investing in redundant assets and excess capacity on the basis of load size is not
economically efficient, equitable, or practical on Scanpower’s network. The loads are too
small to justify the levels of expenditure necessary to secure supply in this manner.
Accordingly the Security Standard has been rewritten to directly support Scanpower’s
outage management objective and target of limiting all HV faults to less than 6500 Customer
Minutes Lost (equates to 1 SAIDI minute). This objective treats all customers to a consistent
standard – if the fault affects many customers (higher load) as in an urban situation then it
must be responded to in a shorter time, if it affects fewer customers as in a remote situation
then the response can be longer.
Page 78 of 193
The Standard therefore defines the preferred network configuration and contingency
provisions necessary to support this objective. For example, specific security provisions for
large customers, levels of network interconnection, contingent capacity, and automation.
Page 79 of 193
Table 18 – Scanpower Security Standard
SCANPOWER SECURITY STANDARD OBJECTIVE All HV faults restored within 1 SAIDI minute following first response getting to site. LARGE ICPs SECURITY PROVISIONS > 1000kVA Dual dedicated 11kV feeders from PCC, CB protected > 500kVA Single dedicated 11kV feeder from PCC, CB protected, critical load secured with Genset > 250kVA Dedicated LV feeder, Transformer/LV interconnection , LV security customer solution >100kVA Transformer/LV interconnection ‐ urban only NETWORK LOAD CENTRES Definition: all load within a mesh network segment able to be by‐passed or all load down stream of a radial network segment if not able to be by‐passed. URBAN ICPs 30% Installed kVA No. of ICP's km Network 90% ICP Restoration (min) CML at Risk >2MVA 1000 10 7.5 7500 >2MVA 500 10 15 7500 >1.5MVA 375 8 20 7500 >1MVA 250 6 30 7500 >500kVA 100 4 75 7500 >250kVA 50 3 150 7500 >100kVA 25 2 300 7500 Contingent Capacity Security Provisions 100% N‐1 1MVA from 2 HV tie points 500kVA from 2 HV tie points 1MVA from 1 HV tie point 100kVA from 4 LV tie points 100kVA from 2 LV tie points 50kVA from 2 LV tie points Closed 11kV N‐1 Ring, Auto‐Sectionalising, DMS/SPS CB Protected, Auto‐sectionalising, Remote Control Tie Switches, Scada Indications CB Protected, Auto‐sectionalising, Remote Fault Indication, Manual Tie Switches CB Protected, Manual/Auto Sectionalising, Remote Fault Indication, Manual Tie Switches Ring Main, Manual/Auto Sectionalising, Remote Fault Indication on Tfmr/LV Feeders, Manual Tie Switches Fuse‐saver, Manual/Auto Sectionalising, Remote Fault Indication on Tfmr/LV Feeders, Manual Tie Switches Fused, Manual Sectionalising, Remote Fault Indication on Tfmr/LV Feeders, Manual Tie Switches Page 80 of 193
Table 18 continued – Scanpower Security Standard
Rural (ICP's/km < 5) 20% Installed No. of kVA ICP's km Network 90% ICP Restoration (min) CML at Risk >2MVA 500 100 15 7500 >1.5MVA 375 75 20 7500 >1MVA 250 50 30 7500 >500kVA 100 25 75 7500 >250kVA 50 10 150 7500 >100kVA 25 5 300 7500 Contingent Capacity 1MVA from 2 HV tie points 500kVA from 2 HV tie points 500kVA from 2 HV tie points 500kVA from 2 HV tie points 100kVA from Genset 50kVA from 2 LV tie points Security Provisions CB Protected, Auto‐sectionalising, Remote Control Tie Switches, Scada Indications CB Protected, Auto‐sectionalising, Remote Fault Indication, Manual Tie Switches CB Protected, Manual/Auto Sectionalising, Remote Fault Indication, Manual Tie Switches Ring Main, Manual/Auto Sectionalising, Remote Fault Indication on Tfmr/LV Feeders, Manual Tie Switches Fuse‐saver, Manual/Auto Sectionalising, Remote Fault Indication on Tfmr/LV Feeders, Manual Tie Switches Fused, Manual Sectionalising, Remote Fault Indication on Tfmr/LV Feeders, Manual Tie Switches Page 81 of 193
10.3.3 Contingent Capacity
Excess capacity is necessary on a network for:

Provision of headroom for new growth between optimal period of upgrade.

Provision for unexpected major loads that would trigger major upgrades unable to be
delivered within the development time of the new load. This reduces the “lack of
available capacity” from presenting hurdles to economic development.

Support of adjacent supplies during maintenance outages i.e. operational headroom.
Where capacity is constrained, constraint on work practices and timing can increase
operational costs.

Tie capacity between feeders as a specific strategy for minimising unplanned outage
and restoration/response times.

Scanpower limits contingent capacity on each 11kV feeder to level that correlates to
the 5-10% voltage drop band. That is when voltage drop reaches 5% a feeder capacity
upgrade is triggered. For temporary situations such as new load connecting or
outages, Scanpower’s voltage standards relax to 10%
10.3.4 Alternative Solutions
The Dannevirke GXP has a 20MVA N-1 capacity and the Woodville GXP has a 10MVA N-1
capacity. Scanpower ‘s network is not able to fully distribute this capacity to its major load
centres as a result of the distance/voltage limitations at 11kV. No part of Scanpower’s
network is built to an N-1 Security Standard. The tie capacity between feeders is insufficient
to support a half bus shutdown at a GXP.
The fundamental issue is that the network has reached its design limitations without the
addition of a sub-transmission system to distribute bulk capacity closer to its load centres. To
develop a sub-transmission system is estimated to cost in the order of $15M and is not
considered a cost effective solution by Scanpower.
Consequently Scanpower must commit to an alternative development strategy. This strategy
has the following main approaches:

The 11kV network will be reconfigured to maximise capacity able to be delivered to
bussing points closer to load centres where voltage correction can be applied and
where N-1 security can also be delivered closer to major loads. The same
reconfiguration would be applied as part of the development of a sub-transmission
system so in the event of a very major new load forcing the need for sub-transmission,
the development can be adapted without loss of value.

To provide for new capacity, beyond the optimal configuration of the existing 11kV
network and the addition of voltage correction equipment, Scanpower will develop its
own portfolio of distributed generation, load management, and energy
Page 82 of 193
diversification/efficiency measures. Facilitating these alternatives not only reduces the
cost of providing line function services but competes with grid connected supply.
The initial tactic will be to install standby generator sets to secure major loads. This is not
only lower cost to securing supply with line solutions but it contributes to establishing a firm
generation base component for developing a distributed energy system on.
10.4 Planning Methodology
The following methodology has been adopted;
1. Review standards against company policies and objectives.
2. Determine conductor capacities.
3. Determine contingent capacity constraints for load growth and contingent support at
feeder tie points.
4. Analyse base load growth by feeder.
5. Identify load growth driven by econometric factors such as dairy conversion and
irrigation.
6. Identify new loads and projects such as industrial developments, sub-divisions,
generation, infrastructure upgrades, etc.
7. Project load growth on each feeder over the planning horizon to forecast when
constraints are likely to compromise standards.
8. Determine the optimal network reconfiguration to address issues identified. That is,
address the issue of the network’s past design no longer being optimal for its future load
characteristics.
9. Re-allocate the growth assumptions and projections across the reconfigured/optimal
network to identify which underlying development issues remain.
10. Investigate alternative development options. A risk assessment test is included to ensure
can invest, control, and manage alternatives such that they are able to be committed to
as a long term strategy.
11. Determine a development strategy and associated preferred solutions. This process
involves costing to determine which solution deliver the most economic and service
value at least cost over the long term.
12. The forecast is then projected with the preferred solutions deployed and the process
reiterated until sufficient development headroom is established, with sufficient flexibility
to meet potential development challenges arising in the medium term (10 year horizon).
13. The plans timeline is then adjusted for funding considerations.
Page 83 of 193
10.4.1 Limitations of the Planning Process
By virtue of the fact that forecasting involves extrapolating historical data into the future, the
NDP has accuracy limitations the further into the long term it is projected. Its long range
value is simply to avoid any development issues that may result in not being able to
sustainably meet Scanpower’s business objectives. For example, large load developments
are unlikely to be visible more than 3 years in advance.
Load forecasts are driven by peak demand data which may have very short load duration.
Where these peaks affect continuity of supply via protection trippings, then the applying peak
demand is a necessity. This results in a worst case forecast. Where there is good diversity or
low risk resulting from low duration of peak conditions some judgement on critically can be
made. However, Scanpower’s network is relatively small and fed directly from Transpower at
11kV. Accordingly there is a comparatively lower level of diversity and feeder profiles are
typically dominated by specific load groups, e.g. dairy sheds.
Forecast timetables are also quite limited particularly in the short term. It is based on long
term historical trend, whereas short-term economic and climatic conditions can create load
variance of as much as 40% in a single year. To address development lead-time issues
growth forecasts and timing to be optimistic which is a conservative approach. It is intended
that developments that prove to be premature can be deferred.
There is also a lower probability that all developments that are possible will ultimately be
developed. The plan however needs to demonstrate that they are catered for. Consequently
expenditure forecasts are likely to prove an overstatement. That is, the plan is optimistic.
10.5
Network Gap Analysis
10.5.1 Network Demand Profiles
The forecasting process starts from historical data points that are known and accurate. In
this case that data used as the 2012 starting points for each feeder are the monthly
maximum demand recorded on the Transpower GXP feeder breakers. These are not
diversified as the protection and operating limitations of each feeder function on the anytime
maximum demand.
The diversity at system level between feeders equates to approximately 17%. The diversity
between feeders with similar load characteristics is significantly less, given that the feeders
most likely to be used to support each, are adjacent to each other and therefore similar in
characteristics to each other, no diversity is assumed when planning at feeder level.
Plotting these monthly values provides the seasonal profile of each feeder and therefore
summating these profiles gives a system profile diversified on a monthly basis. In
Scanpower’s case the peak demand occurs during August. That is, traditional winter peak
with an early dairy season start. With the freezing works killing season extending for 11
months p.a. there is no longer a winter off-season to reduce the impact of peak winter
domestic heating demand. Summer irrigation load has not developed to the point where it is
driving summer peaking.
Page 84 of 193
Figure 18 – Maximum Loadings by Feeder (2011)
10.5.2 Contingent Capacity
The main backbone of Scanpower’s feeders is conductored with “Dog” ACSR (Aluminium
Conductor, Steel Reinforced). After de-rating for designed operating temperature, hot spots
such as connections, etc. Dog has a thermal (current related) capacity limit of 4.4MW.
In order for a feeder to carry contingent load of a GXP half-bus shutdown, N-1 design criteria
would target a maximum load of 2.2MW on each GXP feeder CB. The Dannevirke GXP bus
has 8 feeders distributing 19MW of transformer capacity i.e. 2.4MW each (4.8MW during
contingency) which is marginally over the thermal capacity of a feeder requiring load to be
balanced and diversity utilised to manage contingency.
However, Scanpower’s network has a radial configuration and no sub-transmission with
relatively fewer feeders than a more developed network. This means that not only are feeder
loads higher than typical 11kV feeders but the loads are relatively remote to the GXP and
not well interconnected. For example, the urban feeders have loads in the order of 2-3MW
located more than 6km away from the GXP with minimal distributed load along the way.
Page 85 of 193
Figure 19 – Contingent Capacity for Dog Conductor at 11kV
Contingent Capacity for Dog Overhead Conductor at 11kV Load MW (0.95pf) km to 5%VD km to 10%VD 1.0 14.0 28.0 2.0 7.0 14.0 3.0 4.7 9.4 4.0 3.5 7.0 5.0 2.8 5.6 6.0 2.3 4.7 Note: Thermal limit (MW) Summer @ 75degC 6.7 Derate 35% for connectors, lower operating temp., etc. 4.4 Therefore the 5% VD distance limit (km) at max. thermal rating is 3.2 As a consequence, the network is voltage constrained. That is, high currents over long
distances result in voltage drop that exceeds standards. For Dog conductor operated at
11kV the thermal 4.4MW capacity limit is constrained to 5% volt drop at a distance of only
3.2km.
Page 86 of 193
Table 19 – Contingent Capacity Calculations by Feeder
Feeder Central East Adelaide Max Demand Dist. To Load Growth Cap. MW km 5% VD 3.1 6.1 ‐0.7 2.3 2.8 6.1 6.7 0.1 ‐0.7 Primary Tie Dist. to Tie Contingent Load Thermal Limit Cont. Capacity Cont. Capacity km MW % OL 5%VD 10%VD ABS 21 – East 6.2 1.2 ‐2% ‐2.1 0.0 ABS15 ‐ Adelaide 7.6 1.4 3% ‐2.7 ‐0.8 ABS 21 ‐ Central 6.2 1.6 ‐12% ‐1.7 0.5 ABS182 ‐ Weber 7.5 2.0 ‐1% ‐2.4 ‐0.6 A19 ‐ Mangatera 7.3 1.3 ‐5% ‐2.4 ‐0.3 ABS15 ‐ Central 7.8 1.6 0% ‐2.6 ‐0.8 Weber 2.0 9.8 ‐0.4 ABS182 ‐ East 7.5 1.2 ‐28% ‐1.3 0.6 Mangatera 1.9 14.8 ‐1.0 A19 ‐ Adelaide 7.7 1.4 ‐24% ‐1.5 0.4 A105 ‐ North 14.8 1.9 ‐13% ‐2.9 ‐2.0 North 1.9 14.0 ‐0.9 A105 ‐ Mangatera 14.0 1.9 ‐13% VR's ‐1.8 Pacific 1.4 10.4 0.1 ABS35 ‐ Te Rehunga 6.8 1.1 ‐43% closed ring 0.3 Te Rehunga 1.1 4.0 2.4 ABS35 ‐ Pacific 4.0 1.4 ‐43% 1.0 1.9 Danevirke GXP 16.5 Diversified 14.1 117% Town 1 1.10 5.3 1.7 A106 ‐ Town 2 5.3 1.10 ‐49% 0.6 2.2 Country 0.90 5.3 1.9 A109 ‐ Town 1 5.3 1.10 ‐54% 0.8 2.4 Town 2 1.10 5.3 1.7 A106‐ Town 1 5.3 1.10 ‐49% 0.6 2.2 Woodville GXP 3.10 Diversified 2.8 111% Page 87 of 193
Analysis of voltage drop resulting during peak feeder demands and the additional demand
presented by neighbouring feeders at tie points during contingent events indicates that:

In normal conditions volt drop exceeds 5% during peak periods and the duration of the
excursion from this standard is increasing as load grows. The system is approaching
the limit in terms of Scanpower’s capability to manage this to acceptable limits.

There is minimal headroom for growth.

There is minimal contingent capacity for security during faults and for operational
outages necessary for upgrades to relieve such constraints.
These issues define the problem that the Network Development Planning process must
solve. Forecast load growth is projected against these constraints to determine when
upgrade is necessary.
Analysis shows that Scanpower has the following urgent development needs. That is, the
forecast starts from a position of constraint:

The Central Feeder which supplies the main commercial/retail centre of Dannevirke –
at 3.1MW 6.1km from the GXP it exceeds the 5% Volt Drop standard during peak
times. This will worsen with new developments currently in progress and it has no
contingent capacity to support either the Adelaide (urban residential load) or the East
Feeder (light industrial) during outages. Consequently there is also emerging gap with
respect to Scanpower’s security standards.

Similarly the load on the North Feeder has reached the voltage correction capability of
the Matamau Regulators. The regulators are limited in their capacity to 2MW, have a
limited boosting range of 10%, and limited resolution in tap steps at 2.5% (which is
visible and a quality issue for consumers).

The Weber Feeders main line extends 70km with no voltage correction. Supply of any
quality is only feasible if loads remain very small and their utilisation very low. This is
not likely to continue should dairy conversion increase its command area towards the
coast.
The current network configuration has reached the end of designed development potential
with regard to new load.
10.5.3 Growth Assumptions
Scanpower has a relatively small base load and is constrained. Accordingly, it can be
sensitive to new loads (even though they may be small in terms of modern installation
norms), triggering extensive upgrade requirements. Further, changing load demographics,
such an increase in more intensive dairy farming, displacing low intensity sheep farming, not
only changes the service expectations of consumers, but can increase peak demand (which
drives network upgrade) without necessarily presenting a high energy consumption, kWh,
growth.
Page 88 of 193
Table 20 – Load Growth Forecast Assumptions
Annual Demand Growth MW % 2011 1.10 6.97% 2012 0.54 3.78% Average 0.82 5.38% Base Load Component 0.43 2.82% Feeder 2012 Growth p.a. Central 3.10 0.09 East 2.30 0.06 Adelaide 2.80 0.08 Weber 2.00 0.06 Mangatera 1.90 0.05 North 1.90 0.05 Pacific 1.40 0.04 Te Rehunga 1.10 0.03 Dannevirke GXP 16.50 0.47 Town 1 1.10 0.03 Country 0.90 0.03 Town 2 1.10 0.03 Woodville GXP 3.10 0.09 Planned / Known New Developments ‐ 3 Year Projection Feeder Total 2013 2014 2015 Central 0.80 0.30 0.40 0.10 East 0.60 0.10 0.30 0.30 Adelaide 0.30 0.10 0.10 0.10 Weber 0.10 0.00 0.05 0.05 Mangatera 0.00 0.00 0.00 0.00 North 0.15 0.05 0.05 0.05 Pacific 0.30 0.10 0.10 0.10 Te Rehunga 0.00 0.00 0.00 0.00 Dannevirke GXP 2.25 0.65 1.00 0.70 Town 1 0.00 0.00 0.00 0.00 Country 0.00 0.00 0.00 0.00 Town 2 0.00 0.00 0.00 0.00 Woodville GXP 0.00 0.00 0.00 0.00 Page 89 of 193
Table 20 continued – Load Growth Forecast Assumptions
Dairy Growth Assumptions Total Sheds 237 Below 30kVA ‐ to be upgraded 151 Over 30kVA ‐ New/Upgraded 86 Quantity Per Unit MW New Sheds p.a. 3 0.075 0.225 Shed Upgrades p.a. 2 0.045 0.090 Total 5 0.120 0.315 N.B New/upgraded sheds have been installed over 17 year period = 5 p.a. This load is concentrated on the Te Rehunga, North/Mangatera, Country There is potential for sheep to dairy conversion on the Weber feeder between the Manawatu River and Puketoi Range Irrigation Growth Assumptions Scanpower has 2MW of dedicated Irrigation Pump load averaging 75kW per connection / 1 new connection p.a. No. Per Unit MW New Pumps 1 0.075 Total 1 0.075 MW 0.075 Scanpower’s average peak demand growth over the past two years has been 5.38% p.a.
There has been a strong recovery from loss of the Oringi Freezing Works. This event has
been masking recent growth figures. Demand has since recovered and is forecast to
continue growth at this rate.
To prevent error in growth rates compounding absolute MW figures are applied. Firstly, the
base load growth assumption is determined to be 2.82% which equates to 0.43MW p.a.
proportioned across each feeder.
Any new and specific loads known are added in the year they are expected. This is only
projected for 3 years because it is unlikely Scanpower gets any longer warning and three
years is sufficient time to adjust and implement plans for new loads undisclosed.
Loads such as dairy conversion and irrigation can be predicted from historical trends and
econometric data. For example, assessing the trend in the number of Ha of dairy conversion
p.a. and the electricity consumption per Ha of irrigation.
10.5.4 Load Forecast Baseline
The baseline forecast takes the above data and builds a model projecting cumulating load
growth for each feeder over 20 years to identify which year the network in its existing state
would fall short of service standards.
Page 90 of 193
The Dannevirke GXP is constrained by its N-1 capacity of 19MW by 2018 and will require an
additional 10MW of capacity by the end of the 20 year planning horizon. Note however this
assumes all modelled loads and all feeders eventuate as forecast.
The challenge this issue raises is that if Scanpower were to opt to develop a subtransmission system to resolve voltage constraint on its network (the GXP transformers have
33kV tappings) the GXP would also need significant upgrade. In addition to the $15M of
33kV network development the GXP would require another $10M of new investment. This
path is not likely to meet affordability limitations and Scanpower would be at risk of its
consumers migrating to non-grid supply, stranding the investment.
The ultimate value proposition for the existing transmission assets is to change their
utilisation from off-take connection assets to injection connection assets. That is, as grid
injection point for distributed generation of up to 40MW above network load.
The baseline forecast shows that following feeders exceed their 5% voltage constraint now
(2012) Weber, Managatera, Central, Adelaide. The East feeder becomes constrained in
2014, Pacific in 2015, and Te Rehunga in 2021. That is, every feeder on the Dannevirke
GXP within the 10 year planning horizon of the Asset Management Plan. At current growth
forecasts no issues are visible for any feeders on the Woodville GXP.
Page 91 of 193
Table 21 – Load Growth Forecasts by Feeder
Dannevirke Feeders
Weber Constraint 5%VD Constraint 10%VD Year Starting Load Base Load Growth Development Dairy/Irrigation Load Shifted From Load Shifted To Year Ending Load 2012 1.60 3.75 2.00 0.06 2013 1.60 3.75 2.14 0.06 2014 1.60 3.75 2.20 0.06 0.05 2015 1.60 3.75 2.31 0.06 0.05 2016 1.60 3.75 2.42 0.06 0.08 2.14 2017 1.60 3.75 2.48 0.06 2018 1.60 3.75 2.61 0.06 2019 1.60 3.75 2.67 0.06 2020 1.60 3.75 2.73 0.06 2021 1.60 3.75 2.79 0.06 0.08 2.20 2.31 2.42 2.48 2.61 2022 1.60 3.75 2.85 0.06 2023 1.60 3.75 2.99 0.06 2024 1.60 3.75 3.05 0.06 2025 1.60 3.75 3.11 0.06 2026 1.60 3.75 3.17 0.06 0.08 2027 1.60 3.75 3.23 0.06 2028 1.60 3.75 3.36 0.06 2029 1.60 3.75 3.42 0.06 2030 1.60 3.75 3.48 0.06 2031 1.60 3.75 3.54 0.06 0.08 2.67 2.73 2.79 2.85 2.99 3.05 3.11 3.17 3.23 3.36 3.42 3.48 3.54 3.60 2031 0.90 3.70 4.28 0.05 Mangatera Constraint 5%VD Constraint 10%VD Year Starting Load Base Load Growth Development Dairy/Irrigation Load Shifted From Load Shifted To Year Ending Load 2012 0.90 3.70 1.90 0.05 2013 0.90 3.70 2.00 0.05 2014 0.90 3.70 2.20 0.05 2015 0.90 3.70 2.29 0.05 2016 0.90 3.70 2.42 0.05 2017 0.90 3.70 2.51 0.05 2018 0.90 3.70 2.64 0.05 2019 0.90 3.70 2.81 0.05 2020 0.90 3.70 2.93 0.05 2021 0.90 3.70 3.03 0.05 2022 0.90 3.70 3.15 0.05 2023 0.90 3.70 3.25 0.05 2024 0.90 3.70 3.45 0.05 2025 0.90 3.70 3.54 0.05 2026 0.90 3.70 3.67 0.05 2027 0.90 3.70 3.76 0.05 2028 0.90 3.70 3.89 0.05 2029 0.90 3.70 4.06 0.05 2030 0.90 3.70 4.18 0.05 0.05 0.15 0.05 0.08 0.05 0.08 0.12 0.08 0.05 0.08 0.05 0.15 0.05 0.08 0.05 0.08 0.12 0.08 0.05 2.00 2.20 2.29 2.42 2.51 2.64 2.81 2.93 3.03 3.15 3.25 3.45 3.54 3.67 3.76 3.89 4.06 4.18 4.28 4.33 Central Constraint 5%VD Constraint 10%VD Year Starting Load Base Load Growth Development Dairy/Irrigation Load Shifted From Load Shifted To Year Ending Load 2012 2.40 4.30 3.10 0.09 2013 2.40 4.30 3.19 0.09 0.30 2014 2.40 4.30 3.58 0.09 0.40 2015 2.40 4.30 4.07 0.09 0.10 2016 2.40 4.30 4.26 0.09 2017 2.40 4.30 4.35 0.09 2018 2.40 4.30 4.44 0.09 2019 2.40 4.30 4.53 0.09 2020 2.40 4.30 4.62 0.09 2021 2.40 4.30 4.71 0.09 2022 2.40 4.30 4.80 0.09 2023 2.40 4.30 4.89 0.09 2024 2.40 4.30 4.98 0.09 2025 2.40 4.30 5.07 0.09 2026 2.40 4.30 5.16 0.09 2027 2.40 4.30 5.25 0.09 2028 2.40 4.30 5.34 0.09 2029 2.40 4.30 5.43 0.09 2030 2.40 4.30 5.52 0.09 2031 2.40 4.30 5.61 0.09 3.19 3.58 4.07 4.26 4.35 4.44 4.53 4.62 4.71 4.80 4.89 4.98 5.07 5.16 5.25 5.34 5.43 5.52 5.61 5.70 Page 92 of 193
Table 21 continued – Load Growth Forecasts by Feeder
Pacific Constraint 5%VD Constraint 10%VD Year Starting Load Base Load Growth Development Dairy/Irrigation Load Shifted From Load Shifted To Year Ending Load Bus Section 1
(non diversified)
Bus Section 2
(non diversified)
East Constraint 5%VD Constraint 10%VD Year Starting Load Base Load Growth Development Dairy/Irrigation Load Shifted From Load Shifted To Year Ending Load 2012 1.50 2.80 1.40 0.04 2013 1.50 2.80 1.44 0.04 0.20 2014 1.50 2.80 1.68 0.04 0.05 2015 1.50 2.80 1.77 0.04 0.05 2016 1.50 2.80 1.86 0.04 2017 1.50 2.80 1.90 0.04 2018 1.50 2.80 1.94 0.04 2019 1.50 2.80 1.98 0.04 2020 1.50 2.80 2.02 0.04 2021 1.50 2.80 2.06 0.04 2022 1.50 2.80 2.10 0.04 2023 1.50 2.80 2.14 0.04 2024 1.50 2.80 2.18 0.04 2025 1.50 2.80 2.22 0.04 2026 1.50 2.80 2.26 0.04 2027 1.50 2.80 2.30 0.04 2028 1.50 2.80 2.34 0.04 2029 1.50 2.80 2.38 0.04 2030 1.50 2.80 2.42 0.04 2031 1.50 2.80 2.46 0.04 1.44 1.68 1.77 1.86 1.90 1.94 1.98 2.02 2.06 2.10 2.14 2.18 2.22 2.26 2.30 2.34 2.38 2.42 2.46 2.50 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 8.76 9.65 10.44 10.95 11.24 11.63 11.99 12.30 12.59 12.90 13.26 13.65 13.94 14.25 14.54 14.93 15.29 15.60 15.89 16.13 8.52 9.15 10.09 11.00 11.42 11.80 12.22 12.68 13.17 13.55 13.97 14.35 14.84 15.30 15.72 16.10 16.52 16.98 17.47 17.71 2012 2.40 4.30 2.30 0.06 2013 2.40 4.30 2.36 0.06 0.10 2014 2.40 4.30 2.52 0.06 0.30 2015 2.40 4.30 2.88 0.06 0.30 2016 2.40 4.30 3.24 0.06 2017 2.40 4.30 3.30 0.06 2018 2.40 4.30 3.36 0.06 2019 2.40 4.30 3.42 0.06 2020 2.40 4.30 3.48 0.06 2021 2.40 4.30 3.54 0.06 2022 2.40 4.30 3.60 0.06 2023 2.40 4.30 3.66 0.06 2024 2.40 4.30 3.72 0.06 2025 2.40 4.30 3.78 0.06 2026 2.40 4.30 3.84 0.06 2027 2.40 4.30 3.90 0.06 2028 2.40 4.30 3.96 0.06 2029 2.40 4.30 4.02 0.06 2030 2.40 4.30 4.08 0.06 2031 4.89 4.30 4.14 0.04 2.36 2.52 2.88 3.24 3.30 3.36 3.42 3.48 3.54 3.60 3.66 3.72 3.78 3.84 3.90 3.96 4.02 4.08 4.14 4.18 Page 93 of 193
North Constraint 5%VD Constraint 10%VD Year Starting Load Base Load Growth Development Dairy/Irrigation Load Shifted From Load Shifted To Year Ending Load 2012 1.00 2.00 1.90 0.05 2014 1.00 2.00 2.17 0.05 0.05 0.15 2015 1.00 2.00 2.42 0.05 0.05 0.05 2016 1.00 2.00 2.57 0.05 2017 1.00 2.00 2.69 0.05 2018 1.00 2.00 2.79 0.05 2019 1.00 2.00 2.91 0.05 2020 1.00 2.00 3.08 0.05 2021 1.00 2.00 3.21 0.05 2022 1.00 2.00 3.30 0.05 2023 1.00 2.00 3.43 0.05 2024 1.00 2.00 3.52 0.05 2025 1.00 2.00 3.72 0.05 2026 1.00 2.00 3.82 0.05 2027 1.00 2.00 3.94 0.05 2028 1.00 2.00 4.04 0.05 2029 1.00 2.00 4.16 0.05 2030 1.00 2.00 4.33 0.05 2031 1.00 2.00 4.46 0.05 0.08 2013 1.00 2.00 2.03 0.05 0.05 0.05 0.08 0.05 0.08 0.12 0.08 0.05 0.08 0.05 0.15 0.05 0.08 0.05 0.08 0.12 0.08 0.05 2.03 2.17 2.42 2.57 2.69 2.79 2.91 3.08 3.21 3.30 3.43 3.52 3.72 3.82 3.94 4.04 4.16 4.33 4.46 4.55 Adelaide Constraint 5%VD Constraint 10%VD Year Starting Load Base Load Growth Development Dairy/Irrigation Load Shifted From Load Shifted To Year Ending Load 2012 2.10 3.80 2.80 0.08 2013 2.10 3.80 2.88 0.08 0.10 2014 2.10 3.80 3.06 0.08 0.10 2015 2.10 3.80 3.24 0.08 0.10 2016 2.10 3.80 3.42 0.08 2017 2.10 3.80 3.50 0.08 2018 2.10 3.80 3.58 0.08 2019 2.10 3.80 3.66 0.08 2020 2.10 3.80 3.74 0.08 2021 2.10 3.80 3.82 0.08 2022 2.10 3.80 3.90 0.08 2023 2.10 3.80 3.98 0.08 2024 2.10 3.80 4.06 0.08 2025 2.10 3.80 4.14 0.08 2026 2.10 3.80 4.22 0.08 2027 2.10 3.80 4.30 0.08 2028 2.10 3.80 4.38 0.08 2029 2.10 3.80 4.46 0.08 2030 2.10 3.80 4.54 0.08 2031 2.10 3.80 4.62 0.08 2.88 3.06 3.24 3.42 3.50 3.58 3.66 3.74 3.82 3.90 3.98 4.06 4.14 4.22 4.30 4.38 4.46 4.54 4.62 4.70 Te Rehunga Constraint 5%VD
Constraint 10%VD
Year Starting Load
Base Load Growth
Development Dairy/Irrigation Load Shifted From
Load Shifted To Year Ending Load
2012
2.40
4.40
1.10
0.03
2013 2.40 4.40 1.25 0.03 2014 2.40 4.40 1.40 0.03 2015
2.40
4.40
1.55
0.03
2016
2.40
4.40
1.78
0.03
2017
2.40
4.40
1.93
0.03
2018
2.40
4.40
2.08
0.03
2019
2.40
4.40
2.23
0.03
2020
2.40
4.40
2.38
0.03
2021
2.40
4.40
2.60
0.03
2022 2.40 4.40 2.75 0.03 2023
2.40
4.40
2.90
0.03
2024
2.40
4.40
3.05
0.03
2025
2.40
4.40
3.20
0.03
2026
2.40
4.40
3.43
0.03
2027
2.40
4.40
3.58
0.03
2028
2.40
4.40
3.73
0.03
2029
2.40
4.40
3.88
0.03
2030 2.40 4.40 4.03 0.03 2031 2.40 4.40 4.25 0.03 0.12
0.12 0.12 0.20
0.12
0.12
0.12
0.12
0.20
0.12
0.12 0.12
0.12
0.20
0.12
0.12
0.12
0.12
0.20 1.25
1.40 1.55 1.78
1.93
2.08
2.23
2.38
2.60
2.75
2.90 3.05
3.20
3.43
3.58
3.73
3.88
4.03
4.25 4.28 Page 94 of 193
Total (Dannevirke) Constraint N‐1 Year Starting Load Base Load Growth Development
Dairy/Irrigation Load Shifted From Load Shifted To Year Ending Load 2012 20.00 14.10 0.43 0.00 0.32 0.00 0.00 14.85 2013 20.00 14.85 0.43 0.45 0.32 0.00 0.00 16.04 2014 20.00 16.04 0.43 0.55 0.32 0.00 0.00 17.34 2015 20.00 17.34 0.43 0.55 0.32 0.00 0.00 18.63 2016 20.00 18.63 0.43 0.00 0.24 0.00 0.00 19.30 2017 20.00 19.30 0.43 0.00 0.32 0.00 0.00 20.05 2018 20.00 20.05 0.43 0.00 0.32 0.00 0.00 20.79 2019 20.00 20.79 0.43 0.00 0.32 0.00 0.00 21.54 2020 20.00 21.54 0.43 0.00 0.32 0.00 0.00 22.28 2021 20.00 22.28 0.43 0.00 0.24 0.00 0.00 22.95 2022 20.00 22.95 0.43 0.00 0.32 0.00 0.00 23.70 2023 20.00 23.70 0.43 0.00 0.32 0.00 0.00 24.44 2024 20.00 24.44 0.43 0.00 0.32 0.00 0.00 25.19 2025 20.00 25.19 0.43 0.00 0.32 0.00 0.00 25.93 2026 20.00 25.93 0.43 0.00 0.24 0.00 0.00 26.60 2027 20.00 26.60 0.43 0.00 0.32 0.00 0.00 27.35 2028 20.00 27.35 0.43 0.00 0.32 0.00 0.00 28.09 2029 20.00 28.09 0.43 0.00 0.32 0.00 0.00 28.84 2030 20.00 28.84 0.43 0.00 0.32 0.00 0.00 29.58 2031 20.00 29.58 0.35 0.00 0.05 0.00 0.00 29.98 Town 1 Constraint 5%VD Constraint 10%VD Year Starting Load Base Load Growth Development Dairy/Irrigation Load Shifted From Load Shifted To Year Ending Load 2012 2.80 4.40 1.10 0.03 2013 2.80 4.40 1.13 0.03 2014 2.80 4.40 1.16 0.03 2015 2.80 4.40 1.19 0.03 2016 2.80 4.40 1.22 0.03 2017 2.80 4.40 1.25 0.03 2018 2.80 4.40 1.28 0.03 2019 2.80 4.40 1.31 0.03 2020 2.80 4.40 1.34 0.03 2021 2.80 4.40 1.37 0.03 2022 2.80 4.40 1.40 0.03 2023 2.80 4.40 1.43 0.03 2024 2.80 4.40 1.46 0.03 2025 2.80 4.40 1.49 0.03 2026 2.80 4.40 1.52 0.03 2027 2.80 4.40 1.55 0.03 2028 2.80 4.40 1.58 0.03 2029 2.80 4.40 1.61 0.03 2030 2.80 4.40 1.64 0.03 2031 2.80 4.40 1.67 0.03 1.13 1.16 1.19 1.22 1.25 1.28 1.31 1.34 1.37 1.40 1.43 1.46 1.49 1.52 1.55 1.58 1.61 1.64 1.67 1.70 Country Constraint 5%VD Constraint 10%VD Year Starting Load Base Load Growth Development Dairy/Irrigation Load Shifted From Load Shifted To Year Ending Load 2012 2.80 4.40 0.90 0.03 2013 2.80 4.40 1.01 0.03 2014 2.80 4.40 1.11 0.03 2015 2.80 4.40 1.22 0.03 2016 2.80 4.40 1.32 0.03 2017 2.80 4.40 1.50 0.03 2018 2.80 4.40 1.61 0.03 2019 2.80 4.40 1.71 0.03 2020 2.80 4.40 1.82 0.03 2021 2.80 4.40 1.92 0.03 2022 2.80 4.40 2.03 0.03 2023 2.80 4.40 2.13 0.03 2024 2.80 4.40 2.24 0.03 2025 2.80 4.40 2.34 0.03 2026 2.80 4.40 2.45 0.03 2027 2.80 4.40 2.55 0.03 2028 2.80 4.40 2.66 0.03 2029 2.80 4.40 2.76 0.03 2030 2.80 4.40 2.87 0.03 2031 2.80 4.40 2.97 0.03 0.08 0.08 0.08 0.08 0.15 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 1.01 1.11 1.22 1.32 1.50 1.61 1.71 1.82 1.92 2.03 2.13 2.24 2.34 2.45 2.55 2.66 2.76 2.87 2.97 3.08 Woodville Feeders
Page 95 of 193
Town 2 Constraint 5%VD Constraint 10%VD Year Starting Load Base Load Growth Development Dairy/Irrigation Load Shifted From Load Shifted To Year Ending Load 2012 2.80 4.40 1.10 0.03 2013 2.80 4.40 1.13 0.03 2014 2.80 4.40 1.16 0.03 2015 2.80 4.40 1.19 0.03 2016 2.80 4.40 1.22 0.03 2017 2.80 4.40 1.25 0.03 2018 2.80 4.40 1.28 0.03 2019 2.80 4.40 1.31 0.03 2020 2.80 4.40 1.34 0.03 2021 2.80 4.40 1.37 0.03 2022 2.80 4.40 1.40 0.03 2023 2.80 4.40 1.43 0.03 2024 2.80 4.40 1.46 0.03 2025 2.80 4.40 1.49 0.03 2026 2.80 4.40 1.52 0.03 2027 2.80 4.40 1.55 0.03 2028 2.80 4.40 1.58 0.03 2029 2.80 4.40 1.61 0.03 2030 2.80 4.40 1.64 0.03 2031 2.80 4.40 1.67 0.03 1.13 1.16 1.19 1.22 1.25 1.28 1.31 1.34 1.37 1.40 1.43 1.46 1.49 1.52 1.55 1.58 1.61 1.64 1.67 1.70 Total (Woodville)
Constraint N‐1 Year Starting Load
Base Load Growth
Development
Dairy/Irrigation Load Shifted From
Load Shifted To Year Ending Load
2012
10.00
2.80
0.09
0.00
0.08
0.00
0.00
2.97
2013 10.00 2.97 0.09 0.00 0.08 0.00 0.00 3.13 2014 10.00 3.13 0.09 0.00 0.08 0.00 0.00 3.30 2015
10.00
3.30
0.09
0.00
0.08
0.00
0.00
3.46
2016
10.00
3.46
0.09
0.00
0.15
0.00
0.00
3.70
2017
10.00
3.70
0.09
0.00
0.08
0.00
0.00
3.87
2018
10.00
3.87
0.09
0.00
0.08
0.00
0.00
4.03
2019
10.00
4.03
0.09
0.00
0.08
0.00
0.00
4.20
2020
10.00
4.20
0.09
0.00
0.08
0.00
0.00
4.36
2021
10.00
4.36
0.09
0.00
0.08
0.00
0.00
4.53
2022 10.00 4.53 0.09 0.00 0.08 0.00 0.00 4.69 2023
10.00
4.69
0.09
0.00
0.08
0.00
0.00
4.86
2024
10.00
4.86
0.09
0.00
0.08
0.00
0.00
5.02
2025
10.00
5.02
0.09
0.00
0.08
0.00
0.00
5.19
2026
10.00
5.19
0.09
0.00
0.08
0.00
0.00
5.35
2027
10.00
5.35
0.09
0.00
0.08
0.00
0.00
5.52
2028
10.00
5.52
0.09
0.00
0.08
0.00
0.00
5.68
2029
10.00
5.68
0.09
0.00
0.08
0.00
0.00
5.85
2030 10.00 5.85 0.09 0.00 0.08 0.00 0.00 6.01 2031 10.00 6.01 0.09 0.00 0.08 0.00 0.00 6.18 Page 96 of 193
10.5.5 Network Optimisation
Before consideration is given to upgrading the network with additional lines, heavier
conductor, etc. which is expensive, Scanpower will optimise utilisation of existing assets by
reconfiguring the network into a more efficient structure.
Scanpower’s existing feeder structure is long and radial, relatively highly load, relatively few
feeders, with limited tie points, located at distances too remote for the capacity they are
capable of supporting. For example, there is a tie point between Norsewood on the North
feeder and Ormondville on the Mangatera feeder. The North feeder is unable to support the
Ormondville load because it has a constraint on its voltage regulators and also Mangatera
has no voltage regulators so there is voltage mismatch at the tie point. The Mangatera
feeder supplies the Alliance Works and so most of its capacity is consumed well before
Ormondville i.e. it cannot deliver sufficient tie capacity to support Norsewood.
These issues can be relieved by:

Segmenting the remote feeder ends of the network into smaller sub-feeders with
smaller loads to be supported during contingent events. Smaller loads over shorter
distances equates to more capacity. This also reduces the number of customers
affected by an outage improving outage statistics.

Reconfiguring the front end of feeders to act as incomers to bussing points which
branch out to the sub-feeders. This concept will have a structure similar to a subtransmission system. It provides a point to which voltage correction equipment can be
applied efficiently, improving the capacity of the downstream network and enabling the
front end of the network to be driven harder because it is not so limited by line load
regulation. This solution has a low risk in that, should it ever prove necessary to
develop a sub-transmission, the bussing points can effectively be reused as zone
substations.
With more sub-feeders, an increased number of tie points (interconnections) can be
provisioned, increasing the meshing of the network and therefore its operational flexibility
with regard to contingent events. One advantage of this is that it is possible to extend N-1
security to the Dannevirke CBD and increase the N-1 capacity by redeploying 3 feeders as
parallel incomers to a bussing point.
Bussing points (11kV switching stations) also provide an opportunity to increase the
automation on the network facilitating improved security measures and concentrating load
for application of standby generation.
Scanpower has determined the following switching stations and network reconfigurations
can be achieved with minimal line build:

Develop the Matamau Volt Regulator site on the North feeder as switching station with
three feeders replacing the existing regulator with a bigger 3MVA 3 phase (eliminating
harmonic issues with 2 phase boosting) arrangement recovered from the Oringi site.
Page 97 of 193

Develop a new Dannevirke North switching station on the Mangatera feeder with three
sub-feeders segmenting Adelaide load into three blocks and separating the Alliance
site from rural load.

Develop a new 6 feeder, 3 incomer, 3 bus section Dannevirke South switching station
capable of delivering 8.1MW of N-1 firm capacity (the existing 3 feeders have no or
little N level contingent capacity).

Redeploy the Oringi site 11kV switchboard as a bussing point that feeds back out onto
the network. This will require some short line connections to be built.

The Weber feeder is currently very large in terms of km of line and area of the network
serviced. However it consists of two main branches which can be split into separate
feeeders by redeploying the Pacific CB and one of the old incoming circuits to Oringi.
This only requires a few km of line build. The existing Oringi connection will remain as
a backup supply.
Provided below are line schematics of the existing and proposed line configurations in
respect of the Matamau, Dannevirke North, Dannevirke South and Oringi switching stations.
Page 98 of 193
Page 99 of 193
Page 100 of 193
Page 101 of 193
Page 102 of 193
Page 103 of 193
Page 104 of 193
Page 105 of 193
Page 106 of 193
10.5.6 Other Lines Solutions Considered
In addition to developing a sub-transmission which has been excluded on the grounds of
affordability and the risk of stranding, Scanpower has considered the following lines
solutions to distributing more capacity:

Developing an additional GXP nearer to Norsewood approximately 20km north of the
Dannevirke GXP. This option is estimated to cost in order of $10M for the GXP and an
additional $5M for feeder development on Scanpower’s network. Not only is this a
more expensive option, with a more lumpy investment profile, it is not a
comprehensive solution for the entire network covering the range of development
paths that may occur. It also cannot be delivered by Transpower within the timeframes
necessary. However the decision to exclude this option was based on the risk of
investing in transmission asset.

Increasing the voltage standard on parts of the constrained feeders to 22kV. This is a
viable option for the first 6km of the East and Central feeders which have relative few
transformers to be upgraded. It is far less viable for Scanpower’s longer rural feeders.
Each feeder upgraded would require a pair of auto-transformers to step voltage up at
the GXP and then down again at the other end. They would need to be sized to deliver
contingent capacity and therefore are a more expensive option ($800,000 versus
$150,000) compared to a single stage of 11kV Voltage Regulators as proposed. The
same development in regard of bussing points and switching stations would still be
required. This option remains as a contingency for addressing any new large industrial
loads that may arise but are not forecast.
Capacity has been reassessed and load forecast allocated across the proposed network
segments per the tables below:
Table 22 – Reassessment of Feeder Capacity Across Reconfigured Network
Network Reconfiguration Strategy and Objectives 
Create Bussing points to which voltage correction can be applied ‐ increasing capacity. 
Establish sub‐feeders to segment load into smaller load blocks ‐ creating more interconnection and contingency provisions. 
Create network configuration to which enhanced protection and DA can be applied ‐ enhance security. 
Reduce the size of feeders and balance load by shifting open points ‐ reduces sensitivity to outage. 
Bring N‐1 security into the CBD ‐ Dannevirke South Bus. Page 107 of 193
Table 22 continued – Reassessment of Feeder Capacity Across Reconfigured Network
Matamau 11kV Bus with 3MVA 15% Voltage Regulators Incomer North Sub‐Feeder Norsewood Ormandville Otanga Load Allocation Bus Constraint 10% VD Tie 0.5 2.0 Alliance or Okarae Ormandville Norsewood Alliance or Okarae Load Allocation Bus Constraint 10% VD Tie 3.5 Ex North ‐ GXP to Matamau Ex North ‐ Matamau to Norsewood Ex Mangatera ‐ part Ex Weber ‐ part Ex Mangatera ‐ Alliance to Matamau Dannevirke North 11kV Bus 1.2 0.5 0.15 Incomer Mangatera GXP to Smith/Adelaid 0.1 Sub‐Feeder Alliance Alliance plus Umu Ex North ‐
part 1.3 Otanga Sub‐Feeder Ruahine Ex Adelaide ‐ part 0.75 Waterloo Sub‐Feeder Cole Ex Adelaide ‐ part 0.75 Adelaide Load Allocation Dannevirke South 11kV Bus ‐ tri section Sub‐Feeder Demark Ex Central ‐ part 2.32 Incomer 1 Weber Laws ‐ Ex Weber ‐ part 0.03 Sub‐Feeder CSL 1 Ex East ‐ dedicated feeder 0.37 Sub‐Feeder Waterloo Ex East & Central ‐ part 1.13 Incomer 2 Central Sub‐Feeder Okarae Ex Weber ‐ part 0.17 Sub‐Feeder CSL 2 Ex East ‐ dedicated feeder 0.37 Incomer 3 East Sub‐Feeder Easton Bus Constraint 10% VD 8.6 @N‐1 Tie Waterloo or Adelaide Incomers 2 and 3 N‐1 with CSL2 Bus Section 0 8.1 @N‐1 Central or Easton Incomers 1 and 3 Easton or Weber Bus Section 0 Ex East ‐ part 0.78 8.1 @N‐1 N‐1 with CSL1 Incomers 1 and 2 Waterloo or Okarae Page 108 of 193
Table 22 continued – Reassessment of Feeder Capacity Across Reconfigured Network
Change to Adelaide Feeder Loading MW Original 2.8 Shift to Cole ‐0.75 Shift to Ruahine ‐0.75 Shift from Central 0.43 New 1.73 Split Weber into 2 Feeders (interconnecting and redeploying into Pacific Feeder) MW Pacific Redeployed as main feeder to Weber 1.32 Weber Less load split to Okarae 0.35 Okarae Split from Weber 0.17 Oringi 11kV Bus ‐ redeploy Works switchboard as network feeders MW Incomer 1 Te Rehunga 0.52 Sub‐Feeder Kiritaki 0.42 Sub‐Feeder Gaisford 0.12 Sub‐Feeder Oringi 0.14 Sub‐Feeder OCS 0.5 Incomer 2 Pacific Branch Te Rehunga Open ‐ redployed for Weber 0.48 10.5.7 Optimised Network Load Forecast
Altering the networks configuration resets the baseline forecast by:

Relieving assumptions on constraints

Relieving security issues

Providing more options and flexibility for solving issues going forward

Altering the timing for which developments are triggered.
the reconfigured network essentially adds another 14 CBs supplying sub-feeders to the 11
GXP feeder CBs. This distributes feeder capacity to a finer resolution relieving the current
and short term constraints highlighted in the base forecast. No sub-feeders have constraints
over the AMP planning horizon. The bussing points will develop voltage constraints as load
grows however this can be managed by adding voltage correction to the network as
necessary and standby generation as customised security solutions for larger consumers
where the higher degree of interconnection is still unable to deliver sufficient contingent
capacity.
Page 109 of 193
10.5.8 Security
The existing network does not have sufficient contingent capacity to meet security standards
(old and new) during peak loading periods. It is a specific issue in the CBD and for larger
industrial consumers. It is also an issue for highly loaded residential feeders in Dannevirke
but to a lesser degree because the economic impact of outage is lower. The magnitude of
this gap, in the amount of contingent capacity needed and duration over which there is a
shortfall, continues to grow quickly (inherently twice the pace of load growth).
Security to date has not been an issue, firstly because of the low probability of faults on
these parts of Scanpower’s network, and secondly, because the there is an even lower
probability that they occur during a constraint or peak load period. With growing levels of
constraint and longer duration/low diversification of peak load, these probabilities are
changing rapidly and therefore have been analysed as to what specific security provisions
are necessary to address specific emerging issues.
The first priorities are Scanpower’s larger connections. When analysing a specific site it is
often determined that full N-1 contingency is not needed for the sites peak load because only
a fraction of the peak load is critical to sustaining economic production. Providing security on
a global basis from one end of a feeder to the other is very inefficient in this regard.
Further, security is not delivered at the point of consumption so a generator supplying the
switchboard on site delivers higher security than a second transformer at the GXP which
only delivers N-1 security as far as the GXP – to get N-1 security all the way to the
installation requires duplicate lines and distribution equipment.
N-1 transmission security costs approximately $1500/kW and N-1 distribution security costs
approximately $1400/kW, whereas a generator set only costs in the order of $400/kW. It has
a higher operating cost but ideally runs for only very limited periods – this cost is
comparable, for example, to the magnetising losses of a transformer sitting in standby and
the energy sale recovers a significant component of its operating cost. In this regard it is
same as investing in duplicate or over capacity distribution equipment – it is a redundant
asset that is not required make a return but rather is an insurance that the remaining network
assets continue to deliver line function services, earning for Scanpower, and supporting
economic production.
While a generator set is a viable alternative to a lines solution for security provision and
needs no further justification, it has a number of additional benefits:

The generation can back-feed into the network and if sized adequately can maintain
supply to islands of the network isolated by a fault.

Some industrial processes are able to the host the generator and utilise its waste heat.
This can increase the efficiency/lower the energy cost to a level that allows the
generator to compete with grid supplied energy for peak periods.

It provides the consumer with a physical form energy hedge.

It can support voltage during periods of constraint.
Page 110 of 193

It can be applied to load management.

It can be applied to managing transmission constraint and costs.

Where there is excess capacity in other energy networks such as gas, it can use the
alternative fuel to improve the infrastructure utilisation of both networks. Gas has a
lower cost than diesel and so generation is competitive for longer periods.
At a strategic level, it contributes to a more diverse business model for Scanpower, and
forms a foundation of firm generation capacity to underpin a DG Strategy. This same
foundation supports consumer lead initiatives to lower their cost of supply by investing in
non-grid solutions such PV panels, solar HW, etc.
Accordingly, for the planning period associated with this Plan, Scanpower will be applying
generation solutions to secure key installations, and thereby initiate the entry level
development of a DG Strategy with the objective avoiding the necessity for transmission and
sub-transmission investment in the long term.
Scanpower has a preference to own and operate the plant as many of the benefits able to
be derived are dependent on Scanpower coordinating the generation with its network load
management. It also considers that provision security to a defined standard for the greater
community’s good is its obligation.
Scanpower is targeting the provisioning security to the following load groups:

Key Economic Contributors: - The five largest consumers (all industrial scale
producers) plus a factory at Norsewood (9th largest). Generation is sized on the basis
of their average kW demand per hour plus an allowance for supporting the local
community nearby.

Rural Communities: The Weber and Ormondville are the largest and most remote
communities not supported by nearby security provisions. These generator sets will be
mobile for utilisation at other locations if warranted – for example planned shutdown for
line rebuilds.

ICPs with CDEM significance: In a Civil Defence Emergency and/or a major storm
response, Scanpower, specifically for external work crews involved in the response
and the wider community in general, may need fuel supply, food supply,
accommodation, and hospitality (cooking) facilities. A selected number of such
facilities will be targeted for installation of small generation sets. Scanpower will seek
to ensure these generators have the necessary controls and protection to enable them
to operate to their capacity within a dynamic DG enabled network.

Dairy Sheds: Scanpower has 86 modern sheds with an average demand of 75kW.
Dairy sheds have poor diversity – they all milk at the same – and high load factors
when they are milking. Accordingly they are a challenge to secure at network level but
relatively easy to secure with generators. Loss of supply to a dairy shed can result in
animal welfare issues, reduced production and environmental issues. They have
different service requirements than the original land use the network was designed to
support. Scanpower plans to engineer turnkey solutions and lease generators to these
businesses.
Page 111 of 193
For the purposes of this, plans forecasting installation of generators covering the first 3
groups has been scheduled in accordance with where they will provide the most benefit in
terms of load growth.
Other alternatives for reducing demand, such as PV and solar hot water, are in the process
of research and development of a commercial model. Specifically Scanpower seeks
solutions for improving the demand profiles/energy efficiency of dairy sheds. These
alternatives are not developed sufficiently to be committed to as part of the Scanpower
network development strategy and so do not form part of the forecast at this time.
Table 23 – Summary of Security Strategy for Significant ICPs
Security of Individual Top ICP's Objectives and Strategy 
Secure Key ICP's with hosting merit with firm DG ‐ Lower cost than build contingent capacity. 
Locate DG where it can provide contingent capacity and voltage support at Bus Points. 
Utilise to manage peaks for voltage, capacity, Energy Market and transmission cost. 
Compliment firm DG with a coordinated customised package of renewables and alternatives to reduce capacity constraint (avoid distrubtion upgrades). 
Size to allow consumption during contingency to be gracefully reduced to baseload. 
Size and locate to minimise reverse flows on bus points. 
Facilities that provide emgency provisions (fuel and food) will be assessed for Scanpower supported contingent provisions. 
Facilities that can provide accommodation and catering for emergency workers. 
Dairy sheds will be targeted for standby power supplies on commercial terms ‐ dairy load is very peaky and seasonal resulting voltage and capacity constraints can be managed. 
Where beneficial Scanpower will provide automation and load management services. 
Limit total Genset application to 20% of GXP peak demand ‐ not economic to base load ‐ but ok for voltage management on peaky feeders. Group 1 ‐ Key Local Economy Contributors Annual kWh Av. kW per h Other kW Genset SHW PV Target Year Dannevirke N Bus ‐ Alliance 4,995,426 570 250 750 50 50 2014 Canterbury Spinners Dannevirke S Bus ‐ CSL 2,984,746 341 400 750 30 30 2014 Oringi Cold Stores Oringi Bus 2,973,438 339 250 500 30 30 2013 # Description Bus 1 Alliance 2 3 Dannevirke GXP ‐ 2,757,442 315 PFC Weber Matamau Bus ‐ 9 Kiwi Sock Company 461,942 53 300 350 5 10 2013 Norsewood Note: These developments are required to meet case by case economic test and sanction for expenditure consequently are not budgeted at this time. 4 Kiwi Lumber Page 112 of 193
Table 23 continued – Summary of Security Strategy for Significant ICPs / Locations
Group 2 ‐ Rural Communities/Voltage Support # Description Bus 1 Ormandville Matamau Bus ‐ Ormandville 2 Weber ‐ spur Beyond tie points Annual kWh Av. kW per h Other kW Genset 350 SHW PV 250 Target Year 2013 2015 Group 3 – ICPs with CDEM Significance Annual kWh Av. kW per h Other kW Genset SHW PV Target Year Dannevirke S Bus ‐ Demark 1,017,196 116 100 5 10 2016 High School Dannevirke N Bus ‐ Cole 277,800 32 30 5 10 2016 13 Caltex Westlows Adelaide 271,380 31 30 5 2017 14 BP Dannevirke Dannevirke S Bus ‐ Demark 254,186 29 30 5 2017 18 Caltex Woodville Town 1 225,754 26 30 5 2017 20 Mangatera Hotel Dannevirke N Bus ‐ Ruahine 209,840 24 30 5 5 2016 # Description Bus 6 New World 12 10.5.9 Voltage Support
Voltage standards are the main constraint on Scanpower’s network and primarily a function
of distance. If the voltage can be supported then the conductor generally has the thermal
capacity to supply the load. To a point, voltage support is a lower cost option than installing
bigger conductors or upgrading the network voltage standard.
There are several options for voltage support:

Transpower’s supply transformers are fitted with on load tap changers capable of
regulating voltage to +/-15% automatically in 1.25% voltage steps. Scanpower’s
distribution transformers are fitted with off-load manual fixed tap changers able to
correct voltage by +5% -1.25% which allows for voltage correction of the line
regulation. That is, that the Transpower voltage set-point can be set high and the
distribution transformers close in to the GXP can be set to buck voltage by up to 1%
and those further out boost voltage by up to 5% as they are positioned further out from
the GXP. Transpower is not applying the Line Drop Compensation capability of its
transformer voltage control systems – this is to be remedied. Even so, Scanpower is at
operational limits with which it can utilise this capability. On long lines the line
regulation exceeds the capability of the equipment and on feeders with a large
variation between peak and base load, load regulation becomes a constraining factor.
In short, load levels on Scanpower’s network are now close to the capability of 11kV
distribution.
Page 113 of 193

Improving PF of the loads connected to the network.
Scanpower has two industrial sites where PFC equipment is inadequate and compliance
with its 0.95PF standard at lesser installations, such as dairy sheds and pumps, is assessed
as poor. The difficulty with enforcing a PF standard is that the consumer pays for the
equipment but there is little financial reward/penalty for compliance/non-compliance. If this is
neglected then the network must invest to correct PF on a global basis in order to meet
Transpower connection standards. Costs of doing so may then be recovered indirectly on an
average cost basis – this can be the most cost effective option but is not equitable for all
consumers. Scanpower will address these issues with consumers before it invests in feeder
level correction.
Capacitor banks correct PF on a feeder or line basis. Their normal application is the
correction of voltage on feeders that have high seasonal loads such as irrigation or holiday
destinations. Long lines suffer from line load regulation, capacitors reduce their impedance.
Normally they are switched in and out of service so as not to over correct when load is low.
Accordingly they are less suitable for load that varies significantly throughout the day
because the switching can cause voltage quality disturbances. They can also absorb ripple
signals in parts of the network which is why they haven’t traditionally been used extensively
on New Zealand distribution networks. Scanpower has determined that the Ormondville and
Norsewood areas would benefit from capacitors located at towards the ends of feeders
downstream from the Matamau Voltage Regulators when the voltage drop reaches 5% at
the end of line. These will need to be switched to manage dairy season line regulation.
Voltage Regulators are an auto-transformer with an on-line tap changer attached. They are
used to step the voltage up on long feeders – typically located at approx. 15km from the
supply bus where line regulation start exceeds the capability the GXP voltage correction.
This type of network configuration is normally only applied to lightly loaded rural lines. Such
lines, are normally feeding small single phase loads such as woolsheds and residences. As
a consequence, the voltage regulators are often only applied to 2 phases as cost saving
measure. Once the loadings get beyond a certain point 3 phase boosting is necessary to
keep the system balanced and limit the effects of harmonics created by asymmetrical
boosting. Scanpower has relatively few single phase supplies in its rural networks so
realising the maximum capacity of its lines requires a well-balanced system – 2 phase
boosting is no longer appropriate. Loadings on rural feeders are now exceeding the 1-2MVA
capabilities of its regulators. According Scanpower will need to increase the capacity of
existing regulators and upgrade them to 3 phase units. These are planned to be upgraded
when load exceeds their capacity and additional units added when the voltage drop reaches
10%. They will be located at the bussing points to be established.
10.5.10
Load Forecast for the Preferred Network Development Plan
The forecast provided below assumes the network reconfigurations and preferred
development strategies discussed above. Its purpose is to demonstrate that:

The constraints have been relieved.

The level of headroom that will remain in the system.
Page 114 of 193

The sensitivities regarding load growth, timing and location.
That is, it provides a benchmark against which actual load growth and system performance
can be monitored.
Page 115 of 193
Table 24 – Revised Load / Capacity Forecast under NDP Conditions
Weber Constraint 5%VD Constraint 10%VD Year Starting Load Base Load Growth Development Dairy/Irrigation Genset Voltage Correction Year Ending Load 2012 1.60 3.75 1.67 0.03 2013 1.60 3.75 1.74 0.03 2014 1.60 3.75 1.77 0.03 0.05 2015 1.60 3.75 1.85 0.03 0.05 2016 1.60 3.75 1.68 0.03 1.74 1.77 1.85 1.68 1.71 1.78 1.81 1.84 1.87 1.90 1.96 1.99 2.02 2.05 2.08 Okare (SF) Constraint 5%VD Constraint 10%VD Year Starting Load Base Load Growth Development Dairy/Irrigation Load Shifted From Load Shifted To Year Ending Load 2012 1.60 3.75 0.17 0.03 2013 1.60 3.75 0.24 0.03 2014 1.60 3.75 0.27 0.03 2015 1.60 3.75 0.30 0.03 2016 1.60 3.75 0.33 0.03 2017 1.60 3.75 0.36 0.03 2018 1.60 3.75 0.43 0.03 2019 1.60 3.75 0.46 0.03 2020 1.60 3.75 0.49 0.03 2021 1.60 3.75 0.52 0.03 2022 1.60 3.75 0.55 0.03 2023 1.60 3.75 0.61 0.03 2024 1.60 3.75 0.64 0.03 2025 1.60 3.75 0.67 0.03 2026 1.60 3.75 0.70 0.03 0.24 0.27 0.30 0.33 0.36 0.43 0.46 0.49 0.52 0.55 0.61 0.64 0.67 0.70 0.73 Mangatera Constraint 5%VD Constraint 10%VD Year Starting Load Base Load Growth Development Dairy/Irrigation Load Shifted From Load Shifted To Year Ending Load 2012 1.88 3.75 0.01 0.01 2013 1.88 3.75 0.03 0.01 2014 1.88 3.75 0.08 0.01 2015 1.88 3.75 0.10 0.01 2016 1.88 3.75 0.13 0.01 2017 1.88 3.75 0.15 0.01 2018 1.88 3.75 0.18 0.01 2019 1.88 3.75 0.22 0.01 2020 1.88 3.75 0.25 0.01 2021 1.88 3.75 0.27 0.01 2022 1.88 3.75 0.30 0.01 2023 1.88 3.75 0.32 0.01 2024 1.88 3.75 0.37 0.01 2025 1.88 3.75 0.39 0.01 0.01 0.04 0.01 0.02 0.01 0.02 0.03 0.02 0.01 0.02 0.01 0.04 0.01 0.03 0.08 0.10 0.13 0.15 0.18 0.22 0.25 0.27 0.30 0.32 0.37 0.39 0.04 2017 1.60 3.75 1.71 0.03 2018 1.60 3.75 1.78 0.03 2019 1.60 3.75 1.81 0.03 2020 1.60 3.75 1.84 0.03 2021 1.60 3.75 1.87 0.03 0.04 2022 1.60 3.75 1.90 0.03 2023 1.60 3.75 1.96 0.03 2024 1.60 3.75 1.99 0.03 2025 1.60 3.75 2.02 0.03 2026 1.60 3.75 2.05 0.03 2028 1.60 3.75 2.15 0.03 2029 1.60 3.75 2.18 0.03 2030 1.60 3.75 2.21 0.03 2031 1.60 3.75 2.24 0.03 2.15 2.18 2.21 2.24 2.27 2027 1.60 3.75 0.73 0.03 2028 1.60 3.75 0.80 0.03 2029 1.60 3.75 0.83 0.03 2030 1.60 3.75 0.86 0.03 2031 1.60 3.75 0.89 0.03 0.80 0.83 0.86 0.89 0.92 2026 1.88 3.75 0.42 0.01 2027 1.88 3.75 0.44 0.01 2028 1.88 3.75 0.47 0.01 2029 1.88 3.75 0.51 0.01 2030 1.88 3.75 0.54 0.01 2031 1.88 3.75 0.56 0.01 0.02 0.01 0.02 0.03 0.02 0.01 0.00 0.42 0.44 0.47 0.51 0.54 0.56 0.57 0.04 2027 1.60 3.75 2.08 0.03 0.04 ‐0.25 0.04 0.04 0.04 0.04 Page 116 of 193
Table 24 continued– Revised Load / Capacity Forecast under NDP Conditions
Alliance (SF) Constraint 5%VD Constraint 10%VD Year Starting Load Base Load Growth Development Dairy/Irrigation Genset Voltage Correction Year Ending Load 2012 4.40 4.40 1.30 0.01 0.01 1.32 2013 4.40 4.40 1.32 0.01 0.04 1.37 2014 4.40 4.40 1.37 0.01 0.01 ‐0.75 0.64 2015 4.40 4.40 0.64 0.01 0.02 0.67 2016 4.40 4.40 0.67 0.01 0.01 0.69 2017 4.40 4.40 0.69 0.01 0.02 0.72 2018 4.40 4.40 0.72 0.01 0.03 0.76 2019 4.40 4.40 0.76 0.01 0.02 0.79 2020 4.40 4.40 0.79 0.01 0.01 0.81 2021 4.40 4.40 0.81 0.01 0.02 0.84 2022 4.40 4.40 0.84 0.01 0.01 0.86 2023 4.40 4.40 0.86 0.01 0.04 0.91 2024 4.40 4.40 0.91 0.01 0.01 0.93 2025 4.40 4.40 0.93 0.01 0.02 0.96 2026 4.40 4.40 0.96 0.01 0.01 0.98 2027 4.40 4.40 0.98 0.01 0.02 1.01 2028 4.40 4.40 1.01 0.01 0.03 1.05 2029 4.40 4.40 1.05 0.01 0.02 1.08 2030 4.40 4.40 1.08 0.01 0.01 1.10 2031 4.40 4.40 1.10 0.01 0.00 1.11 Ruahine (SF) Constraint 5%VD Constraint 10%VD Year Starting Load Base Load Growth Development Dairy/Irrigation Load Shifted From Load Shifted To Year Ending Load 2012 4.40 4.40 0.75 0.01 0.76 2013 4.40 4.40 0.76 0.01 0.77 2014 4.40 4.40 0.77 0.01 0.78 2015 4.40 4.40 0.78 0.01 0.79 2016 4.40 4.40 0.79 0.01 0.80 2017 4.40 4.40 0.80 0.01 ‐0.03 0.78 2018 4.40 4.40 0.78 0.01 0.79 2019 4.40 4.40 0.79 0.01 0.80 2020 4.40 4.40 0.80 0.01 0.81 2021 4.40 4.40 0.81 0.01 0.82 2022 4.40 4.40 0.82 0.01 0.83 2023 4.40 4.40 0.83 0.01 0.84 2024 4.40 4.40 0.84 0.01 0.85 2025 4.40 4.40 0.85 0.01 0.86 2026 4.40 4.40 0.86 0.01 0.87 2027 4.40 4.40 0.87 0.01 0.88 2028 4.40 4.40 0.88 0.01 0.89 2029 4.40 4.40 0.89 0.01 0.90 2030 4.40 4.40 0.90 0.01 0.91 2031 4.40 4.40 0.91 0.01 0.92 Cole (SF) Constraint 5%VD Constraint 10%VD Year Starting Load Base Load Growth Development Dairy/Irrigation Load Shifted From Load Shifted To Year Ending Load 2012 4.40 4.40 0.75 0.02 0.77 2013 4.40 4.40 0.77 0.02 0.79 2014 4.40 4.40 0.79 0.02 0.81 2015 4.40 4.40 0.81 0.02 0.83 2016 4.40 4.40 0.83 0.02 ‐0.03 0.82 2017 4.40 4.40 0.82 0.02 0.84 2018 4.40 4.40 0.84 0.02 0.86 2019 4.40 4.40 0.86 0.02 0.88 2020 4.40 4.40 0.88 0.02 0.90 2021 4.40 4.40 0.90 0.02 0.92 2022 4.40 4.40 0.92 0.02 0.94 2023 4.40 4.40 0.94 0.02 0.96 2024 4.40 4.40 0.96 0.02 0.98 2025 4.40 4.40 0.98 0.02 1.00 2026 4.40 4.40 1.00 0.02 1.02 2027 4.40 4.40 1.02 0.02 1.04 2028 4.40 4.40 1.04 0.02 1.06 2029 4.40 4.40 1.06 0.02 1.08 2030 4.40 4.40 1.08 0.02 1.10 2031 4.40 4.40 1.10 0.02 1.12 Page 117 of 193
DVK North Bus Total Constraint 5%VD Constraint 10%VD Year Starting Load Base Load Growth Development Dairy/Irrigation Genset Load Shifted To Year Ending Load 2012 1.88 3.75 2.81 0.05 2013 1.88 3.75 2.88 0.05 2014 1.88 3.75 3.01 0.05 2015 1.88 3.75 2.33 0.05 2016 1.88 3.75 2.42 0.05 2017 1.88 3.75 2.46 0.05 2018 1.88 3.75 2.52 0.05 2019 1.88 3.75 2.63 0.05 2020 1.88 3.75 2.72 0.05 2021 1.88 3.75 2.79 0.05 2022 1.88 3.75 2.88 0.05 2023 1.88 3.75 2.95 0.05 2024 1.88 3.75 3.07 0.05 2025 1.88 3.75 3.15 0.05 2026 1.88 3.75 3.23 0.05 2027 1.88 3.75 3.31 0.05 2028 1.88 3.75 3.39 0.05 2029 1.88 3.75 3.50 0.05 2030 1.88 3.75 3.59 0.05 2031 1.88 3.75 3.66 0.05 0.02 0.08 0.02 ‐0.75 0.04 0.02 ‐0.03 0.04 ‐0.03 0.06 0.04 0.02 0.04 0.02 0.08 0.02 0.04 0.02 0.04 0.06 0.04 0.02 0.00 2.88 3.01 2.33 2.42 2.46 2.52 2.63 2.72 2.79 2.88 2.95 3.07 3.15 3.23 3.31 3.39 3.50 3.59 3.66 3.71 Denamrk (SF) Constraint 5%VD Constraint 10%VD Year Starting Load Base Load Growth Development Dairy/Irrigation Load Shifted From Load Shifted To Year Ending Load 2012 4.40 4.40 2.32 0.07 2.39 2013 4.40 4.40 2.39 0.07 0.30 2.76 2014 4.40 4.40 2.76 0.07 0.40 3.23 2015 4.40 4.40 3.23 0.07 0.10 3.40 2016 4.40 4.40 3.40 0.07 ‐0.10 3.37 2017 4.40 4.40 3.37 0.07 ‐0.03 3.41 2018 4.40 4.40 3.41 0.07 3.48 2019 4.40 4.40 3.48 0.07 3.55 2020 4.40 4.40 3.55 0.07 3.62 2021 4.40 4.40 3.62 0.07 3.69 2022 4.40 4.40 3.69 0.07 3.76 2023 4.40 4.40 3.76 0.07 3.83 2024 4.40 4.40 3.83 0.07 3.90 2025 4.40 4.40 3.90 0.07 3.97 2026 4.40 4.40 3.97 0.07 4.04 2027 4.40 4.40 4.04 0.07 4.11 2028 4.40 4.40 4.11 0.07 4.18 2029 4.40 4.40 4.18 0.07 4.25 2030 4.40 4.40 4.25 0.07 4.32 2031 4.40 4.40 4.32 0.07 4.39 CSL 1 (SF) Constraint 5%VD Constraint 10%VD Year Starting Load Base Load Growth Development Dairy/Irrigation Load Shifted From Load Shifted To Year Ending Load 2012 4.40 4.40 0.37 0.01 0.38 2013 4.40 4.40 0.38 0.01 0.05 0.44 2014 4.40 4.40 0.44 0.01 0.15 ‐0.375 0.23 2015 4.40 4.40 0.23 0.01 0.15 0.39 2016 4.40 4.40 0.39 0.01 0.40 2017 4.40 4.40 0.40 0.01 0.41 2018 4.40 4.40 0.41 0.01 0.42 2019 4.40 4.40 0.42 0.01 0.43 2020 4.40 4.40 0.43 0.01 0.44 2021 4.40 4.40 0.44 0.01 0.45 2022 4.40 4.40 0.45 0.01 0.46 2023 4.40 4.40 0.46 0.01 0.47 2024 4.40 4.40 0.47 0.01 0.48 2025 4.40 4.40 0.48 0.01 0.49 2026 4.40 4.40 0.49 0.01 0.50 2027 4.40 4.40 0.50 0.01 0.51 2028 4.40 4.40 0.51 0.01 0.52 2029 4.40 4.40 0.52 0.01 0.53 2030 4.40 4.40 0.53 0.01 0.54 2031 4.40 4.40 0.54 0.01 0.55 Page 118 of 193
Waterloo (SF) Constraint 5%VD Constraint 10%VD Year Starting Load Base Load Growth Development Dairy/Irrigation Genset Voltage Correction Year Ending Load 2012 4.40 4.40 1.13 0.02 1.15 2013 4.40 4.40 1.15 0.02 0.10 1.27 2014 4.40 4.40 1.27 0.02 0.10 1.39 2015 4.40 4.40 1.39 0.02 0.10 1.51 2016 4.40 4.40 1.51 0.02 1.53 2017 4.40 4.40 1.53 0.02 1.55 2018 4.40 4.40 1.55 0.02 1.57 2019 4.40 4.40 1.57 0.02 1.59 2020 4.40 4.40 1.59 0.02 1.61 2021 4.40 4.40 1.61 0.02 1.63 2022 4.40 4.40 1.63 0.02 1.65 2023 4.40 4.40 1.65 0.02 1.67 2024 4.40 4.40 1.67 0.02 1.69 2025 4.40 4.40 1.69 0.02 1.71 2026 4.40 4.40 1.71 0.02 1.73 2027 4.40 4.40 1.73 0.02 1.75 2028 4.40 4.40 1.75 0.02 1.77 2029 4.40 4.40 1.77 0.02 1.79 2030 4.40 4.40 1.79 0.02 1.81 2031 4.40 4.40 1.81 0.02 1.83 CSL 2 (SF) Constraint 5%VD Constraint 10%VD Year Starting Load Base Load Growth Development Dairy/Irrigation Load Shifted From Load Shifted To Year Ending Load 2012 4.40 4.40 0.37 0.01 0.38 2013 4.40 4.40 0.38 0.01 0.05 0.44 2014 4.40 4.40 0.44 0.01 0.15 ‐0.375 0.23 2015 4.40 4.40 0.23 0.01 0.15 0.39 2016 4.40 4.40 0.39 0.01 0.40 2017 4.40 4.40 0.40 0.01 0.41 2018 4.40 4.40 0.41 0.01 0.42 2019 4.40 4.40 0.42 0.01 0.43 2020 4.40 4.40 0.43 0.01 0.44 2021 4.40 4.40 0.44 0.01 0.45 2022 4.40 4.40 0.45 0.01 0.46 2023 4.40 4.40 0.46 0.01 0.47 2024 4.40 4.40 0.47 0.01 0.48 2025 4.40 4.40 0.48 0.01 0.49 2026 4.40 4.40 0.49 0.01 0.50 2027 4.40 4.40 0.50 0.01 0.51 2028 4.40 4.40 0.51 0.01 0.52 2029 4.40 4.40 0.52 0.01 0.53 2030 4.40 4.40 0.53 0.01 0.54 2031 4.40 4.40 0.54 0.01 0.55 Easton Constraint 5%VD Constraint 10%VD Year Starting Load Base Load Growth Development Dairy/Irrigation Load Shifted From Load Shifted To Year Ending Load 2012 4.40 4.40 0.78 0.02 0.80 2013 4.40 4.40 0.80 0.02 0.82 2014 4.40 4.40 0.82 0.02 0.84 2015 4.40 4.40 0.84 0.02 0.86 2016 4.40 4.40 0.86 0.02 0.88 2017 4.40 4.40 0.88 0.02 0.90 2018 4.40 4.40 0.90 0.02 0.92 2019 4.40 4.40 0.92 0.02 0.94 2020 4.40 4.40 0.94 0.02 0.96 2021 4.40 4.40 0.96 0.02 0.98 2022 4.40 4.40 0.98 0.02 1.00 2023 4.40 4.40 1.00 0.02 1.02 2024 4.40 4.40 1.02 0.02 1.04 2025 4.40 4.40 1.04 0.02 1.06 2026 4.40 4.40 1.06 0.02 1.08 2027 4.40 4.40 1.08 0.02 1.10 2028 4.40 4.40 1.10 0.02 1.12 2029 4.40 4.40 1.12 0.02 1.14 2030 4.40 4.40 1.14 0.02 1.16 2031 4.40 4.40 1.16 0.02 1.18 Page 119 of 193
DVK South Bus Total Constraint 5%VD Constraint 10%VD Year Starting Load Base Load Growth Development Dairy/Irrigation Genset Load Shifted To Year Ending Load 2012 4.05 8.10 5.14 0.16 2013 4.05 8.10 5.34 0.16 0.50 2014 4.05 8.10 6.00 0.16 0.80 5.34 6.00 6.21 North/Matamau Bus Constraint 5%VD Constraint 10%VD Year Starting Load Base Load Growth Development Dairy/Irrigation Load Shifted From Load Shifted To Year Ending Load 2012 1.00 2.00 0.50 0.01 2013 1.00 2.00 0.55 0.01 0.04 Norsewood (SF) Constraint 5%VD Constraint 10%VD Year Starting Load Base Load Growth Development Dairy/Irrigation Genset Load Shifted To Year Ending Load 2015 4.05 8.10 6.21 0.16 0.50 2016 4.05 8.10 6.87 0.16 0.00 2018 4.05 8.10 7.10 0.16 0.00 2019 4.05 8.10 7.26 0.16 0.00 2020 4.05 8.10 7.42 0.16 0.00 2021 4.05 8.10 7.58 0.16 0.00 2022 4.05 8.10 7.74 0.16 0.00 0.04 2023 4.05 8.10 7.93 0.16 0.00 2024 4.05 8.10 8.09 0.16 0.00 2025 4.05 8.10 8.25 0.16 0.00 2026 4.05 8.10 8.41 0.16 0.00 2027 4.05 8.10 8.57 0.16 0.00 0.04 2028 4.05 8.10 8.77 0.16 0.00 2029 4.05 8.10 8.93 0.16 0.00 2030 4.05 8.10 9.09 0.16 0.00 2031 4.05 8.10 9.25 0.16 0.00 ‐0.10 2017 4.05 8.10 6.93 0.16 0.00 0.04 ‐0.03 6.87 6.93 7.10 7.26 7.42 7.58 7.74 7.93 8.09 8.25 8.41 8.57 8.77 8.93 9.09 9.25 9.41 2014 1.00 2.00 0.58 0.01 2015 1.00 2.00 0.67 0.01 2016 1.00 2.00 0.70 0.01 2017 1.00 2.00 0.75 0.01 2018 1.00 2.00 0.78 0.01 2019 1.00 2.00 0.83 0.01 2020 1.00 2.00 0.90 0.01 2021 1.00 2.00 0.94 0.01 2022 1.00 2.00 0.98 0.01 2023 1.00 2.00 1.02 0.01 2024 1.00 2.00 1.06 0.01 2025 1.00 2.00 1.14 0.01 2026 1.00 2.00 1.17 0.01 2027 1.00 2.00 1.22 0.01 2028 1.00 2.00 1.25 0.01 2029 1.00 2.00 1.30 0.01 2030 1.00 2.00 1.37 0.01 2031 1.00 2.00 1.42 0.01 0.02 0.08 0.02 0.04 0.02 0.04 0.06 0.04 0.02 0.04 0.02 0.08 0.02 0.04 0.02 0.04 0.06 0.04 0.02 0.55 0.58 0.67 0.70 0.75 0.78 0.83 0.90 0.94 0.98 1.02 1.06 1.14 1.17 1.22 1.25 1.30 1.37 1.42 1.45 2012 1.00 2.00 1.20 0.04 2013 1.00 2.00 1.28 0.04 0.05 0.02 ‐0.35 2014 1.00 2.00 1.04 0.04 0.05 0.08 2015 1.00 2.00 1.21 0.04 0.05 0.02 2016 1.00 2.00 1.32 0.04 2017 1.00 2.00 1.40 0.04 2018 1.00 2.00 1.46 0.04 2019 1.00 2.00 1.54 0.04 2020 1.00 2.00 1.64 0.04 2021 1.00 2.00 1.71 0.04 2022 1.00 2.00 1.78 0.04 2023 1.00 2.00 1.85 0.04 2024 1.00 2.00 1.92 0.04 2025 1.00 2.00 2.03 0.04 2026 1.00 2.00 2.09 0.04 2027 1.00 2.00 2.17 0.04 2028 1.00 2.00 2.23 0.04 2029 1.00 2.00 2.31 0.04 2030 1.00 2.00 2.41 0.04 2031 1.00 2.00 2.49 0.04 0.04 0.02 0.04 0.06 0.04 0.02 0.04 0.02 0.08 0.02 0.04 0.02 0.04 0.06 0.04 0.02 1.04 1.21 1.32 1.40 1.46 1.54 1.64 1.71 1.78 1.85 1.92 2.03 2.09 2.17 2.23 2.31 2.41 2.49 2.55 0.04 ‐0.75 0.04 1.28 Page 120 of 193
Ormondville (SF) Constraint 5%VD Constraint 10%VD Year Starting Load Base Load Growth Development Dairy/Irrigation Genset Voltage Correction Year Ending Load 2012 1.50 3.00 0.50 0.02 0.02 0.54 2013 1.50 3.00 0.54 0.02 0.08 ‐0.35 0.29 2014 1.50 3.00 0.29 0.02 0.02 0.33 2015 1.50 3.00 0.33 0.02 0.04 0.39 2016 1.50 3.00 0.39 0.02 0.02 0.43 2017 1.50 3.00 0.43 0.02 0.04 0.49 2018 1.50 3.00 0.49 0.02 0.06 0.57 2019 1.50 3.00 0.57 0.02 0.04 0.63 2020 1.50 3.00 0.63 0.02 0.02 0.67 2021 1.50 3.00 0.67 0.02 0.04 0.73 2022 1.50 3.00 0.73 0.02 0.02 0.77 2023 1.50 3.00 0.77 0.02 0.08 0.86 2024 1.50 3.00 0.86 0.02 0.02 0.91 2025 1.50 3.00 0.91 0.02 0.04 0.96 2026 1.50 3.00 0.96 0.02 0.02 1.01 2027 1.50 3.00 1.01 0.02 0.04 1.06 2028 1.50 3.00 1.06 0.02 0.06 1.14 2029 1.50 3.00 1.14 0.02 0.04 1.20 2030 1.50 3.00 1.20 0.02 0.02 1.24 2031 1.50 3.00 1.24 0.02 0.00 1.26 Otanga (SF) Constraint 5%VD Constraint 10%VD Year Starting Load Base Load Growth Development Dairy/Irrigation Load Shifted From Load Shifted To Year Ending Load 2012 1.50 3.00 0.15 0.01 0.01 0.17 2013 1.50 3.00 0.17 0.01 0.04 0.22 2014 1.50 3.00 0.22 0.01 0.01 0.24 2015 1.50 3.00 0.24 0.01 0.02 0.27 2016 1.50 3.00 0.27 0.01 0.01 0.29 2017 1.50 3.00 0.29 0.01 0.02 0.32 2018 1.50 3.00 0.32 0.01 0.03 0.36 2019 1.50 3.00 0.36 0.01 0.02 0.39 2020 1.50 3.00 0.39 0.01 0.01 0.41 2021 1.50 3.00 0.41 0.01 0.02 0.44 2022 1.50 3.00 0.44 0.01 0.01 0.46 2023 1.50 3.00 0.46 0.01 0.04 0.51 2024 1.50 3.00 0.51 0.01 0.01 0.53 2025 1.50 3.00 0.53 0.01 0.02 0.56 2026 1.50 3.00 0.56 0.01 0.01 0.58 2027 1.50 3.00 0.58 0.01 0.02 0.61 2028 1.50 3.00 0.61 0.01 0.03 0.65 2029 1.50 3.00 0.65 0.01 0.02 0.68 2030 1.50 3.00 0.68 0.01 0.01 0.70 2031 1.50 3.00 0.70 0.01 0.00 0.71 2013 1.00 2.00 3.00 2.54 0.01 2014 1.00 2.00 3.00 1.89 0.01 2015 1.00 2.00 3.00 1.91 0.01 2016 1.00 2.00 3.00 1.94 0.01 2017 1.00 2.00 3.00 1.96 0.01 2018 1.00 2.00 3.00 1.99 0.01 2019 1.00 2.00 3.00 2.03 0.01 2020 1.00 2.00 3.00 2.06 0.01 2021 1.00 2.00 3.00 2.08 0.01 2022 1.00 2.00 3.00 2.11 0.01 2023 1.00 2.00 3.00 2.13 0.01 2024 1.00 2.00 3.00 2.17 0.01 2025 1.00 2.00 3.00 2.20 0.01 2026 1.00 2.00 3.00 2.22 0.01 2027 1.00 2.00 3.00 2.25 0.01 2028 1.00 2.00 3.00 2.27 0.01 2029 1.00 2.00 3.00 2.31 0.01 2030 1.00 2.00 3.00 2.34 0.01 2031 1.00 2.00 3.00 2.36 0.01 0.04 ‐0.70 0.01 0.02 0.01 0.02 0.03 0.02 0.01 0.02 0.01 0.04 0.01 0.02 0.01 0.02 0.03 0.02 0.01 0.00 1.89 1.91 1.94 1.96 1.99 2.03 2.06 2.08 2.11 2.13 2.17 2.20 2.22 2.25 2.27 2.31 2.34 2.36 2.37 Matamau Bus Total Constraint 5%VD Constraint 10%VD Constraint 15%VD Year Starting Load Base Load Growth Development Dairy/Irrigation Genset Load Shifted To Year Ending Load 2012 1.00 2.00 3.00 2.35 0.08 0.00 0.11 0.00 0.00 2.54 Page 121 of 193
Adelaide Constraint 5%VD Constraint 10%VD Year Starting Load Base Load Growth Development Dairy/Irrigation Genset Load Shifted To Year Ending Load 2012 2.10 3.80 1.73 0.05 2013 2.10 3.80 1.78 0.05 2014 2.10 3.80 1.83 0.05 2015 2.10 3.80 1.88 0.05 2016 2.10 3.80 1.93 0.05 1.78 1.83 1.88 1.93 1.98 Te Rehunga Branch Constraint 5%VD Constraint Thermal Year Starting Load Base Load Growth Development Dairy/Irrigation Load Shifted From Load Shifted To Year Ending Load 2012 3.50 4.40 0.48 0.01 2013 3.50 4.40 0.52 0.01 2014 3.50 4.40 0.56 0.01 2015 3.50 4.40 0.60 0.01 0.03 0.03 0.03 0.52 0.56 0.60 2017 2.10 3.80 1.98 0.05 2018 2.10 3.80 2.00 0.05 2019 2.10 3.80 2.05 0.05 2020 2.10 3.80 2.10 0.05 2021 2.10 3.80 2.15 0.05 2022 2.10 3.80 2.20 0.05 2023 2.10 3.80 2.25 0.05 2024 2.10 3.80 2.30 0.05 2025 2.10 3.80 2.35 0.05 2026 2.10 3.80 2.40 0.05 2027 2.10 3.80 2.45 0.05 2028 2.10 3.80 2.50 0.05 2029 2.10 3.80 2.55 0.05 2030 2.10 3.80 2.60 0.05 2031 2.10 3.80 2.65 0.05 2.00 2.05 2.10 2.15 2.20 2.25 2.30 2.35 2.40 2.45 2.50 2.55 2.60 2.65 2.70 2016 3.50 4.40 0.66 0.01 2017 3.50 4.40 0.70 0.01 2018 3.50 4.40 0.74 0.01 2019 3.50 4.40 0.78 0.01 2020 3.50 4.40 0.82 0.01 2021 3.50 4.40 0.88 0.01 2022 3.50 4.40 0.92 0.01 2023 3.50 4.40 0.96 0.01 2024 3.50 4.40 1.00 0.01 2025 3.50 4.40 1.04 0.01 2026 3.50 4.40 1.10 0.01 2027 3.50 4.40 1.14 0.01 2028 3.50 4.40 1.18 0.01 2029 3.50 4.40 1.22 0.01 2030 3.50 4.40 1.26 0.01 2031 3.50 4.40 1.32 0.01 0.05 0.03 0.03 0.03 0.03 0.05 0.03 0.03 0.03 0.03 0.05 0.03 0.03 0.03 0.03 0.05 0.03 0.66 0.70 0.74 0.78 0.82 0.88 0.92 0.96 1.00 1.04 1.10 1.14 1.18 1.22 1.26 1.32 1.36 ‐0.03 Te Rehunga/Inc.1 Oringi Constraint 5%VD Constraint 10%VD Year Starting Load Base Load Growth Development Dairy/Irrigation Load Shifted From Load Shifted To Year Ending Load 2012 1.50 3.00 0.52 0.01 2013 1.50 3.00 0.56 0.01 2014 1.50 3.00 0.60 0.01 2015 1.50 3.00 0.64 0.01 2016 1.50 3.00 0.70 0.01 2017 1.50 3.00 0.74 0.01 2018 1.50 3.00 0.78 0.01 2019 1.50 3.00 0.82 0.01 2020 1.50 3.00 0.86 0.01 2021 1.50 3.00 0.92 0.01 2022 1.50 3.00 0.96 0.01 2023 1.50 3.00 1.00 0.01 2024 1.50 3.00 1.04 0.01 2025 1.50 3.00 1.08 0.01 2026 1.50 3.00 1.14 0.01 2027 1.50 3.00 1.18 0.01 2028 1.50 3.00 1.22 0.01 2029 1.50 3.00 1.26 0.01 2030 1.50 3.00 1.30 0.01 2031 1.50 3.00 1.36 0.01 0.03 0.03 0.03 0.05 0.03 0.03 0.03 0.03 0.05 0.03 0.03 0.03 0.03 0.05 0.03 0.03 0.03 0.03 0.05 0.03 0.56 0.60 0.64 0.70 0.74 0.78 0.82 0.86 0.92 0.96 1.00 1.04 1.08 1.14 1.18 1.22 1.26 1.30 1.36 1.40 Page 122 of 193
Kiritaki Sub‐Feeder Oringi Bus Constraint 5%VD Constraint Thermal Year Starting Load Base Load Growth Development Dairy/Irrigation Load Shifted From Load Shifted To Year Ending Load Gaisford Sub‐Feeder Oringi Bus Constraint 5%VD Constraint Thermal Year Starting Load Base Load Growth Development Dairy/Irrigation Load Shifted From Load Shifted To Year Ending Load Oringi Sub‐Feeder Oringi Bus Constraint 5%VD Constraint Thermal Year Starting Load Base Load Growth Development Dairy/Irrigation Load Shifted From Load Shifted To Year Ending Load 2012 3.50 4.40 0.42 0.01 2013 3.50 4.40 0.46 0.01 2014 3.50 4.40 0.50 0.01 2015 3.50 4.40 0.54 0.01 2016 3.50 4.40 0.60 0.01 2017 3.50 4.40 0.64 0.01 2018 3.50 4.40 0.68 0.01 2019 3.50 4.40 0.72 0.01 2020 3.50 4.40 0.76 0.01 2021 3.50 4.40 0.82 0.01 2022 3.50 4.40 0.86 0.01 2023 3.50 4.40 0.90 0.01 2024 3.50 4.40 0.94 0.01 2025 3.50 4.40 0.98 0.01 2026 3.50 4.40 1.04 0.01 2027 3.50 4.40 1.08 0.01 2028 3.50 4.40 1.12 0.01 2029 3.50 4.40 1.16 0.01 2030 3.50 4.40 1.20 0.01 2031 3.50 4.40 1.26 0.01 0.03 0.03 0.03 0.05 0.03 0.03 0.03 0.03 0.05 0.03 0.03 0.03 0.03 0.05 0.03 0.03 0.03 0.03 0.05 0.03 0.46 0.50 0.54 0.60 0.64 0.68 0.72 0.76 0.82 0.86 0.90 0.94 0.98 1.04 1.08 1.12 1.16 1.20 1.26 1.30 2012 3.50 4.40 0.12 0.01 2013 3.50 4.40 0.16 0.01 2014 3.50 4.40 0.20 0.01 2015 3.50 4.40 0.24 0.01 2016 3.50 4.40 0.30 0.01 2017 3.50 4.40 0.34 0.01 2018 3.50 4.40 0.38 0.01 2019 3.50 4.40 0.42 0.01 2020 3.50 4.40 0.46 0.01 2021 3.50 4.40 0.52 0.01 2022 3.50 4.40 0.56 0.01 2023 3.50 4.40 0.60 0.01 2024 3.50 4.40 0.64 0.01 2025 3.50 4.40 0.68 0.01 2026 3.50 4.40 0.74 0.01 2027 3.50 4.40 0.78 0.01 2028 3.50 4.40 0.82 0.01 2029 3.50 4.40 0.86 0.01 2030 3.50 4.40 0.90 0.01 2031 3.50 4.40 0.96 0.01 0.03 0.03 0.03 0.05 0.03 0.03 0.03 0.03 0.05 0.03 0.03 0.03 0.03 0.05 0.03 0.03 0.03 0.03 0.05 0.03 0.16 0.20 0.24 0.30 0.34 0.38 0.42 0.46 0.52 0.56 0.60 0.64 0.68 0.74 0.78 0.82 0.86 0.90 0.96 1.00 2012 3.50 4.40 0.14 0.01 2013 3.50 4.40 0.15 0.01 2014 3.50 4.40 0.16 0.01 2015 3.50 4.40 0.17 0.01 2016 3.50 4.40 0.18 0.01 2017 3.50 4.40 0.19 0.01 2018 3.50 4.40 0.20 0.01 2019 3.50 4.40 0.21 0.01 2020 3.50 4.40 0.22 0.01 2021 3.50 4.40 0.23 0.01 2022 3.50 4.40 0.24 0.01 2023 3.50 4.40 0.25 0.01 2024 3.50 4.40 0.26 0.01 2025 3.50 4.40 0.27 0.01 2026 3.50 4.40 0.28 0.01 2027 3.50 4.40 0.29 0.01 2028 3.50 4.40 0.30 0.01 2029 3.50 4.40 0.31 0.01 2030 3.50 4.40 0.32 0.01 2031 3.50 4.40 0.33 0.01 0.15 0.16 0.17 0.18 0.19 0.20 0.21 0.22 0.23 0.24 0.25 0.26 0.27 0.28 0.29 0.30 0.31 0.32 0.33 0.34 Page 123 of 193
OCS Sub‐Feeder Oringi Bus Constraint 5%VD Constraint Thermal Year Starting Load Base Load Growth Development Dairy/Irrigation Genset Load Shifted To Year Ending Load Oringi Bus Total Constraint 5%VD Constraint 10%VD Year Starting Load Base Load Growth Development Dairy/Irrigation Genset 2012 1.40 2.80 1.70 0.05 Year Ending Load Town 1 Constraint 5%VD Constraint 10%VD Year Starting Load Base Load Growth Development Dairy/Irrigation Genset Load Shifted To Year Ending Load 2012 3.50 4.40 0.50 0.01 2013 3.50 4.40 0.51 0.01 0.20 2014 3.50 4.40 0.22 0.01 0.05 2015 3.50 4.40 0.28 0.01 0.05 2016 3.50 4.40 0.34 0.01 2017 3.50 4.40 0.35 0.01 2018 3.50 4.40 0.36 0.01 2019 3.50 4.40 0.37 0.01 2020 3.50 4.40 0.38 0.01 2021 3.50 4.40 0.39 0.01 2022 3.50 4.40 0.40 0.01 2023 3.50 4.40 0.41 0.01 2024 3.50 4.40 0.42 0.01 2025 3.50 4.40 0.43 0.01 2026 3.50 4.40 0.44 0.01 2027 3.50 4.40 0.45 0.01 2028 3.50 4.40 0.46 0.01 2029 3.50 4.40 0.47 0.01 2030 3.50 4.40 0.48 0.01 2031 3.50 4.40 0.49 0.01 0.28 0.34 0.35 0.36 0.37 0.38 0.39 0.40 0.41 0.42 0.43 0.44 0.45 0.46 0.47 0.48 0.49 0.50 ‐0.50 0.51 0.22 2013 1.40 2.80 1.88 0.10 0.20 ‐0.26 ‐0.50 2014 1.40 2.80 1.72 0.10 0.05 0.09 2015 1.40 2.80 1.91 0.10 0.05 0.15 2016 1.40 2.80 2.16 0.05 2017 1.40 2.80 2.30 0.05 2018 1.40 2.80 2.44 0.05 2019 1.40 2.80 2.58 0.05 2020 1.40 2.80 2.72 0.05 2021 1.40 2.80 2.91 0.05 2022 1.40 2.80 3.05 0.05 2023 1.40 2.80 3.19 0.05 2024 1.40 2.80 3.33 0.05 2025 1.40 2.80 3.47 0.05 2026 1.40 2.80 3.67 0.05 2027 1.40 2.80 3.81 0.05 2028 1.40 2.80 3.95 0.05 2029 1.40 2.80 4.09 0.05 2030 1.40 2.80 4.23 0.05 2031 1.40 2.80 4.43 0.05 0.09 0.09 0.09 0.09 0.15 0.09 0.09 0.09 0.09 0.15 0.09 0.09 0.09 0.09 0.15 0.09 1.84 1.68 1.87 2.12 2.26 2.40 2.54 2.68 2.87 3.01 3.15 3.29 3.43 3.63 3.77 3.91 4.05 4.19 4.39 4.53 2012 2.80 4.40 1.10 0.03 2013 2.80 4.40 1.13 0.03 2014 2.80 4.40 1.16 0.03 2015 2.80 4.40 1.19 0.03 2016 2.80 4.40 1.22 0.03 2017 2.80 4.40 1.25 0.03 2018 2.80 4.40 1.25 0.03 2019 2.80 4.40 1.28 0.03 2020 2.80 4.40 1.31 0.03 2021 2.80 4.40 1.34 0.03 2022 2.80 4.40 1.37 0.03 2023 2.80 4.40 1.40 0.03 2024 2.80 4.40 1.43 0.03 2025 2.80 4.40 1.46 0.03 2026 2.80 4.40 1.49 0.03 2027 2.80 4.40 1.52 0.03 2028 2.80 4.40 1.55 0.03 2029 2.80 4.40 1.58 0.03 2030 2.80 4.40 1.61 0.03 2031 2.80 4.40 1.64 0.03 1.28 1.31 1.34 1.37 1.40 1.43 1.46 1.49 1.52 1.55 1.58 1.61 1.64 1.67 0.09 ‐0.03 1.13 1.16 1.19 1.22 1.25 1.25 Page 124 of 193
Country Constraint 5%VD Constraint 10%VD Year Starting Load Base Load Growth Development Dairy/Irrigation Load Shifted From Load Shifted To Year Ending Load 2012 2.80 4.40 0.90 0.03 2013 2.80 4.40 1.01 0.03 2014 2.80 4.40 1.11 0.03 2015 2.80 4.40 1.22 0.03 2016 2.80 4.40 1.32 0.03 2017 2.80 4.40 1.50 0.03 2018 2.80 4.40 1.61 0.03 2019 2.80 4.40 1.71 0.03 2020 2.80 4.40 1.82 0.03 2021 2.80 4.40 1.92 0.03 2022 2.80 4.40 2.03 0.03 2023 2.80 4.40 2.13 0.03 2024 2.80 4.40 2.24 0.03 2025 2.80 4.40 2.34 0.03 2026 2.80 4.40 2.45 0.03 2027 2.80 4.40 2.55 0.03 2028 2.80 4.40 2.66 0.03 2029 2.80 4.40 2.76 0.03 2030 2.80 4.40 2.87 0.03 2031 2.80 4.40 2.97 0.03 0.08 0.08 0.08 0.08 0.15 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 1.01 1.11 1.22 1.32 1.50 1.61 1.71 1.82 1.92 2.03 2.13 2.24 2.34 2.45 2.55 2.66 2.76 2.87 2.97 3.08 Town 2 Constraint 5%VD Constraint 10%VD Year Starting Load Base Load Growth Development Dairy/Irrigation Load Shifted From Load Shifted To Year Ending Load 2012 2.80 4.40 1.10 0.03 2013 2.80 4.40 1.13 0.03 2014 2.80 4.40 1.16 0.03 2015 2.80 4.40 1.19 0.03 2016 2.80 4.40 1.22 0.03 2017 2.80 4.40 1.25 0.03 2018 2.80 4.40 1.28 0.03 2019 2.80 4.40 1.31 0.03 2020 2.80 4.40 1.34 0.03 2021 2.80 4.40 1.37 0.03 2022 2.80 4.40 1.40 0.03 2023 2.80 4.40 1.43 0.03 2024 2.80 4.40 1.46 0.03 2025 2.80 4.40 1.49 0.03 2026 2.80 4.40 1.52 0.03 2027 2.80 4.40 1.55 0.03 2028 2.80 4.40 1.58 0.03 2029 2.80 4.40 1.61 0.03 2030 2.80 4.40 1.64 0.03 2031 2.80 4.40 1.67 0.03 1.13 1.16 1.19 1.22 1.25 1.28 1.31 1.34 1.37 1.40 1.43 1.46 1.49 1.52 1.55 1.58 1.61 1.64 1.67 1.70 Total (Diversified) Constraint N‐1 Year Starting Load Base Load Growth Development Dairy/Irrigation Load Shifted From Load Shifted To Year Ending Load 2012 10.00 2.80 0.09 2013 10.00 2.97 0.09 2014 10.00 3.13 0.09 2015 10.00 3.30 0.09 2016 10.00 3.46 0.09 2017 10.00 3.70 0.09 2018 10.00 3.87 0.09 2019 10.00 4.03 0.09 2020 10.00 4.20 0.09 2021 10.00 4.36 0.09 2022 10.00 4.53 0.09 2023 10.00 4.69 0.09 2024 10.00 4.86 0.09 2025 10.00 5.02 0.09 2026 10.00 5.19 0.09 2027 10.00 5.35 0.09 2028 10.00 5.52 0.09 2029 10.00 5.68 0.09 2030 10.00 5.85 0.09 2031 10.00 6.01 0.09 0.08 0.08 0.08 0.08 0.15 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 0.08 2.97 3.13 3.30 3.46 3.70 3.87 4.03 4.20 4.36 4.53 4.69 4.86 5.02 5.19 5.35 5.52 5.68 5.85 6.01 6.18 Page 125 of 193
10.6
Automation and Protection Development Plan
10.6.1 Automation Gap Analysis
Analysis of Scanpower’s Fault Cause statistics (refer section 12) indicate that 15 SAIDI
minutes p.a. (26%) of fault outage results from transient or unknown causes. This is
attributed to:

Automation and protection systems not working effectively and reliably. This is a
combination of issues around application of the right technology, implemented
correctly, and adequately maintained in an operational state.

Network configuration, load and distance issues. These are systems engineering
issues. Without a sub-transmission system Scanpower has substantially less
sectionalising and automation density.

Retention of an older group fusing approach to protection negating the benefits of the
newer automated sectionalising and reclosing approach. The strategy of shifting to
new best practice has therefore only been partially completed as confidence in the
current automation is not high.
It has been determined that the systems engineering with regard to the selection and
application of technology is not optimal and therefore is to be addressed by redeploying
existing equipment and developing the protection and automation systems with the addition
of new technology options that were not available previously.
This has been specifically targeted at the North, Mangatera, and Weber feeders which show
the greatest need, and will deliver the greatest potential benefits in terms of reduced SAIDI.
The Country feeder would also deliver some benefit from improved technology deployment;
however this is to be preceded by an investigation into improved interconnection and
network re-configuration in the Kumeroa area.
Comparison between feeders statistics on load density within network segments and with
other benchmarked networks of similar characteristics has been made to determine targets
for an appropriate level of automation. This is detailed below:
Page 126 of 193
Table 25 – Feeder Statistics and Technical Comparison
GXP Dannevirke Woodville Feeder Weber Mangatera Central Pacific East North Adelaide Feeder Statistics MW kWh (excl. ICP's>1GWh) ICP's km km % of System 2.2 10,209,548 853 262 31% 2 10,005,209 612 132 16% 1.8 7,444,624 1151 13 2% 1.8 6,569,411 216 61 7% 3.8 16,775,955 735 11 1% 1.7 7,648,866 559 127 15% 339 9,729 29 2.52 1.29 203 6,721 33 3.01 1.54 37 6,675 180 31.11 2.85 111 9,750 88 1.95 1.82 26 5,335 205 28.27 2.36 3.26 11,969 38,968 4.64 16,348 75,797 88.54 6,468 572,663 3.54 30,414 107,695 1 1 3 6 2 2 1 1 2 1 1 13 20 26 66 7 19 29 87 No. of Transformers Connected Tfmr Capacity Average Tfmr Size No. of ICP's/Tfmr No. of Tfmr/km Impact Indicators ICP/km (Connection Density) kWh/ICP kWh/km (Load Density) Automation Equipment TPNZ Indoor CB Nulec Recloser Cooper Recloser Peanut Sectionalizer Automated ABS Isolator Automated ABS Tie Potential No. of Auto‐sections Section km Transformers/ section ICP/section Te Rehunga Town No.1 2.6 10,279,778 892 17 2% 1.1 5,749,357 295 62 7% 1.1 6,352,069 546 34 4% 223 6,350 28 2.51 1.76 46 4,630 101 19.39 2.71 118 3,648 31 2.50 1.90 66.82 22,824 1,525,087 4.40 13,683 60,227 52.47 11,524 604,693 1 1 1 1 1 1 3 4 Scanpower Waitaki Centralines 0.9 5,145,702 422 96 11% 1.2 3,866,062 428 26 3% 20.2 90,046,581 6709 841 51 240,000,000 12257 1346 25 118,000,000 8245 1397 75 3,795 51 7.28 2.21 156 4,785 31 2.71 1.63 43 2,505 58 9.95 1.65 1,377 63,923 46 4.87 1.64 2,569 173,000 67 4.77 1.91 2,245 93,000 41 3.67 1.61 4.76 19,489 92,732 16.06 11,634 186,826 4.40 12,194 53,601 16.46 9,033 148,695 7.98 13,422 107,071 9.11 19,581 178,306 5.90 14,312 84,467 1 1 1 1 1 1 1 11 4 10 7 7 6 59 43 0 0 33 39 22 35 172 102 13 25 120 131 11 17 63 1 2 1 13 37 1151 2 31 56 108 1 11 26 735 5 25 45 112 1 17 46 892 Benchmarks Town No.2 1 Country Total 2 31 59 148 1 34 75 546 4 24 39 106 2 13 22 214 33 33 32 Page 127 of 193
Table 25 continued – Feeder Statistics and Technical Comparison
GXP Feeder Dannevirke Mangatera Central Pacific East North Adelaide Total Country Scanpowe
r Town No.2 Benchmarks Te Rehunga Town No.1 Fused sections Fused section km Transformers/Fused section ICP/Fused section ABS Tie/Bypass ABS Manual Sections (incl. Fused) Manual section km Transformers/manual section ICP/Manual section Spurs 51 5 7 17 12 63 4 5 14 27 34 4 6 18 11 45 3 5 14 21 9 1 4 128 10 19 1 2 61 2 10 6 11 22 11 21 3 5 10 7 1 11 26 735 9 10 1 3 74 2 28 5 8 20 12 40 3 6 14 23 8 2 6 112 10 18 1 3 50 5 13 5 9 23 6 19 3 6 16 11 11 3 7 50 4 15 2 5 36 8 24 4 7 18 4 28 3 6 15 19 5 5 9 86 7 12 2 4 36 3 194 4 7 35 96 57 290 3 5 23 128 427 427 3 5 19 Target Auto Isolation for 12km 22 11 1 5 1 11 1 5 3 8 2 70 TPNZ Indoor CB Nulec Recloser Cooper Recloser Peanut Sectionalizer Automated ABS Isolator Automated ABS Tie Existing 1 2 4 6 7 2 22 0 13 9 1 1 2 2 3 2 11 0 8 3 1 1 0 1 0 1 1 1 2 5 0 2 3 1 1 0 1 0 1 1 1 3 3 2 11 0 5 6 1 1 0 1 0 1 1 1 2 5 0 2 3 1 2 3 0 1 2 1 1 1 1 3 1 8 0 4 4 1 1 2 0 2 0 11 5 11 12 18 13 70 39 31 59 43 0 0 33 33 33 32 Weber Woodville Waitaki Centralines Page 128 of 193
Table 25 continued – Feeder Statistics and Technical Comparison
GXP Dannevirke Feeder Weber Automation Equipment per NDP TPNZ Indoor CB Scanpower Indoor CB Nulec Recloser Cooper Recloser Peanut LSB Fuse Saver Automated ABS Isolator Automated ABS Tie Mangatera 1 1 3 6 2 2 1 1 2 3 4 Central Pacific 1 East 1 1 North 1 Adelaide 1 1 1 2 Te Rehunga Town No.1 1 1 1 1 Woodville Total Country Scanpowe
r Town No.2 1 1 1 1 1 1 Benchmarks Waitaki 11 4 10 7 7 6 Centralines Page 129 of 193
10.6.2 Automation Strategy
In re-engineering the automation scheme the following strategies have been applied to
address the above issues:

The open points between feeders have been shifted to balance feeders with regard to
the number of km of network that collect faults and the number of connections that are
therefore exposed to those faults. This is constrained by the network configuration and
capacity but the main focus has been to reduce the size of the Weber feeder by
shifting segments onto the East and Mangatera feeders.

Reducing the km of network between key segments (isolation points). This reduces the
area automatically isolated by protection equipment during faults. Remotely controlled
equipment is able to be operated to further reduce the isolated area and/or provide
back-feeds while repair crews mobilise. Scanpower needs to increase the number of
segments from approx. 40 to 70 to match the automation density of its benchmark
networks (12km auto-isolating sections). Scanpower’s network inherently has fewer
segments because the number of 11kV feeders is fewer (with no sub-transmission)
and therefore the number of km and ICPs within each segment is larger.

Reducing the number of reclosing/sectionalising protection devices deployed in series
along the main line to a maximum of 2-3 down-stream from the Transpower CB i.e.
eliminate cascading of protection schemes where the failure of one scheme cascades
into the next. Sectionalisers have essentially been positioned at the branches
downstream from a main line recloser such that there are no reclosers downstream of
sectionalisers. The feeders are so long that upstream devices have difficulty seeing
end of system faults and therefore failure to perform effectively as backup protection.

Automated ABSs have been placed midway between reclosers/sectionalisers in the
automatically isolated faulty segment to allow that segment to be further halved by
remote control while faultmen travel to site. Accordingly this equipment has been
shifted further out on the network where it can deliver the biggest improvement in
response time.

Replace fusing with fault indicators at key patrolling decision points and fault
make/load break rated ABSs able to be operated from the ground by non-linemen if
necessary.

Branch and group fusing will be eliminated once sufficient alternative technology is
deployed. HV fusing will therefore be retrenched to the transformer fuses.
Scanpower is currently using DDO fusing as is main isolating device. These being pole top
equipment, needs to be operated by lineman from a bucket truck (in the case of a wooden
pole), and are not 3 phase load break/fault make devices. This results in a more time
consuming, resource constrained, labourious switching process. Scanpower only has 158
ABSs and even fewer of these are rated for live working.
The density of this equipment is about one fifth of the benchmark networks resulting in much
larger segments for fault isolation and maintenance shutdowns. A programme will be
Page 130 of 193
developed to upgrade existing ABSs and improve their density over a 10 year period. In the
interim the DDO fuses will be replaced by solid links where defusing is desirable.
10.6.3 Other Issues
Some of the existing equipment is proving unreliable and this will need to be resolved before
it is redeployed.

The Electropar automated ABSs are unreliable. This makes the fault response more
difficult and is actually worse than a manually operated alternative. If the manufacturer
is unable to resolve the problem they will need to be replaced with an alternative
product.

The Cooper Reclosers are not providing the desired amount of information via the
SCADA. Specifically current readings that the SCADA can log are desirable.

Transpower owns/operates the CBs that Scanpower’s protection scheme relies on as
the primary reclosing device. They won’t allow the standard industry practice for fault
finding of reclosing onto potential faults.

The Peanut sectionalisers are prone to getting out of sequence. This is thought to be
an issue with the fault indicator being armed inappropriately during periods of very low
load i.e. they are being operated outside their capability. Reconfiguration may allow
more coarse protection to be applied. Smart metering may provide an alternative to
fault indicators.

ABSs are not fault make load break rated for live operating and their handles are not
always operable from the ground. This is a safe operating practice and quality of
solution issue. It restricts the number of staff able undertake field operating. An
investigation into rating is required to determine an improvement plan.
10.6.4 Solution Options
This plan only addresses the Weber, Mangatera, and North feeders which are the 3 most
highly represented feeders in the particular outage statistic being targeted. The Country
feeder also has some scope for improvement but this will be addressed separately when
interconnection with the Pacific feeder is investigated.
To constrain cost the initial scope is limited to reconfiguration of the network, relocation of
existing equipment into more effective locations, and the addition of new equipment required
to coordinate the re-engineered scheme.
To match the 12km benchmark of other network for auto-isolation will require additional
investment beyond this proposal. In this scenario:

The Weber feeder would require 22 sections. It currently has 13 sections and it is
proposed to reconfigure it to 17 sections. The proposal to split Weber into two feeders
will create further segmentation.
Page 131 of 193

The Mangatera feeder would require 11 sections. It currently has 8 sections and this
will remain unchanged. However Voltage Regulators are being upgraded at Matamau
and this will further split this feeder into a number of sub-feeder circuits resulting in 22
segments with greater interconnection capability.

The North feeder would require 11 sections. It currently has 5 sections and it is also
proposed to reconfigure it into multiple sub-feeders creating 16 sections.
Initially two options were investigated in detail:

The first selected ABS switches paired with Fault Indicators on spurs which were not
automated (cost prohibitive) and sectionalisers and/or reclosers on the main line. This
would then allow the network to be de-fused – this is most common strategy applied by
other networks over the past 20 years. However, the market lacks products that are
cost effective for Scanpower’s scale/load density - specifically full blown reclosers are
offered instead of a lower cost sectionaliser option, fault indicators have become very
expensive now that they are configured for remote communications, and Scanpower
has a legacy of using DDO Isolators instead of ABSs so it cannot deploy existing
equipment and de-fusing becomes an issue for operability.

The second option considered the KAON Fuse Saver which is a ‘new to market’
technology. It is effectively a single shot sectionaliser that operates in series with
branch fusing. Consequently it will automatically clear transient faults that would
otherwise blow fusing. It therefore works with existing equipment and provides
automatic sectionalising capability at lower cost than reclosers making it a better fit to
Scanpower’s network. It also logs fault indication data and has a remote
communications upgrade path.
The ABS/Fault Indicator option has been excluded not only on long term cost grounds but
also because it lacks scalability for more intensive automation application in the future.
Following an investigation into protection coordination across the Weber feeder to prove the
concept, the Fuse Saver option has been selected. It is planned to install the first 10 sets on
the Weber feeder in 2013.
This plan has been coordinated with the proposals in the wider Network Development Plan
to develop a number of 11kV bus points/switchboards supplying sub-feeders at 4 strategic
locations within the Scanpower network which increases network segmentation and
improves the interconnection (and potential for automation). This proposal is intended to
improve the contingent capacity and voltage levels on the network, whereas the automation
and protection project specifically targets improved SAIDI.
It is also unclear at this time whether Scanpower is best to invest in more distribution
automation equipment (reclosers, sectionalisers, etc.) in the medium term or remotely
controlled switchgear which is lower cost but could be overlaid in the future with a
Distribution Management System (Smarts on the SCADA platform as opposed to in field
devices). This approach would be greatly enabled by smart grid application of the Advanced
Metering Infrastructures (AMI – smart meters) that will be deployed over the next 3-5 years.
Scanpower will develop a more comprehensive Distribution Automation strategy once AMI
solutions have been committed to in its region.
Page 132 of 193
The tables below detail the changes proposed. The total capital cost of approximately
$350,000 is spread over 3 years (3 feeders) when incorporated into the Network
Development Plan. As approximately one third of the cost is relocating existing plant this
component could be allocated as an operational expense funded from operational savings
expected over the long term.
The NDP signals some provisional budget to extend this project to other feeders but as
stated above detailed planning has not been completed for this at this time.
Table 26 – Fuse Saver Deployment Summary (North Feeder)
Automation Development Plan deploying Fuse Savers North Feeder Notes Estimated Cost New Equip Fuse Saver Reloc. Shift Tie point with Mangatera to ABS84 ‐ Automate ABS84 Ex A82 $5,000 $5,000 Redploy P77 Top Grass/Umutoaroa ‐ as Auto LBS Ex P77 $5,000 $5,000 Ex C927 $5,000 $5,000 new $8,500 $8,500 Replace Recloser C913 with Recloser Ex N915 $5,000 $5,000 Replace F528 with Recloser and ABS Ex N920 $5,000 $5,000 new $4,500 $4,500 $300 $300 Install Recloser at ABS 128 Umutoaroa Add Fuse Saver to F529 Replace F419 with ABS Remove F318 ‐ shift jumpers downstream of F529 Replace L324 with ABS new $4,500 $4,500 Install new ABS midway Top Grass new $5,500 $5,500 Add Fuse Saver to F508 new $8,500 $8,500 Add Fuse Saver to F377 new $8,500 $8,500 Add Fuse Saver to F376 new $8,500 $8,500 Add Fuse Saver to F351 new $8,500 $8,500 Add Fuse Saver to F308 new $8,500 $8,500 Add Fuse Saver to F309 new $8,500 $8,500 Add Fuse Saver to F304 new $8,500 $8,500 Add Fuse Saver to F319 new $8,500 $8,500 Add Fuse Saver to F493 new $8,500 $8,500 Add Fuse Saver to F523 new $8,500 $8,500 Add Fuse Saver to F491 new $8,500 $8,500 Add Fuse Saver to F493 new $8,500 $8,500 $2,000 $2,000 $152,300 $14,500 $110,500 $27,300 Check Fuse Grading TOTAL NORTH FEEDER BUDGET Page 133 of 193
Table 27 – Fuse Saver Deployment Summary (Mangatera Feeder)
Automation Development Plan deploying Fuse Savers Mangatera Feeder Notes Estimated Cost New Equip Fuse Saver Reloc. $5,500 $5,500 $8,500 $8,500 $11,700 $11,700 Ex A140 $5,000 $5,000 Add Fuse Saver to F301 new $8,500 $8,500 Add Fuse Saver to F484 new $8,500 $8,500 Add Fuse Saver to F328 new $8,500 $8,500 Add Fuse Saver to F3484 new $8,500 $8,500 Add Fuse Saver to F339 new $8,500 $8,500 Add Fuse Saver to F329 new $8,500 $8,500 Add Fuse Saver to F332 new $8,500 $8,500 Add Fuse Saver to F498 new $8,500 $8,500 Add Fuse Saver to F345 new $8,500 $8,500 Add Fuse Saver to F370 new $8,500 $8,500 Add Fuse Saver to F531 new $8,500 $8,500 Add Fuse Saver to F532 new $8,500 $8,500 Shift Tie with North ‐ replace A82 with ABS/FI new Shift Tie point with Weber from A3 to A123 existing Add Fuse Saver to F352 new Remove Recloser C916 Redeployed Replace F306 with Peanut LBS new Shift tie pt with Weber Remove ABS108, replace F533 with Auto ABS Check Fuse Grading $2,000 $2,000 TOTAL MANGATERA FEEDER BUDGET $134,700 $17,200 $110,500 $7,000 Page 134 of 193
Table 28 – Fuse Saver Deployment Summary (Weber Feeder)
Automation Development Plan deploying Fuse Savers Weber Feeder Shift open point betwwen 2 main branches Open A121 close A169 Notes Estimated Cost New Equip Fuse Saver Reloc. $1,000 $1,000 $5,000 $5,000 Shift branch 1 to DVK S Bus ‐ open ABS192 Disconnect Tipapakuku at F387 jumper to Cowper Rd Install Recloser at Tipapakuku ‐ Stage 2 Ex C913 Remove N920 ‐ Stage 2 redeployed Replace Recloser C921 with Recloser N920 redep./ex N924 $5,000 $5,000 Add Fuse Saver to F385 ‐ after trial new $8,500 $8,500 Add Fuse Saver to F526 ‐ after trial new $8,500 $8,500 Add Fuse Saver to F364 new $8,500 $8,500 Replace Sectionaliser P157 with Recloser redep/ex C914 $5,000 $5,000 Add Fuse Saver to F359 new $8,500 $8,500 Replace F356 with Auto LBS Ex A19 $5,000 $5,000 Remove Sectionalisr P177 redeployed Replace recloser C914 with Peanut LBS ex P177 $5,000 $5,000 Add Fuse Saver to F396 new $8,500 $8,500 Add Fuse Saver to F403 new $8,500 $8,500 Add Fuse Saver to F408 Replace Sectionaliser P77 with new Fuses and Fuse Saver new $8,500 $8,500 $8,500 $8,500 Replace F380 with Peanut LBS Ex P157 $5,000 $5,000 Add Fuse Saver to F393 new $8,500 $8,500 Add Fuse Saver to F392 new $8,500 $8,500 Add Fuse Saver to F423 ‐ Stage 2 Add Fuse Saver to Aerodrome Rd Stage 2 new $8,500 $8,500 $8,500 $8,500 Check Fuse Grading $4,000 $4,000 TOTAL WEBER FEEDER BUDGET $137,000 $0 $102,000 $35,000 redep. /new new 10.6.5 Justification
This is essentially a reliability project. The benefits are primarily reduced SAIDI and reduced
fault response costs.
The industry approach to determining the value improved reliability is to assess the
economic cost to consumers/businesses having their supply interrupted – electricity is
essentially an input to economic production – depriving the economy of supply has an
economic cost. This is known as the Value of Lost Load (VoLL or unserved energy) and the
figure that is applied by the Electricity Authority to the Grid Investment Test for Transpowers
Grid Upgrade Plans is $20/kWh of lost load.
Page 135 of 193
This figure was determined for the Electricity Authority by a Centre of Advanced Engineering
survey of consumer’s direct losses across the Residential, Commercial, Agricultural and
Industrial Sectors. A model for its determination has calibrated with real events and
benchmarked with international determinations.
CAE undertook a further study that adapted this model to determine VoLL for the Otago
Region. By assuming Tararua has a similar sector weighting and risk exposure and by
selecting the outage performance of a line company comparable with Scanpower, a VoLL for
Scanpower of $13/kWh lost has been determined.
It is assumed that the above plan will deliver a 10.6 minute drop in SAIDI from the 14.6
minutes of SAIDI lost to transient faults targeted by this project. With a total annual
consumption of 88GWh p.a. Scanpower’s system consumption per minute is 167kWh/min.
Therefore, 10.6 SAIDI minutes represents a VoLL of $23,012 p.a.
The savings in planned outage time associated with smaller isolation segments and ease of
operating. This is a saving in the order of $6,000p.a. in terms of VoLL.
Savings in fault response costs in the order of 11% p.a. ($11,000 of the non-fixed costs).
This justifies the maintenance expenditure proposed.
It is concluded that project benefits will payback project costs within a 10-20 year period. The
assets are expected to deliver a 25 - 35 year service life and therefore the proposal will add
value to Scanpower and the consumers it serves.
Page 136 of 193
10.7
Table 29 – Network Development Plan Budget and Forecast Expenditure
NDP Project Description Network Development Matamau Substation Development Dannevirke South Substation Development Dannevirke North Substation ‐ land Dannevirke North Substation Development Oringi Substation ‐ Design Oringi Substation ‐ Refurbish Switchboard Oringi Substation ‐ Controls Oringi Substation ‐ Develop feeders Line Upgrades Matamau Substation ‐ feeder devel. Dannevirke South Substation ‐ feeder devel. Dannevirke North Substation ‐ feeder devel. Norsewood A81 to ABS184 Weber Pacific Interconnection Kumuroa Interconnection Automation and Protection (capex only) Protection Reconfiguration ‐ Weber (incl. temp. Recloser) Protection Reconfiguration ‐ North ‐ Equipment Protection Reconfiguration ‐ North ‐ Fuse Savers Protection Reconfiguration ‐ Mangatera ‐ Equipment Protection Reconfiguration ‐ Mangatera ‐ Fuse Savers Protection Reconfiguration ‐ Country ‐ Equipment Protection Reconfiguration ‐ Country ‐ Fuse Savers Protection Reconfiguration ‐ Te Rehunga ‐ Equipment Protection Reconfiguration ‐ Te Rehunga ‐ Fuse Savers 2013 $490,350 $215,250 $537,750 $19,000 $34,356 $190,050 $113,200 $14,500 $34,000 $30,000 $160,000 $42,500 $17,200 $34,000 2016 2015 $96,000 $46,000 $115,000 $30,000 2014 2017 $77,500 $34,000 $42,500 $34,000 $17,200 $42,500 $45,000 $42,500 $17,200 $17,000 2020 $45,000 2019 $390,000 2018 2021 2022 Page 137 of 193
Table 29 continued – Network Development Plan Budget and Forecast Expenditure
NDP Project Description Auto LBS ‐ replacement ABS Upgrades Kumuroa Interconnection NDP Project Description Smart Grid Metering ‐ Distribution Subs 156 @16p.a. Feeder Voltage profiling (100 @ 10p.a.) RF Mesh (3 Access Pt's +12 Relays) DMR Backhaul 3 links RF Mesh Design Voltage Correction Load Flow Analysis Capacitor Bank ‐ Norsewood Capacitor Bank ‐ Ormandville PFC OCS Weber Voltage Reg. 2MVA (ex Matamau) Oringi Voltage Reg. 5MVA Network Development Projects Total 2013 $21,000 $5,250 2014 $21,000 $5,250 2013 2014 $14,480 $4,000 10,000 $75,000 2015 $21,000 $5,250 2015 $14,480 $4,000 $7,000 $30,000 $75,000 $30,000 $30,000 $1,243,449 $869,194 $592,245 2017 $21,000 $5,250 2018 $21,000 $5,250 2018 2016 $14,480 $4,000 $7,000 $15,000 $20,000 2016 $21,000 $5,250 2017 $14,480 $4,000 $7,000 $15,000 $14,480 $4,000 $314,946 $515,947 2019 $21,000 $5,250 2019 $14,480 $4,000 $89,248 2020 $21,000 $5,250 2020 $14,480 $4,000 $46,749 $14,480 $4,000 $46,750 2021 $21,000 $5,250 2022 $5,250 2021 2022 $14,480 $4,000 $85,000 $131,751 $14,480 $4,000 $25,752 Page 138 of 193
11.
LIFE CYCLE MANAGEMENT
11.1
Summary of Life Cycle Management
Scanpower does not have a significant population of any specific category of asset that is
considered critical in terms its primary service delivery objectives – keeping the lights on.
The bulk of its asset is an 11kV/400V pole mounted electricity distribution network. The age
and condition related replacement of hardwood poles in this network is the primary focus of
Scanpower’s life cycle management activity.
This plan has improved the targeting of replacements on assets and network segments
where condition is driving performance.
Analysis indicates that more attention/pace is warranted on the LV network which has
passed the optimal point for renewal (but does not affect regulatory performance
benchmarking).
The transformer population is approaching its optimal service life and because it is relatively
expensive to renew, it will be pre-emptively replaced via opportunistic renewal policies as
part of other work programmes in order the spread replacement over a wider time period.
Service line condition and the need for its replacement, is an issue that affects Scanpower’s
costs but is not an asset it owns. The industry is still in the process of determining how it will
respond to this issue.
Tree management is currently a significant non-asset but performance driving issue currently
on Scanpower’s network. Forestry outside the regulatory clearances is the main contributor.
Scanpower has established major resourcing capacity to address these issues. Tree
trimming funded by the network is a major component of life cycle costs and this will
continue for several cycles until cost responsibility has been transferred to tree owners.
11.2
Introduction to Life Cycle Management
In terms of PAS55, life cycle management refers to the cyclical asset management process
of:
1.
2.
3.
4.
Design/Build/Acquire
Operate
Inspect/Maintain/Repair
Renew/Replace/Dispose
such that the cost and performance is optimised over the entire life cycle relative to the
business objectives. It is the system performance that matters in terms of business
objectives.
Electricity distribution assets have long service lives and form part of a system. Individual
assets can become technically obsolete, capacity constrained, business objectives may
change, etc. such that these considerations require them to be replaced well before their
serviceability dictates.
Page 139 of 193
11.3
Asset Information by Category
11.3.1 Asset Values by Category
Information disclosure regulations prescribe the asset categories Scanpower must apply in
this Plan. The categories relevant to Scanpower are:

11kV Network

LV Network

Transformers

Switchgear

Secondary Assets
The following table provides information on the size of the financial asset Scanpower has in
each of these categories plus some additional detail of sub-asset categories Scanpower has
assigned to the prescribed asset categories. Clearly evident from this information is that
Scanpower’s assets are predominantly an overhead/pole mounted 11kV/400V distribution
system in a relatively mature steady state.
Table 30 – Asset Values by Category
ASSET TYPE 11kV Lines 11kV Cables 11kV System LV Lines, Cables and Dist. Equipment Service Laterals and Fusing LV System Transformers ‐ Pole Mounted Transformers ‐ Ground Mounted Distribution Subs Transformer Fuses Voltage Regulators Distribution Transformers Air Break Switches Isolating Fuses Circuit Breakers Reclosers Sectionalisers Ring Main Units Distribution Switchgear TOTAL Secondary Assets GRAND TOTAL DRC AT 1 APRIL 2012 RC AT 1 APRIL 2013 % RC % Life Remaining $12,691,827 $953,528 $13,645,355 $4,870,689 $1,086,455 $5,957,145 $1,176,952 $3,069,207 $413,008 $605,965 $109,912 $5,375,045 $374,791 $86,343 $54,489 $258,852 $101,462 $92,741 $968,677 $25,946,222 $2,599,882 $28,546,104 $22,297,073 $1,220,825 $23,517,898 $8,611,230 $3,317,807 $11,929,036 $2,148,588 $6,585,022 $1,946,132 $1,301,427 $166,381 $12,147,549 $705,341 $221,019 $222,910 $356,218 $124,398 $125,044 $1,754,930 $49,349,412 $2,599,882 $51,949,294 43% 2% 45% 17% 6% 23% 4% 13% 4% 3% 0% 23% 1% 0% 0% 1% 0% 0% 3% 5% 43% 22% 42% 43% 67% 50% 45% 53% 79% 53% 34% 56% 47% 61% 76% 27% 18% 26% 45% Page 140 of 193
Scanpower has no sub-transmission system and therefore no zone substations (or HV
switchboards/CB panels) – it takes supply directly from Transpower at 11kV which is its only
distribution (high) voltage.
Its LV reticulation is limited in its interconnection, that is it makes limited contribution to the
systems engineering of the network. Scanpower does not own service lines (HV or LV) but
operates HV service asset largely as if it did own it.
Its operational scope includes the asset management of ancillary assets such as street light
networks and it shares assets of other utilities such as Telecom. Consequently there are
limitations on how accurately Scanpower’s asset categories and associated
cost/performance information fits the prescribed disclosure model.
11.3.2 Description and Quantity of Assets by Type
The following tables summarise the quantity of network asset by category, and further by
ODV Handbook description.
Table 31 – Asset Quantity by Asset Category and ODV Handbook Description
Asset Category – 11kV Distribution Lines / Cables Length (KM) 4.0 Distribution Lines 11 kV O/H DCct Medium Distribution Lines 11 kV O/H Light (≤ 50mm2 Al) 649.8 Distribution Lines 11 kV O/H Medium (>50mm2, <150mm2 Al) 165.5 21.8 Distribution Lines 11 kV single phase or SWER lines Distribution Cables 11 kV U/G Medium (>50mm2, <240mm2 Al) 3.2 Distribution Cables 11 kV U/G Light (≤ 50mm2 Al) 8.4 TOTAL 11kV System 852.6 Asset Category – Low Voltage System Length (KM) 3.3 LV Cable Underground Medium ‐ with HV (≤ 240mm2) 60.1 LV Cable Underground Medium LV only (≤ 240mm2) LV Lines Overhead Light 2 wire LV only (≤ 50mm2 Al) 0.9 LV Lines Overhead Light 4 wire LV only (≤ 50mm2 Al) 27.2 5.8 LV Lines Overhead Light Underbuilt 2 wire (≤ 50mm2 Al) 2.6 LV Lines Overhead Medium 4 wire LV only (≤ 150mm2 Al) LV Lines Overhead Medium Underbuilt 4 wire (≤ 150mm2 Al) TOTAL Low Voltage System 85.8 185.7 Page 141 of 193
Table 31 continued – Asset Quantity by Asset Category and ODV Handbook Description
Quantity Asset Category Ground Mounted 11/0.4kV Cable Entry 3 Phase 11/0.4kV 100 kVA 16 Ground Mounted 11/0.4kV Cable Entry 3 Phase 11/0.4kV 200 kVA 57 Ground Mounted 11/0.4kV Cable Entry 3 Phase 11/0.4kV 300 kVA 22 Ground Mounted 11/0.4kV Cable Entry 3 Phase 11/0.4kV 500 kVA 3 Ground Mounted 11/0.4kV Cable Entry 3 Phase 11/0.4kV 750 kVA 5 Ground Mounted 11/0.4kV Cable Entry 3 Phase 11/0.4kV 1000 kVA 6 Pole Mounted 11/0.4kV Bushing Terminations 1 Phase 11/0.4kV 30 kVA 14 Pole Mounted 11/0.4kV Bushing Terminations 1 Phase 11/0.4kV UP TO AND INCLUDING 15 kVA 61 Pole Mounted 11/0.4kV Bushing Terminations 3 Phase 11/0.4kV 100 kVA 37 Pole Mounted 11/0.4kV Bushing Terminations 3 Phase 11/0.4kV 200 kVA 16 Pole Mounted 11/0.4kV Bushing Terminations 3 Phase 11/0.4kV 50 kVA 82 Pole Mounted 11/0.4kV Bushing Terminations 3 Phase 11/0.4kV 500 kVA 1 Pole Mounted 11/0.4kV Bushing Terminations 3 Phase 11/0.4kV UP TO AND INCLUDING 30 kVA 1053 1373 Make Asset Category AEI Quantity Rack ‐ mount Circuit Breaker Cooper Pole – mount recloser 10 Nulec Pole – mount recloser 5 6 Cooper Pole – mount sectionaliser Electropar Pole – mount, remotely operated Air Break Switch 18 Schneider Pole – mount, manually operated Air Break Switch (load break) 36 Schneider Pole – mount, manually operated Air Break Switch (non‐load break) DDO’s Pole – mount drop – out fuse assembly (line isolation) 11.4
8 95 213 Asset Age Profiles
Age profiles are used to determine where in the life cycle the asset population sits as it is the
probability density function (summation) of survival curves (bath-tub curve) for each asset
(per the conceptual asset life profile figure below).
Populations that display a roll-off of survival at certain age give an indication of the point at
which an assets operating costs increase because they need more intensive maintenance
and their reliability declines i.e. the age where they pass the optimal point with regard to life
cycle costs. It also indicates how many years the asset can remain in service (with rising
costs) before its performance becomes unacceptable and/or it fails in service.
The roll-off point of the survival curve roughly approximates to the optimal point of the Life
Cycle Cost depending on how sensitive/critical asset management objectives are to the
asset performance.
Page 142 of 193
However the process is not an exact science and relies on the experience and judgement of
the asset manager. This is because historical records of asset age and quantity are not likely
to be consistent and/or accurate, the asset deployed changes in materials, type and
specification, there is variation in the quantities deployed every year, and the level of
maintenance during the earlier life asset is in-determinant in terms of its contribution to life
extension.
For example, the age of an 11kV line is derived from the date it was originally constructed in
its entirety. There are no records of whether the materials were new or recycled. The
conductors and poles have different life expectancies. The standard for poles has changed
from wooden to concrete. It is the condition of the wooden poles that is currently driving HV
Line maintenance.
Depending on a particular asset groups significance in terms of criticality determines the
polices, strategies and practices applied to its maintenance and/or replacement. Critical
assets for example, might get replaced before they reach the minimum cost point because a
lower risk of in-service failure is deemed appropriate. However, when an asset passes its
optimal point it displays rising costs for declining performance. There is a case for replacing
assets before they get into this state because if they are replaced early before reaching the
optimal cost/life point their costs are still higher than optimal but their performance is
significantly better for that higher cost. This rationale is used to spread the replacement time
period of asset populations replacement phase. Eventually, after several life cycles, a
matured asset population will reach a steady state in terms of the annual quantities being
renewed.
Figure 20 – Conceptual Asset Age Profile Curves / Interval Setting
Page 143 of 193
Figure 20 continued – Conceptual Asset Age Profile Curves / Interval Setting
11.4.1 Asset Age Profile Graphs
Provided below are the age profile graphs for the main categories of network asset.
Page 144 of 193
Figure 21 – High Voltage Pole Age Profile by Material Type
Page 145 of 193
Figure 22 – 11kV Overhead Conductor Age Profile (Length and Type by Year of Installation)
Page 146 of 193
Figure 23 – 11kV Underground Cable Age Profile (Length and Type by Year of Installation)
Page 147 of 193
Figure 24 – LV Overhead Conductor Age Profile (Length and Type by Year of Installation)
Page 148 of 193
Figure 25 – LV Underground Cables Age Profile (Length and Type by Year of Installation)
Page 149 of 193
Figure 26 – Small Transformer (<75kVA) Age Profile – Number Installed per Year by Capacity Rating
Page 150 of 193
Figure 27 – Large Transformer (>50kVA) Age Profile – Number Installed per Year by Capacity Rating
Page 151 of 193
Figure 28 – Air Break Switch Age Profile (Quantity by Year of Installation)
Page 152 of 193
Note: limited age profile data is available for LV Poles. The asset records only have the date
of construction for LV Lines.
The above charts on conductor are also limited as to age profiles because of the practice of
reusing second-hand conductor. LV records were not consistently kept prior to
undergrounding programmes. Similarly data on the LV lines underbuilt on HV Lines may
relate to HV construction dates.
11.4.2 Asset Age Profile Conclusions
The survival rate of hardwood poles declines rapidly after 45 years. Scanpower has a policy
of not climbing wooden poles, therefore safety management is currently driving renewal
programmes. This population is at the end of its economic service life and at the life-cycle
cost minimum. Lower condition pole populations (LV and service lines) are displaying higher
fault response and reactive maintenance costs indicating this asset has past the optimum
cost/performance trade-off.
LV service lines in particular are well past the optimal replacement point. However
Scanpower does not own these assets and their owners take a much shorter term view of
costs and risks. Scanpower therefore intends to control the impact of the rising cost of
operating these assets via inspection and notification services.
The transformers population is displaying evidence that the population is approaching its
service limits. The asset is costly to renew if left to fail in service. The more optimal strategy
is to start age replacement of population slightly ahead their predicted end of service. This
smoothes expenditure at a small cost premium but does not incur the performance penalty in
addition to the cost premium that results from leaving asset in service past its optimal service
life.
No life cycle conclusions can be drawn on other assets categories as the asset there is
inadequate data and/or the life cycle is not sufficiently progressed.
11.5
Drivers for Maintenance Planning
11.5.1 Overview of Performance and Condition Assessment
Scanpower’s AM process for maintenance and renewals programmes is based on a cycle of:

Targeting inspections, (which in the first instance are visual), on the basis of known
condition, age and performance feedback from fault cause analysis. Inspection cycle
periods are determined by consideration of type (e.g. wood versus concrete poles) and
age. As the asset ages inspection frequency increases ensure that the survival roll-off
point is captured before in-service failure. This is an improvement on earlier plans
where inspection was comprehensive and at fixed intervals.

The inspection process results include a risk assessment where assets are graded by
significance of the defect and urgency with which it requires attention. This is a
Page 153 of 193
standard risk matrix approach and the management actions it drives are dependent on
the assets criticality assessment.

A rule based approach is also applied to determine whether or not assets will receive
more formal testing such as ultra-sounding wooden poles. The data obtained from this
testing allows more accurate assessment of remaining life and whether renewal is
necessary or a lesser repair is adequate. This is reactive maintenance.
Figure 29 – Performance and Condition Factors – Conceptual Model
Test results are fed back into the population condition data to improve the accuracy of
records. For example, by modelling the design pole strength of standard structures and
assigning a design strength to each pole record, the remaining strength can be better
quantified by de-rating the structure for various conditions (e.g. missing stay) found during
inspection. The resulting Safety Index can then be applied to prioritising replacement
programmes. This is a continuous improvement process as illustrated above.
Failure mode analysis and analysis of historical data is a lagging performance indicator
whilst condition assessment is considered a leading performance indicator. The Historical
data applied to priorities is an example of the application of lagging performance indicator
11.5.2 Criticality and Risk Assessment
Without a sub-transmission system and its associated high value assets, Scanpower does
not have assets it assesses as being critical in terms of the risk profile they present to
delivery of its most critical mission – keeping the power supply on.
Page 154 of 193
This tends to limit the options with regard to economically justified maintenance. Leaving
assets in service until they fail is a valid strategy in many parts of Scanpower’s low load
density network.
Figure 30 – Risk-based Analysis and Justification Model
11.5.3 Reliability and Cost Performance
Consequently Scanpower applies mostly “rule-based” strategies for its core distribution
assets. Reliability and cost performance (both the cost of unplanned response and the cost
of planned or pre-emptive maintenance) are the two main drivers for selection of
maintenance strategies.
11.5.4 Maintainability and Operability
These are also considerations that form part of a holistic asset management approach.
However the greatest opportunity for addressing issues with maintenance and operability is
at the time of design e.g. design for live line maintenance. Altering work practice is an option
for improvements in the mid-life cycle. Maintenance may therefore include elements of
continuous improvement and/or modification. Relocating assets to more optimal positions in
the network is an example.
Page 155 of 193
11.5.5 Modernisation, Quality and Safety Improvements
Scanpower also applies some historical data derived strategies with regard to specific assets
identified with age deterioration, quality, safety, or other sustainable performance issues.
11.5.6 Systemic Issues
Some issues of performance are driven by systemic issues such as:

Trade-offs made at the time of design to meet economic constraint on the cost of
supply e.g. lower strength/capacity design standards, reuse of second hand materials,
line route/accessibility, etc.

Operating practices – Scanpower’s use of isolators as its primary switching device has
the disadvantage of not being able break 3 phase load for example.

Systems engineering – technology is only an improvement when it operates correctly.
11.6
Maintenance Driver Analysis by Asset Category
11.6.1 Hardwood HV Poles
Table 32 below summarises the maintenance drivers / approach to hardwood HV poles.
Table 32 – Hardwood HV Poles Maintenance Driver Summary
HARDWOOD HV POLES Maintenance Drivers POLICY & PRACTICE  All hardwood poles to be eliminated from the system by 2020 requiring 193 poles per year to be changed for 8 years. o Safety policy: Wooden poles must not be climbed with just a ladder. o Age renewal: some poles are known to have been second hand when installed and consequently the oldest poles are over 50 years old.  In terms of safety compliance, all remaining poles will be subject to below ground inspection over the coming three years at a rate of 515 per year to allow for prioritisation of maintenance activity. CRITICALITY AND RISK ASSESSMENT  This asset category is of moderate criticality to the over all system, therefore rules based asset management practices have been applied.  Maintenance work will be inspection driven with testing determining remaining life and urgency.  Risk weighting has been carried both in terms of ICPs and load.  Impact and probability drivers assigned equal weighting as criticality is moderate Table 33 below summarises the expected maintenance activity by feeder and years to
completion.
Page 156 of 193
Table 33 – Hardwood HV Poles Maintenance Prioritisation, Risk Scoring and Forecast Implementation Time Frames
Gap Analysis – Hardwood HV Poles Feeder Weber Mangatera Central Pacific East North Adelaide Te Rehunga Town No.1 Country Town No.2 Total No. of HW HV Poles 563 292 24 46 11 133 51 63 129 169 66 1547 % of Population 36% 19% 2% 3% 1% 9% 3% 4% 8% 11% 4% 3 Yr Inspection Cycle 188 97 8 15 4 44 17 21 43 56 22 ICP Driven (SAIDI Risk) 1.53 0.55 0.10 0.09 0.06 0.49 0.10 0.13 0.13 0.28 0.08 kWh Driven (VoLL Risk) 1.23 0.36 0.05 0.16 0.10 0.61 0.11 0.22 0.14 0.31 0.02 Average 1.38 0.46 0.08 0.13 0.08 0.55 0.11 0.17 0.13 0.29 0.05 Risk Weighting 40% 13% 2% 4% 2% 16% 3% 5% 4% 9% 1% 2011/12 Feeder SAIDI Class C 21.8 11.6 10.3 0.6 % of All System Faults 39% 21% 0% 18% 1% 516 Security Risk Indexes 1.4 0% 3% 8.4 0% 15% 0% 2% 3% 100% 55.7 SAIDI by Cause ‐ Condition 15% 37% 6% 99% 11.3 Condition SAIDI 3.27 4.29 0.00 1.40 0.00 0.17 0.00 1.60 0.00 0.62 0.59 11.94 Condition Weighting 27% 36% 0% 12% 0% 1% 0% 13% 0% 5% 5% Targets 100% 1.6 3.42 Inspection Driven 19 10 1 2 0 4 2 2 4 6 2 53 Risk Driven 28 9 2 3 2 11 2 4 3 6 1 70 Performance Driven 19 25 0 8 0 1 0 9 0 4 3 70 Total 66 44 2 12 2 17 4 15 7 15 7 192 Years to Elimination 8.51 6.60 10.06 3.73 5.72 7.99 13.12 4.18 18.45 11.06 9.90 Page 157 of 193
11.6.2 Hardwood LV Poles
Table 34 below summarises the maintenance drivers / approach to hardwood HV poles.
Table 34 – Hardwood LV Poles Maintenance Driver Summary
HARDWOOD LV POLES Maintenance Drivers POLICY & PRACTICE  All hardwood poles to be eliminated from the system by 2020 requiring 65 poles per year to be changed for 8 years. o Safety policy: Wooden poles must not be climbed with just a ladder. o Age renewal: some poles are known to have been second hand when installed and consequently the oldest poles are over 50 years old.  In terms of safety compliance, all remaining poles will be subject to below ground inspection over the coming three years at a rate of 172 per year to allow for prioritisation of maintenance activity. CRITICALITY AND RISK ASSESSMENT  This asset category is of moderate criticality to the over all system, therefore rules based asset management practices have been applied.  Maintenance work will be inspection driven with testing determining remaining life and urgency.  Risk weighting – prioritise urban locations where in‐situ risk is higher.  Impact and probability drivers assigned equal weighting as criticality is moderate Table 35 below summarises the expected maintenance activity by feeder and years to
completion.
Page 158 of 193
Table 35 – Hardwood LV Poles Maintenance Prioritisation, Risk Scoring and Forecast Implementation Time Frames
Gap Analysis – Hardwood LV Poles Feeder Weber Mangatera Central Pacific East North Adelaide Te Rehunga Town No.1 Country Town No.2 Total 88 79 42 25 0 97 38 22 49 52 25 517 17% 15% 8% 5% 0% 19% 7% 4% 9% 10% 5% 29 26 14 8 0 32 13 7 16 17 8 ICP Driven (SAIDI Risk) 1.53 0.55 0.10 0.09 0.06 0.49 0.10 0.13 0.13 0.28 0.08 kWh Driven (VoLL Risk) 1.23 0.36 0.05 0.16 0.10 0.61 0.11 0.22 0.14 0.31 0.02 Average 1.38 0.46 0.08 0.13 0.08 0.55 0.11 0.17 0.13 0.29 0.05 Risk Weighting 40% 13% 2% 4% 2% 16% 3% 5% 4% 9% 1% 2012 LV Faults 19 4 8 6 1 17 6 13 18 17 11 % of LV Faults 16% 3% 7% 5% 1% 14% 5% 11% 15% 14% 9% Condition Weighting 16% 3% 7% 5% 1% 14% 5% 11% 15% 14% 9% No. of HW LV Poles % of Population 3 Yr Inspection Cycle 172 Load Density Indexes Targets 3.42 120 Inspection Driven 3 3 2 1 0 4 1 1 2 2 1 20 Risk Driven 9 3 0 1 0 4 1 1 1 2 0 22 Performance Driven 4 1 2 1 0 3 1 2 3 3 2 23 Total 16 7 4 3 1 11 3 4 6 7 3 65 5.53 11.69 11.49 8.52 0.00 9.20 11.49 4.93 7.91 7.26 7.39 Years to Elimination Page 159 of 193
11.6.3 Small Transformers (Below 100kVA)
Table 36 – Small Transformers – Maintenance Policy, Criticality and Risk Assessment, and Gap Analysis
Policy and Practice Service Life Renewal Growth Quality Standarisation Security Safety Indefinite ‐ tend to be replaced for other reasons before failure ‐ potentially at start of age renewal cycle (monitor failures) Manufacturing Standards reduced in 1970's ‐ newer transformers have a shorter nominal life 25‐35yrs c.f. with 45yrs of BS147 Where poles are being replaced the transformer will also be renewed if old than 20 years Transformers manufactured before 1964 have higher iron losses ‐ to be systematically eliminated from population Past practice of refurbishing old transformers stopped ‐ does not extend life economically Limited to new installations ‐ few capacity upgrades Shift to concrete pole/steel crossarm standard design ‐ match crossarm durability to transformer To be reviewed with respect to low capacity supplies and alternative solutions. No contingent capacity capacity provided as interconnection limited Privision for 1 fault per annum Theft of earths biggest safety issue ‐ survey area when discovered and replace as required Older installations may need more satistfactory earthquake rated mounting ‐ upgrade with HV inspection Forecast Work 6 p.a. for 10 years 6 p.a. for 10 years 14 p.a. for 12 years 8 p.a. 1 p.a. 20 p.a. 20 p.a. Criticality and Risk Assessment Criticality Low (2‐3 ICPs per transformer) ‐ therefore replaced on failure, growth, condition, quality or safety Risk Weighting Low ‐ transformers are very lightly loaded and therefore not stressed Lightning and trees clashing lines are the most common root cause of failue and shorten transformer life Performance Low capacity utilisation as a result of historic 3 phase development standard 3 phase supplies have a reduced probability of total loss of supply and reduce the investment in customer service mains However, more costly to the network and a barrier to alternative supply Risk Management Inspection driven ‐ rust, leaks, earth testing, safety ‐ all testing is visual, oil testing is not undertaken Opportunistic renewal undertaken when appropriate Page 160 of 193
Table 35 continued – Small Transformers – Maintenance Policy, Criticality and Risk Assessment, and Gap Analysis
Gap Analysis Average installations per annum over 60 year population range Average installations per annum over last 10 years (Increase believed to be related to pole replacement ‐ understated due to legacy practice of avoiding transformer poles) (However will assume high correlation between aged poles and transformers) Pre 1964 transformers Forecast Work 20 p.a. 26 p.a. 14 p.a. for 12 years 11.6.4 Large Transformers (100kVa and above)
Table 37 – Large Transformers – Maintenance Policy, Criticality and Risk Assessment, and Gap Analysis
Policy and Practice Service Life Renewal Growth Quality Standarisation Security Safety Indefinite – tend to be replaced for other reasons before failure Manufacturing Standards reduced in the 1970’s – newer transformers have a shorter nominal life of 25‐35yrs c.f. with 45yrs of BS147 Where poles are replaced the transformer will also be renewed if older than 20 years Transformers manufactured before 1964 have high iron losses – to be systematically removed from the population Past practice of refurbishing old transformers stopped – does not extend life economically Limited to new installations – few capacity upgrades Shift to concrete pole / steel crossarm standard design – match crossarm durability to transformer To be reviewed with respect to low capacity supplies and alternative solutions No contingent capacity provided as interconnection limited Provision for 1 fault per annum Theft of earths is the main safety issue – survey area when discovered and replace as necessary Older installations may need more satisfactory earthquake rated mounting – upgrade with HV inspection Forecast Work 1 p.a. for 10 years 1 p.a. for 10 years 2 p.a. for 7 years 3 p.a. 1 p.a. 20 p.a. 20 p.a. Page 161 of 193
Table 37 continued – Large Transformers – Maintenance Policy, Criticality and Risk Assessment, and Gap Analysis
Criticality and Risk Assessment Criticality High (many ICPs per transformer) – therefore replaced on growth, condition, quality or safety but prior to failure Risk Weighting Medium – transformer loadings not accurately known at the present time Minimal LV interconnection – low level of contingency capacity provisioned Over loading is the most common root cause of failure and shortens transformer life Performance High capacity utilisation as a result of low ADMD assumptions 3 phase supplies have a reduced probability of total loss of supply and reduce the investment in consumer service mains However more costly to the network and a barrier to alternative supply Risk Management Inspection driven – rust, leaks, earth testing, safety review – visual only, no oil testing performed Opportunistic renewal when appropriate Infill distribution and develop LV interconnections as new capacity is required Population Statistics Ground mounted Pole mounted Pre 1964 Forecast Work 36 110 14 Gap Analysis Average installations per annum over 60 year population range Average installations per annum over last 10 years (Increase believed to be related to pole replacement ‐ understated due to legacy practice of avoiding transformer poles) (However will assume high correlation between aged poles and transformers) Pre 1964 transformers Forecast Work 2 p.a. 7 p.a. 2 p.a. for 7 years Page 162 of 193
11.6.5 Air Break Switches
Table 38 – Air Break Switches – Maintenance Policy, Criticality and Risk Assessment, and Gap Analysis
Policy and Practice Service Life Renewal Growth Quality Standarisation Security Safety Nominal life of 35 years – tend to remain on system until faulty May be recycled and / or relocated to locations requiring lower duty Load Break heads to be fitted to ABS breaking more than 1000kVA transformer capacity ABS are to be rated for Load Break Fault Make duty. Must be operable from the ground without ladders or shotgun stick. Must be accessible – not obstructed by fences, ditches, vegetation, stock etc. Standardise to underhung mounting for live line installation ore removal Line will not be shackled off onto the ABS frame Located where 3 phase switching and / or fault isolation / sectionalising is required. Density to be increased. Provision for 1 fault per annum. Earthing standard revised – upgrades in progress Forecast Work 2 p.a. 2 p.a. 2 p.a. for 10 years 1 p.a. 1 p.a. 15 p.a. for 10 years Criticality and Risk Assessment Criticality Low – fuses are the primary isolation points, therefore ABS are replaced on failure, growth, condition, quality or safety Risk Weighting Low – rated for duty Failure modes – out of adjustment, contact burning, cracked insulator / frost, animal / bird related blow ups Performance High – mature proven technology 3 phase supplies have a reduced probability of total loss of supply and reduce the investment in consumer service mains However more costly to the network and a barrier to alternative supply Risk Management Inspection driven – operating mechanisms, arc horn alignment, earth test, safety review Opportunistic renewal and reoptimisation of location – old equipment may be redeployed Page 163 of 193
Table 37 continued – Air Break Switches – Maintenance Policy, Criticality and Risk Assessment, and Gap Analysis
Gap Analysis Automation projects in 2005 and 2008 account for 40 installations Excluding these the average installation rate over the past 10 years 13% of the population is older than the 35 year nominal life – indicative of recycling Additions due to growth Age or fault related replacements Load break heads required in some locations – replace with new ABS then relocate existing ABS to more suitable location Density of sectionalising points to be increased for faster fault isolating processes Forecast Work 4 p.a. 1 p.a. 2 p.a. 11.6.6 Tree Management
Table 39 – Tree Management and Maintenance – Summary of Drivers, Objectives, Policies and Strategies
Background Trees are not a network asset but Scanpower has a regulatory requirement to manage the safety issues they create when they interfere with its assets. Tree cutting is the single largest component of maintenance expenditure ‐ managing these costs is driver of operational effciency of the Network business. Scanpower has a high tree management challenge resulting from its area being windy and having relatively intensive forrestry. Objectives ALARP ‐ Fire risks asociated with Scapower owned lines. ALARP ‐ Public safety where public have uncontrolled access to Scanpower owned asset. ALARP ‐ Risks to stock and property from Scanpower owned asset. Outages caused by tree/line clashing < 2000 CML per event. Note: There are no "reasonably practical" solutions to addressing mature forrestry blocks compliant with regulation in terms of clearance but presenting a fall zone risk. Page 164 of 193
Table 39 continued – Tree Management and Maintenance – Summary of Drivers, Objectives, Policies and Strategies
Assumptions: Forrestry owners also actively manage fire risk. Private property owners manage risks on their property and control public access accordingly. Service line owners manage their own tree issues. Policies Free first cut. No interest declarations subject to strict compliance with legistlation. Disconnection preferred alternative response to forced cuts for service lines. Scanpower will meet duty to notify non‐compliant discoveries ‐ it will not police or enforce regulations. No restoration of supply following a tree related until tree clearances have been restored . Scanpower provides a network subsidised tree trimming service to address lack of resourcing available to tree owners ‐ this service proitises network tree clearing. Gap Analysis Trees are the biggest single cause of outage on Scanpowers network ‐ refer Fault Cause Analysis. Cause analysis indicates that the high impact outages are caused by trees breaking in high winds damanging lines in difficult access locations ‐ typically mature forrestry planted after line construction. These outages are not adequately mitigated by compliance with tree regulations ‐ cost issues shift them outside the "reasonably practical" threshold. Addressing the protection schemes performance to reclose, sectionalise, and clear transcient faults would address tree clashing and burning issues with regard to managing outage. Resource analysis has determined that there are a lack of tree cutting services in the district to allow tree owners to act on tree notices within prescribed timeframes. Historical cutting statistics indicate a backlog in cutting resulting from lack of resource and resistance from tree owners to carry the cost. Refer Cutting Statistics Analysis. Strategy Increase the number of tree crews and dedicate a crew to network only tree clearing. Appoint a Tree Services Manager to drive notification, risk assessment, and work gramming processes. Direct reporting and funding of the Tree Smart to the Network Manager. Refocus risk assessment on network only priorities, safety and cost balance. Refer Tree Risk Assessment Process. Target faster inspection/notice cycles (2 per annum) with an 90% resolution/action target on each cycle. Migrate towards a higher component of chargeable work by eliminating backlog in first cuts and urgent notices. Improve clearance of transcient faults related to trees and wind via the Protection and Automation Plan. Page 165 of 193
11.6.6.1
Tree Risk Assessment Process
Figure 31 – Tree Risk Assessment Tool
Tree Risk Matrix ‐ 5x5 Probability Rating x Consequence Rating 5 Trees burning in HV Network Lines 4 Trees in the Growth Limit Zone of HV Network Lines 3 Trees burning in HV Service Lines 2 Trees in the Growth Limit Zone of HV Service Lines 1 Trees in the Growth Limit Zone of LV Network Lines Probability
Probabilty 5
5 10 15 20 25
Risk Assessment Priority 4
4
8 12 16 20
High 3 months 3
3
6
9 12 15
Medium 1 year 2
2
4
6
8 10
Low 3 years 1
1
2
3
4
5
1
2
3
4
5
Consequence Consequence +1 Fire risk and/or forestry +1 High population density and/or public access +1 Risk to property and/or stock +1 Outage likely to exceed 2000CML +1 Other Significant factor e.g. Major Customer, School, CBD Page 166 of 193
11.6.6.2
Tree Cutting Statistics and Forecast
Table 40 – Historic Tree Cutting Statistics
Year
1st Cuts incl. No Interest 2nd Cut No Interest 2nd Cut Tree Owner Cost Total Sites Cut
2005/06
159 0 0 159
2006/07
250 0 0 250
Sites per 2yr Cycle Sites p.a. New 1st Cuts p.a. New No Interest Cust p.a. Annual Total
Available Resources - Network Crew
338 169 46 8 223
250 Private Line Assumption - Tree Owner Cost
Available Resources - Service Crew
56 250 25% Backlog
Backlog Cummul. Backlog Urgent Cut Backlog Cut Backlog Notice Backlog
64 64 93 271 338 ‐27 37 2007/08
167 0 0 167
2008/09
100 0 0 100
2009/10
69 3 3 75
2010/11
43 7 1 51
2011/12
26 14 5 45
56 93 123 216 148 364 172 536 178 714 76% 21% 4% 112% Page 167 of 193
Table 41 – Forecast Tree Cutting Statistics
Forecasts
Urgent Cuts
1st Cuts
2nd Cuts
3rd Cuts
4th Cuts
Total Target - Network
Cuts at Network Cost
Cuts at Tree Owner Cost
Targeted Private Tree Work
(for full use of resource - 2 crews)
2012/13
93 54 3 2013/14
0 54 196 2014/15
0 54 72 124 2015/16
0 54 0 196 250
2016/17
0 54 0 187 0 241
2017/18
0 54 0 0 169 223
2018/19
0 54 0 0 169 223
150
250
250
150 56 194 103 203 194 72 234 194 54 252 194 54 243 203 54 225 221 54 225 221 Page 168 of 193
11.7
Maintenance Strategy and Practice
11.7.1 HV Line Inspections – Visual Line Inspections
Table 42 – HV Line Inspection Maintenance Strategy and Practice
HV Line Inspections ‐ visual ground inspections Objectives Cycle Scope Other Identify need/priority for targeted condition assessment Capture Defect Register records and assess defect criticality/risk Idendify development of safety issues ‐ not all issues are visible from perfomance monitoring Ensure maintenance is based on tangible necessity with regard to safety and performance Nominally every 5 years for mature assets ‐ dependent on age/condition risk assessments and/or preformance Age driven ‐ 1st inspection 25 years, 2nd and 3rd 10 years, then 5 yearly for wood, continue at 10 yearly for concrete Condition driven ‐ declining average condition indicates assets approaching end of life. Performance driven ‐ lines in areas of high wind exposure display higher hardware defect rates Ref. SP447 Includes check of broader issues such as trees, foundations/staying, and conductor condition Line patrols are initiated on a reactive basis when casue of a fault or protection setting was not identified The practice of line tightening 2‐5 years after construction is to be introduced as a quality improvement 11.7.2 Below Ground Pole Inspections – Ultrasound
Table 43 – Below Ground Pole Inspections Maintenance Strategy and Practice
Below Ground Pole Inspections ‐ ultrasound Objectives Cycle Scope Zero in service pole failures Identify remaining strength and service life Prioritse wooden pole replacement programme All hardwood poles over 3 years 1 cycle only as be eliminated from network within 10 years Softwood pole population will reach the age requiring inspections over next 5‐10 years Inspections are targeted by results of visual ground inpsections and/or reported defects Ultrasounds results are applied to assessment of design strength to determine remaining strength Risk assesmment criteria is applied to remaining strength to prioritise replacement programme 11.7.3 LV Line Inspections – Roadside Reticulation Only
Table 44 – LV Line (Roadside) Inspections Maintenance Strategy and Practice
LV Line Inspections ‐ roadside reticulation only Info As for HV poles with the following differentiation LV poles an spans are shorter, services provide lateral pole top support so design is inherently more robust Lower risks associated with lower voltage. Condition poor in low density rural areas ‐ limited justification for improvement Lower performance drivers as incidents affects fewer consumers Lower condition is driving higher reactive maintenance/fault response Poorer condition in low density rural areas ‐ limited justification for improvement Little merit in upgrading line when consumers relectant Scope Note a signifcant portion of the LV net is underbuilt on HV poles or has been undergrounded The condition of Telecom road crossing poles is driving decisions to underground Page 169 of 193
11.7.4 LV Service Lines (Not Owned by Scanpower – Operating Service Only)
Table 45 – LV Service Lines Maintenance Strategy and Practice
LV Service Lines ‐ not owned or managed by Scanpower ‐ default operating service only Info These assets are not covered by Line Function Services and Public Safety Management Systems Customer initiated maintenance proving inadequate ‐ driving fault response Poles very old and often light‐weight, conductor old and often inadaquate capacity Objectives Reducing the incidential costs and disruption to work programmes is being addressed via an inspection/notification process Scanpower is not the Regulator ‐ it limits its involvement to notification of non‐compliant or hazardous conditions Consumers will be encouraged to underground when renewing LV service mains Encourage capacity upgrade to improve voltage All repair work is chargeable and actioned by Contracting business unit not Network Cycle A single 10 year inspection cycle of all overhead services Process being developed by EEA will be trialed ‐ resourcing will be drawn from Contracting, Network fault crews, and electricians 11.7.5 HV Switchgear – Visual Ground Inspections
Table 46 – HV Switchgear Visual Ground Inspections Strategy and Practice
HV Switchgear ‐ visual ground inspections Info Includes ABS's, Reclosers, Auto LBS, Sectionalisers Objectives Capture Defect Register records and assess defect criticality/risk Identify development of safety issues Cycle Nominally every 5 years ‐ sites are visited more frequently as part of routine operating Age driven ‐ 1st inspection 25 years, 2nd and 3rd 10 years, then 5 yearly for wood, continue at 10 yearly for concrete Condition driven ‐ declining average condition indicates assets approaching end of life. Performance driven ‐ equipment with lower reliability inspected more frequently Scope Ref. SC2302 Includes check of broader issues such as trees, access, and earthing Functional and/or trip tests are undertaken on a reactive basis i.e. following a mal‐operating event. Other Modern equipment does not require field maintenance. Fusing and Isolators being reviewed as part of Automation and Protection Development Project ‐ 5 year programme 11.7.6 Ground Mounted Distribution Substations
Table 47 – Ground Mounted Distribution Substations Strategy and Practice
Ground Mounted Distribution Substations Objectives Capture Defect Register records and assess defect criticality/risk Identify development of safety issues Assess loading ‐ no MDI fitted so spot checks required Cycle Every 2 years ‐ sites are typically located in urban areas and transformer are larger, supplying more consumers May lead to installation of load recorders to assess loading May follow up with thermovision of cable terminations Condition driven ‐ addressing vandalism is the main issue Performance driven ‐ addressing loading is the main issue Scope Ref. MS2001 Includes check of broader issues such as safety notices, trees, access, and earthing Includes LV distribution frames and cable terminations Other Oil processing no longer economic Page 170 of 193
11.7.7 Pole Mounted Distribution Substations
Table 48 – Pole Mounted Distribution Substations Strategy and Practice
Pole Mounted Distribution Substations Objectives Capture Defect Register records and assess defect criticality/risk Identify development of safety issues Assess loading ‐ no MDI fitted so spot checks required Cycle Every 5 years ‐ sites are typically located in rural areas and transformers are smaller, supplying fewer consumers May lead to installation of load recorders to assess loading May follow up with thermovision of cable terminations Condition driven ‐ rusting and oil leaks main issues experienced Performance driven ‐ addressing loading is the main issue Scope Ref. SP420 Earth testing SP502 Includes check of broader issues such as safety notices, trees, birds nests, and earthing Includes LV Fusing and cable terminations 11.7.8 Tree Trimming
Table 49 – Tree Trimming Maintenance Strategy and Practice
Tree Trimming Objectives Eliminate high risk/intolerable tree issues Manage trees in the network lines to ALARP principles Provide/support adequate tree trimming resources within the district. Cycle 2 inspection/notfication cycles p.a. High priority sites ‐ 3 month resolution/action Medium priority sites ‐ 1 year resolution/action Low priority sites ‐ 3 year resolution/action or priority reassessed Target 90% cutting success rate per notice cycle Scope HV network owned lines supplying multiple customers have a higher priority Excludes Service lines other than notification of discovered issues unless interable safety issue (disconnect) Other Also addressed by Protection and Automation Project 11.8
Operating Budgets
11.8.1 Asset and Resource Quantity Targets
The maintenance planning process determines the quantities and priorities. Specific assets
asset can be targeted. Where there are a number of competing maintenance objectives
targets are balanced according to risk/cost – benefits. This is often necessary when there
are conflicting short term and long term objectives.
From this step the budget provisions derived from historical unit costs and the quantity of
labour/plant resources determined. The asset management team can then decide whether
additional resources need to be outsourced and/or specialist skills such a “live line” working
need to be provisioned in order to deliver on outage budgets for example. This process is
dynamic because the element of reactive work in response to condition assessment, for
example, may drive to the need to re-optimise the plan.
Page 171 of 193
11.8.2 Maintenance Expenditure Budget
Table 50 – 10 Year Maintenance Expenditure Budget by Asset Activity / Maintenance Type
Asset Type Quantity Unit Cost 11 kV Lines & Cables Routine and Preventative Ground Patrols ‐ after Faults 52 Refurbishment and Renewals Total Years 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 $13,000 $250 $13,000 10 $13,000 $13,000 $13,000 $13,000 $13,000 $13,000 $13,000 $13,000 $13,000 $13,000 $65,000 $39,000 10 $39,000 $39,000 $39,000 $39,000 $39,000 $39,000 $39,000 $39,000 $39,000 $39,000 $26,000 10 Pole Relocations 13 $3,000 Minor Maintenance 52 $500 LT Maintenance Routine and Preventative $26,000 $26,000 $26,000 $26,000 $26,000 $26,000 $26,000 $26,000 $26,000 $26,000 $52,000 $52,000 $52,000 $52,000 $52,000 $52,000 $52,000 $52,000 $52,000 $52,000 $52,000 Follow‐up repairs after Faults 104 $500 $52,000 10 Refurbishment and Renewals $61,240 Pole Relocations 6 $3,500 $21,000 10 $21,000 $21,000 $21,000 $21,000 $21,000 $21,000 $21,000 $21,000 $21,000 $21,000 Minor Maintenance 42 $500 $21,000 10 $21,000 $21,000 $21,000 $21,000 $21,000 $21,000 $21,000 $21,000 $21,000 $21,000 LT Misc. Voltage checks, etc. 26 $240 $6,240 10 $6,240 $6,240 $6,240 $6,240 $6,240 $6,240 $6,240 $6,240 $6,240 $6,240 Service Fuse Replacements 52 $250 $13,000 10 $13,000 $13,000 $13,000 $13,000 $13,000 $13,000 $13,000 $13,000 $13,000 $13,000 Transformer Maintenance Routine and Preventative $30,600 Inspection GM Subs 156 $50 $7,800 10 $7,800 $7,800 $7,800 $7,800 $7,800 $7,800 $7,800 $7,800 $7,800 $7,800 MD Check 156 $25 $3,900 10 $3,900 $3,900 $3,900 $3,900 $3,900 $3,900 $3,900 $3,900 $3,900 $3,900 Earth Testing (all equipment) 300 $50 $15,000 10 $15,000 $15,000 $15,000 $15,000 $15,000 $15,000 $15,000 $15,000 $15,000 $15,000 HV Term./LV Pillar Thermal Imaging 156 $25 $3,900 10 $3,900 $3,900 $3,900 $3,900 $3,900 $3,900 $3,900 $3,900 $3,900 $3,900 Page 172 of 193
Table 50 continued – 10 Year Maintenance Expenditure Budget by Asset Activity / Maintenance Type
Asset Type Total Years Refurbishment and Renewals Quantity Unit Cost $13,350 2013 2014 2015 2016 2017 2018 2019 2020 2021 Minor 6 $500 $3,000 Replace stolen Earthing 20 $240 Upgrade Seismic Standards 20 $240 Install CT's 30 $25 2022 10 $3,000 $3,000 $3,000 $3,000 $3,000 $3,000 $3,000 $3,000 $3,000 $3,000 $4,800 10 $4,800 $4,800 $4,800 $4,800 $4,800 $4,800 $4,800 $4,800 $4,800 $4,800 $4,800 5 $4,800 $4,800 $4,800 $4,800 $4,800 $0 $0 $0 $0 $0 $750 5 $750 $750 $750 $750 $750 $0 $0 $0 $0 $0 Switchgear Maintenance Routine and Preventative $15,300 $14,400 10 $14,400 $14,400 $14,400 $14,400 $14,400 $14,400 $14,400 $14,400 $14,400 $14,400 10 $900 $900 $900 $900 $900 $900 $900 $900 $900 $900 Pole top service /operation Check 36 $400 Thermal Imaging 36 $25 $900 Refurbishment and Renewals $75,000 Relocations 6 $5,000 $30,000 10 $30,000 $30,000 $30,000 $30,000 $30,000 $30,000 $30,000 $30,000 $30,000 $30,000 Fuse Coordination 1 $2,000 $2,000 5 $2,000 $2,000 $2,000 $2,000 $2,000 $0 $0 $0 $0 $0 HV Fusing 6 $1,500 $9,000 10 $9,000 $9,000 $9,000 $9,000 $9,000 $9,000 $9,000 $9,000 $9,000 $9,000 Upgrade Earthing/Handle 4 $1,000 $4,000 5 $4,000 $4,000 $4,000 $4,000 $4,000 $0 $0 $0 $0 $0 Regulator Overhaul 3 $6,000 $18,000 1 $18,000 $0 $0 $0 $0 $0 $0 $0 $0 $0 CB Overhaul 6 $2,000 $12,000 1 $12,000 $0 $0 $0 $0 $0 $0 $0 $0 $0 Secondary Systems Maintenance Injection Plant Maintenance $5,600 Support Contract 2 $800 $1,600 10 $1,600 $1,600 $1,600 $1,600 $1,600 $1,600 $1,600 $1,600 $1,600 $1,600 Annual Check 2 $2,000 $4,000 10 $4,000 $4,000 $4,000 $4,000 $4,000 $4,000 $4,000 $4,000 $4,000 $4,000 Page 173 of 193
Asset Type Scada Maintenance Quantity Unit Cost Total Years $24,000 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 Scada Master Support 1 $6,000 $6,000 10 $6,000 $6,000 $6,000 $6,000 $6,000 $6,000 $6,000 $6,000 $6,000 $6,000 Licences 1 $6,000 $6,000 10 $6,000 $6,000 $6,000 $6,000 $6,000 $6,000 $6,000 $6,000 $6,000 $6,000 Programming & Maintenance 6 $2,000 $12,000 10 $12,000 $12,000 $12,000 $12,000 $12,000 $12,000 $12,000 $12,000 $12,000 $12,000 Radio System Maintenance $18,500 Annual Check 1 $4,500 $4,500 10 $4,500 $4,500 $4,500 $4,500 $4,500 $4,500 $4,500 $4,500 $4,500 $4,500 Support 2 $3,000 $6,000 10 $6,000 $6,000 $6,000 $6,000 $6,000 $6,000 $6,000 $6,000 $6,000 $6,000 Licences and Site Rentals 1 $8,000 $8,000 10 $8,000 $8,000 $8,000 $8,000 $8,000 $8,000 $8,000 $8,000 $8,000 $8,000 Miscellaneous Maintenance $11,200 Safety 2 $1,500 $3,000 10 $3,000 $3,000 $3,000 $3,000 $3,000 $3,000 $3,000 $3,000 $3,000 $3,000 Quality Investigations 12 $500 $6,000 10 $6,000 $6,000 $6,000 $6,000 $6,000 $6,000 $6,000 $6,000 $6,000 $6,000 Compliance, inspections, etc. 6 $200 $1,200 10 $1,200 $1,200 $1,200 $1,200 $1,200 $1,200 $1,200 $1,200 $1,200 $1,200 Unplanned 2 $500 $1,000 10 $1,000 $1,000 $1,000 $1,000 $1,000 $1,000 $1,000 $1,000 $1,000 $1,000 Faults Maintenance $87,020 11kV Distribution Faults 52 $500 $26,000 10 $26,000 $26,000 $26,000 $26,000 $26,000 $26,000 $26,000 $26,000 $26,000 $26,000 11kV Equipment Faults 4 $750 $3,000 10 $3,000 $3,000 $3,000 $3,000 $3,000 $3,000 $3,000 $3,000 $3,000 $3,000 Transformer Faults 4 $750 $3,000 10 $3,000 $3,000 $3,000 $3,000 $3,000 $3,000 $3,000 $3,000 $3,000 $3,000 Tree Faults 26 $750 $19,500 10 $19,500 $19,500 $19,500 $19,500 $19,500 $19,500 $19,500 $19,500 $19,500 $19,500 LT Service Faults (chargeable) 104 $0 $0 10 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 LT Distribution Faults 156 $200 $31,200 10 $31,200 $31,200 $31,200 $31,200 $31,200 $31,200 $31,200 $31,200 $31,200 $31,200 Page 174 of 193
Asset Type Quantity Unit Cost Total Years 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 LT Fuse Base Replacements 52 $80 $4,160 10 $4,160 $4,160 $4,160 $4,160 $4,160 $4,160 $4,160 $4,160 $4,160 $4,160 Secondary Systems Faults 4 $40 $160 10 $160 $160 $160 $160 $160 $160 $160 $160 $160 $160 $477,849 $477,849 $447,852 $447,855 $447,858 $447,861 $436,314 $436,317 $436,320 $436,323 $436,326 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 11.8.3 Growth and Renewal Capital Budgets
Table 51 – 10 Year Capital Expenditure Budget
Description 11kV HW Pole Replacement Quantity Unit Cost Budget Years $454,409 8 $83,234 $83,234 $83,234 $83,234 $83,234 $83,234 $83,234 $83,234 $0 $0 Weber 47 $1,756 $83,234 Mangatera 34 $1,756 $60,578 8 $60,578 $60,578 $60,578 $60,578 $60,578 $60,578 $60,578 $60,578 $0 $0 Central 2 $1,756 $2,782 8 $2,782 $2,782 $2,782 $2,782 $2,782 $2,782 $2,782 $2,782 $0 $0 Pacific 11 $1,756 $18,978 8 $18,978 $18,978 $18,978 $18,978 $18,978 $18,978 $18,978 $18,978 $0 $0 East 2 $1,756 $2,733 8 $2,733 $2,733 $2,733 $2,733 $2,733 $2,733 $2,733 $2,733 $0 $0 North 12 $1,756 $21,444 8 $21,444 $21,444 $21,444 $21,444 $21,444 $21,444 $21,444 $21,444 $0 $0 Adelaide 2 $1,756 $3,841 8 $3,841 $3,841 $3,841 $3,841 $3,841 $3,841 $3,841 $3,841 $0 $0 Te Rehunga 13 $1,756 $22,749 8 $22,749 $22,749 $22,749 $22,749 $22,749 $22,749 $22,749 $22,749 $0 $0 Page 175 of 193
Table 51 continued – 10 Year Capital Expenditure Budget
Description Quantity Unit Cost Budget Years 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 Town No.1 3 $1,756 $4,725 8 $4,725 $4,725 $4,725 $4,725 $4,725 $4,725 $4,725 $4,725 $0 $0 Country 10 $1,756 $16,928 8 $16,928 $16,928 $16,928 $16,928 $16,928 $16,928 $16,928 $16,928 $0 $0 Town No.2 4 $1,756 $7,839 8 $7,839 $7,839 $7,839 $7,839 $7,839 $7,839 $7,839 $7,839 $0 $0 Pole Replacements ‐ Condition Driven 53 $3,332 $176,579 8 $176,579 $176,579 $176,579 $176,579 $176,579 $176,579 $176,579 $176,579 $0 $0 Pole Replacements ‐ Work Arising 16 $2,000 $32,000 10 $32,000 $32,000 $32,000 $32,000 $32,000 $32,000 $32,000 $32,000 $32,000 $32,000 $115,101 LT HW Pole Age Replacement Pole Replacement ‐ All feeders 32 $1,985 $63,504 8 $63,504 $63,504 $63,504 $63,504 $63,504 $63,504 $63,504 $63,504 $0 $0 Pole Replacements ‐ Condition Driven 13 $1,985 $25,799 8 $25,799 $25,799 $25,799 $25,799 $25,799 $25,799 $25,799 $25,799 $0 $0 Pole Replacements ‐ Work Arising 13 $1,985 $25,799 10 $25,799 $25,799 $25,799 $25,799 $25,799 $25,799 $25,799 $25,799 $25,799 $25,799 $40,845 $40,845 $40,845 $40,845 $40,845 $0 $0 $0 $0 $0 $0 $0 $0 $308,952 11kV Switchgear Age Replacement Woodlands GXP bypass structures Transformers Large (100kVA+) 1 2 Work Arising 1 $38,619 $38,619 10 $38,619 $38,619 $38,619 $38,619 $38,619 $38,619 $38,619 $38,619 $38,619 $38,619 Pole Replacement Programme 1 $38,619 $38,619 8 $38,619 $38,619 $38,619 $38,619 $38,619 $38,619 $38,619 $38,619 $0 $0 Age replacement ‐ pre 1964 2 $38,619 $77,238 7 $77,238 $77,238 $77,238 $77,238 $77,238 $77,238 $77,238 $0 $0 $0 Growth 3 $38,619 $115,857 10 $115,857 $115,857 $115,857 $115,857 $115,857 $115,857 $115,857 $115,857 $115,857 $115,857 Faults 1 $38,619 $38,619 10 $38,619 $38,619 $38,619 $38,619 $38,619 $38,619 $38,619 $38,619 $38,619 $38,619 Page 176 of 193
Table 51 continued – 50 Year Capital Expenditure Budget
Description Transformers Small (100kVA‐) Quantity Unit Cost Budget Years 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 $216,458 Work Arising 6 $6,185 $37,107 10 $37,107 $37,107 $37,107 $37,107 $37,107 $37,107 $37,107 $37,107 $37,107 $37,107 Pole Replacement Programme 6 $6,185 $37,107 8 $37,107 $37,107 $37,107 $37,107 $37,107 $37,107 $37,107 $37,107 $0 $0 Age replacement ‐ pre 1964 14 $6,185 $86,583 12 $86,583 $86,583 $86,583 $86,583 $86,583 $86,583 $86,583 $86,583 $86,583 $86,583 Growth 8 $6,185 $49,476 10 $49,476 $49,476 $49,476 $49,476 $49,476 $49,476 $49,476 $49,476 $49,476 $49,476 Faults 1 $6,185 $6,185 10 $6,185 $6,185 $6,185 $6,185 $6,185 $6,185 $6,185 $6,185 $6,185 $6,185 New Connections (works) $115,080 large (50kVA+) 7 $7,119 $49,833 10 $49,833 $49,833 $49,833 $49,833 $49,833 $49,833 $49,833 $49,833 $49,833 $49,833 Small (50kVA‐) 26 $2,510 $65,247 10 $65,247 $65,247 $65,247 $65,247 $65,247 $65,247 $65,247 $65,247 $65,247 $65,247 $1,250,845 $1,250,845 $1,250,845 $1,210,000 $1,210,000 $1,210,000 $1,210,000 $1,210,000 $1,132,762 $545,325 $545,325 Total Page 177 of 193
11.8.4 Ten Year Network Expenditure Summary
Table 52 – 10 Year Network Expenditure Forecast (all Categories)
Type Maintenance 2013 2014 2015 2016 2017 $477,849 $447,852 $447,855 $447,858 $447,861 Routine Capital $1,250,845 $1,250,845 $1,210,000 $1,210,000 $1,210,000 Network Development $1,243,449 $869,194 $592,245 $314,946 $515,947 Total $2,972,143 $2,567,891 $2,250,100 $1,972,804 $2,173,808 Type 2018 2019 2020 2021 2022 $436,314 $436,317 $436,320 $436,323 $436,326 $1,210,000 $1,210,000 $1,132,762 $545,325 $545,325 $89,248 $46,749 $46,750 $131,751 $25,752 $1,735,562 $1,693,066 $1,615,832 $1,113,399 $1,007,403 Maintenance Routine Capital Network Development Total Figure 32 – 10 Year Network Expenditure Forecast (All Categories)
Scanpower is opting to treat pole replacements whether condition driven or age renewal as
capital. The pole replacement programme accounts for approximately 50% of the routine
capital expenditure hence the drop at the end to the wooden pole replacement programme in
approximately 8 years. Potentially softwood pole populations and wooden crossarms will be
displaying age performance issues by this time.
Page 178 of 193
Maintenance expenditure is relatively flat as would be expected in an asset base that is
mature and in its steady state. Tree trimming expenditure is not included in these figures. It
is treated as separate profit centre. While it currently is the main non-asset maintenance
expense, it is forecast to decline rapidly as repeat cutting cycles will be charged to the tree
owner.
Development expenditure projections are limited by the distance visiable into the future.
Scanpower is delaying development to allow the role of DG and smart grid technology to
become clearer. Generation and associated R&D is not included in the NDP at this time.
Scanpower itself might take on a role of providing DG and/or brokering the energy generated
by consumers. This would ultimately become as a separate business within Scanpower
when it achieves adequate scale but it may start in the Network as an initiative to manage
network issues.
Page 179 of 193
12.0
EVALUATION OF PERFORMANCE
This section of the AMP describes the progress made with regard to previous plans. In terms
of PAS 55 its purpose is to assess how effective the plan has been at delivering on
objectives and performance targets. It is the “closing the loop” step the Plan-Do-Check-Act
continuous improvement cycle.
12.1
Review of Progress Against Plan
12.1.1 Financial Performance – Capital Expenditure
Scanpower’s actual capital expenditure for the financial year ending 31 March 2012 is
presented in the two tables below; one with the expenditure allocated by asset type and the
other by primary purpose. The actual figures are presented alongside the original budget
and the variance to budget arising in each case.
Table 53 – 2011/2012 Actual vs Budget Capital Expenditure by Asset & Expenditure Type
Scanpower Category
2011/12 Actual
2011/12 Budget
Variance
11kV Line Reconstruction
$969,096
$647,000
+$322,096
400V Line Reconstruction
$63,467
$32,000
+$31,467
$185,694
$140,000
+$45,694
$20,381
$63,500
-$43,119
$137,182
$55,000
+$82,182
$1,375,820
$937,500
+$438,320
2011/12 Actual
2011/12 Budget
Variance
$0
$36,000
-$36,000
$50,665
$60,000
-$9,335
$1,290,490
$811,000
+$479,490
$34,665
$30,500
+$4,165
Asset Relocations
$0
$0
-
Undergrounding of Urban 400V Overhead Lines
$0
$0
-
$1,375,820
$937,500
+$438,320
Transformer Replacements
Switchgear
Secondary Systems
TOTAL CAPITAL BUDGET
Category
Customer Connections
System Growth
Asset Replacement and Renewal
Reliability, Safety and Environment
Total Capital Expenditure
Page 180 of 193
As is evident from the figures provided above, at a consolidated level total capital
expenditure exceeded budget by $438,320 representing a variance of 47%. The primary
driver of this performance was volume of work rather than cost; i.e. more projects were
completed during the year than had been anticipated at the budgeting stage.
In the case of 11kV line reconstruction, which constitutes the majority of the variance, 13.84
kilometres of line had been budgeted for replacement (Piripiri Road, Okarae Road, State
Highway 2 – Smith Street to Otanga Street, Saddle Road – final lower section, Tipapakuku
Road, Maunga Road, Cowper Road – Weber to Knight Roads).
In addition to this planned work, an additional 7.14 kilometres of line reconstruction was
completed (most significantly Mackinley Road, Swinburn Street, State Highway 2 – France
Road to ABS122, Blairgowrie Road, Esdale Road, and Park Road). On a proportional basis
therefore, 52% more 11kV line was replaced than planned and this explains the 50% cost
variance.
The decision to undertake this additional work (effectively bringing forward planned projects)
was made on the basis that internal contracting / field staff resources were available and
would otherwise have been under utilised, and that these projects could be funded without
any material adverse impact on the company’s financial position.
Similarly, in the case of 400V line reconstruction, whilst Swinburn Street was completed as
planned, additional work was completed in York Street and Mclean Street, resulting in 45%
more physical asset being replaced. Given a financial variance of 100%, in relative terms
cost performance was not as effective as in the 11kV line category, however at $31,467 the
financial impact was relatively minor.
Capital expenditure in the transformer asset category was $45,694 or 33% higher than
expected. When budgeting expenditure in this category it is necessary to include a
predictive component to cover unplanned changes that arise due to failures in service. In
the case of this financial year, an inadequate amount was budgeted for this purpose (i.e. the
cost of replacing faulted units was higher than anticipated). Given Scanpower’s size and
relatively small budgets, it is not difficult to exceed those budgets with one or two additional
failures (for example the failure this year of a 200KVA transformer contributed $16,716 to the
adverse variance).
In the switchgear category, whilst planned asset replacements occurred at MacLaurin Street,
Dannevirke sewage plant and Gaisford Road, other routine life cycle replacements were
deferred pending the investigation of alternative new technologies. Therefore actual
expenditure was $43,119 lower than budget which in part offsets that additional expenditure
undertaken in the 11kV and 400V line replacement categories.
The balance of $137,182 recorded in capital expenditure on secondary systems comprised
the following:

Upgrades to the company’s radio network
$20,439

Ripple relay replacements
$85,637

New public safety signage
$13,063
Page 181 of 193

GIS software enhancements / functionality
$18,043
The $55,000 initially budgeted had been intended to cover solely the replacement of ripple
relays. As is evident from the actual figure of $85,637 this project did experience a cost over
run. This variance was driven by higher labour costs as opposed to material costs, with
gaining access to customer premises one of the main challenges. In regard to the other cost
items, these were essentially unbudgeted projects that were implemented during the year.
In the case of the new public signage, this initiative arose from the implementation of the
company’s new public safety management system.
In summary therefore, whilst capital expenditure was high relative to budget, this was
volume rather than cost driven and correspondingly more assets were replaced / produced
for the additional cost. Nonetheless, this review of financial performance has identified
several areas of the budgeting process that can be improved going forwards. This includes
more focus on predictive aspects of the budget (i.e. more sophisticated forecasting of growth
and fault driven work) and a more granular breakdown of projects. In addition to this, during
the year Scanpower has deployed and bedded in a new project costing system (EXO Job
Costing) which should enhance project planning, monitoring and reporting.
12.1.2 Financial Performance – Maintenance Expenditure
Provided in the table below are summary maintenance costs for the financial year ending 31
March 2012. The actual figures are presented alongside the original budget and the variance
to budget arising in each case.
Table 54 – 2011/2012 Actual vs Budget Maintenance Expenditure by Expenditure Type
Category
2011/12 Actual
2011/12 Budget
Variance
Routine and Preventative Maintenance
$181,074
$210,000
-$28,926
Refurbishment and Renewal Maintenance
$351,236
$360,000
-$8,764
Fault and Emergency Maintenance
$345,411
$210,000
+$135,411
Total Maintenance Expenditure
$877,721
$780,000
+$97,721
Total maintenance expenditure for the year of $877,721 was $97,721 higher than budget,
representing an adverse variance of 12.5%. As is evident from the composition of that total,
whilst both Routine and Preventative Maintenance and Refurbishment and Renewal
Maintenance fell relatively close to budget, it was in the Fault and Emergency Maintenance
category that the largest variance occurred.
Routine and Preventative Maintenance primarily relates to vegetation clearance / tree
trimming and this can fluctuate with growth rates and the frequency of interest / no interest
declarations by customers. The total favourable variance of $28,926 or 13.8% is considered
relatively minor given the variables inherent in this category. It does however reflect on a
generally falling number of “first cuts” (that are completed at Scanpower’s cost) as the tree
Page 182 of 193
management programme enters the second cut / trim cycle (completed at the customer’s
cost).
Refurbishment and Renewal Maintenance fell within 2.4% of budget, producing a small
favourable variance of $8,764. Financially therefore it was in line with budgetary
expectations. In physical terms, all planned maintenance activities were completed
satisfactorily.
Fault and Emergency maintenance is typically the cost category with the greatest volatility,
being driven by the frequency and nature of unplanned system outages. Fluctuations in the
number and type of these outages directly impacts on cost performance as Scanpower has
no choice but to respond. As is evident, costs of $345,411 were significantly higher than
budget, giving rise to an adverse cost variance of $135,411 or 64%.
Both SAIDI and SAIFI results for the year were higher than our internal target levels at 98.79
(target 82.92) and 1.25 (target 0.92) respectively. This indicates that the number of
unplanned events was higher than anticipated, and this is reflected in the adverse cost
variance. Furthermore, the nature of the faults over 2011/2012 compounded the cost over
run. This was particularly evident during August 2011 when heavy winds and snowfalls
produced 33 outage incidents, the majority of which were caused by fallen trees through
power lines. This subsequently necessitated extensive tree / vegetation clearance work in
addition to the pole / line repair works which also contributed to the relatively significant cost
variance.
12.2
Review of Service Delivery Against Targets
The following outage performance was achieved during the 2011/12 year. SAIDI
performance could have been managed to target by reducing planned outages. However,
the work program was dominated by pole replacements and line reconstructions and this
would have either resulted in less work being completed and/or more costly live line
resources being applied. Given the demand on live line crews, it was determined that the
long term benefits of asset renewal would take precedent over annual targets.
Table 55 – 2011/2012 SAIDI and SAIFI Reliability Performance (Actual vs Target)
Description Actual Target Variance Result NETWORK RELIABILITY – SAIDI 98.786 82.290 +16.496 x
NETWORK RELIABILITY – SAIFI 1.251 0.919 +0.332 x
The monthly profile graphs for SAIDI and SAIFI over the course of the 2011/2012 year are
provided below.
Page 183 of 193
Figure 33 – SAIDI Montly Performance Trend 2011/2012
Figure 34 – SAIFI Montly Performance Trend 2011/2012
Page 184 of 193
During 2012 Scanpower continued to display a SAIFI outcome exceeding its target. This is
has been determined as an issue related to faults caused by mature forestry which although
clear of the regulatory growth limits will fall into lines. Forestry happens to be located in
areas less suitable for intensive farming so the network is correspondingly remote, spur
connected, and cover a wide area/many ICP’s. Mature trees are often twice the height of
lines and modern pine species are weak/prone to top breakouts in the districts high winds.
SAIFI is also influenced by increase in the amount of planned worked undertaken during the
year. While SAIDI can be controlled by maximising the component undertaken by live line
practices any outage no matter how short incurs a SAIFI penalty.
SAIDI has been managed back to target during 2012 despite SAIFI indicating that speed of
response has been improved but there are limited options for addressing the number of
consumers affected when a spur line faults.
Apart from the increased resourcing being to tree trimming, Scanpower’s response has been
to:

Opportunistic diversion of lines away from forestry.

Investigation of Remote Area Power supplies for remote connections beyond forestry.
Both these options are very expensive and often beyond the capacity of farmers to deal with.
Scanpower shares some of the burden where this is clearly a legacy issue.
12.3
Review of Planning Process Objectives
The planning process and objectives of this plan are new and their derivation is discussed in
detail in the AM Strategy section. Although new, they are however largely consistent with
previous objectives. Scanpower has not yet completed a PAS55 AM cycle to be in a
position to review the effectiveness of its AM System.
The AMMAT schedule provided in Appendix A details the level of AMS development that has
been realised to date.
12.4
Performance Gap Analysis
Scanpower has undertaken a Fault Cause Analysis to determine the main drivers of its
outage statistics and identify the parts of the network requiring priority attention. This
analysis has led directly to the changes in policy and practice. That is, it has been applied as
an input to the planning process, which has been changed to a PAS 55 approach, rather
than a check on the effectiveness of past policies and practices which are no longer to be
continued.
Specifically, the actions targeted by these policy changes are:

Revision of the Security Standard;
Page 185 of 193

The Automation and Protection Development Project; and

Weighting hardwood pole renewal targets on the basis of feeders with the worst
performance (and condition) rather than those supplying the most customers (but
performing well despite their age).
12.4.1 Fault Cause Analysis
By analysing the cause and effect of faults on reliability statistics it is possible to determine
the effectiveness of:

Maintenance programmes.

Protection and automation equipment.

Network configuration.

The fault finding response.
This has been done on a feeder by feeder basis to help determine the priorities for where
effort can be most effectively applied in terms of impact on statistics.
The analysis is based on the SAIDI statistics for every fault that was experienced in the
2011/12 year. This information has been grouped by feeder and filtered into the 3 most
dominant causes that are directly manageable:
1. Transient: These are tripping’s where the cause was not found and the protection held
in on reclose – that is, self-clearing faults such as line clashes, bird strikes, tree touches,
etc. These statistics indicate the effectiveness of automation. If the protection operates
and turns the power off when the fault would otherwise self-clear, then it is the protection
system itself that is creating the outage - effectively turning a transient fault into a
permanent hard fault.
2. Condition: Lines are designed to be out in all weather conditions for their entire service
life. When there are a high number of faults caused by wind and snow it indicates that
the condition of asset has deteriorated over time and may benefit from more intensive
maintenance.
3. Trees: This is an issue that needs constant management attention and statistics clearly
communicate effectiveness of programmes and processes.
The statistics are presented in the following figure:
Page 186 of 193
Figure 35 – Summary of Fault Cause Analysis
GXP Feeder Feeder Statistics MW kWh (excl. ICP's>1GWh) ICP's km km % of System Impact Indicators ICP/km (Connection Density) kWh/ICP kWh/km (Load Density) Probabilty Factors Network Faults/km Feeder Fault Probability Security Risk Indexes ICP Driven (SAIDI Risk) kWh Driven (VoLL Risk) Average Supply Risk Ranking 2011/12 Feeder SAIDI Class C % of All System Faults SAIDI by Cause ‐ Transients SAIDI by Cause ‐ Trees SAIDI by Cause ‐ Condition Weber 2.2 7,460,542 853 262 31% 3.26 8,746 28,475 0.0459 12.0258 1.53 1.23 1.38 1 Mangatera 2 4,335,544 612 132 16% 4.64 7,084 32,845 6.0588 0.55 0.36 0.46 3 21.8 39% 11.6 21% 36% 47% 15% 15% 43% 37% Central 1.8 6,417,197 1151 13 2% 88.54 5,575 493,631 0.5967 0.10 0.05 0.08 9= Dannevirke Pacific East 1.8 3.8 4,272,494 13,980,563 216 735 61 11 7% 1% 3.54 66.82 19,780 19,021 70,041 1,270,960 2.7999 0.5049 0.09 0.06 0.16 0.10 0.13 0.08 6= 9= 1.4 3% 0% 0% 0% 100% North 1.7 7,648,866 559 127 15% 4.40 13,683 60,227 5.8293 0.49 0.61 0.55 2 8.4 15% 0% Adelaide 26% 60% 2% 2.6 10,279,778 892 17 2% 52.47 11,524 604,693 0.7803 0.10 0.11 0.11 8 Te Rehunga 1.1 5,749,357 295 62 7% 4.76 19,489 92,732 2.8458 0.13 0.22 0.17 5 Town No.1 1.1 6,352,069 546 34 4% 16.06 11,634 186,826 1.5606 0.13 0.14 0.13 6= 1.6 3% 0% 0% 0% 100% Woodville Country 0.9 5,145,702 422 96 11% 4.40 12,194 53,601 4.4064 0.28 0.31 0.29 4 Town No.2 1.2 1,216,777 428 26 3% 16.46 2,843 46,799 1.1934 0.08 0.02 0.05 11 10.3 18% 0% Total 0.6 1% 27% 18% 6% 1% 0% 99% 20.2 72,858,889 6709 841 7.98 10,860 86,634 38.6019 55.7 14.6 20.3 11.3 Page 187 of 193
12.4.2 Fault Cause Analysis Findings
The fault statistics confirm previous security analysis that the feeders that present the
biggest risk profile, in terms of both SAIDI minutes and the economic impact of outages on
our consumers, are the rural feeders.
There were no faults recorded on any of the urban feeders. Shorter spans and heavier
conductor make these lines more robust. The load centres are closer in which means
response is quicker (so there is less benefit in automation) and the asset is more
visible/likely to get prompt maintenance attention.
Transients
Transient faults account for 26% (15 minutes) of all SAIDI minutes lost to Class C Outages
(faults). Further 54% is attributed to a single feeder – Weber. It would be expect that a
properly functioning protection and automation scheme to keep outages attributed non-solid
faults below the 2% level. The most likely reasons for this poor performance are:

The protection scheme is assessed to be too complicated making coordination difficult.
There are too many protection devices organised in series. Specifically, the design is
mixing an older branch and group fusing approach with the more modern practice of
defusing in favour of automation (reclosers, sectionalisers, remotely controlled
switches, and fault indicators).

Retrenching fusing back to the transformer fuses would align Scanpower with a well
proven best practice. However this needs to be balanced with replacing fault
isolation/response capability with more fault indicators, optimising the number of lines
sections, placing automation equipment in the most effective locations, etc.

The feeders are so long that fault levels are very low at their extremities and in some
cases outside of the operating parameters of the automation equipment. This is a
more challenging problem to solve – essentially the longest feeders are in the order of
twice the distance that would be expected in an 11kV distribution system. This is only
possible because the loadings are so low. A 22kV network and/or one with a subtransmission system would have higher fault levels. Generation is likely to be most
practical solution in Scanpower’s case.

The protection settings are correspondingly quite sensitive. It is better to coarsen the
protection so that faults develop sufficient energy to make the damage solid and
permanent. A fault that can be seen and heard is more readily located. For example, it
would not be expected that the tips of trees burning in the lines would trip the
protection to lock-out.

The location of automation can be improved. There has been a tendency to locate
equipment close-in, where customer density is highest. It may be more effectively to
deploy it further out where travel times are longer, asset condition is worse, faults are
harder to find, and where faults affect a greater number of up-stream consumers.
Similarly, automated tie points tend to be close-in because interconnection is not
possible further out.
Page 188 of 193

This equipment may deliver greater benefit if it is targeted at faster fault location and
isolation. At Scanpower’s relatively low level of fault events, there are diminishing
returns to be gained from a strategy of fast supply restoration – that is, investment is
better made on network robustness and fault tolerance. Strategy often losses sight of
the fact that it is better not to have faults than to be good at responding to them.
Trees
Trees are the biggest single cause of outage on Scanpower’s network. They account for
36% (20 minutes) of total fault SAIDI. An effective tree management process could be
expected to reduce this to between 5-10% at a cost of less than 25% of the current cost to
network.
Savings in tree cutting and fault response can then redirected into more productive asset
management activity. That is, Scanpower needs to get on top of tree management quickly to
bring system performance and cost efficiency back into balance. The cost of dealing with
trees and faults outweighs the profit contributed to the company by Treesmart pursuing
private chargeable work.
Tree faults are almost entirely restrained to the three largest rural feeders – Weber (10
minutes), Mangatera (5 minutes), and North (5 minutes). Tree fault SAIDI minutes directly
correlate with feeder line lengths.
These 3 feeders are clearly where tree trimming notifications are going to deliver the biggest
impact and therefore will be prioritised accordingly.
While the sensitivity of the protection system does make a significant contribution to tree
related SAIDI, the number of breakages due to tree contacts indicates that the level
clearance being enforced during tree trimming is not aggressive enough. That is, breakages
are not caused by the tips of trees touching the lines – it is more substantial branches and
wind fall that is the issue.
Trimming to regulatory limits is inadequate – these are the backstops/minimum clearances.
Treesmarts cutting recommendations to the owner need to consider how far the trees are
likely to sway in the wind and the fall zone of limbs/tree tops that may breakout. The
assessment of regulatory clearance can validly take this into account.
Of note is that feeders with a high density of dairy farming tend not to have any tree
management issues – the land owner has stepped up to mark for other reasons. The Weber
feeder in particular, suggests that lines through forestry are an issue – pines tree tops
breakout in snow.
Condition
Condition attributes to approximately 20% (11 minutes) of the fault statistics. Typically,
condition is an age related issue however the performance with age is not linear and the
survival rate rolls-off in last 5-10 years of the assets service. Lower construction standards
(lighter conductor, old copper, bigger spans, thinner poles, etc.) on rural lines usually result
in condition issues being restricted to remote/rural feeders – Scanpower is no exception.
Page 189 of 193
Condition related issues are more frequent than would be expected on a network where
growth was driving upgrade before asset performance starts to decline. Accordingly,
Scanpower has a higher demand for maintenance that results in asset renewal, particularly
with regard to crossarms (which are the weak link in terms of life expectancy) and copper
conductor (which work hardens and lacks strength).
The Weber feeder condition related outages are consistent with its system length (30%) and
this indicates that it is in an average condition for Scanpower’s asset base. Accordingly the
existing levels of maintenance expenditure need to be sustained.
The North feeder is showing the benefit of recent maintenance and replacement
programmes – it has the lowest level of condition related outage of the rural feeders.
The Mangatera feeder dominates condition related faults contributing 4.3 minutes (38%
compared to it being only 16% of the network km). That is, its condition related performance
is approx. 2 times worse than average. While maintenance expenditure needs be normalised
in terms of feeder length, there is a clear case for biasing proportionally more expenditure on
the Mangatera feeder.
Feeder Specific Issues
The Weber feeder represents 39% (22 minutes) of all faults and in terms of system length
represents 31% of the network. Clearly it would deliver the most gain from priority asset
management attention but the core issue is actually its configuration and the systems
engineering of the technology deployed on it.
The Weber feeder may be improved by reconfiguring it into two main branches with aim of
reducing its excessive spur-like configuration and allow automation to be more optimally
deployed. The ultimate long term fix for the feeder however is a generation and/or energy
storage/backup system.
Generation would also be helpful beyond the load centres on the North and Mangatera
feeders. However, an alternative that might be considered is to move one of the
transformers, and half the 11kV switchboard, at Dannevirke GXP to a new GXP 15km to the
north (Matamau). This does not affect security of the transmission supply or Scanpower’s
ability to interconnect via 11kV.
In fact, it would improve security, 11kV tie capacity, improve the voltage/capacity, shorten
the rural feeder lengths, reduce the need for voltage boosters, etc. The approach is to
distribute the transmission capacity (the normal purpose of sub-transmission) closer to the
load centres on the 11kV network i.e. more GXP’s, more numerous but shorter 11kV
feeders, and greater interconnection. This is a more efficient use of transmission asset than
concentrating load and then supplying with 100% redundancy (n-1 security).
These findings have been applied as input to the Network Development Plan and developed
further.
Page 190 of 193
12.5
Public Safety Management
Scanpower was issued with a Telarc certification of its Public SMS to NZS7901:2008 on 31
May 2012. It is yet to complete a full cycle of the management system but has completed its
first internal audit. The system is at a low level of maturity, partly due to the low frequency of
incidents.
To date there have been no public safety events or issues to manage and accordingly there
is nothing to report.
Page 191 of 193
APPENDIX A
ASSET MANAGEMENT MATURITY ASSESSMENT TOOL
ASSESSMENT OF SCANPOWER
REPORT PREPARED BY UTILITY CONSULTANTS LIMITED
Page 192 of 193
Asset Management Maturity Assessment Tool (AMMAT) assessment summary Prepared for ScanPower Ltd by Utility Consultants Ltd www.utilityconsultants.co.nz February 2013 Introduction Schedule 13 of the Electricity Distribution Information Disclosure Determination 2012 requires all EDB’s to complete an assessment of the maturity of their asset management practices using a prescribed template derived from PAS 55. This requires each EDB to score the maturity of each identified asset management element between 0 and 4 using prompts, and it is expected that the assessment will be repeated at regular intervals as part of the Asset Management Plan disclosure process. This report is intended only as a summary of the Schedule 13. Readers should refer to the full Schedule 13 in regard to compliance with the Determination. Assessment methodology ScanPower engaged Utility Consultants to assist with compiling the AMMAT (Schedule 13). The assessment methodology included discussions with the following people...  Ken Mitchell – Network Manager.  Lee Bettles – Chief Executive.  Ben van der Spuy – Company Accountant. The assessment also included inspections of various documents including the...  2012 – 2022 AMP.  Working papers for the PAS 55 implementation.  Various board papers.  Board agendas.  Design and construction standards.  Faults database.  Network development plan.  Network automation strategy.  PSMS certificate.  Emergency preparedness plan. Summary of ScanPower’s assessment The assessment process resulted in scores from 1 to 3, with most elements scoring a 3. Those elements that scored only a 1 or 2 should easily progress to a 3 as ScanPower implements PAS 55. Key areas identified for possible improvement along with suggested priorities are... Question(s) Suggested priority Recommendation 3 Low Develop a specific AM Policy that visibly links to the Strategic Objectives. 31 Low Continue developing HR Plans and assessing competency requirements, possibly also develop a long‐term funding plan if the network funding requirements are expected to change. 45 Low Implement firmer quality controls for the few AM activities that are out‐sourced. 59 Low Continue with the IS gap analysis work, and more clearly document the interaction of key AM IS. 63, 64 High Continue the current data integrity improvement work. 69, 79 High Include the proposed improved asset lifecycle criticality and risks in the 2013 – 2023 AMP. 82 Medium Consider performing a comprehensive legislative and regulatory compliance review, and from that compile various checklists and calendars for each manager to implement. 113 Medium Continue implementing PAS 55, which will embed continual performance, risk and cost assessments. Detailed assessment of each element The detailed assessment of ScanPower’s asset management practices is as follows... Q. No. Question 3
To what extent has an asset management policy been documented, authorised and communicated? 10
What has the organisation done to ensure that its asset management strategy is consistent with other appropriate organisational policies and strategies, and the needs of stakeholders? Score 2
Evidence inspected Discussions with key people Chapter 1.2 of the AMP sets out 3 objectives for Ken Mitchell indicated that ScanPower is AM. ScanPower's strategic plan was sighted. moving to a PAS 55 objective. However there is no AM Policy as such. 3
The 3 objectives set out in Chapter 1.2 of the Ken Mitchell indicated that ScanPower has AMP are 3 of ScanPower's 6 corporate revised its Strategic Plan in accordance with PAS 55 guidelines. objectives. Q. No. Question 11
In what way does the organisation's asset management strategy take account of the lifecycle of the assets, asset types and asset systems over which the organisation has stewardship? Score 3
Evidence inspected Discussions with key people Chapters 5 and 6 of the 2012 ‐ 2022 AMP Ken Mitchell confirmed that the planned consider the lifecycle of distribution assets revision of the AMP to PAS 55 guidelines will strengthen the linkages between asset (including secondary systems) and also trees. categories and key lifecycle parameters such as failure modes, condition degradation, financing etc. 26
How does the organisation establish and document its asset management plan(s) across the life cycle activities of its assets and asset systems? 3
Draft PAS 55 documents were inspected.
Ken Mitchell indicated that adoption of the PAS 55 Lifecycle Optimisation is leading to even greater consideration of asset lifecycles and cost optimisation. 27
How has the organisation communicated its plan(s) to all relevant parties to a level of detail appropriate to the receiver's role in their delivery? 3
The Network Manager's presentation to the Board for Network Development was sighted. This identifies key issues and recommends actions and resourcing. Ken Mitchell indicated that the key themes of the AMP have been explained to staff, including budget targets. ScanPower's field crews are now part of Network so the communication paths are more direct. 29
How are designated responsibilities for delivery of asset plan actions documented? 3
Chapter 2.5 of the AMP describes the Ken Mitchell indicated that the new responsibilities of the CEO and Network structure more clearly identifies roles and Manager. The new structure in which field contributions to objectives. crews are part of Network was also inspected. 31
What has the organisation done to ensure that appropriate arrangements are made available for the efficient and cost effective implementation of the plan(s)?
(Note this is about resources and enabling support) 2
The Network Manager's presentation to the Board for Network Development was sighted, and includes resourcing, methodologies and possible funding mechanisms. 33
What plan(s) and procedure(s) does the
organisation have for identifying and responding to incidents and emergency situations and ensuring continuity of critical asset management activities? 3
Chapter 7.3 of the 2012 ‐ 2022 AMP describes Ken Mitchell indicated that the emergency the integrated suite of emergency and outage preparedness plans are also included in the plans. PSMS. A back‐up control room is maintained, and SCADA can be remotely operated from laptops. Fault responses can be observed on SmartPhones. Ben van der Spuy that there are no obvious funding constraints to ScanPower's expected works programs. Ken Mitchell indicated that staff competencies and numbers are currently being assessed. Q. No. Question 37
What has the organisation done to appoint member(s) of its management team to be responsible for ensuring that the organisation's assets deliver the requirements of the asset management strategy, objectives and plan(s)? Score 3
Evidence inspected Chapter 2.5 of the AMP describes the responsibilities of the CEO and Network Manager. The new structure in which field crews are part of Network was also inspected. Discussions with key people Ken Mitchell has been appointed as Network Manager with full responsibility for network operation, performance and investment. 40
What evidence can the organisation's top management provide to demonstrate that sufficient resources are available for asset management? 3
The AM model from PAS 55 for building Ben van der Spuy indicated that company competencies has been examined. ScanPower's continued consumer discounts are evidence that ScanPower is adequately funded. Ken Mitchell indicated that a strong balance sheet provides plenty of headroom for debt funding, but that forecast spend requirements can be adequately funded from revenue and retained earnings. ScanPower is currently reviewing competency requirements and recruiting as the nature of work changes eg. installing more voltage regulators. 42
To what degree does the organisation's top management communicate the importance of meeting its asset management requirements? 3
The Network Manager's presentation on the Ben van der Spuy indicated that the Board Network Development Plan was sighted. are very well informed of AM requirements. Ken indicated that the Exec Team are also well informed. The ScanPower Trust receives a copy of the AMP and approves the SCI. Field staff are being told of shifts in direction by weekly meeting and daily communication eg. change in emphasis of work and targets. Q. No. Question 45
Where the organisation has outsourced some of its asset management activities, how has it ensured that appropriate controls are in place to ensure the compliant delivery of its organisational strategic plan, and its asset management policy and strategy? Score 2
Evidence inspected No substantial evidence of firm controls was apparent. This risk is mitigated by the low number of outsourced contracts and by the simplicity of the network. Discussions with key people Ken Mitchell indicated that the only out‐
sourced AM activity is engineering design and specialist activities such as protection setting. The control mechanisms include proven expertise, long‐term long‐term partnering, and involving suppliers at the technical design phase. 48
How does the organisation develop plan(s) for the human resources required to undertake asset management activities ‐ including the development and delivery of asset management strategy, process(es), objectives and plan(s)? 3
A paper by the Network Manager titled Network Ken Mitchell indicated that firstly the Staffing Establishment was sighted. Strategic Plan defines ScanPower's direction, which determines the competencies. A gap analysis of both the volume and nature of competencies is undertaken (as part of the PAS 55 model). 49
How does the organisation identify competency requirements and then plan, provide and record the training necessary to achieve the competencies? 3
A paper by the Network Manager titled Network Notwithstanding that many competencies Staffing Establishment was sighted. are safety requirements, Ken Mitchell indicated that competency requirements are identified directly from the Strategic Plan. ScanPower expects to increase its training as competency requirements evolve. 50
How does the organization ensure that persons under its direct control undertaking asset management related activities have an appropriate level of competence in terms of education, training or experience? 3
A training record was inspected, confirming that a strategic view of competencies is taken. The course notes for the Safety Auditor's course were inspected. A certificate of attendance at a Transpower substation course was inspected. The unit standards training matrix was inspected. Ken Mitchell confirmed that safety competencies are mandatory for prescribed work, and are comprehensively managed. Non‐prescribed work eg. engineering is subject to a strategic review of competencies driven by the changing nature of work requirements and practice changes. Q. No. Question 53
How does the organisation ensure that pertinent asset management information is effectively communicated to and from employees and other stakeholders, including contracted service providers? Score 3
Evidence inspected The Network Manager's presentation on the Network Development Plan was sighted. Board reports of key network parameters were sighted. Discussions with key people Ken Mitchell indicated that two‐way communication has been enhanced by bringing field crews into the Network division. The Board are deemed to be intimately informed of the AMP, whilst the Trust are considered to be informed of the SCI's content. Wider stakeholders can examine the AMP and SCI. 59
What documentation has the organisation
established to describe the main elements of its asset management system and interactions between them? 2
Chapter 2.6 of the 2012 ‐ 2022 AMP shows the Ken Mitchell indicated that the interaction interaction of key AM systems. of AM systems is not significantly documented, but a review is in progress. 62
What has the organisation done to determine what its asset management information system(s) should contain in order to support its asset management system? 3
The AMIS Needs Analysis was sighted. The Security Of Supply Analysis was sighted, and confirmed that such pieces of work are used to inform strategy and budgets. Ken Mitchell indicated that a needs analysis of the both tools and data has been undertaken, with a number of priorities being identified by gap analyses eg. MDI's at large distribution substations, being protection models back in‐house, consideration of structural design soft‐
ware. 63
How does the organisation maintain its asset management information system(s) and ensure that the data held within it (them) is of the requisite quality and accuracy and is consistent? 1
Chapter 8.4 of the 2012 ‐ 2022 AMP has been inspected, confirming that integrity of asset data is an area of concern and that remedial measures are planned. The PSMS was inspected. Ken Mitchell indicated that data accuracy and quality gaps are emerging as new AM practices are considered eg. lifecycle modeling reveals that some recorded conductor ages are doubtful. It is expected that implementing PAS 55 will strengthen data quality controls. 64
How has the organisation's ensured its asset management information system is relevant to its needs? 2
An external advisors report identifying asset Ken Mitchell indicated that he has data gaps was sighted. The faults database was undertaken a needs analysis which has sighted. identified gaps in both the existence and quality of data. Q. No. Question 69
How has the organisation documented process(es) and/or procedure(s) for the identification and assessment of asset and asset management related risks throughout the asset life cycle? Score 2
Evidence inspected Discussions with key people Drafts of the 2013 ‐ 2023 AMP have been Ken Mitchell indicated that the revised inspected, and it is confirmed that these risk 2013 ‐ 2023 AMP will consider Criticality & assessments are included. Risks for each asset category. This will include systematic assessment of all classes of risk along with risk mitigation tactics. 79
How does the organisation ensure that the results of risk assessments provide input into the identification of adequate resources and training and competency needs? 2
The analysis estimating the number of poles per Ken Mitchell indicated that least‐cost feeder to be changed every year based on optimisation strategies for delivering objectives and performance has been inspected. objectives are derived from the risk assessments. From those strategies, resources and competencies are being identified, which in turn are reflected in the budgets. 82
What procedure does the organisation
have to identify and provide access to its legal, regulatory, statutory and other asset management requirements, and how is requirements incorporated into the asset management system? 2
The directors certification of the 2012 ‐ 2022 AMP has been confirmed. Monthly board reports were examined, and the directors attestation of solvency and risk position was noted. Various papers included in the board agendas addressed risk and strategic initiatives. Lee Bettles indicated that ScanPower tends to rely on the ENA bulletins, Commerce Commission mailing lists and consultants advice. This tends to be reactive. 88
How does the organisation establish implement and maintain process(es) for the implementation of its asset management plan(s) and control of activities across the creation, acquisition or enhancement of assets. This includes design, modification, procurement, construction and commissioning activities? 3
The construction standards for overhead and underground were inspected. The network design standard was inspected. The procedure for converting pole inspection data to safety indices was inspected. Ken Mitchell indicated that lifecycle activities such as design and construction are controlled by Manuals, Design Standards etc. Field crews routinely do work for other EDB's and are therefore used to working to prescribed standards. Pole replacement is being informed by objective methods such as ultra‐sound. Modeling of standard structures is also undertake to estimate safety indices, which are de‐rated for missing components etc. Q. No. Question 91
How does the organisation ensure that process(es) and/or procedure(s) for the implementation of asset management plan(s) and control of activities during maintenance (and inspection) of assets are sufficient to ensure activities are carried out under specified conditions, are consistent with asset management strategy and control cost, risk and performance? Score 3
Evidence inspected The network design standard, the HV inspection policy and the construction standards for overhead and underground were inspected (leading control mechanisms). The lagging control mechanisms of Site Quality Audit, Defect / Non‐Conformance Report, and Site Safety Inspections were sighted. Discussions with key people Ken Mitchell indicated that leading and lagging KPI's have been established. All new prescribed electrical works are inspected for electrical compliance and for project completeness. Site safety audits are also performed. A key control mechanism is the weekly field services meeting. 95
How does the organisation measure the performance and condition of its assets? 3
The faults database was sighted, pole inspection
records were inspected. The PSMS was sighted. ABS inspection records were examined. Earth testing records were inspected. Ken Mitchell indicated that analysis of fault data for causes and restoration time is a principal method of performance measurement. Safety performance is measured as part of the PSMS. Condition is assessed principally by planned inspections based on criticality (which are linked to business objectives). 99
How does the organisation ensure responsibility and the authority for the handling, investigation and mitigation of asset‐related failures, incidents and emergency situations and non conformances is clear, unambiguous, understood and communicated? 3
The emergency preparedness plan was sighted. The procedure for fault analysis was discussed, and the Network Manager's paper on fault cause analysis was sighted. Ken Mitchell indicated that completed fault reports are examined by the Duty Engineer to identify any patterns, trends or systemic issues. A policy is in place to inspect assets after faults and eliminate possible causes. An emerging trend may result in an engineering study, and budget allocations. 105
What has the organisation done to establish procedure(s) for the audit of its asset management system (process(es))? 3
The PSMS Audit Certificate was sighted.
Ken Mitchell indicated that the PSMS audit has occurred, and that future audits will occur as ScanPower moves to PAS 55 accreditation. Q. No. Question 109
How does the organisation instigate appropriate corrective and/or preventive actions to eliminate or prevent the causes of identified poor performance and non conformance? Score 3
Evidence inspected The Protections & Automation Development Plan was sighted. The Fault Cause Analysis was sighted, and consideration of key issues was confirmed. Discussions with key people Ken Mitchell indicated that processes include fault analysis, KPI reviews, alignment to security of supply criteria, review of policies to better reflect ScanPower's changing circumstances. 113
How does the organisation achieve continual improvement in the optimal combination of costs, asset related risks and the performance and condition of assets and asset systems across the whole life cycle? 2
Working papers and conference notes were inspected. The draft 2013 ‐ 2023 AMP was inspected, which uses a format aligned to PAS 55. Ken Mitchell indicated that ScanPower's adoption of PAS 55 will involve continual pursuit of optimal performance, risk and costs for each asset class because the PAS 55 methodology is cyclical. 115
How does the organisation seek and acquire knowledge about new asset management related technology and practices, and evaluate their potential benefit to the organisation? 3
The NM's analysis of automation options was sighted, and confirmed as being consistent with the wider strategic direction. An email from a supplier to estimate equipment costs was sighted. An email to another EDB to identify possible solutions was sighted. It was confirmed that the process progresses from concept to detail, from broad to narrow. Ken Mitchell indicated that the starting point is to understand ScanPower's needs, and then to identify and assess options against suitable criteria. Obtaining information about new technologies includes attending conferences, reading magazines, talking to suppliers, talking to other EDB's etc. APPENDIX B
SCANPOWER LIMITED ASSET MANAGEMENT PLAN
COMPLIANCE ASSESSMENT MATRIX / REVIEW
Page 193 of 193
Commerce Act (Electricity Distribution Services Information Disclosure)
Asset Management Plan Content Requirements
This table sets out the mandatory disclosure requirements with respect to AMPs and references those requirements to the contents this AMP document
AMP Ref.
Reg. Ref.
AMP Design
1
The core elements of asset management‐
3.2
1.1
A focus on performance measurement, monitoring and continuous improvement of asset management practices;
Sect. 3.0
1.2
Close alignment with corporate vision and strategy;
Sect. 4.0
1.3
That asset management is driven by clearly defined strategies, business objectives and service level targets; Sect. 5.0
1.4
That responsibilities and accountabilities for asset management are clearly assigned;
1.5
An emphasis on knowledge of what assets are owned and why, the location of the assets and the condition of the assets;
Sect. 6.0
1.6
An emphasis on optimising asset utilisation and performance;
Sect. 10.0
1.7
That a total life cycle approach should be taken to asset management;
Sect. 11.0
1.8
That the use of 'non‐network' solutions and demand management techniques as alternatives to asset acquisition is considered .
Sect.10.0
8.1
2
The disclosure requirements are designed to produce AMPs that‐
2.1
Are based on, but are not limited to, the core elements of asset management identified in clause 1;
3.2
2.2
Are clearly documented and communicated to all stakeholders;
8.4
2.3
h the EDB's asset management processes meet best practice criteria consistent with outcomes produced in competitive markets
2.4
Specifically support the achievement of disclosed service level targets;
5.1
2.5
Emphasise knowledge of the performance and risks of assets and identify opportunities to improve performance and provide a sound basis for ongoing risk assessment ;
9.4
2.6
Consider the mechanics of delivery including resourcing;
8.2
2.7
Consider the organisational structure and capability necessary to deliver the AMP;
8.2
2.8
Consider the organisational and contractor competencies and any training requirements;
8.3
2.9
Consider the systems, integration and information management necessary to deliver the plans;
Sect. 4.0
2.10
2.11
Use unambiguous and consistent definitions of asset management processes to enhance comparability of asset management practices over time and between EDBs;
Promote continual improvements to asset management practices.
Sect. 7.0
Sect. 3.0
3.2
Contents of the AMP
3
The AMP must include the following:
3.1
A summary that provides a brief overview of the contents and highlights information that the EDB considers significant
3.2
Details of the background and objectives of the EDB's asset management and planning processes including the purpose statement in clause 3.3 of this appendix.
3.3
A purpose statement which:
2.1
3.3.1
makes clear the purpose and status of the AMP in the EDB's asset management practices. The purpose statement must also include a statement of the objectives of the asset management and planning processes
4.1
3.3.2
states the corporate mission or vision as it relates to asset management
4.3
3.3.3
identifies the documented plans produced as outputs of the annual business planning process adopted by the EDB
4.1
3.3.4
states how the different documented plans relate to one another, with particular reference to any plans specifica lly dealing with asset management
4.1
3.3.5
includes a description of the interaction between the objectives of the AMP and other corporate goals, business planning processes, and plans The purpose statement should be consistent with the EDB's vision and mission statements, and show a clear recognition of stakeholder 3.5
Details of the AMP planning period, which must cover at least a projected period of 10 years commencing with the disclosure year following the date on which the AMP is required to be disclosed
The date that it was approved by the directors
3.6
A description of stakeholder interests (owners, consumers etc) which identifies important stakeholders and indicates:
3.4
Sect. 2.0
3.1, 5.1
1.1
1.2
Sect. 4.0
3.6.1
how the interests of stakeholders are identified
4.2
3.6.2
what these interests are
4.2
3.6.3
how these interests are accommodated in asset management practices
4.2
3.6.4
how conflicting interests are managed
4.2
3.7
3 .8
A description of the accountabilities and responsibilities for asset management on at least 3 levels, including:
3.7.1 governance‐a description of the extent of director approva l required for key asset management decisions and the extent to which asset management outcomes are regularly reported to directors
8.1
3.7.2
executive‐an indication of how the in‐house asset management and planning organisation is structured
8.1
3.7.3
field operations‐an overview of how field operations are managed, including a description of the extent to which field work is undertaken in‐
house and the areas where outsourced contractors are used
8.1
All significant assumptions
3.8.1
quantified where possible
9.5
3.8.2
clearly identified in a manner that makes their significance understandable to interested persons
9.5
3.8.3
a description of changes proposed where the information is not based on the EDB's existing business
9.5
3.8.4
set out the sources of uncertainty and the potential effect of the uncertainty on the prospective information
9.5
3.8.5
include the price inflator assumptions used to prepare the financial information disclosed in nominal New Zealand dollars in the Network Expenditure AMP Report
9.5
3.9
A description of the factors that may lead to a material difference between the prospective information disclosed and the corresponding actual information recorded in future disclosures
9.6
3.10
An overview of asset management strategy and delivery
3.1
To support the AMMAT disclosure and assist interested persons to assess the maturity of asset management strategy and delivery, the AMP should identify:
•
•
•
•
how the asset management strategy is consistent with the supplier's other strategy and policies;
how the asset strategy takes into account the life cycle of the assets;
the link between the asset management strategy and the AMP;
processes that ensure costs, risks and system performance will be effectively controlled when the AMP is implemented.
3.11
An overview of systems and information management data
Sect.7.0
To support the AMMAT disclosure and assist interested persons to assess the maturity of systems and information management, the AMP should describe :
•
•
•
•
the processes used to identify asset management data requirements that cover the whole of life cycle of the assets;
the systems used to manage asset data and where the data is used, including an overview of the systems to record asset conditions and operation capacity and to monitor the performance of assets;
the systems and controls to ensure the quality and accuracy of asset management information; and
the extent to which these systems, processes and controls are integrated .
3.12
A statement covering any limitations in the availability or completeness of asset management data and disclose any initiatives intended to improve the quality of this data
7.8
3.13
A description of the processes used within the EDB for:
7.6
3.14
3.13.1 managing routine asset inspections and network maintenance
Sect. 11.0
3.13.2 planning and implementing network development projects
Sect. 10.0
3.13.3
measuring network performance.
Sect.12.0
an overview of asset management documentation, controls and review processes
To support the AMMAT disclosure and assist interested persons to assess the maturity of asset management documentation, controls and review processes, the AMP should:
•
identify the documentation that describes the key components of the asset management system and the links between the key components;
•
describe the processes developed around documentation, control and review of key components of the asset management system;
where the EDB outsources components of the asset management system, the processes and controls that the EDB uses to ensure efficient •
and cost effective delivery of its asset management strategy;
•
where the EDB outsources components of the asset management system, the systems it uses to retain core asset knowledge in‐house; and
•
audit or review procedures undertaken in respect of the asset management system.
3.15
An overview of communication and participation processes
8.4
To support the AM MAT disclosure and assist interested persons to assess the maturity of asset management documentation, controls and review processes, the AMP should:
•
•
3.16
3.17
communicate asset management strategies, objectives, policies and plans to stakeholders involved in the delivery of the asset management requirements, including contractors and consultants;
incentivise staff engagement in the efficient and cost effective delivery of the asset management requirements.
The AMP must present all financial values in nominal New Zealand dollars;
The AMP must be structured and presented in a way that the EDB considers will support the purposes of AMP disclosure set out in clause 2 above.
confirmed
3.2
Assets covered
4
The AMP must provide details of the assets covered, including:
4.1
4.2
4.3
a high‐level description of the service areas covered by the EDB and the degree to which these are interlinked, including:
Sect. 6.0
4.1.1 the region(s) covered
6.1
4.1.2
identification of large consumers that have a significant impact on network operations or asset management priorities
6.2
4.1.3
description of the load characteristics for different parts of the network
6.3
4.1.4
peak demand and total energy delivered in the previous year, broken down by sub‐network, if any.
6.4
a description of the network configuration, including:
6.5
4.2.1 identifying bulk electricity supply points and any embedded generation with a capacity greater than 1MW. State the existing firm supply capacity and current peak load of each bulk electricity supply point;
6.5.1
4.2.2
a description of the subtransmission system fed from the bulk electricity supply points, including the capacity of zone substations and the voltage(s) of the subtransmission network(s). The AMP must identify the extent to which individual zone substations have n‐x subtransmission security;
6.5.2
4.2.3
a description of the distribution system, including the extent to which it is underground;
6.5.3
4.2.4
a brief description of the network's distribution substation arrangements;
6.5.4
4.2.5
a description of the low voltage network including the extent to which it is underground; and
6.5.5
4.2.6
an overview of secondary assets such as protection relays, ripple injection systems, SCADA and telecommunications systems .
6.5.7
If sub‐networks exist,the network configuration information referred to in subclause 4.2 above must be disclosed for each sub‐network.
6.5.8
Network assets by category
4.4
4.5
The AMP must describe the network assets by providing the following information for each asset category:
4.4.1
voltage levels;
4.4.2
description and quantity of assets;
4.4.3
age profiles;
4.4.4
value of the assets in the category; and
4.4.5
a discussion of the condition of the assets, further broken down into more detailed categories as considered appropriate. Systemic issues leading to the premature replacement of assets or parts of assets should be discussed.
The asset categories discussed in subclause 4.4 above shou ld include at least the following:
Sect. 11.0
11.3
11.3.2
11.4
11.3.1
11.5, 11.6
Sect. 6.0
4.5.1
the categories listed in the Network Asset AMP Report set out in Schedule 16;
6.5
4.5.2
assets owned by the EDB but installed at bulk supply points owned by others;
6.5.7
4.5.3
EDB owned mobile substations and generators whose function is to increase supply reliability or reduce peak demand; and
6.5.9
4.5.4
other generation plant owned by the EDB. Service Levels
6.5.10
Service Levels
5
The AMP must clearly identify or define a set of performance indicators for which annual performance targets have been defined. The annual performance targets must be consistent with business strategies and asset management objectives and be provided for each year of the AMP planning period. The targets should reflect what is practically achievable given the current network configuration, condition and planned expenditure levels. The targets should be disclosed for each year of the AMP planning period.
6
For non‐exempt EDBs, performance indicators for which targets have been defined in clause 5 above must include the SAlDl assessed value and the SAIFI assessed value required under the price quality path determination applying to the regulatory assessment period in which the next disclosure year falls.
7
Performance indicators for which targets have been defined in clause 5 above should also include:
7.1
Consumer oriented indicators that preferably differentiate between different categories of consumer;
7.2
Indicators of asset performance, asset efficiency and effectiveness, and service efficiency, such as technical and financial performance indicators related to the efficiency of asset utilisation and operation.
8
The AMP must describe the basis on which the target level for each performance indicator was determined. Justification for target levels of service includes consumer expectations or demands, legislative, regulatory, and other stakeholders' requirements or considerations. The AMP should demonstrate how stakeholder needs were ascertained and translated into service level targets.
9
Targets should be compared to historic values where available to provide context and scale to the reader .
10
Where forecast expenditure is expected to materially affect performance against a target defined in clause 5 above, the target should be consistent with the expected change in
the level of performance .
Sect. 5.0
5.1
10.3.2
4.4.4
Sect. 4&5
12.2
10.6.5
Network Development Planning
11
AMPs must provide a detailed description of network development plans, including‐
Sect. 10.0
11.1
A description of the planning criteria and assumptions for network development;
10.1
11.2
Planning criteria for network developments should be described logically and succinctly. Where probabilistic or scenario‐based planning techniques are used, this should be indicated and the methodology briefly described.
10.4
11.3
A description of strategies or processes (if any) used by the supplier that promote cost efficiency through the use of standardised assets and designs;
11.4
The use of standardised designs may lead to improved cost efficiencies. This section should discuss:
10.5.8&9
11.6
11.4.1
the categories of assets and designs that are standardised;
11.6
11.4.2
the approach used to identify standard designs.
11.6
11.5
A description of strategies or processes (if any) used by the EDB that promote the energy efficient operation of the network.
10.5.5
11.6
A description of the criteria used to determine the capacity of new equipment for different types of assets or different parts of the network.
10.5.2
11.7
A description of the process and criteria used to prioritise network development projects and how these processes and criteria align with the overall corporate goals and vision.
10.6.4
12.4.1
11.8
Details of demand forecasts, the basis on which they are derived,and the specific network locations where constraints are expected due to forecast increases in demand;
10.5
11.8.1 explain the load forecasting methodology and indicate all the factors used in preparing the load estimates;
10.5.3
11.8.2
provide separate forecasts to at least the zone substation level covering at least a minimum 5 year forecast period. Discuss how uncertain but substantial individual projects/developments that affect load are taken into account in the forecasts, making clear the extent to which these uncertain increases in demand are reflected in the forecasts;
10.5.4
11.8.3
identify any network or equipment constraints that may arise due to the anticipated growth in demand during the AMP planning period; and
10.5.2
11.8.4 discuss the impact on the load forecasts of any embedded generation or anticipated levels of distributed generation in a network, and the projected impact of any demand management initiatives.
10.5.8
11.9
12
Analysis of the significant network level development options available and details of the decisions made to satisfy and meet target levels of service, including
11.9.1 the reasons for choosing a selected option for projects where decisions have been made;
11.9.2
the alternative options proposed for projects that are planned to start in the next 5 years and the potential for non‐network solutions described;
11.9.3
a consideration of planned innovations that improve efficiencies within the network, such as improved utilisation, extended asset lives, and deferred investment.
AMPs must include a description and identification of the network development programme including distributed generation and non‐network solutions and actions to be taken, including associated expenditure projections. The network development plan must include:
12.1
A detailed description of the projects currently underway or planned to start within the next 12 months;
12.2
A summary description of the projects planned for the next 4 years; and
12.3
An overview of the projects being considered for the remainde r of the AMP planning period.
10.5.5
10.6
10.6.4
10.6
10.5.5
10.5.5
10.5.5
10.6
10.5.5
10.7
13
AMPs must describe the EDB's policies on distributed generation, including the policies for connecting embedded generation. The impact of such generation on network development plans must also be stated.
10.5.8
14
AMPs must discuss the EDB's policies on non‐network solutions, including:
10.5.5
14.1
Economically feasible and practical alternatives to conventional network augmentation. These are typically approaches that would reduce network demand and/or improve asset utilisation; and
14.2
The potential for non‐network solutions to address network problems or constraints .
10.5.5
10.5.8&9
Lifecycle Asset Management Planning (Maintenance and Renewal)
15
The AMP must provide a detailed description of the lifecycle asset management processes, including‐
Sect. 11.0
15.1
The key drivers for maintenance planning and assumptions ;
11.5
15.2
Identification of routine and corrective maintenance and inspection policies and programmes and actions to be taken for each asset category, including associated expenditure projections. This must include:
11.6
15.2.1
the approach to inspecting and maintaining each asset category, including a description of the types of inspections, tests and condition monitoring carried out and the intervals at which this is done;
15.2.2 any systemic problems identified with any particular asset types and the proposed actions to address these problems; and
15.2.3
budgets for maintenance activities broken down by asset category for the AMP planning period.
11.7
11.5.6
11.6
11.8
15.3
Identification of asset refurbishment and renewal policies and programmes and actions to be taken for each asset category, including associated expenditure projections. This must include:
11.6
15.3.1
the processes used to decide when and whether an asset is replaced or refurbished, including a description of the factors on which decisions are based;
15.3.2
a description of the projects currently underway or planned for the next 12 months;
11.7
15.3.3
a summary of the projects planned for the following 4 years; and
11.8
15.3.4
an overview of other work being considered for the remainder of the AMP planning period.
11.5&6
11.8.4
Risk Management
16
AMPs must provide details of risk policies, assessment, and mitigation, including‐
Sect. 9.0
16.1
Methods, details and conclusions of risk analysis;
9.4
16.2
Strategies used to identify areas of the network that are vulnerable to high impact low probability events and a description of the resilience of the network and asset management systems to such events;
9.4
16.3
A description of the policies to mitigate or manage the risks of events identified in subclause 16.2 above;
9.4
17
Details of emergency response and contingency plans.
9.2
18
Details of any insurance cover for the assets, including:
9.3
18.1
The EDB's approaches and practices in regard to the insurance of assets, including the level of insurance;
9.3
18.2
In respect of any self insurance, the level of reserves,details of how reserves are managed and invested, and details of any reinsurance.
9.3
Evaluation of performance
19
AMPs must provide details of performance measurement, evaluation, and improvement, including‐
19.1
Sect. 12.0
A review of progress against plan, both physical and financial;
12.1
•
•
•
19.2
referring to the most recent disclosures made under clause 5 of section 2.5, discussing any significant differences and highlighting reasons for substantial variances;
commenting on the progress of development projects against that planned in the previous AMP and provide reasons for substantial variances along with any significant construction or other problems experienced;
commenting on progress against maintenance initiatives and programmes and discuss the effectiveness of these programmes noted.
An evaluation and comparison of actual service level performance against targeted performance;
•
12.2
in particular, comparing the actual and target service level performance for all the targets discussed under the Service Levels section of the AMP over the previous 5 years and explain any significant variances;
19.3
An evaluation and comparison of the results of the asset management maturity assessment disclosed in the AMMAT Report against relevant objectives of the EDB's asset management and planning processes.
7.10
19.4
An analysis of gaps identified in subclauses 19.2 and 19.3 above . Where significant gaps exist (not caused by one‐off factors), the AMP must describe any planned initiatives to address the situation .
12.4
Capability to deliver
20
AMPs must describe the processes used by the EDB to ensure that;
20.1
The AMP is realistic and the objectives set out in the plan can be achieved ;
8.2
20.2
The organisation structure and the processes for authorisation and business capabilities will support the implementation of the AMP plans.
8.2
AMMAT Report
21
Each supplier must complete the AMMAT Report. The EDB must ensure that the person responsible for managing network assets (or a similar level individual) in the organisation takes responsibility for completing and maintaining the AMMAT, including:
Append. B
21.1
Organising people within the organisation to answer the questions;
7.10.1
21.2
Arranging for all information to be captured within the AMMAT;
7.10.1
21.3
Reporting to the organisation on the results of the assessment;
7.10.1
21.4
Planning the assessment process, including:
21.4.1
determining the form the assessment process is to take. In this context, the principal formats are generally taken to be interviews, facilitated groups/pane ls or a combination of the two;
7.10.1
21.4.2
arranging for appropriate outsourced service providers and stakeholders to act as respondents during the assessment exercise;
7.10.1
21.4.3
providing appropriate pre‐assessment communication (and training where appropriate) to ensure that, as a minimum, the proposed respondents are aware of the AMMAT process and the part within it that they are being asked to play;
7.10.1
21.4.4
identifying which questions are to be asked of which respondents .
7.10.1

Scanpower Asset Management Plan 2013/2023 Scanpower Asset

Transcription

Similar documents

PureNet™ Asset Management

Maintenance, Facility Management, and Capital Planning Software

Integrating Asset Management Into the Transportation Planning

Ajilon – Asset Management

Asset protection unit product guide

Asset Management

Platinum | Gold | Silver | Bronze | Table

BEST Sourcing Shop

METAL FEEDER COVERS

Asset management….