TL CONDUCTORS AND INSULATORS - Transpower

TL CONDUCTORS AND Insulators © Transpower New Zealand Limited 2013. All rights reserved.

TL CONDUCTORS AND INSULATORS

Fleet Strategy

Document TP.FL 01.00

16/10/2013

TL Conductors and Insulators Fleet Strategy TP.FL 01.00 Issue 1 October 2013

TL CONDUCTORS AND INSULATORS FLEET STRATEGY © Transpower New Zealand Limited 2013. All rights reserved.

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TL CONDUCTORS AND Insulators © Transpower New Zealand Limited 2013. All rights reserved.

Table of Contents

EXECUTIVE SUMMARY ...................................................................................................................... 1

SUMMARY OF STRATEGIES .............................................................................................................. 4

1 INTRODUCTION ....................................................................................................................... 7

Purpose ................................................................................................................................. 7 1.1

Scope .................................................................................................................................... 7 1.2

Stakeholders ......................................................................................................................... 7 1.3

Strategic Alignment ............................................................................................................... 8 1.4

Document Structure .............................................................................................................. 9 1.5

2 ASSET FLEET ........................................................................................................................ 10

Asset Statistics .................................................................................................................... 10 2.1

Asset Characteristics .......................................................................................................... 16 2.2

Asset Performance .............................................................................................................. 32 2.3

3 OBJECTIVES .......................................................................................................................... 37

Safety .................................................................................................................................. 37 3.1

Service Performance ........................................................................................................... 37 3.2

Cost Performance ............................................................................................................... 38 3.3

New Zealand Communities ................................................................................................. 38 3.4

Asset Management Capability ............................................................................................ 39 3.5

4 STRATEGIES.......................................................................................................................... 41

Planning .............................................................................................................................. 41 4.1

Delivery ............................................................................................................................... 55 4.2

Operations ........................................................................................................................... 58 4.3

Maintenance ........................................................................................................................ 60 4.4

Disposal and Divestment .................................................................................................... 66 4.5

Asset Management Capability ............................................................................................ 67 4.6

Summary of RCP2 Fleet Strategies .................................................................................... 71 4.7

APPENDICES ..................................................................................................................................... 73

CONDITION INFORMATION .................................................................................................. 74 A

CORROSION ZONE MAP ...................................................................................................... 78 B

CONDUCTOR DEGRADATION EXAMPLES ......................................................................... 80 C


TL CONDUCTORS AND INSULATORS FLEET STRATEGY © Transpower New Zealand Limited 2013. All rights reserved. Page 1 of 72

EXECUTIVE SUMMARY

Introduction

Transmission line conductors are core components of the transmission network, and enable the flow of electricity from generators to consumers. Insulators are essential for high-voltage transmission, and are used to attach energised conductors to supporting structures such as towers and poles.

The performance of conductors and insulators is critical to ensuring public safety and maintaining reliability of supply to customers.

Our asset management approach for conductors and insulators seeks to achieve a high level of reliability for this essential equipment, to mitigate safety hazards and to achieve least whole-of-life cost.

Asset fleet and condition assessment

There are approximately 12,000 route kilometres1 of transmission line and 58,000 insulator circuit sets, comprised of 210,000 insulator strings, in service on the network.

Despite the large numbers of components in service, the reliability of conductors and insulators is high, and failures are rare. The 10-year average rate of conductor drop incidents resulting from failures of conductors or insulators is less than three events each year. Most incidents are caused by failure of joints.

The environmental conditions in New Zealand vary greatly by region, but many areas experience a temperate, moist, maritime climate. There are frequent strong winds, with predominant westerly winds from the ocean. The strong winds and high rates of salt deposition in many coastal regions lead to relatively short lifetimes for conductors and insulators. Despite the often harsh environmental conditions, the fleet of conductors and insulators is generally in good condition.

We use the results of scheduled condition assessments together with forecasting models to project future requirements for maintenance and replacement. The condition forecasting uses degradation models that take account of regional environmental conditions. Replacements are scheduled in advance, based on the forecasting models, so that replacement occurs at or just before the point where the component can no longer support its design load, including a safety margin. Some components are replaced before the normal condition-based threshold, if alignment with other work makes early replacement economic.

Reliable condition assessment of conductors is of vital importance because of the public safety and reliability consequences of conductor failure. Quality condition assessment data provides the basis for asset management decision making and allows us to optimise the timing of conductor replacement projects.

Over 70% of all our transmission lines use an aluminium conductor reinforced with a steel wire core. Experience with this type of conductor has shown that it is vulnerable to significant deterioration of the aluminium conductor and internal steel core before there is visible external evidence.

1 Route length is the end-to-end distance traversed by the line; circuit length is the total length of the

circuits carried on the line (for example, a double circuit line of 100 route km will be a 200 circuit km line).



Numerous instances have been found where corrosion of the aluminium conductor against the steel wire core has advanced to the point where there is visible bulging of the conductor bundle. There has been one significant incident where a conductor on a major transmission line failed as a consequence of severe conductor deterioration leading to burn down of the steel core.

The condition assessment approach for conductors is based on the assessed and forecast condition. We use more intensive inspection methods as the condition of the conductor gets closer to the replacement criteria. These inspection methods include close visual inspection from a helicopter, and the use of a line-crawling robot that provides a reliable assessment of the condition of the inner steel core.

Condition assessment of insulators is relatively straightforward, and relies on standardised visual inspection criteria. Glass and porcelain insulators together make up approximately 80% of the fleet. A condition forecasting model is used for these types of insulator to predict when they will reach the replacement criteria. The remaining 20% of insulators use composite technology.2 We are still gaining experience with condition assessment and lifetime forecasting of composite insulators.

We have an ongoing programme of insulator replacement to maintain the asset health of the fleet.

Conductor and insulator strategies

The primary strategy for the conductors and insulator asset fleet is the condition-based replacement of degraded conductors. We will continue to use more intensive condition assessment techniques to supplement routine condition assessment as the conductor condition approaches replacement criteria.

We will optimise the timing of conductor replacement projects by undertaking localised repairs to defer the need for complete conductor replacement. Our strategy is to replace conductors when condition assessment shows a significant proportion of spans have sections nearing end of life due to loss of strength or cross sectional area, and the cost of maintaining such defects and the risk of failure have become unacceptably high.

The conductor replacement projects planned for the RCP2 period include five large projects with a combined forecast cost of approximately $120m. We propose that the detailed design and implementation of these five large re-conductoring projects will be subject to individual regulatory approval, rather than being part of base capital expenditure (capex). Capitalised investigation costs will be retained in base capex, to allow further refinement of cost and scope prior to submission.

We plan to replace approximately 1,400 insulator circuit sets each year through the RCP2 period to maintain the asset health of the insulator fleet and avoid major failures. The annual planned replacement volume represents 2.4% of the fleet.

2 Composite insulator assemblies use a fibreglass rod with silicone rubber sheath and sheds.



Improvements

Our planning for the RCP2 period has included a number of improvements to the asset management of conductors and insulators, such as:

improved modelling of condition degradation

introduction of asset health indices to allow better comparison of asset condition across fleets

use of updated and more detailed building blocks for cost estimates

prioritisation of works now includes network and safety criticality

For the insulator fleet, our approach remains unchanged from the RCP1 period, except that composites will now be used only in extreme and very high contamination areas. Glass will be installed elsewhere. This is a change from the RCP1 strategy which proposed installing composites in moderately polluted areas. This is due to uncertainty regarding achievable composite life in the New Zealand environment and the difficulty associated with condition assessing them.

Further improvements will include:

refinement of condition assessment techniques and the asset health model

refinement of the asset criticality framework.



SUMMARY OF STRATEGIES

This section provides a high-level summary of the main asset management strategies for conductors and insulators in the RCP2 period (2015–2020).

Capital expenditure (Capex)

Replace Degraded Conductors RCP2 Cost $16.4m

Our strategy is to replace conductors when condition assessment shows a significant proportion of spans have sections nearing end of life due to loss of strength or cross-sectional area, and the cost of maintaining such defects and the risk of failure have become unacceptably high. This strategy will lead to improved safety and reliability through reduced likelihood of conductor drops.

We are proposing that the design and implementation phases of five large conductoring projects set out below, with a total expenditure forecast of $117.8m, be removed from base capex and submitted for separate approval. This leaves $16.4m under this strategy.

Line Name (Section) Cost

BPE-WIL A (WIL-JFD Section) $48.9m

OTB-HAY A (45A-68) $27.8m

CPK-WIL B (full) $25.7m

BRK-SFD B (full) $11.1m

BPE-WIL A (BPE-JFD Section) $4.3m

Over the RCP2 period, we plan to replace approximately 450 circuit kms at a cost of $134.2m.3&4

Replace Degraded Insulators and Hardware RCP2 Cost $36m

Our strategy is to replace insulators and hardware when they have degraded to the point where they can no longer reliably carry their design loads (including a margin of safety), or their electrical performance has become unreliable. This strategy will lead to improved safety and reliability through reduced likelihood of conductor drops or electrical flashover.

Over the RCP2 period, we plan to complete 3,900 insulator circuit set replacements at 110 kV and below, and 3,200 at 220 kV or above, at a total cost of $36m.

3 This excludes expenditure associated with re-conductoring 236 circuit km on the BPE-HAY A and B lines as

this is being covered under the major capex work stream. 4 Re-conductoring projects typically include associated works such as tower strengthening, foundation

strengthening and complete re-insulation.



Replace Degraded Earthwires RCP2 Cost $8.3m

The network includes ageing earthwires, some with poor asset health that are more likely to fail. Failed earthwires can fall into phase conductors causing extended outages and safety concerns.

Our strategy is to replace degraded earthwires based on asset health and criticality. This strategy will lead to improved safety and reliability through reduced likelihood of earthwire drops.

Over the RCP2 period, we plan to replace a total of 330 km of earthwire on 19 lines due to corrosion of the wires. This work has an estimated cost of $8.3m.

Update Aerial Laser Surveys RCP2 Cost $4.2m

Over the last decade, we have performed aerial laser surveys (ALS) of 93% of our transmission line routes. The ALS data has proven invaluable in assisting with the management of statutory clearance requirements and for uprating investigations. The remaining portion of the network will be surveyed during RCP1.

Our strategy is to keep the aerial laser survey data up to date, by undertaking further ALS flights every second year, to resurvey lines that have been modified, or where underbuild has occurred.

Over the RCP2 period, we plan to resurvey a total of 3000 km of line (approximately 25% of the network route length), at an estimated cost of $4.2m.

Under Clearance Span Management RCP2 Cost $3.2m (capex)

$2.7m (opex)

Very low conductors pose an unacceptably high risk to the public.

Our strategy is to prioritise known under-clearance spans for mitigation using a risk-based approach. We plan to carry out works to mitigate the risk for all spans assessed as requiring mitigation by 2020. This strategy will lead to improved safety and reliability through reduced likelihood of flashover.

Over the RCP2 period, we plan to replace structures associated with fixing clearance violations at 115 sites at an estimated cost of $3.2m. Further clearance violation rectification work at 175 sites has an estimated total cost of $2.7m over RCP2.



Provide Inter-Phase Spacers RCP2 Cost $2m

Operating experience has shown that some transmission lines are vulnerable to conductor clashing in severe climatic conditions, causing damage to the conductors, and creating a power system fault that may lead to significant interruptions to customers. Inter-phase spacers can be effective in preventing conductor clashing.

Our strategy is to provide inter-phase spacers on vulnerable spans where the costs are justified by the benefits, taking into account the network consequences of conductor clashing.

Over the RCP2 period, we plan to provide inter-phase spacers on WRK-WHI line A, at an estimated total cost of $2m.

Operating expenditure (opex)

Replace Degraded Vibration Dampers and Spacers & Insulator Hardware

RCP2 Cost $12.6m

Failed dampers and spacers lead to rapid degradation of conductor condition, increasing risk of failure.

Our strategy is to replace vibration dampers, spacers and hardware when they have degraded to the point where they can no longer reliably perform their intended function, or when postponing replacement will significantly increase replacement cost. This strategy will lead to improved safety and reliability through reduced likelihood of conductor drops.

Over the RCP2 period, we plan to replace spacers on a total of 885 circuit spans at an average annual cost of $1.46m, replace dampers on a total of 2,300 circuit spans at an average annual cost of $990,000, and replace insulator hot end hardware on 120 circuit spans at a total RCP2 cost of $400,000.

Monitor Conductor Health and Risk RCP2 Cost $10.8m

A comprehensive understanding of the condition of conductor assets is critical for selecting the most appropriate timing of conductor replacement. This is supported through enhanced regular visual condition assessments of conductors (by targeted close aerial surveys, Cormon corrosion detector and conductor sampling).

The strategy is to continue to assess conductor health and criticality to prioritise conductor sections for replacement five years ahead of need date. This strategy will lead to improved safety and reliability through reduced likelihood of conductor drops. It also enables efficient deferral of capital expenditure.

For each year of the RCP2 period, we plan to assess 165 spans using Cormon testing, undertake aerial surveying on 400 spans, and cut out and test 5 conductor samples. This programme has a total estimated cost over RCP2 of $10.8m.

Chapter 4 has further details on these strategies and a discussion of the remaining strategies.



1 INTRODUCTION

Chapter 1 introduces the purpose, scope, stakeholders, and strategic alignment of the conductors and insulators fleet strategy.

Purpose 1.1

We plan, build, maintain and operate New Zealand’s high-voltage electricity transmission network (‘Grid’), which includes the conductors and insulators that facilitate the transportation of electricity from generators to customers and distributors.

The purpose of this fleet strategy document is to describe our approach to lifecycle management of our conductors and insulators fleet. This includes a description of the asset fleet, objectives for future performance and strategies being adopted to achieve these objectives.

The strategy sets the high-level direction for fleet asset management activities across the lifecycle of the asset fleet. These activities include Planning, Delivery, Operations, and Maintenance.

This document has been developed based on good practice guidance from internationally recognised sources, including BSI PAS 55:2008.

Scope 1.2

The scope of the strategy includes the following components of the conductor assets:

aluminium, copper and steel stranded phase conductors

earthwires

conductor joints, spacers, dampers and marker balls.

The scope of the strategy also includes the following components of the insulator fleet:

glass, porcelain and composite insulators

phase conductor and earthwire clamps

associated hardware, such as shackles and link straps.

This strategy does not include submarine or underground cables, which are included in the HVDC and Cables fleet strategies respectively.

Stakeholders 1.3

Conductors and insulators are important components of the transmission system. Correct operation and maintenance of conductors and insulators is essential for the safe transport of electricity from generators to customers and distribution networks across public and private land.



Key stakeholders include:

landowners

relevant Transpower Groups: Grid Development, Performance and Projects

regulatory bodies: Commerce Commission, Electricity Authority, and the Environmental Protection Authority

generators

service providers

customers, including distribution network businesses.

Strategic Alignment 1.4

A good asset management system shows clear hierarchical connectivity or ‘line of sight’ between the high-level organisation policy and strategic plan, and the daily activities of managing the assets.

This document forms part of that connectivity by setting out our strategy on the conductors and insulators asset fleet. This asset strategy directly informs the Asset Management Plan - TL Conductor and Asset Management Plan - TL Insulators.

The hierarchical connectivity is represented graphically in Figure 1. It indicates where this fleet strategy and conductors and insulator plans fit within our asset management system.

Figure 1: The Conductors & Insulators Strategy within the Asset Management Hierarchy

Conductors Plan

Conductors & Insulators Strategy

Insulators Plan

Corporate Objectives & Strategy

Asset Management Policy

Asset Management Strategy

Lifecycle Strategies

DeliveryPlanning Operations DisposalMaintenance



Document Structure 1.5

The rest of this document is structured as follows.

Chapter 2 provides an overview of the conductor and insulator fleets including statistics, characteristics and their performance.

Chapter 3 sets out asset management related objectives for the conductor and insulator fleet. These objectives have been aligned with the corporate and asset management policies, and with higher-level asset management objectives and targets.

Chapter 4 sets out the fleet specific strategies for the management of the fleet. These strategies provide medium-term to long-term guidance and direction for asset management decisions and will support the achievement of the objectives in chapter 3.

Appendices are included that provide further detailed information to supplement the fleet strategy.



2 ASSET FLEET

Chapter 2 provides a high-level description of the conductor and insulator asset fleets, including:

Asset statistics: including population, diversity, age profile, and spares

Asset characteristics: including safety and environmental considerations, asset criticality, asset health, and maintenance requirements and interaction with other assets

Asset performance: including reliability, safety and environmental.

Asset Statistics 2.1

This section outlines the conductor and insulator asset fleet population, along with their diversity and age profiles.

Asset Population 2.1.1

Conductors

The transmission line network is made up of 11,600 route km of transmission line or 17,200 circuit km. In total, this results in more than 65,000 km of phase conductor, and approximately 5,600 km of earthwire. Earthwires are generally only provided for the first 1 km to 2 km from a substation, but some lines have more extensive earthwire coverage. Table 1 shows the population of the conductor fleet by voltage.

< 66 kV 110 kV 220 kV 350/HVDC Total

Route km 636 4,528 5,880 583 11,627

Circuit km 883 5,925 8,860 1,549 17,217

Earthwire km 662 727 3,655 531 5,5765

Table 1: Conductor Length by Voltage

Hardware

There is a number of hardware types associated with the conductor population. Table 2 sets these out, with their approximate population numbers.

Hardware Type Number

Mid-span joints 60,000

Dead end and other joints 40,000

Spacers6 240,000

Dampers 320,000

Table 2: Conductor hardware population

5 Total includes 600 km of Optical Ground Wire (OPGW).

6 Spacers maintain the distance between twin and triple conductor configurations.



Insulators

There are approximately 210,000 insulator strings in service on the transmission line network, comprising 58,000 insulator circuit sets (approximately 51,000 suspension sets and 7,000 strain sets). For the purposes of this document, a strain set comprises all the strain insulators for one circuit on a structure; that is the forward string, the back string and usually a jumper string. Generally there are three strings for each circuit, although some lines with heavier conductor have twin strings at strains and some suspension structures.

Fleet Diversity 2.1.2

Conductors

Early transmission lines for the 110 kV, 66 kV and 50 kV systems primarily used copper conductors with some Aluminium Conductor Steel Reinforced (ACSR)/GZ.7 The 220 kV system development from the mid-1950s required ACSR/GZ for the longer spans, and larger diameter conductors were required to manage the higher currents and corona effects.

A programme of grease application during the manufacture of ACSR/GZ conductor began in the mid-1950s, but the application of the grease was inconsistent until the late 1970s. Then it became evident that grease could significantly extend core life. Also during this period there was an attempt to extend service life by replacing the traditional galvanised core wire with aluminium clad wire.

All Aluminium Alloy Conductor (AAAC)-type conductors have recently been introduced and been adopted for all recent new transmission lines and for most major conductor replacements. AAAC conductor is now the preferred conductor type, but its use can be limited by corridor width (it tends to blow out more than ACSR) and ground clearance (it sags more than ACSR).

Reflecting the historical changes in approach, there is a range of conductor types in service, as shown in Table 3.

Type Description Typical Use %

ACSR-GZ (greased)

Aluminium conductor steel reinforced, galvanised steel wire core (greased)

Phase conductors and earthwires

51%

ACSR-GZ (ungreased)

Aluminium conductor steel reinforced, galvanised steel wire core (ungreased)


7%

ACSR-AC (greased)

Aluminium conductor steel reinforced, aluminium clad steel wire core


10%

AAAC (greased) All Aluminium Alloy Conductor Phase conductors 3%

Copper All copper conductor Phase conductors 9%

SC/AC Steel conductor, aluminium clad (Alumoweld) Earthwires 4%

SC/GZ Steel conductor, galvanised Earthwires 13%

Other Other Earthwires 0%

OPGW Optical Ground Wire Earthwires 3%

Total 100%

Table 3: Conductor Types and Proportion of Network

7 ASCR/GZ means Aluminium Conductor Steel Reinforced, Galvanised Steel Wire Core.



Diversity in conductor material is not a significant issue. Over time, legacy materials such as copper will be replaced by new standard conductor types (such as AAAC and ACSR-AC). The populations of dampers and spacers are relatively homogenous, with no issues arising from their diversity.

Insulators

Five types of insulator are currently deployed on the Grid. These are:

porcelain discs (cap and pin)

porcelain line posts (solid porcelain posts with integral sheds)

glass discs (cap and pin)

composite long rod (fibreglass rod with silicone rubber sheath and sheds)

composite line post (as for long rods, but with thicker fibreglass rod capable of carrying compression and bending forces).

As at 30 June 2013, the proportions of insulator types are as shown in Figure 2.

Figure 2: Insulators - Diversity

Glass insulators are used for new installations in most locations, but composites are used in polluted environments or where audible noise is likely to be an issue. Composite line posts are now used rather than porcelain as they are considerably lighter, less brittle and more resilient to impact loads. These are generally only used on pole lines.

All porcelain discs are gradually being phased out across the fleet, however, due to performance issues, all non-alumina porcelain discs have now been removed from the 220 kV network. A very small number remain on a few lower-voltage lines, but these continue to be phased out as a priority over alumina porcelain discs.

Age Profile 2.1.3

Our transmission lines have been installed progressively with particular periods of Grid development in the 1930s and the 1950s to 1980s. There has also been ongoing replacement and upgrading of conductors and insulators throughout this time, depending on the life expectancy of the asset and requirements for capacity upgrades.

Conductors

The average age of transmission conductors varies by construction and material type. The main conductor types have average ages as shown in Table 4.

GLASS (64%)

PORCELAIN (18%)

COMPOSITE (18%)

INSULATORS - DIVERSITY



Conductor Type Average Age (years)

ACSR-GZ 40 (Greased) / 54 (Ungreased)

ACSR-AC 16 (All greased)

AAAC 2 (All greased)

Copper 74

SC/AC 38

SC/GZ 48

Table 4: Conductors - Average Age

The observed life expectancy of conductors varies significantly depending on location of the circuit and the type of conductor. The impact of location relates to corrosion, which increases with windblown salty air and the acidic nature of geothermal areas.

Figure 3 shows the age profile of conductors.

Figure 3: Conductors - Age Profile

As for tower steel, conductor degradation rate is highly dependent on the environment. We have allocated each span to one of the six corrosion zones: Extreme, Very Severe, Severe, Moderate, Low, and Benign. Currently the same zone is used for the tower steel, insulators and conductor. For example, if tower 42 and 43 are in the severe zone, then span 42 is also deemed to be in the severe zone. The classification was determined by analysis of existing tower and conductor ages and current condition. Significant reference was also made to research by the Building Research Association of New Zealand and corrosion maps and tables from the New Zealand Heavy Engineering Research Association. Appendix B shows the geographical location of transmission spans by corrosion zone, and Table 5 gives typical life expectancies for the main conductor types in each of the six corrosion zones.

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

0 10 20 30 40 50 60 70 80 ≥90

CIR

CU

IT K

M

AGE (YEARS)

ACSR-GZ ACSR-AC AAAC COPPER SC/AC SC/GZ

CONDUCTORS - AGE PROFILE



Type Benign Low Moderate Severe Very

Severe Extreme

ACSR-GZ Greased* 157 126 99 73 54 38

ACSR-GZ Grease Holiday 121 96 74 53 38 26

ACSR-GZ Ungreased 114 90 70 50 35 24

ACSR-AC Greased* 180 143 113 91 70 47

ACSR-AC Grease Holiday 126 113 88 71 54 35

AAAC Greased 160 139 120 103 87 70

Copper 117 104 90 77 65 54

SC/GZ 80 63 49 35 25 17

SC/AC & SC/CC 96 75 59 48 36 23

Table 5: Conductor Life Expectancy by Type and Corrosion Zone

* Values given in Table 5 for greased ACSR assume well-greased conductor throughout the entire length. Yet it has become evident that many conductors purchased prior to the mid-2000s had very poor quality controls applied to grease application. Consequently, many have patches of core wire with little or no grease. We refer to these as ‘grease holidays’. Grease holidays decrease conductor life dramatically. The reduction in life due to grease holidays is modelled as ranging from 12 years for extreme zones to 36 years for benign zones.

Condition, rather than age, is the primary driver for conductor replacement. Age is used as a ‘trigger’ for more detailed testing to ascertain the condition-based need date for conductor replacement. See sections 2.2.3, 2.2.4 and 2.2.5 for more details pertaining to condition assessment and asset health predictions for conductors and earthwires.

Hardware

Most spacers are still original, although a number of lines have had dog bone type spacers replaced because they were shown to damage the conductor. Others have been replaced in recent years just before the clamp bolts were likely to seize up. We only started installing vibration dampers in the early 1990s after the damaging effects of conductor Aeolian vibration were recognised.

Table 6 lists the proportion (percentages) of hardware circuit sets by corrosion zone.

Hardware Type

Benign Low Moderate Severe Very

Severe Extreme Total

Spacers 7% 16% 47% 21% 8% 1% 100%

Dampers 6% 14% 52% 16% 9% 1% 100%

Table 6: Hardware Circuit Sets by Corrosion Zone

Table 7 lists the typical life expectancies for the spacers and dampers by corrosion zone.

Hardware Type


Severe Extreme

Spacers 65 55 45 35 25 20

Dampers 30 30 25 20 15 10

Table 7: Hardware life expectancies



Insulators

Figure 4 shows the insulator fleet age profile.

Figure 4: Insulators - Age Profile

Table 8 lists the expected service life for each insulator type by corrosion zone.

Insulator Type


Severe Extreme

Glass 80 60 40 25 15 7

Porcelain 80 60 40 25 15 7

Composite 35 35 35 30 20 10

Table 8: Insulator Life Expectancy by Type and Corrosion Zone

Note that insufficient data exists for composite insulator service life in New Zealand, so these figures are estimates only based on limited field experience and guidance from overseas utilities.

Spares 2.1.4

Service providers keep a special inventory of conductor, insulators and hardware (spacers and dampers and other fittings) to allow rapid repairs to take place following minor failures or damage. These stocks are specific to each service area depending on the nature of the fleets in the area. These stocks are termed ‘Emergency Kits’. The emergency scenarios and types of spares carried are particular to the lines in each service providers ‘patch’. Generally, spares in the kits are to allow restoration of a single conductor span as well as insulators and hardware on two suspension structures and one strain.

In addition to the emergency kits held by service providers, we maintain minimum stock levels at our three warehouses. Sufficient stocks are carried to replace four typical spans of each conductor type.

The convenient availability of spares significantly reduces the length of outages, aiding our network reliability objectives. Without spares available, it could take several months to get replacement conductor, insulators or hardware.

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

0 10 20 30 40 50 60 ≥70

AGE (YEARS)

GLASS PORCELAIN COMPOSITE

INSULATORS - AGE PROFILE



Asset Characteristics 2.2

The conductor and insulator asset fleets can be characterised according to:

safety and environmental considerations

asset criticality

asset condition

asset health

maintenance requirements

interaction with other assets.

These characteristics and the associated risks are discussed in the following subsections.

Safety and Environmental Considerations 2.2.1

We are committed to ensuring that safety and environmental risks are minimised at all times. These risks are considered early in the asset management planning process. The most significant safety and environmental considerations for the conductor and insulator fleets are the risk of conductor drops and noise pollution from insulators. These issues are described below.

Conductor drops

The most significant safety concern relating to insulators and conductors is the risk of component failure leading to a conductor drop in a built-up area. The consequence of such a failure will depend on the specific local environment (typically worse for road crossings, line crossings, and urban zones) and the power system (number of circuits, voltage and current).

Our approach is to ensure assets are replaced prior to failure. This is informed through a detailed condition assessment regime and appropriately set replacement criteria. This minimises the risk of failure and mitigates the associated safety risk.

Noise pollution from insulators

Insulators used in areas with relatively high levels of airborne pollutants may accumulate significant contaminants on the insulators to cause corona discharge at audible levels. This can be a nuisance to the public. Porcelain and glass discs are more prone to this than composite insulators. As discussed in subsection 2.1.2, composites are used in polluted environments or where audible noise is likely to be an issue.

Porcelain insulators

Porcelain insulators are subject to electrical puncture, which can lead to mechanical failure and conductor drop. They are also more difficult to condition assess than glass insulators. Therefore, all porcelain discs are gradually being phased out.

Asset Criticality 2.2.2

We have established a process to determine criticality based on:

consideration of the importance of the site or circuit in terms of the load carried

the level of reliability required by the relevant customers



constraints and effects that would be placed on the rest of the Grid in the event of a failure

level of redundancy.

Based on these factors, we have established a framework for assigning asset criticality that classifies all assets as low, medium or high criticality. This approach is at an early stage of development and implementation so it will continue to be refined and improved over RCP2. Further information on the asset criticality approach is provided in the document: Asset Risk Management – Criticality Framework.

Our approach to asset management has been adapted to recognise the differing levels of asset criticality. Highly critical assets will be designed and maintained to provide a higher level of reliability than less critical assets.

The most critical conductor and insulator assets are those that are components in high impact circuits. Insulator criticality is directly linked to the defined criticality of the associated conductor. Figure 5 sets out the proportion of conductors in each criticality category. Almost half of the conductor fleet is classified as medium or high impact with respect to network criticality.

Figure 5: Conductors - Criticality

We have also developed a preliminary methodology for assigning safety criticality to conductor and insulator assets. All lines will be assigned a criticality of low, medium, high or very high depending on how they affect the safety of the community if a failure were to occur. We are still at a relatively early stage in the development and application of safety criticality, and will continue to refine and develop this throughout RCP2.

Subsections 2.2.4 and 4.1.2 discuss how criticality is taken into account, in combination with asset health to determine prioritised replacement programmes.

Asset Condition 2.2.3

We carry out regular condition assessments on the conductor and insulator fleet. The programme began in 1996 and today provides high-quality data to inform maintenance decisions.

The assessments produce a condition assessment score (‘CA’) for various components on a scale from 100 (new) to 20 (replacement or decommissioning criteria). New structures are first assessed just prior to expiration of the defects liability period. Thereafter, tower line assets are generally assessed every eight years and pole lines every six years. When the CA score of any component is less than 50, the assessment frequency is generally doubled, to take place every four years for towers and three years for poles. The aim is to ensure that no component is allowed to deteriorate by more than 50% between assessments (such as from CA score 60 to 30). Sites with very high degradation rates or criticality may be assessed more frequently.

LOW (46%)

MEDIUM (41%)

HIGH (14%)

CONDUCTORS -NETWORK CRITICALITY



See Appendix A and TP.SS 02.17C for more detail regarding conductor and insulator condition assessment.

Conductor condition

Earthwire condition

Most existing earthwires on the Grid are steel, clad with either aluminium or zinc (SC/AC or SCGZ). These are easier to condition assess than ACSR because any rusting is clearly visible. Close aerial inspections are used to complement ground-based and structure-based visual assessments, and samples may be taken for analysis when end of life is thought to be within five years. ACSR earthwires are assessed in the same way as conductors, using close aerials, Cormon testing and sample analysis when end of life is approaching.

Conductor condition

Degradation of conductor condition depends primarily on the corrosiveness of the local atmosphere, but also on the construction (such as greasing) and the conductor material.

Conductor condition is assessed based on a combination of loss of section and loss of tensile strength. See the replacement criteria below.

Ground-based and structure-based visual assessments yield valuable results for steel earthwire because any rusting can be readily observed. However, for ACSR and AAAC conductors, such assessments are of very limited use in predicting end of life in a timely manner. This is because degradation (corrosion, fatigue, fretting) generally begins on the inside of the conductor, so is invisible until well advanced. Even detecting white corrosion product or small bulges is extremely difficult from the ground when looking up into the sky.

The photographs (Figures 6 to Figure 8) were taken of a sample cut from the BPE-WIL A line in 2009. They graphically illustrate the internal corrosion problem.

Figure 6: Sample showing two bulges that are relatively large, but still extremely difficult to see in span from the ground

Figure 7: Close-up of bulge 1 (the right hand bulge of the previous photo)



Figure 8: Bulge 1 after removal of the outer layer of aluminium strands, showing the extent of internal damage of aluminium wires

Figure 9: Bulge 2 core steel showing red/brown rust deposits

Specialist metallurgical consultants have investigated the phenomena of corrosion-induced conductor bulging in detail and advise that conductors may only remain serviceable for 3 to 5 years after visible bulges occur. This timeframe is too short to allow appropriate options analysis, planning, consenting and implementation of a major re-conductoring project. Prudent conductor management therefore requires more advanced condition assessment techniques than purely visual.

We use the following regime and techniques to monitor conductor condition.

Regular visual CA: This involves qualified condition assessment staff making a judgement of the conductor condition at sample locations along the line. Access to the conductors is generally from structures as part of the CA process. Visual indicators and their respective scores are defined in TP.SS 02.17, Part C. Appendix A of this fleet strategy has extracts from TP.SS 02.17.

Predictive modelling for end of life: This is relatively new and is still developing. Inputs are location (corrosion zone) as for tower steel, conductor material, number of aluminium conductor layers, greased or ungreased. Later, after close inspection or Cormon testing, it is updated if grease holidays are found. Modelling is used in



combination with regular visual CA to trigger more detailed investigations. All spans are modelled. The model is continually updated with the latest inspection data from visual, Cormon or sample testing for each line section to provide the best available prediction for end of life.

Close aerial survey: Close-up visual assessment from helicopters. This technique was developed following the 2005 BPE-HAY A conductor failure and has proven particularly successful in detecting white powder and slight bulging of conductors as well as spacer induced damage. Such defects are far easier to observe when looking down from above than if looking up from the ground. Close aerial surveys are carried out on lines where regular CA has observed issues worthy of closer inspection, or where the predictive model suggests end of life is approaching. In addition, once corrosion defects have been observed, close aerial inspections are carried out regularly on the section of concern (generally annually or biannually) to locate defects as they arise. These defects are then repaired as required until full conductor replacement is carried out.

Cormon overhead line corrosion detector: The Cormon detector is a non-destructive test device that uses eddy current technology to estimate the remaining thickness of zinc or aluminium coating on the steel core wire of ACSR conductors. The Cormon detector is placed on the conductor by linemen span by span. The device then self-propels to the other end of the span, taking measurements every 5mm to 10mm. Results from this device have proven to be remarkably accurate, providing an excellent indication of conductor condition without the need for destructive sample testing. We have carried out a Cormon test programme annually since 2006. Some 1,200 sub conductor spans had been tested by February 2013. Although some catch-up was required initially, the programme is now at a stage where it can follow a prioritised listing of assets based on their predicted end of life. The strategy is to begin Cormon testing some 10 years before predicted end of life, and then establish appropriate times for repeat inspections to ensure end of life predictions are refined as they approach.

Conductor sampling: This destructive process involves the removal of a short length of conductor from the line followed by dismantling and often metallurgical assessment in a laboratory. Prior to the Cormon programme, we used to cut out numerous samples around the country annually in an effort to monitor conductor condition. The use of Cormon has allowed this practice to be reduced markedly. Samples are generally now only taken from copper conductors (on which Cormon doesn’t work) and ACSR conductors when very close to end of life as indicated by Cormon. It is also the only technique that provides a full qualitative conclusion about the condition of the conductor (at a specific location).

Conductor condition reports: When conductors are approaching end of life, comprehensive condition reports are compiled to summarise known condition, data sources and likely replacement date. These are updated whenever new condition information comes to hand and form the basis of the business case for all conductor replacement projects.

Conductor degradation can be classified into two distinct categories, ageing and defects, as set out in the paragraphs below.



Ageing

Seven relevant types of conductor ageing mechanisms are explained below. Photographic examples are provided in Appendix C.

Grease degradation (where applicable): Grease is used in stranded conductors as a means of preventing corrosion between dissimilar metals. In ACSR conductors, it delays the onset of galvanic corrosion while it remains fluid. As grease ages, it breaks down and changes structure from a fluid to a solid state prone to fracture and ingress of pollutants. Typical life expectancy for grease inside stranded conductor is quoted by some manufacturers as approximately 20 years in ‘all weather conditions’.

Aluminium corrosion: Aluminium as a metal has excellent corrosion resistance due to the barrier of oxide film that occurs and is bonded strongly to its surface. If damaged, the oxide film re-forms immediately in most environments. Localised corrosion of aluminium can still occur – usually driven by the random formation of pits or crevices most commonly produced by the presence of sea salt.

Galvanic corrosion: ACSR conductors are susceptible to galvanic corrosion in which one metal corrodes preferentially when in electrical contact with a different type of metal and both metals are immersed in an electrolyte. Due to the extensive coastline in New Zealand, salt acts as an electrolyte. When the zinc or aluminium coating on the steel core wire is depleted, the conductor’s aluminium strands then corrode and form white aluminium oxide that expands within the conductor to form bulges, break strands and, if left undetected, cause conductor failure.

Copper corrosion: Copper corrodes at negligible rates in unpolluted air and water. Copper alloys resist many saline solutions, alkaline solutions, and organic chemicals, but is susceptible to oxidising acids such as hydrogen sulphide (H2S) gas. The most frequent sources of H2S gas are from geothermal, volcanic or swampy areas. In conductors the corrosion is usually even across the strands, with a very thick film of dark grey/black copper oxide. Some copper conductors have been in service in New Zealand since the 1920s and are still in relatively good condition.

Fatigue: For fatigue to occur there must be repeated cycles of stress in the conductor strands. These cycles act to ‘work harden’ the material to the point where it becomes so brittle that fracture occurs. Lines with high stringing tensions are more susceptible to fatigue than those with relatively low tensions. Conductor fatigue tends to occur at the suspension structure attachment points as a result of Aeolian vibration. Armour rods and good clamp design help limit damage, but keeping the fatigue-inducing stress below damage levels requires energy= absorbing vibration dampers.

Annealing: Annealing mostly applies to homogeneous conductors that rely on the copper or aluminium strands to maintain tensile strength. For annealing to occur as an ageing mechanism the conductors must be run at relatively high operating temperatures (90 degrees Celsius and above) for a significant period of time. This is currently not a significant issue.

Fretting: Fretting is the wear process that occurs at the contact area between two materials under load and subject to minute relative motion. The amplitude of this relative motion is often in the order of micrometres to millimetres. Aeolian vibration causes fretting in conductors, as does the slow and repetitive motion of conductor swing. Fretting causes mechanical wear at the contact surface, often followed by oxidation of both the metallic debris and the freshly-exposed metallic surfaces.



Because the oxidised debris is usually much harder than the surfaces from which it came, it often acts as an abrasive agent that increases the rate of fretting and mechanical wear. Grease applied to conductor layers has the effect of reducing fretting by increasing conductor self-damping, making it less susceptible to Aeolian vibration and by providing lubrication to the contact surfaces. Energy-absorbing vibration dampers and spacers help to mitigate the risk of fretting.

Defects

Defects relate to localised damage where a specific type of repair can be applied. Full conductor replacement is not normally warranted unless multiple defects are present in a span or section of line. Typical conductor defects are explained below.

Grease holiday corrosion: As discussed in subsection 2.1.3 above, grease applied to the core wire during manufacture provides a barrier to galvanic corrosion and can significantly extend conductor life. However, if it is applied poorly it is of little or even negative benefit. Experience has shown that grease application was poorly managed for conductors on many lines throughout the country, resulting in sections of core wire where no grease was applied at all (‘grease holidays’). Grease holidays expose small localised areas of the core wire to the environment that results in higher than normal corrosion rates. In 2005, a span on the BPE-HAY A line failed due to corrosion after only 25 years in service. Subsequent close aerial inspections revealed widespread instances of bulging of the conductor on the A and B lines, all due to grease holidays.

Dog bone spacer corrosion: A number of lines in the network with twin bundled conductors have external corrosion damage from early ‘dog bone’ spacers. This corrosion occurred through the late 1980s to early 1990s as a result of incompatible rubber in contact with the conductor. The majority of damage is confined to the outer layer of the conductor. Preform rods have been applied as a permanent repair. Sampling and metallurgical assessment suggest the corrosion mechanism is relatively benign now that the incompatible rubber has been removed. Some lines in more coastal areas require implosive repair sleeves to be fitted, as damage is beyond the repair capabilities of the pre-form rods.

Fatigue: Fatigue is mentioned here as experience shows some lines can suffer localised fatigue damage due to terrain, orientation, tension or a combination of each. Where it is identified, a localised repair programme can be applied and steps taken to prevent or limit re-occurrence.

Power arc damage: This is typically phase to earth at the structure as a result of insulation or air gap failure. Where armour rods are installed, damage to conductor does not generally occur. Flashover outside the ends of armour rods or phase to phase within the span can result in strand damage. The later tends to be more damaging due to the high phase to phase currents.

Lightning damage: Applies where a lightning strike contacts a conductor. Damage occurs on earthwires (where fitted) or to phase conductors where there is no earthwire.

Hardware abrasion: Typical examples of this are loose clamps on subconductor spacers, vibration dampers, inter-phase spacers etc. If left undetected, significant strand breakage can occur followed by conductor failure.



Gunshot damage: Whether intentional or by accident, bullets can damage many outer strands as they deflect off or partially through the conductor. There have been occasions where full penetration to the steel core has occurred. Fortunately, gunshot damage events are rare on the network.

Fire: Most fires under lines result in a breakdown of the air gap and circuit tripping. Damage is generally restricted to power arc damage except where temperatures at conductor height become severe, in which case annealing of the span(s) will result in a permanent reduction in conductor strength. This phenomenon is rare.

Mobile plant contact: If mobile plant breaches the critical flashover distance or makes physical contact with live conductors, the resultant power arc can cause damage to the strands. In extreme cases, conductor failure can and has occurred.

Tree strikes: If vegetation breaches the critical flashover distance or makes physical contact with live conductors, the resultant power arc can cause damage to the strands. In extreme cases, conductor failure can and has occurred.

Conductor replacement criteria

Conductor condition is assessed based on a combination of loss of section and loss of tensile strength. AAAC conductors are deemed to have reached replacement criteria at 15% loss of strength or section loss and at 10% for copper. For ACSR conductors, the replacement criteria is set at 20% loss of tensile strength and 15% section loss. These values are generally in line with those used by other international utilities.

Currently, only the visual CA assessments are assigned a rating score. Given that these are of limited value in predicting end of conductor life, they are not discussed further here. Rather, see subsection 2.2.4 Asset Health for end of life predictions. Condition assessment guidelines can be found in Appendix A.

Under-clearances and aerial laser survey

Aerial laser survey (ALS) data is used to build accurate models of each transmission line. These have proven invaluable in assisting with the management of statutory clearance requirements and for uprating investigations. Projects have been carried out recently to re-survey the lines. These works will continue through RCP2.

Insulator condition

All transmission line insulators on the network have their condition assessed during condition assessment patrols in line with TP.SS 02.17. Generally, this assessment is visual with the insulators in place; however, one string on every tenth structure inspected is removed and closely examined, usually on the ground (termed a lifting inspection). Lifting inspections help to evaluate if socket/pin connections have frozen up (which can put undue bending forces onto the pins) and allow very close examination of the entire insulator string. Frozen connections between adjacent discs or between clamps and hardware have led to several failures. For this reason, particular attention must be paid to identify frozen connections. We do not currently perform routine voltage drop or corona tests on all insulator strings; rather, these tests are only performed where some concern exists with regard to the electrical performance of the line insulation.

Degradation of insulators depends on the corrosiveness of the environment. In New Zealand, porcelain and glass cap and pin insulators generally reach end of life due to corrosion of the steel pins. In relatively rare cases, porcelain discs may become porous leading to electrical and possibly mechanical failure. For composite insulators, end of life



could be reached either due to steel end fitting corrosion or from degradation of the sheath material. In any case, degradation of insulator assemblies depends strongly on the corrosiveness of the local environment. Each structure has therefore been classified into one of six corrosion zones depending on location, historical performance and steel degradation rates. Currently, the same zone classification is used for the tower steel, insulators and conductors of any given structure.

Figure 10 shows the condition assessment ratings (adjusted to 2013 values) for the population of insulator sets on the network, where a rating of 100 is new and 20 is normal replacement criteria. The chart shows that a number of (primarily glass) insulators are scored at less than CA 20.

Figure 10: Insulators – Condition (for each circuit span)

Insulator set hardware is also assessed during line patrols and assigned an appropriate CA score. Separate scores are assigned for the ‘hot’ and ‘cold’ end hardware; that is, hardware at the conductor end of the insulator string and at the structure end respectively.

Conductor joint condition

As joints age, their resistance tends to rise. In extreme cases, this can lead to thermal runaway and physical joint failure.

Experience has shown that visual condition assessment of compression joints and bolted connections is ineffective unless failure is imminent. Thermography has been used successfully to discover a small number of very bad joints, but technical difficulties prevent it from identifying joints that are at an earlier stage of degradation. Most lines in New Zealand run at relatively low operating temperatures, and this reduces the effectiveness of thermography.

Measuring the resistance across the joints is now considered the best technical and asset management solution. We are now one of the worldwide leaders in high-voltage joint resistance testing. The programme started in the early 2000s when joints were tested as part of thermal uprating projects. In 2009, following a joint failure over urban housing, we instigated a maintenance programme to test joints. To date, approximately 12,000 joints (approximately 20% of the fleet) have been tested. Of these, approximately 1% of the mid-span and dead-end joints were deemed to have unacceptably high resistance, and were

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GLASS PORCELAIN COMPOSITE

INSULATORS - CONDITION



replaced. Some 20% of all bolted palm joints tested had unacceptably high resistance and were refurbished.

Conductor vibration damper and spacer condition

Vibration dampers and sub-conductor spacers are visually condition assessed during condition assessment patrols in line with TP.SS 02.17.

Vibration dampers generally reach end of life when the galvanised messenger wire corrodes to an extent where the damper no longer oscillates as designed. In other cases the wire strands may fail by fretting, the weights may be loose or the clamp may be worn and cannot be tightened.

Sub-conductor spacers generally require replacement due to excessive corrosion of either the fixings, hardware or wire strands (used on ring spacer types). Other reasons for replacement include worn or broken clamps and broken strands due to fretting (on ring type spacers). Where possible, spacers are targeted for replacement just prior to seizure of the bolts (CA score 30). If left longer, the spacers often have to be cut off, which risks damaging the conductor. Figure 11 shows the condition of the damper fleet and Figure 12 shows the condition of the spacer fleet.

Figure 11: Dampers – Condition (for each circuit span)

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DAMPERS - CONDITION



Figure 12: Spacers – Condition (for each circuit span)

Figures 11 and 12 show that, while the majority of spacers and dampers are still in reasonable condition, a number are at or approaching replacement criteria.

Asset Health 2.2.4

The Asset Health Index (AHI) reflects the forecast remaining life for any given asset – in effect it is an assessment of current and future asset ‘fitness for purpose’. The AHI forecast of remaining useful life is based on modelling deterioration or risk that cannot be addressed by normal maintenance (such as where maintenance to address the deterioration or risk is not possible/practical or is uneconomic). For transmission line structures, this is when the structure can no longer be relied upon to carry its design loads. At this point, major intervention is required, such as total replacement of the asset or refurbishment that significantly extends the original design life.

Asset health indicators provide a proxy for the probability of failure in asset risk management analysis.

AHI is calculated using:

the current condition of the asset

the age of the asset

the typical degradation path of that type of asset

any external factors that affect the rate of degradation, such as proximity to the coast that affect the rate of corrosion of steel towers.

Assessing asset health is particularly important, as it is used to understand the deterioration profile of asset fleets and to forecast and prioritise replacement and refurbishment activities. Asset health information is used in combination with asset criticality data to assign an overall priority to each asset, which is used to optimise the level of investment in the fleet.

We are still at a relatively early stage in the development and application of asset health indicators. More details on our asset health methodology are set out in the document ‘Asset Risk Management – Asset Health Framework’.

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CA SCORE

SPACERS - CONDITION



Prioritisation is based on the matrix shown in Figure 13, which reflects remaining life and criticality. ‘Now Due’ works carry a higher priority than a high impact structure or span just reaching end of life, due to their heightened risk of failure.

Figure 13: Priority Matrix

Conductors

Unlike all other transmission line assets, which are discrete, a conductor is a compound linear asset. Deciding when to replace it is not straightforward. The occasional corrosion bulge can be removed; however, when widespread corrosion bulges occur in a span, replacement is prudent.

Loss of tensile strength is the most common failure mode in ACSR, although if the aluminium is severely deteriorated the final failure mode occurs when the steel core attempts to carry the current.

For sites where grease holiday issues are identified, special assessments are required to identify if it is acceptable to extend the conductor system life by replacement of short sections of line, or if a larger project is required to replace the entire circuit.

As discussed in subsection 2.2.3, we have developed and maintain a model to predict end of life for each span of conductor and earthwire. The model initially uses the expected life for each conductor type in each corrosion zone as tabulated in subsection 2.1.3. As end of life approaches, more detailed inspections are carried out, such as close aerial inspections, Cormon testing and laboratory inspections of samples. Results of these investigations are incorporated into the model so that it represents the best estimate of conductor end of life, or asset health, at any given time. We are still at a relatively early stage in the development and application of a formal conductor asset health model, and will continue to refine and develop this throughout RCP2.

Insulators

The age of all composite insulators is known as they have only been installed since the early 1990s. However, the exact age of many glass and porcelain insulators is unknown.

For composite insulators, where installed date is accurately known, end of life is simply predicted based on the expected service life as given in Table 8. These range from 10 years in extreme environments to 35 years in benign environments. Basing end-of-life predictions on age and not condition is unusual for transmission line assets, but it is appropriate for composite insulators due to the lack of historic performance data for the New Zealand environment and the relative difficulty in determining their end of life by visual condition alone. Asset health models for composite insulators may be developed in the future based on different criteria, as more experience is gained.

Increasing Criticality

Decre

asin

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ealth



Glass and porcelain insulators invariably reach end of life due to corrosion of the cap and pin. This corrosion is accurately monitored by condition assessment. Figure 14 plots the degradation of insulator condition with time, based on service experience. Note that end of life is deemed to occur at CA score 20.

Figure 14: Insulators - Degradation Path by Corrosion Zone

End of life (asset health) for each glass or porcelain insulator set is calculated by taking the current condition score and extrapolating along the curves to predict a replacement date. Figure 15 shows the current asset health profile of the insulator fleet as at 30 June 2013.

Figure 15: Insulators - Asset Health

Vibration dampers and spacers

Spacers and dampers invariably reach end of life due to corrosion. This is monitored by condition assessment. Figures 16 and 17 plot the degradation of condition with time. These curves are based on service experience and engineering judgment. Note that end of life is deemed to occur at CA score 20. End of life (asset health) is calculated by taking the current condition score and extrapolating along the curves to predict a replacement date.

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INSULATOR DEGRADATION RATE CURVES (GLASS AND PORCELAIN)

*AFFECTS METAL COMPONENTS OF INSULATORS

12+ YRS (85%)

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INSULATORS - ASSET HEALTH (12/13)



Figure 16: Dampers - Degradation Path by Corrosion Zone

Figure 17: Spacers – Degradation Path by Corrosion Zone

Figure 18 shows the current asset health profile of the damper and spacer fleets as at 30 June 2013.

Figure 18: Dampers and Spacers – Asset Health

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12+ YRS (61%)

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DAMPERS -ASSET HEALTH (12/13)

12+ YRS (87%)

7-12 YRS (9%)

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SPACERS -ASSET HEALTH (12/13)



Maintenance Requirements 2.2.5

This subsection describes the maintenance activities undertaken on the conductor and insulator asset fleets which inform the maintenance strategies (section 4.4). The most common types of maintenance carried out on the conductor and insulator fleet are:

preventive maintenance, including:

- line patrols and condition assessments

- servicing

corrective maintenance, including:

- fault response

- repairs

maintenance projects.

The maintenance lifecycle provides further details on the above maintenance works. Maintenance projects typically consist of relatively high-value planned repairs or replacements of components of larger assets.

Preventive maintenance

Line patrols and condition assessments

Line patrols are generally performed once a year on every transmission line asset, although sites with very high criticality may be patrolled more frequently. The primary purpose of the patrols is to identify defects. A ground-based patrol visits each structure/span and will walk the conductor line, if possible, to identify any defects. A patrol report identifies defects required to be rectified. As discussed in subsection 2.2.3, condition assessments are carried out at every structure on a cyclic basis and include a detailed inspection of the structure.

Servicing

Except for occasionally washing some insulators, no servicing is carried out on the conductor and insulator fleets. We do not undertake a significant amount of line and insulator washing, as the level of rainfall prevalent in the New Zealand climate generally makes this type of maintenance unnecessary.

Corrective maintenance

Fault response

The most common fault response is patrolling lines following faults to try and establish the cause and rectify the problem.

Repairs

Typical repairs undertaken on the conductor and insulator fleets include:

repairing broken conductor strands (gunshot, lightning)

refixing or replacing loose vibration dampers or spacers

removing foreign objects entangled in conductors (kites, bags, animals)

replacing insulators with broken skirts

replacing missing split pins from hardware or insulators



replacing isolated worn hardware

investigation and possible replacement of noisy insulators.

Maintenance projects

Maintenance projects typically consist of relatively high-value planned repairs or replacements of components of larger assets. Maintenance jobs are typically run as a project where there are operational and financial efficiencies from doing so. The drivers for maintenance projects include asset condition, mitigating safety and environmental risks, and to improve performance. Future maintenance projects are discussed in subsection 4.4.3. Examples of past maintenance projects are set out below.

Manage corroded conductor risks until full conductor replacement

Numerous lines are known to be corroding due to minimal or no remaining protective coating on the steel core wire, or from dog bone spacer damage. Until the conductors are replaced, the plan is to cut out sections of conductor at replacement criteria or install repair sleeves.

This work allows efficient deferral of capital expenditure on the full replacement of conductor.

Annual maintenance projects have been carried out recently to repair portions of conductors and will continue through RCP2.

Monitor conductor health and risk

Early detection of conductor corrosion by ground-based visual survey is difficult, so a very careful and detailed programme of testing and investigation is required. This programme includes line patrols, condition assessments and predictive modelling. Annual maintenance projects have been carried out recently to monitor conductor health and risk, and will continue through RCP2.

Resistance test joints and address those found to be defective

As stated in subsection 2.2.3, a number of conductor joints on towers are showing rising resistance. Annual maintenance projects have been carried out recently to replace joints with unacceptably high resistance. These replacements will continue through RCP2.

Replace degraded vibration dampers, spacers and insulator hardware

As stated in subsection 2.2.3, an increasing number of conductor hardware is nearing replacement criteria. Annual maintenance projects have been carried out recently to replace degrading hardware. These will continue through RCP2 and constitute a significant strategy (see subsection 4.4.3).

Under-clearance span management

A risk-based model has been developed for under-clearance spans. The model calculates the probability of flashing over to a person, vehicle or other object. Various rectification strategies are in place to mitigate the risk posed by spans with an unacceptably high risk of flashover. Annual maintenance projects have been carried out recently to rectify spans with an unacceptably high risk of flashover. These works will continue through RCP2.



Historic spend – maintenance projects

Figure 19 provides an overview of historic maintenance project expenditure. Future maintenance projects are discussed in subsection 4.4.3.

Activity 2009/10 2010/11 2011/12

Aerial Survey $120k $334k -

Monitor Conductors $957k $761k $615k

Manage Corroded Conductors $770k $905k $803k

Replace Hardware $1.4m $2.8m $1.7m

Test and Replace Joints $1.5m $1.5m $699k

Under-Clearance Span Management $303k $265k $37k

Various $575k $321k $122k

Total $5.6m $6.9m $4.0m

Figure 19: Historic Expenditure on Maintenance Projects

Interaction with other Assets 2.2.6

Programmes of work for conductors and insulators are closely aligned with foundation and tower works, as any new conductor work may require foundation and tower strengthening due to heavier conductors being used or the need to maintain clearance standards and other regulatory requirements that may have changed since the towers and/or foundations were first commissioned. These integration processes are managed through IWP as discussed in subsection 4.1.3.

Asset Performance 2.3

This section describes the historic performance of the conductor and insulator fleet.

Reliability 2.3.1

Achieving an appropriate level of reliability for our asset fleets is a key objective as it directly affects the services received by customers. Reliability is measured primarily by the frequency and length of outages. The main asset risks that impact on reliability are major failures (such as conductor drops) and forced and fault outages due to insulator failures.

Figure 20 shows the annual number of failure events which caused conductor to drop and the general reason for each. ‘Veg’ is an event where a tree has fallen into a line causing conductor drop. All events reported as ‘snow’ are incidents where snow loading resulted in a conductor breakage. Note that if an event causes two or more poles or towers to fail, this is shown as two or more failures. (An example of this is the January 2004 failure of three towers on the BEN-HAY A HVDC line).



Figure 20: Conductor Drops - Causes

Conductors and joints

Since 2001, 14 conductor drop events were due to conductors breaking. These failures generally occurred during severe wind events, although four occurred as a result of snow build-up on the conductors. In rare instances, conductors have failed when hit by lightning.

The physical reliability of our hard-drawn copper conductors is poor by comparison with ACSR and other modern conductors. The relatively small copper conductor is more likely to fail under snow load, when hit by lightning or during other faults. The ratio of copper to ACSR related failures (excluding jointing failures) exceeds 10 to 1. Copper conductor makes up only 9% of the current total conductor population.

Since the early 1950s, records show that 51 midspan and 5 dead end joints have failed mechanically. Four failures have occurred since 2001. In almost every case the cause was attributed to poor workmanship at the time of installation. The most significant event occurred in 2009 when a mid-span joint failed in urban Auckland, dropping a conductor onto houses below. Roofs, fences and electrical appliances were damaged, but thankfully, no-one was injured. A significant programme of joint testing was instigated following this and still continues.

Insulators

Mechanical failure of insulator sets is rare in spite of there being several million mechanical connections in service within insulator sets. Since 2001, 16 such failures have occurred. Frozen connections between adjacent discs or between clamps and hardware have led to several of the failures. For this reason, particular attention is now being paid to identifying seized connections as part of the condition assessment process.

Cost and Performance Benchmarking 2.3.2

International Transmission Operations & Maintenance Study (ITOMS) results provide a useful indication of our performance and maintenance costs compared to overseas electricity networks. Some care in interpreting the results is required, as the report uses various simplified methods to adjust data for a more fair comparison.

Figure 21 and Figure 22 respectively show reliability and cost for 100-199 kV and 200+ kV transmission lines. The overseas networks are represented by letters, and the letter representing Transpower has been circled and labelled ‘L’.

0

2

4

6

8

10

12

01/02 02/03 03/04 04/05 05/06 06/07 07/08 08/09 09/10 10/11 11/12 12/13

CONDUCTOR CROSSARM INSUL JOINT

POLE TOWER SNOW VEG

FAILURES CAUSING CONDUCTOR DROPS



From the ITOMS results shown, our 110 kV lines sit firmly in the high cost/weak reliability quadrant indicating relatively poor overall performance. Our 220 kV lines sit in the high cost/strong reliability quadrant indicating strong reliability performance but poor cost performance relative to peer utilities.

Figure 21: International Comparison of Opex Costs and Reliability for 100-199 kV Transmission Lines (ITOMS 2011)

Figure 22: International Comparison of Opex Costs and Reliability for 200+ kV Transmission Lines (ITOMS 2011)

Safety and Environmental Performance 2.3.3

As discussed in subsection 2.3.1, a number of failures have occurred resulting in conductor drops. Such events are rare, and to date no one has been harmed by such an event.



Tree strikes pose a significant safety and environmental risk. Fortunately, no injuries have been reported from such incidents.

Risks and Issues 2.3.4

This subsection briefly discusses the most significant risks and issues facing the asset management of the current population of conductors and insulators.

Chapter 4 sets out the strategies to manage and mitigate these risks.

Insulator failure

Insulator failure can be either electrical or mechanical.

Mechanical failure is generally attributable to steel corrosion, and will generally drop the conductor unless the insulator set comprises some redundancy (multiple strings).

Electrical failure of insulators is typically caused by pollution, either by bird droppings or other contaminants. This can lead to flashover and in extreme cases, mechanical failure.

Underbuild

Compared to similar overseas utilities, very few of our lines have easements. We have limited control over land use beneath or beside our lines. It is important to manage the clearance distances around lines to avoid vegetation/human related influences resulting in flashover and associated risks to public safety.

Conductor drops

Conductor drops can occur for a number of reasons, including mechanical insulator failure and failure of the conductor itself. Drops over urban areas and motorways pose a serious risk to public safety as these can lead to inadvertent contact with live conductors by members of the public and property. See subsection 2.3.1 for a summary of incidents. Conductor drops also have significant system performance impacts.

Joint failure

While the probability of a joint failure is low, the consequences can be high as the conductor will drop. Resistance testing joints provides the most reliable indication of joint condition, but it is expensive to carry out.

There are over 60,000 mid-span and 40,000 dead end joints in service. As joints age, their resistance tends to rise. If left unchecked, this can lead to thermal runaway and physical joint failure. As the joint fleet ages and the electrical load on circuits rise, the risk of joint failure increases.

Measuring the resistance across the joints is now considered the best technical and asset management solution. We are now one of the worldwide leaders in high-voltage joint resistance testing. The programme started in the early 2000s when joints were tested as part of thermal uprating projects. In 2009, following a joint failure over urban housing, we instigated a maintenance programme to test joints. To date, some 12,000 joints have been tested. Of these, approximately 1% of the mid-span and dead-end joints were deemed to have unacceptably high resistance and were replaced. Some 20% of all bolted palm joints tested had unacceptably high resistance and were refurbished.

The Transpower standard TP.SS 02.16 specifies acceptable values for joint resistances which vary with criticality.



Perhaps the greatest risk pertaining to joints is poor installation workmanship. This is known to have caused the majority of joint failures in the past. It is imperative that the inner steel sleeve is centred in an ACSR joint. Severely offset sleeves are known to have caused the 2009 and 2012 failures on the OTA-WKM A and B lines. With support of engineering contractors we have developed a device which can detect offset steel. This is now being used routinely during the resistance testing programme.

Conductor condition

‘Grease holidays’

A programme of grease application for ACSR/GZ began in the mid-1950s, but the application of the grease stayed inconsistent until the late 1970s. Then it became evident that grease could significantly extend core life. Grease holidays refer to conductors that had less grease applied than optimal, and are now experiencing aggressive corrosion and increased likelihood of failure.

Ageing conductor

The ageing of the conductor asset fleet is contributing to deteriorating condition, corrosion and reduction in mechanical strength. This change in condition drives programmes of replacement and refurbishment.

General deterioration is a serious risk for aged equipment as it affects safety as well as system security. There have been a number of conductor drops due to degradation over the last 10 years. Conductor degradation, in its early stages, cannot be readily observed by visual assessment. See subsection 2.2.3 for further details.

Safety

Mechanical failure of conductors invariably results in a conductor drop incident, which can cause a serious public safety hazard: the public are at risk of electrocution and their property at risk of physical damage and fire. The quantum of risk is highly dependent on the local environment at the failure location.



3 OBJECTIVES

Chapter 3 sets out asset management related objectives for the transmission line conductors and insulators. As described in section 1.4, these objectives have been aligned with our corporate management objectives, and higher-level asset management objectives and targets as set out in the Asset Management Strategy.

Our overarching vision for the conductor and insulator fleets is to enable safe and reliable transmission and provide secure distribution of electricity. Specific objectives have been defined in the following five areas:

Safety

Service performance

Cost performance

New Zealand communities

Asset management capability.

These objectives are set out below, while the strategies to achieve them are discussed in chapter 4.

Safety 3.1

We are committed to becoming a leader in safety by achieving injury-free workplaces for our employees and to mitigating risks to the general public. Safety is a fundamental organisational value and we consider that all incidents are preventable.

Safety Objectives for Conductor and Insulator Fleets

- Zero conductor drops over spans with very high and high safety criticality

- Reduce the overall number of conductor drops (due to conductor breakage, joint failure or insulator or hardware failure) to below 1.5 each year. The 2003/04–2012/13 average was 2.8 each year.

Recognising the reduced level of control we have in relation to public safety, we will take all practicable steps to ensure transmission line assets do not present a risk of serious harm to any member of the public or significant damage to property.

Service Performance 3.2

Ensuring appropriate levels of network performance is a key underlying objective. We have specified network performance for the Grid in terms of Grid Performance (reliability) and Asset Performance (availability) in the Asset Management Strategy.

Grid performance objectives state that a set of measures are to be met for Grid Exit Points (GXPs) based on the criticality of the connected load. In addition, asset performance objectives linked to system availability have been defined. These high-level objectives are supported by a number of fleet specific objectives, and we will work towards these being formally linked in the future.



Service Performance Objectives for the Conductor and Insulator Fleets

- Average annual forced and fault outage rate (expressed in events for each 100 km each year) less than 0.5 for 110 kV lines and 0.15 for 220 kV lines over RCP2.8

Cost Performance 3.3

Effective asset management requires optimising lifecycle asset costs while managing risks and maintaining performance. We are committed to implementing systems and decision-making processes that allow us to effectively manage the lifecycle costs of our assets.

Cost Performance Objectives for the Conductor and Insulator Fleets

- Achieve improved efficiency through extension of the planning horizon.

- Design, construct, and maintain conductor and insulator systems to minimise lifecycle costs, while meeting required levels of performance.

- Minimise cost of capital projects through long-term third party resource planning.

- Minimise cost of works by packaging work into blocks of consecutive spans wherever possible.

New Zealand Communities 3.4

Asset management activities associated with the conductor and insulator fleets have the potential to impact on both the environment and on the day-to-day lives of various stakeholders. Relationships with landowners and communities are of great importance to us and we are committed to using asset management approaches that protect the natural environment.

New Zealand Communities Objectives for Conductor and Insulator Fleets

- Minimise noise pollution from cracking insulators in sensitive areas.

- No significant environmental damage (such as from forest fires) due to component failure.

- No damage to third party property due to conductor and insulator component failures.

- Minimise stakeholder disruption by packaging work into blocks of consecutive spans wherever possible.

- Maintain effective relationship with stakeholders affected by conductor and insulator works.

8 This includes outages due to structure and foundation failures.



Asset Management Capability 3.5

We aim to be recognised as a leading asset management company. To achieve this we have set out a number of maturity and capability related objectives. These objectives have been grouped under a number of processes and disciplines that include:

Risk Management

Asset Knowledge

Training and Competency

Continual Improvement and Innovation.

The rest of this section discusses objectives in these areas relevant to the conductor and insulator fleets.

Risk Management 3.5.1

Understanding and managing asset-related risk is essential to successful asset management. We currently use asset criticality and asset health as a proxy for a fully modelled asset risk approach.

Asset criticality is a key element of many asset management systems. We are currently at an early stage of developing and implementing the framework as we work towards formal and consistent integration of asset criticality into the asset management system. We have commenced this by prioritising fleet replacement expenditure programmes, based on the model outputs.

Risk Management Objectives for Conductor and Insulator Fleets

- Finalise and implement the safety and network criticality categorisation systems for conductor and insulator applications.

- Develop an integrated asset health model for conductor assets.

- Continuously improve the asset health modelling of insulator assets.

- Formalise and implement an asset management approach that is differentiated by network and safety criticality.

- Develop a risk-based model for assessing the trade-offs between different work methods (such as live line techniques), including the risk-weighted cost of circuit unavailability (that is, the cost of outage or increased chance of outage due to reduced redundancy).

Asset Knowledge 3.5.2

We are committed to ensuring that our asset knowledge standards are well defined to ensure good asset management decisions. Relevant asset knowledge comes from a variety of sources including experience from assets on the Grid and information from the manufacturers. This asset knowledge must be captured and recorded in such a way that it can be conveniently accessed.



Asset Knowledge Objectives for the Conductor and Insulator Fleets

- Expand knowledge of conductor condition through use of non-destructive and selective destructive testing.

- Improve the condition assessment consistency through improved guidelines (such as photographic examples).

- Enhance the failure and incident records system to improve consistency and usefulness of data, including root cause analysis.

Training and Competency 3.5.3

We are committed to developing and retaining the right mix of talented, competent and motivated staff to improve our asset management capability.

Training and Competency Objectives for the Conductor and Insulator Fleets

- All conductor and insulator works to be carried out by service providers that are suitably qualified and competent for the specific tasks required.

- Sufficient quantity of trained live line maintenance personnel is available.

- Develop and implement a competency improvement plan for conductor jointers.

Continual Improvement and Innovation 3.5.4

Continual improvement and innovation are important aspects of asset management. A large source of continual improvement initiatives will be ongoing learning from our asset management experience.

Continual Improvement and Innovation Objectives for the Conductor and Insulator Fleets

- Continue to monitor new and emerging technologies, including:

variable and dynamic line rating

high temperature conductor.



4 STRATEGIES

Chapter 4 sets out the fleet specific strategies for the management of the conductor and insulator fleet. These strategies provide medium-term to long-term guidance and direction for asset management decisions and will support the achievement of the objectives in chapter 3. The strategies are aligned with our lifecycle strategies below and the chapter has been drafted to be read in conjunction with them.

Planning Lifecycle Strategy

Delivery Lifecycle Strategy

Operations Lifecycle Strategy

Maintenance Lifecycle Strategy

Disposal Lifecycle Strategy

This chapter also discusses personnel and service provider capability related strategies which cover asset knowledge, training and competence.

Scope of strategies

The strategies focus on expenditure that is planned to occur over the RCP2 period (2015/16–2019/20), but also include expenditure from 1 July 2013 to the start of the RCP2 period and some expenditure after the RCP2 period (where relevant). Capex planned for the RCP2 period is covered by the strategies in sections 4.1 and 4.2, and opex is covered by the strategies in sections 4.3 to 4.6. The majority of the capex consists of asset replacements as described in subsection 4.1.3.

Planning 4.1

This subsection describes our strategies for the planning lifecycle of the conductor and insulator fleets.

Planning activities

Planning activities are primarily concerned with identifying the need to make capital investments in the asset fleet. The main types of investment considered for this fleet are replacement, refurbishment and development works.

We support the planning activities through a number of processes, including:

Integrated Works Planning (IWP)

cost estimation.

The planning lifecycle strategies for these processes are described in the subsections below.



Capital investment drivers

Categories of capital investment have specific drivers or triggers that are derived from the state of the overall system or of individual assets. These drivers include demand growth, compliance with Grid reliability standards and failure risk (indicated by asset criticality and health measures).

Specific examples that drive capital investment in conductors and insulators include new line developments or uprating of existing circuits (driven by demand) and replacements for deteriorated or, in rare cases, failed assets. The generalised process map for planning work illustrated in Figure 23 summarises the approach used to identify required capital investments in the conductor fleet.

Conductor CA and Grid Planning

Electrical Loadings

Grid Planning Process

Conductor CA Inspections Process

National Economic Planning

Entire Line Asset Condition

Structure Condition

Foundation Condition

Insulator Condition

Work Planned on this Asset

Asset Performance History

Efficient Work Approval and

Delivery Strategy

Workforce Capacity and Skills

Regulatory Requirements

Contracting Arrangements

Corridor and Landowner

Management Policy

Local Environment

Council Planning

Land Management Strategy

Modern standard asset design

Safe Work

Tower Design

Conductor Type

TP.SS 04.12 Standard Wires

Future grid Needs and Upcoming

Development Projects

Inputs:

Site patrols, Engineering Survey and

Condition Assessment

Council, Landowner and Transmission

Customer Contracts

Grid Development Network Planning

Analysis

Analysis:

Asset Works Planning Meetings

Design and Engineering Investigations

Cost and Economics Analysis

Delivery Planning:

Project Documentation Preparation

Logistics and Deliverability

Asset Works Planning Integration

Regulatory (economic) Approval

Work Delivery Framework:

BC1: Work Initiation

BC2: Investigation Planning

BC3: Work Delivery Approval and Plan

Conductor is degraded

due to annealing,

corrosion, mechanical

wear

Conductor affected by

local environmental

changes

(eg encroachment of

urban development)

Conductor affected by

grid development needs

(reconductoring or line

uprating)

Initial Drivers Work Planning Strategic Direction

NEW WIRESPlanning horizon 5-10 years

Figure 23: Process Map for Planning Capital Investment in Conductors

Enhancement and Development 4.1.1

Enhancement driven projects are undertaken to meet expected growth and to ensure appropriate reliability for customers. Enhancement and development projects principally include new greenfield transmission projects and the uprating of existing lines. Re-conductoring triggered by condition is classified as replacement.9

9 This includes situations where conductors are replaced with standardised modern equivalent assets,

which may have higher ratings.



Build new lines and uprate existing lines where necessary

Build new lines and uprate existing lines to ensure appropriate reliability for

customers is achieved while minimising lifecycle costs.

We follow a comprehensive Grid planning and options analysis methodology to establish optimised transmission solutions. The upgrade planning process outside the scope of this document. For details, refer to the Planning Lifecycle. We have the following major enhancement projects planned for completion prior to the end of RCP2 (2020). These projects have all been subject to individual regulatory approval processes.

Line Name (Section) Type Length Timing

WRK-WKM C – 220 kV New line 80 km 2013–2014

WRK-WKM B –220 kV Removal 40 km 2014–2015

ROX-TWZ A (ROX-CYD) – 220 kV Duplexing 68 km 2013–2014

AVI-LIV A – 220 kV Duplexing 40 km 2015–2016

ROX-ISL A (ROX-LIV) – 220 kV (on hold)10

Duplexing 142 km 2016–2018

AVI-BEN A – 220 kV (on hold)10

Duplexing 36 km 2017–2019

Table 9: Major transmission line enhancement projects

Replacement and Refurbishment 4.1.2

This subsection describes replacement and refurbishment strategies for the conductor and insulator fleets. Replacement is expenditure to replace substantially all of an asset. Refurbishment is expenditure on an asset that creates a material extension to the end of life of the asset. It does not improve its attributes. This is distinct from maintenance work, which is carried out to ensure that an asset is able to perform its designated function for its normal life expectancy.

Condition driven projects

Replacement and refurbishment of conductor and insulator assets are primarily triggered by asset health data which forecasts remaining life and reflecting asset condition. Specific interventions have been defined for conductor and insulator assets based on their condition and informed by their relative criticality. As discussed in subsection 2.2.3, the condition scores are on a scale from 0 to 100 where 100 is new. When a score of 20 is reached it is generally considered necessary to replace or refurbish the asset.

Our approach is consistent with those used by peer utilities. The investment criteria have been defined to support the objectives discussed in chapter 3 and have been selected to achieve the optimum time to refurbish or replace the asset.

10

The duplexing of the ROX-LIV section of the ROX-ISL A line, and the duplexing of the AVI-BEN A Line are both part of the Clutha – Upper Waitaki Lines Programme (CUWLP) approved by the Electricity Commission in August 2010. In November 2011, action on these two sections was put on hold because generation growth in the lower South Island had not occurred as forecast. A review of the status of these projects was scheduled for 2013; and this review is currently underway.



Replace degraded conductors

Replace conductors when condition assessment shows a significant

proportion of spans have sections at end of life due to loss of strength or

cross-sectional area, and the cost of maintaining such defects and the risk of

failure have become unacceptably high.

Conductor replacements are based on condition. As outlined in subsection 2.2.3, homogeneous conductors are deemed to reach replacement criteria at 15% loss of either strength or section loss for AAAC and 10% for copper. For ACSR conductors, the replacement criteria is set at 20% loss of tensile strength and 15% section loss. These values are generally in line with those used by other international utilities.

Conductor corrosion and fretting tends to occur on the inside of the conductor. This means that early detection by ground and structure based visual survey is essentially impossible. To ensure that adequate condition data is available, we now use a combination of techniques including: age based predictive modelling, close aerial inspections, Cormon (eddy current) testing of sample spans, and analysis of samples removed from spans. These methods are discussed in detail in subsection 2.2.3.

Defects, such as corrosion bulges, can be repaired by cutting out the defect and installing a new length of conductor, typically around 10m in length but occasionally much longer. The complexity and cost of such repairs can vary considerably depending on the location of the span. However, when numerous defects start to appear, aside from the increasing costs, the risk of not detecting defects, and so the risk of failure, increases. At this stage, the frequency and scope of Cormon and close aerial inspections are increased to help mitigate failure risk while managing the conductor through to replacement.

There is potential for further life extension where electrical and mechanical loads are assessed as low. This principle has been successfully applied on a number of occasions and will continue to be applied where appropriate. Table 10 summarises lines with conductors that have degraded to a point where replacement is planned prior to mid-2020.

Line Name (Section), Type Total Length (Circuit km)

Timing

BPE-HAY A (full), 1cct 220 kV11

118 km 2015–2020

BPE-HAY B (full), 1cct 220 kV 118 km 2015–2020

NPL-SFD A (6-21), 2cct 220 kV 12.8 km 2015–2016

OTB-HAY A (45A-68), 2 poles 350 kV DC 9.5 line km 2017–2018

CPK-WIL B (full), 2cct 110 kV (last spans at CPK end are 3 cct)

24.8 km 2017–2019

BPE-WIL A (JFD-WIL section), 2cct 220 kV 56 km 2018–2020

BRK-SFD B Line, 1cct 220 kV 97 km 2019–2022

BPE-WIL A (BPE-JFD section)12

244 km RCP3

Table 10: Major Re-conductoring projects planned for RCP2

Each of these lines has already had corrosion bulges cut from them which were at or below replacement criteria. Inevitably, more will appear in subsequent years. Managing conductor by relying on close aerial inspections to see white powder and bulging has inherent risk.

11

Re-conductoring of the BPE-HAY A and B lines is being submitted as major capex. 12

Investigation and design costs only. Replacement is planned for RCP3 period.



Metallurgical consultants have concluded that in severe marine environments (in which all of the above lines are located) conductors may not remain serviceable 3 to 5 years after visible bulges occur. Cormon testing has shown each to have multiple locations where the galvanised coating on the core wire has completely gone, leading to galvanic corrosion of the aluminium strands. Such corrosion leads to section loss, white power bulging and often internal broken strands.

Detailed conductor condition reports have been prepared for each of the above line sections. These reports bring together all sources of condition data, address the loss of mechanical and electrical capacity, and investigate circuit electrical loads, maximum tensions and the risks associated with continued operation. They then recommend a replacement need date.

See subsection 4.1.4 for details on how costs have been estimated for these major re-conductoring works.

Over the RCP2 period, we plan to replace approximately 450 circuit kms at a cost of $134.2m.13 We are proposing that five large conductoring projects with a total expenditure forecast of $117.8m be removed from base capex and submitted for separate approval. This leaves $16.4m under this strategy. Capitalised investigation costs for the five large projects will be retained in base capex, to allow further refinement of cost and scope prior to submission.

Replace degraded earthwires

Replace earthwires when condition assessments show that replacement

criteria have been met.

A total of 330 km of earthwire on 19 lines are programmed for replacement between 2015 and 2020 due to corrosion of the wires. This work has an estimated cost of $8.25m. Because earthwire replacement is more straightforward than for conductors, costs for this work are estimated using volumetric cost estimation (see subsection 4.1.4).

Replace at-risk copper conductors in critical spans

Investigate all copper conductors strung over high and very high safety critical

areas, and replace those assessed as having a positive cost benefit for doing

so.

The physical reliability of the copper conductors is poor by comparison with ACSR and other modern conductors. The ratio of copper to ACSR related failures (excluding jointing failures) exceeds 10 to 1, even though copper conductors now make up only 9% of the total conductor population. The relatively small copper conductors are more likely to fail than a modern conductor, particularly when loaded with snow, when hit by lightning or following some other flashover event.

We have recently completed a policy document pertaining to copper conductor replacement (TP.GL 03.02). Spans strung with copper will be assessed and programmed for replacement where the impact of a conductor failure on the system, customers, public safety or on

13

This excludes expenditure associated with re-conductoring 236 circuit km on the BPE-HAY A and B lines, as this is being covered under the major capex work stream.



landowners is such that it is desirable and cost effective to reduce the risk. To qualify for conductor replacement, such line sections will have been analysed for the degree of inherent risk for maintaining the status quo verses the projected cost benefit for replacement.

The volumes and costs associated with this strategy have not yet been established. The initial strategy is to complete the assessments by the end of 2015 and programme any replacements to occur after that. There are some 2,000 circuit km of copper, with 2% over very high and high safety criticality areas. If 50% of these require replacement, this equates to some 20 circuit km of line. If replaced over a 5-year period, this equates to 4 km each year.

This strategy will lead to improved safety and reliability through reduced likelihood of conductor drops.

Provide inter-phase spacers and fit dampers

Provide inter-phase spacers on vulnerable spans where justified on a risk

basis.

Operating experience has shown that some transmission lines are vulnerable to conductor clashing in severe climatic conditions, causing damage to the conductors, and creating a power system fault that may lead to significant interruptions to customers. Inter-phase spacers can be effective in preventing conductor clashing.

Our strategy is to provide inter-phase spacers on vulnerable spans where the costs are justified by the benefits, taking into account the network consequences of conductor clashing.

During RCP2, new inter-phase spacers will be installed on WRK-WHI A at a cost of approximately $2m. New dampers will be installed on LCH-KIN B at a cost of approximately $100,000.

Replace degraded insulators and hardware

Replace insulators and hardware when they have degraded to the point

where they can no longer reliably carry their design loads or their electrical

performance has become unreliable.

Based on the condition assessment programme, the following replacement criteria have been developed for insulators and hardware.

Porcelain or glass disc replacement criteria

Punctured, cracked or otherwise electrically unsound or defective.

Corroded metal parts when the critical pin diameter has been reduced to 0.84 of its original diameter anywhere on the circumference.

Strings frozen together by rust.

Heavy contamination that is severe enough to degrade its electrical performance.

Porcelain post insulator replacement criteria

Electrical flashover damage.



Severely corroded, cracked, distorted or worn metal fittings.

Broken, chipped or badly chipped porcelain.

Corroded or worn metal parts which have reduced the critical load bearing area by 30% or more from its original.

Composite insulator replacement criteria

Electrical flashover damage.

Damage to the polymer housing.

Severe corona erosion near the end fittings.

Severely corroded or worn metal end fittings.

Damaged sheds which effect overall electrical performance of the insulator.

Puncturing of the core rod sheath.

Corroded or worn metal parts that have reduced the critical load bearing area by 30% or more from its original.

Heavy contamination that is severe enough to degrade its electrical performance.

Insulator fitting replacement criterion

When the component has experienced a reduction in strength equivalent to a strength factor (load/capacity) of 0.9 for cast hardware and 1.0 for forged or fabricated hardware on site-specific ultimate loads, it requires replacement.

In New Zealand, porcelain and glass insulators generally require replacement due to corrosion of the steel pins. Because of their relatively young age, few composite insulators have required replacement to date. Those that have been replaced to date generally had degraded silicone or EPDM sheaths. Corrosion of the single pin at the hot end of a composite can also drive replacements.

The replacement criterion for corroded pins, which drives most replacements, is a reduction in diameter to 84% of original. This equates to a 30% loss of area: pin strength is reduced to 70% of a new pin. Pin strength tends to govern the overall disc strength (the Specified Mechanical Load, or SML), so reducing pin area to 70% has the effect of reducing the insulators specified strength by the same amount. Seventy per cent of SML is commonly used as the limit for damage in-line design scenarios, such as is noted in International Standard IEC 60826.

Insulators which reach replacement criteria should be replaced within one year of being identified. However, rather than waiting for each insulator to reach the exact replacement criteria before replacing it, it is generally more cost effective and less disruptive to landowners if several consecutive structures are re-insulated at one time. We will therefore strive to package works into consecutive structure groups, replacing insulators on, or close to replacement criteria (typically within 10 CA points). It should be noted that insulators on adjacent structures generally are in similar condition.

We will always replace insulators for all three phases at one time, and avoid replacing individual strings.

This strategy aligns with the objective of minimising lifecycle costs.



Insulator replacement volumes

The insulator replacement model predicts current and future insulator condition. It assumes the following for the two broad insulator categories:

Glass and Porcelain: degradation by corrosion zone (as shown in Figure 14); degrading to CA 20 from most recently recorded condition assessment

Composite: linear degradation from installed date to end of life, derived from life expectancy in subsection 2.2.3.

The age of the composite fleet is well recorded because they have only been used since the 1990s. The reason for not using CA is that visually assessing composites is difficult, and the data recorded to date for composites is not mature so will not be a good indicator of remaining life.

Predictive modelling indicates that the minimum level of insulator replacement required to replace only those sets reaching CA 20 is over 1,000 sets a year until 2019, trending upwards after that date.

In addition to these, over the RCP2 period, it is estimated that some 150 circuit sets each year will be replaced up to five years early by following the approach of re-insulating in consecutive blocks of structures rather than purely when CA 20 is reached. A further 300 circuit sets each year will require re-insulating during pole and attachment point replacements when the existing insulators have CA above 20 but below 60. (Note: 200 pole replacements and 520 attachment points are planned for replacement annually over the RCP2 period.)

Figure 24 sets out the approximate annual insulator circuit set replacement volume predicted for insulator and insulator hardware replacements until 2019/20.

Figure 24: Insulators – Replacement Quantity14

14

These quantities are derived during the asset health modelling and are calculated from the approved works budget. Works prioritisation is based on the prioritisation matrix discussed in subsection 2.2.4. Modelled quantities may differ from planned deliverables as the mix of planned works will be slightly different from the plan. We are still at a relatively early stage in the development and application of the insulator replacement model, and will continue to refine and develop this throughout RCP2.

0

200

400

600

800

1,000

1,200

1,400

1,600

2013/14 2014/15 2015/16 2016/17 2017/18 2018/19 2019/20

REPLACEMENT QTY RCP2 AVERAGE

INSULATORS - REPLACEMENT QUANTITY



Over the RCP2 period, insulator replacements are planned for 3,900 insulators circuit sets at or below 110 kV, and 3,200 at or above 220 kV.

The effect of the replacement plan on the asset health profile of the insulator fleet is shown in Figure 25. It should be noted that this represents an ideal result. Deliverability constraints and needs for scale efficiency may lead to insulators being addressed in a ‘lumpier’ manner than is modelled. The effect of the replacement plan is contrasted with the effect of doing ‘nothing, and letting the fleet degrade without replacements.

Figure 25: Insulator Asset Health - End RCP2

Costs

Table 10 summarises the costs used in the insulator replacement modelling.

Insulator Type Cost $

≤110 kV, Strain and Suspension/cct 4,000

220 kV and 350 kV DC, Strain and Suspension/cct 6,500

Table 11: Insulator Modelled Replacement Cost

The costs above were derived from weighted averages. For 220 kV and above, 1 in 8 structures are strains, with strain replacements costing $10,000 and suspensions costing $6,000. For 110 kV and below, 1 in 5 structures are strains, with strain replacements costing $6,000 and suspensions costing $3,500.

Cost and scope estimation for insulator replacement works is an example of volumetric forecasting (see Planning Lifecycle and subsection 4.1.4 for further details). Through RCP2, the average annual number of replacements each year is 1,420 circuit sets, at an average cost of $7.2m. The total cost of this programme through RCP2 is $36m.

12+ YRS (74%)

7-12 YRS (22%)

2-7 YRS (4%)

0-2 YRS (0%)

NOW DUE (0%)

INSULATORS - ASSET HEALTH (19/20 - PLAN)

12+ YRS (60%)

7-12 YRS (19%)

2-7 YRS (10%)

0-2 YRS (3%)

NOW DUE (7%)

INSULATORS - ASSET HEALTH (19/20 - DO NOTHING)



Figure 26 sets out the approximate annual insulator circuit set replacement costs predicted for insulator and insulator hardware replacements until 2019/20.

Figure 26: Insulators – Replacement Cost

Under-clearance span management

Prioritise known under-clearance spans for mitigation using a risk-based

approach. Carry out works for all spans assessed as requiring mitigation by

2020.

In 2002 we started a process of surveying and modelling all existing transmission lines. As of 2012, some 93% of all spans have been surveyed and modelled for clearance requirements stated in NZECP34: 2001. While compliance with NZECP34 clearances is not mandatory for existing lines, compliance is deemed to provide electrically safe distances.

We have developed a risk-based model for under-clearance spans that calculates the probability of flashing over to a person, vehicle or other object, considering the minimum actual clearance and the likely number of risk exposure events each year (such as how often is someone likely to drive a four-wheel drive vehicle on a rugged hillside directly under the low point of the span). This allows ranking of the under-clearance spans based on risk. The model is intentionally conservative, as it assumes the conductor is continuously at maximum operating temperature, or, in other cases, at maximum blowout.

Spans with a flashover probability of greater than 10-4 each year at maximum sag are considered as requiring mitigation. Approximately 560 spans have been identified in this category. Mitigations can vary widely. Possible rectifications include:

raising the tower, either by inserting a body extension or moving onto a new taller foundation

replacing the tower with a taller tower

replacing an existing pole with a taller pole

converting the insulation arrangement (from suspension to strain, or to akimbo)

reshaping the ground

re-tensioning the conductor

0

$1m

$2m

$3m

$4m

$5m

$6m

$7m

$8m

2013/14 2014/15 2015/16 2016/17 2017/18 2018/19 2019/20

REPLACEMENT COST RCP2 AVERAGE

INSULATORS - ANNUAL COST



removing hanger brackets

removing violating buildings.

All of the above rectifications have been carried out successfully in recent years, generally as part of uprating projects.

Of the 560 sites identified as potentially being at risk, 100 will be mitigated during RCP1. A further 100 are likely to be classified as somewhat lower risk once a more detailed assessment, including site inspection, is carried out.

Over the RCP2 period, we plan to rectify clearance issues at a total estimated cost of $5.8m. Of this total, we plan to replace structures associated with fixing clearance violations at 115 sites at an estimated cost of $3.2m; that is, $28,000 each. These works meet the test for capital expenditure, as they involve the replacement of an asset. Further clearance violation rectification work at 175 sites involves the replacement or refurbishment of components so is therefore expensed and run as a maintenance project at an estimated total cost of $2.7m over RCP2; that is, $15,400 for each site.

Update aerial laser survey data and line models

Keep transmission line aerial laser survey data up to date by periodically re-

surveying lines or sections which have been modified (for example, re-

conductored) or underbuilt (such as in an urban area).

Over the last decade, we have performed aerial laser surveys (ALS) over 93% of our transmission lines. The ALS data has been used to build accurate models of each line. These have proven invaluable in assisting with the management of statutory clearance requirements and for uprating investigations.

In the two year period 2013 to 2015, a planned project will fly the remainder of the transmission line assets, including any newly commissioned or modified since the last flight in 2010.

Thereafter, during the RCP2 period, flights are planned to be carried out every second year to re-survey lines that have been modified or underbuilt. This will entail the re-survey of 3,000 km of line at a total cost of $6m ($4.2m in the RCP2 period).

This strategy supports our safety and network performance objectives.

Prioritise conductor and insulator works

Prioritise conductor and insulator replacements, taking into account existing

health, asset criticality and degradation rate.

We have developed an integrated risk-based prioritisation approach for tower works. The following factors will be used to prioritise tower works:

AHI

asset criticality (in respect to Grid reliability and safety).

This approach ensures that the risks associated with conductor and insulator works are appropriately factored into prioritisation decision.

Figure 13 shows the prioritisation matrix used for this approach.



Integrated Works Planning 4.1.3

Our capital governance process – IWP – includes the creation of business cases that track capital projects through three approval gates, with the scope and cost estimates becoming more accurate as the project becomes more refined.

The IWP process integrates capex across a moving window of up to 10 years in the future. This optimisation approach seeks to ensure that works are deliverable and undertaken in an efficient and timely manner. Planning of all the conductor and insulator works takes into consideration relevant site strategies, minimises required outages and resources, and identifies potential synergies with other projects.

Uprate lines when replacing conductors

Integrate network development uprating works with condition-based

conductor replacement work.

Conductors are replaced for two reasons: network development (uprating) or when their condition has degraded and reached replacement criteria. Once a conductor has been identified as requiring replacement due to degradation, as part of the planning process, we will first identify if any need exists to upgrade the line. If there is a need, various upgrade options will be investigated. Robust cost benefit analysis techniques are used to select the preferred re-conductoring option. This strategy aligns with our objectives of increasing system reliability and minimising lifecycle costs.

Optimise replacement works

Replace hardware and insulators if their CA is less than 60 when re-

conductoring, or replacing structures, or replacing structure attachment

points.

Having climbed a structure and lifted the weight of conductors, the incremental cost to replace insulators and other hardware is relatively small, as site establishment and lifting costs are already sunk. While it would be inefficient to replace items in near new condition, we have determined that if conductors have been temporarily lifted to undertake other works, then items with less than half their remaining life should be replaced at the same time. This broadly equates to a CA score of 60. This reduces lifecycle cost and landowner disruption, uses the work force in an efficient manner and minimises outage requirements.

In the case of re-conductoring, checks must first be made to verify that the existing insulators have sufficient capacity to carry the new loads, which may increase somewhat depending on tensions and conductor size.

This strategy supports our cost performance and stakeholder objectives.

Cost Estimation 4.1.4

Cost estimation is a key stage of the investment planning process and forms a critical input into projects at various stages in the planning process. Historically, cost estimates for conductors and insulator works were developed using proprietary systems. This has now transitioned to a central cost estimation team, which uses the cost estimation tool Transpower Enterprise Estimation System (TEES).



Estimating conductor and insulator costs is undertaken using two main approaches:

tailored scoping and costing using the customised estimate approach is used for major re-conductoring projects

volumetric based estimates are used for insulation projects and minor re-conductoring.

The cost estimates aim to achieve P50. See the Planning Lifecycle Strategy for further details on our volumetric and customised cost estimation approach.

Major re-conductoring project cost estimation

Use a tailored scoping and costing approach to estimate major re-

conductoring project costs (customised estimate).

Experience has shown that the final cost to re-conductor transmission lines is subject to large variation depending on the context, characteristics and location of each line. This is a significant issue in any cost estimation for projects at the conceptual stage. The application of a simple building block model is considered inappropriate. For example, structure strengths, foundation capacities, and required clearances all need to be reviewed and may need to be amended. There can also be significant cost uncertainties relating to access, particularly in urban and semi-urban environments.

To provide robust cost estimates for major re-conductoring projects, we have applied a detailed process based on its customised estimate approach.

Customised estimate methodology

Due to the lead time before undertaking the projects, the approach used is essentially a ‘top-down’ exercise, based on the detailed review of each line project. This has been undertaken by experienced, specialist estimators leveraging off the costs of current and recent re-conductoring projects (for which costs based on more detailed analysis and design are available). It does not extend to a detailed ‘bottom-up’ estimate based on line-specific detailed designs.

The four main steps involved in the process include:

1. deriving base case costs/km for standard benign (vanilla) line configurations (less material costs)

2. amending the base case estimate to reflect project specific characteristics

3. estimation of material costs

4. statistical risk analysis.

The above steps are undertaken with input from site inspections, maintenance and project managers, engineering, environment, and property teams. They are described in further detail below.

Base case costs

Two base case scenarios have been derived reflecting two applicable line configurations for the envisaged re-conductoring projects. These base cases are:

single circuit, simplex zebra conductor with flat top towers

double circuit, duplex zebra conductor with double circuit towers.



For these base case costs, the location and characteristics of the lines and works are assumed to be benign with a reasonable scale. As part of the base case, 29 project characteristics have been defined. Some of the main characteristics include:

extensive farming land use

easy terrain

reasonable access

normal density of road and distribution crossings

project size 25–50km

no structural or foundation strengthening required.

In a New Zealand context, these conditions can be considered close to ideal.

Tailoring the base case for each project

Having chosen the most relevant base-case, the next step is to undertake a detailed review of each project to adjust the base-case characteristics. This involves considering what project specific issues vary materially from those of the base case. This process included a series of desktop reviews and site inspections to gauge access issues and asset condition. Based on the findings of these investigations, a set of predefined cost adjustment line items or uncertainty ranges were applied. Up to 35 characteristics (including the 29 defined in the generic base case) were subjected to specific review for each line project.

Examples of specific cost adjustment line items include the presence of the following conditions:

high-voltage line crossings

motorway or railway crossings

complex substation terminations.

Examples of circumstances or characteristics that are addressed through the application of uncertainty ranges to existing cost items include:

rugged terrain, and difficult access

urban land-use

condition of existing conductor and hardware

average span length

remoteness

outage restrictions

size of project.

Line items impacted by the above factors were adjusted by applying upper and lower risk ranges to deal with the uncertainties caused by the issues.

Estimating material costs

The material costs of like-for-like re-conductoring projects can be estimated to a reasonable degree of accuracy as the quantities are well defined.



The major variables are in the component costs themselves, much of which is dictated by metal indices and exchange rate fluctuations. For each material line item, an upper or lower bound of the costs is estimated to deal with the remaining uncertainties, excluding the metal indices and exchange rate fluctuations discussed above.

The base case costs, the project specific adjustments and the material costs are summed to provide an expected P50 cost for the project.

Ensure volumetric works are scoped to achieve P50

Ensure project works are scoped to achieve P50, an estimate of the project

cost based on a 50% probability that the cost will not be exceeded.

With the exception of major re-conductoring projects, most conductor and insulator-related works are reasonably repetitive with largely similar scopes. These are categorised as volumetric works for estimation purposes. The key determinant of accurate cost estimates for volumetric capital projects is the effective feedback of cost out-turns from completed, equivalent historic projects. Volumetric estimates are determined using the TEES (US Cost) system. Tailored ‘building blocks’ have been developed for various works based on out-turn feedback. This feedback-based process is used to derive average unit costs for future works.

The P50 cost value is an estimate of the project cost based on a 50% probability that the cost will not be exceeded. The P50 estimate is one with equal chance of project overruns or under runs up until when the project scope can be finalised. In a general sense, the expected cost of a programme of similar projects is of more interest than the costs of projects separately. Individual project works are considered at the mean of a simulated cost distribution, typically the P50 estimate. Assumptions made in using a volumetric costs methodology to achieve P50 include:

the sample size of historic works is sufficiently large to provide a symmetric distribution for the cost

a large number of equivalent projects will be undertaken in future

cost building blocks based on historic out-turn costs capture the impact of past risks

scope is reasonably well defined and reflects a predetermined list of standard building blocks applied to all estimates.

This strategy supports our cost optimisation objective.

Delivery 4.2

Once the planning activities are completed, capex projects move into the Delivery Lifecycle. Delivery activities undertaken are described in detail in the Delivery Lifecycle Strategy. The following discussion focuses on delivery issues that are specific to the conductors and insulators fleets.



Design 4.2.1

Adopt principles of critical infrastructure design

Ensure design standards take account of asset criticality, balancing project

specific cost optimisation with lifetime performance and resilience to high

impact events.

The transmission line loading standard (TP.DL 12.01) specifies higher return period weather events for critical assets than for less critical ones (that is, a higher reliability level for more critical assets). This is in line with standard international practice. We design lines to ensure clearances are maintained in line with the standard TP.DL 12.02. Again, this standard is closely aligned to those used by international utilities. This ensures the safety of workers and the public as well as acceptable system performance.

Design and procurement standards

Maintain modern internationally aligned design and procurement standards.

We will continue to develop and maintain a suite of internationally aligned design and procurement standards to ensure industry best practice.

Minimise fleet diversity

Minimise, as far as practical, the diversity of conductor and insulator types

and fittings used in new and replacement construction.

We will continue to maintain a list of pre-approved conductors from which all new conductors must be selected. The same applies for insulators and hardware. Minimising fleet diversity supports cost optimisation by reducing costs associated with design, procurement, installation, maintenance and spares.

Conductor selection

Select conductors, balancing project specific cost optimisation with lifetime

performance.

Any significant conductoring project, whether it is a new build or re-conductoring, must undergo a rigorous conductor selection process. The objective is to balance project cost with lifetime performance to deliver a cost-optimised solution. We will carry out cost benefit analyses to select the conductor with the lowest lifecycle cost.

Numerous factors must be considered in this process, including existing and future network requirements, conductor losses, existing land use rights, easement requirements, visual impacts, structure and foundation capacities (new or existing), structure height requirements and corrosiveness of the environment. The process is often complex with numerous options requiring consideration, both in terms of conductor type and various maximum operating temperatures for each. Conductor selection guidelines are included in TP.SS 04.12.



It is expected that the AAAC will last longer than the ACSR conductors because the homogeneous AAAC will not suffer from dissimilar metal corrosion. Further investigation is required to ascertain how much longer it may last in various environments throughout New Zealand, but the possibility of longer life should be considered during the conductor selection cost benefit process.

Insulator selection

Install composite insulators in areas with extreme and very high

contamination and in sensitive areas where audible noise is an issue. Install

glass cap and pin insulators in all other areas.

Glass discs are the default insulator on the network and will be installed in all locations except in highly corrosive environments or where audible noise is an issue, where composite insulators will be installed.

The difference between installed costs for composite, porcelain and glass insulators is less than 5%. Composite insulators provide better contamination performance and reduced audible noise compared to cap and pin insulators. Installations of composites in polluted environments, such as Oteranga Bay, have proven particularly successful, significantly reducing the incidence of pollution related trips. They have also been successfully installed in areas where audible noise complaints have been received for the cap and pin strings. Yet they are subject to cracking and their condition is far more difficult to assess than glass. The longevity of composite insulators in the New Zealand environment is still unknown, as the first of these was only installed on the network in the early 1990s.

Glass insulators are preferred over porcelain as defects are easier to detect. Defective glass discs shatter while porcelain may simply crack or puncture, making them unreliable and potentially dangerous to linemen. A broken porcelain disc can fail mechanically during a fault, dropping a conductor, whereas a broken glass disc will not. Glass discs are also relatively easy to condition assess as their dominant failure mechanism is from corrosion of the steel fittings. For composites and porcelain, close visual inspections augmented by voltage testing are required. For these reasons, glass insulators are still preferred in all but very high contamination environments.

Procurement 4.2.2

For more details of our general approach to procurement, see The Sourcing, Supply & Contracts Approach (2011) and the Delivery Lifecycle Strategy.

Procurement issues relevant to the conductor and insulator fleets are described below.

Full grease coverage

Ensure the conductor manufacturing process delivers full grease coverage to

avoid untimely early replacement due to grease holiday defects.

‘Grease holidays’, patches of ACSR core wire with no grease applied, have caused significant life reduction to numerous conductors on the network. It is vital that the procurement programme ensures the quality control of conductor grease application.



Delivery Planning 4.2.3

The plan for delivering new conductors and insulators for new transmission lines and upgraded transmission lines are managed under the ‘Grid Works Planning’ process. This subsection sets out how the Grid Works Planning process is applied to these works.

Project deliverability

Ensure planned projects are deliverable within available financial, labour and

material constraints.

Our IWP processes deliver on this strategy. In particular, ensuring deliverability of projects planned in line with the IWP processes is essential to support our objectives of controlling costs and achieving the desired asset management outcomes.

Work packaging

Package work into blocks of consecutive structures/spans wherever possible

to maximise efficiency and minimise outages and landowner disruption.

Where practicable, package work to ensure that any system outages are minimised. A holistic view is taken rather than evaluating the sum of the individual works. This strategy aligns with our network performance and stakeholder objectives.

Operations 4.3

The Operations Lifecycle phase for asset management relates to planning and real-time functions. Operational activities undertaken are described in detail in the Operations Lifecycle Strategy. The following discussion focuses on operational issues that are specific to the conductors and insulators fleets.

Outage Planning 4.3.1

Power system outages for preventive maintenance, corrective maintenance and replacements must be planned meticulously to minimise disruption to customers. A number of procedures carried out on conductors and insulators for preventive maintenance, corrective maintenance, and replacements cannot be carried out as live line work. This means that an outage must be planned and managed in a way that creates a safe environment for employees and contractors to undertake the work, while minimising the disruption for customers. Grid Operations identifies requirements for outages (including reclose blocks) and manages the planning of outages and reclose blocks.

Conductor and insulator works outage planning

Meticulously plan conductor and insulator works that require outages, to

minimise disruption to customers.

We coordinate with key stakeholders to ensure that any unavoidable system disruptions and outages are notified well in advance so that affected parties can prepare. This strategy aligns with our system performance and reliability objectives.



Contingency Planning 4.3.2

With approximately 65,000 km of phase conductor and approximately 210,000 insulator strings on the network located in many different conditions, it is inevitable that conductors and insulators will occasionally fail during extreme events such as high winds, earthquakes, volcanic eruptions, and landslides. Planning for such events is therefore essential so that in the event of an operational failure, overhead transmission lines can be restored relatively readily.

To ensure rapid restoration times, we will employ the following contingency strategies.

Contingency preparedness

Ensure there are sufficient plans, skilled manpower and emergency spares to enable rapid restoration of transmission service following single or multiple structure failure(s) or conductor drop(s).

Resources must be sufficient to manage contingencies using a tiered response where local service providers rectify failures of one or two structures, but may call upon others for assistance following multiple structure or span failures. We will ensure asset specific emergency plans are developed for critical assets.

Emergency Restoration Team and Spares: Maintain readiness of emergency restoration team and structures – ability to temporarily restore a localised failure (up to 5 towers or 2 km) of any one line (double or single circuit) within 10 days where physical Grid redundancy is not available.

Emergency Management Team: Maintain readiness of emergency management team – communications routes to Civil Defence and to site works contractors. Yearly drill for significant outage communications and process. Continue the business continuity plan, including emergency restoration structures.

This strategy supports our network performance objectives.

Corridor Management 4.3.3

We engage closely with stakeholders in relation to corridor management. Material provided to landowners and occupiers of land impacted by line corridors includes brochures15 and advisories on our activities. The brochures together with regular maintenance visits assist in identifying asset related and third party risks. This is considered the most cost-effective means of ensuring that developers are aware of safety requirements before committing to detailed design.

The public education process also includes liaison with:

local authorities

building and rural contractors

(improving relationships with) landowner/occupiers.

It is anticipated that these actions will reduce the number of disputes with landowners and occupiers when negotiating access for conductor and insulator related works.

15

Brochures include a General Corridor Management Brochure, a Corridor Management Activity Lists Brochure, a Development Guide and Tree Management brochures.



Establish Council regulated buffer distances

Seek provisions in council plans to ensure that appropriate buffer distances

are provided from existing transmission assets for third party activities.

This strategy will ensure adequate corridors are maintained to allow safe operation and maintenance of the Grid. This supports our network performance and stakeholder objectives.

Maintenance 4.4

We and our service providers carry out ongoing works to maintain assets in an appropriate condition and to ensure that they operate as required. Our approach to maintenance and the activities we undertake are described in detail in the Maintenance Lifecycle Strategy. We class maintenance tasks into the following categories:

preventive maintenance

- line patrols and condition assessments

- servicing

corrective maintenance

- fault response

- repairs

maintenance projects.

These activities and associated strategies are discussed in the following sections.

Maintenance Approach

Live Line Work

Carry out line work live, using live line techniques, where practicable and cost

effective and subject to the work being able to be carried out safely.

The following benefits are achieved through live work:

enhanced plant and line availability

reduced need for outages that would otherwise impact on system security or would have resulted in outages

assistance in avoiding the need for asset enhancements;

improved safety behaviour

a more highly skilled work force.

While initially it may be considered that de-energised work is safer than live line, this has not proven to be the case. This is due to the high level of controls applied in live line work to mitigate the hazard of the livened line.



Preventive Maintenance 4.4.1

Preventive maintenance is work undertaken on a scheduled basis to ensure the continued safety and integrity of assets and to compile condition information for subsequent analysis and planning. Preventive maintenance is generally our most regular asset intervention, so it is important in terms of providing feedback of information into the overall asset management system. Being the most common physical interaction with assets, it is also a potential source of safety incidents and human error. The main activities undertaken are listed below.

Inspections: non-intrusive checks to confirm safety and integrity of assets, assess fitness for service, and identify follow up work.

Condition Assessments: activities performed to monitor asset condition or predict the remaining life of the asset.

Servicing: routine tasks performed on the asset to ensure asset condition is maintained at an acceptable level.

For the conductor and insulator fleets, the largest component of preventive maintenance is condition assessment, as little servicing is required, mostly because there are no moving parts. Condition assessments are very important because of their role in planning replacement and refurbishment to prevent outages and conductor drops.

We intend to implement the following preventive maintenance on the conductor and insulator fleets in support of our objectives stated in chapter 3.

Perform regular line patrols

Carry out regular line patrols to allow the planning of work required to

mitigate or avoid any failure risks.

Line patrols are generally performed once a year on every transmission line asset. The frequency of patrols will be determined based on site or corridor safety criticality. A ground based patrol visits each structure and span to identify any defects that could pose risk to the lines integrity. When significant defects are identified, a maintenance job is raised to rectify the issue (refer repairs below).

Perform condition assessments

Carry out regular detailed condition assessments for conductors, insulators

and associated hardware.

The condition assessment programme monitors and records the condition of transmission line structures, foundations, conductors and hardware. The assessment produces a CA score for various components and a defect list. It applies a consistent approach to assessment of line components and allows extrapolation of the assessed condition into the future.

Condition assessment is carried out in line with TP.SS 02.17C Transmission line condition assessment Part C: Insulators and Conductors. Some examples of the assessment guidelines are contained in Appendix A.

Inspections are generally visual, but are augmented with corona and voltage testing on suspect insulator strings. Special techniques are used to assess conductor condition when it approaches end of life.



Regular condition assessments give a good indication of the condition of individual assets and the asset fleet as a whole, enabling the optimisation of maintenance and replacement works.

Risk-based condition assessment frequencies

Vary the frequency of condition assessments based on asset condition and

criticality.

The frequency of condition assessment visits is varied based on the structure/span criticality and health. New assets will first be assessed prior to the end of any defect liability period. Thereafter, each tower and associated span is to be condition assessed every 8 years, and each pole structure and span every 6 years. Assessments are performed more frequently, (generally 4 years for tower structures and 3 years for pole structures) if the span or structure have a CA score less than 50. Structures and spans located in unusually aggressive environments, or deemed to be highly critical, either to the Grid or for safety reasons, are assessed more frequently.

We plan to use Reliability-Centred Maintenance (RCM) to further develop advanced maintenance plans and procedures. RCM will allow us to consider risks and costs associated with various maintenance regimes before selecting the optimal approach. This may influence the frequency of patrols.

Insulator washing

Wash insulators when pollution causes poor electrical performance on

otherwise sound insulators.

Insulator washing will only be required in a few severely polluted areas, and is consequently a minor maintenance cost. This is largely due to the relatively high rainfall experienced over most of New Zealand, which provides natural washing. Generally, insulators reach replacement criteria before washing is required.

Vegetation management

Continue to manage vegetation to meet statutory and public safety

requirements, and ensure that the security of the transmission system is not

compromised.

Vegetation management includes the removal of vegetation that is at risk of breaching statutory minimum clearances from live conductors. Vegetation management beneath transmission lines is a significant issue and currently accounts for a significant proportion of preventive maintenance spend. Vegetation has the potential to cause circuit trippings and, in extreme cases, conductor drops. Ensuring vegetation is maintained at adequate distances around transmission lines supports our network performance objective. For further details, see the Maintenance Lifecycle Strategy.

Corrective Maintenance 4.4.2

Corrective maintenance includes unforeseen activities to restore an asset to service, make it safe or secure, prevent imminent failure and address defects. It includes the required follow-



up action, even if this is scheduled some time after the initial need for action is identified. These jobs are identified as a result of a fault or in the course of preventive work such as inspections. Corrective works may be urgent and if not completed for a prolonged period may reduce network reliability.

Corrective maintenance has historically been categorised as repairs and fault (response) activities. Repairs include the correction of defects identified during preventive maintenance and other additional predictive works driven by known model type issues and investigations.16 Timely repairs reduce the risk of failure, improve redundancy and remove system constraints by maximising the availability of assets. Activities include:

Fault restoration: unscheduled work in response to repair a fault in equipment that has safety, environmental or operational implications, including urgent dispatch to collect more information

Repairs: are unforeseen tasks necessary to repair damage, prevent failure or rapid degradation of equipment

Reactive inspections: patrols or inspections used to check for public safety risks or conditions not directly related to the fault in the event of failure.

Fault response

Conductor and insulator failure response

Respond to all failures in a timely manner, as determined by the criticality of

the asset.

We have established a process to determine and model asset criticality based on the criticality of the line. This will be used to prioritise fault response and determine how quickly personnel are required to respond to most efficiently maintain the performance of the network.

This strategy supports our key objectives of reliability, system performance and safety.

Repairs

Repair programmes for conductors and earthwires, delivered as maintenance projects, are discussed in further detail in the following subsection.

Maintenance Projects 4.4.3

As discussed in subsection 2.2.5, maintenance projects consist of relatively high value planned repairs or replacements of components of larger assets. Maintenance projects would not be expected to increase the original design life of the larger assets. Maintenance jobs are typically run as a project where there are operational and financial efficiencies from doing so. The drivers for maintenance projects include asset condition, mitigating safety and environmental risks, and to improve performance.

Over the RCP2 period we intend to implement the following maintenance projects on the conductor and insulator fleets.

16

Where the number of potential repairs is deemed sufficiently high, a Maintenance Project will be instigated to undertake the repairs works.



Manage corroded conductor risks until full conductor replacement

Ensure localised conductor corrosion defects, when identified, are repaired or

removed in a timely fashion, prioritising on risk.

Numerous lines strung with ACSR conductor are known to have minimal or no remaining protective coating on the steel core wire. Corrosion is known to be occurring on these lines, and will accelerate with time. Until the conductors are replaced, we must plan to cut out and repair sections of conductor at replacement criteria. Undertaking localised repairs in this way allows us to optimise the timing of complete conductor replacement projects by deferring the need date.

A number of lines were fitted with dog bone spacers that caused corrosion of the outer aluminium conductor strands. All these spacers have now been removed, but the damaged conductors remain and are prone to corrosion. Dog bone spacer damage is best managed by installing helical preforms over the area, or, where damage is more severe, implosive or compression repair sleeves.

Based on recent experience, it is expected that some 150 repairs will be required annually throughout RCP2, at a cost of $750,000 each year ($5,000 for each repair).

Monitor conductor health and risk

Implement a conductor health and criticality assessment process to prioritise

conductor sections for replacement five years ahead of need date. As

conductors approach end of life, supplement visual condition assessment

with more advanced assessment techniques.

Early detection of corrosion by ground-based visual survey is difficult, so a very careful and detailed programme of testing and investigation is required. The advanced conductor condition assessment techniques currently used are discussed in subsection 2.2.5. Some of our testing and investigation strategies are noted below.

Line patrols, fault recording and regular visual condition assessment.

Enhanced visual ground/tower based condition assessment by the use of close aerial inspections and by using the Cormon conductor tester (or similar). Conduct laboratory testing of samples where Cormon or visual inspections show reason for further investigation.

Predictive models to prioritise lines for enhanced condition assessment. The aim is to start some Cormon inspections 10 years prior to expected end of life. Continually update the predictive model. Re-assign lines to different corrosion zones as appropriate, or modify degradation rates for various zones if corroborated by on-site observations.

For sites where grease holiday issues are identified, special assessments will be carried out to identify if it is acceptable to extend the conductor system life by replacement of short sections of line, or if a larger project is required to replace the entire circuit.

Asset-specific ‘Conductor Condition Reports’ will address the loss of mechanical and electrical capacity, circuit electrical loads, maximum tensions and the risks associated with continued operation. Solutions will be optimised to take account of risk and lifecycle cost.



We plan to Cormon test approximately 165 spans annually over the RCP2 period at an estimated cost of $660,000 each year ($4,000/span). In addition, 400 spans will be close aerial surveyed each year at an estimated cost of $160,000 each year ($400/span). Given the high level of confidence in Cormon data, only five conductor samples and analysis each year are likely to be required, at an estimated cost of $50,000 ($10,000 each).

Based on recent experience, it is expected that an additional $300,000 will be required annually throughout RCP2 to cover the management of the conductor testing and monitoring programme.

Joint monitoring and testing is combined with conductor monitoring and testing as the work is complementary. This programme of work totals $1m annually over RCP2 and is discussed in more detail in the following strategy for joints.

The total cost for this programme over the RCP2 is therefore $10.8m.

Resistance test joints and address those found to be defective

Progressively resistance test all conductor joints on spans classified with high

or medium network criticality, or very high or high safety criticality. Repair or

replace those found to be defective.

Our current strategy is to resistance test all conductor joints on spans classified with high or medium network criticality, or very high or high safety criticality. Approximately 50% of spans fall into one of these categories. Joints will also be tested for offset steel when resistance measurements indicate an offset may be present. Joints found to be defective will repaired or replaced. If a bolted palm is found to be defective, all palms on that circuit will be refurbished at the structure.

We plan to test 1,900 joints annually through to the end of the RCP2 period. The actual number of joints tested each year will vary depending on the number that fail the test and require replacement. At 1,900 each year, with seven years testing, a further 13,300 joints will be tested, bringing the total to approximately 25,000 joints, or 25% of the population.

To test a joint costs approximately $525/joint (either for a mid-span, or for a dead-end and bolted palm). Joint testing is predominantly completed using live line techniques, minimising impact on system availability. Replacement/refurbishment costs vary markedly depending on conductor type and location in span, but average at $6,000. This applies to either a single mid-span or dead end replacement, or a complete circuit refurbishment at a structure for bolted palms. Assuming the historical failure rates of 1% for mid-span/dead-ends and 20% for bolted palms, it will cost $1.85m each year to test 1,900 joints annually and replace/refurbish those found to be substandard.

The total cost for this programme over the RCP2 is therefore $9.3m. Of this total cost, $4.1m over RCP2 is allocated to joint replacement and refurbishment. The remaining $5.2m is allocated to the testing programme and is combined with the conductor testing programme discussed in the previous strategy.

This strategy supports our safety and network performance objectives.



Replace degraded vibration dampers, spacers and insulator hardware

Replace vibration dampers, spacers and hardware when they have degraded

to the point where they can no longer reliably perform their intended

function, or when postponing replacement will significantly increase

replacement cost.

Over the RCP2 period, we plan to replace spacers on a total of 885 circuit spans at an average annual cost of $1.46m, replace dampers on a total of 2,300 circuit spans at an average annual cost of $990,000, and replace insulator hot end hardware on 120 circuit spans at a total RCP2 cost of $400,000.

The total cost of spacer and damper replacements during RCP2 is forecast to be $12.6m.

Disposal and Divestment 4.5

The disposal and divestment phase includes the process from when planning of disposal of an asset begins through to the point where we no longer own the asset. The approach is set out in detail in the Disposal Lifecycle document. This subsection describes our approach to the disposal of assets within the conductors and insulators fleets.

Disposal 4.5.1

The decommissioning/disposal stage of the life cycle eventuates when conductors are no longer needed. Conductors and insulators may be replaced as described in subsection 4.1.3, but there are important requirements for the disposal phase.

In the case of a failure, we carry out diagnostic inspection and testing to investigate the cause of the failure. This information is fed into the management of the entire conductor and insulator asset fleets.

Follow appropriate decommissioning process

Maintain and follow an appropriate decommissioning process where re-use is

not appropriate.

Requirements for recovery and recycling/disposal work include safe work and site management processes and appropriate probity and environmental responsibility of scrap disposal processes.

Requirements for conductor and/or insulator removal, recovery and recycling/disposal work include:

safe work and site management processes

any requirement for diagnostic inspection of failed insulators or conductors

appropriate site reinstatement processes

appropriate environmental responsibility of scrap disposal and recycling processes.



Recycle materials if feasible

Recycle elements of conductors and insulators, where feasible.

Conductors are always sold as scrap metal. Unfortunately no practical recycling option currently exists for insulators so they are disposed as general waste.

Divestment 4.5.2

Implementation of divestment is primarily the change of ownership, although we must also remain aware of any safety and environmental issues and technical impacts on the Grid, such as a change in constraints and flexibility of Grid operation.

Conductor divestment

Divest conductors (and associated hardware) as part of transmission line

divestments to customers.

We are continuing to transfer a number of assets at the fringes of the existing Grid to our distribution business customers. This process and its justification are described fully in the Disposal and Divestment Lifecycle Strategy.

Table 11 shows the quantity of conductor likely to be transferred to customers between 2013/14 and 2019/20. This includes all divestments that we believe have a 50% or greater likelihood of occurring during the timeframe.

Period 66 kV 110 kV Total (km)

RCP117

222 422 644

RCP2 0 138 138

TOTAL 222 560 782

Table 12: Line Divestments (span km)

The total number of assets to be transferred represents a very small proportion of the total conductor fleet as at June 2013. Lines likely to be divested are all lower-voltage lines.

Asset Management Capability 4.6

We require national Grid assets and equipment to be maintained, tested and operated to high standards of skill, professionalism and safety supported by high-quality asset knowledge and risk management tools. This will ensure satisfactory and safe functioning of the network while minimising whole-of-life costs. To achieve the required quality standards and prevent injury to workers and the general public, the work is to be carried out only by individuals with competencies that are both appropriate and current (see TP.SS 06.20 Minimum Competencies for Line Maintenance, and TP.SS 06.25 Minimum Requirements for Transpower field Work).

17

This excludes historical divestments; in other words, it only includes divestments to be carried out in 2013/14 and 2014/15.



This section describes the specific strategies for obtaining and maintaining capability in managing and handling the conductors and insulators fleets.

The capability strategies are described under three headings:

Asset Knowledge

Risk Management

Training and Competence.

Asset Knowledge 4.6.1

Robust asset knowledge is critical to good decision making for asset management.

Maintain up-to-date asset records

Maintain up-to-date records of all conductors and insulators.

Comprehensive records that cover the original installation of conductors and insulators and any subsequent modifications are vital to enable quality asset management decisions. Data must include details of exactly what is installed, type test reports, design reports, condition data and investigation reports.

While good asset attribute and condition data is available for most sites, some fields are currently incomplete. Data quality and completeness will continually be reviewed and amended as required to ensure a high-quality data set is maintained. The current project to transition to the MAXIMO- based asset management information system will include a review and cleansing of data.

We plan to enhance the failure and incidence records system to improve consistency and usefulness of the data, including root cause analysis.

We also plan to finalise and implement the safety and network criticality categorisation systems for conductor and insulator applications. Related is our goal to develop an integrated asset health model for conductor assets.

To improve condition assessment consistency, improved guidelines will be developed including more photographic examples where relevant.

Investigate conductor deterioration processes

Undertake investigations of conductor deterioration processes to improve

forecasting models.

Forecasting of conductor condition requires an understanding of deterioration processes. Our previous experience provides a sound basis for forecasting. However, investigations of conductor deterioration will lead to improvements in the reliability of forecasts and improve our levels of confidence in outcomes of our asset management strategies.

Specific investigations that we currently have underway, or have planned, include:

understanding the effects of saline intrusion into cracks in the aluminium cladding of steel core wire

testing the effects of thermal cycling on an aged conductor.



Conductor technology developments

Continue to monitor and trial technology developments in conductor and

conductor inspection technology, considering risk and cost-optimising

opportunities.

We will constantly review practices and materials employed both nationally and internationally to ensure modern, cost-effective solutions are being used.

Investigations are currently underway to assess and approve a suitable high temperature conductor for New Zealand conditions. This will consider the somewhat unique risks in New Zealand related to corrosion and the degree of urban encroachment that has occurred beneath transmission lines. A high temperature conductor is more expensive than ACSR or AAAC, but may allow existing transmission lines to be uprated substantially without materially altering a line’s appearance. Costly property rights may therefore be avoided. Tests have been carried out on an ACSS high temperature conductor, but corrosion and vibration performance have proven sub-optimal to date and attention is now shifting to other options.

International developments pertaining to condition assessments and repairs used on-conductor robots or small unmanned aircraft are also showing some promise and will be investigated further for possible application in New Zealand.

Risk Management 4.6.2

Our approach to risk management is central to our asset decision making as we seek to achieve our overall asset management objectives and optimise the timing of major investments.

Knowledge of conductor condition along the length of a line is crucial to the assessment of options for localised repair and replacement compared with the complete replacement of large sections of line. As outlined in subsection 2.2.3, we apply an adaptive condition assessment approach, where the frequency and extent of condition assessment interventions is determined based on the most recent condition assessment and the predicted current state.

Condition-based risk assessment of the conductor typically varies considerably along the length of the line. Our risk management techniques aim to optimise the timing of large-scale conductor replacements by addressing localised deterioration with repairs and minor replacements. This enables deferral of the major investment, but leads to an increasing proportion of the overall line reaching replacement criteria before major replacement of conductor is initiated.

The deferral of major investment in replacement of conductors leads to increasing reliance on the condition assessment process, the condition forecasting model and the risk assessment methodology. Understanding and modelling uncertainty then becomes an increasingly important element in risk management decision making, particularly given the consequences of conductor failure, and the long lead time for major conductor replacement projects.

The risk management process for insulators is more straightforward than for conductors, because the condition can be more readily observed and forecasted. In addition, insulator replacement works can be implemented at short notice, and in an economic manner, even for relatively small scale projects, if this is required to address localised deterioration.



Risk-based options evaluation framework

Develop an improved risk-based framework and associated tools for

evaluation of options for conductors and insulators.

We will develop an improved risk management framework and tools that can be used across the conductors and insulators fleet to evaluate investment options. The key parts of this will be tools for making quantitative estimates of the likely impacts of conductor and insulator failures on service performance and safety on a span-by-span basis. The risk model will specifically consider uncertainty in the inputs to risk-based decision making.

We will also ensure more robust and detailed development of scope for major replacements, to improve the accuracy of cost estimates and the validity of the economic analysis of options. Risk management processes will be made more robust and systematic, and will allow risk assessments to be more readily communicated to internal and external stakeholders.

Training and Competence 4.6.3

We have two service specifications that define the competency requirements for working with transmission line assets:

TP.SS 06.20 Minimum competencies for lines maintenance

TP.SS 06.25 Minimum requirements for Transpower field work.

Adhere to competency requirements for transmission line workers

Adhere to the following service specifications, TP.SS 06.20 (Minimum competencies for lines maintenance) and TP.SS 06.25 (Minimum requirements for Transpower field work).

We maintain a minimum baseline of retained skilled workforce: engineers and site works operators who understand the physical assets. All workers must hold appropriate competencies to work on our assets in line with the service specifications.

Since 2011, we have provided much of the training to service providers at no cost (other than the service providers’ time). This has resulted in a considerable increase in service provider training. We will continue with this training approach in RCP2.

Asset management competency

Increase and then maintain the in-house skill base with regard to Asset Management.

To ensure better long-term asset management outcomes, we plan to increase the emphasis on training in Asset Management principles and application across all relevant parts of the business.



Summary of RCP2 Fleet Strategies 4.7

Our asset management plans for the fleet of conductors and insulators is summarised below for each lifecycle stage.

Planning

Enhancement and Development

Build new lines and uprate existing lines to ensure appropriate reliability for customers is achieved while minimising lifecycle costs.

Replacement and Refurbishment

Replace conductors when condition assessment shows a significant proportion of spans have sections at end of life due to loss of strength or cross-sectional area, and the cost of maintaining such defects and the risk of failure have become unacceptably high.

Replace earthwires when condition assessments show that replacement criteria have been met.

Investigate all copper conductors strung over high and very high safety critical areas and replace those assessed as having a positive cost benefit for doing so.

Provide inter-phase spacers on vulnerable spans where justified on a risk basis.

Replace insulators and hardware when they have degraded to the point where they can no longer reliably carry their design loads or their electrical performance has become unreliable.

Prioritise known under-clearance spans for mitigation using a risk-based approach. Carry out works for all spans assessed as requiring mitigation by 2020.

Keep transmission line aerial laser survey data up to date by periodically resurveying lines or sections which have been modified (for example, re-conductored) or underbuilt (such as in urban areas).

Prioritise conductor and insulator replacements, taking into account existing health, asset criticality and degradation rate.

Integrated Works Planning

Integrate network development uprating works with condition-based conductor replacement work.

Replace hardware and insulators if their CA is less than 60 when re-conductoring, or replacing structures, or replacing structure attachment points.

Cost Estimation

Use a tailored scoping and costing approach to estimate major re-conductoring project costs (customised estimate).

Ensure project works are scoped to achieve P50, an estimate of the project cost based on a 50% probability that the cost will not be exceeded.

Delivery

Design

Ensure design standards take account of asset criticality, balancing project specific cost optimisation with lifetime performance and resilience to high impact events.

Maintain modern internationally aligned design and procurement standards.

Minimise, as far as practical, the diversity of conductor and insulator types and fittings used in new and replacement construction.

Select conductors, balancing project specific cost optimisation with lifetime performance.

Install composite insulators in areas with extreme and very high contamination and in sensitive areas where audible noise is an issue. Install glass cap and pin insulators in all other areas.

Procurement Ensure the conductor manufacturing process delivers full grease coverage to avoid untimely early replacement due to grease holiday defects.

Delivery Planning

Ensure planned projects are deliverable within available financial, labour and material constraints.

Package work into blocks of consecutive structures/spans wherever possible to maximise efficiency and minimise outages and landowner disruption.

Operations

Outage Planning Meticulously plan conductor and insulator works that require outages, to minimise disruption to customers.

Contingency Planning

Ensure there are sufficient plans, skilled manpower and emergency spares to enable rapid restoration of transmission service following single or multiple structure failure(s) or conductor drop(s).

Corridor Management

Seek provisions in council plans to ensure that appropriate buffer distances are provided from existing transmission assets for third party activities.



Maintenance

Maintenance Approach

Carry out line work live, using live line techniques, where practicable and cost effective and subject to the work being able to be carried out safely.

Preventive Maintenance

Carry out regular line patrols to allow the planning of work required to mitigate or avoid any failure risks.

Carry out regular detailed condition assessments for conductors, insulators and associated hardware.

Vary the frequency of condition assessments based on asset condition and criticality.

Wash insulators when pollution causes poor electrical performance on otherwise sound insulators.

Continue to manage vegetation to meet statutory and public safety requirements, and ensure that the security of the transmission system is not compromised.

Corrective Maintenance

Respond to all failures in a timely manner, as determined by the criticality of the asset.

Maintenance Projects

Ensure localised conductor corrosion defects, when identified, are repaired or removed in a timely fashion, prioritising on risk.

Implement a conductor health and criticality assessment process to prioritise conductor sections for replacement five years ahead of need date. As conductors approach end of life, supplement visual condition assessment with more advanced assessment techniques.

Progressively resistance test all conductor joints on spans classified with high or medium network criticality, or very high or high safety criticality. Repair or replace those found to be defective.

Replace vibration dampers, spacers and hardware when they have degraded to the point where they can no longer reliably perform their intended function, or when postponing replacement will significantly increase replacement cost.

Disposal and Divestment

Disposal Maintain and follow an appropriate decommissioning process where re-use is not appropriate.

Recycle elements of conductors and insulators, where feasible.

Divestment Divest conductors (and associated hardware) as part of transmission line divestments to customers.

Capability

Asset Knowledge

Maintain up-to-date records of all conductors and insulators.

Undertake investigations of conductor deterioration processes to improve forecasting models.

Continue to monitor and trial technology developments in conductor and conductor inspection technology, considering risk and cost-optimising opportunities.

Risk Management Develop an improved risk-based framework and associated tools for evaluation of options for conductors and insulators.

Training and Competence

Adhere to the following service specifications, TP.SS 06.20 (Minimum competencies for lines maintenance) and TP.SS 06.25 (Minimum requirements for Transpower field work).

Increase and then maintain the in-house skill base with regard to Asset Management.


Appendices

TL Conductors and Insulators Fleet Strategy TP.FL 01.00 Issue 1

October 2013

TL CONDUCTORS AND INSULATORS FLEET STRATEGY © Transpower New Zealand Limited 2013. All rights reserved. Appendices | page 74

CONDITION INFORMATION A

Table 12 sets out the condition assessment guidelines for ACSR (GZ) conductors.

CA Score Guidelines

100 New conductor, with bright outer finish.

90 Outer strands dulled to light grey colour, brightness gone.

80 Outer strands roughened. Grease hardening.

70 Grease hard and becoming ineffective.

60 Start of core wire zinc loss.

50 First signs of white powder between strands. Outer strands have roughened.

40 Grease, drying up. Core wire zinc still intact, but getting depleted.

30 Zinc on core wire depleted in isolated spots. No rusting started. First white powder visible near core.

20 Grease gone, lots of white powder between layers, bulging starting in larger diameter conductors, occasional breaks to outer aluminium strands, severe corrosion affecting cross section of some inner strands. Steel core wire rusting in patches but no loss to cross section or UTS of steel core. 20% loss of conductor UTS.

10 Visible intermittent bulging, many broken aluminium strands, patchy surface rusting on core wire.

0 Severe loss of aluminium strand cross section, tensile strength effectively reduced to that of the core wire only. Burn down risk high.

Table 13: ACSR (GZ) Conductor Condition Assessment Guidelines

Table 13 sets out the condition assessment guidelines for ACSR (AC) conductors.

CA score Guidelines

100 New conductor, with bright outer finish.

90 Outer strands dulled to light grey colour, brightness gone.

80 Outer strands roughened. Grease hardening.

70 Grease hard and becoming ineffective.

60 Grease now ineffective.

50 First signs of white powder between outer strands. Outer strands have roughened considerably.

40 First white powder, visible near core.

30 White powder increasing between inner strands, some minor pitting of outer aluminium strands.

20 (R/C) Lots of white powder between layers, bulging starting in larger diameter conductors, occasional breaks to outer aluminium strands, severe corrosion affecting cross section of some inner strands. No loss of cross section or UTS on steel. 15% loss of conductor UTS.

10 Visible intermittent bulging, many broken aluminium strands.

0 Severe loss of aluminium strand cross section, tensile strength effectively reduced to that of the core wire only. Burn down risk high.

Table 14: ACSR (AC) Conductor Condition Assessment Guidelines

Table 14 sets out the condition assessment guidelines for copper conductors.

CA score Guidelines

100 New conductor. Strands of copper very bright red/brown gold colouring, bound tightly. Smooth to touch.

90 Weathered to dark brown.

80 Brown becoming greener.

70 Surface noticeably roughened.

60 Conductor half way to replacement criteria, due to vibration damage, corrosion, or annealing.


October 2013


50 Minimal corrosion within the conductor, external surface rough, flakes readily when bent.

40 There is no guideline for CA40.

30 Isolated outer strands breaking due to corrosion/annealing/vibration.

20 (R/C) Outer layer severely corroded, and flaking when bent. Alternatively, conductor may look satisfactory, but tests show considerable loss of strength due to annealing. 10% loss of conductor UTS.

10 Damage or loss of strength such that design loads cannot be sustained.

0 Failure of conductor possible under ‘everyday conditions’.

Table 15: Copper Conductor Condition Assessment Guidelines

Table 15 sets out the condition assessment guidelines for SC/GZ (galvanised steel or GEHSS).

CA score Guidelines

100 New galvanised steel strands, smooth, medium grey in colour, bright or spangled in appearance.

90 Dulling of galvanising, light grey in appearance, still smooth to touch.

80 Surface roughening.

70 Galvanising approximately 50% depleted.

60 Isolated spots of reddening discolouration.

50 Patches of galvanising gone. Discolouration spreading.

40 Galvanising all but gone, surface rusting spreads, and wire now mostly red/brown. No significant loss of steel strand cross section.

30 First observable loss of cross section due to surface pitting.

20 (R/C) Earthwire etched and pitted strands rusting to each other, strands brittle, cross section depleted to 15% loss of UTS.

10 Incapable of meeting design loads, but immediate failure not likely.

0 Failure imminent under ‘everyday conditions’.

Table 16: SC/GZ (galvanised steel or GEHSS) Condition Assessment Guidelines

Table 16 sets out the condition assessment guidelines for SC/AC (aluminium clad steel) and SC/CC (copper clad steel).

CA score Guidelines

100 New earthwire, bright smooth finish.

90 Surface dulling to light grey, brightness gone.

80 Surface roughening starting.

70 Surface roughening occurred.

60 Aluminium or copper cladding rough and loss of about 60% thickness.

50 Some light corrosion to strands possible, isolated patches of light rusting, yellow brown, where aluminium or copper cladding has been damaged or lost to corrosion.

40 Aluminium or copper cladding depleted in some locations, but no rusting of underlying steel.

30 Rust spreading along wire, now red brown in colour. No loss of strand cross-sectional area.

20 (R/C) Strands heavily surface rusted in many locations, but cross-sectional loss minimal in most cases. Capable of meeting design loads. 15% loss of UTS. 20% drop in conductivity.

10 Wire incapable of taking design loads, but failure not imminent.

0 Failure under ‘everyday conditions’ possible.

Table 17: SC/AC (aluminium clad steel); SC/CC (copper clad steel) Condition Assessment Guidelines

See TP SS.02.17C for further notes about the condition assessment guidelines for conductors.


October 2013


Table 17 sets out the condition assessment guidelines for insulators (composite post and composite long rod).

CA score Guidelines

100 New insulators. Hydrophobicity of insulation to STRI Guide 3 level HC 1.

90 Dulling of galvanised metal components. Dulling or bleaching of weathersheds.

80 Hydrophobicity to STRI Guide 3 level HC 2.

70 Roughening of galvanised metal parts. Chalking of weathersheds or core rod sheath, hydrophobicity to STRI Guide 3 level HC 3.

60 Specks of rust appearing on end fittings near interface with insulation, more so on prevailing wind side. Possible wear to end fittings on lightly loaded strings (jumper string), especially in windy locations.

50 Continued weathering of insulation, hydrophobicity level to STRI Guide 3 level HC 4. Weathersheds damaged by splits, cuts or gunshot.

40 Specks of rust appearing elsewhere on end fittings. Increased end fitting corrosion near interface with insulation, flaking rust, some loss of metal.

30 Ball and socket joint may be frozen by corrosion. Insulation showing signs of tracking or treeing, hydrophobicity to STRI Guide 3 level HC 5.

20 (R/C)

Possible 30% metal loss from corrosion to end fitting cross section. 30% loss of strength (SML). Complete freezing up due to corrosion of ball/socket joints. Insulation heavily oxidised or badly affected by tracking or treeing, hydrophobicity to STRI Guide 3 level HC 6. Core rod sheath damaged so that core rod is near exposure or showing pinholes. Alternatively, the insulator may be blackened by flashover, but still functioning.

10 Significant metal loss on end fittings. Insulation has lost all hydrophobicity (STRI Guide 3 level HC 7). Core rod exposed and damage occurring.

0 Insulation damaged by flashover or core rod sheath penetrated by bullet. Excessive loss of end fitting cross section. Ball pin fatigued/cracked. Line post clamp top pivots worn so clamp is excessively loose and cannot be tightened.

Table 18: Insulator (composite post and composite long rod) Condition Assessment Guidelines

Table 18 sets out the condition assessment guidelines for insulators (strings, glass/porcelain).

CA score Guidelines

100 New insulators.

90 Dulling of galvanised metal components.

80 Roughening of galvanised surfaces.

70 Roughening of galvanised metal parts.

60 Specks of rust appearing on pin beneath insulator skirt, more so on prevailing wind side. Possible wear to ball and socket on lightly loaded strings (jumper string), especially in windy locations.

50 Pin rust progressing to slight pitting.

40 Specks of rust appearing on cap. Increased corrosion to skirt end of ball pin, flaking rust, some loss of metal.

30 Ball and socket joint may be frozen by corrosion.

20 (R/C) Metal loss from corrosion to ball pin cross section resulting in a 16% reduction of effective pin diameter (0.84 of original). “Complete freezing up” of units, due to corrosion of ball/socket joints. Alternatively the string may be badly damaged by flashover, but still functioning.

10 Significant metal loss on pins. Glass units may begin to shatter, and porcelain units fail electrical tests due to internal or external cracking.

0 Pin corrosion or extreme flashover damage. Excessive loss of ball pin diameter. Ball pin fatigued/cracked. Electrical test failure.

Table 19: Insulator (strings, glass/porcelain) Condition Assessment Guidelines


October 2013


Table 19 sets out the condition assessment guidelines for insulator fittings (hot or cold end).

CA score Guidelines

100 New components free from defects.

90 Surfaces dulled to a light grey colour.

80 Wear due to movement at 25% of replacement criteria.

70 Weathering of components, roughening of surfaces occurring.

60 Some light rusting to bolt threads, split pin holes. Rust stain appearing. Alternatively, wind wear at 50% of replacement criteria.

50 Darkening due to loss of galvanising.

40 Wind wear at 75% of replacement criteria.

30 Significant rusting, particularly from prevailing wind or seaward direction, some loss of metal. Build up of corrosion product resulting in minor freezing of hardware connection.

20 (R/C) Wind wear reaches replacement criteria, or corrosion severe enough to create significant metal loss, and reach replacement criteria. 20% metal loss of critical cross-sectional area. Any hardware connection frozen by corrosion contamination and unable to operate as designed.

10 Components rusted or worn beyond replacement criteria, but risk of failure minimal.

0 Serious loss of strength, failure likely under ‘everyday conditions’.

Table 20: Insulator fittings (hot or cold end) Condition Assessment Guidelines

See TP SS.02.17C for further notes about the condition assessment guidelines for insulators.


October 2013


CORROSION ZONE MAP B

Figure 27: Corrosion Zones

The Figure 27 map shows the geographical location of transmission structures and spans by corrosion zone. Extreme corrosion zones are restricted to small areas near Bluff, Oteranga Bay, New Plymouth and some geothermal areas on the Volcanic Plateau. Most towers rated as very severe are located on the Kapiti and Taranaki coasts. At the other end of the scale, most of Central Otago is classified as benign.


October 2013


Table 21 shows the proportion of the main conductor types in each of the six corrosion zones.

Type Benign Low Moderate Severe Very

Severe Extreme

ACSR-GZ (greased

and ungreased) 3% 9% 35% 11% 5% <1%

ACSR-GZ (greased) 3% 3% 3% <1% <1% <1%

ACSR-GZ

(ungreased) <1%

ACSR-AC (greased) <1% <1% 5% 4% 2% <1%

AAAC (greased)

<1% 2% 1% <1%

Copper <1% 3% 7% <1% <1%

SC/AC

<1% <1%

AAC

<1% <1%

Total 6% 15% 52% 17% 8% 1%

Table 21: Conductor Circuit Length by Corrosion Zone18

Table 21 shows the proportion of circuit sets for each insulator type in each of the six corrosion zones.

Insulators (cct sets)


Severe Extreme

Glass 3.3% 10.7% 35.6% 9.7% 4.2% 0.5%

Porcelain 2.1% 3.5% 8.9% 2.4% 0.6% 0.1%

Composite 0.0% 1.9% 7.2% 4.9% 4.2% 0.3%

Total 5.4% 16.0% 51.7% 16.9% 9.0% 1.0%

Table 22: Insulator Life Expectancy by Type and Corrosion Zone

18

The table excludes earthwire.


October 2013


CONDUCTOR DEGRADATION EXAMPLES C

Ageing examples

Figures 28, 29 and 30 show examples of ageing.

Galvanic corrosion

Figure 28: Bulging conductor caused by internal corrosion products

Fretting

Figure 29: Fretting marks at strand contact points Figure 30: Sectioned strand shows loss of area


October 2013


Defect examples

Figures 31 and 32 show examples of defects.

Grease holidays corrosion

Severe corrosion bulge at ‘grease holiday’

Adjacent conductor with good grease

Multiple grease holiday bulges

Core exposed and no grease (white patches)

Figure 31: Grease holiday photos

Dog bone spacer corrosion

Old ‘dog bone spacer’ with rubber ends

White aluminium oxides

Figure 32: Dog bone spacer photos

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