Foreword

Welcome to The Lines Company’s 2020 Asset Management Plan (AMP).

This 2020 AMP reflects our company’s continued journey of change. It provides an overview of our assets, the processes we use and the expenditure we are planning to both maintain and grow our network over the next ten years.

Much of our attention in this plan focuses on improving our system reliability and security of supply, and our on our approach to achieve these key objectives. We are acutely aware that maintaining a safe and reliable electricity supply system is fundamental to supporting regional economic growth, and our planning challenge is to do this in a sustainable and cost- effective way.

To achieve that balance, this 2020 AMP continues to build on our capabilities in managing risk and optimising both the performance and lifecycles of our existing assets. Central to achieving this is strengthening our asset data and business analysis capabilities and so we are specifically extending our information technology tools, including building a database of the vegetation growing in and around the lines on our network.

We are also continuing to refine our project planning and building up our competencies in project management to ensure our expenditure provides the best possible balance of safety, service and cost outcomes.

The safety of our people, our community and our assets is paramount to us, thus it continues to be a key feature of our planning. We are investing specifically to reduce safety risks on our assets, their interaction with the community we serve, and in the way we work as a company to maintain them.

In developing the 2020 AMP our goal has been to provide a long-term roadmap for our assets in an informative and easily read way. We want to encourage our stakeholders – our customers, our business partners, and the people living in our community - to engage with us on the way we manage the custodianship of our assets and on the projects that stem from the guiding principles outlined in this document.

As we have been developing this plan, our attention has been drawn to the broadening impacts of the international coronavirus (COVID-19) pandemic in which New Zealand and the world is beginning its journey of management and recovery. How those impacts are felt by our community, and how TLC, as an essential service supplier may need to adjust its business to maintain supply to our customers is an evolving challenge. We are working hard to continue to keep our community connected and deliver our business objectives including the significant and important work outlined in this AMP.

With your support and feedback our business can continue to develop and succeed, so I invite you to comment by emailing [email protected].

The Lines Company

Sean Horgan Chief Executive

Foreword | 2

Contents 1. Introduction ...... 6 2. Background ...... 22 3. Network Assets ...... 38 4. Introduction ...... 51 5. Capital Project Planning & Delivery...... 68 6. Operations and Maintenance ...... 102 7. Summary of Expenditure and Forecast ...... 118 8. Asset Management Performance ...... 124 9. Continual Improvement ...... 140 10. Appendix A: Glossary ...... 146 11. Appendix B: Information Disclosure Compliance ...... 148 12. Appendix C: Information Disclosure Asset Management Plan Schedules ...... 159 13. Appendix D: Director Certification ...... 178

Table of Contents | 3

Introduction | 4

Plan Summary

Introduces our business and summarises our plan

Introducing Our Business And Our Assets

Introduces The Lines Company, our Describes the assets we own and operate customers and our network

How We Manage Our Assets

Sets out our approach to asset management and how we manage risks

Our 10-Year Plan

Summarises our forecast Sets out our plans Sets out how we maintain capital and operational for developing the our network assets and our expenditure for the next network supporting operations 10 years

How We Monitor Compliance With Industry Regulators

Describes how well our business and assets Describes how we intend to improve our perform against our strategic objectives performance over time

How We Comply With Industry Regulations

Appendix A Provides a glossary of key terms used in this document

Appendix B References the compliance requirements in our AMP

Appendix C Provides summary schedules required by the Commerce Commission

Appendix D Provides the Directors Certification for this AMP

Introduction | 5

1. Introduction This chapter introduces our 2020 Asset Management Plan (AMP). It outlines its purpose and objectives, for whom it is written and how it is structured. It also provides a summary of the AMP including the key themes and initiatives that underpin our ten-year planning period, as we see them at the current time.

Purpose

This Asset Management Plan (AMP) describes our electricity network, our assets and our investment requirements. It also provides an overview of our asset management practices, our planning and our key risks and issues as we perceive them.

The purpose of this AMP is to communicate with our stakeholders by:

• Providing readers with an understanding of the nature and characteristics of our network region.

• Describing the assets we own and operate.

• Detailing the investment requirements we foresee over the AMP period, so we can continue to operate our network safely and reliably and meet our strategic objectives, which are to be sharp in our abilities and operational practices, to be centred on our customers and people, to be thriving in and with the community, and to be growing in ways that bring value back to our stakeholders.

• Outlining our asset management objectives, which are to develop proficiency in leadership and enablement, asset planning, business process and continual improvement.

• Outlining our short to medium term planning objectives, which are improving safety, improving reliability, improving security of supply, building resilience in our power transformer fleet and maintaining a sustainable line renewal programme.

• Detailing our asset management processes which have been put in place to meet those objectives.

• Describing the relationship between our AMP and our strategic plan, and its importance as a key planning document.

Overview

The Lines Company 2020 Asset Management Plan is intended to take the significant, high quality technical information we hold about our assets and demonstrate how that aligns with TLC’s strategic direction and objectives.

In doing so we have sought to provide information to our stakeholders about how we are managing the assets they have entrusted to us. Specifically, we aim to:

• Provide readers with a broad understanding of the characteristics of our network, and the assets we own and operate.

• Demonstrate the investment requirements we foresee over the AMP period to enable us to progress in accordance with our business objectives.

Introduction | 6

• Convey the asset management and planning processes which have been established to manage our significant asset investments and to maintain our stakeholder interests.

Through this AMP document, we have aimed to explain technical issues in a way that is meaningful to all our stakeholders. Consequently, this AMP document is a concise overview of our broader asset management processes and outputs and is deliberately presented in the form of a high-level summary of deeper technical information.

We aim to provide enough detail to explain how our plans and decisions arise and are implemented in a way that makes it easy to read and understand.

This plan covers a ten-year period from 1 April 2020 to 31 March 2030 (the planning period). As with any long-term plan, the details tend to be more accurate in the earlier years as it is easier to predict the near-term state of our assets and required actions, plans and expenditure. This Asset Management Plan was approved by The Lines Company Limited Board of Directors on 26 March 2020.

1.2.1 Short term challenges

The following issues provide both immediate and long-term opportunities and challenges and have been key considerations as we have developed this AMP.

Keeping the community and our people safe

Safety is our highest business priority. Our focus on safety continues to be prioritised to ensure that hazards that could cause injury to our people or the public are addressed. We have identified a number of safety related issues related to our assets that are we are specifically progressing in this Asset Management Plan. Specifically, these are related to some of our older ground mounted transformers, some of our 11kV power cables and older distribution switches.

Improving our reliability performance

In the past three years, TLC’s reliability performance has exceeded some of our regulatory targets, and as a consequence addressing reliability is a key objective of this plan.

Identifying the specific drivers of outages on our network is often complex because the underlying causes can be multifaceted, and include weather, environmental factors, vegetation (tree fall), asset failure, human error and third- party interference. In some cases, tracing the cause of faults is further complicated because the fault can clear (power is restored) by automated switches before the physical location and fault cause can be identified. Improving our reliability performance, therefore, means that we need to become better at identifying these issues and target our effort in areas that have most effect.

In this AMP we are specifically seeking to gain a deeper understanding of our outage causes through empirical information and analysis. To do this we are investing in better tools (a vegetation database and improved business and data analysis tools) and working to improve our internal capabilities and processes.

Building resilience in our network

Over the past three years we have been progressing through a programme to improve the overall resilience of our network. The starting point to achieve that outcome is to incorporate backup supplies to our zone substations, prioritising those that serve large numbers of customers. We have already made significant progress including the upgrade of three of our largest substations. This AMP continues that programme and will see a range of upgrades to key substations, and a number of network design improvements by the end of the planning period.

Introduction | 7

Customer growth and changes in how energy is used

We are also continuing to experience significant industrial growth on our network, and so we are bringing forward some network upgrade projects, and preparing engineering resources, to support these large-scale customer projects.

Alongside these increases in power demand, we are beginning to see changes in the way our customers use energy. The two most immediate changes and impacts are the installation of solar technology on homes, and the emergence of electric vehicles and their charging infrastructure. At this stage the impacts on our network are small, but we expect these and other technology changes to make a significant difference in the way energy on our network is used, and as a consequence, how we may need to plan and adapt our network operations to support that change.

1.2.2 Key Assumptions in Developing this Plan

This plan has been developed with the following key assumptions

• TLC is able to attract and retain staff and has access to contractors via the wider market to fulfil its capital programme.

• Conditions that affect our business (weather, business costs and operating environment) do not vary materially from where we understand them today.

• Access to capital and inflation remains stable.

• The regulatory environment does not change significantly over the planning period.

• The availability of resource and equipment is not materially changed from current market conditions; i.e. is not materially impacted by pandemic or other natural or un-natural disaster.

1.2.3 Our Business Structure

TLC has four business units that integrate to support the management of its distribution network. The relationship of the three business units to the core network and its asset management is set out below.

Figure 1.1: Integrated TLC Business

NW Operational NW Performance TLC Generation TLC Network and Continual FCLM Metering Strategy Improvement

Assist reliability of Provide data and analytics supply support to assist with network Asset Management continual improvement Strategy

TLC Network Services

Deliver safe and cost-efficient services to the network including condition and risk feedback

Introduction | 8

1.2.4 Network Overview

The Lines Company Network provides an electricity distribution service to over (18,000 customers with around 24,000 ICPs connection points (or ICPs) covering 13,700 km2. It is one of the largest network areas in New Zealand but has a low population density and doesn’t supply a major urban centre. Consequently, much of the network is committed to providing electrical distribution services to rural and sparsely populated areas.

Relative to other distributors in New Zealand, the TLC network is also electrically complex. It has one of the most diverse customer populations, a long circuit length, multiple and varied points of supply (from both Transpower and large generators), and significant electricity generation that is embedded within the network.

Figure 1.2: The TLC Network Region

Taharoa

Otorohanga Waitomo Te Kuiti Mangakino Whakamaru Piopio

Benneydale Mokai

Mokau

Taumarunui

Turangi

National Park

Ohakune

1.2.5 Network Growth

Electricity demand on the TLC network has continued to grow, driven primarily by farming, commercial and industrial business growth. In 2019 TLC upgraded the Hangatiki 110 kV supply point (the installation of a new high voltage transformer), to provide backup security and to cater for load growth in the northern area.

Over the ten year planning period this AMP plan covers, we expect continued growth will require continued investment in our major supply points and zone substations. In some cases where customers have signalled their needs for more capacity, those upgrades are already being actively planned.

It is possible that before the end of the planning period some of our major GXP supply points may need expansion. The investment required to do that is significant and has not been allowed for in this 2020 AMP. We intend to monitor

Introduction | 9 our growth rate in the next five years and adjust our estimates of load growth and capital investment to support GXP upgrades, if and when this indicates that more capacity is required.

In total we expect both network coincident demand and network energy growth to increase by circa 25% over the planning period.

Figure 1.3: Network Demand Forecast

Network Demand Forecast 100 90 80 70 60 50 40 30 Megawatts (MW) Megawatts 20 10 0 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Financial Year

GXP Coincident Demand Network Coincident Demand

Figure 1.4: Network Energy Forecast

Network Energy Forecast 500 450 400 350 300 250 200 150

100 Giggawatt Hours (GWh) Hours Giggawatt 50 0 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Financial Year

Introduction | 10

1.2.6 Asset Summary

The network assets that are used to provide electricity to the TLC geographic area are summarized in Table 1.1 below:

Table 1.1 Summary of Assets

Portfolio Asset Class Population Points of Supply Transpower Grid Exit Points 5 Direct Generator Connections 3 Embedded Generators >1MW TLC owned or controlled Hydro Generation Plants 3 King Country Energy Owned Generation Plants 4 Zone Substations and power Buildings (including containers) 39 transformers Power transformers 40

Sub-Transmission Switchgear Air-break switches and secitonalisers 111 Circuit breakers 46 Fuses and Fuse Links 7 Load Break Switches 1 Reclosers 14 Solid Links 47 Transformer Fuses 8 Support structures Poles 34,085 Crossarms 51,208 Overhead conductors Sub-transmission 456 Distribution 3,069 Low Voltage 478 Cables Sub-transmission 11 Distribution 130 Low Voltage Underground cables 182 Distribution transformers Ground mounted transformers 495 Pole mounted transformers 4,709 Distribution switches Air-break switches 440 Circuit breakers 176 Fused switches / Fused Links 1,029 Load Break Switches 174 Reclosers 132 RTE switches 68 Sectionalisers 64 Solid Links 519 Transformer Fuses / Tap Off Fuses 5,604 Secondary systems SCADA and communication 927 Protection relays 278 Load Control Systems 10 LV Pillar Boxes Pillar Boxes 4,146

Introduction | 11

Our Asset Management Objectives

1.3.1 Key Asset Management Objectives

The objectives of the 2020 AMP maintain consistency with the 2018 and 2019 AMPs, because they remain relevant and are in progress. They are:

Improving Safety

TLC has three significant Safety and Environmental risks that will be addressed in the 2020 AMP:

• Public safety risks associated with distribution transformers enclosed in wooden and tin sheds;

The replacement of the distribution transformers noted above is a continuation of a programme identified in the 2018 AMP and is scheduled to complete in year three of the planning period. To date all priority one transformers (which carried public safety risks) have been upgraded, and TLC is mid-way through its priority two transformer upgrades.

• Safety and reliability risks associated with the cables on the Ruapehu ski-fields;

Designing and implementing a workable solution for improving the safety and reliability of the cables that supply the Ruapehu ski-fields remains challenging and ongoing. It requires extensive input from our customer and consultation with both Iwi and the Department of Conservation. We expect to conclude this project over a five- year period focusing on improving cable resilience on crossings first and lifting reliability and performance by continued monitoring and design improvements over time.

• Switchgear that is unsafe to operate when live (known as SDAF switchgear).

The one remaining SDAF switch on our network will be replaced or removed over the coming 12 months.

Improving reliability

Unplanned outages remain a key issue for the business. Historically we have put the most focus on targeting replacement of high-risk, lower condition assets. In this 2020 AMP we are expanding our approach to reliability management including:

• Improving how we collect, analyse and apply asset and network data to estimate the probability of an outage

• How we mitigate the impact of outages when they occur (e.g. the installation of sectional break switches to limit and isolate faults)

• How we assess and apply vegetation management to minimise outages

• Developing our systems and asset management practices to provide greater insights and data analysis to help us understand and mitigate the causes of faults.

We are specifically investing in a vegetation database in FY2021. TLC has one of the largest and most forested networks in New Zealand, and vegetation outages (from tree fall and wind-blown branches) are a key cause of outages on our network. In addition, we have a higher than average number of unknown cause outages which we suspect is due to interference from vegetation.

Introduction | 12

The investment in a vegetation database (including an initial survey of our network) will support understanding of our vegetation management needs, including the right-size of our management programme, and how to best target our vegetation management expenditure into the future.

Security of Supply

Although we have made significant progress in alleviating security of supply constraints in the last two years, this remains a work in progress as well as a moving target. Both customer growth and asset failures (power transformers) are maintaining pressure on security of supply, and this means that TLC must continue investment in the short to medium term. Currently around 6,500 customers are connected to a zone substation that does not meet our security of supply targets. At the end of the planning period we expect this to be reduced to 2,876 customers.

Figure 1.5: shows an overview of our zone substation security. In the chart ‘N-1’ means there is a redundant transformer or backup feed in place to provide supply if one of the key substation assets fails. The term ‘N’ means there is no backup supply. In some cases, there is a backup supply, that can supply part (but not all) of the customer load at peak times, and this is depicted as ‘N-1 Constrained’.

We are seeking to achieve an N-1 status for most substations, and all substations that support large numbers of customers. For those that don’t have a full N-1 security of supply status, TLC can provide ‘fast response’ backup (back feed) options.

Projects within the planning period will address four current security constraints providing a more reliable and resilient supply to our customers.

Figure 1.5: Security Rating of TLC’s Zone Substations

Zone Substation Security Summary Zone substation 3500 security improvement projects in the 2020 3000 ~6,500 customers (around 27%) are 2500 impacted by security of supply constraints 2000

1500

1000

Number of Customers of Number 500

0

Tuhua

Piripiri

Tawhai

Otukou

Turangi

Kuratau

Te Anga Te Waitete

Taharoa

Marotiri

Oparure

Borough

Tokaanu

Arohena

Manunui

Maraetai

Nihoniho

Hangatiki

Waiotaka

Awamate

Kiko Road Kiko

Mahoenui

Kaahu Tee Kaahu

Te Waireka Te

Gadsby Road Gadsby Falls Wairere National Park National

Taharoa Village Taharoa N N-1 N-1 Constrained N-1 Switched

Introduction | 13

Building Resilience in TLC’s Power Transformer Fleet

In recent years, TLC has experienced several failures in its power transformer fleet. To alleviate this, four new transformers have been ordered (two each of 2.5MVA and 15MVA). The 2.5 MVA transformers will be deployed into existing substations to allow refurbishment of existing units, with the 15MVA transformers deployed at a new Waitete substation with installation scheduled for FY2022. This will in turn release the existing transformers for a cascading zone substation upgrade programme, creating greater power transformer resilience across the network.

Maintaining a sustainable line renewal programme

One of the most significant challenges for the business is transforming its line renewal programme to create a sustainable forward management programme. TLC has some 4000 km of lines which are supported by approximately 34,000 poles and 51,000 crossarms. The establishment of the core network took place through the mid 1900’s and since that time the renewal of line infrastructure has not quite kept sufficient pace to maintain an average mid-life age.

Figure 1.6 shows TLC’s rolling average pole age profile. Although this is a crude indicator of risk, it shows that the average age of TLC’s pole asset fleet has been steadily increasing year on year.

Figure 1.6: TLC’s Pole Age Profile

Rolling Average Pole Age 40 35 2020 30 AMP 25 Plan 20

15 Age (Years) (Years) Age 10

5 (years)

0 Average

1919 1929 1939 1949 1959 1969 1979 1989 1999 2009 2019 2029

Average Pole Age at Year X

Although our line renewal programme has successfully improved the reliability of our distribution network over the last fifteen years, that performance will begin to erode without further planned renewal.

Introduction | 14

Key Outcomes

1.4.1 Planned Capital Expenditure

Over the past two years, significant work has been undertaken to review our approach to security of supply and reliability of the network. The historical focus has been on increasing the reliability of the distribution and sub- transmission networks, which has seen a marked improvement in the overall reliability of the network over the past 15 years. However, over that period growth across the network (both incremental and customer driven) has now meant that investment is required in zone substations and points of supply over the planning period to ensure that a reliable supply of electricity is able to be maintained to those areas. In parallel with that, the line renewal programme needs to continue at levels similar to previous years to ensure reliability is maintained.

In the 2017 Asset Management Plan Update we signalled a lift in capital expenditure from an historical base of around $10m to $15m per annum to enable us to continue to provide a safe, reliable, resilient network. In developing this AMP, we have continued that focus.

A summary of the capital expenditure for the planning period is outlined below.

Table 1.2: Summary of Total Capital Investment – 10 years (Constant Dollars)

$ 000’s 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

Network

Asset Renewals 13,999 12,078 12,549 10,773 9,629 10,043 7,342 8,250 8,568 9,098 Network 4,726 4,360 4,716 3,425 2,244 3,172 1,082 2,336 2,803 3,176 Development Customer Required 6,440 4,744 1,028 1,028 1,028 1,179 1,179 1,179 1,179 1,179

Non-Network

Routine 352 352 352 352 352 164 164 164 164 164 Atypical 514 2,056 0 0 0 0 0 0 0 0 Total All Capital 26,032 23,590 18,645 15,579 13,254 14,558 9,767 11,930 12,714 13,617 Expenditure Less Capital Contributions from (6,065) (4,215) (654) (654) (654) 0 0 0 0 0 Customers Total Expenditure 19,966 19,375 17,991 14,925 12,600 14,558 9,767 11,930 12,714 13,617

Introduction | 15

Figure 1.7: All Capital Investment

Network Capital Expenditure Asset Renewal Programme Network Development Programme Customer Required Projects Non Network Atypical Non Network Routine 30,000

25,000

20,000

15,000

10,000

5,000 Capital Expenditure (000s) Expenditure Capital

0 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Financial Year

Introduction | 16

1.4.2 Planned Operational Expenditure

Our Opex spend across the planning period remains relatively consistent with that identified last year. There are increases in the near term that are offset with decreases over time as efficiency improvements across the business are realised.

Table 1.3: Planned Operational Expenditure (Constant Dollars)

$ 000’s 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

Maintenance

Preventive 1,236 1,238 1,240 1,241 1,243 1,244 1,246 1,248 1,249 1,251 Expenditure Reactive 1,186 1,186 1,186 1,186 1,186 1,186 1,186 1,186 1,186 1,186 Expenditure

Asset Replacement and Renewal

Planned 193 193 193 193 193 193 193 193 193 193 Expenditure

Vegetation Management

Planned 1,419 1,220 1,221 1,221 1,222 1,223 1,224 1,225 1,226 1,227 Expenditure

System Operations and Network Support (SONS)

Planned 2,032 2,044 2,057 2,070 2,083 2,097 2,110 2,123 2,136 2,150 Expenditure

Business Support

Planned 7,871 7,918 7,927 7,942 7,956 7,971 7,986 8,001 8,016 8,031 Expenditure

Total 13,938 13,799 13,824 13,854 13,884 13,915 13,945 13,976 14,007 14,038

Introduction | 17

Figure 1.8: All Operational Expenditure

Network Operational Expenditure

16,000

14,000

12,000

10,000

8,000

6,000

4,000

2,000

0

Operational Expenditure (000s) Expenditure Operational 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

Business Support System Operations and Network Support Vegetation Management Asset Replacement and Renewal Reactive Expenditure Preventive Expenditure

1.4.3 Asset Management Performance

In developing this Asset Management Plan, we have determined four asset management performance measures that will assist in determining our effectiveness over time. These are detailed below:

• Safety: Safety of our team, our customers and our community is of paramount importance to TLC. No job is so important that it cannot be completed safely.

• Customer Experience: Our customers’ experience in dealing with us and the service levels they receive from our network are key elements in how we operate our business. We remain focused on ensuring that our network remains reliable and that when our customers contact us, we respond in a timely and professional manner to resolve their queries.

• Cost Efficiency: We aim to deliver service from a safe, reliable network to our customers in the most cost- effective manner possible across the life of our assets. The widely varying nature of our network and its relatively low customer density provides a number of challenges in ensuring that costs remain well controlled.

• Asset Performance: Performance of our assets is strongly influenced by the decisions we make in the design, construction, operation and maintenance of our assets. Our focus is to ensure that our assets achieve or maintain performance levels at the lowest life cycle cost.

1.4.4 Continual Improvement

We are continually improving the way we manage our assets and the outcomes we provide to our stakeholders. The Commerce Commission provides a standard framework for measuring asset management improvement, which ranks our maturity level from 0 to 4. For the last three years, we have had this assessed by an external party.

Introduction | 18

This year our competency level has increased resulting from the development work undertaken in asset management during 2019. The conclusion from this review is that TLC is making steady progress in our asset management maturity, but also that we have many areas that we can further strengthen. These will be key focal points on our further development.

Figure 1.9: Asset Management Improvement

Asset strategy and delivery TLC 2019 4.0 TLC 2020 3.5 PAS 55 Compliance 3.0 2.5 Competency and training 2.0 Documentation, controls and review 1.5 1.0 0.5 0.0

Structure, capability and Systems, integration and authority information management

Communication and participation

Introduction | 19

Development Initiatives

1.5.1 Asset Management Framework

In 2018 TLC reviewed its approach to Asset Management and has committed to aligning our Asset Management Framework to the internationally recognised ISO55000 series of standards. In aligning with these standards, we have structured our Asset Management Planning around four pillars. These are summarised below:

• Leadership and Enablement of the asset management approach which is aligned with TLC’s business objectives, and meets the requirements of both external and internal stakeholders;

• Asset Planning - a detailed end-to-end planning process across the asset portfolio which commences with risk profiling of the assets, through to delivery.

• Business Processes - well defined quality processes for the delivery of Capex and Opex work to the assets along with other tasks such as switching, investigations, materials supply and so forth. The intent is to reduce the cost of work through quality management, assure consistency of approach and promote the competency of all teams involved with service delivery.

• Continual improvement – consistently improving asset management processes as well as determining future options for network resilience and reliability.

Introduction | 20

Background | 21

2. Background This chapter provides an overview of The Lines Company including ownership and governance, business context, our customers and stakeholders, our network, asset summary and operating environment.

Overview of The Lines Company

2.1.1 Company Profile

The Lines Company’s core business is the ownership, maintenance and operation of an electricity distribution business predominantly located in the King Country and Ruapehu regions of New Zealand.

The Lines Company (TLC) was established in 1999 when electricity industry reforms required the separation of retailing and distribution lines businesses. Before then, TLC’s lines business assets were vested in King Country Energy Ltd and the Waitomo Energy Company, both of which had themselves been created out of the old Power Boards as part of reforms earlier that decade.

TLC is 100% owned by the Waitomo Energy Services Customer Trust (“WESCT”), which is governed by six trustees. Three trustees are elected by customers within a gazetted area (Hangatiki and Whakamaru) who then appoint one further trustee. Major customers within the Hangatiki and Whakamaru area also elect two trustees.

TLC’s Head Office is located in Te Kuiti with operational depots in Taumarunui, Ohakune and Turangi. The group has three business units; Network, Generation and Network Services and three subsidiaries FCLM Metering, Speedy’s Road Hydro and GoodMeasure Limited.

2.1.2 Business Context

Government policy and climate change

Climate change is an increasing focal point of government policy. New Zealand’s primary response to managing its climate change targets is through electrification of the transport industry, which along with agriculture is our largest contributor or greenhouse gasses into the environment.

Migrating to a future where most of New Zealand’s transport is fueled by electricity is challenging. New Zealand has approximately 4 million light vehicles in use today, each with the potential to consume more energy than an average house. Extending New Zealand’s electricity distribution infrastructure to meet this future demand will be a significant challenge for the industry, and one that the industry as a whole is already planning for.

The volume of electric vehicles in New Zealand so far has been small – currently around 20,000 plug-in or fully electric vehicles in use as at the end of 2019. We have not yet seen or measured any noticeable impact on the TLC network, but we are acutely aware of how quickly this could change should electric vehicle growth begin to accelerate.

The Ministry of Transport forecasts around 200,000 electric vehicles will be in use by the end of 2025, which is approximately 5% of New Zealand’s light vehicle fleet. In this 2020 AMP we are building up both capacity and security of supply on our network over a similar time frame , which will enable and support the use electric vehicles by our customers and by visitors to our region.

Background | 22

Further Transformation of the Electricity Supply Industry

The electricity supply industry in New Zealand is undergoing other significant changes driven by factors such as the uptake of Distributed Energy Resources (e.g. photovoltaics, battery storage etc.), increasing consumer engagement, projected growth of electric vehicles and a new regulatory focus on performance and reliability.

The Lines Company is part of this transformation and we are faced with a number of present and future challenges in relation to the management of our assets and the services we provide to our customers. Some of these are listed below, along with a description of how we are addressing these challenges.

In response to feedback we received from Customer consultation, TLC transitioned from Customer and demand based pricing to a simpler time of use A philosophy of ‘keeping engaged with the community pricing structure in 2018. TLC is still the only customers and the community’ is part of TLC’s new engagement company in New Zealand that direct bill’s its business ethos. customers and are reviewing whether that is appropriate for our customers going forward.

Following an external review undertaken in 2017 The Health and Safety at Work Act (2015), sets and 2018, TLC has increased its focus and Safety Leadership an expectation that businesses move from a resourcing relating to health, safety and wellbeing. compliance to a proactive safety culture. TLC continues to progress its health and safety culture towards best practice.

TLC has an aging asset base that is spread across Cost effective a wide geographical area. TLC is focused on TLC has revised the asset management planning network service maintaining network reliability at the least process with a view to optimising reliability, risk, delivery possible life cycle cost which remains challenging cost and customer experience. with an aging asset and a low population base.

TLC is involved in a number of technology The emergence of new technology such as initiatives from a solar trial and EV charging photovoltaics, battery storage, smart in-home through to real time data acquisition and Emerging devices, electric vehicles and digital trading monitoring of network information. TLC has technologies platforms, to name a few, has the potential to embraced new drone technologies for inspecting its significantly change the industry and TLC’s lines and is progressing to radar (Lidar) imaging of business activities. vegetation and prediction of interruptions.

TLC’s new customer management system went live Investment in TLC’s systems and processes require updating in 2018. A number of process improvement systems and and investment in order to meet the programmes are now in progress to strengthen our processes requirements of an evolving business. operational capability – especially in the network development and operations area.

2.1.3 Business Structure

TLC has three business units that integrate to support the management of its distribution network. Further detail on the Network business unit is provided in Section 2.3. The relationship of the three business units to the core network and its asset management is set out below:

Background | 23

Figure 2.1: Integrated TLC Business

NW Performance NW Operational TLC Generation TLC Network and Continual FCL Metering Strategy Improvement

Assist reliability of Provide data and analytics supply support to assist with network Asset Management continual improvement Strategy

TLC Network Services

Deliver safe and cost-efficient services to the network including condition and risk feedback

These business units provide strategic opportunities for the ongoing refinement of TLC’s approach to asset management.

Generation

TLC operates and maintains three hydro generation sites – these are either wholly owned or owned in partnership with landowners. Two generation sites (Speedys Road and Mangapehi) are in TLC’s network area while one site is located at Matawai near Gisborne. These generation sites are run of the river (i.e. no hydraulic storage) hydroelectric plants. The output is dependent on rainfall in the catchments that supply the in-take rivers. Incremental improvements continue to be made on plant and equipment in order to optimise generation output and ensure reliability of supply.

Metering

FCL Metering (FCLM) is a wholly owned subsidiary of TLC and represents the Group’s metering interests. FCLM owns both on-network meters (meters on the TLC Network) and off-network meters (which exist on non-TLC networks) where FCL derives income from electricity retailers and some industrial sites throughout New Zealand. TLC also owns Goodmeasure Ltd – a specialist data acquisition business specialising in meter analytics using cloud-based platforms.

Network Services

TLC Network Services provides network construction services, as well as maintenance, fault management and technical services to customers. The business unit employs approximately 65 staff and is focused as a specialist support unit to the network..

In addition to in-house teams, TLC also engages external service providers for vegetation management (arborist services) and other specific major construction projects.

Background | 24

2.1.4 Organisation Structure

The Lines Company is structured into five divisions which manage the TLC business unit portfolio. The organisational divisions, along with the key functions they perform is shown below.

Figure 2.2: TLC Organisation Structure and Key Functions

Chief Executive

IT Manager Executive Support

GM Customer and GM People and CE FCL GM Finance GM Network Communications Safety Metering

Finance Contact Centre Network Operations Health and Safety Data Services

Organisational Field services Accounting Billing Network Engineering Development

Recruitment and Fault service Network Compliance Pricing Management Construction Retention

Network Human REsource Customer Experience Test House Regulatory Maintenance Management

Communications Asset Management

Asset Information

Major Customers

Generation

Background | 25

Business Objectives

2.2.1 Strategic Framework

TLC is on journey of change, and our intent is progress our business towards becoming a company that is both efficient in its commercial practice, and increasingly integrated with our customers and our community. This vision is summarised under four themes.

• Being Sharp – In our business capabilities and operational practices. This means continuously improving so that we are capable, astute, innovative and efficient, continuously taking cost out, and building value in.

• Being Centred – On our customers and people. This means putting customers and staff at the center of our business so that they are at the heart of our planning and decision making. It also means constantly striving to ensure that TLC is a good employer and cares about the well-being of its people and the people in its community.

• Thriving – In and with the community. Aside from providing a good customer service, TLC needs to be a valued community citizen. This means being a regional enabler, working closely on common goals, and building strong and long-term partnerships.

• Growing – In ways that make sense and bring value back to our stakeholders.

This plan is a continual work in progress, and we hope to demonstrate gradual but consistent improvements in our asset management and business planning in the years ahead.

2.2.2 Link to Asset Management Planning

This asset management plan is central to achieving our strategic goals. It is a key foundational component of our wider business plan and outlines how we intend to manage the significant assets we are entrusted with to progress towards our key themes. It specifically describes how we plan to apply funds to our business to improve our asset performance, and how we intend to improve some of our key business practices

There are four key areas:

• Safety: Safety of our team, our customers and our community is of paramount importance to TLC. No job is so important that it cannot be completed safely.

• Customer Experience: Our customers’ experience in dealing with us and the service levels they receive from our network are key elements in how we operate our business. We remain focused on ensuring that our network remains reliable and that when our customers contact us, we respond in a timely and professional manner to resolve their queries.

• Cost Efficiency: We aim to deliver service from a safe, reliable network to our customers in the most cost-effective manner possible. The widely varying nature of our network and its relatively low customer density provides a number of challenges in ensuring that costs remain well controlled.

• Asset Performance: Performance of our assets is strongly influenced by the decisions we make in the design, construction, operation and maintenance of our assets. Our focus is to ensure that our assets achieve or maintain performance levels at the lowest life cycle cost.

Our Asset Management performance itself is measured, and this is detailed in Section 8.

Background | 26

2.2.3 Organisational Values

TLC has defined a set of organisational values. These values, supported by a set of behaviours underpin how the people within TLC act with their colleagues, our customers and our community. These values are detailed below.

Figure 2.3: Organisational Values

• Health and wellbeing comes first.

• Act safely.

• Protect those around us. Keep Well

• Innovate and bring ideas to life.

• Punch above our weight.

• Embrace change positively.

Be Awesome • Exceed expectations.

• Work hard to get the job done.

• Make a difference.

• Celebrate our expertise.

Be Proud • Embrace our unique community.

• Be responsible for our actions.

• Take ownership from start to finish.

• Deliver on promises.

Own It • Overcome challenges.

Background | 27

Our Network

2.3.1 Overview

In total the TLC network provides an electricity distribution service to over 24,000 connected customers covering 13,700 km2. It is one of the largest network areas in New Zealand without a major urban centre, and consequently has become a specialist in providing electrical distribution services to rural and sparsely populated areas. These areas include the highest points in the North Island of New Zealand (the Turoa and Whakapapa ski fields on Mount Ruapehu).

The region’s core economic industries are dairy farming, industrial processing (limestone and timber), mining (iron sand), and tourism. The network also includes popular ski fields with a consequent winter peak loading, plus an increasing uptake in holiday homes and tourist destinations, which can lead to significant swings in network loads in these regions from a low permanent resident base.

TLC’s network supplies ~381GWh of electricity per year and has a regulated asset base (RAB) value of $206 million (March 2019).

Figure 2.4: Our Network Region

Taharoa Otorohanga Waitomo Te Kuiti Mangakino Whakamaru Piopio

Benneydale Mokai

Mokau

Taumarunui

Turangi

National Park

Ohakune

Points of Supply (POS) to the TLC network are not only from Transpower grid exit points (GXPs), but also from major Waikato generation plants connected to our sub-transmission network. Supply to the network is also supported by a number of embedded hydro generators connected to the distribution network at 11kV and 33kV.

TLC is conscious that a safe and reliable electricity supply is a key enabler for regional economic growth, and our asset planning seeks to deliver improvements to support this objective.

Background | 28

Our network characteristics are influenced by our customers, our assets, our operating environment, our stakeholders and our network boundaries.

Figure 2.5: Key Influences on the TLC Network

2.3.2 Our Customers

TLC serves around 24,000 homes and businesses supplied through six points of supply being Hangatiki, Whakamaru, Ongarue, Tokaanu, National Park and Ohakune.

Our customers are a mix of high value industry, dairy farming, traditional residential customers and a high proportion of tenancy or holiday-based accommodation. Table 2.1 below sets out our customer profile with ICP numbers by category:

Table 2.1 Number of customers (ICPs) by category

Customer Group Customers % of ICPs

Accommodation 223 1%

Commercial 2,414 10%

Farming 3,039 13%

Holiday Home 3,599 15%

Major 114 0%

Residential 14,323 60%

Unmetered 87 0%

Other 203 1%

TOTAL 24,002 100%

Note:

1) Other is a combination of new, decommission in process and ICPs that are transitioning from one type to another.

Background | 29

Figure 2.6: Location of Major Customers Large Load Customers Taharoa There are several diverse, large load customers that Otorohanga generate considerable economic value to the region Waitomo and have increased reliability and quality Mangakino Te Kuiti requirements. A number of these facilities are on the Whakamaru end of long sections of network, with no alternative Piopio supply. As large load customers may not always be Mokai able to fund high levels of network security, there is a Benneydale heightened demand for network reliability as well as good communications for managing interruptions to Mokau

supply. These large load customers include the Taumarunui following and are also shown in the supply coverage map shown in Figure 2.6 Turangi • Iron sands processing and loading

• Ski fields National Park

• Corrections facilities

• Limestone extraction and processing Ohakune

• Meat processing

• Timber processing Major Customers Towns • Milk processing

• Glasshouse complex food production

2.3.3 Our Assets

TLC operates a sub-transmission network operating at 33 kV, connecting points of supply to zone substations. TLC’s network is one of the most geographically complex and distributed networks in New Zealand. Its key characteristics include:

• One of the smallest customer populations in New Zealand (ranking 20th out of 29 electricity distributors in terms of number of customers).

• A relatively long circuit length (12th out of 29 in terms of the length of network) and no large urban centres, resulting in a low customer per km ratio.

• Sparsely populated, with long lines in rugged terrain, and few alternative supply options.

• Embedded hydro generation that is reliant on rain and water inflows.

• A customer mix (and need) that is widely varied, being a mix of high-value primary sector industry, dairy farming, a relatively low proportion of traditional residential customers, and a high proportion of tenancy or holiday-based accommodation.

Background | 30

To address the geographic and customer characteristics, our network has a unique asset configuration, which includes:

• Few lines on roadsides and many across rugged mountainous terrain.

• Large numbers of Single Wire Earth Return (SWER) systems (60 plus).

• North Eastern areas supplied directly from major Waikato generation plants bypassing Transpower grid exit points (GXPs).

• A number of embedded hydro generators connected to the distribution network.

• Long lengths of 33kV network providing sub transmission.

• Long lengths of privately owned 11kV lines, often in remote rugged country.

The majority of the distribution network operates at 11kV and is characterised by long rural feeders across terrain that is difficult to access, and as such is prone to a higher level of interruption than typical, given its size.

2.3.4 Our Operating Environment

The environment we operate in is an important factor in delivering our services. The following factors determine our operating environment:

• Topography

• Geology and regional climate

• Land access

• Vegetation

• Access to human resource

• Decarbonisation and Government policy

• Technological changes

• Energy consumption trends

Topography

The topography of our supply area varies greatly from the iron-sand beaches on the west coast to the highest points in the North Island of New Zealand at the Turoa and Whakapapa ski fields on Mount Ruapehu. It is an area of steep, rolling hills and valleys dissected by rivers and streams. As a result, lines tend to go from hill to hill and predominately through remote rugged terrain.

Geology and Regional Climate

The King Country is a broad expanse of uplifted sedimentary rock west of the North Island main divide and central volcanic zone, and is part of a larger, geologically similar tract of land that includes inland Whanganui and Taranaki. Mountain ranges flank the King Country – the greywacke and argillite Hērangi Range in the west and the greywacke and ignimbrite Rangitoto and Hauhungaroa ranges to the east. The hills are siltstone, sandstone and mudstone.

Background | 31

TLC’s western coastal assets are subject to salt laden air; therefore, assets are chosen that perform well in this environment.

Thermal areas, such as Tokaanu, require components that can be installed in hot ground. In one case TLC obtained special dispensation to not follow Taupo District Council District plan for underground reticulations in urban areas, as the ground was too hot for an underground cable. TLC has also been compelled to install wooden poles in some regions due to the corrosive nature of the gases in the geothermal area that reduce the life of concrete poles.

Overall, the diversity of soil types of our network region (iron sand, peat soils, sandstone, pumice, etc.) along with the diversity of regional geological conditions (volcanic zones, coastal areas etc.) adds complexity to the design, construction and operation of our network.

Land Access

TLC has an extensive distribution system across private land in order to cost-effectively reach remote regions. Land access is fundamental to our continuing operations but is regularly constrained by climatic conditions (wet soils preventing vehicle access to hilly terrain during winter), and community considerations such as vehicle access across paddocks during lambing periods.

As a network operator TLC has existing rights under the Electricity Act 1992 for assets built prior to 1992. These rights give TLC to access and maintain the equipment constructed prior to 1992. Notwithstanding these rights, practical access is often restricted by the constraints mentioned above, and as such TLC has a relatively high use of helicopters to support construction and maintenance.

Vegetation

TLC’s distribution network crosses through dense vegetative and forested areas. As such TLC has a high exposure to faults resulting from tree fall, particularly during storm events. TLC invests significantly in vegetation management (tree-trimming) to maintain reliable supply to its rural customers and on Department of Conservation estates.

Access to Human Resource

The labour market supporting the electrical distribution industry continues to be ‘tight’, with it being very difficult to find sufficient skilled workers to carry out all planned works. This is expected to become more challenging as other companies around New Zealand embark on significant re-investment programmes over the next 10 years and reconstruction of infrastructure destroyed by the Australian bushfires commences. TLC is investing in its staff training and development including the continued recruitment of line mechanic trainees each year to assist in mitigating the risk that this skills shortage presents.

Decarbonisation and Government Policy

The New Zealand Government is committed to decarbonisation as part of the global response to climate change. The primary contributors to carbon production in New Zealand is agriculture and transport, and the focus of Government policy is on progressing towards electrification of the transport industry.

Electric vehicles (EVs) provide an opportunity for TLC to support New Zealand’s transition to a more environmentally friendly transport fleet. EVs are gradually increasing in number in New Zealand, driven by the emerging availability of suitably priced second-hand options and a push by the government to increase the number of EVs on the road. The charging requirements of EVs could see an increase in peak capacity requirements for the network if not carefully

Background | 32 managed. Consequently, we are planning our network to operate effectively and continue to support EV charging on our network as volumes grow.

Technological Changes

Solar energy at a domestic level is becoming more economically viable with an increasing trend in installation numbers across the country. Alternative business models are being developed whereby customers pay no money up front but receive discounted electricity from the installation of solar panels on their property. Over time this approach may see the aggregation of individual solar installations into virtual power plants. The uptake of solar in The Lines Company network is still relatively low and is not expected to increase materially in the short term, however consideration is being given as to how to manage the network in an environment where there is bi-directional power flow.

Battery storage technology is also emerging as a significant network consideration. It is currently being driven predominantly by the electric vehicle market, with the economics of domestic, distribution or grid battery systems still being generally unfavourable on a large scale when compared to traditional means of electricity distribution. It is expected that as further investment in battery technology and manufacturing takes place, the cost of battery systems will decrease and there will be an increase in the number of combined solar/battery-based systems at a domestic level. There are, however, a number of opportunities within the TLC network where moderate sized battery installations may provide a viable commercial and technical solution due to the remote nature of the customer installation and length of the associated connection to the network.

Where batteries by themselves are not viable, other technology options that integrate solar panels, batteries and diesel generation have been developed commercially, as stand-alone systems that often provide a more reliable and cost effective electricity supply to customers than the cost of replacement of a traditional distribution line.

The Internet of Things continues to evolve and influence the electricity industry as a whole. As a result, customers are becoming more engaged in their energy consumption through the increased visibility that is provided through connected sensors, presented in a user-friendly format on devices such as smart phones. There are a number of business from the very large (e.g. Apple, Amazon) through to small start-ups that are beginning to offer energy-based products and services to customers. This will drive change into the traditional electricity generation, distribution and retail model.

Energy Consumption Trends

Worldwide there is a trend toward more efficient use of electricity. In New Zealand this is being driven by

• Improvements in building standards seeing better insulation of newly constructed buildings

• Widespread uptake of heat pumps as an efficient means of home heating

• The evolution of LED lighting replacing traditional incandescent lamps

• The replacement of old appliances with modern energy efficient designs

• These changes have the effect of reducing consumption (kWh), however capacity requirements are increasing as more electrical equipment is used during peak times. In addition there is a gradual but steady transition of New Zealand’s transport energy from fossil fuels to electricity, which similarly increases energy consumption and demand on distribution networks.

Background | 33

Essential Services

TLC is a lifeline utility as defined in the Civil Defence Emergency Management Act 2002 and our network supplies electricity to a number other lifeline utilities and essential services as detailed below:

• District/Regional Councils – Water, waste water and roading infrastructure, emergency management

• New Zealand Transport Agency – Roading infrastructure

• Waikato District Health Board – Hospital services at Te Kuiti and Taumarunui

• Emergency Services – Police, Fire and Ambulance

• Telecommunications companies – Landline, mobile and internet

• Kiwirail – Rail infrastructure

Specific network needs and operational interactions are determined on a case by case basis with these entities.

2.3.5 Our Stakeholders

In considering the operation of our business we consider the wide and varied interests of the many stakeholders who have an interest in ensuring that our network continues to provide a safe, reliable and cost-effective electricity supply to our customers and community.

Two engagement models are used to understand stakeholder requirements

Representative: This model is used where the quantity of stakeholders is too large to consult with on an individual basis (e.g. customers and wider community). This engagement sees a mix of interaction with representative groups (e.g. community led organisations, Federated Farmers etc.), through to public meetings, customer clinics and customer panels held on a regular basis.

Direct: Where the stakeholder group is smaller, a direct engagement approach is used to understand specific requirements. This allows a more detailed level of interaction with individual stakeholders and allows us to optimize our approach to gain maximum benefit for all parties.

Our key Stakeholders and their principal interests are summarised below:

Table 2.2 Key Stakeholder Requirements

Key stakeholders Main Interests Engagement

Representative, direct Service quality and reliability; price; safety; connection for major customers or Our customers agreements where otherwise required

Communities, iwi, Public safety; environment; land access and respect for traditional Representative, direct landowners lands where required

Department of Environmental management; land access; supply to essential Direct Conservation services; emergency management

Regional and District Public safety; environmental management; land access; supply to Direct Councils essential services; emergency management

Background | 34

Employees and Safe, productive work environment; remuneration; training and Direct, representative contractors development; asset management documentation where required

Waitomo Energy Efficient management; financial performance; governance; risk Direct (via Board of Services Customer management Directors) Trust

Efficient management; financial performance; governance; risk Board of Directors Direct management

Commerce Pricing levels; effective governance; quality standards, reviews Direct Commission and audits leading to continual improvement

Business processes; access to the network; use of systems Electricity retailers Direct agreements; customer service

Workplace safety, (Worksafe); electrical compliance (Worksafe, Regulators Energy Safety); market operation and access (Electricity Direct Authority); environmental performance (Regional Councils)

Distributed Access to the network; connection agreements, price, operations Direct generators management

Load forecasting; GXP planning, technical performance; technical Transpower Direct compliance

Managing stakeholder conflicts of interest

Where material conflicts of interest emerge between different stakeholders, these are reported and discussed by the senior leadership team to form a resolution, followed by further engagement with the affected parties or their representatives. Cases with high impact (which may be both objective and subjective) are reported to and discussed with TLC’s Board of Directors.

2.3.6 Our Network Boundaries

TLC’s network crosses boundaries of seven district councils and three regional councils. In some cases, we provide electricity distribution and other services to these councils as customers. A high degree of co-ordination and interaction is required between TLC and councils to ensure that the services we collectively provide are safe, reliable and cost effective.

Table 2.3 List of Regional and Local Councils

Regional Council District Council

Otorohanga District Council

Waitomo District Council

Waikato Regional Council Taupo District Council

Waipa District Council

South Waikato District Council

Background | 35

Manawatu-Wanganui Regional Council Ruapehu District Council

Taranaki Regional Council New Plymouth District Council

The TLC network boundaries are defined as:

• Supply from Transpower: Supply from Transpower is at the connection to Transpower grid exit points, as defined in Transpower connection agreements.

• Supply from large Generation plants: At Whakamaru, Atiamuri and Mokai, the demarcation point is that defined in connection agreements.

• Supply from distributed generators: The asset boundary for distributed generators is the ‘Point of Connection’ as detailed in TLC’s Terms of Service.

• Supply to the Customer: Supply to the customer is at the customer’s ‘Point of Connection’ as defined in TLC’s Standard Terms of Service.

Company policy is to regard any line that supplies a property owned by a single entity as private regardless of voltage. The private lines start at the Point of Connection to the network and then travel to individual properties. The ‘Point of Connection’ may or may not be the ‘Point of Supply’. The ‘Point of Supply’ is defined in legislation and, in most cases, is the point where a line crosses the boundary to a property. If these lines were included in the assets owned by TLC, the likely line length increase would be a further 17% or approximately 730km.

These private lines can be non-compliant with present day codes and from time to time can cause faults that affect other customers. TLC carries out inspections on private lines free of charge and notifies customers when maintenance or issues of noncompliance are identified.

Background | 36

Network Assets | 37

3. Network Assets This chapter describes our network configuration and asset portfolio in detail.

Asset Summary

To summarise our assets we have grouped our distribution system (including Non-TLC supply points) into eleven portfolios described in Table 3.1. The key information for each portfolio is set out in the following sections.

Table 3.1: TLC’s Asset Portfolio

Portfolio Asset Class Population Transpower Grid Exit Points 5 Points of Supply Direct Generator Connections 3 TLC owned or controlled Hydro Generation Plants 3 Embedded Generators >1MW King Country Energy Owned Generation Plants 4

Zone Substations and power Buildings (including containers) 39 transformers Power transformers 40

Air-break switches and secitonalisers 111 Circuit breakers 46 Fuses and Fuse Links 7 Sub-Transmission Switchgear Load Break Switches 1 Reclosers 14 Solid Links 47 Transformer Fuses 8 Poles 34,085 Support structures Crossarms 51,208 Sub-transmission 456 Overhead conductors Distribution 3,069 Low Voltage 478 Sub-transmission 11 Cables Distribution 130 Low Voltage Underground cables 182 Ground mounted transformers 495 Distribution transformers Pole mounted transformers 4,709 Air-break switches 440 Circuit breakers 176 Fused switches / Fused Links 1,029 Load Break Switches 174 Distribution switches Reclosers 132 RTE switches 68 Sectionalisers 64 Solid Links 519 Transformer Fuses / Tap Off Fuses 5,604 SCADA and communication 927 Secondary systems Protection relays 278 Load Control Systems 10 LV Pillar Boxes Pillar Boxes 4146

Network Assets | 38

Points of Supply

3.2.1 Overview

The TLC network is supplied from eight locations which include five from Transpower’s Grid Exit Points (GXPs), two directly from hydro generators and one geothermal plant. Figure 3.1 shows a high-level depiction of the points of supply to the TLC Network.

Figure 3.1: Location of Major Points of Supply

Hangatiki Atiamuri Whakamaru

Mokai

Ongarue

Tokaanu

National Park 220 kV Transmission Line 110 kV Transmission Line Transpower Supply Point to TLC Ohakune Supply Point to TLC Tangiwai Major Generation Plant

Table 3.2 outlines the characteristics of each point of supply to the network, and the key loads supplied from each.

Table 3.2: Characteristics of Supply Points

Supply Points Description Key Load Types Served

Industrial loads Iron sand extraction Timber processing Supplied by three transformers with load below the Limestone processing Hangatiki GXP capacity of two transformers. Meat processing Distributed Generation (10.1MW) Rural loads (dry stock and dairy) Te Kuiti and Otorohanga towns

Rural loads Single transformer supply with backup via a 33kV line from Ongarue GXP Taumarunui town Tokaanu Distributed Generation (7.5MW)

Holiday accommodation Dual transformer supply with load below the capacity of Tokaanu GXP Corrections Department one transformer Turangi town

Whakapapa Ski field National Park Single transformer supply with backup via a 33kV line from Holiday accommodation GXP Tokaanu National Park Township

Network Assets | 39

Turoa Ski field Single transformer supply with limited backup from Ohakune GXP Holiday accommodation Tangiwai GXP Ohakune town Single transformer supply directly from the large hydro Dairy farming Whakamaru generators on the Waikato River with limited backup from Holiday accommodation Atiamuri)

Mokai Energy Single supply from Tuaropaki Mokai Geothermal Power Milk processing facilities Park station with limited backup Horticulture (glasshouses)

3.2.2 Summary of Points of Supply

Table 3.3 shows a summary of our supply points and outlines the level of security we have at each point and impact that a loss of supply would cause.

Table 3.3: Supply Point Summary

Operating Installed Trans- Cust. Peak Load 11kV or 33kV Supply Points Asset Owner Security Capacity former Serviced (MVA) Backup Level (MVA) Security Transpower / Hangatiki 9042 N-1 41.3 70 N-1 Light (2.0MVA) TLC1 Tokaanu Transpower 4870 N-1 10.9 40 N-1 Yes N-1 Ongarue Transpower 4638 13.3 20 N Yes Switched

2 Atiamuri TLC N-1 14.8 10 N Yes 2566 Whakamaru Tuaropaki Switched 10.0 23 N Yes Ohakune3 Transpower 2061 N3 8.0 20 N Light (2.0MVA) N-1 National Park Transpower 813 6.5 20 N Yes Switched Mokai TLC 13 N 4.8 7.5 N Light (1.0MVA)

Notes:

1. A third 110kV/33kV 30MVA Power transformer was commissioned at Hangatiki in 2019 bringing its transformer security to N-1.

2. Atiamuri is a backup supply for Whakamaru

3. Ohakune currently operates over the backup capacity of 2MVA for 40% of the year.

Network Assets | 40

Embedded Generators

3.3.1 On-Network Generation

TLC has six embedded hydro generating stations of greater than 1MW connected to its network. TLC operates and maintains two of these hydro generation sites. These are either wholly-owned or owned in partnership with landowners. The other four stations are owned by King Country Energy.

When available, generation output is used to support the operation of the network. However, as all of the generation has minimal storage the generation output is not essential to maintain supply to customers.

Table 3.4: Distributed Generation Summary

Ongarue GXP1 Hangatiki GXP2 Owner/Operator Station/Machine Rating (MW) Station/Machine Rating (MW) Kuratau 1 3.0 Wairere 4 3.0 Kuratau 2 3.0 Wairere 5 1.2 King Country Energy Piriaka 1 1.0 Mokauiti 1 1.0 Piriaka 2 0.3 Mokauiti 2 0.6 Piriaka 3 0.3 Mangapehi 1 1.5 The Lines Company Mangapehi 2 1.5 Speedys Road3 2.2

Notes:

1. Ongarue generation can be switched to support National Park or Tokaanu GXPs as required

2. With the exception of Speedys Road, Hangatiki generation can be switched to support Whakamaru POS on a limited basis

3. Speedys Road is 75% owned by TLC, with the remaining 25% owned by the landowner where the station is located.

3.3.2 Off-Network Generation

TLC owns and operates one off network hydro generation station that is embedded in Eastland Energy’s network.

Network Assets | 41

Zone Substations

3.4.1 Overview

TLC maintains and operates 28 zone substations that transform electricity from our 33kV sub-transmission network to supply our 11kV distribution network. Figure 3.2 shows TLC’s 33kV sub-transmission network and the location of its zone substations.

Our 33kV sub-transmission network is one of the longest in New Zealand at 456km and as such its exposure to faults caused by weather and vegetation related incidents is high. Sub-transmission line backups between points of supply are long and amongst the oldest parts of the network. Reliability-centered maintenance of the sub-transmission network is an essential part of our asset management approach, coupled with targeted reinvestment to minimise interruptions to customers’ supply.

Figure 3.2: TLCS’s Sub-Transmission (33kV) Network and Zone Substations

Taharoa Village Hangatiki Sub & GXP

Taharoa Te Waireka Arohena

Te Anga Waitete Maraetai Oparure Gadsby Rd Atiamuri POS Whakamaru POS Kaahu Te e Wairere Falls Marotiri Mokai POS

Maehoenui Ongarue Sub & GXP

Nihoniho Tuhua Awamate Kuratau Borough Kiko Rd Manunui

Turangi Waiotaka Otukou National Park Tokaanu Tawhai Sub & GXP Sub & GXP

Ohakune 33 kV Sub-transmission Line Sub & GXP TLC Zone Substation Transpower Supply Point to TLC Supply Point to TLC Major Generation Plant

Network Assets | 42

Table 3.5 shows a summary of the zone substations and their security levels.

TLC has a number of zone substations with single transformers and with light load backup from other substations via the 11kV distribution network. This places higher requirements for sub-transmission and zone substation maintenance and operational response to minimise interruptions to customers’ supply.

Table 3.5: Zone Substations Summary

Serviced Customers (MVA) PeakLoad (MVA) Capacity Installed Zone Operating Security Substation Substation Security Building Tfmr 33kV Bus 11kV

Level Strength (% of Line Back- new building up1 standard)2 Arohena 543 N 2.4 3 N N N Med Unassessed Awamate 308 N-1 Switched 1.4 2 N N N Yes 100% Borough 2833 N-1 8.5 20 N-1 N-1 N-1 Light 100% Gadsby Road 1283 N-1 Switched 5.6 5 N N-1 N Yes 100% Hangatiki 393 N 3.2 5 N N-1 N Light 20% Kaahu Tee 251 N 1.6 2 N N-1 N Med 100% Kiko Road 841 N-1 Switched - 3 N N N Yes No building Kuratau 1640 N4 2.5 8 N N-1 N No No building Mahoenui 617 N 0.9 3 N N N Med No building Manunui 1096 N 3 5 N N-1 N Light No building Maraetai 1259 N2 5.8 10 N N N Light Unassessed3 Marotiri 513 N-1 Switched 2.9 3 N N N Yes Unassessed National Park 621 N-1 Switched 1.9 3 N N-1 N Yes 100% Nihoniho 356 N-1 Switched 0.5 1.5 N N N Yes No building Oparure 72 N 1.7 3 N N N Light Unassessed Otukou 60 N 0.3 0.5 N N-1 N No No building Piripiri N/A N-1 Switched - 5 N N N Yes Unassessed Taharoa 1 N-1 15.8 15 N-1 N-1 N No Unassessed5 Taharoa Village 113 N-1 Switched 0.3 2 N N-1 N Yes 100% Tawhai 131 N 4.5 5 N N-1 N Light No building Te Anga 306 N-1 Switched 2.2 2 N N N Yes 100% Te Waireka 3051 N-1 11.1 30 N-1 N-1 N-1 Light 100% Tokaanu 79 N 0.2 1.25 N N-1 N No No building Tuhua 353 N-1 Switched 1.4 1.5 N N N Yes No building Turangi 1994 N 4.9 10 N-1 N N-1 Med >66% Waiotaka 6 N-1 Switched 2.3 2 N N N Yes 100% Wairere Falls 1339 N - 5 N-1 N N Med 100% Waitete 1867 N-13 9.4 15 N-1 N-1 N-1 Med 100% Direct from 2074 supply point

Network Assets | 43

Notes:

1. The 11kV backup designations mean: • No: There is no 11kV backup supply • Light backup: The 11kV system can supply < 20% of peak load • Medium backup: The 11kV system can supply 20% to 50% of peak load • Yes: The 11kV backup system can supply the total peak load of the substation

2. The substation building at Maraetai is not owned by TLC, and the switchgear currently contained within is being removed and mounted outside the building. 3. Only the secondary bus at Waitete is fully backed up. The primary bus cannot be fully backed up by the secondary bus. 4. Kuratau is currently N security due to the failure of one transformer. A 3 MVA transformer is currently in service and a backup 5MVA is in the process of being connected 5. The substation building at Taharoa is owned and maintained by Taharoa Ironsands Ltd.

Zone Substation Power Transformers

3.5.1 Summary of Power Transformers

Power transformers are primary plant that is used to feed power to or from our distribution network. The following table provides a general overview of our power transformers. The three categories are based on manufacturer as each has a different risk profile. The manufacturing defects that prompt this split are detailed further below.

Table 3.6: Power transformer overview

Description Alstom ETEL Other Quantity 5 7 28 Average Age (Years) 19 9 47 Expected Life (Years) 50 30 70

Network Assets | 44

Sub transmission 33kV Switchgear

3.6.1 Summary of Sub-transmission Switchgear

TLC has 234 sub-transmission switches. Some of the assets are located in zone substations and others are in the field on sub-transmission lines. The switch ages and condition vary, and they are renewed when no longer serviceable.

Table 3.7: Sub-transmission Switchgear Assets and Location

Description Field Zone Subs Total Air Break Switches 44 67 111 Circuit Breakers 6 40 46 Fused Links 2 5 7 Load Break Switches - 1 1 Reclosers 9 5 14 Solid Links 26 21 47 Transformer Fuses - 8 8 Total 87 147 234

Support Structures: Poles

3.7.1 Summary of Poles

TLC has 34,085 poles supporting its overhead line network. These are a mix of concrete, hardwood, softwood and iron rail. Most of the pole assets are pre-stressed concrete.

Table 3.8: Pole population by network configuration and pole type

Network Population Pole Material Description Pre-stressed Concrete Most of the poles supporting 33kV conductor are pre- Sub-transmission Mass reinforced Concrete stressed concrete. The population only includes the 3,412 Line (33 kV) Hardwood poles that support 33kV overhead conductor, with no Softwood additional underbuilt lower voltage conductors. Pre-stressed Concrete Over 60% of poles supporting 11kV conductors are Mass reinforced Concrete concrete, and the majority of them are pre-stressed. Distribution Line 25,565 Hardwood Poles that have 33 kV conductor above the 11kV (11 kV) Softwood conductor and/or low voltage conductor under built are Iron Rail included in this group. Hardwood Most of our poles supporting LV overhead conductor are Low Voltage Line 5,108 Softwood wooden poles. Iron Rail Total 34,085

Network Assets | 45

Support Structures: Crossarms

3.8.1 Summary of Crossarms

TLC has 51,208 cross arms in service, most of which are wooden.

Table 3.9: Crossarm by Network Configuration and Material

Network Population Description Subtransmission Line (33 kV) 3,551 Distribution Line (11 kV) 32,435 About 99% are wooden. Low Voltage Line 15,222 Total 51,208

The Crossarm summary above includes bolted (no crossarm), steel crossarms and wooden crossarms.

Overhead Line Conductor

3.9.1 Summary of Overhead Conductors

TLC has 4003 km of overhead line conductor, with the majority being 3-phase 11kV. However TLC has a substantial amount of 33kV (456 km) and 11kV Single wire Earth Return (SWER – 875 km) conductor, which are both proportionally higher than most NZ networks.

Table 3.10: Conductor Population

Overhead Conductors Line Length (km) Description Sub-transmission – 33 kV 456 Distribution – 11 kV 3 phase 2,195 Single Wire Earth Return systems (SWER) are single conductor lines. Distribution – 11 kV SWER 875 Two feeders (Tokaanu River and Pihanga) operate at 6.6kV to earth, all others operate at 11kV to earth. LV 478 Total 4,003

Notes: All overhead line length values are derived from crossarm data records in our asset database (Basix).

The 33kV subtransimission line length has reduced from our 2018 disclosure following data improvements in our asset database.

Network Assets | 46

Cables

3.10.1 Summary of Cables

Underground cables form a critical part of our network and are used largely to mitigate a cascade pole failure scenario around zone substations, and to reticulate the ski-field areas.

Table 3.11: Underground Cable Network Summary

Network Length (km) Cable Type Description Sub-transmission 4.4km of 33kV cable was installed at the Taharoa 11 Largely modern XLPE (33 kV) mine in 2017

50% of cabling is on the two ski fields on Mt Mostly older generation XLPE Ruapehu. Distribution cable in average condition. 130 The highest criticality cable on the network is the (11 kV) Steel wire armoured cables used main supply cable from Transpower at Ohakune. in the two ski fields. This cable circuit is approaching its capacity limit.

Includes solid core, double pass, Low Voltage 182 PVC insulated single core and Often no marking or mechanical protection stranded aluminium cables

Distribution Transformers

3.11.1 Summary of Distribution Transformers

TLC has 5204 distribution transformers in service, with the majority being pole mounted.

Table 3.12: Distribution Transformer Summary

Transformer Size (kVA)

<=15 30 50 100 200 300 500 >500 Total

Pole Mount

Single Phase 2558 260 38 36 19 0 0 0 2911

Two Phase 138 21 10 0 0 0 0 0 169

Three Phase 404 386 291 142 27 1 0 0 1251

Not recorded 378

Ground Mount

Single Phase 7 5 6 0 0 0 0 0 18

Three Phase 11 13 24 62 185 123 33 63 471

Not recorded 6

Total 3118 685 369 240 231 124 33 63 5,204

Network Assets | 47

Distribution Switches

3.12.1 Summary of Distribution Switches

TLC has 8,206 distribution switches in service, with the majority being ground mounted.

Table 3.13: 11kV Distribution Switchgear and Control Assets

Switch Type Pole Mt Ground Mt Total 11kV Air Break Switches 440 - 440 11kV Circuit Breakers 24 152 176 11kV Fused Switches/Fused Links 964 65 1,029 11kV Load Break Switches 16 158 174 11kV Reclosers 131 1 132 11kV RTE Integrated Transformer Switches - 68 68 11kV Sectionalisers 64 - 64 11kV Solid Links 519 - 519 11kV Transformer Fuses 4,995 3 4,998 11kV Tap-off Fuses 606 - 606 Total 7,759 447 8,206

Secondary Assets

Table 3.14 provides a summary of TLC’s secondary assets

Table 3.14: Secondary Assets Summary

Secondary Assets TLC has 113 voltage regulators. The majority of the sites have two relatively new Regulators single-phase regulators operating in open delta to give + 10% regulation. Devices fitted with protection relays fall into a 5 yearly inspection program. Older style Protection Relays electromechanical relays are being changed out to electronic relays where required with switchgear upgrades. Where possible Arc Flash detection is included. TLC operates two generations of ripple systems, one in the southern part of the network (317Hz Decabit) and a combination of new (317Hz Decabit) and old (725Hz Semagyr) in the north. Ripple Injection Systems The 725 Hz system is being phased out as meters around the network are replaced with smart meters that have internal ripple control capabilities. The 725 Hz ripple control transmitters are decommissioned as the meter installation programme is concluded in each 11kV zone in the northern network. TLC network uses a Lester Abbey central control system and RTUs to automate our 27 SCADA System zone substations, and other assets essential to maintaining network performance The UHF data communication system consists of a head end and 12 repeater sites Data Communication (excluding individual RTU radios) using both analog and digital technology, operating on two channels. A frequency modulated voice communication system consisting of six repeaters, linking Voice Radio Equipment equipment and radios in the mobile fleet is owned and operated by TLC

Network Assets | 48

Mobile Emergency Generator and TLC owns a mobile generator, protection transformer, and circuit breaker capable of Injection Transformer injecting into the 11kV network under emergency or shutdown conditions TLC has an 11kV mobile capacitor bank and 4 fixed capacitor bank units that are rated Capacitor Banks at 1MVAr. TLC, through a subsidiary company (FCL Metering), owns the majority of customer Metering Assets meters and relays. It also owns interconnection metering assets at Whakamaru, Mokai and Tangiwai.

Asset Data Accuracy

Data accuracy varies across the asset base and is steadily being refined and improved as both inspections and work are completed on the network.

It is estimated that accurate distribution and sub transmission line condition data is held for around 80% of the network, with this information having been gathered as part of the line inspection programme which has been running for the past 14 years. The level of accuracy held on low voltage lines remains low as the focus remains on gathering information on and improving the performance of the distribution and sub-transmission networks.

Age related data is uncertain across a number of asset classes, largely as a result of the various changes in ownership over time and consequently a number of assets have a default commissioning date (typically 1980). TLC is commencing a data cleansing programme to increase accuracy of age and condition related data for these assets which is detailed in Section 5 of this AMP.

Network Assets | 49

Approach to Asset Management | 50

4. Introduction This chapter explains our asset management policy and process. It sets out how we translate our business strategy and objectives into our day-to-day investment and operational decisions ensuring effective line of sight between business goals and asset management practice.

TLC is transitioning its asset management approach to align with the ISO 55000 framework. As part of this an assessment against the requirements of ISO 55001:2014 was conducted and alignment with a four-pillar interpretation of that standard has been adopted as summarised below:

• Leadership and Enablement of the asset management approach which is aligned with TLC’s business objectives, and meets the requirements of both external and internal stakeholders;

• Asset Planning - a detailed end-to-end planning process across the asset portfolio which commences with risk profiling of the assets, through options analysis in the Capital Plan.

• Business Processes - well defined quality processes for the delivery of CAPEX and OPEX work to the assets along with other tasks such as switching, investigations, materials supply and so forth. The intent is to reduce the cost of work through quality management, assure consistency of approach and promote the competency of all teams involved with service delivery.

• Continual improvement – consistently improving asset management processes as well as determining future options for network resilience and reliability.

Asset Management System

The TLC Asset Management System is shown overleaf as a structured framework with multiple functions which work together to deliver the asset management pillars listed above. Implicit in this framework is a quality management approach, based on ISO 55001, leading to continual improvement to reduce the overall cost of asset ownership as well as manage risk within defined risk appetites. Figure 4.1 shows our current asset management process. This will further evolve over time as TLC continues to develop its people, processes and systems to strengthen its alignment with the ISO 55001 methodologies.

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Figure 4.1: Our Asset Management System

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Asset Management Policy

Our Asset Management Policy sets out high level asset management principles that link our Company Strategic Framework to our Asset Management Objectives.

The Lines Company Asset Management Policy

Leadership and Enablement

1. Safety is our highest priority, with a proactive approach to the safety of all personnel who work on our network, our communities who live, work and play near our network, and our customers who use electricity from our network.

2. Asset management is how we realise sustainable value for our shareholder, community and customers through balancing the opportunities, risks and costs against the desired performance of our physical assets

3. Asset management will be delivered by an informed leadership who communicate to and engage with external and internal stakeholders to ensure an efficient approach which is cognisant of both current and future requirements of those stakeholders and the company.

Asset Planning

4. We will provide services that meet our customers’ needs, including minimising planned network outages, reducing unplanned outages and delivering electricity to our customers at an efficient price through planning and scheduling the work in advance.

5. We will prioritise investment into our network to focus on areas that provide the best overall value to our customers and community.

6. We focus on maintaining network reliability at the least possible life cycle cost, addressing an aging asset base and low population densities.

7. Asset planning will consider options other than capital replacement to address issues associated with compliance, condition and performance.

8. We will seek out and implement new and emerging technology where a demonstrable benefit in cost, risk or performance is determined.

9. We will endeavour to remain compliant with our regulatory requirements, as set out by the Commerce Commission, for all measures of our quality and asset management performance, by appropriately and cost effectively managing our asset and network risk.

Business Processes

10. TLC is committed to ensuring rigorous risk management processes are in place including the development of Tier 2 and 3 risk registers.

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11. To implement risk management effectively, it must be integrated into TLC’s business operations, projects and decision-making processes. It is part of our mind set and integral to the way we do things.

Continual Improvement

12. Network services will be continually monitored, and this information used to determine future asset renewal work.

13. We will continually enhance our community reputation through ongoing improvements in services and improvements in cost versus risk management of the network.

14. We will collaborate with our industry peers and partners drawing on their experience and expertise to improve the performance of our network.

Asset Management Objectives

Table 4.1: Asset Management Objectives

Asset Management Policy Area Asset Management Objectives

Leadership and Enablement

Safety specifications are clear Operational targets are defined Safety is our top priority Cost control processes are defined

Appropriate work practices and design standards are provided to assure Asset management is how we realise power quality and minimise security risk sustainable value from the physical assets Capital planning processes are defined

Asset requirements to achieve our license to operate are clear and Asset management will be delivered by an incorporated into project, operating and maintenance processes informed leadership Asset management-relevant community, environmental and sustainability safeguards and obligations are clear

Asset Planning

Safety integrated into design, asset specifications and work planning Our customers’ experience will be enhanced Credible long-term budgets are developed based on information about the

operations and the assets We are focused on maintaining network Asset planning is optimised for life cycle cost and operational performance reliability at the least possible life cycle cost Optimal supply and risk to power quality and security is a planning

consideration Asset planning will consider options other Capital work planning considers business case targets and is optimised for life than capital replacement cycle cost and resources

Asset planning outcomes are consistent with the requirements of the license We will implement new and emerging to operate technology where these provide advantages Asset work planning considers environmental standards and obligations

Business Process

We will deliver quality work through Capital investment is consistent with the approved long-term budgets competent teams and efficient processes. Work is timely and completed within budget

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Service level performance will be met or Faults and risk to network reliability are managed to reduce unplanned exceeded interruptions Capital work is undertaken as per plan with effective management of Our asset management approach will be contingencies to address risk to cost, quality and the design outcome supported by an integrated management Work is planned for effective use of resources system Asset-specific sustainability safeguards and community engagement steps are incorporated into the work delivered

Continual Improvement

Safety performance is measured Operational performance including customer satisfaction and on-time fault response measured and reported Network reliability and quality of supply will be continually monitored Expenditure is monitored, and budget compliance reported Faults measured, and asset-related incidents correlated with asset condition and work history We will continually enhance our community reputation Capital projects are assessed for compliance to the business case targets, cost control and performance

Compliance of work and asset performance to the license to operate is We will collaborate with industry peers and measured and reported partners Breaches of asset-induced environmental protection and non-compliances in environment and sustainability audits are reported along with their level of severity

Asset Management Accountabilities

Asset management is a multi-level process involving governance, management and execution for many areas of the business. Table 4.2 shows the accountabilities across the TLC business as they relate to the asset management process.

Table 4.2: Asset Management Accountabilities

Role Accountability

Set strategic direction of business Board Approve and monitor risk appetite and associated risk management framework Review and approve Asset Management Plan (AMP) and associated budgets

Develop and implement Business Plan Chief Executive Enable delivery of AMP outputs

Monitor the implementation of the Asset Management Policy and Objectives Asset Management Review material network risks Committee Monitor the condition and performance of the assets and ensure they are maintained Review changes to key policies that impact the network assets and expenditure plans

Develop and implement Asset Management Framework GM Network Produce annual AMP Manage and monitor delivery of AMP outputs.

Assess feedback on asset health and performance which need to be addressed in the AMP and/or Asset Strategy require updates of the asset class strategies Manager Review and rationalise risk ranking of issues and proposed work in the AMP

Determine requirements for capitalised maintenance and major asset renewals

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Schedule a pipeline of project work to be prioritised, planned and scheduled Development and budget estimate of the short-term work from the AMP Refinement of scopes of work and cost estimates Annual scheduling of major work

Define criteria for monitoring of asset health, risk and performance Specify equipment and installation standards for assets Develop the preventative maintenance schedule of asset surveillance. Determine feedback Asset Engineers requirements and trigger points on asset condition Monitor equipment condition following maintenance inspections and advise when remedial action or renewals should take place

Address load constraints and risks to voltage compliance across the network Network Performance Develop strategies to reduce unplanned SAIDI Engineer Planning for network growth Scenario analysis to consider impact of disruptive technology on the network

Profiling and budgeting for expected customer driven growth Commercial Manager Engagement with major customers on scheduled future work

Manage the AMP information systems Manager, Asset Report on the risk and cost profiles within the AMP Information Report on the preventative maintenance schedule in the asset information system Manage asset condition data

Detailed planning of work packages from the AMP Manager, Network Delivery of project work Services Delivery of the preventative maintenance schedule

Collect condition data and provide feedback on faults response plus other repairs

4.4.1 AMP Governance

Asset Management decisions are authorised according to The Lines Company’s Delegated Financial Authority policy, which defines the capital and operational expenditure limits of the Senior Leadership Team. Separate limits are defined for budgeted and unbudgeted expenditure. Any expenditure that exceeds these limits is submitted to the Board of Directors with a business case for separate consideration and approval.

The asset management capital and maintenance programmes are reported to the Board of Directors by the Senior Leadership Team as part of the Board reporting cycle, with explanatory notes on deviations from the plan.

Risk Management

Risk management is a fundamental asset management discipline. It requires robust processes in place to assess and manage all business-related risk. We are transitioning our risk management processes to align with ISO 31000:2009 commencing with Tier 1 as detailed below

Risk is defined as the effect of uncertainty on the ability of an organisation to meet its objectives. The purpose of a risk management framework is to actively apply risk treatment options, so that TLC can ensure any uncertainties of meeting its objectives can be avoided, reduced, removed, or managed.

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4.5.1 Tier 1 Risk Management Framework

Tier 1 risks are those risks that are visible to the Board with accountability for managing them assigned to a Senior Leadership Team member. The Board is involved in setting the Company risk appetite for each type of risk identified.

Risk identification and evaluation encompasses assessment of the following areas

• People safety and resource availability.

• Stakeholder confidence/reputation; environmental and cultural (ngā taonga tuku iho nō ngā tūpuna) preservation.

• Commercial/financial sustainability.

• Performance of core services.

• Regulatory.

Following identification of the risks, strategies and processes to manage risks in line with the business’ risk appetite are implemented. These efforts are supported by a comprehensive risk monitoring and reporting regime, with visibility provided to the Board Audit, Risk and Finance Committee on a bi-annual basis and any changes to Tier 1 risks reported to the Board as part of regular Management reporting.

4.5.2 Tier 2 & 3 Risks

Tier 2 and 3 risks are currently managed within individual business units in a manner that best reflects the needs of the business unit. Tier 2 and 3 risks are being aligned with the Tier 1 risk framework across the company to enable a consistent approach to managing risks. This will allow common and cascading risks to be identified and ensure they are managed appropriately.

Detailed asset related risk is currently considered at both Tier 2 and 3 levels and is used as a means to prioritise activity developed as part of the asset management process. The assessment methodology is further detailed in Section 4.6.5.

Life Cycle Management

Management of our assets is based on taking a whole of life approach to asset management. Our interpretation of the life cycle is shown in Figure 4.2.

Figure 4.2: Asset Life Cycle Process

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A detailed description of TLC’s asset life cycle management is provided in the following sections.

4.6.1 Plan

Planning is the processes of identifying specific network requirements that will deliver stakeholder expectations for service and price, investigating options and authorisation of expenditures.

Our capital project planning and acquisition process consists of the following steps:

Needs identification

There are three broad categories to our planning; asset renewals, network development (to address growth and security requirements) and customer required work.

Asset Renewals

Needs identification for asset renewal planning uses the information gathered from condition, reliability and risk assessments. This ensures that assets that have been identified as approaching end of life or are a high safety risk, are scheduled for renewal. An assessment is made on the scope of the renewal, which may comprise refurbishment, overhaul or outright replacement.

Network Development

Monitoring and modelling of network performance and customer load use patterns drives investment planning for network development purposes. This assessment takes a medium to long term view of network requirements to ensure that performance remains within statutory limits and that incremental growth due to changes in population and network configuration are able to be accommodated with minimal impact. Asset relocation for improving security or quality of supply is also included in this category.

Customer Required

Customer required work is usually initiated by a major customer due to establishment of a new plant or a change in the electricity requirements of an existing plant. Agreement is reached with the customer on how to fund this development, which may see a full or partial capital contribution from the customer with any additional funding requirements being met through ongoing connection charges.

Prioritisation

Prioritisation of asset renewal and network development projects is carried out based on risk assessment outlined in in Section 4.6.5, which includes asset related risks and business related risks. This process analyses consequences including safety, loss of load or loss of security, and a likelihood of occurrence. Prioritisation of customer required projects is based largely on the timing requirements of the customer. Once the assessment process is complete, a ranked list of capital projects is produced.

Development of Proposals

Proposals for identified capital projects are developed to ensure all requirements are identified and incorporated into the planning process, and that financial approval is gained in line with company delegated authorities.

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The development process includes the following:

• Scope technical and performance requirements.

• Identify any project pre-requisites (e.g. land access, consenting, design, and procurement lead times).

• Consider alignment with other projects to minimise cost and outage impacts.

• Consideration of the use of standardised designs or asset types to minimise lifecycle costs.

• Consideration of alternative options, including non-network options, if these present lower cost outcomes.

• Schedule projects across the planning period (10 years).

• Where projects are identified for years 1-3, more detailed planning (Design & Construct) commences.

Financial and Outage Budgeting

The financial budget is based on a combination of historical project information and estimation of costs through TLC’s Network Services business unit. Following the development of proposals, cost estimates for projects are co-optimised with outage availability. This is to ensure that an optimal point is met between the cost of delivering the project, and the outage impact that it will have when the work is carried out.

This includes:

• Phasing of planned outages to ensure they are executed at the optimal time of year (consideration is given to weather patterns, land access, dairy season and historical outages)

• Use of generators to reduce customer outages (cost versus outage co-optimisation)

• Additional resourcing to reduce the time associated with a project outage

Formation of Annual Capital Plans

The outputs from the preceding stages that result in projects in year 1 are consolidated and assessed at a Management and Board level to ensure that all identified risks have been managed within the Company’s risk appetite, and once complete the capital spend is confirmed.

Detailed planning for execution of project work then commences.

4.6.2 Design and Construct

Design and construct is the implementation of the planning process through works delivery.

Design

In house design capability is maintained for line related works. New lines are designed to AS/NZS7000. Minor design changes to other asset classes are carried out by internal engineering staff where resource and skillset allows. Major projects on asset classes other than lines and pole mounted equipment are completed by external parties. The impact of any changes to design or introduction of new equipment are assessed by engineering staff as part of the design review process. Soil condition and climate impact on assets is assessed in the design phase.

Construct

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Line related construction activity is carried out by the Network Services business unit, with support from key contractors where needed to manage resource or outage constraints. Network Services also carries out minor project works where their skillset and resource allow.

Major projects (e.g. construction or renewal of zone substations) are outsourced either as a design and build package or design is completed by specialists with construction contracted out separately.

Project related work is usually managed using the internal project management team to ensure that TLC stakeholder, technical and commercial requirements for work completed are met.

4.6.3 Operate and Maintain

Operate and maintain means that TLC operates the network and assets in such a way as to deliver the service levels sought by customers, in line with our regulatory requirements, and effectively maintain the equipment and network through defect identification and planned maintenance activities. Network operations and our approach to maintenance are detailed in Section 6 and summarised below:

Preventive Maintenance

Preventative maintenance is predominantly condition, operating cycle, or time based maintenance and involves the collection of operational and asset condition information through site inspection, asset routine service and asset condition test. TLC’s preventive maintenance strategy seeks to provide essential information about the health of the assets, reduce preventable defects and meet all statutory obligations.

Our preventive maintenance schedule ensures that routine work is scheduled as required to ensure TLC’s assets meet all performance requirements and remain compliant with regulations. The schedule is defined by and managed in accordance with the strategy approved by the Asset Engineers and budgeted in the Annual Works Plan.

Reactive Maintenance

TLC’s reactive maintenance comprises fixing defects identified from preventative maintenance inspections and fault response. Focused primarily on fault response, reactive maintenance makes up the largest proportion of our maintenance by spend. The majority of reactive maintenance spend is driven by external factors (generally weather, vegetation and third-party related events) rather than a high rate of asset failure. The balance between preventative and reactive maintenance is monitored on an ongoing basis to ensure the network performance is maintained to target levels in the most cost-efficient manner.

Maintenance Scheduling

Preventative maintenance activities are scheduled as part of the annual planning process and are based on the current understanding of asset condition and performance requirements for the planning period. These activities are incorporated into the annual works plan. Planned maintenance activities are scheduled such that they do not create resource or outage constraints during peak work times, which often means this work carried out during winter when land access for line renewal work is constrained.

Financial and Resource Budgeting

An allowance for both cost and resource for corrective maintenance is made in the annual planning process. This is based on historical requirements and as noted above is driven largely by weather, vegetation and third-party events.

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4.6.4 Assess Asset Condition, Renew or Dispose

Asset condition assessment is the process of identifying assets which meet the end of life criteria and to decide when to renew and/or dispose of assets.

An essential part of managing the life cycle of our assets is understanding their condition, the impact that has on overall reliability of the network and the business risk that the combined condition and reliability presents. The following sections outline our approach to this.

Condition Assessment

The condition of assets is assessed through a combination of factors. At the time of commissioning an expected life is applied to an asset based on its design and performance of similar assets. This provides a baseline view of expected life assuming the asset is operated within design parameters and required maintenance is completed. Failure modes for the asset are identified and, where possible, indicators of these failure modes are monitored during preventative inspections or when routine or corrective maintenance is carried out.

The majority of TLC’s assets are assessed on a combination of age and observed condition basis with engineering judgment applied to determine when best to renew them.

Reliability Assessment

Overall reliability of the network is monitored using the SAIDI and SAIFI performance targets determined by the Commerce Commission. Detailed analysis of historical faults has been completed in the development of this Asset Management Plan with plans developed to target underperforming asset classes and areas of the network. Network reliability is monitored on a daily, weekly and monthly basis at various levels of the organisation to ensure targeted service levels are achieved.

4.6.5 Asset Risk Assessments and AMP Prioritisation

Risk assessments are completed on in service assets to understand the overall effect that a failure of that asset may have on the performance of the network. These risk assessments are also used in the prioritisation of project work within the Asset Management Plan.

The following methodology is used to assess asset related risk

Likelihood

Probability of Likelihood Score Notes Failure (per annum) 1 <1% Type of problem has not occurred previously in the industry 2 1-2% Type of problem has not occurred in TLC but has occurred in the industry 3 2-10% Type of problem has occurred in TLC previously Has occurred at that location previously or a comparable location (similar 4 11-20% environment, utilisation, make and model of equipment etc.) 5 >20% Almost assured to occur at that location

Consequence

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Consequence Consideration Notes Score No features that make it more 1 likely to attract funding than Unlikely to have any noticeable impact any other issue Some network performance May affect the backbone of a distribution feeder or be a sub 2 consequence in one category transmission asset which has some issues (e.g. environmental risk) This issue has been assessed as significant in more than one Likely to have a significant impact on network performance as well as 3 consequence category (e.g. safety, compliance or environmental loss of supply to customers, financial, environment etc) High level of network May result in a widespread interruption to critical load or long duration 4 performance consequence of many hours to affected customers. A consequence of high in more Urgent review is carried out to see whether this work should be 5 than one category expedited.

Detectability

Detectability Score Consideration 1 Will always detect the failure before it occurs 2 High probability of detecting the failure before it occurs. Preceded by a warning most of the time 3 Moderate probability of failure before it occurs. Around 50% likelihood of getting a warning 4 Low probability of detecting a failure before it occurs. Always occurs with little or no warning 5 Remote probability of detecting a failure before it occurs. Always occurs without warning

Mitigation

Mitigation Score Consideration The proposed solution will completely resolve the issue and no further work will be needed within the 100% foreseeable future 80% It is likely that further work will be needed in 5-10 years 40% It is likely that further work will be needed in 2-5 years 20% There is a high likelihood that further work will be needed within the next two years

The ratings above are combined to provide three metrics, which are used both to determine asset risks profiles and planned project values.

Metrics

Metric Description Calculation Inherent Risk The current risk Likelihood * Consequence * Detectability

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Residual Risk Remaining risk once mitigation work is completed Inherent Risk – (Inherent Risk * Mitigation) Assessment of the effectiveness of any project work Project Value Inherent Risk – Residual Risk carried out to address the risk

All other things being equal, the higher the project value, the more priority that will be given to the proposed work within the AMP.

Information Systems

4.7.1 Systems Overview

To assist in managing our assets, TLC operates four core Information Technology platforms.

• BASIX Asset Management

• Navision Financial System

• Orion Billing Management

• ESRI GIS Platform

Key information is exchanged between three of these systems automatically as demonstrated in a simplified format in Figure 4.3. The ESRI GIS platform currently operates independently of these systems.

Figure 4.3: Overview of System Layout and Interaction

4.7.2 BASIX

BASIX is our core asset management system and used as a tool to support and provide information for our asset management processes and planning. It contains asset data and is used to calculate reliability statistics and regulatory valuations. It also produces reports that align with the network performance criteria.

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The system comprises various modules including:

• Regulatory Asset Register

• Works Management

• Outage and Reliability

• Reporting

• Annual Planning

Assets are organized into a hierarchy allowing both vertical (e.g. feeder or substation) and horizontal (asset class, e.g. distribution transformer) analysis and reporting.

The asset register is used to access the network data and is broken down into:

• Lines

• Installations

• Zone substations

• Transformers

• Switchgear

• Protection and Control

• Network Model

• Property

• Batteries

• SCADA & Radio

Details of proposed projects that result from the Asset Management Planning process are entered into the annual planning section of the BASIX database, providing an ongoing reference and ability to track progress against plan in a structured manner. Financial forecasts are then extracted from the database for AMP and disclosure purposes.

4.7.3 Navision

Navision is the Company’s financial system and is also used by the Network Services business unit to track and record costs associated with work carried out for the Network and external customers.

4.7.4 Orion

Orion is the customer billing system. It is used to track individual customer consumption at peak, shoulder and off- peak times, along with other customer specific information related to customer communications line charge categorisation and billing.

4.7.5 ESRI Geographical Information System (GIS)

The ESRI GIS system primarily records geographical information for TLC’s assets. The system is currently stand alone and is used to identify where assets currently or may, in the future impact property owners.

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Business Continuity Planning

TLC manages business continuity risk through the implementation of Incident Management Framework. The framework is based on Civil Defense Coordinanted Incident Management System (CIMS) and uses the Four Rs of Emergency Preparedness Reduction, Readiness, Response and Recovery.

The Incident Management Framework identifies a Duty Manager who is able act as Incident Controller during an emergency event. If necessary, an incident management team will be established to ensure that any public and staff safety risk is minimised and that our obligations as a lifeline utility are able to be met with minimal interruption to supply.

Reduction of business risk is managed through the organisational risk framework detailed in section 4.5. This sees risk management plans implemented to reduce either the likelihood and/or consequence of an event occurring that would have a negative impact on the business. At an asset level risk is managed through ongoing monitoring, maintenance and renewal of assets as determined in the asset class strategies and this Asset Management Plan.

Readiness for an emergency event is covered at multiple levels through the organisation. The Incident Management Plan provides a generic emergency management framework which includes:

• required to co-ordinate emergency response activities during an event.

• Background and reference information.

• Contact details for internal and external parties and key stakeholders.

• Communication systems, options and protocols.

• Defined responsibilities for readiness and for response.

A number of specific incident response guides are either developed or under development as detailed below:

• Serious Injury/Fatality

• Significant threat to employees

• Environmental Incident

• Medical Emergency

• Building relocation

• Cyber Security breach or IT system failure

• Earthquake

• Volcano

• Major Storm Activity

• Significant Asset Failure

• Network Event

• Pandemic

Desktop emergency exercises are conducted to give staff exposure to the incident management framework and identify any areas of improvement required in either business process or field response during an emergency.

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Staff are also encouraged to ensure they and their family are prepared for major disasters.

Response to an event is determined depending on the cause and extent. The Incident Management Plan makes provision for establishment of a small incident management team for local events, network event management teams in the event of a major network incident, and a full incident response team including the Board should it be deemed necessary by the Incident Controller.

Following any activation of the Incident Management Plan, an event review is conducted with any learnings incorporated into the Incident Management Framework for use during future events.

Recovery following an incident is managed on a case by case basis with input from appropriate levels within the organisation as required.

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Capital Project Planning and Delivery | 67

5. Capital Project Planning & Delivery This chapter explains our approach to planning our network capital investment and provides a summary of the Capex for the next ten years.

Introduction

Our capital projects contribute to the long-term reliability of our network and supply security as well as risk mitigation. In total we manage around 700 individual projects across the ten-year planning period which are reviewed and adjusted each year. When we set our capital programme, we set short and long-term objectives which guides the project prioritisation and resource management.

5.1.1 Capital Project Portfolio – Key Objectives

The objectives of the 2020 AMP maintain consistency with the 2018 and 2019 AMPs, because they remain relevant and in progress. They are:

• Improving Safety

The 2018 AMP identified a number of ground mounted (tin shed) transformers that presented both public and staff safety risks and outlined a four-year replacement plan. TLC is progressing through this plan and is mid-way through its priority two transformer upgrades. In addition, TLC is seeking to improve protection of the cables at the Whakapapa Ski Field. These programmes will continue in the 2020 AMP.

• Managing reliability

Unplanned outages remain a key issue for the business despite increased focus and expenditure on this issue over the last three years. In the 2020 AMP we are broadening our approach to understanding and addressing reliability including:

o Improving how we collect, analyse and apply asset and network data to estimate the probability of an outage o How we mitigate the impact of outages when they occur (e.g. the installation of sectional break switches to limit and isolate faults) o How we assess and apply vegetation management to minimise outages o Developing our systems and asset management practices • Alleviating security of supply constraints

Although we have made significant progress in alleviating security of supply constraints in the last two years, this remains a work in progress. The key drivers are customer growth and failures of key assets (power transformers) which are both maintaining pressure on security of supply. This means that TLC must continue investment to strengthen its security of supply through further substation development in the short to medium term.

• Building Resilience in TLC’s Power Transformer Fleet

In recent years, TLC has experienced a number of power transformer failures. To alleviate this new power transformers have been ordered and will be deployed in the early stages of the ten-year planning period, commencing with a major upgrade of the Waitete substation. This release the existing transformers for a

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cascading zone substation upgrade programme, creating greater power transformer resilience across the network.

• Maintaining a sustainable line renewal programme

TLC has made good progress in its line renewal programme in the last two years. This needs to continue for two reasons – first to continue to lift network resilience, and second to bring the asset age and condition profile to a level that will reduce TLC’s longer-term line renewal programme to a sustainable level.

• Supporting customer growth

Enabling customer growth is important for regional economic development. TLC is engaging with customers on several major projects at the current time, and consequently has incorporated significant project resourcing in this asset management plan to support these initiatives.

5.1.2 How this section is structured

This section is outlines our investment across five key categories. These are:

Section Purpose 5.2 Asset Renewal Asset renewal projects address areas of asset condition related risk, safety and environmental issues. The investment primarily covers asset renewal and refurbishment driven by the reasons above. The asset categories covered in this section include: • Overhead Lines • Switchgear • Transformers • Cables 5.3 Network Reliability Network reliability projects focus on reducing the occurrences and impacts of outages on customers. 5.4 Network Development Network development projects focus on adding asset capability to cater for growth and to maintain supply security. 5.5 Customer Projects Customer projects are driven by customer specific needs but may also trigger investment in upstream assets to increase system capacity to support that demand. 5.6 Non Network Assets Non Network projects are related to supporting the business operations including computers, office costs and assets related to the TLC organisational support functions.

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5.1.3 How this section aligns with Commerce Commission investment categories

When developing our expenditure plan, TLC considers the current business drivers and the key objectives related to each asset portfolio. Each asset portfolio covers a range of investment categories that TLC is required to report on in its Information Disclosure to the Commerce Commission. The table below shows the association between investment category in the Information Disclosure and TLC’s capital investment portfolio, and the key business drivers. Often one business driver is associated with multiple investment categories and appears in more than one project type.

Table 5.1: Capital Investment Portfolio

Investment Category Portfolio Business Drivers (Commerce Commission) Equipment renewals Asset replacement and renewal Asset Renewal Hazardous equipment Other Reliability, safety and environment Safety

Network Reliability Other Reliability, safety and environment Network Reliability

System growth Security of supply Network Development Quality of supply Quality of supply Consumer connection Customer Required Cumulative capacity Asset relocations Non-system fixed assets – Atypical Non Network Business support Non-system fixed assets - routine

5.1.4 Deferral of Investment – a key consideration before we invest

Although maintaining our electricity supply assets requires ongoing investment, TLC endeavours to defer investment and maximise the life cycle of its assets where it makes sense to do so having regard for risk, economic outcomes and customer service. We have undertaken several innovations that defer asset replacements by easing network constraints. These include: • Use of Mobile and fixed power factor correction capacitor banks. Mobile capacitor banks are a bank of capacitors mounted on a trailer that can be deployed at short notice to support network constraints during faults or outages.

• Installation of voltage regulators. TLC uses voltage regulators extensively in its rural reticulation. These improve power quality and allow small conductors to remain in service which defers reconductoring projects.

• Extensive deployment of load control and metering technologies that enables shedding of up to 16MW load (25% of our coincident GXP demand) at critical times.

• Time of use pricing that incentivises customers to shift load out of peak times, and to utilise controlled water heating.

• Use of drones for confirming line condition prior to replacement. In the last twelve months we have used drones to verify asset condition prior to commencing planned line renewal work. This has resulted in some projects being de-prioritised and their replacement deferred.

• Development of Business Intelligence (BI) tools. We are investing in business intelligence technologies and systems to provide deeper analysis of our assets and their performance. This is providing new insights on how

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our assets perform against a range of environmental and electrical conditions, allowing more informed decisions in our asset renewal planning.

Asset Renewal

5.2.1 Introduction

Asset renewal is expenditure that focuses on replacing an asset because it has reached its end of life, or because it presents a safety, reliability, environmental or performance issue or risk. Our decision to replace an asset may be driven by a single issue related to performance, condition or other factor, or a combination of these.

5.2.2 Our Key Asset Renewal Objectives

Our key objectives in our asset renewal programme are:

• To alleviate safety risks related to our wooden and tin-shed enclosed ground mount transformers

• To improve safety and reliability of our 11kV cables

• To improve the reliability of our power transformer fleet and

• To progress our line renewal programme to achieve a sustainable long-term investment profile.

5.2.3 How to interpret the condition information in this section

The sections within this asset renewal overview present the current state of TLC’s key assets classes, like poles, conductors, transformers etc, and describe the issues we are seeking to address with our planned expenditure. Each asset class shows a view of the current condition of the assets using a condition profile table, similar to the one below.

The table shows the percentage of assets in each class ranked against six condition categories; U, H1, H2, H3, H4 and H5. The meaning of these categories is also outlined below.

The condition scoring reflects the condition of the assets at their last inspection, and this one key input used for planning and prioritising the asset renewal programme, along with a number of other inputs that reflect the overall status of risk and priority for replacement. An exception is the condition of conductors (overhead line and cables) which has been based on their age rather than inspection.

Description of Health Indicator Example Condition Chart

U - Asset health unknown Steel Wood Concrete 80% H1 - Replacement recommended 60% H2 - High risk H3 - Increasing risk 40%

H4 - Asset serviceable 20% % in Service in % H5 - As new condition 0% H5 H4 H3 H2 H1 U

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5.2.4 Overhead Lines

Poles

TLC has 34,085 poles and 52,687 crossarms in service supporting its overhead line network. TLC’s poles are a mix of concrete, wood and steel (which are typically iron rail). Most of TLC’s poles installed in the last ten years have been concrete. The age and condition of these assets is summarised below

Description Condition Profile Quantity of Asset

Concrete 19,124 Steel Wood Concrete Poles 80% Wooden 11,462 Poles 60% Steel Poles 3,494 40% Crossarms 51,208

Service in % 20%

0% H5 H4 H3 H2 H1 U

Age Profile

Steel Wood Concrete 5,000 4,500 4,000 3,500 3,000 2,500 2,000 1,500 1,000

500 Service in Totalof % 0 80 75 70 65 60 55 50 45 40 35 30 25 20 15 10 5 0 Age (Years)

Notes:

1) In some cases, our pole data is populated with default rather than actual commissioning date values, which has the effect of showing abnormal pole installation volumes in specific years. Default values were populated when TLC’s records were transferred from paper to a digitised format, and it is assumed they represent instances where the commissioning dates were missing from the paper records.

2) The high volume of poles with a default age is problematic from a planning point of view, so this year we will re- estimate the age of these assets using a range of evidential pointers that will provide an improved level of

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accuracy. This is will include known installation dates of surrounding poles, condition data, and historical record searches.

Overhead Conductor

TLC has 4003 km of overhead conductor. The age and condition of these assets is summarised below.

Quantity Description of Asset Condition Profile (km)

33kV Overhead Lines 456 33kV 11kV LV 11kV Overhead Lines 3069 80% LV Overhead Lines 478 See Note 1 below on condition 60% assessment methodology 40%

20%

% fo Total km in Servicein kmTotal fo % 0% H5 H4 H3 H2 H1 U

Age Profile

33kV 11kV LV 300

250

200

150

100 km in Serviceinkm 50

0 80 75 70 65 60 55 50 45 40 35 30 25 20 15 10 5 0 Age (Years)

Notes

1) Conductors are long life assets, and to date the condition scoring has been assessed based on age, rather than physical inspection results. However, most of TLC’s conductors remain from the original electrification of the King Country region. Consequently, we are now commencing a programme to remove test sample line sections when line renewals are undertaken, to improve our understanding of the rate of deterioration of these conductors, and how the locational influences impact their performance.

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Distribution Lines – Key Risks and Issues

One of the most significant challenges for the business is transforming its line renewal planning to create a sustainable forward management programme.

shows TLC’s rolling average pole age profile. Although this is a crude indicator of risk, it shows that the average age of TLC’s pole asset fleet has been steadily increasing year on year, indicating that the line renewal run rate has not quite kept pace with assets aging over time. Some of that increase is expected because it reflects our high proportion of concrete poles which have a longer design life than wood, but in general we are seeking continue to decelerate and ultimately flatten the average age curve.

The 2020 AMP continues the line renewal programme identified in the 2018 AMP, with intent to stabilise the asset age profile as a proxy for risk management. At the same time TLC is continuing to increase its understanding of pole and line asset health to optimise renewal expenditure where supported by a risk assessment. The starting point for that process is to improve our pole and line condition data set. In 2021 we will investigate options to, accelerate our inspection rate and we will also undertake a data cleansing process to refresh, correct and in some cases populate pole data in our asset management system.

We also intend to review and automate our processes to reduce the subjectivity of condition assessment. This should enable greater certainty and consistency when assessing our pole and line health.

Our primary indicator of asset health is to date has been pole condition. This year we are changing our approach to give performance (line sections with defective equipment events) a greater weighting and using that measure (supplemented with age and condition data as secondary inputs) to prioritise our line renewal programme.

This initiative is a continuation of our progression towards a risk-based approach for planning our line renewal programme, which we intend to align this with the ISO55000 standard over time.

Figure 5.1: TLC’s Rolling Avergate Pole Age Profile

Rolling Average Pole Age 40 35 2020 30 AMP 25 Plan 20

15 Age (Years) (Years) Age 10

5 (years)

0 Average

1919 1929 1939 1949 1959 1969 1979 1989 1999 2009 2019 2029

Average Pole Age at Year X

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Line Renewal Capital Plan (Poles, Conductors, Crossarms)

Expenditure Plan $ 000’s 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

33kV Planned Line 1,807 370 2,007 1,487 1,974 1,125 819 675 292 292 Renewals 11kV Line Renewals 3,554 5,281 5,090 4,914 4,415 5,458 4,338 5,757 6,011 6,361 LV Line Renewals 717 382 375 928 848 836 958 538 1,127 1,620

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5.2.5 Switchgear

Sub-transmission Switchgear

TLC has 234 sub-transmission switches. Some of these assets are located in zone substations and others are in the field on sub-transmission lines. The switch ages and condition vary, and they are renewed based on risk assessment or when no longer serviceable.

Description of Asset Quantity Condition Profile

Air Break Switch 111 Air Break Switch Ring Main Unit Recloser Load Break Switch 1 Circuit Breaker Fuse / Fuse Link Solid Link 80% Recloser 14 Circuit Breaker 46 60% Fuse / Fuse Link 7 40% Solid Link 47

Transformer Fuses 8 20%

Servicein Number 0% H5 H4 H3 H2 H1 U

Age Profile

Air Break Switch Circuit Breaker Fuse / Fuse Link Load Break Switch Recloser Solid Link 20 18 16 14 12 10 8 6 4

2 Servicein Number 0 80 75 70 65 60 55 50 45 40 35 30 25 20 15 10 5 0

Age (Years)

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Distribution Switchgear

TLC has 8,206 Distribution Switches of various forms.

Description of Asset Quantity Condition Profile

Air Break Switch 440 Air Break Switch Circuit Breaker Sectionaliser Circuit Breaker 176 Load Break Switch Recloser RTE Switch 80% Sectionaliser 64

Load Break Switch 174 60% Recloser 132

RTE Switch 68 40%

20% Number in Servicein Number

0% H5 H4 H3 H2 H1 U

Not shown in age and condition graphs Fuse / Fuse Link 1029 Solid Link 519

Age Profile

Air Break Switch Circuit Breaker Sectionaliser Load Break Switch Recloser RTE Switch 60

50

40

30

20

10 Number in Servicein Number 0 80 75 70 65 60 55 50 45 40 35 30 25 20 15 10 5 0 Age (Years)

Notes:

1) The switches that are contained within the Ring Main Units are counted in the other switch categories above.

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2) For ease of visualisation, the age and condition profiles above do not show the fuse, fuse links and solid links which are high-volume common connection assets. 3) Condition assessment of switchgear falls into two groups. The first groups (sectionalisers, air break switches, pole mount fuse switches, pole mounted load break switches, solid links, RTE switch and transformer tap off fuses) receive visual inspections during routine maintenance and are replaced as required. For high impact installations these may be inspected more regularly. The second group are devices that have active control relays that ned to be tested to prove they still work. A subset of these have oil which needs to be changed periodically. In both cases assessment during the inspection cycle determines any replacement or maintenance actions if required, and the assets are not specifically profiled to maintain a condition level.

Switchgear Risks and Issues

The TLC network has 3 oil filled Ring Main Units (RMU’s) remaining, two will be removed from service in 2021, the third (Reyrolle) remains in service as it is a low risk site and there are no known industry alerts on its continued use.

Switchgear Expenditure Plan

Expenditure Plan $ 000’s 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Switchgear Renewals () 404 301 232 181 77 203 85 85 85 141 Switchgear Safety 0 123 81 180 156 0 0 67 0 61 Replacements (Note 1) (Note 2)

Notes:

1) The expenditure above covers projects where the primary driver is switchgear replacement. However, switchgear is also being replaced under other projects where the primary driver is transformer replacement (as an example) which is not included in the expenditure profile above. These includes the replacement of five Magnefix units. Therefore, the expenditure that has been shown for switchgear safety replacement above is understated. 2) Switchgear upgrades are part of the ground mount safety programme and is approximately $120k. This does not include installation cost, which is accounted for in the transformer upgrades and difficult to separate out.

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5.2.6 Transformers

Power Transformers

Power transformers convert energy at sub-transmission voltage from 33kV to 11kV for distribution across the TLC network. TLC has 40 Power transformers located at its zone substations. For discussion we have grouped these into three categories.

Description of Asset Quantity Condition Profile

Alstom Transformers 5 Alstom ETEL All Others ETEL Transformers 7 100% All Others 28 80%

60%

40%

20%

Servicein Number 0% H5 H4 H3 H2 H1 U

Age Profile

Alstom ETEL All Others 4

3

2

1 Number in Servicein Number

0 80 75 70 65 60 55 50 45 40 35 30 25 20 15 10 5 0 Age (Years)

Notes:

1) Condition of the transformers is primarily determined by dissolved gas analysis of the transformer oil, supplemented with visual inspection and other electrical tests when the transformer is undergoing maintenance.

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Power and Distribution Transformers – Risks and Issues

There are two key issues that are driving abnormal deterioration of TLC’s transformer fleet.

Issue 1: Crimp connections on Alstom Power Transformers

TLC purchased seven transformers from Alstom in the late 1990’s to early 2000’s, of which four have since failed, with two being a total loss. All were manufactured and supplied by the same factory over a six-year period. The failures occurred over a long period of time, and consequently were not been identified as a systemic reliability risk until 2017.

The root cause of failure has been identified as poor crimp connections between transformer windings and bushing or tap changer jumper leads - a manufacturing quality issue. These transformers have been proactively removed from service to repair the crimp connections. Of the five that remain in service, three have now been repaired, and the remaining two will be repaired as soon as it is practical to remove them from service. One is installed at the Atiamuri substation, which is a single-transformer substation. It cannot be removed for inspection and repair until the substation is upgraded, and this will be co-ordinated with the planned upgrade of that substation in 2022.

Issue 2: Accelerated Aging of ETEL Transformers

TLC has seven ETEL Power Transformers in service. Three continue to show very high levels of hydrogen due to partial discharge that is caused by a design defect in the transformers. While it presents no imminent safety issues or risk of failure it is expected to represent a significant reduction in the expected life of the transformers. Five ETEL transformers were subsequently returned to the manufacturer to be rebuilt, however they continue to produce higher than normal levels of hydrogen.

The issue is detectable using Dissolved Gas Analysis (DGA) testing, which is used to detect arcing or abnormal heating that may be occurring within the transformer. The arcing or heating causes elevated levels of hydrogen and other gases in the oil.

Despite ongoing support and remanufacturing of the transformers by the supplier, we have not yet gained confidence that the problem can be completely resolved. In 2021 we will commission an independent test to identify the root cause and provide advice on their risk profile. To do this we have ordered two new 2.5MVA transformers which will replace the ETEL transformers at Kaahu Tee and Te Anga in a staged process and allow those units to be tested.

Figure 5.3 (a) Burnt connections on a 3MVA Figure 5.3 (b): Replacement of an ETEL Power Alstom transformer Transformer

Distribution Transformers

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Distribution transformers convert 11kV distribution energy to low voltage for direct supply to homes and businesses. TLC has 5,204 Distribution Transformers. The age and condition of these assets is summarised below.

Description of Asset Quantity Condition Profile

Ground Mounted 495 Ground Mounted Pole Mounted Pole Mounted 4,709 100%

80%

60%

40%

20%

0% Service inTotal of % H5 H4 H3 H2 H1 U Age Profile

Ground Mounted Pole Mounted 250

200

150

100

50 Number in Servicein Number 0 80 75 70 65 60 55 50 45 40 35 30 25 20 15 10 5 0 Age (Years)

Notes

1) There are significant gaps in age data of our older transformers. The age graph above excludes 1,115 transformers that have their commissioning date set to a default value (1974 and 1980). These default commissioning dates were used for transformers that had no record of commissioning when TLC’s asset records were digitised. It is known that many of these transformers were commissioned after this date, and consequently this business rule has the effect of increasing the average asset age.

2) This year TLC will undertake a data cleansing programme which will include identifying (or estimating) the transformer asset age data from forensic information, such as tracing the manufacturing date from the serial number, applying known installation dates of the pole assets the transformer is mounted on, or estimating commissioning dates using other data sources such as records from other electricity distributors who have similar assets with known manufacturing dates.

Distribution Transformers – Risks and Issues

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In 2018 AMP, TLC identified 65 ground mounted transformers that were considered high risk because they were enclosed in wooden or tin sheds or were an open enclosure style. These transformers would not meet current standards if constructed today because in most cases these historic housing designs do not offer any secondary protection against contact with live electrical parts (such as a secondary insulation barrier) if the first protection layer is compromised.

A programme commenced to replace those transformers over a four-year period, and to date 19 have been replaced including all transformers that presented a public safety risk, and all transformers in wooden structures. For the remaining transformers, protective insulation barriers were installed to prevent accidental contact of live conductors by staff and contractors who work on this equipment as an interim measure.

In the process of replacement, it was found that in some cases the existing switchgear should also be replaced, or new switchgear added to improve system management and reliability. Consequently, the size and speed of the programme has been impacted. The 2020 AMP will continue the programme and a further 16 (the highest priority of the remaining transformers) will be replaced in FY2021. However, completion of the total programme is now scheduled for FY 2023, one year later than the original plan. We consider this risk as being acceptable because the public safety risk has now been alleviated, and because of the mitigations we have now put in place in the remaining transformers to provide greater protection for staff working on the equipment.

Figures 5.1 (a,b and c) show the transformers that the programme is addressing.

Figure 5.6: Typical wooden shed Figure 5.6:Typical tin shed Figure 5.6: Typical open external enclosure (now all replaced) transformer enclosure transformer

Distribution Transformer Expenditure Plan

$ 000’s 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

Transformer Renewals 245 245 245 245 245 272 272 272 272 272 (Note 1) Transformer Safety 1,430 1,726 1,318 0 0 0 0 57 120 220 Renewals

Notes

1) The Transformer Renewals expenditure reflects the ongoing replacement of transformers that fail from environmental factors (such as lightning) and end of life.

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5.2.7 Cables

Cables form a critical part of our network. They are used largely to mitigate a cascade pole failure scenario around zone substations, and to reticulate the ski-field areas.

Quantity Description of Asset Condition Profile (km)

33kV 11kV LV 33kV Cables 11 100% 11kV Cables 130 LV Cables 182 80%

60%

40%

20%

% of Total km in Servicein kmTotal of % 0% H5 H4 H3 H2 H1 U

Age Profile

33kV 11kV LV 80 70 60 50 40 30

20 Serviceinkm 10 0 80 75 70 65 60 55 50 45 40 35 30 25 20 15 10 5 0 Age (Years)

Notes:

1) Data quality on age and condition on our older cables is poor, particularly low voltage cables. Over 55% of our low voltage cable and 25% of our 11kV cables have a default date. 2) Underground cables are generally not accessible for inspection, and hence the physical condition of most of TLC’s cables is unknown. 3) Most of the cables installed on Mt Ruapehu are over-ground. These are visually inspected annually for damage and repaired as required. In some cases, these cables have experienced ongoing damage and maintenance and are now being considered for targeted replacement. 4) TLC has only a small quantity of 33kV cable in service with the majority in as-new condition having recently been installed at the Taharoa mine.

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Cables – Risks and Issues

Cables on the Ruapehu Ski-Fields

The Ruapehu mountain is supplied by about 23km of TLC owned cables. About half is laid over-ground rather than being buried, and as such all of these cables are steel-wire-armoured to provide additional mechanical protection. This method of reticulation is not unique to TLC and is used in other ski-fields in New Zealand where burying cables is either impractical (because the volcanic rock base is difficult to penetrate) or restricted by Department of Conservation or Iwi guardianship.

The mountainous environment presents a particularly difficult challenge for these assets as it is a continuously moving platform. Through the winter, rocks on the surface of the mountain are physically moved by the pressures of ice formation and the weight of snow accumulation. Movement occurs again in summer as temperatures rise and snow melt shifts ice sheets and rocks over the cable once again.

The environment is further complicated by snow grooming activities which may cross the cables routes during winter, as these are unseen when under snow cover.

As a result, the over-ground cables in the upper mountain areas can suffer damage from both rock abrasion and snow grooming activities. The key impact to date has been in reduced reliability of certain sections of cables, which can fail if the outer sheath is breached allowing water ingress, which then freezes within the cable in the following winter. These cables are therefore inspected annually to identify and repair or replace any damaged sections.

TLC is seeking to make improvements to minimise damage to the cables, and also minimise access to the cable route from public or operational activities on the mountain. A significant budget was allocated in the 2018 and 2019 AMPs to enable (if required) the majority of the cables to be trenched. Since that time, it has become clear that undergrounding is not only physically difficult, is also not aligned with cultural values related to guardianship of the mountain. As a consequence, the 2020 AMP now assumes that over-ground protection solution will be applied. In terms of planning, this assumption means that TLC will now seek out a new range of solutions with evidence that they have been applied successfully in other similar installations either locally or internationally. It is expected that an over ground solution will be materially less expensive than trenching, and so we have roughly halved the expenditure previously proposed, although this remains an estimate until a design is formalised.

Progressing this project is challenging but remains a priority. In the course of the FY2021 year we expect to formalise a design solution for implementation over the following three-year period.

Cables Expenditure Plan

$ 000’s 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

11kV Cable Renewals 206 465 540 668 540 334 477 129 129 0 LV Cable Renewals 0 0 622 410 51 1,486 0 435 0 0

Note: The large expenditure in 2026 is due to a planned upgrade of the LV cable reticulation in the Whakamaru village, in tandem with transformer replacement. The cable expenditure noted above is overstated, as some of the project expenditure includes transformers and associated switchgear.

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5.2.8 The Key Projects

Our key projects to address the above issues are listed below.

Table 5.2: Key asset renewal programmes

Project Name Est.Cost ($ 000’s) Timing (FY) Distribution Transformer Safety Renewal Programme 4,871 2021 - 2023 Cable Upgrades 3,487 2021 - 2029 33kV Line Renewal Programme 10,849 2021 - 2030 11kV Line Renewal Programme 51,181 2021 - 2030 LV Line Renewal Programme 8,329 2021 - 2030

5.2.9 Total Asset Renewal Investment

Table 5.3: Summary of Total Asset Renewal Investment

$ 000’s 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

33kV Line Renewals 1,807 370 2,007 1,487 1,974 1,125 819 675 292 292 11kV Line Renewals 3,554 5,281 5,090 4,914 4,415 5,458 4,338 5,757 6,011 6,361 LV Line Renewals 717 382 375 928 848 836 958 538 1,127 1,620 Switchgear Safety 0 123 81 180 156 0 0 67 0 61 Replacements Transformer Renewals 245 245 245 245 245 272 272 272 272 272 Transformer Safety Renewals 1,430 1,726 1,318 0 0 0 0 57 120 220 11kV Cable Renewals 206 465 540 668 540 334 477 129 129 0 LV Cable Renewals 0 0 622 410 51 1,486 0 435 0 0 Substation Renewals 1,083 189 1,702 1,501 1,001 79 239 124 422 21 Load Control 0 0 143 0 143 0 0 0 0 0 All Other Renewals 327 172 126 192 112 176 79 36 36 36

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Network Reliability

5.3.1 Introduction

Reliability investment focuses on reducing the occurrence and impact of outages across the TLC network.

5.3.2 Our Key Network Reliability Objectives

Our key objectives in our Network Reliability programme are:

• To alleviate power transformer failure risk

• To support strengthen supply options in key supply points

• To improve our understanding of vegetation related outages

• To improve our ability to minimise the impacts of outages when they occur.

5.3.3 Key Network Reliability Projects

As described earlier in this section, TLC has experienced several power transformer failures in recent years. We are now seeking to improve the network’s resilience to power transformer failures, which will be achieved in two ways:

1) Create a floating stock of transformers that can be easily deployed when a failure occurs and 2) Gradually improve substation security of supply by progressing our key substations to N-1 security over time (meaning we will ensure key substations have a permanent spare transformer installed as a backup supply).

Waitete Zone Substation Upgrade

To achieve these objectives TLC will replace the Waitete Substation to increase its capacity and security. This includes installing two new 15MVA transformers which will release the existing three 5MVA transformers as strategic spares for installation in other substations or as floating stock.

The Waitete Substation was chosen because it supplies a major population centre (the Te Kuiti town and surrounding areas) and currently operating above its firm capacity. The upgrade project will see it move to a full N-1 supply point.

The upgrade of the Waitete substation is a major project, which requires the purchase of two 15MVA transformers, installation of new concrete pads to support the transformers, upgrades to the 33kV incoming bus, and replacement of the 11kV switchgear. The total cost of the project is estimated at $4.7m and is scheduled for completion in 2022.

Turangi Alternative Supply

Turangi is currently supplied by a single 33kV line and has limited backfeed options. To alleviate this constraint a study has been commissioned to examine alternative supply options. The findings of this work provided a range of options that are currently under engineering review, however an allocation of ~$1.2m has been provided in the 2020 Asset Management Plan to accommodate the project costs of the selected option.

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Vegetation Database

The TLC network has around 4,000 km of overhead lines that run across 13,700 square km (about 5% of New Zealand’s land mass). Much of that area is covered in forestry and other vegetation which can interrupt electricity supply, either by growing into the lines or by falling across the lines under high winds.

The primary indicator of the right size of its expenditure has to date been the volume of vegetation interruptions. While this provides some degree of indication, it is not an objective measure of vegetation growth rates and threat.

In 2021 we are seeking to improve both our understanding and effectiveness of vegetation management to ensure that expenditure is optimised. To achieve this, we intend to develop a vegetation database that will hold locational information on tree types, their current size, growth rate and risk to the network to establish the base information set for the database.

Lidar is a point-map radar survey undertaken by aircraft, which provides detailed visual images and analysis of vegetation surrounding power lines, along with height and clearance measurements of pole assets. It will provide TLC with a comprehensive vegetation analysis tool set to optimise our current vegetation expenditure. The survey will cover our entire 33kV and 11kV network (approximately 4000km) and give us a range of valuable data including:

• Single trees that present point risks for feeders (either now or in the near future)

• An objective baseline of current vegetation risk we carry across all feeders

• Evidence of vegetation interference on high outage count feeders, to grow our understanding of unknown outages

• An estimate of the vegetation trimming programme that will be needed longer term.

The Total cost is estimated at ~$870k but we expect this will be paid back over time from savings including reduced helicopter inspections in subsequent years.

Switch Automation

TLC is a sparse rural network in which its distribution lines cover vast distances to feed relatively small rural populations. When a fault occurs on a rural line, it can sometimes mean that upstream population centres are affected until the fault is removed.

To alleviate this issue, TLC will renew some switches to new technology that is able to be remotely controlled and adding automation to other existing switches that are able to be upgraded. These programmes total $1.5m of which most ($1.0m) is planned for the first three-year period of the asset management plan. This automation upgrade will allow the upstream sections of lines to be restored sooner, while enabling the downstream line sections to remain de- energised for repair.

Along with this programme, TLC is also planning to install new switches to allow the network to be broken into smaller sections. This will enable faster restoration when a fault occurs.

The total expenditure for the automation programme including renewal, automation and new switches for sectionalisation is $8.1m over the ten-year planning period, with $3.8m planned for the first three years of this asset management plan.

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From a reporting point of view, this expenditure is split between Asset Renewal, and Network Development, and some of that expenditure has already been included in the Switchgear totals above. However, because it all forms a part of a cohesive reliability project, we have shown this as a project total below.

Fire Management

As part of our zone substation reliability improvement we are upgrading the fire suppression capability of some of our substations. This is primarily a risk management project, with the upgraded suppression systems reducing the extent of damage in our substations in the event of a fire. This is planned for completion in 2021.

5.3.4 The Key Projects

Table 5.4: Key Reliability Focused Projects

Project Name Est.Cost ($ 000’s) Timing (FY) Waitete Substation Upgrade 3700 2021 - 2022 Turangi Alternative Supply 1233 2021 - 2022 Vegetation Database 894 2021 - 2021 Switch Automation (Note 1) 8,044 2021 - 2030 Fire Suppression Upgrades 164 2021

Notes:

1) From a reporting point of view, the switch automation expenditure is split between Asset Renewal and Network development, and some of that expenditure has already been included in the Switchgear totals above. However, because it all forms a part of a cohesive reliability project. Table 5.4 shows the total planned expenditure for this initiative, and Table 5.5 shows the expenditure allocated to the Commerce Commission’s reliability category.

5.3.5 Total Network Reliability Investment

Table 5.5: Summary of Total Reliabily expenditure

$ 000’s 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

Zone Substation Reliability 2,920 2,179 0 0 0 0 0 0 0 0 Switchgear Automation 404 301 232 181 77 203 85 85 85 141 SCADA and Radio 412 644 66 66 66 74 74 74 74 74 Vegetation Reliability 894 0 0 0 0 0 0 0 0 0 Database

Note: The Waitete, Turangi and Fire Suppression projects are included in Zone Substation Reliability.

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Network Development

5.4.1 Introduction

Network development covers system growth, security of supply and quality of supply.

5.4.2 Our Key Network Development Objectives

Our key objectives in our Network Development programme are:

• To alleviate security of supply constraints on our major zone substations

• To support emergent customer growth projects

• To improve quality of supply and reliability for our customers.

5.4.3 Security of Supply

The 2018 AMP identified a range of security of supply constraints that the network was facing at that time. Many of those issues have now been addressed providing enhanced security of electricity supply for our customers. The completed projects are shown in Table 5.6 below.

Table 5.6: Security of supply constraints resolved since 2018

Location Security of Supply Issue – Completed since 2018 Planned Completion

Hangatiki GXP Peaking above firm capacity Complete Te Waireka Peaking above firm capacity Complete Wairere Falls 33kV Bus at end of life Complete Borough Peaking above firm capacity Complete Ohakune Supply constrained by a low capacity 11kV cable. Complete

However, security of supply remains an issue for TLC and today approximately 6,500 customers (27% of our customer base) are supplied by substations that don’t meet our security of supply standard. To address this, seven additional projects are planned for completion within the first three years of the 2020 AMP.

This AMP seeks to address these issues through significant substation upgrades over the planning period. Table 5.7 shows the security of supply projects that are remaining, and their indicative planned year of completion.

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Table 5.7: Security of supply projects remaining.

Location Security of Supply Issues Being Addressed in the 2020 AMP Planned Completion

Turangi Single 33kV supply with limited back feed options 2021 (Note 1) Arohena Single spur line supply 2021 Kuratau Single transformer (following failure of the second unit in 2017) 2021 Waitete Peaking at firm capacity 2022 (Note 1) Atiamuri POS Peaking above firm capacity 2022 Ohakune Single GXP transformer, with minimal back feed options. 2024 Te Kawa 33kV lines between Hangatiki and Otorohanga reaching capacity 2022 Maraetai The Maraetai substation runs at N security with a significant dairy load 2022 Wairere / Mahoenui Single 33kV supply with limited back feed options In planning (Note 2)

Notes

1) The expenditure for the Turangi and Waitete projects is covered under Network Reliability expenditure (Section 5.3). 2) The Wairere / Mahoenui security of supply improvement is still in planning and as such project completion has not yet been determined.

Figure 5.7Error! Reference source not found. shows the security level of TLC’s Zone substations. The highlighted substations indicate areas where priority work is required to strengthen security of supply. Together these substations serve ~6,500 customers (~27%) of TLC’s customer base. The grey bars show substations that have a single transformer with no immediate backup supply and would result in a sustained outage if a fault occurs, ranging from several hours to days. The light green bars are substations that can be back-fed from other areas to provide supply, but this may be at a lower level than needed, and the orange bars show substations that have multiple transformers but a single unit cannot supply the full load.

Figure 5.7: Security Rating of TLC’s Zone Substations

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Zone Substation Security Summary 3500 Zone substation security improvement 3000 projects in the 2020 ~6,500 customers (around 27%) are 2500 impacted by security of supply constraints 2000

1500

1000

Number of Customers of Number 500

0

Tuhua

Piripiri

Tawhai

Otukou

Turangi

Kuratau

Waitete

Te Anga Te

Taharoa

Marotiri

Oparure

Borough

Tokaanu

Arohena

Manunui

Maraetai

Nihoniho

Hangatiki

Waiotaka

Awamate

Kiko Road Kiko

Mahoenui

Kaahu Tee Kaahu

Te Waireka Te

Gadsby Road Gadsby Falls Wairere National Park National

Taharoa Village Taharoa N N-1 N-1 Constrained N-1 Switched

5.4.4 System incremental growth

The TLC network is supplied not only from Transpower grid exit points (GXPs), but also from major Waikato generation plants and seven large (>1MW) distributed hydro generators. The network has long 33 kV lines between distributed generators and GXPs.

The key area of demand growth in the forecast period is expected to be in the northern network region supplied by the Hangatiki and Atiamuri GXPs. Sources of additional demand are expected from ironsand mining, dairy farming (milk chilling), limestone industrial processing and milk processing. These projects are in discussion at the time of writing but have other external dependencies before they can be realised.

5.4.5 Demand Forecasts: Points of Supply

Table 5.8 shows the demand forecasts at TLC’s points of supply.

Table 5.8: Point of Supply Demand Forecasts (MVA)

Point of Supply 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Hangatiki (Note 1) 41.3 44.8 45.0 48.5 48.7 49.0 49.2 49.4 49.7 49.9 Ohakune 8.0 8.2 8.4 8.5 8.7 8.9 9.1 9.2 9.4 9.6 Ongarue 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 Tokaanu 10.9 10.9 11.0 11.0 11.1 11.1 11.2 11.2 11.3 11.4 National Park 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 Whakamaru 10.0 10.1 10.7 14.7 15.0 15.3 15.6 15.9 16.2 16.6 Mokai 4.8 5.0 5.3 5.3 5.4 5.4 5.5 5.6 5.7 5.8 Atiamuri 14.8 15.1 16.0 20.0 20.4 20.7 21.1 21.5 21.9 22.4 Notes:

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Growth on the the Hangatiki and Atiamuri points of supply is driven by major customer projects that are currently in planning. Our current forecast includes our best estimate of that load over the planning period, but this may change pending finalisation of those projects. There is potential for the demand on the Hangatiki point of supply to exeed its firm capacity, towards the end of the planning period, which may trigger further investment, which is not currently in plan, to strengthen security at that GXP. At a regional level, most of TLC’s transmission supply points are not likely to become constrained over the next ten years, based on current demand growth forecasts. However, constraints are expected at the following key assets.

• Atiamuri Point of Supply The Atiamuri point of supply acts as a backup for Whakamaru and currently reaches its rated capacity for short periods. A project to augment that supply point with an additional transformer is being planned. This will increase its capacity and improve the substation security to N-1.

• Te Waireka/Te Kawa 33kV lines The pair of lines from Hangatiki to Otorohanga (Te Waireka Zone Substation) are reaching their thermal firm capacity. We expect further load growth in the Otorohanga area to result in reducing the line security from N-1 to N at peak loading times. Consequently, we are bringing forward projects to complete the line renewal and reconductoring of these lines to support industrial growth in the area.

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5.4.6 Demand Forecasts: Zone Substations

Table 5.9 shows the expected zone substation demand forecasts for the planning period. Most growth is expected to be driven by two major industrial customers, which in both cases will require the construction of new zone substations if those projects are realised. At this stage we are not anticipating any material impacts from distributed generation in the near term.

Table 5.9: Zone Substation Demand Forecasts (MVA)

Firm Zone (N-1) Security 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Substation Capacity (MVA) Taharoa N-1 10 15.0 15.0 15.0 15.0 15.0 15.0 15.0 15.0 15.0 15.0 Waitete N-1 10 8.9 8.9 8.9 8.9 8.9 8.9 8.9 8.9 8.9 8.9 Gadsby Rd N-1S 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Hangatiki N 3.7 3.8 3.9 4.1 4.2 4.3 4.4 4.6 4.7 4.8 Wairere Falls N 2.5 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 Te Anga N-1S 2.1 2.1 2.1 2.1 2.1 2.1 2.1 2.1 2.1 2.1 Piripiri N-1S 2.1 2.1 2.1 2.1 2.1 2.1 2.1 2.1 2.1 2.1 Te Waireka N-1 15 12.8 13.1 13.3 13.6 13.9 14.1 14.4 14.6 14.9 15.2 Oparure N 2.0 2.0 2.1 2.1 2.1 2.1 2.1 2.2 2.2 2.2 Mahoenui N 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 Taharoa Village N-1S 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 Atiamuri N 10.9 11.2 11.4 11.6 11.8 12.1 12.3 12.6 12.8 12.8 Maraetai N 5.9 6.0 6.2 6.4 6.5 6.7 6.8 7.0 7.1 7.3 Marotiri N-1S 2.8 2.9 2.9 3.0 3.1 3.2 3.3 3.4 3.5 3.6 Arohena N 2.7 2.8 2.9 2.9 3.0 3.1 3.2 3.3 3.4 3.5 Kaahu Tee N 1.6 1.6 1.7 1.7 1.8 1.9 1.9 2.0 2.0 2.1 Tawhai N 4.9 4.9 4.9 4.9 4.9 4.9 4.9 4.9 4.9 4.9 Nat. Park N-1S 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Otukou N 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 Borough N-1 10 8.5 8.5 8.5 8.5 8.5 8.5 8.5 8.5 8.5 8.5 Manunui N 3.3 3.5 3.6 3.7 3.9 4.0 4.1 4.3 4.4 4.5 Tuhua N-1S 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 Nihoniho N-1S 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 Turangi N-1 5 4.9 5.0 5.0 5.0 5.0 5.0 5.0 5.0 5.0 5.0 Kuratau N 2.5 2.4 2.4 2.4 2.4 2.4 2.3 2.3 2.3 2.3 Kiko Road N-1S 1.6 1.7 1.7 1.8 1.8 1.9 1.9 1.9 2.0 2.0 Awamate N-1S 0.7 0.7 0.6 0.6 0.5 0.5 0.4 0.4 0.4 0.3 Waiotaka N-1S65 2.1 2.1 2.1 2.1 2.1 2.1 2.1 2.1 2.1 2.1 Tokaanu N 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2

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Note. The Wairere, Te Anga and Piripiri substations are connected to local generation, and as such the forecasts above reflect export energy at those zone substations. Te Anga and Piripiri substations provide a switched backup for each other and are designated as N-1S (N-1 switched).

The Key Projects

TLC key investment projects to address the risk and issues discussed above are listed the table below.

Table 5.10: Summary of Key System Growth Investments

Est. Timing Project Name Investment Need Cost (FY) ($ 000’s) Install a new 20/23MVA 33/11kV transformer to boost capacity at Atiamuri POS. Atiamuri provides N-1 security to the Whakamaru Atiamuri POS Upgrade region. 2,100 2022 Alternative Option Considered: Have diesel generators or battery banks available to limit peak demand. Reconductor and upgrade line between Atiamuri and Kaahu Tee to increase the backup capacity for the Whakamaru region. This is part Kaahu Tee to Atiamuri of a major customer capacity project which follows on from the 650 2021 33kV Tie Line Atiamuri upgrade. Alternative Option Considered: Have diesel generators or battery banks available to limit peak demand. New substation in the Whakamaru area to cater for increasing dairy load and to provide an 11kV backup to Maraetai and Kaahu Tee. Alternative Options Considered: Whakamaru Zone 1) Install additional 33kV line and reconductor Whakamaru 11kV 2,050 2024 Substation feeder. Install additional transformer at Maraetai. Install diesel generators or battery banks to cater for peak demand. 2) Upgrade the Maraetai substation by installing a second transformer (ex-Borough), and additional switchgear to provide N-1 security. Reconductor the 33kV Te Kawa feeder. The timing of this is dependent on load growth. On current plan we expect this project to Reconductor Te Kawa be driven by a major customer connection requiring completion by 978 2022 33kV Feeder 2022. Alternative Option Considered: Have diesel generators or battery banks available to limit peak demand. Purchase and installation of 2x 15MVA transformers at Waitete and develop a new substation on Waitete Road. Waitete Substation Alternative Options Considered: 3,600 2022 Upgrade 1) Upsizing of the Gadsby Road substation 2) Upsizing of the existing Waitete substation Reconductor the Turoa / Tangiwai feeder tie between switch 5695 and 5680 to strengthen the back feed from Tangiwai,and install a Turoa to Tangiwai 11kV switch to connect directly to the Transpower 11kV bus. 700 2024 Tie Line Alternative Option Considered: Have diesel generators or battery banks available to support load during outages. Convert existing 2 wire and SWER 11kV lines to 3 phase and upgrade to increase capacity for development in that region. Waihaha 11kV Feeder 490 2023 Alternative Option Considered: Diesel generation, PV and battery banks. Replace aging copper conductor along Rangitoto Road between Rangitoto Rd 11kV switches 112 and 192. 460 2022 Feeder Alternative Option Considered: Install fault reducing equipment at Waitete zone substation.

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Est. Timing Project Name Investment Need Cost (FY) ($ 000’s) Completion of capacity upgrade project started in 2018. Now requires upgrade of the 11kV switchgear on the A and B Buses. B-bus Te Waireka Upgrade upgrade will complete in 2021 and A-bus in 2024 1,315 2024 Alternative Option Considered: Have diesel generators or battery banks available to limit peak demand. Upgrade the Tangiwai to Turoa line to 33kkV to provide a high Ohakune Alternative capacity alternative supply to the Ohakune town. This would involve 2,800 2026 Supply step up transformers and a new 33kV zone substation.

5.4.7 Determination of Equipment Capacity

When planning for all growth and security of supply projects, the rated nameplate capacity is used for project planning. The only exception to this relates to transformers where the short time overload capacity, based on the international standard that the transformer was constructed to, may be taken into account. Short time overloading may reduce the overall life of the transformer, but it does not greatly increase the risk of failure.

5.4.8 Total Network Development Project Investment

Table 5.11: Summary of Total System Growth and Quality of Supply Investment

$ 000’s 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

Voltage Regulators 203 124 124 120 0 0 0 249 249 124 11kV Feeder Development 648 725 615 1,122 66 147 0 258 681 0 11kV Feeder Reliability 116 87 0 0 0 0 0 0 0 0 11kV Switchgear 607 866 348 379 707 1,066 534 534 577 630 Automation 33kV Lines Capacity 257 749 1,551 657 0 0 0 0 0 858 Development 33kV Lines Reliability 587 461 0 0 0 0 0 0 0 0 Development Supply Point Capacity 956 1,203 0 0 0 0 0 0 0 0 Development Supply Points Reliability 0 51 720 107 1,346 1,346 0 0 0 0 Development Zone Substation Capacity 56 0 112 0 112 599 534 1,282 1,282 1,282 Development Zone Substations 1,285 82 1,234 1,028 0 0 0 0 0 267 Reliability Development

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Customer Projects

5.5.1 Introduction

Customer required projects are projects that have either been requested by customers to provide for their specific needs, or projects where the system demand has risen significantly due to the impact of growth from a specific customer.

There are various processes for customer driven development based around the size of customer needs.

Once a customer need is established, concept options are developed. Needs for major customers are normally established by site visits and discussions. Tools such as load flow studies and fault analysis are used to develop the concepts. The network details, down to distribution transformer level, are stored and regularly updated on the ETAP network analysis program to assist with the process.

Once viable options are determined, high-level costs are estimated, and the advantages and disadvantages of each option are articulated. This will include customer consultation so that the benefits of each option can be accurately assessed by the customer. These discussions are used to determine a number of things, including the amount of future proofing a developer or industrial customer wants to fund. At the current time, TLC has a range of customer driven projects that are in various stages of consultation. TLC has estimated costs for these projects but in most cases, these are provisional estimates prior to detailed scoping and design.

5.5.2 Key Customer Projects

The most significant projects include the expansion of the TLC network to accommodate two large industrial customers that are seeking supply. If these projects are confirmed, we expect to construct two new zone substations along with interconnecting 33kV lines, and the upgrade of some of our supply points to accommodate the additional load.

In total these two projects are expected to require ~$10.3m in capital expenditure over a three-year period commending in 2021.

Other customer driven projects include incremental demand from industrial processing and general new connections and upgrades.

5.5.3 The Key Projects

Table 5.12: Summary of Key Customer Driven Projects

Project Name Est.Cost ($ 000’s) Timing (FY) Large Industrial Customer Growth Projects 10,300 2021 - 2024 Other Customer Growth Projects 5,931 2021 - 2030 General New Connections and Upgrades 3,953 2021 - 2030

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5.5.4 Total Customer Project Investment

Table 5.13: Summary of Key Customer Driven Investments

$ 000’s 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Major Customer Projects 6,065 4,215 0 0 0 0 0 0 0 0 Other Customer Projects 0 154 654 654 654 763 763 763 763 763 General New Connections 374 374 374 374 374 416 416 416 416 416 and Upgrades

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Non-Network Asset Investment

Non-network capital investment includes work that is not specifically related to network assets, but is required for business support, efficiency or business improvement.

5.6.1 Key projects

Non-Network capital expenditure is focused in the following areas:

• Office Building This investment is centred on bringing the TLC office and control room to a fit-for-purpose standard. The investment will create a more functional and collaborative working area for our staff and create greater resilience and security in our operationally critical control room. Secondary benefits will be the creation of a modern working environment that will promote a higher degree of interaction between teams and assist in attracting and retaining high calibre staff.

• Vehicles Ongoing replacement of vehicle fleet.

• Field and Data Systems This covers upgrades to existing software and the development of new systems and major hardware replacements. In particular, TLC is seeking to make better use of its core systems that support its asset management processes.

• Plant and Equipment Covers the replacement and acquisition of new inspection and testing equipment.

Table 5.14: Summary of Total Non-Network Capital Investment

$ 000’s 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Office Building 514 2,056 0 0 0 0 0 0 0 0 Data Systems 193 193 193 193 193 33 33 33 33 33 Vehicle Replacements 125 125 125 125 125 93 93 93 93 93 Office Area 0 0 0 0 0 0 0 0 0 0 Plant and Equipment 34 34 34 34 34 38 38 38 38 38

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Total Capital Expenditure

Table 5.15: Summary of Total Capital Investment – 10 years

$ 000’s 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

Network

Asset Renewals 13,999 12,078 12,549 10,773 9,629 10,043 7,342 8,250 8,568 9,098 Network 4,726 4,360 4,716 3,425 2,244 3,172 1,082 2,336 2,803 3,176 Development Customer Required 6,440 4,744 1,028 1,028 1,028 1,179 1,179 1,179 1,179 1,179

Non-Network

Routine 352 352 352 352 352 164 164 164 164 164 Atypical 514 2,056 0 0 0 0 0 0 0 0 Total All Capital 26,032 23,590 18,645 15,579 13,254 14,558 9,767 11,930 12,714 13,617 Expenditure Less Capital Contributions from (6,065) (4,215) (654) (654) (654) 0 0 0 0 0 Customers Total Expenditure 19,966 19,375 17,991 14,925 12,600 14,558 9,767 11,930 12,714 13,617

Figure 5.8: All Capital Investment

Network Capital Expenditure Asset Renewal Programme Network Development Programme Customer Required Projects Non Network Atypical Non Network Routine 30,000

25,000

20,000

15,000

10,000

5,000 Capital Expenditure (000s) Expenditure Capital

0 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Financial Year

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New Technologies

TLC is actively monitoring the development of new technologies that may emerge as compelling options for alternative means of supply.

At the current time battery and solar technologies as alternative supply options remain economically marginal for general supply services but are increasingly reaching economic viability in targeted applications. Other technological developments such as Electric Vehicles and their charging infrastructure are being actively pursued by TLC and are considered to be key enablers for future regional economic and environmental prosperity.

The rapid advance of new technology is expected to impact the economic lives of more traditional distribution assets as customers invest in providing their own energy supplies using PV and batteries. In these circumstances it may be necessary to accelerate depreciation on assets that become displaced or stranded to ensure that costs are adequately recovered.

At the current time, TLC has not undertaken scenario analysis of the impact that new technologies may impose. However, we expect that technology impact analysis will become a necessary part of our asset management planning process in the near term, as the economic viability of these options continues to improve.

Deliverability

We are confident that the TLC BAU capex plan (i.e. all except large customer required projects) for FY2021 is achievable because it is consistent with the capex volume delivered in FY2019.

We intend to outsource most of the work associated with major customer projects. These projects are in commercial negotiation at the time of writing and consequently the timing of these projects remains subject to confirmation by our customers.

The key components of our capex plan outlined in Figure 5.9: Allocation of internal and external work Figure 5.9.

Figure 5.9: Allocation of internal and external work

General Work

Int

Line Renewals Int

Reliability Projects Int

Internal GMT Programme Int

Ext General Work

Line Renewals Ext

Reliability Projects Ext

GMT Programme Ext

Power TX

Ext External

Security of Supply Ext

TLC Building Ext

Customer Projects Ext - 1,000 2,000 3,000 4,000 5,000 6,000 7,000 Capex (000s)

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Summary of Key Assumptions

The key assumptions that may materially impact this plan are outlined below:

Table 5.16: Key Assumptions

Asset Renewals 11kV Cable Renewals A technical solution for the Ruapehu cable upgrade is yet to be finalised with stakeholders. Material uncertainties may arise from formalisation of a design. Line renewal programme Data cleansing of historic records (i.e. clarifying default dates), and further condition analysis work does not result in a significant departure from our line renewal expenditure plan. Zone substation renewals Finalisation of designs for remedial substation development to meet seismic regulations does not result in a significant departure from our expenditure plan. Network Development Whakamaru Zone Substation There are no material constraints in implementing the planned zone substation to supply Whakamaru (i.e. access to land and any required easements) resulting in significant changes from our expenditure plan. Ohakune alternative supply An alternative supply point for Ohakune is agreed with Transpower and remains within our (220kV) planned cost envelope. Customer Required Projects Otorohanga West Zone A project is formalised with our customers for a new substation to support industrial Substation growth in the western side of Otorohanga. Material uncertainties may arise from formalisation of a design and developing customer needs. All Capex Projects Delivery of this AMP assumes availability of resource, equipment and capital is consistent with current market experience, i.e. not materially impacted by a pandemic or other natural or un-natural disaster. This includes: • Availability of internal and contracted resources required for project delivery • Costs of equipment supply. • Finance being accessible and at rates that are not inconsistent with the current market at the time of writing.

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6. Operations and Maintenance This chapter explains the operation and maintenance of our electricity assets. It aims to ensure the safe and reliable performance of our assets over their expected lives. It outlines the planning process for maintenance, vegetation management and System operations and Support activities; how we establish our budgets and describes how we deliver our operations and maintenance tasks.

Introduction

Operations and maintenance is an essential part of the asset management process. Operational expenditure covers maintenance and business support activities rather than asset investment (which is capital expenditure covered in Section 5).

6.1.1 Operations and Maintenance Portfolio – Key Objectives

Operations and maintenance is an essential part of the asset management process. TLC continually seeks to improve the approach taken to delivering work across the network. This includes:

• Assurance that the preventive maintenance strategy continues to provide essential information about the health of the assets, manage down preventable defects and meet all statutory obligations.

• Minimisation of breakdown rates of the assets, and adjustment of the services delivery or recommendations on asset renewal where the condition of the assets represents a high probability of failure.

• Assurance of timeliness of response to urgent work.

• Optimisation of scheduled work, including balancing resource commitments between capital projects, preventative maintenance programmes and faults.

• Assurance that the personnel delivering services are suitably trained and experienced to be safe in their work and assure high quality for each job.

• Assurance that systems remain appropriate to enabling efficient work management and reporting.

Summary of Expenditure | 103

6.1.2 How this section is structured

This section is outlines our investment across five key categories. These are:

Section Purpose Covers the activities that we undertake to maintain our assets. It includes details on: • Scheduling inspections of assets 6.2 Preventative Maintenance • Scheduled repairs and improvement work • Scheduled corrective maintenance to repair defects as they emerge 6.3 Reactive Maintenance Outlines how we respond to faults and interruptions to supply. Outlines how we manage the vegetation that grows near our distribution lines to 6.4 Vegetation Management prevent tree-related outages. Business, system Outlines the expenditure used for our business support functions and network 6.5 operation and network operations, including staff, IT and office costs. support (SONS) 6.6 Expenditure Summary Summarises our total operational expenditure plan

Summary of Expenditure | 104

Preventative Maintenance

The intent of planned maintenance is to prevent or minimise risk of failure by removing or reducing failure causes before they accumulate to create fault. Preventative maintenance includes inspections of assets, repairs and correction of known defects.

Planned maintenance begins at the annual planning stage, where an inspection schedule is renewed or developed, and the work costed for budgetary approval. Following approval of the expenditure, work packs are developed that include detailed instructions for field staff to carry out the planned inspections or maintenance work. Resources are then scheduled to ensure the work can be carried out within the planning year.

When complete, each job is reviewed and assessed to consider what additional improvements or changes can be made to the maintenance plan, to further minimise risk of failure in the future.

Preventative maintenance activities are scheduled annually based on the current understanding of asset condition and performance requirements for the planning period. These activities are incorporated into the annual works plan. Planned maintenance activities are scheduled to avoid resource constraints during peak work times, which often results in this work being carried out during winter when land access for renewal work is constrained.

The preventative maintenance plan outlines the inspection requirements for overhead lines, distribution switches, ground mounted transformers and zone substations. It is also used to monitor the condition of power transformers with regular condition tests. Currently our pole inspections are time driven rather than condition or risk driven, which presents an opportunity for improvement in the pole inspection regime.

TLC’s vegetation management programme also links to preventative maintenance with all of the sub-transmission and a third of the distribution network inspected every year via helicopter. This allows targeted trimming of trees before they encroach on the regulatory growth limits.

Figure 6.1: Maintenance Workflow

Summary of Expenditure | 105

6.2.1 Preventative Maintenance Schedule

The objective of the preventive maintenance schedule is to ensure that routine work is scheduled so that our assets remain safe, reliable and compliant. The maintenance schedule also seeks to achieve a time-relevant understanding of the asset condition in order to enable renewal or improvement works at the optimal time. TLC’s preventative maintenance schedule is outlined below.

Overhead Structure and Conductors

Key Risks

Key risks for overhead structure and conductors include • Public safety risk caused from vehicles colliding with the poles, resulting in uncontrolled exposure to live conductors

• Insulator failures

• Flashover and earth faults caused from animals (birds, opossums etc)

• Flashover caused by contact with trees or wind-blown debris

• Public or staff injury from pole collapse, caused by rotten pole structure or loss of pole stay wires

• Pole, insulator or conductor damage caused by lightning strike

Maintenance Undertaken Maintenance is centered on conducting visual inspections to identify existing or potential problems which may cause future failures.

Asset Class Frequency Scope of Work Sub-transmission 12 Monthly Helicopter patrols Lines 11 kV and Low 18 Monthly Drive or foot patrol Voltage Lines 3 Yearly Helicopter patrols - Hazard 11 kV Structure and 15 Yearly A full inspection programme including pole testing Conductors

Summary of Expenditure | 106

Cables

Key Risks

Key risks for cables are: • For Mt Ruapehu ski-field cables, public safety and reliability risk caused by rock and snow groomer damage

• Mechanical damage from third party excavations

• Cable joint failures

Maintenance Undertaken Maintenance includes visual inspections of over-ground cables, and repairs as issues are identified.

Asset Class Frequency Scope of Work

Cables (ski-field Foot patrols through the low valley areas, stream beds, rock 12 Monthly areas) movement areas, in/around tracks and high hazard areas.

Foot patrols of cables and visual inspections of till box Other Cables 3 Yearly integrity. Pillar box 5 Yearly Inspection terminations

Pole Mounted Distribution Switches

Key Risks

Key risks for pole mounted distribution switches are:

• Staff injury from flashover caused by failed switch mechanisms

• In service failure resulting in an outage

Maintenance Undertaken

Asset Class Frequency Scope of Work Remote switchgear 12 Operational check of remote controlled switchgear overhead operation Monthly Overhead Remote Change the battery on all remote switch control units. Check Switch Battery 3 Yearly alarms. Visual inspection change

3 Yearly Oil Recloser oil Operation Recloser refurbishment at workshop change Count

Summary of Expenditure | 107

Ground Mounted Distribution Transformers and Switches

Key Risks

Key risks for ground mounted distribution transformers and switches are: • Staff injury from flashover or explosion caused by failed switch mechanisms

• Electrocution risk when working on ground mount transformers with exposed conductors (in tin sheds)

• Environmental damage caused by uncontained oil spills

• Operational failure caused by deterioration of paper insulation of the windings.

Maintenance Undertaken

Asset Class Frequency Scope of Work Transformers 5 Yearly Inspection Distribution Visual Inspection, Check, record value and reset MDIs at 2 Monthly substations selected distribution substations. GM Oil filled HV 12 Monthly Service Oil Switches and check operation switch service

Voltage Regulators

Key Risks

Key risks for voltage regulators are: • Environmental risk caused by fire damage or uncontained oil spills

• Public safety risk caused by compromised fencing and barriers

• Injury to staff and public from flashover and explosion caused by faulty equipment

Maintenance Undertaken

Maintenance Type Frequency Scope of Work

Regulator Inspection 12 Monthly Visual inspection

Regulator Thermal Thermal image survey of regulator and all associated 12 Monthly Image Survey equipment and connections. Regulator Controller 12 Monthly Operation and alarm test. Test Regulator Internal 200,000 Internal inspection and change oil in regulators. Inspection Operations

Summary of Expenditure | 108

Zone Substation Buildings and Grounds

Key Risks

Key risks for zone substation buildings and grounds are:

• Substation and environmental risk caused by fire damage or uncontained oil spills

• Public safety risk caused by compromised fencing and barriers

• Water and condensation damage to control circuitry

Maintenance Undertaken

Asset Class Frequency Scope of Work

Buildings and 2 Monthly Inspection and minor repairs without requiring outage Grounds

Zone Substation Power Transformers

Key Risks

Key risks for zone substation power transformers are: • Environmental damage caused by uncontained oil spills

• Operational failure caused by deterioration of paper insulation of the windings, or manufacturing defects.

• Flashover caused by wind-blown debris

• Failure caused by windings and packing become loose and wet with age.

• Failure caused by fault currents that cause movement and localised heating.

• Failure caused by movement which can deform windings and create localised heating, resulting in ionisation of moisture in the transformer windings.

Maintenance Undertaken

Maintenance Type Frequency Scope of Work Visual Inspection 2 Monthly Routine visual equipment inspections and checks. Thermal Imaging 12 Monthly Thermal imaging. Test oil for acidity, power factor, breakdown voltage, moisture content, interfacial tension, colour and dissolved Transformer oil test 2 Yearly gas analysis (DGA). Furan reading for insulating paper analysis.

Summary of Expenditure | 109

Clean out tap changer to ensure free of arc products and Tap changer service 5 Yearly deposits. Replace insulating oil. Check contact alignment and correct operation of tap changer. Close visual inspection, insulation resistance, impedance Transformer and Winding Capacitance and power factor test, Buchholz 5 Yearly maintenance and pressure relief operational test, temperature gauge check, Neutral Earth Resistor test. Test Zone substation Test zone substation earth mats. Test bonding of 15 Years earthing system equipment and structure.

Zone Substation 33kV Switchgear

Key Risks

Key risks for zone substation 33kV switchgear are: • Injury to staff and public from flashover and explosion caused by faulty equipment

• Injury to staff from inadvertent operation of unsafe-to-operate SDAF switchgear

• Injury to staff from incorrect identification and operation of switchgear

Maintenance Undertaken

Maintenance Type Frequency Scope of Work Routine visual equipment inspections and checks, including Inspection 12 Monthly thermal imaging. Outdoor 33kV Vacuum and SF6 Circuit breaker timing and operational test. Visual 5 Yearly Circuit Breaker inspection of switchgear condition, check SF6 gas pressure. servicing

Outdoor Oil Circuit Circuit breaker timing and operational test. Visual Breaker major 5 Yearly inspection of switchgear condition. Breaker service Oil servicing change, inspect contact. Indoor Switches 2 Monthly Routine visual equipment inspections and checks. Thermal Image and Partial Discharge 2 Monthly Thermal imaging and partial discharge diagnostic tests testing Indoor 11kV Oil Circuit breaker timing and operational test. Visual Circuit Breaker major 3 Yearly inspection of switchgear condition. Breaker service Oil servicing change, inspect contact.

Indoor 11kV Vacuum Circuit breaker timing and operational test. Visual and SF6 Circuit 5 Yearly inspection of switchgear condition, check SF6 gas pressure. Breaker servicing

Summary of Expenditure | 110

Field 33kV Switchgear

Key Risks

Key risks for field 33kV switchgear are: • Injury to staff and public from flashover and explosion caused by faulty equipment.

• Injury to staff from incorrect identification and operation of switchgear.

• In service failure resulting in outage.

Maintenance Undertaken

Maintenance Type Frequency Scope of Work Routine equipment Routine visual equipment inspections and checks, including 12 Monthly inspections thermal imaging. Outdoor 33kV Vacuum and SF6 Circuit breaker timing and operational test. Visual 5 Yearly Circuit Breaker inspection of switchgear condition, check SF6 gas pressure. servicing

Outdoor Oil Circuit Circuit breaker timing and operational test. Visual Breaker major 3 Yearly inspection of switchgear condition. Breaker service Oil servicing change, inspect contact.

Outdoor current and voltage transformers

Key Risks

Key risks for outdoor current and voltage transformers are: • Arc flash and / or failure caused by wind-blown debris

• Failure or environmental damage caused from oil leaks

Maintenance Undertaken

Maintenance Type Frequency Scope of Work Routine inspections Routine visual equipment inspections and checks, including 12 Monthly and checks thermal imaging.

33kV oil filled VT’s & 3 Yearly Insulation resistance test, oil change. CT’s

Summary of Expenditure | 111

Other assets

Maintenance Undertaken

Asset Class Frequency Scope of Work

SCADA and

communications Visual inspection, battery charger and battery impedance Radio site checks 3 Yearly tests

Auxiliary supplies 12 Battery impedance test and charger test. Visual Battery maintenance Monthly inspection

Protection Relays Routine inspections and 12 Routine visual equipment inspections and checks checks Monthly Protection testing for electromechanical/static 5 yearly Secondary injection tests and check operation Relays Protection testing for 5 yearly Secondary injection tests and check operation numerical Relays

Relay attributes check including settings, standards, Protection review discrimination and records checks. Check for the impact of any changes in the Network

Summary of Expenditure | 112

Reactive Maintenance

Reactive maintenance refers to the repair of faults, as well as urgent unplanned work that may be required to avoid a safety or environmental issue or prevent an imminent failure.

Reactive maintenance cannot usually be scheduled and is highly dependent on weather events such as storms or high winds, which create conditions that can lead to a failure, e.g. wind loading, tree-fall, lightning and car-hits-pole events. Reactive maintenance uses the same engineering and field staff as planned maintenance and capital works. When it occurs, it necessarily breaks into and takes priority of the work schedule. As such work scheduling continually changes to cater for these unplanned events.

Vegetation Management

6.4.1 Introduction

Our network crosses through dense vegetation and forested areas. As such TLC has a high exposure to faults resulting from tree fall, particularly during storm events. We invest significantly in vegetation management to maintain reliable supply to our rural customers.

Vegetation management involves tree trimming and removal, inspections to determine the amount of work required, and liaising with tree owners regarding the work needed on their property.

The issues and solutions associated with our vegetation management is summarised in the table below:

Issues Steps to Address

Landowners planting under lines. 3 yearly patrols following up on new plantings.

Charging landowners for problems caused by trees that breach the fall Trees that breach the fall distance. distance if the tree does fall through lines.

Strict follow up on notices. Landowners not complying with Tree Account follow up on any invoiced charges. Regulations.

Issues are addressed one at a time when problems occur. They are mostly Legacy issues. associated with plantation owners and their desire to maximise forest production.

Where a heightened risk of forest fire is known, inspection regimes of lines, Forest fires started by trees falling through trees and associated equipment are increased to assist in reducing the lines. probability that a line fault could start a fire.

Summary of Expenditure | 113

6.4.2 Vegetation Management Performance

TLC’s tree strategy has historically focused on maintaining the areas where cutting had taken place within the prior 4 years and moving out into uncut areas in response to outage trends and areas with known problems.

TLC introduced 3 yearly helicopter patrols in 2006 covering the more remote uncut areas, which has provided a periodic view of problem growth.

In 2019 we implemented a structured vegetation management plan to ensure our approach to vegetation management wastargeted at high risk and under-performing areas of the network This plan is updated on an annual basis.

In the last two years we have increased our vegetation expenditure from $0.98m to $1.2m per year with intent to materially reduce vegetation related outages. However, the resulting impact on outage count has been variable, complicated to a large degree by changes in weather conditions between years. In 2021 we are further increasing the vegetation management expenditure to $1.4m specifically to monitor the impact that this further increase has on vegetation fault performance.

Assessing the cause of an outage when it occurs is also complicated. In some cases vegetation related outages can be reasonably assessed as being caused by weather. Similarly, vegetation can have momentary contact with a distribution line, causing a short duration outage that clears a few moments later when power is restored by an auto- recloser. These events cannot be accurately identified during or after the event and are usually recorded as being from an unknown cause.

Figure 6.2 shows the unplanned outages related to vegetation, adverse weather and unknown cause over the past five years, noting that 2016 was a mild year in terms of storm events. Although there has been a downward trend in vegetation related outages, unknown outages have been increasing, and consequently it is difficult to confirm a correlation with expenditure and outage reduction.

Figure 6.2: Unplanned outages causes recorded as vegetation, adverse weather and unknown

TLC's Unplanned Outages (Raw SAIDI) 280

240 All outages - average 200 202

160

120 Average Vegetation + Adverse Weather + Unknown

80 85

40

- 2015 2016 2017 2018 2019

Vegetation Adverse Weather Unknown All SAIDI All SAIDI - Average Average Vegetation Related

Summary of Expenditure | 114

6.4.3 Vegetation Management Strategy

In the 2020 AMP we intend to grow our knowledge of the quantum of vegetation we have on our network, develop a deep understanding of vegetation growth and behavior, and understand how best to target and optimise our vegetation expenditure.

To do this we are planning to undertake two initiatives:

• In FY2021 we will develop a vegetation database, initially populated with a Lidar survey of our 33kV and 11kV lines. This will capture a comprehensive data set allowing us to objectively assess and size our vegetation stock, which will allow us to size work and cost to maintain it to ensure acceptable service levels. • We will further increase our tree trimming expenditure to $1.4m for the FY2021 year, to identify the correlation and effectiveness of increased tree trimming on our reliability performance. The level of vegetation expenditure will be reassessed at the end of the year.

Business Support, System Operation and Network Support

Business support, system operation and network support (SONS) relates mainly to our people and business that provide the supporting functions for our operations and control functions. This includes personnel expenses, professional fees for network support and supporting expenditure.

Annual business support budget planning is based on a combination of historical costs and trends supplemented to reflect the future effort associated with projected network growth and renewal.

Summary of Expenditure | 115

Total Forecasted Operational and Maintenance Expenditure

The 10-year maintenance expenditure forecast is provided in the table below:

Table 6.1: Summary of all Operational and Maintenance Expenditure – 10 years

$ 000’s 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

Maintenance

Preventive 1,236 1,238 1,240 1,241 1,243 1,244 1,246 1,248 1,249 1,251 Expenditure

Reactive 1,186 1,186 1,186 1,186 1,186 1,186 1,186 1,186 1,186 1,186 Expenditure

Asset Replacement and Renewal

Planned 193 193 193 193 193 193 193 193 193 193 Expenditure

Vegetation Management

Planned 1,419 1,220 1,221 1,221 1,222 1,223 1,224 1,225 1,226 1,227 Expenditure

SONS

Planned 2,032 2,044 2,057 2,070 2,083 2,097 2,110 2,123 2,136 2,150 Expenditure

Business Support

Planned 7,871 7,918 7,927 7,942 7,956 7,971 7,986 8,001 8,016 8,031 Expenditure

Total 13,938 13,799 13,824 13,854 13,884 13,915 13,945 13,976 14,007 14,038

Summary of Expenditure | 116

Figure 6.3: Summary of All Operational Expenditure

Network Operational Expenditure

16,000

14,000

12,000

10,000

8,000

6,000

4,000

2,000

0

Operational Expenditure (000s) Expenditure Operational 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

Business Support System Operations and Network Support Vegetation Management Asset Replacement and Renewal Reactive Expenditure Preventive Expenditure

Summary of Expenditure | 117

Summary of Expenditure | 118

7. Summary of Expenditure and Forecast This chapter provides a summary of the expenditure forecasts discussed in previous chapters.

Capital Expenditure

Our Capital Expenditure forecasts are based on the following assumptions:

• Nominal costs (labour and materials) are assumed to be stable over the planning period

• Capital contributions have been excluded from the expenditure forecasts

Unless otherwise stated the forecasts in this section are presented in constant dollars, that is they are not inflation adjusted.

Forecasts that are presented in the appendix of this document, Schedules 11a - Forecast Capital Expenditure, in the appendix of this document that are presented in nominal dollars assume a CPI inflator of 2%.

7.1.1 Total Asset Renewal and Reliability Investment

$ 000’s 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

33kV Line Renewals 1,807 370 2,007 1,487 1,974 1,125 819 675 292 292 11kV Line Renewals 3,554 5,281 5,090 4,914 4,415 5,458 4,338 5,757 6,011 6,361 LV Line Renewals 717 382 375 928 848 836 958 538 1,127 1,620 Switchgear Automation and 404 301 232 181 77 203 85 85 85 141 Renewals Switchgear Safety 0 123 81 180 156 0 0 67 0 61 Replacements Transformer Renewals 245 245 245 245 245 272 272 272 272 272 Transformer Safety Renewals 1,430 1,726 1,318 0 0 0 0 57 120 220 11kV Cable Renewals 206 465 540 668 540 334 477 129 129 0 LV Cable Renewals 0 0 622 410 51 1,486 0 435 0 0 Substation Renewals 1,649 1,628 674 1,296 1,001 79 239 124 422 21 Vegetation Database 894 0 0 0 0 0 0 0 0 0 SCADA and Radio 412 644 66 66 66 74 74 74 74 74 Load Control 0 0 143 0 143 0 0 0 0 0 Zone Substation Reliability 1,378 21 1,028 206 0 0 0 0 0 0 All Other Renewals 327 172 126 192 112 176 79 36 36 36

Summary of Expenditure | 119

7.1.2 Total Network Development Investment

$ 000’s 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

Voltage Regulators 203 124 124 120 0 0 0 249 249 124 11kV Feeder Development 648 725 615 1,122 66 147 0 258 681 0 11kV Feeder Reliability 116 87 0 0 0 0 0 0 0 0 11kV Switchgear 607 866 348 379 707 1,066 534 534 577 630 Automation 33kV Lines Capacity 257 749 1,551 657 0 0 0 0 0 858 Development 33kV Lines Reliability 587 461 0 0 0 0 0 0 0 0 Development Supply Point Capacity 956 1,203 0 0 0 0 0 0 0 0 Development Supply Points Reliability 0 51 720 107 1,346 1,346 0 0 0 0 Development Zone Substation Capacity 56 0 112 0 112 599 534 1,282 1,282 1,282 Development Zone Substations 1,285 82 1,234 1,028 0 0 0 0 0 267 Reliability Development

7.1.3 Total Customer Required Investment

$ 000’s 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

Major Customer Projects 6,065 4,215 0 0 0 0 0 0 0 0 Other Customer Projects 0 154 654 654 654 763 763 763 763 763 General New Connections 374 374 374 374 374 416 416 416 416 416 and Upgrades

7.1.4 Total Non-Network Investment

$ 000’s 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Office Building 514 2,056 0 0 0 0 0 0 0 0 Data Systems 193 193 193 193 193 33 33 33 33 33 Vehicle Replacements 125 125 125 125 125 93 93 93 93 93 Office Area 0 0 0 0 0 0 0 0 0 0 Plant and Equipment 34 34 34 34 34 38 38 38 38 38

Summary of Expenditure | 120

7.1.5 Capital Expenditure

The total capital expenditure for the 10 year planning period is summarized in the following table.

$ 000’s 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

Network

Asset Renewals 13,999 12,078 12,549 10,773 9,629 10,043 7,342 8,250 8,568 9,098 Customer Required 4,726 4,360 4,716 3,425 2,244 3,172 1,082 2,336 2,803 3,176 Network 6,440 4,744 1,028 1,028 1,028 1,179 1,179 1,179 1,179 1,179 Development

Non-Network

Routine 352 352 352 352 352 164 164 164 164 164 Atypical 514 2,056 0 0 0 0 0 0 0 0

All Capital 26,032 23,590 18,645 15,579 13,254 14,558 9,767 11,930 12,714 13,617 Expenditure

Capital Contributions (6,065) (4,215) (654) (654) (654) 0 0 0 0 0 from Customers

Total Expenditure 19,966 19,375 17,991 14,925 12,600 14,558 9,767 11,930 12,714 13,617

Figure 7.1: Total Network Capital Expenditure

Network Capital Expenditure 30,000

25,000

20,000

15,000

10,000

5,000

Capital Expenditure (000s) Expenditure Capital 0 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

Asset Renewal Programme Network Development Programme Customer Required Projects Non Network Atypical Non Network Routine

Summary of Expenditure | 121

Operational Expenditure

Our Operational Expenditure forecasts are based on the following assumptions

• Nominal costs (labour and materials) are assumed to be stable over the planning period

• The operating and regulatory environment remains consistent with current experience.

Unless otherwise stated the forecasts are presented in constant dollars, that is they are not inflation adjusted.

Forecasts that are presented in the appendix of this document, Schedules 11b - Forecast Operational Expenditure, in the appendix of this document that are presented in nominal dollars assume a CPI inflator of 2%.

$ 000’s 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

Maintenance

Preventive 1,236 1,238 1,240 1,241 1,243 1,244 1,246 1,248 1,249 1,251 Expenditure Reactive 1,186 1,186 1,186 1,186 1,186 1,186 1,186 1,186 1,186 1,186 Expenditure

Asset Replacement and Renewal

Planned 193 193 193 193 193 193 193 193 193 193 Expenditure

Vegetation Management

Planned 1,419 1,220 1,221 1,221 1,222 1,223 1,224 1,225 1,226 1,227 Expenditure

SONS

Planned 2,032 2,044 2,057 2,070 2,083 2,097 2,110 2,123 2,136 2,150 Expenditure

Business Support

Planned 7,871 7,918 7,927 7,942 7,956 7,971 7,986 8,001 8,016 8,031 Expenditure

Total 13,938 13,799 13,824 13,854 13,884 13,915 13,945 13,976 14,007 14,038

Summary of Expenditure | 122

Figure 7.2: Total Network Operational Expenditure

Network Operational Expenditure

16,000

14,000

12,000

10,000

8,000

6,000

4,000

2,000

0

Operational Expenditure (000s) Expenditure Operational 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

Business Support System Operations and Network Support Vegetation Management Asset Replacement and Renewal Reactive Expenditure Preventive Expenditure

Summary of Expenditure | 123

Asset Management Performance | 124

8. Asset Management Performance This chapter provides an overview of our network performance, its impact on our customers, and our targets for improving customer outcomes.

Introduction

8.1.1 Overview

This chapter outlines our performance and targets for the FY2021 to 2030 years. There are three areas of focus:

• Safety

• Network Performance

• Customer experience

The measures outlined in this chapter are based on progressive improvements to our performance monitoring framework and may differ to those outlined in the last full AMP in 2018. Our asset management performance framework is undergoing continuous review to align it with the new strategic direction of the company, and it is expected that the measures and targets will continue to change as this work is completed.

Improvements that will contribute to these changes are identified in each of the categories below.

8.1.2 SAIDI and SAIFI Indices

Reliability of supply is measured by network performance indicators called SAIDI and SAIFI which are used extensively through this chapter. The definitions of these indices are as follows:

• SAIDI: System Average Interruption Duration Index.

SAIDI is a measure of the total duration of outages that an average customer may experience each year. It is calculated as the sum of all outage minutes for each customer on the network, divided by the total number of customers to give an average.

• SAIFI: System Average Interruption Frequency Index.

SAIFI is a measure of the total frequency of outages that an average customer may experience each year. It is calculated as the count of all outages for each customer on the network, divided by the total number of customers to give an average.

For compliance reporting, SAIDI and SAIFI are normalised by applying compliance rules to adjust the measures under certain defined circumstances. For most of this chapter however, analysis is presented as either Raw SAIDI or Raw SAIFI which means they have not been normalised. We have used this approach for the analysis and improvement

Asset Management Performance | 125

targets because raw values give a true view of the impact that is felt by customers from supply outages on the TLC network.

Safety

8.2.1 Overview

Safety of our team, our customers and our community is of paramount importance to TLC. We strongly believe that there is no job that is so important that it cannot be completed safely.

TLC is committed to a zero-harm culture, and so we seek to minimise the risk of harm to people by incorporating safety into the design and operations of our business and assets.

Safety targets for the coming year are:

• That there are no notifiable incidents that lead to serious harm;

• There is steady decrease in lost time injuries and;

• That there is continuous improvement in our health and safety culture.

Public Safety

A large number of our assets are located within areas that are accessible to the public. Our design standards include incorporation of public safety requirements, and ongoing inspection and audit of our network ensures that these safety measures remain effective. Areas that are deemed as high public safety risks (e.g. schools, parks, community areas) are inspected on a more regular basis. During execution of work on our assets, our teams are focused on ensuring that all risks and hazards are identified and managed in accordance with best industry practice.

Our public safety target is zero public safety incidents.

Privately Owned Lines

Our preventative maintenance inspections will often identify and attend to unsafe service lines. However, there are a large number of privately-owned service lines which are not maintained by TLC. Where an unsafe customer-owned service line is identified, we will work with the owner, and if necessary, work with Energy Safety to reach a satisfactory outcome.

Asset Management Performance | 126

Network Performance

8.3.1 Planned outages

TLC advises customers of planned shutdowns for maintenance or other planned work, by way of a shutdown notification. The notification (usually mailed) provides the reason for the shutdown as well as the planned start and finish times. Planned shutdowns are measured and reported on each year through TLC’s annual regulatory reporting.

8.3.2 Faults

Faults on the TLC network may occur from asset defects or external effects such as storms, tree fall, or interference from third parties such as animals or car crashes. Faults are unplanned interruptions and TLC tracks these faults in various forms, including the number of faults that occur each 100km of line shown below. Our target is to achieve an average of 14.36 faults per 100km on our 11kV lines, which is the industry average for 11kV distribution lines.

Figure 8.1: Faults per 100km of line (count of all interruptions on the 11kV network)

Faults per 100km - Distribution Lines (11kV) 40 35 30 Target = 14.36 (Industry Average) 25 20 15 10

5 Faults per 100km of Overhead Line Overhead of 100km per Faults 0 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

Total Target

The cause of faults on our network falls into seven categories ranging from defective equipment to third party interference (e.g. a car hits a pole). The table below shows the type and quantity of faults that happen on the TLC network each year on average, and the impact on our customers in terms of total average minutes without supply (technically known as Raw SAIDI). Although some of these causes are outside TLC’s control, we try to minimise the effects of these faults when they occur, by repairing the line as quickly as possible or by putting in place backup supply systems.

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Table 8.1: Type and Quantity of Faults on the TLC Network – five year average (2015 to 2019)

Impact of Unplanned Interruptions Number of Unplanned Interruptions (Raw unplanned outage minutes)

Cause of Interruption Count % of total Minutes % of total Defective equipment 194 30% 77 37% Wildlife 43 7% 6 3% Unknown 122 19% 15 7% Adverse weather 55 8% 24 11% Vegetation 77 12% 47 22% Lightning 129 20% 12 6% Human error 3 0% 3 1% Third party Interference 26 4% 25 12%

8.3.3 Major Causes of Interruptions

The faults that have the most significant impact on customer supply on the TLC network are defective equipment, vegetation (meaning tree-fall), adverse weather and third-party interference. The graph below shows the impact of these interruption types over the last ten years. Our asset management plan seeks to minimise all interruptions through planning, maintenance and operational activities like tree trimming.

Figure 8.2: SAIDI by Main Cause

RAW SAIDI by Main Cause Breakdown of outage minutes per customer by cause of interruption

250

200

150

year) 100 RAW SAIDI RAW

50

0

(Average outage minutes per customer per per customer per minutes outage (Average 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

Defective equipment Vegetation Adverse weather Third party Interference

8.3.4 Interruptions Caused by Defective Equipment

Defective equipment contributes 35% of TLC’s unplanned interruptions on average, however some defective equipment outages can have a significant customer impact in terms of minutes without supply. For example, in

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FY2018, eleven defective equipment outages (6% of the total defective equipment outages by count), contributed 64% total defective equipment outage minutes.

Figure 8.3 shows the proportion of defective equipment outages over the last five-year period.

Figure 8.3: Defective equipment outage trends – last 5 years

Unplanned Outages (Raw SAIDI) 280

240 All outages - average 200 202 All SAIDI 160 Defective Equipment 120 All SAIDI - Average 80 Defective Equipment - average 71 Defective Equipment Average 40

- 2015 2016 2017 2018 2019

We have undertaken a review of defective equipment outages to understand their cause and impact. Figure 8.4 shows the breakdown of main causes of defective equipment outages over the past five years.

Figure 8.4: Defective equipment outage trends (main causes) – last 5 years

Defective Equipment Breakdown of outage minutes by main cause

80 70 Ageing Equipment

60 TLC Operator & Authorised 50 Contractor Error Pole 40 Cable - Underground

RAW SAIDI RAW 30 20 Connection Failure 10

(Ooutage minutes per customer) per minutes (Ooutage 0 2015 2016 2017 2018 2019

The key findings for our analysis are:

• Defective equipment outages of the sub-transmission (33kV) network or associated zone substations have a large impact.

• Power transformer failures were a material cause of defective equipment SAIDI over the past three years.

• Pole top (cross arms and insulators) have grown as a cause of defective equipment outages.

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To address these issues, we are implementing a number of actions:

• An additional four power transformers have been ordered in FY20. Two of these will be placed into service to replace units that have been removed to accommodate transformer failures in other areas. A further two units will be held as spares to be used as permanent installations in the event of other power transformer failures. This will see swifter return to service times through being able to contingency plan for replacement. It will also lower overall costs should a failure occur because the spare transformers will be right sized to become a permanent installation.

• Replacement of the Kuratau transformer (shifting a 5MVA unit into place following upgrade to the Borough Substation which serves Taumarunui) and the installation of automation to allow a swifter restoration of supply in the event of another transformer failure at that substation.

• We have created a priority pole programme. In total 601 poles and 1602 cross arms have been scheduled for replacement across the network in FYs 2020 and 2021 to target problematic crossarms.

• The line inspection programme will be changed to target line inspection based on assessed pole risk, rather than the current time-based process. This will see inspections carried out on areas that have the potential for higher impact on customers and provide more accurate information to assess future line renewal work.

• We are improving the data quality within our asset management system to improve aged or incomplete records and to prioritise the assessment and population of records with unknown asset condition. This will allow more accurate prediction of future risk of failure.

Targets

We are targeting a 40 SAIDI minute reduction at the end of FY2022 (against FY2018 numbers) in defective equipment as a result of these changes.

8.3.5 Interruptions Caused by Vegetation

Vegetation interruptions are outages that are caused by trees or other vegetation falling onto a power line. TLC is particularly exposed to vegetation interruptions because much of its ~4000km of power lines run across rural land and in many cases through forestry plantations. Vegetation outages are also closely linked to adverse weather, so the following analysis also provides our key mitigation options for managing adverse weather issues.

Figure 8.5: Vegetation outage trends – last five years

Unplanned Outages (Raw SAIDI) 280

240 All outages - average 200 202 All SAIDI 160 Vegetation 120 All SAIDI - Average 80 Vegetation outages- average Vegetation Average 40 47

- 2015 2016 2017 2018 2019

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Vegetation Review

We have undertaken a comprehensive review of vegetation outages covering the 2018 and 2019 financial years. The key findings were:

• The most significant causes of outages are:

o growth into lines o trees/branches falling and causing an outage. o trees falling through line (initiated by weather). • Increasing expenditure on vegetation control (i.e. tree trimming) reduces vegetation outages

• Annual inspections via helicopter and foot patrol have been effective in managing this risk

Table 8.2 below shows the key issues identified during the review for the 2018 and 2019 financial years.

Table 8.2: Key Vegetation Management Issues Identified

2018 Key Issues 2019 Key Issues Wind borne material causing outages, resulting from Non-planation outages caused by tree growth and branch weather related events contact Non-planation outages caused by tree growth and Planation trees falling through subtransmission lines branch contact causing outages resulting from weather related events The worst performing feeders were Kuratau, Taharoa A 33, The worst performing feeders were Raurimu, Gravel Te Mapara, Northern, Maihiihi, Raurimu. However, of these Scoop, Ongarue, and Bennydale. only Raurimu and Northern had more than two outages. Significant one-off outages caused by trees through lines.

Vegetation management plan

As a result of this analysis we have developed a vegetation management plan, which defines specific actions to reduce vegetation related outages and their impact on the TLC network and consumers. The vegetation management plan outlines a five-point vegetation management strategy:

Table 8.3: Vegetation Management Strategy

Strategy Issues addressed Reduce potential for non-plantation tree growth into lines Maximise tree felling within growth zones and improve resilience to weather-related issues Where felling cannot be achieved, seek tree clearance at Reduce potential for non-plantation tree growth into lines a 5-year growth zone and improve resilience to weather-related issues Reduce the potential for plantation trees falling through Increase the plantation tree clearances from lines lines Maximise the SAIDI reduction impacts by ensuring that Ensure vegetation on all high-impact feeders is feeders with high potential impacts are addressed to inspected and proactively remediated reduce the potential for one-off major vegetation outages. Match the vegetation resources to the vegetation Prevent underspend of vegetation budget. budget

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Planned Actions

The following actions have been undertaken or are in process to improve our management of vegetation.

• Increase vegetation management budget and vegetation cutting work

A 30% increase in the vegetation management budget was approved for FY2021, bringing the total to $1.4m. This will result in around 14,500 trees cut or trimmed each year and is the key mitigation tool for TLC to reduce vegetation outages.

• Dedicated Vegetation Manager

A new Vegetation Manager role has been created and filled. The key purpose of this role is to make the vegetation management work more proactive, ensure that work is completed as planned, and to address any issues identified

• Additional vegetation inspections

Additional resource has been contracted to carry out vegetation inspections on areas of the network that are showing decreasing performance due to vegetation. This work will be targeted on performance of the network and prioritised by risk and criticality (we will be targeting the consistently poor performing feeders and areas where there are known issues and risks).

• Establishment of a vegetation database

A vegetation database will be established to allow ongoing monitoring of vegetation near our lines, including vegetation type, size and growth rates. The database will allow analysis of our vegetation and allow us to optimise the effectiveness and expenditure on vegetation management. A Lidar survey (aerial radar technology) which is undertaken by aircraft is planned to be completed in the coming 12-month period to establish an initial data set for the vegetation database.

Targets

We have set an ambitious target where by the end of FY2021 vegetation related outages will be no greater than 15% of unplanned SAIDI. Achieving this target will place us between the median of all electricity distributors in New Zealand (12%) and below our peer group (other rural electricity distributors) who have an average of 17%.

8.3.6 Interruptions Caused by Third Party Interference

Third party interreference outages are outages that are caused by the activities of people that impact our network. A common example is when a car crashes into a pole and causes an outage. Third party interference outages make up about 12% of TLC’s total outages on average.

Figure 8.3.9 shows the trends of third-party outages on the TLC network over the past five years.

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Figure 8.6: Third party interference outage trends – last five years

Unplanned Outages (Raw SAIDI) 280

240 All outages - average 200 202 All SAIDI

160 Thrird Party Interference 120 All SAIDI - Average 80 Third Party Interefernce 40 Third Party Interference - average Average 25 - 2015 2016 2017 2018 2019

Planned Actions

Because third party interference outages are caused by the activities of people, they are difficult to predict or prevent. The key mitigation is to ensure the TLC network has response mechanisms in place to minimise impact when they occur. Therefore, we are continuing significant investment in automation and sectionalisation. This enables more granular areas of our network to be isolated when a fault occurs, so that supply can be restored to more customers, faster.

8.3.7 Managing Unplanned Outages

General Approach

We incorporate five general approaches to mitigate unplanned outages:

• Reducing the probability of occurrence. This is through design (planned backup and redundancy of critical assets), maintenance and inspection.

• Restricting the extent of an outage. This is inherent in the design of the network through the protection settings, sectionalisers, reclosers etc.

• Responding to an outage once it occurs and this will involve travel time and assessment of the cause of the fault. Until this is complete it is not possible to identify the swiftest method to restore supply, typically this is two to three hours for a major fault.

• Restoration of supply to some or all customers through removing the fault, putting in place backfeeds or if necessary, installation of generation. Note generation connection is generally 2-3 hours of work once a generator is on site, so an assessment of repair vs generation time is made by the field and control room teams.

• Remediation of any faulted equipment, which may be at the time of the fault, or deferred if interim arrangements can be made to restore supply, subject always to staff and public safety.

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Specific Improvement Actions

The Asset Management Plan Update for 2019 identified improvements in reliability that TLC intended to make and estimated the corresponding SAIDI and SAIFI improvement that these actions would realise. These actions are now in progress and continue to be priorities for this 2020 Asset Management Plan.

Initial Action Expected Reduction Progress Target

SAIDI SAIFI

Security of Supply Progress on all four initiatives - approximately 35% 13 0.24 EOFY22 Upgrades complete. Power Transformer Approach modified, two transformers ordered, two 12 - EOFY22 reliability undergoing finalisation of contract Increased network 17 - EOFY21 Approximately 40% complete. automation Additional crossarm & 11 0.08 EOFY22 Approximately 60% complete. insulator replacement Enhanced vegetation 33 0.2 EOFY21 Additional spend and resource on vegetation achieved management

8.3.8 Feeder Performance

Along with measuring the causes of outages, we also track how outages affect individual feeders on our network. A feeder is a long power line that distributes energy from zone substations. TLC has 76 feeders in total. Their individual performance is a function of both asset condition and the environmental elements they are exposed to, such as interference from trees and their exposure to wind or snow.

Figure 8.7 shows the individual feeder performance. The left graph shows the count of all faults on each feeder (as a five-year average) and the graph on the right shows the average minutes of outages per customer on each feeder.

Figure 8.7: Feeder Performance – Count of faults, and Raw SAIDI per feeder

Raw SAIDI by Feeder 5-Year Average 2015-2019 All Faults per Feeder - 5 Year Average 2015-2019 35 14 30 12

25 10

8 20

6 15

4 10 Average for all feeders Average for all feeders 2 5

- -

Performance is measured as both the period of outages (SAIDI) and the frequency that they occur (SAIFI). The graph below shows how each feeder ranks based against SAIDI and SAIFI. The size of each dot represents the volume of customers connected to each feeder. The best performing feeders fall within the square.

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Figure 8.8: Feeder Performance – Raw SAIDI vs Raw SAIFI

Feeder Performance Analysis

0.20 Tokaanu / Kuratau 33

Tangiwai Northern 0.15

Kuratau 0.10 Coast

Ohura 0.05 Mahoenui

0.00

SAIFI (Defective SAIFI (Defective Equipment Interruptions last 3 years) -5 - 5 10 15 20 25

-0.05 SAIDI (Defective Equipmeent Interruptions Last 3 years)

Good Condition Medium Condition Low Condition

Planned Actions

Our historic maintenance and line renewal work used asset condition as the primary driver for expenditure. In the 2020 AMP we are also seeking to improve the performance of our worst performing feeders (those outside the square). We will still retain expenditure to maintain a good level of asset condition, but projects to improve our worst performing feeders will be elevated in their priority compared with prior years.

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Customer Experience

8.4.1 Overview

Our customers’ experience in dealing with us and the service levels they receive from our network are key elements in how we operate our business. We remain focused on ensuring that our network remains reliable and that when our customers contact us, we respond in a timely and professional manner to resolve their queries.

We proactively engage our customers through regular customer clinics across the region offering advice on improving energy efficiency within the home, tips on managing power bills and general information on the services that we offer as a company as well as soliciting feedback on the level of service they receive from us at both a company and a network level.

This year we are revising how we monitor customer experience based on their proximity to major towns, rather than as single averaged performance indicator. We have reclassified our network into three groups

• Urban – customers that live within 5 km of a major town

• Rural – customers that live within 5-40 km of a major town

• Remote – customers that live beyond 40 km from a major town

Figure 8.9 shows the number of customers within each category.

Figure 8.9: Number of Urban Rural and Remote Customers on the TLC network

Urban, Rural and Remote Customers on the TLC network 12,000

10,000 11,139 10,225 8,000

6,000

4,000 2,000 2,885 Customers of Number - 0..5km 5..40km 40+ km Urban Rural Remote

8.4.2 Trends and Targets

We are seeking to continuously improve our performance by reducing the outages in each customer group by 3% per year. Figure 8.10 shows the historical average outage performance and the improvement we are targeting for the next five-year period.

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Figure 8.10: Outages and targets for Urban, Rural and Remote customers

SAIDI Targets for Urban, Rural and Remote Customers

350 300 Urban - 5 year average 250 Urban Target 200 Rural - 5 year average 150

Rural Target Raw SAIDI Raw 100 Remote - 5 year average 50 Remote Target 0 2019 2020 2021 2022 2023 2024 2025

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Regulatory Measures and Targets

8.5.1 Safety

Financial Year

Safety 2018 2019 2021 2022 2023 2024 2025

Lost Time Injuries 5 8 Continued reduction from previous year

Serious Harm Incidents 0 0 0 0 0 0 0

Public Safety Incidents 0 0 0 0 0 0 0

8.5.2 Customer Experience Measures and Targets

Compliance Targets (Normalised values) Financial Year

Planned 2018 2019 2021 2022 2023 2024 2025

Planned SAIDI 77.7 148.9 88 88 88 88 88

Planned SAIFI 0.52 1.09 1.75 1.75 1.75 1.75 1.75

Unplanned 2018 2019 2021 2022 2023 2024 2025

Unplanned SAIDI 226.0 240.1 165 159.5 154 148.5 143

Unplanned SAIFI 3.52 3.89 2.6 2.6 2.6 2.6 2.6

Customer Targets (Raw SAIDI / SAIFI) Financial Year Raw Unplanned Customers 2018 2019 2021 2022 2023 2024 2025 SAIDI/SAIFI Urban 46% 59.2 44.1 46 45 43 41 40 Unplanned Rural 42% 140.1 156.8 123 119 115 111 107 SAIDI Remote 12% 26.7 39.1 31 30 29 28 27

Total 100% 226.0 240.1 201 194 187 180 174

Urban 46% 1.3 1.1 1.2 1.1 1.1 1.0 1.0 Rural 42% 1.8 2.3 1.8 1.7 1.6 1.6 1.5 Unplanned SAIFI Remote 12% 0.4 0.4 0.5 0.4 0.4 0.4 0.4

Total 100% 3.5 3.9 3.4 3.3 3.2 3.0 2.9

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8.5.3 Cost Efficiency Measures and Targets

Values in constant dollars (i.e. excluding CPI) Financial Year

Opex Cost per Customer 2018 2019 2021 2022 2023 2024 2025

Target 499 517 588 579 578 576 574

Actual 513 601

Variance % 2.8% 16.2%

Values in constant dollars (i.e. excluding CPI) Financial Year

Capex Cost ($000) 2018 2019 2021 2022 2023 2024 2025

Target 19,365 18,377 19,966 19,375 17,991 14,925 12,600

Actual 14,460 22,359

Variance % -36%% 18%

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9. Continual Improvement This chapter explains how our current asset management performance is assessed to identify gaps to drive improvement programme.

Assessment of Asset Management Performance

9.1.1 Asset Management Maturity Assessment Tool (AMMAT)

The Asset Management Maturity Assessment Tool is a prescribed group of questions set by the Commerce Commission that all electricity distributors in New Zealand must use to assess our asset management capability.

The AMMAT tool is a self-assessment comprising 31 questions that are grouped into six key areas. The questions relate to the key components of the PAS 55 standard framework for asset management and ranks our maturity level from 0 to 4. We undertake this self-assessment each year to track and report on our progress in asset management competency.

The AMMAT tool informs us and stakeholders about the level of competency we believe we have reached at the time of assessment. We derive benefit from our internal discussions and views around the level of asset management capability and competency appropriate for our stakeholders and the identification of improvement opportunities.

9.1.2 2020 AMMAT Assessment

Our 2020 assessment is summarised below. Overall, we believe our asset management performance and maturity is still developing, but we have made significant improvements since our last assessment in 2019. This indicates that the initiatives we are undertaking to improve our business systems, structure, and asset management processes are beginning to take effect. We have a range of initiatives planned for the coming year that are intended to lift our understanding of our assets, their key risks and the way we manage our asset management workflow. We are also continuing to progress our core asset management structure and processes.

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Figure 9.1: Asset Management Maturity Assessment

Asset strategy and delivery TLC 2019 4.0 TLC 2020 3.5 PAS 55 Compliance 3.0 2.5 Competency and training 2.0 Documentation, controls and review 1.5 1.0 0.5 0.0

Structure, capability and Systems, integration and authority information management

Communication and participation

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9.1.3 Asset Management Gaps to Maturity Level 3

An assessment of each functional area of asset management shows the following gaps to competent (Maturity level 3): Table 9.1: AMMAT Improvement Opportunities

PAS 55 Functional Area Improvement Opportunities

Enhance communication of Asset Management Policy for general awareness and understanding of policy content by relevant persons. Network Monthly Report meeting is a Asset Management good opportunity for a brief checking of alignment of the Asset Management Policy to Policy collect information for a periodic review of the policy. Document the requirements for the communication of the policy in the Strategic Asset Management Plan (SAMP)

Produce a separate SAMP which gives a full coverage of the strategies required for all asset Asset Management management activities and provides a clear version control of the reference. Strategy Document the requirements for continual implementation of the Asset Management Strategy and monitoring the performance.

Asset management Put the processes in place for reviewing the performance of the internal people and the plan(s) external service providers so that they are aligned to defined responsibilities.

Complete the development of TLC Incident Management Plan Consider adding: • a chart to show the framework and the key elements of the plan • risk responsibilities (duty manager) under each of the of the “four R”s in the Contingency planning Business Continually Framework. Document contingency plans for: • Key maintenance activities • Major network scenarios • Resources including internal and external resources

Structure, authority and Document the communication strategy when developing a SAMP. responsibilities Outsourcing of asset Develop the processes for contractor performance review management activities

Develop a structured means for planning and recording training for all core asset Training, awareness and management related competencies. competence Regular performance review to assess staff competency level and identify required training

Asset Management Provide more detailed description of AMS when developing a SAMP document. System documentation

Continue to implement formal data quality review processes. Information Develop overarching information requirements for asset management which allow a management continual review of information needs as part of continual improvement processes. Develop asset information strategy and include it in the SAMP.

Risk management Continue to develop asset risk profiling modes for the key network asset classes.

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Document and approve the resource, competence and training requirements that are necessary to implement the risk control measures in the training plans or risk management strategy.

Outline TLC legal compliance obligations and document the strategy for identifying and Legal and other reviewing relevant legislation and regulation for change. requirements Document the strategy for communication to ensure awareness in all relevant parties and the strategy for providing appropriate training as required to relevant personnel.

Document the KPI processes for projects and maintenance. Life Cycle Activities Develop equipment procurement specifications, construction standards, and project standards.

Apply the Ofgem Common Methodology to all key asset classes to consistently assess condition, performance and risk for the network assets to enable a continual improvement in delivering high quality network performance through targeted risk reduction at the Performance and lowest life cycle cost. condition monitoring Utilise the existing asset risk management models developed for TLC overhead line assets to gain a deep understanding of asset health and criticality with the contributing data and factors which will have a vital influence in the decision making.

Investigation of asset- related failures, Complete development of TLC Incident Management Plan. incidents and nonconformities

Corrective & Continue implementing asset management system to align with ISO 55001 framework. Preventative action Continue to embed continuous improvement as part of the TLC’s basic culture.

9.1.4 Communication and Participation

A key area of improvement has been TLC’s communication of its Asset Management Plan and processes across the business. This has been an outcome of our AMP review initiative that commenced in 2017 and has included a full process review and re-development of our asset management policy and framework. Staff across the organisation have participated in the review process as part of that development initiative.

Our communication with the wider stakeholder group has been by way of newsletters to the community, and direct engagement with our major customers, our Board and our Trust.

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9.1.5 Key Initiatives for Improvement

The conclusion from this review is that we are making steady progress in our asset management maturity, but also that have many areas that we can further strengthen.

9.1.6 Key Initiatives for Improvement

We have identified several areas for improvement which will be a key focus for our asset management development in the next 12 months. These are outlined in the following table.

Table 9.2: Planned AMMAT Improvement Initiatives

Improvement Area Key Initiatives

Safety and Continue to develop TLC’s safety and environmental processes, and cultural development Environmental

Management Continue development and documentation of asset management processes, including TLC’s asset management strategy and strategic asset management plan, which underpin this AM Process Regulatory AMP. Development Put processes in place to communicate the AM Policy, Strategy and SAMP with the asset management team and TLC business stakeholders. Embed the Risk Framework into the organisation. Consistently apply risk management processes across the organisation and in asset Risk Management management planning activities. Maintain a risk register that identifies and monitors management of high risks Emergency Response Continue development of emergency response and business continuity plans, and ensure Planning they are routinely developed and tested. Improve timeliness and quality of capital works design (work packs) Improve processes that enable formal options analysis, cost estimation and business case development for major projects Capital Works Planning Improve processes that support quality design and project management for large complex projects that are atypical for the business but are key deliverables in the short to medium term. Continue to progress the structure of the asset management and service delivery teams to ensure all staff have a clear understanding of their role in the asset management process. Ensure these are defined in their job descriptions, performance plans, and performance reviews. AM Team Development Ensure they are equipped with the necessary tools and training and management support to be effective in their role. Put in place a structured process for planning and recording training for asset management related competencies. Complete deployment and integration of automated field tools Information Systems Integrate GIS and asset data systems Further develop asset data systems to provide asset condition and risk insights Further develop business scheduling and resource management systems Service Delivery Review and put in place service level agreements with internal and external service Mechanisms providers. Develop integrated service delivery reporting mechanisms

Continual Improvement | 145

Appendices | 146

10. Appendix A: Glossary

ABBREVIATION DESCRIPTION

ABS Air Break Switch

AHI Asset Health Index

AMMAT Asset Management Maturity Assessment Tool

AMP Asset Management Plan

CB Circuit Breaker

DGA Dissolved Gas Analysis

DNO Distribution Network Operators

EDB Electricity Distribution Business

EV Electric Vehicle

GIS Geographic Information System

GWh Gigawatt Hour

GXP Grid Exit Point

HI Health Index

HILP High Impact Low Probability

HV High Voltage

ICP Installation Control Point

IT Information Technology

kV Kilovolts

kW Kilowatt

LTI Lost-time Injury

LTIFR Lost-time Injury Frequency Rates

Appendices | 147

ABBREVIATION DESCRIPTION

LV Low Voltage

MVA Mega Volt Ampere

MW Megawatt

N N system security means that the system is not able to tolerate the failure of any single component in the network. Any failure will result in a loss of supply

N-1 N-1 means that the system must be able to tolerate the failure of any single component in the network without affecting the supply of electricity

OH Overhead Lines

PD Partial Discharge

PoF Probability of Failure

PoS Point of Supply

PV Photovoltaic

RCA Root Cause Analysis

SAIDI System Average Interruption Duration Index

SAIFI System Average Interruption Frequency Index

SCADA Supervisory Control and Data Acquisition

SF6 Sulphur Hexafluoride

SONS System Operation and Network Support

TLC The Lines Company

XLPE Cross Linked Polythene

Appendices | 148

11. Appendix B: Information Disclosure Compliance

REFERENCE REQUIREMENT REF

Summary

3.1 The AMP must include a summary that provides a brief overview of the 1.2 contents and highlights information that the EDB considers significant.

Background and Objectives

3.2 The AMP must include details of the background and objectives of the EDB's 1.2.1, 1.3.1, 4.3, asset management and planning processes. 5.1.1, 6.1.1

Purpose Statement

3.3 The AMP must include a purpose statement that:

3.3.1 Makes clear the purpose and status of the AMP in the EDB's asset 1.1 management practices. The purpose statement must also include a statement of the objectives of the asset management and planning processes.

3.3.2 States the corporate mission or vision as it relates to asset management. 1.1

3.3.3 Identifies the documented plans produced as outputs of the annual business 4.1 planning process adopted by the EDB.

3.3.4 States how the different documented plans relate to one another, with 4.1 particular reference to any plans specifically dealing with asset management.

3.3.5 Includes a description of the interaction between the objectives of the AMP 4.1, 4.2, 4.3, and other corporate goals, business planning processes, and plans. 4.4

AMP Period

3.4 The AMP must state that the period covered by the plan is 10 years or more 1.2 from the commencement of the financial year.

3.5 The AMP must state the date on which the AMP was approved by the Board 1.2 of Directors.

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Stakeholder Interests

3.6 The AMP must include a description of stakeholder interests (owners, consumers etc) which identifies important stakeholders and indicates:

3.6.1 How the interests of stakeholders are identified. 2.3.5

3.6.2 What these interests are. 2.3.5

3.6.3 How these interests are accommodated in asset management practices. 2.3.5

3.6.4 How conflicting interests are managed. 2.3.5

Accountabilities and Responsibilities

3.7 The AMP must include a description of the accountabilities and responsibilities for asset management on at least 3 levels, including:

3.7.1 Governance - a description of the extent of director approval required for key 4.1, 4.4, 4.6 asset management decisions and the extent to which asset management outcomes are regularly reported to directors.

3.7.2 Executive - an indication of how the in-house asset management and 2.1.4 planning organisation is structured.

3.7.3 Field operations - an overview of how field operations are managed, 2.1.3, 5.9 including a description of the extent to which field work is undertaken in- house and the areas where outsourced contractors are used.

Assumptions

3.8 The AMP must include all significant assumptions. 1.2.2 5.10, 7.1, 7.2

3.8.1 All significant assumptions must be quantified where possible. 5.10

3.8.2 All significant assumption must be clearly identified in a manner that makes 1.2.2, 5.10, their significance understandable to interested persons. 7.1, 7.2

3.8.3 The identification of significant assumptions must include a description of 1.2.2, 5.10, changes proposed where the information is not based on the EDB's existing 7.1, 7.2 business.

3.8.4 The identification of significant assumptions must include a description of the 1.2.2, 5.10, sources of uncertainty and the potential effect of the uncertainty on the 7.1, 7.2 prospective information.

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3.8.5 The identification of significant assumptions must include a description of the 7.1, 7.2 price inflator assumptions used to prepare the financial information disclosed in nominal New Zealand dollars in the Report on Forecast Capital Expenditure set out in Schedule 11a and the Report on Forecast Operational Expenditure set out in Schedule 11b.

Material Difference in Information

3.9 The AMP must include a description of the factors that may lead to a 1.2.2, 5.10 material difference between the prospective information disclosed and the corresponding actual information recorded in future disclosures.

Asset Management Strategy and Delivery

3.10 The AMP must include an overview of asset management strategy and 2.2.1, 4.1, 4.6, 5 delivery.

Systems and Information Management Data

3.11 The AMP must include an overview of systems and information management 4.7 data

3.12 The AMP must include a statement covering any limitations in the availability 3.1.4, 4.7.6, 5, or completeness of asset management data and disclose any initiatives 6.4.3, 9.1.3 intended to improve the quality of this data.

Asset Management Process

3.13 The AMP must include a description of the processes used within the EDB for:

3.13.1 Managing routine asset inspections and network maintenance. 4.6, 6.2, 6.3

3.13.2 Planning and implementing network development projects. 4.1, 4.6

3.13.3 Measuring network performance. 4.6

3.14 The AMP must include an overview of asset management documentation, 4.6 controls and review processes.

Communication Processes

3.15 The AMP must include an overview of communication and participation 4.1, 4.6, 9.1.4 processes.

Financial Values

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3.16 The AMP must present all financial values in constant price New Zealand Throughout dollars except where specified otherwise. the document

Disclosure Requirements

3.17 The AMP must be structured and presented in a way that the EDB considers Throughout will support the purposes of AMP disclosure set out in clause 2.6.2 of the the document determination.

Assets Covered

4 The AMP must provide detail of the assets covered, including:

4.1 A high-level description of the service areas covered by the EDB and the 1.2 degree to which these are interlinked, including:

4.1.1 The region(s) covered. 2.3

4.1.2 Identification of large consumers that have a significant impact on network 2.3 operations or asset management priorities.

4.1.3 Description of the load characteristics for different parts of the network. 2.3

4.1.4 Peak demand and total energy delivered in the previous year, broken down 1.2.5 by sub-network, if any.

Network Configuration

4.2 The AMP must provide a description of the network configuration, including:

4.2.1 Identifying bulk electricity supply points and any distributed generation with 3.2, 3.3 a capacity greater than 1 MW. State the existing firm supply capacity and current peak load of each bulk electricity supply point.

4.2.2 A description of the sub-transmission system fed from the bulk electricity 3.4 supply points, including the capacity of zone substations and the voltage(s) of the sub-transmission network(s). The AMP must identify the supply security provided at individual zone substations, by describing the extent to which each has n-x sub-transmission security or by providing alternative security class ratings.

4.2.3 A description of the distribution system, including the extent to which it is 3.1 underground.

4.2.4 A brief description of the network's distribution substation arrangements 3.4

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4.2.5 A description of the low voltage network including the extent to which it is 3.1 underground.

4.2.6 An overview of secondary assets such as protection relays, ripple injection 3.1 systems, SCADA and telecommunications systems.

Sub-Networks

4.3 If sub-networks exist, the network configuration information referred to in N/A clause 4.2 must be disclosed for each sub-network.

Network Asset Information

4.4 The AMP must describe the network assets by providing the following information for each asset category:

4.4.1 Voltage levels. 3

4.4.2 Description and quantity of assets. 3

4.4.3 Age profile. 5

4.4.4 A discussion of the condition of the assets, further broken down into more 5 detailed categories as considered appropriate. Systemic issues leading to the premature replacement of assets or parts of assets should be discussed.

Network Asset Information by Asset Category

4.5 The asset categories discussed in clause 4.4 should include at least the following asset categories:

4.5.1 The categories listed in the Report on Forecast Capital Expenditure in 5 Schedule 11(a).

4.5.2 Assets owned by the EDB but installed at bulk electricity supply points owned 3.3 by others.

4.5.3 EDB owned mobile substations and generators whose function is to increase 3.13 supply reliability or reduce peak demand.

4.5.4 Other generation plant owned by the EDB. 3.3

Service Levels

5 The AMP must clearly identify or define a set of performance indicators for 8 which annual performance targets have been defined. The annual performance targets must be consistent with business strategies and asset

Appendices | 153

management objectives and be provided for each year of the AMP planning period. The targets should reflect what is practically achievable given the current network configuration, condition and planned expenditure levels. The targets should be disclosed for each year of the AMP planning period.

6 The AMP must include performance indicators for which targets have been 8.5 defined in clause 5 must include SAIDI values and SAIFI values for the next five disclosure years.

7 The AMP must include performance indicators for which targets have been defined in clause 5 above should also include:

7.1 Consumer oriented indicators that preferably differentiate between different 8.4, 8.5 consumer types.

7.2 Indicators of asset performance, asset efficiency and effectiveness, and 8.3, 8.5 service efficiency, such as technical and financial performance indicators related to the efficiency of asset utilisation and operation.

8 The AMP must describe the basis on which the target level for each 8.3, 8.5 performance indicator was determined. Justification for target levels of service includes consumer expectations or demands, legislative, regulatory, and other stakeholders' requirements or considerations. The AMP should demonstrate how stakeholder needs were ascertained and translated into service level targets.

9 Targets should be compared to historic values where available to provide 8.2, 8.5 context and scale to the reader.

10 Where forecast expenditure is expected to materially affect performance against a target defined in clause 5, the target should be consistent with the expected change in the level of performance.

Network Development Planning

11 AMPs must provide a detailed description of network development plans, including:

11.1 A description of the planning criteria and assumptions for network 4.6 development.

11.2 Planning criteria for network developments should be described logically and 4.6 succinctly. Where probabilistic or scenario-based planning techniques are used, this should be indicated and the methodology briefly described.

11.3 A description of strategies or processes (if any) used by the EDB that promote 4.61 cost efficiency including through the use of standardised assets and designs.

Appendices | 154

11.4 The use of standardised designs. 4.6.1

Network Efficient Operation

11.5 The AMP must include a description of strategies or processes (if any) used 4.6 by the EDB that promote cost efficiency including through the use of standardised assets and designs.

Equipment Capacity

11.6 The AMP must include description of the criteria used to determine the 5.4.7 capacity of equipment for different types of assets or different parts of the network.

Project Prioritisation

11.7 The AMP must include a description of the process and criteria used to 4.6 prioritise network development projects and how these processes and criteria align with the overall corporate goals and vision

Demand Forecasts

11.8 The AMP must provide details of demand forecasts, the basis on which they 5.4 are derived, and the specific network locations where constraints are expected due to forecast increases in demand.

11.8.1 The AMP must explain the load forecasting methodology and indicate all the 5.4 factors used in preparing the load estimates

11.8.2 The AMP must provide separate forecasts to at least the zone substation 5.4 level covering at least a minimum five year forecast period. Discuss how uncertain but substantial individual projects/developments that affect load are taken into account in the forecasts, making clear the extent to which these uncertain increases in demand are reflected in the forecasts.

11.8.3 The AMP must identify any network or equipment constraints that may arise 5.4 due to the anticipated growth in demand during the AMP planning period.

11.8.4 The AMP must discuss the impact on the load forecasts of any anticipated 5.4.6 levels of distributed generation in a network, and the projected impact of any demand management initiatives.

Network Development Options

11.9 The AMP must provide an analysis of the significant network level 5.1 – 5.4 development options identified and details of the decisions made to satisfy and meet target levels of service, including:

Appendices | 155

11.9.1 The reasons for choosing a selected option for projects where decisions have 5.1 – 5.4 been made.

11.9.2 The alternative options considered for projects that are planned to start in 5.1 – 5.4 the next five years and the potential for non-network solutions described.

11.9.3 The consideration of planned innovations that improve efficiencies within the 5.1 – 5.4 network, such as improved utilisation, extended asset lives, and deferred investment.

Network Development Programme

11.10 The AMP must provide a description and identification of the network 5.1, 5.2, 5.3, development programme including distributed generation and non-network 5.4, 5.5 solutions and actions to be taken, including associated expenditure projections. The network development plan must include:

11.10.1 A detailed description of the material projects and a summary description of 5.1, 5.2, 5.3, the non-material projects currently underway or planned to start within the 5.4, 5.5 next twelve months.

11.10.2 A summary description of the programmes and projects planned for the 5.1, 5.2, 5.3, following four years (where known) 5.4, 5.5

11.10.3 An overview of the material projects being considered for the remainder of 5.1, 5.2, 5.3, the AMP planning period. 5.4, 5.5

Distributed Generation

11.11 The AMP must provide a description of the EDB's policies on distributed 5.8 generation, including the policies for connecting distributed generation. The impact of such generation on network development plans must also be stated.

Non-Network Solutions

11.12 The AMP must provide description of the EDB's policies on non-network solutions, including:

11.12.1 Economically feasible and practical alternatives to conventional network 4.6.1 augmentation. These are typically approaches that would reduce network demand and/or improve asset utilisation.

11.12.2 The potential for non-network solutions to address network problems or 4.6.1 constraints.

Lifecycle Asset Management Planning (Maintenance and Renewals)

Appendices | 156

12 The AMP must provide a detailed description of the lifecycle asset management processes, including:

12.1 The key drivers for maintenance planning and assumptions. 6.1, 6.2, 6.3, 6.4

Maintenance Programme

12.2 The AMP must provide identification of routine and corrective maintenance 6 and inspection policies and programmes and actions to be taken for each asset category, including associated expenditure projections. This must include:

12.2.1 The approach to inspecting and maintaining each category of assets, 6.2 including a description of the types of inspections, tests and condition monitoring carried out and the intervals at which this is done.

12.2.2 Any systemic problems identified with any particular asset types and the 5 proposed actions to address these problems.

12.2.3 Budgets for maintenance activities broken down by asset category for the 6.6 AMP planning period.

Renewal Programme

12.3 The AMP must include identification of asset replacement and renewal 4.6, 5 policies and programmes and actions to be taken for each asset category, including associated expenditure projections. This must include:

12.3.1 The processes used to decide when and whether an asset is replaced or 4.6.4 refurbished, including a description of the factors on which decisions are based, and consideration of future demands on the network and the optimum use of existing network assets.

12.3.2 A description of innovations that have deferred asset replacements. 5.1.4

12.3.3 A description of the projects currently underway or planned for the next 5.2, 5.3, 5.4, 5.5 twelve months.

12.3.4 A summary of the projects planned for the following four years (where 5.2, 5.3, 5.4, 5.5 known).

12.3.5 An overview of other work being considered for the remainder of the AMP 5.2, 5.3, 5.4, 5.5 planning period.

12.4 The asset categories discussed in clauses 12.2 and 12.3 should include at 5.2, 5.3, 5.4, 5.5 least the categories in clause 4.5.

Appendices | 157

Non-Network Development, Maintenance and Renewal

13 The AMP must provide a summary description of material non-network development, maintenance and renewal plans, including:

13.1 A description of non-network assets. 5.6

13.2 Development, maintenance and renewal policies that cover them. 5.6, 6.5

13.3 A description of material capital expenditure projects (where known) 5.6 planned for the next five years.

13.4 A description of material maintenance and renewal projects (where known) 5.6 planned for the next five years.

Risk Management

14 The AMP must provide details of risk policies, assessment, and mitigation, including:

14.1 Methods, details and conclusions of risk analysis 4.5, 5

14.2 Strategies used to identify areas of the network that are vulnerable to high 4.5 impact low probability events and a description of the resilience of the network and asset management systems to such events

14.3 A description of the policies to mitigate or manage the risks of events 4.5 identified in clause 14.2

14.4 Details of emergency response and contingency plans 4.8

Evaluation of Performance

15 The AMP must provide details of performance measurement, evaluation, and improvement, including:

15.1 A review of progress against plan, both physical and financial. 8

15.2 An evaluation and comparison of actual service level performance against 8.5.3 targeted performance.

15.3 An evaluation and comparison of the results of the asset management 9 maturity assessment disclosed in the Report on Asset Management Maturity set out in Schedule 13 against relevant objectives of the EDB's asset management and planning processes.

Appendices | 158

15.4 An analysis of gaps identified in clauses 15.2 and 15.3. Where significant gaps 9.1.3 exist (not caused by one-off factors), the AMP must describe any planned initiatives to address the situation.

Capability to Deliver

16 The AMP must describe the processes used by the EDB to ensure that:

16.1 It is realistic and the objectives set out in the plan can be achieved 5.9

16.2 The organisation structure and the processes for authorisation and business 2.1, 4.1, 4.4, 4.6 capabilities will support the implementation of the AMP plans.

Appendices | 159

12. Appendix C: Information Disclosure Asset Management Plan Schedules

Number Report Name

11a Forecast Capital Expenditure

11b Forecast Operational Expenditure

12a Asset Condition

12b Forecast Capacity

12c Forecast Network Demand

12d Interruptions and Duration

13 Asset Management Maturity

14a Mandatory Explanatory Notes on Forecast Information

Appendices | 160

-

- -

-

13

16

164

123

898

325

196

147

1,021

8,974

2,265

1,179

1,220

1,073

2,707

1,409

13,616

13,452

15,260

16,598

16,272

16,076

10,725

CY+10

CY+10

31 30 Mar

31 30 Mar

-

-

-

-

74

13

87

15

164

651

577

298

192

763

676

8,494

2,212

1,179

9,952

2,592

1,381

12,713

12,549

14,135

15,193

14,895

14,703

CY+9

CY+9

31 29 Mar

31 29 Mar

-

-

-

-

The The Lines Company

13

15

164

762

228

534

274

188

875

262

613

8,023

1,789

1,179

9,216

2,055

1,354

11,930

11,766

13,329

13,978

13,704

13,515

1 April 2020 1 April 31 – 2030 March

CY+8

CY+8

31 28 Mar

31 28 Mar

-

-

-

-

13

15

164

795

261

534

534

220

185

895

294

601

601

9,766

9,602

7,081

1,179

7,974

1,328

11,855

11,218

10,998

10,813

CY+7

CY+7

31 27 Mar

31 27 Mar

Company Name Company

-

-

-

-

13

14

164

403

746

321

181

445

824

AMP Planning Period AMP Planning

2,816

2,413

9,640

1,179

3,109

2,664

1,302

14,558

14,394

17,014

16,395

16,073

15,892

10,643

CY+6

CY+6

31 26 Mar

31 26 Mar

-

-

-

12

13

352

704

179

708

287

381

762

194

2,758

2,053

8,925

1,028

2,984

2,222

9,661

1,113

13,254

12,901

11,665

13,925

14,345

13,964

CY+5

CY+5

31 25 Mar

31 25 Mar

-

-

-

12

13

352

808

694

331

374

857

2,322

1,514

9,965

1,899

1,028

2,464

1,607

2,015

1,091

15,579

15,226

18,410

16,168

16,531

16,158

10,575

CY+4

CY+4

31 24 Mar

31 24 Mar

-

-

-

12

12

352

680

388

366

4,758

2,456

2,302

2,402

1,028

4,950

2,555

2,395

2,499

1,070

18,645

18,293

10,092

16,582

19,105

19,397

19,031

10,500

CY+3

CY+3

31 23 Mar

31 23 Mar

-

-

-

12

12

481

2,408

6,475

4,928

1,547

7,150

2,801

4,744

4,299

2,456

6,605

5,027

1,578

7,293

2,857

4,839

23,590

21,182

22,218

20,244

24,062

21,606

CY+2

CY+2

31 22 Mar

31 22 Mar

-

-

-

12

12

866

521

866

8,319

5,724

2,595

8,276

2,119

6,440

6,065

8,319

5,724

2,595

8,276

2,119

6,440

26,032

25,165

20,154

20,487

26,032

25,166

CY+1

CY+1

31 21 Mar

31 21 Mar

-

-

-

-

50

50

389

371

789

2,025

4,044

1,372

2,672

8,549

2,916

2,203

4,044

1,372

2,672

8,549

2,916

17,974

15,949

16,349

18,922

18,551

16,349

31 20 Mar

31 20 Mar

Current Year CY Year Current

Current Year CY Year Current

$000 constant prices) (in

$000 dollars) nominal (in

for year ended

for year ended

Other reliability, safety and environment

Legislative and regulatory

Quality of supply

Other reliability, safety and environment

Legislative and regulatory

Quality of supply

Research and development

Overhead underground to conversion

Energy efficiencyEnergy and demand side reduction management, losses of energy

Expenditure on non-network assets

Total reliability, safety and environment safety and reliability, Total

Reliability, safety and environment:

Asset relocations

Asset replacement and renewal

System growth System

Consumer connection

Assets commissioned

Value of assetsvested

Value of capital contributions

Cost of financing

Expenditure on non-network assets

Total reliability, safety and environment safety and reliability, Total

Reliability, safety and environment:

Asset relocations

Asset replacement and renewal

System growth System

Consumer connection

Expenditure on assets

Expenditure on network assets

Capital expenditureCapital forecast

Expenditure on assets

Expenditure on network assets

Subcomponents of expenditure on (whereassets known)

less

plus

plus

11a(i):AssetsExpenditure on Forecast

9

8

7

50

49

48

47

46

45

44

43

42

41

40

39

38

37

36

35

34

33

32

31

30

29

28

27

26

25

24

23

22

21

20

19

18

17

16

15

14

13

12

11

10

SCHEDULE 11a:ON CAPITALFORECAST EXPENDITURE SCHEDULE REPORT

This information is partnot of audited disclosure information.

EDBs must provide explanatory constant difference on the between comment price and nominal dollar forecasts of expenditure on assets in Schedule 14a (Mandatory Explanatory Notes).

of commissioned assets value the (i.e., additions) of RAB

This schedule requires a breakdown of forecast expenditure on assets for current the disclosure year and a 10 year planning period. forecasts The should consistent be supportingwith the information forecast set The inout AMP. the is expressed be to in both constant price and nominal dollar Also terms. required is a forecast value of the sch ref sch

Appendices | 161

-

3

32

24

199

175

442

230

2,656

2,624

1,751

CY+10

31 30 Mar

-

2

28

13

99

112

380

202

2,182

2,154

1,458

CY+9

31 29 Mar

-

2

24

34

79

113

266

175

1,774

1,749

1,193

CY+8

31 28 Mar

-

2

21

33

67

67

100

893

149

1,232

1,211

CY+7

31 27 Mar

-

1

17

42

78

293

251

123

1,515

1,498

1,003

CY+6

31 26 Mar

-

-

-

-

-

-

-

1

66

75

29

58

15

84

179

179

112

374

654

654

300

227

169

736

1,028

1,092

1,063

CY+5

CY+5

31 25 Mar

31 25 Mar

-

-

-

-

-

-

1

75

21

49

93

62

120

657

374

654

654

300

953

932

142

610

116

1,899

1,899

1,122

1,028

CY+4

CY+4

31 24 Mar

31 24 Mar

-

-

-

-

-

1

75

14

99

93

97

41

124

615

112

374

654

654

300

752

738

192

407

2,402

2,402

1,551

1,028

CY+3

CY+3

31 23 Mar

31 23 Mar

-

-

-

-

-

0

75

48

99

31

56

95

124

725

749

529

300

472

424

129

143

2,801

2,801

1,203

4,215

4,744

4,369

CY+2

CY+2

31 22 Mar

31 22 Mar

-

-

-

-

-

0

1

0

0

0

0

0

(0)

(0)

(0)

75

203

648

257

374

300

2,119

2,119

1,012

6,065

6,440

6,065

CY+1

CY+1

31 21 Mar

31 21 Mar

-

-

-

-

-

-

-

-

-

-

-

-

27

389

389

253

109

578

178

400

400

2,916

2,916

1,666

1,250

31 20 Mar

31 20 Mar

Current Year CY Year Current

Current Year CY Year Current

$000 constant prices) (in

$000

for year ended

for year ended

Other reliability, safety and environment

Legislative and regulatory

Quality of supply

Capital contributions funding system growth

Other network assetsOther network

Distribution switchgear

Distribution substations and transformers

Distribution and cables LV

Distribution and lines LV

Zone substationsZone

Subtransmission

Capital contributions funding consumer connection

*include additional*include if needed rows

Non StandardNon Connection

Standard Connection Density - Low

Standard Connection - High Density

Consumer defined types by EDB*

Expenditure on non-network assets

Total reliability, safety and environment safety and reliability, Total

Reliability, safety and environment:

Asset relocations

Asset replacement and renewal

System growth System

Consumer connection

System contributions growth capital less

System growth expenditure

Consumer contributions capital less connection

Consumer expenditureconnection

Expenditure on assets

Expenditure on network assets

Difference between nominal and constant price forecasts

less

less

11a(iii):System Growth

11a(ii): Consumer Connection 11a(ii): Consumer

90

89

88

87

86

85

84

83

82

81

80

79

78

77

76

75

74

73

72

71

70

69

68

67

66

65

64

63

62

61

60

59

58

57

56

55

54

53

52 51

Appendices | 162

-

-

-

-

-

-

-

-

-

-

-

-

12

12

12

79

96

707

245

180

2,053

2,053

1,346

8,925

8,925

5,264

1,086

1,974

CY+5

CY+5

CY+5

31 25 Mar

31 25 Mar

31 25 Mar

-

-

-

-

-

-

-

-

-

-

-

12

12

12

79

107

379

200

245

667

1,514

1,514

1,028

9,965

9,965

5,842

1,444

1,487

CY+4

CY+4

CY+4

31 24 Mar

31 24 Mar

31 24 Mar

-

-

-

-

-

-

-

-

-

-

-

12

12

12

79

720

348

251

245

751

2,302

2,302

1,234

5,466

1,190

2,110

10,092

10,092

CY+3

CY+3

CY+3

31 23 Mar

31 23 Mar

31 23 Mar

-

-

-

-

-

-

-

-

-

51

82

87

12

12

12

53

461

866

376

320

245

122

370

1,547

1,547

7,150

7,150

5,664

CY+2

CY+2

CY+2

31 22 Mar

31 22 Mar

31 22 Mar

-

-

-

-

-

-

-

-

-

-

-

12

12

12

587

607

116

224

424

307

2,595

2,595

1,285

8,276

8,276

4,271

1,243

1,807

CY+1

CY+1

CY+1

31 21 Mar

31 21 Mar

31 21 Mar

-

-

50

50

50

209

340

200

461

200

255

2,672

2,672

1,923

8,549

8,549

4,625

1,415

1,593

31 20 Mar

31 20 Mar

31 20 Mar

Current Year CY Year Current

Current Year CY Year Current

Current Year CY Year Current

$000 constant prices) (in

$000 constant prices) (in

$000 constant prices) (in

for year ended

for year ended

for year ended

0

0

0

0

Capital contributions funding quality of supply

All projectsother or programmes - quality of supply

*include additional*include if needed rows

Sub and 33kVDev -Supply Points

Sub and 33kVDev - Substations

Sub and 33kVDev - 33kV Lines

11kV Fdr - Switch Dev Automation and Renewal

11kV Development Fdr - Feeder Dev

Project or programme* or Project

Capital contributions funding asset relocations

All projectother or programmes - asset relocations

*include additional*include if needed rows

Miscellaneous

Project or programme* or Project

Capital contributions funding asset replacement and renewal

Other network assetsOther network

Distribution switchgear

Distribution substations and transformers

Distribution and cables LV

Distribution and lines LV

Zone substationsZone

Subtransmission

Quality of supply less capital contributions capital less supply of Quality

Quality of supply expenditure supply of Quality

Asset relocations less capital contributionsAsset capital less relocations

Asset expenditurerelocations

Asset replacement contributions renewal and capital less

Asset replacement renewal and expenditure

less

less

less

11a(vi): Quality of Supply 11a(vi):of Quality

11a(v): Asset11a(v): Relocations

11a(iv):Asset Renewal Replacement and

99

98

97

96

95

94

93

92

91

134

133

132

131

130

129

128

127

126

125

124

123

122

121

120

119

118

117

116

115

114

113

112

111

110

109

108

107

106

105

104

103

102

101 100

Appendices | 163

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

11

23

80

57

352

352

125

193

704

704

567

CY+5

CY+5

CY+5

31 25 Mar

31 25 Mar

31 25 Mar

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

11

23

57

352

352

125

193

808

808

160

591

CY+4

CY+4

CY+4

31 24 Mar

31 24 Mar

31 24 Mar

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

11

23

352

352

125

193

552

492

2,456

2,456

1,412

CY+3

CY+3

CY+3

31 23 Mar

31 23 Mar

31 23 Mar

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

11

23

352

125

193

291

114

535

2,408

2,056

2,056

4,928

4,928

1,753

2,234

CY+2

CY+2

CY+2

31 22 Mar

31 22 Mar

31 22 Mar

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

11

23

866

514

514

352

125

193

206

5,724

5,724

1,184

1,368

2,966

CY+1

CY+1

CY+1

31 21 Mar

31 21 Mar

31 21 Mar

-

-

-

-

-

-

-

75

40

75

40

410

115

2,025

1,910

1,500

1,372

1,372

1,257

31 20 Mar

31 20 Mar

31 20 Mar

Current Year CY Year Current

Current Year CY Year Current

Current Year CY Year Current

$000 constant prices) (in

$000 constant prices) (in

$000 constant prices) (in

for year ended

for year ended

for year ended

All projectsother or programmes - atypical expenditure

*include additional*include if needed rows

Eng & AssetEng Capital - Building Re-structure

Project or programme* or Project

All projectsother or programmes - routine expenditure

*include additional*include if needed rows

Eng & AssetEng Capital - Vehicles

Eng & AssetEng Capital - Miscellaneous Equipment

Eng & AssetEng Capital - Office Area

Eng & AssetEng Capital - Data Systems - Annual Sys. Req.

Project or programme* or Project

Capital contributions funding reliability,other safety and environment

All projectsother or programmes - reliability,other safety and environment

*include additional*include if needed rows

SCADA, Radio,SCADA, Data Systems, Other

Tx & Service Boxes 2 Pole - GMT, Structures

Sub and 33kVDev -Supply Points

Sub and 33kV - Substations Dev

11kV Fdr - Switchgear, Dev Cables

Project or programme* or Project

Capital contributions funding legislative and regulatory

All projectsother or programmes - legislative and regulatory

*include additional*include if needed rows

Project or programme* or Project

Expenditure on non-network assets

Atypical expenditureAtypical

Routine expenditure

Other environment safety and reliability, contributions capital less

Other environment safety and reliability, expenditure

Legislative and regulatory less capital contributionsLegislative regulatory and capital less

Legislative regulatory and expenditure

Atypical expenditureAtypical

Routine expenditure

less

less

11a(ix):Non-Network Assets

11a(viii):Other Reliability, Environment Safetyand

11a(vii):Legislative Regulatory and

188

187

186

185

184

183

182

181

180

179

178

177

176

175

174

173

172

171

170

169

168

167

166

165

164

163

162

161

160

159

158

157

156

155

154

153

152

151

150

149

148

147

146

145

144

143

142

141

140

139

138

137

136 135

Appendices | 164

-

-

38

419

752

244

239

231

336

193

231

2,739

1,986

1,567

2,069

2,150

8,031

3,857

1,251

1,227

1,186

2,569

9,598

4,610

1,495

1,466

1,417

14,038

10,181

16,776

12,167

CY+10

CY+10

CY+10

31 30 Mar

31 30 Mar

31 30 Mar

-

-

33

367

662

214

210

204

336

193

227

2,404

1,743

1,376

2,063

2,136

8,016

3,855

1,249

1,226

1,186

2,503

9,392

4,516

1,464

1,436

1,390

14,007

10,152

16,411

11,895

CY+9

CY+9

CY+9

31 29 Mar

31 29 Mar

31 29 Mar

-

-

The The Lines Company

29

316

573

186

182

176

336

193

222

2,078

1,505

1,190

2,058

2,123

8,001

3,852

1,248

1,225

1,186

2,439

9,190

4,425

1,433

1,407

1,362

13,976

10,124

16,054

11,629

1 April 2020 1 April 31 – 2030 March

CY+8

CY+8

CY+8

31 28 Mar

31 28 Mar

31 28 Mar

-

-

24

266

486

157

154

150

336

193

218

1,759

1,274

1,008

2,052

2,110

7,986

3,849

1,246

1,224

1,186

2,376

8,994

4,335

1,403

1,378

1,336

13,945

10,096

15,705

11,369

CY+7

CY+7

CY+7

31 27 Mar

31 27 Mar

31 27 Mar

Company Name Company

-

-

20

218

830

400

130

127

123

336

193

214

AMP Planning Period AMP Planning

1,448

1,048

2,047

2,097

7,971

3,847

1,244

1,223

1,186

2,315

8,801

4,247

1,374

1,350

1,309

13,915

10,068

15,363

11,116

CY+6

CY+6

CY+6

31 26 Mar

31 26 Mar

31 26 Mar

-

-

16

98

828

172

656

317

102

101

336

193

209

1,145

2,041

2,083

7,956

3,844

1,243

1,222

1,186

2,255

8,612

4,161

1,345

1,323

1,284

13,884

10,040

15,029

10,868

CY+5

CY+5

CY+5

31 25 Mar

31 25 Mar

31 25 Mar

-

-

12

76

75

73

848

613

127

486

235

336

193

205

2,036

2,070

7,942

3,842

1,241

1,221

1,186

2,197

8,428

4,077

1,317

1,296

1,259

13,854

10,012

14,702

10,625

CY+4

CY+4

CY+4

31 24 Mar

31 24 Mar

31 24 Mar

-

-

8

83

50

49

48

558

403

320

155

336

193

201

2,030

9,985

2,057

7,927

3,840

1,240

1,221

1,186

2,141

8,247

3,995

1,290

1,270

1,234

13,824

14,383

10,388

CY+3

CY+3

CY+3

31 23 Mar

31 23 Mar

31 23 Mar

-

-

4

41

77

25

24

24

276

199

158

336

193

197

2,025

9,962

2,044

7,918

3,837

1,238

1,220

1,186

2,085

8,076

3,914

1,263

1,244

1,210

13,799

14,075

10,161

CY+2

CY+2

CY+2

31 22 Mar

31 22 Mar

31 22 Mar

-

-

-

-

-

-

-

-

-

-

-

336

193

193

2,020

9,903

2,032

7,871

4,035

1,236

1,419

1,186

9,903

2,032

7,871

4,035

1,236

1,419

1,186

13,938

13,938

CY+1

CY+1

CY+1

31 21 Mar

31 21 Mar

31 21 Mar

-

-

-

-

-

-

-

-

-

-

-

290

190

190

1,844

8,606

6,359

2,247

3,794

1,219

1,220

1,165

8,606

6,359

2,247

3,794

1,219

1,220

1,165

12,400

12,400

31 20 Mar

31 20 Mar

31 20 Mar

Current Year CY Year Current

Current Year CY Year Current

Current Year CY Year Current

$000

$000 constant prices) (in

$000 dollars) nominal (in

for year ended

for year ended

for year ended

Business support

System operationsSystem and support network

Asset replacement and renewal

Routine and corrective maintenance and inspection

Vegetation management Vegetation

Service interruptions and emergencies

Insurance

Research and Development

Direct billing*

energy lossesenergy

Energy efficiencyEnergy and demand side reduction management, of

Business support

System operationsSystem and support network

Asset replacement and renewal

Routine and corrective maintenance and inspection

Vegetation management Vegetation

Service interruptions and emergencies

Business support

System operationsSystem and support network

Asset replacement and renewal

Routine and corrective maintenance and inspection

Vegetation management Vegetation

Service interruptions and emergencies

Operational expenditure

Non-network opex

Network Opex

Operational expenditure

Non-network opex

Network Opex

Operational expenditure

Non-network opex

Network Opex

Operational Expenditure Forecast

Difference between nominal and real forecasts

Subcomponents of operational expenditure (where known)

* Direct billing consumers of bill majority expendituretheir the by Direct suppliers* direct that

9

8

7

SCHEDULE 11b: ON OPERATIONAL FORECAST EXPENDITURE SCHEDULE REPORT

This information is partnot of audited disclosure information.

EDBs must provide explanatory constant difference on the between comment price and nominal dollar operational expenditure forecasts in Schedule 14a (Mandatory Explanatory Notes).

This schedule requires a breakdown of forecast operational expenditure for disclosure the year and a 10 year planning period. forecasts The should consistent be supportingwith the information forecast set The inout AMP. the is expressed be to in both constant price and nominal dollar terms.

50

49

48

47

46

45

44

43

42

41

40

39

38

37

36

35

34

33

32

31

30

29

28

27

26

25

24

23

22

21

20

19

18

17

16

15

14

13

12

11

10 sch ref sch

Appendices | 165

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

4.50%

1.59%

9.64%

2.17%

0.66%

11.43%

% of assetof %

replaced in

next 5 years

forecast to be

3

3

3

3

4

3

2

2

3

(1–4)

Data accuracy accuracy Data

N/A

N/A

N/A

N/A

N/A

N/A

N/A

N/A

N/A

N/A

N/A

N/A

N/A

N/A

N/A

N/A

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

1.43%

0.46%

1.59%

0.31%

12.50%

35.97%

10.06%

The LinesThe Company

Grade unknown

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

1 April 2020 1 April 31 2030– March

7.46%

4.29%

0.68%

6.94%

23.04%

34.92%

38.89%

68.75%

12.01%

H5

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

92.54%

82.86%

69.12%

61.90%

61.11%

18.75%

82.23%

54.04%

76.70%

H4

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

Company Name Company

0.88%

0.57%

AMP Planning Period AMP Planning

H3

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

Asset atperiod start condition (percentage planning of unitsof grade) by

6.91%

0.77%

0.22%

16.78%

H2

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

0.46%

1.59%

1.40%

0.44%

11.43%

H1

km

km

km

km

km

km

km

km

km

km

km

No.

No.

No.

No.

No.

No.

No.

No.

No.

No.

No.

No.

No.

No.

Units

3.3/6.6/11/22kV CB (pole mounted)

3.3/6.6/11/22kV CB (ground mounted)

50/66/110kV CB (Outdoor)

50/66/110kV CB (Indoor)

33kV RMU

33kV Switch (Pole Mounted)

33kV Switch (Ground Mounted)

22/33kV CB (Outdoor)

22/33kV CB (Indoor)

Zone substationsZone 110kV+

Zone substationsZone up 66kV to

Subtransmission submarine cable

Subtransmission 110kV+ (PILC)UG

Subtransmission 110kV+ (GasUG Pressurised)

Subtransmission 110kV+ (OilUG pressurised)

Subtransmission 110kV+ (XLPE) UG

Subtransmission up 66kV to UG (PILC)

Subtransmission up 66kV to UG (Gas pressurised)

Subtransmission up 66kV to UG (Oil pressurised)

Subtransmission up 66kV to UG (XLPE)

Subtransmission OH 110kV+ conductor

Subtransmission OH up 66kV to conductor

Other pole types

Wood poles

Concrete poles / steel structure

Asset class

Zone substationZone switchgear

Zone substationZone switchgear

Zone substationZone switchgear

Zone substationZone switchgear

Zone substationZone switchgear

Zone substationZone switchgear

Zone substationZone switchgear

Zone substationZone switchgear

Zone substationZone switchgear

Zone substationZone Buildings

Zone substationZone Buildings

Subtransmission Cable

Subtransmission Cable

Subtransmission Cable

Subtransmission Cable

Subtransmission Cable

Subtransmission Cable

Subtransmission Cable

Subtransmission Cable

Subtransmission Cable

Subtransmission Line

Subtransmission Line

Overhead Line

Overhead Line

Overhead Line

Asset category

HV

HV

HV

HV

HV

HV

HV

HV

HV

HV

HV

HV

HV

HV

HV

HV

HV

HV

HV

HV

HV

HV

All

All

All

Voltage

9

8

7

35

34

33

32

31

30

29

28

27

26

25

24

23

22

21

20

19

18

17

16

15

14

13

12

11

10

SCHEDULE 12a:ON CONDITION ASSET SCHEDULE REPORT

replaced in 5 next years. the All information should consistent be informationwith the provided in and AMP expenditure the the on assets forecast in Schedule 11a. All units relating cable to and line assets, that are expressed in circuit refer to km, lengths.

This schedule requires a breakdown of asset condition by asset class as start at the forecast of the year.data The accuracy assessment relates percentage values the to disclosed in asset the condition columns. Also required is a forecast percentage of ofunits the be to sch ref sch

Appendices | 166

-

-

-

-

-

-

-

-

-

-

-

-

6.45%

0.10%

4.77%

5.76%

3.77%

1.85%

0.31%

0.56%

4.05%

0.81%

0.10%

1.59%

2.56%

10.15%

% of asset of %

replaced in replaced in

next 5 years

forecast to be

3

3

4

3

3

2

2

2

2

3

3

3

2

3

3

2

3

3

2

2

2

4

(1–4)

Data accuracy accuracy Data

N/A

N/A

N/A

N/A

-

-

-

-

-

-

-

-

-

-

-

-

8.33%

7.53%

3.94%

7.72%

0.61%

0.08%

1.35%

0.51%

0.59%

95.92%

89.92%

51.21%

93.77%

81.68%

Grade unknown

-

-

-

-

-

-

0.63%

4.66%

4.46%

2.39%

1.26%

9.23%

0.35%

1.85%

15.38%

50.00%

18.56%

17.65%

14.37%

13.11%

35.47%

10.81%

18.21%

33.33%

35.59%

15.38%

H5

-

-

-

-

-

3.45%

5.50%

3.84%

8.28%

53.85%

41.67%

54.15%

71.68%

24.92%

61.85%

79.41%

85.26%

85.04%

63.61%

89.19%

81.13%

66.67%

59.01%

64.39%

75.52%

82.05%

H4

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

0.02%

0.36%

0.01%

0.05%

0.19%

H3

-

-

-

-

-

-

-

-

-

-

-

Asset condition at start of planning periodAsset at start (percentage condition planning of grade)units of by

9.61%

2.94%

0.37%

1.85%

0.31%

0.56%

4.05%

0.68%

2.56%

30.77%

13.26%

23.86%

28.52%

34.59%

21.84%

H2

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

6.45%

0.10%

0.29%

0.14%

0.11%

0.02%

10.15%

H1

km

Lot

Lot

km

km

km

km

km

km

km

km

km

No.

No.

No.

No.

No.

No.

No.

No.

No.

No.

No.

No.

No.

No.

Units

Cable Tunnels

Relays

Centralised plant

Capacitors including controls

SCADA andSCADA communications operating equipment as a single system

Protection relays (electromechanical, solid state and numeric)

OH/UG consumerOH/UG service connections

LV OH/UG Streetlight OH/UG circuitLV

LV UG Cable UG LV

LV OH ConductorLV

Ground Substation Mounted Housing

Voltage regulators

Ground Transformer Mounted

Pole Transformer Mounted

3.3/6.6/11/22kV RMU

3.3/6.6/11/22kV Switch RMU (ground - except mounted)

3.3/6.6/11/22kV Switches and fuses (pole mounted)

3.3/6.6/11/22kV (Indoor)CB

3.3/6.6/11/22kV (poleCB - reclosers mounted) and sectionalisers

Distribution Submarine Cable

Distribution PILC UG

Distribution or XLPE PVC UG

SWER SWER conductor

Distribution OH Aerial Cable Conductor

Distribution OH Open Wire Conductor

Zone SubstationZone Transformers

Asset class

Civils

Load Control

Load Control

Capacitor Banks

SCADA andSCADA communications

Protection

Connections

LV StreetlightingLV

LV CableLV

LV Line LV

Distribution Substations

Distribution Transformer

Distribution Transformer

Distribution Transformer

Distribution switchgear

Distribution switchgear

Distribution switchgear

Distribution switchgear

Distribution switchgear

Distribution Cable

Distribution Cable

Distribution Cable

Distribution Line

Distribution Line

Distribution Line

Zone SubstationZone Transformer

Asset category

All

All

All

All

All

All

LV

LV

LV

LV

HV

HV

HV

HV

HV

HV

HV

HV

HV

HV

HV

HV

HV

HV

HV

HV

Voltage

64

63

62

61

60

59

58

57

56

55

54

53

52

51

50

49

48

47

46

45

44

43

42

41

40

39

38

37 36

Appendices | 167

-

Explanation

The LinesThe Company

1 April 2020 1 April 31 2030– March

Constraint managed with through major agreement customer

Transformer ofout service. Site currently operating as a switching station.

Scheduled upgrade 20/25MVA to in 2020 / 2021

Company Name Company

(cause)

AMP Planning Period AMP Planning

Constraint years+5

Installed Firm Capacity FirmInstalled Capacity

No constraintNo within years+5

No constraintNo within years+5

No constraintNo within years+5

No constraintNo within years+5

No constraintNo within years+5

No constraintNo within years+5

No constraintNo within years+5

No constraintNo within years+5

No constraintNo within years+5

No constraintNo within years+5

Transformer

No constraintNo within years+5

No constraintNo within years+5

No constraintNo within years+5

No constraintNo within years+5

No constraintNo within years+5

No constraintNo within years+5

No constraintNo within years+5

No constraintNo within years+5

No constraintNo within years+5

No constraintNo within years+5

No constraintNo within years+5

No constraintNo within years+5

No constraintNo within years+5

No constraintNo within years+5

Transformer

No constraintNo within years+5

No constraintNo within years+5

Transformer

No constraintNo within years+5

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

0.9

1.2

1.0

0.9

1.5

0.8

0.8

%

Utilisation of of Utilisation

Installed FirmInstalled

Capacity + 5yrs + Capacity

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

2.5

5.0

3.0

10.0

15.0

10.0

10.0

(MVA)

Installed FirmInstalled

Capacity +5 years+5 Capacity

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

94%

98%

74%

91%

85%

158%

%

Capacity

Utilisation of of Utilisation

Installed FirmInstalled

-

-

-

-

-

3.8

1.1

0.5

1.9

0.7

2.7

2.4

0.7

2.4

1.1

0.7

1.2

1.0

1.3

0.5

1.2

0.5

0.1

1.0

1.3

5.7

2.5

1.3

0.8

10.0

(MVA)

Transfer Capacity

(type)

Classification

Security of Supply Security Supply of

N - 1 N

N - 1 N

N

N - 1 N

N N

N

N - 1 N

N-1

N

N

N - 1 N

N-1

N

N

N

N

N

N

N

N

N

N

N

N

N

N

N - 1 N

N

N

N

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

2.5

5.0

2.4

2.4

10.0

15.0

10.0

10.0

(MVA)

Capacity

Installed FirmInstalled

-

-

9.4

2.9

2.3

4.9

1.4

0.2

2.2

4.5

0.3

0.3

1.7

0.5

1.9

4.3

2.9

5.8

3.0

0.9

2.5

1.6

3.2

5.6

8.5

1.4

2.4

11.1

15.8

11.6

(MVA)

Current Load Peak

¹ Extend forecast capacity table as necessary to disclose allto disclose tablecapacity as bycapacity necessary Extendeach zone ¹ forecast substation

Waitete

Wairere

Waiotaka

Turangi

Tuhua

Tokaanu

Te WairekaTe

Te Anga Te

Tawhai

Taharoa Village

Taharoa

Piripiri

Otukou

Oparure

Nihoniho

National Park

Mokai

Marotiri

Maraetai

Manunui

Mahoenui

Kuratau

Kiko Road

Kaahu Tee

Hangatiki

Gadsby Road

Borough

Awamate

Atiamuri

Arohena

Existing Zone Substations

12b(i): System Growth - Zone Substations Zone 12b(i):-System Growth

9

8

7

39

38

37

36

35

34

33

32

31

30

29

28

27

26

25

24

23

22

21

20

19

18

17

16

15

14

13

12

11

10

SCHEDULE 12b: ON CAPACITY FORECAST SCHEDULE REPORT

table should relate operation the to in network of the its normal steady state configuration.

This schedule requires a breakdown of current and forecast capacity and utilisation for each substation zone and current distribution transformer capacity. data The provided should consistent be information with the provided Informationin AMP. the provided in this sch ref sch

Appendices | 168

-

-

6

9

29

91

89

89

12

76

10

92

44

(13)

426

455

357

145

59%

6.5%

0.043

CY+5

CY+5

31 25 Mar

31 25 Mar

-

-

6

9

29

90

88

88

12

75

10

92

44

(13)

422

452

355

145

59%

6.5%

0.043

CY+4

CY+4

31 24 Mar

31 24 Mar

-

-

The LinesThe Company

5

9

29

88

87

87

12

74

10

92

44

(13)

419

448

352

145

59%

6.5%

0.043

1 April 2020 1 April 31 2030– March

CY+3

CY+3

31 23 Mar

31 23 Mar

-

5

1

9

29

87

86

86

12

74

10

92

44

(12)

416

444

350

146

59%

6.5%

0.043

Number connections of

CY+2

CY+2

31 22 Mar

31 22 Mar

Company Name Company

-

-

5

9

27

86

78

78

12

66

10

92

44

(12)

394

421

328

145

61%

AMP Planning Period AMP Planning

6.5%

0.043

CY+1

CY+1

31 21 Mar

31 21 Mar

-

-

5

8

9

11

84

81

81

17

64

82

39

(12)

403

415

323

130

58%

2.7%

0.034

31 20 Mar

31 20 Mar

Current Year CY Year Current

Current Year CY Year Current

for year ended

for year ended

Total delivered energy ICPs to

Net electricityNet supplied (from) to EDBs other

Electricity supplied from distributed generation

Electricity exports GXPs to

Electricity supplied from GXPs

Net transfersNet (from) to EDBsother atand HV above

Distributed generation atandoutput HV above

GXP demand

Capacity of distributed generation installed in year (MVA)

Number of connectionsNumber

*include additional*include if needed rows

Non-Standard Customer Connection

Standard Rural Connection: Remote

Standard Connection: Rural

Standard Connection: Urban

Consumer defined types by EDB*

Loss ratio

Load factor

Losses

Electricity enteringElectricity system to for supply ICPs

Demand on system to for supply consumers' connection points

Maximum coincident system coincident Maximum demand

Connections total

Number of in ICPs by connected typeyear Number consumer

Electricity volumes carried (GWh)

Maximum coincident system demand (MW)

Distributed generation

less

less

less

less

plus

plus

12c(ii)System Demand

12c(i): Consumer Connections 12c(i): Consumer

9

8

7

40

39

38

37

36

35

34

33

32

31

30

29

28

27

26

25

24

23

22

21

20

19

18

17

16

15

14

13

12

11

10

SCHEDULE 12C: REPORT ON FORECAST NETWORK DEMAND 12C: ON NETWORK FORECAST SCHEDULE REPORT

assumptions used in developing expenditure the forecasts in Schedule 11a and Schedule 11b and capacity the and utilisation forecasts in Schedule 12b.

This schedule requires a forecast connections of new (by consumer peak demand type), and volumes energy for disclosure the year and a 5 year planning period. forecasts The should consistent be supportingwith the information set inout as AMP the well as the sch ref sch

Appendices | 169

User Guidance User

AMP 2018 AMP

AMP 2018 AMP

AMP 2018 AMP

Asset Management AssetPolicy Management

The LinesThe Company

1 April 2020 1 April 31 2030– March

Evidence—Summary

the TLC the AMP. 2018

maintenance schedule is maintenance asset key the detailed for classes of 6.2.1 in Section

project manager and project engineer to each confirmed project. Preventive Preventive project. each to confirmed engineer project and manager project

and project/programme work package. Plan hasCapexwork Work assigned project/programme and

management system. Capex Work Programme is define annual used work to system. Programme Capexmanagement Work

available to stakeholders as appropriate to their role within the assetthe within role available their to stakeholders as to appropriate

The AMP reviewed and updated annually is the key document which iswhich made annually is document key updated and the reviewed The AMP

phases is not produced yet. yet. phases is produced not

with detailed description of strategies detailed description with assetat the class levelall for lifecycle

through Sections 6.1 - 6.3 of the TLC 2018 AMP. However a separate SAMP aSections 6.1 - TLCseparate 6.3 of the SAMP However AMP. 2018 through

regarding strategies for operations and maintenance planning is provided planning is strategiesregarding maintenance and provided operations for

and contract, operate and maintain, and dispose. Further information information dispose. and maintain, and Further operate contract, and

approaches for managing assetsfor the approaches life in their cycle including plan, design

"Life Cycle Management" in Section 4.6 "Lifeof TLC in definesSection Cycle overall AMP 2018 Management"

asset plans. management

and methodologies used by TLC to convert asset used TLCobjectives by to convert methodologies and management to

TLC 2018 AMP "Approach to Asset Management" sets Asset overall strategiesto out Management" TLC "Approach AMP 2018

TLC's business objectives assetand objectives. 4 of the Section management

documented in Section 1.4.2 of 1.4.2 TLC in indicatesSection linkageAMP 2018 the between documented

Strategy. "Integration of AMP Objectives TLCof AMP with Business"Integration Strategy. Strategy"

its AssetPolicy, Business Management Riskand Strategy Management

TLC's Asset Management Objectives approved by the board TLC's are aligned with board the by AssetObjectives Management approved

requirements for the communication were documented. documented. were communication the for requirements

the asset management policy had been effectively communicated and the the and asseteffectively the been policy had communicated management

within the business. the within that wasevidence No availabledemonstrating however

asset policy has same the management status as Risk Policy Management

included in Section 4.2 of TLC 2018 AMP for all 4.2 of TLC in for Section included access. stakeholders to AMP 2018 The

by the board and is stored in Toolbox for all isand for in staffToolbox board stored the access. by to The policy is also

An asset management policy document has established been asset approved An and policy document management

3

2.9

2.8

Score

2.75

Company Name Company

AMP Planning Period AMP Planning

Question

Asset Management Standard Applied Management Standard Asset

and assetand systems?

life cycle activities of its assets

management plan(s) acrossmanagement the

establish and document its establishasset document and

How does the organisation does the How

organisation organisation has stewardship?

systems over which the the systemswhich over

assets, asset types assetand

account of the lifecycleof the account of the

management strategy take management

organisation's asset

In what way does the way does the what In

stakeholders?

strategies, needs of the and

organisational policies and

consistent with other appropriate appropriate other consistent with

management strategy ismanagement

to ensure that its that ensure assetto

What has the organisation done has What organisation done the

communicated?

documented, authorised and and authorised documented,

management policy been policy been management

To what extent has extent an To what asset

Function

plan(s)

Asset management Asset management

strategy

Asset management Asset management

strategy

Asset management Asset management

policy

Asset management Asset management

3

26

11

10

Question No. Question

SCHEDULE 13: REPORT ON ASSET MANAGEMENT MATURITY 13: ON MANAGEMENT SCHEDULE ASSET REPORT This schedule requires information self-assessment EDB’S on the maturity of the of its asset practices management .

Appendices | 170

User Guidance User

website

AMP isAMP accessible TLC's from

The LinesThe Company

1 April 2020 1 April 31 2030– March

Evidence—Summary

network scenarios. network

contingency plans activities contingency are in maintenance place key major and for

decisions for mitigating the risk. There is no evidence however that that decisions mitigatingrisk. isthe for There however evidence no

/ Observed Hazard Report process is Report Hazard / assessObserved in placenotify, to make and

mainly on Response phase of incident management. Emergency Work Sheet Sheet Work Emergency Response on mainly phasemanagement. of incident

Incident Management System (CIMS). The draft IMP document focuses document IMP (CIMS). The draft System Management Incident

Continuity framework developed basedCivil on developed Defence Co-ordinated framework Continuity

Management Plan (IMP) which is organisation's which Plan of the (IMP) part BusinessManagement

of the TLC of the TLC AMP. 2018 is processof Incident in the of developing

The The process of TLC 4.8 in Section Business Planning is Continuity documented

instruction. Planned works have been delivered since delivered have been 2018. works Planned instruction.

with defined project notes, priority level, work type, task type, details level, work and work priority notes, project defined with

with external contractors. Work Pack is delivery Work in place manage work contractors. to external with

delivery of the planned projects is achieved through outsourcing arrangement arrangement outsourcing is projects planned achieved through of the delivery

delivery of the planned work. To ensure work continuity and efficiency,and continuity work To ensure work. planned of the delivery

analyse required resources and support resource and outage planning for planning for outage and resource support and resources analyse required

an efficient and cost-effective manner. Capex Work Programme is used to Programme an Capexefficient cost-effectiveWork and manner.

existing resources and hired more new staff to support delivery of itsin delivery AMP staff new support to existing more hired and resources

TLC has been through a restructuring processhas which re-allocated athe TLC restructuring has through been

stakeholders. stakeholders.

accountabilities and key relationships between internal and external external and internal accountabilities relationships key between and

confirmed project in Capex Work Plan. in CapexTLC definesWork project Description Position key confirmed

Accountabilities. Project manager and project engineer are assignedengineer project and each manager to Accountabilities. Project

system. Section 4.4 system. of TLCdefines Section Asset AMP 2018 Management

Organisation Chart to Organisationdesigned to responsibilitiesChart its for asset management

TLC has established an Asset Management Committee and developed TLC an has developed and established an Committee Asset Management

projects, Projects and Maintenance, Generation, Financial and AMP progress. Financial AMP and Generation, Maintenance, and Projects projects,

Customer services, People, Network Operation and Performance, Top Top Performance, and Operation services, Network Customer People,

Report meetings. The monthly report covers Health and Safety, Public Safety, Public Safety, covers Health Safety, and report meetings. The monthly Report

consistently communicated with all relevant parties through Network Monthly Monthly Network all parties with through relevant consistently communicated

web site. progress have been web plansAsset work and management

The Asset Management Plan is published annually and made public on TLC's Plan The Assetison public made annually and Management published

3

3

3

Score

2.25

Company Name Company

AMP Planning Period AMP Planning

Question

Asset Management Standard Applied Management Standard Asset

management activities? management

continuity of critical assetcontinuity

situations ensuring and

incidents and emergency incidents emergency and

identifying and responding to to responding and identifying

does the organisation have for organisation have for does the

What plan(s) and procedure(s) plan(s)What procedure(s) and

enabling support)

(Note this is (Note and resources about

the plan(s)?the

cost effective implementation of cost effective implementation

available efficient the and for

arrangements are made are made arrangements

to ensure that appropriate appropriate that ensure to

What has the organisation done has What organisation done the

asset plan actions documented?

responsibilities for delivery responsibilitiesof delivery for

How are designated How

receiver's role in their delivery? receiver's in their role

detail appropriate to the the to detail appropriate

relevant parties to a parties to levelrelevant of

communicated its plan(s) all to communicated

How has How organisation the

Function

planning

Contingency Contingency

plan(s)

Asset management Asset management

plan(s)

Asset management Asset management

plan(s)

Asset management Asset management

33

31

29

27

Question No. Question SCHEDULE 13: REPORT ON ASSET MANAGEMENT MATURITY (cont) 13: ON MANAGEMENT SCHEDULE ASSET REPORT

Appendices | 171

User Guidance User

Master Service Agreement Service Master

Network Monthly Report Monthly Network

TLC Organisation Chart

The The Lines Company

1 April 2020 1 April 31 – 2030 March

Evidence—Summary

training and switching competence assessment. switchingand training competence

instruction. TLC sets out the requirements for the contractor on induction induction on contractor the for TLCinstruction. sets requirements the out

prepared to specify deliverables,to taskscope of work, detailsprepared work and

managed through the internal project managers. Work Pack for each work is each Pack work for managers. Work project internal the through managed

management activities from design to construction. All outsourced works are works All activities designoutsourced construction. management to from

contractor management to ensure quality delivery of outsourced asset of outsourced delivery quality ensure to management contractor

TLC has developed Master Service Agreement which focuses which external TLCon Agreement Service Master has developed

indicates the communication channels. indicates communication the

team. Furthermore, "Key Relationships" "Key in TLCdefined Description Position Furthermore, team.

communication culture and the top management is very reachable for the is the reachable for management very top the and culture communication

Being a relatively small organisation, TLC has a flexible open and

meetings are held for the assetthe meetings are for held managerscatch up. to engineers project and

project progress and budget. Within the asset management group weekly weekly asset the group Within progress budget. and management project

customer services, resources, maintenance and operation, top projects, projects, top services, operation, and customer resources, maintenance

meetings cover all meetings cover aspects of asset including safety,and health management

from the company's Finance and People sections. The month network report report network sections. People Finance and company's the The month from

attended by all asset management groups under Network section and people section people and allNetwork by assetattended under groups management

meeting asset management requirements. Network monthly report meetings report monthly Network asset meeting requirements. management

TLC of has used aimportance the range of strategies communicate to

delivery. delivery.

requirement and recruitment of resources to support asset support management of resources to recruitment and requirement

participants TLC's Network Monthly Report meeting to communicate communicate to meeting Report participants TLC's Monthly Network

management team with defined position and responsibility. and position HRdefined advisor with team management

management is determined and more new resources are added to the assetthe to resources are added new more and is management determined

As a part of restructuring process, the required resource for asset for resource process, required the As aof restructuring part

objectives and objectives plans.and

to ensure that the assets deliver the requirements of the asset of the assetsthe that ensure management to requirements the deliver

result area and the required competencies for the position. position. Thisisthe for approach competencies result required area the and

Description comprehensively defines accountabilities key the in comprehensively Description each key

Management Accountabilities" in Section 4.4 of TLC Accountabilities" in Section TLC AMP. Management 2018 Position

Chart and for the positions accountabilitiesthe the for and are specifiedChart in "Asset

network assets.network TLC's assetis team in itsdefined management Organisation

Executive to facilitate Executive to effective the oversee of itsand stewardship electricity

TLC has Chief the establishedin by 2019 an AssetCommittee Management

3

3

Score

2.75

2.75

Company Name Company

AMP Planning Period AMP Planning

Question

Asset Management Standard Applied Management Standard Asset

and strategy? and

and itsand asset policy management

organisational strategic plan,

the compliant delivery of its delivery compliant the

controls are in place controls ensure to

it ensured that appropriate appropriate that it ensured

management activities, hasmanagement how

outsourced some of itssome assetoutsourced

Where the organisation hasthe Where

requirements?

meeting itsmeeting asset management

communicate the importance of importance the communicate

organisation's top management organisation's management top

To what degree does the does degree the To what

for assetfor management?

sufficient resources are available

provide to demonstrate that that demonstrate to provide

organisation's top management organisation's management top

What evidence canevidence What the

and plan(s)?and

management strategy, objectives management

requirements of the assetof the requirements

organisation's assets the deliver

responsible for ensuring that the the ensuring that responsible for

management team to be be to team management

to appoint member(s) of its member(s) appoint to

What has the organisation done has What organisation done the

Function

activities

asset management

Outsourcing of Outsourcing

responsibilities

and and

Structure, authority authority Structure,

responsibilities

and and

Structure, authority authority Structure,

responsibilities

and and

Structure, authority authority Structure,

45

42

40

37

Question No. Question SCHEDULE 13: REPORT ON ASSET MANAGEMENT MATURITY (cont) 13: ON MANAGEMENT SCHEDULE ASSET REPORT

Appendices | 172

User Guidance User

The LinesThe Company

1 April 2020 1 April 31 2030– March

Evidence—Summary

Switching compenetndd Switching

required competence to identify the required training has been undertaked. hastraining undertaked. been required the identify to competence required

There is however no evidence that regular assessmentregular that evidence no isagainstof persons There however the

Descriptions.

Asset management skills and competencies are documented in Position in Position skillsAsset management are documented competencies and

management related competencies is not currently in place. is currently competencies related not management

A structured means for planning and recording training for all for training asset core recording planning and means for A structured

requirements in Position Descriptions.in Position requirements

TLC design job in the identifies process competencies includesand core the

competence. competence.

managers to discuss appropriate training opportunities to improvement their their improvement to discussopportunities managers training to appropriate

arrange on jog training for the personnel or from the personnel who reach the the reach who personnel the from or personnel the jog for training on arrange

communication approach which can be either from the managers who managers who the from can either which be approach communication

requirements are identified/discussed through an interpersonal an interpersonal are identified/discussed through requirements

Key competencies are documented in Position Descriptions.in Position Training are documented competencies Key

2.5

2.5

2.5

Score

Company Name Company

AMP Planning Period AMP Planning

Question

Asset Management Standard Applied Management Standard Asset

experience?

education, training or or training education,

competence in terms of in terms competence

have an appropriate level of have an appropriate

management related activities related management

direct control undertaking asset undertaking control direct

ensure that persons under its under persons that ensure

How does the organization organization does the How

competencies?

necessary achieve to the

provide and record the training training the record and provide

requirements and then plan, then and requirements

identify competency competency identify

How does the organisation does the How

and plan(s)?and

strategy, strategy, process(es), objectives

delivery of assetdelivery management

including the development and and development including the

asset management assetactivities management -

resources required to undertake undertake to required resources

develop plan(s) for the human plan(s)human the develop for

How does the organisation does the How

Function

competence

awareness and

Training,

competence

awareness and

Training,

competence

awareness and

Training,

50

49

48

Question No. Question SCHEDULE 13: REPORT ON ASSET MANAGEMENT MATURITY (cont) 13: ON MANAGEMENT SCHEDULE ASSET REPORT

Appendices | 173

User Guidance User

2018 AMP 2018

Statement Of Corporate Intent Intent Of Corporate Statement

The LinesThe Company

1 April 2020 1 April 31 2030– March

Evidence—Summary

asset accuracy. and data quality

use. This approach enables a structured and consistent improvement of of use. consistent and improvement enablesThis aapproach structured

reliable visualised and managers engineers and the to for asset information

stored in BASIX systems by developing Dashboard to turn the asset the data turn into to systems in Dashboard BASIX developing stored by

TLC has processes validateexisting and started the review to asset data

are documented . are documented

planning. There is no evidence however the asset information requirements requirements asset the is planning. information There however evidence no

management system used to support TLC asset system processessupport used to management and management

platforms for key information exchanging. is BASIX asset core the information key for platforms

Information Technology platforms used and the linkages used the these and platforms between Technology Information

Section 4.7 of TLC 2018 AMP describes its information systems4.7 TLCof describes Section including itsAMP 2018 information

55000 requirement and documented in Section 4.1 TLCof in Section AMP. 2018 documented and requirement 55000

between them for its Asset Management System which is itswhich for System Assetaligned ISO them with Management between

TLC has establishedinterrelations/interactions and elements key the

company. company.

approach on communication ensure the information flows freely within the the flows within freely information the ensure communication on approach

capture all capture assetissues. related project and door The small open and team

activities, weekly trickle down meetings within the asset management team asset team the meetings within activities, management down trickle weekly

network report provide information on all on aspects information assetof provide management report network

effective communication with its staff. For example monthly meetings on meetings on its with staff. monthly example For effective communication

TLC uses both formal and less formal communication strategies TLC facilitate lessand to uses formal communication formal both

3

2.5

2.5

Score

2.75

Company Name Company

AMP Planning Period AMP Planning

Question

Asset Management Standard Applied Standard Management Asset

consistent?

quality and accuracy isand and quality

it (them) is it requisite (them) the of

ensure that the data held within within data held the that ensure

information system(s) and information

maintain itsmaintain asset management

How does the organisation does the How

system?

to support its asset support to management

system(s) should contain in order system(s) in order contain should

management information information management

to determine what its what asset determine to

What has the organisation done has What done organisation the

interactions between them? between interactions

asset management asset system and management

describe the main elements of itsof elements main describe the

organisation establishedorganisation to

What documentation has the documentation What

contracted service providers? contracted

stakeholders, including stakeholders,

from employees and other other and employees from

effectively communicated to and and to effectively communicated

management information is information management

ensure that pertinent asset pertinent that ensure

How does the organisation does the How

Function

management

Information Information

management

Information Information

documentation

System System

Asset Management Asset Management

consultation

participation and and participation

Communication, Communication,

63

62

59

53

Question No. Question SCHEDULE 13: REPORT ON ASSET MANAGEMENT MATURITY MATURITY (cont) 13: MANAGEMENT ON SCHEDULE ASSET REPORT

Appendices | 174

User Guidance User

The LinesThe Company

1 April 2020 1 April 31 2030– March

Evidence—Summary

maintenance strategy plans. maintenance

TLC 2018 AMP. The regulatory requirements are applied in the preventive preventive are in applied the requirements TLC The regulatory AMP. 2018

documented within Tier 1 Risk Management Framework in Section 4.5.1 of of 4.5.1 in Section Tier 1 RiskFramework within Management documented

The requirement for reviewing and assessing and reviewing isfor requirements Regulatory the The requirement

resourcing, competencies and training plans.training and competencies resourcing,

not evidence that mitigating actions are being comprehensively linked to to linked mitigating actionsthat evidence are being comprehensively not

While there is is risksWhile there that evidence there mitigated, are and being identified,

and forecast risk for distribution poles, conductors, and crossarms.and poles, conductors, forecast distribution and risk for

methodology published by Ofgem. Models have been developed to assess to Ofgem. developed by have been published Models methodology

TLC usingan asset has tool amodelling developed leading risk management

both Tier 2 3 and levelsboth isand asset activities.prioritise used to management

described in Section 4.5 TLCof Assetin Section described AMP. risk2018 related is at considered

TLC has categorised its risks Tier 1 Risksinto Tier and 2 3 and Risks as

that data is relevant to their needs. data istheir that to relevant

information management team works with the asset the with data works usersensure team to management information

the asset strategy, the objectives plan(s).and management The asset

information systems are providing the asset information necessary to support necessary asset support the systemsto are providing information information

systems processes - The BASIX. review asset enable the ensuring

TLC is on a journey to put in place the processes to review its key information in TLCplace processes itsput the to review is information key to a on journey

3

Score

2.25

2.25

2.75

Company Name Company

AMP Planning Period AMP Planning

Question

Asset Management Standard Applied Standard Management Asset

the assetsystem? the management

requirements incorporated into into incorporated requirements

requirements, and how is how and requirements,

asset management asset management

regulatory, statutory and other other and statutory regulatory,

provide accessprovide its to legal,

organisation have to identify and and identify have organisation to

What procedure does the does the procedure What

competency needs? competency

resources and training and and training and resources

the identification of adequate adequate of identification the

assessments provide input into assessmentsinto input provide

ensure that the results the riskof that ensure

How does the organisation does the How

asset life cycle?

related risks throughout the the risksrelated throughout

asset assetand management

identification and assessmentand identification of

procedure(s) for the the for procedure(s)

documented process(es) and/or documented

How has organisation How the

its needs?

information system is to relevant information

ensured its ensured asset management

How has organisation'sHow the

Function

requirements

Legal and other Legal other and

information

asset risk

maintenance of maintenance

Use and

process(es)

Risk management Risk management

management

Information Information

82

79

69

64

Question No. Question SCHEDULE 13: REPORT ON ASSET MANAGEMENT MATURITY MATURITY (cont) 13: MANAGEMENT ON SCHEDULE ASSET REPORT

Appendices | 175

User Guidance User

AMP, BasixAMP, Database

Database

Operating Procedures, Basix Operating Procedures,

AMP, Distribution Standard, Standard, Distribution AMP,

The The Lines Company

1 April 2020 1 April 31 – 2030 March

Evidence—Summary

related fault data is processed and captured in BASIX and routinely reviewed. reviewed. fault related data isroutinely and in BASIX processed captured and

reported by either employees/contractors or by the general the public. by Asset or employees/contractors either by reported

dealing with observed defects dealing possible and observed TLC the with hazards on Network,

Procedure Emergent Worksheets set out the process for commutating and and process commutating the set for Worksheets out Emergent Procedure

emergency situations and non-conformances. TLC Network Operating TLC situationsNetwork non-conformances. and emergency

investigation and mitigation investigation of asset-related mitigation and failures, incidents and

and outlines the responsibility and the authority for the handling, the for authority responsibility the outlines and and the

Work in progress to complete Incident Management Plan which documents documents Plan which Management Incident in complete progress to Work

condition and performance. performance. and condition

and information in BASIX system for more accurately monitoring of asset accurately monitoring more systemin BASIX for information and

its availability quality. and TLC is validate progress in to the its asset data

provides a comprehensive review of asset information and condition data for data for condition and of asset review a information provides comprehensive

poles, conductors and crossarms. The process of the model development crossarms.and development The poles, process model conductors of the

of failure. Models have been developed for its overhead line its assetfor overhead of failure. developed have Models been including

assessing asset consequence and risk basedasset on performance condition,

TLC has implemented a leading methodology published by Ofgem by published for TLCa leadinghas methodology implemented

the maintenance and inspection of assets.inspection and maintenance the

for effective implementation and control of asset activities control and management for effective for implementation

requirements of the 6.2 schedulesof TLC of in the Section are outlined AMP 2018 requirements

with defined scope of work and frequency of inspection. of inspection. Detailed frequency and scope defined of work with

TLC has developed the preventive maintenance schedules allmaintenance for TLC asset preventive the has developed groups

(draft). (draft).

Closeout. TLC has reviewed and updated its Security of Supply Standard Standard Closeout. TLCof itsSupply Security hasupdated and reviewed

Master Service Agreement, Work Pack Businessand Work ProcessAgreement, Project Service Master for

delivery of asset delivery of plans. management Evidence includes development

of putting in place processes and procedures to manage and control the the in place manage control of putting and to processes procedures and

operations. While having standards operations. in itsplace, distribution TLC is in process

TLC has in place asset athe covering procedures suite of operating

2.5

2.5

2.5

Score

2.25

Company Name Company

AMP Planning Period AMP Planning

Question

Asset Management Standard Applied Management Standard Asset

communicated?

unambiguous, understood and and understood unambiguous,

non conformances is conformances clear, non

and emergency situations and emergency and

asset-related failures, incidents

investigation and mitigation investigation of mitigation and

authority for the handling, the for authority

ensure responsibility and the responsibility the and ensure

How does the organisation does the How

condition of its assets?condition

measure the performance and and performance the measure

How does the organisation does the How

performance?

control cost, risk and control

asset strategy and management

conditions, are consistent with are consistent with conditions,

carried out under specified under out carried

sufficient to ensure sufficient activitiesensure to are

(and (and inspection) of assets are

of of activities maintenance during

management plan(s) and control plan(s) control and management

implementation of asset implementation

procedure(s) for the the for procedure(s)

ensure that process(es) that ensure and/or

How does the organisation does the How

activities?

construction and commissioning and construction

modification, procurement, procurement, modification,

assets. This includes design,

acquisition or enhancement of enhancement acquisition or

of of activities across creation, the

management plan(s) and control plan(s) control and management

implementation of its assetimplementation

maintain process(es)maintain the for

establish implement and and establish implement

How does the organisation does the How

Function

nonconformities

and and

failures, incidents

asset-related

Investigation Investigation of

monitoring

condition condition

Performance and and Performance

Activities

Life Cycle

Activities

Life Cycle

99

95

91

88

Question No. Question SCHEDULE 13: REPORT ON ASSET MANAGEMENT MATURITY (cont) 13: ON MANAGEMENT SCHEDULE ASSET REPORT

Appendices | 176

User Guidance User

database improvements database improvements

Performance Target, BasixPerformance

The The Lines Company

1 April 2020 1 April 31 – 2030 March

Evidence—Summary

appropriately.

The senior management team review opportunities and implement implement and opportunities review team The senior management

- equipment suppliers - equipment

- professional bodies and regulatory -bodies professional bodies regulatory and

- participation in industry groups such groups as in industry - participation EEA ENA and

- conferences and forums - forums and conferences

- international papers and standard standard papers and - international

sources including:

TLC acquires knowledge and information for improvement from a range of from improvement for TLC information and acquires knowledge

a reliable and ready to use format to support asset support managers to engineers.and ause reliableto format ready and

A recent example is the development of Dashboard which turns asset turns which of Dashboard data to isexample A recent development the

changing to seek continual improvement since aligning ISO changing 55000. seekwith improvement to continual

term investment decision making. TLCinvestment hasterm experiencing a been culture-

assess long lines support overhead to asset their risk related for condition

risk, and performance. TLC has also applied Ofgem Common Methodology to TLCto hasrisk, performance. and Methodology also applied Ofgem Common

will improve its maintenance practice in a manner that balances that its practice in a willcost, maintenance manner assetimprove

regard to its to regard service area, land access, thistechnology new topography, and

and other infrastructure. Given the operating environment TLC facing in environment operating the Given infrastructure. other and

TLC field hastrailsinspectlineshelp itsuseto conducted to drones power

managed through normal business normal activities, through managed roles responsibilities.and

conformance register. Non conformances or issues or actively conformances register. are Non however conformance

TLC does not currently have a formal non-conformance process such as a have non-conformance anon formal TLC currently does not

AMMAT review. AMMAT

Evidence includes engaging an independent party to undertake the annual the undertake to Evidence includes party engaging an independent

actions to evaluate its asset management performance and actionscapability.and evaluate its to asset performance management

TLC is on the journey TLC of aligned ISO has and 55000 iswith taking journey started the on

2.5

Score

2.75

2.75

2.25

Company Name Company

AMP Planning Period AMP Planning

Question

Asset Management Standard Applied Management Standard Asset

to the organisation? the to

evaluate their potential benefit benefit potential evaluate their

technology and practices,and and technology

new asset new related management

and acquire knowledge about about knowledge acquire and

How does the organisation does seekthe How

the whole life whole the cycle?

assets assetand systems across

performance and condition of condition and performance

costs, asset risksrelated the and

in the optimal combination of combination optimal in the

achieve continual improvement achieveimprovement continual

How does the organisation does the How

and non conformance? non and

of identified poor performance performance poor of identified

eliminate or prevent the causesthe prevent eliminate or

and/or preventive actions to preventive and/or

instigate appropriate corrective corrective instigate appropriate

How does the organisation does the How

system (process(es))?

audit of itsaudit asset management

to establish procedure(s) for the the establish to for procedure(s)

What has the organisation done has What organisation done the

Function

Improvement

Continual Continual

Improvement

Continual Continual

Preventative action Preventative

Corrective & Corrective

Audit

115

113

109

105

Question No. Question SCHEDULE 13: REPORT ON ASSET MANAGEMENT MATURITY (cont) 13: ON MANAGEMENT SCHEDULE ASSET REPORT

Appendices | 177

SCHEDULE 14A: MANDATORY EXPLANATORY NOTES ON FORECAST INFORMATION 1. This Schedule requires EDBs to provide explanatory notes to reports prepared in accordance with clause 2.6.6.

2. This Schedule is mandatory – EDBs must provide the explanatory comment specified below, in accordance with clause 2.7.2. This information is not part of the audited disclosure information, and so is not subject to the assurance requirements specified in section 2.8.

Commentary on difference between nominal and constant price capital expenditure forecasts (Schedule 11a).

3. In the box below, comment on the difference between nominal and constant price capital expenditure for the current disclosure year and 10 year planning period, as disclosed in Schedule 11a.

Box 1: Commentary on difference between nominal and constant price capital expenditure forecasts:

Inflation of 2% has been applied across the planning period commencing in year 2.

Commentary on difference between nominal and constant price capital expenditure forecasts (Schedule 11a).

4. In the box below, comment on the difference between nominal and constant price operational expenditure for the current disclosure year and 10 year planning period, as disclosed in Schedule 11b.

Box 2: Commentary on difference between nominal and constant price operational expenditure

forecasts:

Inflation of 2% has been applied across the planning period commencing in year 2.

The Lines Company | Asset Management Plan 2020 Appendices | 178 13. Appendix D: Director Certification SCHEDULE 17: CERTIFICATION FOR YEAR-BEGINNING DISCLOSURE

Clause 2.9.1

We, SIMON YOUNG and MARK DARROW, being directors of The Lines Company Limited certify that, having made all reasonable enquiry, to the best of our knowledge:

a) the following attached information of [name of EDB] prepared for the purposes of clauses 2.4.1, 2.6.1, 2.6.3, 2.6.6 and 2.7.2 of the Electricity Distribution Information Disclosure Determination 2012 in all material respects complies with that determination.

b) The prospective financial or non-financial information included in the attached information has been measured on a basis consistent with regulatory requirements or recognised industry standards.

c) The forecasts in Schedules 11a, 11b, 12a, 12b, 12c and 12d are based on objective and reasonable assumptions which both align with [name of EDB]’s corporate vision and strategy and are documented in retained records.

DIRECTOR DIRECTOR

Date: 26 March 2020 Date: 26 March 2020

The Lines Company | Asset Management Plan 2020 Appendices | 179