Unison Networks Limited Asset Management Plan

Transcription

1 Unison Networks Limited Asset Management Plan

2 Distributed micro-generation, self healing networks, communications enabled assets and dynamic ratings all form part of Unison s Smart Grid vision. An application of next generation distribution technology to improve the customer experience.

3 Unison Networks Limited Asset Management Plan TABLE OF CONTENTS SECTION 1 SUMMARY OF THE PLAN SECTION 2 BACKGROUND & OBJECTIVES SECTION 3 ASSETS COVERED SECTION 4 SERVICE LEVELS SECTION 5 NETWORK DEVELOPMENT PLANS SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLANNING SECTION 7 RISK MANAGEMENT SECTION 8 EVALUATION OF PERFORMANCE SECTION 9 EXPENDITURE FORECASTS AND RECONCILIATION APPENDIX A GLOSSARY OF TERMS APPENDIX B REQUIREMENT 7(2) This Asset Management Plan (AMP) is available for public disclosure and applies for the period 1 April 2011 to 31 March The AMP is reviewed each year and a revised AMP is expected to be available for public disclosure by 1 April UNISON NETWORKS LIMITED 2011 Cover: Greenmeadows, Napier at sunrise. Greenmeadows is Unison s Smart Suburb; the test-bed for Unison s trial of smart network technologies.

4 Summary of the plan section 1 Summary of the plan Communications enabled 11kV ENTEC switches form a vital part of Unison s automated sectionalisation and restoration programme.

5 SECTION 1 SUMMARY OF THE PLAN Summary Company Profile Overview Corporate Goals Ownership and Governance Electricity Distribution Network UnisonFibre Limited Contracting Services ETEL Limited Facilities Management Asset Management Plan Structure Background and Objectives Assets Covered Service Levels Network Development Planning Life Cycle Asset Management Planning Risk Management Evaluation of Performance Expenditure Forecasts and Reconciliations Appendix A: Glossary of Terms Appendix B: Assumptions in Asset Management Planning Key Stakeholder Information Customer Service Levels Major Projects to Improve Customer Service Overhead to Underground Conversion Projects Stakeholder Feedback Financial Summary of Asset Expenditure and Reconciliation Table 1-1: Unison network according to key industry metrics Table 1-2: Summary of Unison's consumer oriented service targets Table 1-3: Summary of Unison s asset and business oriented performance targets Table 1-4: Major projects to improve customer service Table 1-5: HBPCT OHUG programme 2011/

6 1-2 SECTION 1 SUMMARY OF THE PLAN 1 Summary 1.1 Company Profile Overview Unison Networks Limited (Unison) is an energy infrastructure business based in the North Island of New Zealand. Unison and its subsidiaries have a range of interests, products and service offerings including electricity distribution, communications, distribution equipment, facility management services, renewable generation development, and energy infrastructure contracting services Corporate Goals Unison s key corporate goals are published in its Statement of Corporate Intent and have been reproduced below. These goals are critically relevant to the way Unison manages its asset base. Vision To be the service provider of choice for energy infrastructure solutions Mission To be a successful business through excellence in customer service, innovation, and leadership Ownership and Governance Unison is wholly owned by the Hawke s Bay Power Consumers Trust (HBPCT) on behalf of Hawke s Bay electricity consumers. Unison s Board of Directors is appointed by the HBPCT Electricity Distribution Network Electricity distribution businesses (EDB) are an integral part of New Zealand s electricity market, forming the physical link between the transmission network and electricity consumers. Unison owns, manages and operates the distribution network that serves Hawke s Bay, Rotorua and Taupo consumers. Electricity supply is taken at 33kV from Transpower s grid exit points (GXP) and is transported to zone substations by Unison s sub-transmission network. At zone substations, the voltage is converted to 11kV for distribution. Over 9,000 distribution substations throughout the network then reduce the voltage to 400V for end use. This Asset Management Plan (AMP) is concerned with the management of the assets that deliver this service. The Unison network is comprised of over $420m worth of assets, almost 10,000km in length and supplies around 110,000 connection points, making Unison the fifth largest EDB in New Zealand. Within Unison s network footprint are a variety of terrain types and consumer densities, meaning it is necessary to employ a range of reticulation methods and asset management techniques to strike the optimal balance between quality of supply and efficient deployment of assets. The quality of supply experienced by Unison s consumers has improved consistently over the past five years.

7 SECTION 1 SUMMARY OF THE PLAN 1-3 The following table provides further information on the Unison network according to key industry metrics. Metric Description Value (2009/10) Trend Consumers connected Total installation control points (ICP) connected to the network. 108,212 System length Total length of all energised circuits. 9,571km Sub-transmission system length Distribution system length Low voltage system length Percentage underground Total length of all energised 33kV circuits. 441km Total length of all energised 11kV circuits. 4,561km Total length of all energised LV circuits. 4,569km The proportion of total system length that is undergrounded. 39% - Asset value Unison s Regulatory Asset Base. $429m Faults per 100km Average number of unplanned interruptions per 100km of high voltage circuits per annum. 6.2 SAIDI System Average Interruption Duration Index. A measure of the number of minutes per year the average consumer is without electricity supply. (Regulatory limit in parentheses) minutes (147.9) SAIFI System Average Interruption Frequency Index. A measure of the number of interruptions per year that affect the average consumer. (Regulatory limit in parentheses) interruptions (2.70) Electricity supplied Electricity entering system for supply to consumers. 1,665GWh Loss factor Proportion of electricity lost on the high voltage network. 4.0% Capacity utilisation Maximum demand on distribution transformers as a proportion of installed capacity. 28% Table 1-1: Unison network according to key industry metrics The business supporting the electricity network is divided into six operating departments: Commercial, Finance, Information Management, Networks and Operations, Operations Support, and Regulatory and Pricing. Networks and Operations is the department with primary responsibility for asset management, however resources are drawn from all parts of the business and the contracting market to ensure that customer service, the regulatory environment, financial considerations and field expertise are given appropriate focus. The asset management tradeoffs that exist between these business areas and drivers are considered explicitly in Section UnisonFibre Limited UnisonFibre Limited is a wholly owned subsidiary of Unison. It provides fibre optic connection services to Unison Networks, for interconnection between zone substations and office locations, and metro-fibre (intra-city infrastructure) for external customers. Unison Fibre currently (as at February 2011) has a comprehensive core fibre network deployed around Napier, Hastings and environs as well as a backbone between the two cities. A backbone fibre has been connected around Taupo and Rotorua. The UnisonFibre network is designed to build future spurs to accommodate customer demand. Extending from these core runs, links will be provided in the first instance to commercial premises, schools, health centres and other data-intensive end-users.

8 1-4 SECTION 1 SUMMARY OF THE PLAN Contracting Services Unison Contracting Services Limited (UCSL) is a wholly owned subsidiary of Unison. UCSL provides contracting services to the Unison network in all regions and to other electricity distribution businesses. UCSL has depots located in the Hawke s Bay, Rotorua and Taupo and has recently expanded its service offering to include communications, vegetation management and civil contracting ETEL Limited ETEL Ltd, a leading New Zealand manufacturer of electricity distribution equipment is wholly owned by Unison. ETEL produces a range of transformers for the New Zealand and Australian markets Facilities Management Since October 2002, Unison has provided facility management services to Centralines, the EDB that supplies electricity consumers in the Central Hawke s Bay. The facilities management service includes asset management, network planning, detailed design and contractor management. 1.2 Asset Management Plan Structure The structure of this AMP follows the format prescribed in the Electricity Information Disclosure Handbook 31 March 2004 (as amended 31 October 2008). An outline of the content of each section is provided below, along with material changes that have been made to the plan since the previous disclosure Background and Objectives The Background and Objectives section sets out the context for the AMP, including the background, purpose statement and a description of how the AMP is interrelated with other company plans and objectives. This section also identifies stakeholder interests, sets out the responsibilities for asset management within the business and provides a high level description of the systems and processes used in asset management at Unison. Changes made in the Background and Objectives section since the previous disclosure: Section Changed Section 2.3 Section 2.6 Description A section on Unison s Smart Grid Initiative has been added. This provides context for the detailed project discussions in Sections 5 and 6. Several Unison business areas have been restructured since the publication of the previous AMP. The new structure as it pertains to asset management is presented in this section Assets Covered The Assets Covered section provides a detailed view of the assets that make up the Unison network. At the highest level, the geographic network footprint is provided, along with a description of the configuration of the network. The section then moves into greater detail, with information provided on the various categories of assets employed, including age, value and condition. Finally, technical and financial justification for assets employed is provided. Changes made in the Assets Covered section since the previous disclosure:

9 SECTION 1 SUMMARY OF THE PLAN 1-5 Section Changed Description - No material changes Service Levels Service levels allow Unison and external stakeholders to objectively measure the performance of the network and Unison as a business. This section sets out the many consumer oriented performance measures used by Unison, and justifications as to why these meet industry best practice and the best interests of stakeholders. Changes made in the Service Levels section since the previous disclosure: Section Changed Description - No material changes Network Development Planning In the Network Development Planning section, information is provided on the criteria, assumptions and techniques upon which the future planning of the Unison network is based. Models used for project prioritisation, demand forecasting and assessing system security are described in detail. The network development programme is then addressed, system constraints are identified and solutions in the form of both network and non-network projects are evaluated. Finally the capital and operational expenditure forecasts for the planning period are provided. Changes made in the Network Development Planning section since the previous disclosure: Section Changed Section Section 5.2 Section Section Section Section Section Description Majority of this section moved to Section 5.5. Emphasis changed to utilisation and rollout of smart technology. Network Investment Toolbox introduced with new diagram added. Network Investment Framework (NIF) changed to Investment Prioritisation tool (IPT). New diagram to show the relationships between tools. Updated to include Contact s Tauhara geothermal plant. Introduced the concept of using the smart meter to control demand as an alternative to installing new ripple receivers. Added an explanation of how the data received from smart devices will allow Unison to study reactive demand. Section Moved District Load Forecasts to immediately follow Section Section 5.5 Changed graph to reflect the completion of Fleet Street zone substation. Fully updated to reflect the latest equipment and concepts for the roll out of the smart network Life Cycle Asset Management Planning The Life Cycle Asset Management Planning section is concerned with Unison s asset maintenance and renewal programmes. Unison s approach to all aspects of asset maintenance, inspection, renewal and refurbishment are presented at a granular asset category level and the renewal and refurbishment projects that will take place within the planning period are discussed with associated expenditure forecasts. Changes made in the Life Cycle Asset Management Planning section since the previous disclosure:

10 1-6 SECTION 1 SUMMARY OF THE PLAN Section Changed Section 6.3 Section 6.3 Description Introduction of a new section covering the condition assessment benefits achieved through the implementation of the Smart Grid Initiative. Discussion on the CAPEX projects that have been deferred and the associated risk mitigation strategy Risk Management The Risk Management section contains detail on Unison s risk policies, assessment and mitigation strategies. Specific risks that are considered include risks to assets, failure to meet service levels, emergency response and environmental management. Changes made in the Risk Management section since the previous disclosure: Section Changed Section Section 7.3 Section Description Change to Unison s statement of policy to reflect commitment to public safety. Addition of concept of harm-free to the build and grow business strategic objective. Information on Unison Safety Management System added. Section Addition of two additional asset-related key risks to Table 7-1. Section Section Section Section Risk types in Table 7-2 have been colour coded to highlight the focus of each type. Table 7-2 reviewed and updated to better explain the asset failure mode, consequences and mitigating actions and reflect improvements in Unison s Public Safety Management Systems. Environmental Risk - Status of 2009 initiatives has been updated; a summary added of all audits to date as well as the results of the 2010 Environmental Audit have been added. Health and Safety Policy, and Company Commitment There is an addition and recognition of public safety through asset design, construction and maintenance. Target for children has increased to 2500 up from 2000 previous year Evaluation of Performance The Evaluation of Performance section reviews Unison s progress against capital and operational expenditure plans, compares actual performance against targets (for service levels and other company objectives), and identifies areas for improvement. Changes made in the Evaluation of Performance section since the previous disclosure: Section Changed Description - No material changes Expenditure Forecasts and Reconciliations Unison s expenditure forecasts and reconciliations are presented in accordance with Appendix A of the Electricity Information Disclosure Handbook 31 March 2004 (as amended 31 October 2008). Changes made in the Expenditure Forecasts and Reconciliation section since the previous disclosure:

11 SECTION 1 SUMMARY OF THE PLAN 1-7 Section Changed Section 9.1 Description Expenditure forecast table updated to reflect an expedited roll out of a smart network. The change in the expenditure forecast is possible due to the validation of the assumptions underpinning the Smart Grid Initiative and benefits thereof Appendix A: Glossary of Terms Appendix A provides a glossary of terms used in the AMP Appendix B: Assumptions in Asset Management Planning Requirement 7(2) of the Electricity Distribution (Information Disclosure) Requirements 2008 requires that where the AMP provides prospective information, certain details about the assumptions made to derive this information are provided. This requirement is addressed in Appendix B. Changes made in Appendix B since the previous disclosure: Section Changed Assumption 8 Assumption 10 Description Assumption 8 (Uncertain load types and external factors) was added to capture the uncertainty around energy intensity change and proliferation of distributed generation on the Unison network. Assumption 10 (Benefits of the Smart Grid Initiative) was updated to reflect the work that was completed during 2010/11 to validate the expenditure forecasts presented in the AMP. 1.3 Key Stakeholder Information Unison firmly believes that the AMP should be accessible to readers of varying levels of technical understanding, and that all stakeholders should be able to extract the information they require. From experience, Unison recognises that for many stakeholders (including the majority of Unison s customers), the information of the most interest is the level of service that can be expected, projects that have been initiated to improve the quality of electricity supplied, and progress on the HBPCT s overhead to underground conversion (OHUG) programme in the Hawke s Bay. To this end, this section provides an executive summary of these three areas. Under each subheading a reference to the more detailed discussion later in the plan is provided Customer Service Levels For Unison, providing a service is about understanding the expectations of stakeholders and where possible delivering a cost effective solution to meet these expectations. Service standards encompass not only quality of electricity supplied, but also health and safety, account management, project management, environmental outcomes and general communication and interactions with Unison. This philosophy is supported by the Mission Statement which has, as a cornerstone, the goal of achieving excellence in customer service. Customer service standards that Unison monitors its performance against are grouped into two categories: Consumer Oriented Performance Targets Delivering a reliable electricity supply of appropriate quality to consumers is Unison s core business. In order to measure Unison s effectiveness in achieving this, a number of performance targets are used. These include network average reliability indices (SAIDI, SAIFI and CAIDI), faults per 100km of circuit, improvement of worst performing feeders, consumer grouping targets and quality of supply on individual feeders. Further detail on Unison s Consumer Oriented

12 1-8 SECTION 1 SUMMARY OF THE PLAN Performance Targets is provided in section 4.2. Evaluation of performance against targets for the previous year is provided in Section 8. Service Standard Measure Target SAIDI SAIFI Interruptions occurring in urban areas Interruptions occurring in urban areas Interruptions occurring in rural areas Interruptions occurring in rural areas Interruptions occurring in remote rural areas Interruptions occurring in remote rural areas System Average Interruption Duration Index. A measure of the number of minutes per year the average consumer is without electricity supply. System Average Interruption Frequency Index. A measure of the number of interruptions per year that affect the average consumer. Length of time before supply is restored following an unplanned interruption. Number of unplanned interruptions per annum. Length of time before supply is restored following an unplanned interruption. Number of unplanned interruptions per annum. Length of time before supply is restored following an unplanned interruption. Number of unplanned interruptions per annum : < minutes : < 2.70 interruptions Maximum of twenty events to exceed three hours before supply is restored per annum. Maximum of one feeder to exceed four unplanned interruptions per annum. Maximum of ten events to exceed six hours before supply is restored per annum. Maximum of one feeder to exceed ten unplanned interruptions per annum. Maximum of five events to exceed six hours before supply is restored per annum. Maximum of one feeder to exceed twenty unplanned interruptions per annum. Table 1-2: Summary of Unison's consumer oriented service targets Asset and Business Oriented Performance Targets As well as delivering a high quality of supply, Unison must prove to its shareholders and the regulator that it is operating in an efficient and cost effective manner. Asset and Business Oriented Performance Targets are used to measure the efficiency of Unison s asset management practices. Measures employed include network losses, load factor and capacity utilisation. Further detail on Asset and Business Oriented Performance Targets is provided in Section 4.3. Evaluation of performance against targets for the previous year is provided in Section 8. Table 1-3 below summarises Unison s Asset and Business Oriented Performance Targets: Service Standard Measure Target Total cost per ICP Total direct and indirect cost per electricity consumer <$271 Total cost per km Total direct and indirect cost per circuit km <$3159 Utilisation factor Capacity utilisation of distribution transformers 31% Proportion of total energy lost on Unison s high 6% Loss ratio voltage network Faults per 100km Faults per 100km on Unison s high voltage network <7.99 faults per 100km Table 1-3: Summary of Unison s asset and business oriented performance targets

13 SECTION 1 SUMMARY OF THE PLAN Major Projects to Improve Customer Service The development plans and options presented in the Network Development Planning section of the AMP reflect a network development philosophy that attempts to balance customer needs, Unison s strategic objectives and industry best practice. The planning period considered by this AMP sees a continuation of capital investment in the network to meet customer driven growth, maintain network security, meet customer service levels and network reliability targets, and ensure compliance with regulatory requirements (e.g. health, safety and environmental) Smart Grid The Smart Grid concept offers a number of important opportunities to allow Unison to improve its asset management practices. The definition of Smart Grid that Unison has adopted is: The application of real time information, communication and emerging trends in electricity delivery to improve capacity utilisation, optimise asset management practices and improve services on the modern network thereby optimising network investment to the benefit of all stakeholders, or in other words, applying new technology and clever thinking to enhance asset management outcomes for the benefit of stakeholders especially the customer. During 2010 Unison undertook a new technology trial in Greenmeadows, Napier (the Smart Suburb ), which resulted in a number of assets being selected for a larger deployment. The success of the trial and the development of a comprehensive Smart Grid strategy have elevated the Smart Grid Initiative to being one of Unison s most important strategic initiatives. Further information on the Smart Grid Initiative is provided in Section 2.3. The projects that have arisen from the initiative are discussed in detail in Sections 5 and Projects that will Improve Quality of Supply The table below details the most notable projects that will improve quality of supply that will be completed within the next five years. Project Name Description Completion Year Ground Fault Neutraliser (GFN), Irongate zone substation New power transformer at Windsor zone substation Install Powersense sensors to aid fault finding and restoration. Install voltage regulators on Kaharoa, Mamaku and Waikato feeders Install voltage regulators on Otamauri and Puketitiri feeders The GFN reduces the amount of electrical arcing in the event of an earth fault, decreasing the risk of electrocution and fire. It will also enable Unison to maintain power supply to homes and businesses during fault conditions. Within the next 5 years, an additional zone substation will be equipped with a GFN, depending on the success of the Irongate installation. Windsor loads have grown to the extent that the 11kV network cannot back feed peak loads from adjacent substations should the single power transformer at Windsor trip. Adding a second power transformer at this zone substation will ensure compliance with Unison s network security criteria. This technology uses state of the art current sensors to provide accurate current, voltage and fault passage information in real time over the mesh radio network back to Unison s information management systems. This will enable Unison to expedite the location and isolation of faults thus reducing customer outage times and hence SAIDI. Voltage regulation on these feeders is below Unison s standards. Voltage regulators are a cost-efficient way to address voltage regulation problems on high voltage feeders. Voltage regulation on these feeders is below Unison s standards. Voltage regulators are a cost-efficient way to address voltage regulation problems on high voltage feeders

14 1-10 SECTION 1 SUMMARY OF THE PLAN Project Name Description Completion Year New sub-transmission circuit between Ohaaki and Fernleaf Establish a zone substation at Te Toki. Establish a zone substation at State Mill Road, Rotorua Self healing trial, Hawke s Bay Replace distribution fusing with Entec switches on Ongaroto feeder, Taupo Installation of feeder current differential protection relays in Taupo Fault Passage Indicator (FPI) Deployment of Entec switches in Rotorua and Taupo Capacitor bank trial, Hawke s Bay Taupo fast transfer scheme Taupo self healing scheme The introduction of a new sub-transmission circuit between Ohaaki and Fernleaf will greatly improve the security of supply to consumers supplied from the Fernleaf zone substation. Currently there is one 33kV circuit feeding Fernleaf, meaning that a single fault can cause a significant interruption to supply. Substantial dairy conversion is expected within the planning period in the vicinity of Broadlands Road and SH5. The magnitude of the growth cannot be supported through the existing 11kV network. A zone substation at Te Toki would cater for this growth as well as providing further 11kV interconnectivity, enhancing security of supply in the area. High industrial load is forecast for the southern outskirts of Rotorua. A constraint arises early in the planning period, meaning a significant upgrade of the network will be required. The optimal solution is to establish a new zone substation. This will also increase the security of supply in the area. The trial of self healing networks commenced in 2010/11. This technology, complemented by automated switches, was aimed at optimising load shifting, managing network constraints and reducing outage occurrence and duration. Ongaroto feeder is a remote 11kV circuit with reliability issues, predominately related to vegetation and extreme weather events. Deployment of the Entec switch in place of distribution dropout fuses (DDO) was selected as the optimal solution. Protection relays operate to minimise the damage to assets in the event of a fault. Relays with differential protection enhance this capability by reducing the risk of faults propagating between circuits on the same set of poles. This technology is utilised in Taupo on the Centennial Drive Switching Station to Runanga zone substation 33kV circuit. FPIs are portable devices used to determine the location of faults on overhead networks. The deployment of FPIs on the network will enable Unison to quickly identify transient faults, reducing recurrence. The Smart Grid rollout will focus on the deployment of automated Entec switches to replace existing manually operated air break switches (ABS). The Entec switch will greatly reduce restoration times to the majority of affected consumers in the event of a fault. Feeders where reliability has traditionally been a problem will be targeted first. Capacitor banks provide a cost effective alternative to improving feeder capacity where low voltage is a problem. Low voltage is an issue for Unison in rural areas where large irrigation loads are present. Capacitor banks will improve voltage profiles and asset utilisation. This project utilises automated switches (overhead and ground mounted) to quickly transfer load between zone substations using the 11kV network. This project builds on the fast transfer scheme with the addition of a substantial array of automated switches and sensors on the 11kV network. This enables the fast isolation of the faulted section of an 11kV feeder and the automatic restoration of as many customers as possible Timing determined by customer requirements Complete Complete Complete Complete On-going Complete Table 1-4: Major projects to improve customer service

15 SECTION 1 SUMMARY OF THE PLAN Overhead to Underground Conversion Projects Each year in lieu of part of its consumer dividend, the HBPCT initiates several overhead to underground conversion (OHUG) projects in urban areas of the Hawke s Bay. Unison contributes to these projects to the extent required for notional like-for-like renewal of the overhead assets. The HBPCT has asked Unison to prioritise OHUG projects to take advantage of synergies with the asset renewal programme. This arrangement results in the completion of six OHUG projects worth a total of approximately $1.8M per annum. Table 1-5 provides an indicative view of the projects that will be undertaken in 2011/12 Project Name Description Indicative Cost Keats Avenue OHUG conversion of the full length of Keats Avenue, Napier. $126,000 Shackleton Street OHUG conversion of Shackleton Street, Napier from Hillary Crescent to Nobel $140,000 Road. Darwin Crescent OHUG conversion of Darwin Crescent, Napier from Lodge Road to Bledisloe $401,000 Road. Avon Terrace OHUG conversion of the full length of Avon Terrace, Napier. $167,000 Mayfair Avenue OHUG conversion of the full length of Mayfair Avenue, Hastings. $479,000 Townshend Street Phase 2 OHUG conversion of Townshend Street, Hastings from Heretaunga Street to Southampton Street $396,000 Table 1-5: HBPCT OHUG programme 2011/ Stakeholder Feedback Unison s 2009 AMP was rated as a top performer by Strata Energy Consulting in its AMP Compliance Review 2008/09 on behalf of the Commerce Commission. The review found the AMP highly compliant with the requirements of the Electricity Information Disclosure Handbook Areas of the AMP that were identified as being either partially compliant or non-compliant were addressed in the 2009/10 AMP that was not subject of external review. The 2010/11 AMP goes one step further by including additional information that is required for stakeholders to develop a good understanding of asset management planning at Unison. Unison encourages feedback on all aspects of the AMP to enable continued improvement in meeting the needs of consumers and stakeholders. Feedback should be addressed to: Grant Adams, Asset Manager, Unison, PO Box 555, 1101 Omahu Road, Hastings. [email protected]

16 1-12 SECTION 1 SUMMARY OF THE PLAN 1.4 Financial Summary of Asset Expenditure and Reconciliation

17 SECTION 1 SUMMARY OF THE PLAN 1-13

18 section 2 background & objectives background & objectives Smart Network Engineer Jennifer Wen discusses the decision rules guiding smart network asset deployment with Network Strategy Analyst Josh Lloyd.

19 SECTION 2 BACKGROUND AND OBJECTIVES Background and Objectives Purpose Purpose of the Asset Management Plan Objectives of Asset Management Planning Relationship with Other Business Plans and Goals Mission and Vision Statements as they relate to Asset Management Documented Plans Produced in Annual Planning Process Relationships between Plans, Processes, Models and Stakeholders Smart Grid Initiative Background and Purpose Objective A Definition of Smart Grid Network Benefits Planning Approach Period Covered by the Plan Stakeholders Interests Identification of Stakeholder Interests Accommodation of Interests into Asset Management Planning Conflict Resolution Accountabilities and Responsibilities Asset Management Systems and Processes Managing Routine Asset Inspections and Network Maintenance Planning and Implementation of Network Development Projects Measuring Network Performance for Disclosure Purposes

20 2-2 SECTION 2 BACKGROUND AND OBJECTIVES Figure 2-1: Competing Drivers Figure 2-2: Information flows in Unison s asset management and business planning processes Figure 2-3: The Smart Grid Initiative Figure 2-4: Smart Grid Initiative Documentation Hierarchy Figure 2-5: Data Management Vision Figure 2-6: Responsibilities for asset management at Unison Figure 2-7: Managing routine asset inspections and network maintenance Figure 2-8: Examples of substation internals within Unison's GIS Figure 2-9: Planning process Figure 2-10: Process for measuring and analysing network performance Figure 2-11: Call & dispatch geographic view Figure 2-12: Call & dispatch detail map view Table 2-1: Relationship between AMP and other documented plans Table 2-2: High Level Benefits of Smart Grid Initiative Table 2-3: Twelve Stated Network Benefits of the Smart Grid Initiative Table 2-4: Stakeholders' key interests

21 SECTION 2 BACKGROUND AND OBJECTIVES Background and Objectives 2.1 Purpose Purpose of the Asset Management Plan The primary purpose of this Asset Management Plan (AMP) is to provide a window into Unison s business in order to develop stakeholder understanding of key drivers and objectives, network planning techniques and asset maintenance practices. This improved understanding will in turn lead to enhanced dialogue between Unison and its stakeholders, allowing Unison enhance its performance as an electricity distribution business. The secondary purpose of the AMP is to satisfy regulatory requirements by detailing Unison s asset management policies, practices and processes in accordance with the Electricity Information Disclosure Handbook Objectives of Asset Management Planning The starting point for asset management planning at Unison is the Statement of Corporate Intent (SCI). To achieve the objectives embodied in the SCI while ensuring best practice asset management, Unison makes a tradeoff between three competing drivers. The first element to be considered in the trade off exercise is the provision of a high quality customer experience. This is achieved through consultation and focusing on what is important to customers. Customer requirements must however be tempered by the constraints of the regulatory environment and the need for Unison to remain financially sustainable as a provider of an essential service. Finally, because Unison s pricing is regulated, a natural tension exists between financial drivers and regulatory compliance. The competing drivers are depicted in Figure 2-1 below. Customer Experience Customer service Quality of supply Customised service offerings Financial Sustainability Network CAPEX Asset maintenance Indirect Costs Regulatory Compliance Default Price Path (DPP) Disclosure requirements H&S and environmental Optimal Asset Management Planning Figure 2-1: Competing Drivers

22 2-4 SECTION 2 BACKGROUND AND OBJECTIVES A variety of tools, systems and techniques are used to reach the optimal trade off. Some examples of these are provided below and each is discussed in further detail in later sections of the AMP as indicated. A cohesive, integrated suite of information systems, data repositories and models (Section 2); A highly granular understanding of the asset base, demands of large customers, and the areas of operation (Section 3); Consultation with customers on the relationship between the cost of distribution services and the quality of supply received (Section 4); A set of service standards that are used to assess how Unison is performing as an electricity distribution business (Sections 4, 8); Hawke s Bay and Central Region network development plans for the planning period to ensure customer service levels are satisfied and network security criteria are met over the long term (Section 5); A strong focus on the use of non-network solutions and demand-side management techniques as alternatives to further investment in traditional network assets (Section 5); The introduction of smart network technologies to improve utilisation of the asset base, enhance reliability and meet emerging customer demands (Sections 5, 6, 7); A bespoke suite of decision support tools used to reach optimised tradeoffs between investment in new assets and maintenance of existing assets based on a total life cycle cost approach (Sections 5, 6); A comprehensive risk management strategy that includes asset specific and event specific mitigation techniques (Section 7). 2.2 Relationship with Other Business Plans and Goals Asset management at Unison is informed by a number of sources including the SCI, customer consultation, professional judgment of experienced employees, international best practice, lessons learned from other utilities and other internal plans. The AMP represents the confluence and consolidation of information from these sources Mission and Vision Statements as they relate to Asset Management Vision To be the service provider of choice for energy infrastructure solutions Mission To be a successful business through excellence in customer service, innovation, and leadership The AMP clearly sets out the path required for Unison to achieve its Vision and Mission statements from an asset management perspective. For Unison, providing industry leading infrastructure solutions (as per the company Vision) means not only engaging in current best practice asset management, but also setting the industry standard for asset management going forward. Customer service, innovation, growth and leadership are desirable business qualities

23 SECTION 2 BACKGROUND AND OBJECTIVES 2-5 identified in the Mission. These qualities underpin Unison s asset management practices. The concepts embodied in the Vision and Mission statements are recurring themes throughout the AMP. Unison s Smart Grid Initiative is a prime example of the business commitment to the Vision and Mission. This initiative will redefine customer service in the electricity distribution industry by ensuring that Unison is responsive to changing demands and expectations and is continually improving its service offering (both quality and range of services). The Smart Grid Initiative is driving innovation at Unison and is providing the business with growth opportunities as the technology and intellectual property that is established becomes part of best practice asset management. The Mission and Vision statements are behind Unison s drive for asset management excellence Documented Plans Produced in Annual Planning Process The key documented plans produced as outputs of the annual business planning process are shown in Table 2-1 below: Name of Planning Document Description Relationship with AMP Statement of Corporate Intent (SCI) Business Plan (CAPEX & OPEX Forecasts) Network Management Plan (NMP) Smart Grid Project Management Plan (SG PMP) Contracting Framework Unison s SCI is published annually and approved by the Hawke s Bay Power Consumers Trust (HBPCT) on behalf of shareholders. The SCI sets out key goals and objectives for the business and includes the Vision and Mission statements (Section 2.2.1). The Business Plan sets annual goals, objectives and key performance indicators for the business. It also contains expenditure projections for approval by the Board of Directors. The Network Development Team and Asset Management Team annually produce the internal NMP which includes policies, standards and strategies. This document provides a comprehensive strategic roadmap for the deployment of new technology (including distribution assets, communications and demand side management devices), the development of data management solutions to deal with the avalanche of data generated by the smart network and the review and upgrade of Unison s decision support framework, necessitated by the smart grid paradigm shift. The Contracting Framework is Unison s strategy for having works built, upgraded and maintained by the contracting market. Key objectives of the Contracting Framework are competitive outcomes, contractor efficiency and quality workmanship. The AMP describes the ways in which the goals and objectives embodied in the SCI will be achieved from an asset management perspective. A subset of the key performance indicators published in the Business Plan is adopted into the published AMP (Section 4). The expenditure forecasts published in the AMP are based upon the forecasts approved annually by the Board of Directors within the Business Plan. The NMP informs Sections 5 and 6 of the AMP (network development and lifecycle asset management planning). The SG PMP is a critical input to the 2011 AMP and will be continue to be important in subsequent AMP publications, as smart grid concepts continue to shape Unison s asset management practices. The expenditure forecasts that are produced for the Business Plan and are adopted by the AMP are checked for consistency with the Contracting Framework.

24 2-6 SECTION 2 BACKGROUND AND OBJECTIVES Name of Planning Document Description Relationship with AMP Risk Register Environmental Management Plan (EMP) Health and Safety Management Plan (HSMP) The Risk Register is a live database that is used to document key business risks. Risk mitigation strategies are reviewed annually. The EMP is a set of planning documents that manage environmental outcomes on the Unison network. The plan includes guidelines on environmental best practice, management of hazardous substances and the environmental audit regime. The HSMP defines health and safety protocol on the Unison network. Risks related to asset management within the Risk Register inform Section 7 of the AMP. The EMP informs Section 7 of the AMP. The HSMP informs Section 7 of the AMP. Table 2-1: Relationship between AMP and other documented plans Relationships between Plans, Processes, Models and Stakeholders Figure 2-2 shows how the different documented goals and plans relate to one another in terms of conceptual linkages and information flows. References are provided for further detail on individual elements of the diagram.

25 SECTION 2 BACKGROUND AND OBJECTIVES 2-7 Figure 2-2: Information flows in Unison s asset management and business planning processes 2.3 Smart Grid Initiative A section on Unison s Smart Grid Initiative has been added to the 2011 AMP. This reflects the fundamental impact that the smart grid is having on asset management planning at Unison. The section provides an overview of the initiative to ensure that the Network Development Plans presented in Section 5 and the Lifecycle Asset Management Plans presented in Section 6 are read in the context of the broader strategy.

26 2-8 SECTION 2 BACKGROUND AND OBJECTIVES Background and Purpose Smart Grid became a strategic direction for Unison Networks Ltd in June 2009, following the presentation of a vision for a network of the future to the Board of Directors. Combined with the development of a strategy to increase Unison s relevance to its customers, and an investigation into advanced metering infrastructure (AMI), the Smart Grid Initiative represents a strategy that has been designed to revolutionise Unison s business model and empower the customer. Figure 2-3 shows the key elements of Unison s Smart Grid Initiative. Figure 2-3: The Smart Grid Initiative Objective The goal of the Smart Grid Initiative is to leverage off new technology to improve and expand upon the services Unison provides to its customers, reduce network expenditure and obtain the twelve stated network benefits (see 2.3.4) while creating revenue growth opportunities A Definition of Smart Grid The term Smart Grid has come to mean a number of things in a range of contexts. To ensure clarity, the following definition of Smart Grid has been adopted by Unison: The application of real time information, communication and emerging trends in electricity delivery to improve capacity utilisation, optimise asset management practices and improve services on the modern network thereby optimising network investment to the benefit of all stakeholders. This is a broad definition that emphasises the cross-functional nature of the Initiative.

27 SECTION 2 BACKGROUND AND OBJECTIVES Network Benefits The Smart Grid Initiative has been designed to deliver benefits an order of magnitude greater than the investment required by improving the efficiency of the underlying assets employed. In practical terms this means being able to run assets harder for longer without materially increasing the risk of failure. The initiative will also deliver classes of benefits not currently available as the network becomes more responsive to the demands of the customer. At the highest level the network benefits offered by the Smart Grid Initiative are: Category Benefits Reduction in network expenditure CAPEX deferral Optimisation of maintenance expenditure Improvement in customer service Enhanced network performance Improved power quality Customised service offerings Safer and more sustainable network Health and safety Environmental, sustainable network development and energy efficiency Table 2-2: High Level Benefits of Smart Grid Initiative The high level benefits are further disaggregated into a set of twelve that have been prioritised and are key to the planning process. It is these twelve benefits that are the touchstones for the development of any network solutions within the penumbra of the Smart Grid Initiative. These benefits are: Twelve Stated Benefits 1. Enhanced asset capacity (rating) 2. Extended asset life 3. Avoidance of faults 4. Faster restoration of supply post-fault 5. Optimisation of planned maintenance 6. Optimisation of control room operations 7. Improved power quality 8. Health and safety issues dealt with pre-emptively and promptly 9. Reduction in electrical losses 10. Improved planning and network design 11. Pinpoint load control 12. Demand-side management Table 2-3: Twelve Stated Network Benefits of the Smart Grid Initiative

28 2-10 SECTION 2 BACKGROUND AND OBJECTIVES Planning Approach As the definition in suggests, the Smart Grid Initiative has evolved to being far more than just a deployment of new technology on the network, supported by communications infrastructure. To provide the appropriate structure to the multi-dimensional plan, the initiative has been disaggregated into five workstreams as shown in Figure 2-4. Figure 2-4: Smart Grid Initiative Documentation Hierarchy The five workstreams are summarised briefly below: Smart Network The Smart Network Workstream Plan contains the deployment plan for new technologies. It includes summaries of each of the technologies that have been selected, the decision rules for asset placement (quantities and positions) and a detailed project list. This document is most closely related to the Communications Network Workstream Plan Communications Network The objective of the Communications Network Workstream Plan is the provision of a fit for purpose communications network to support the smart network asset deployment. The communications network is an essential element of the overall Smart Grid Initiative as it allows assets to work cooperatively, and provides the medium for data to be returned to Unison for use in decision tools and data management algorithms Decision Support Tools The Smart Grid Initiative will have a profound impact on the decision support tools contained within the Network Investment Toolbox. The increased scope and volume of data that the smart assets will provide means significant redesign of the tools will be necessary to realise their full potential. The tools will be complemented strongly by the Data

29 SECTION 2 BACKGROUND AND OBJECTIVES 2-11 Management Workstream Plan which envisages the development of data management algorithms that will package the vast data streams into information that the tools can process. The tools and the data management solutions together present a strong value proposition for commercialisation in the smart grid space Data Management The Data Management Workstream Plan sets out the roadmap for the development of a computational framework that will guide asset management at Unison. The key areas of focus for the Data Management workstream are data visualisation, algorithms to enable the realisation of defined Smart Grid benefits using data fusion and the establishment of a collaborative arrangement with likeminded distribution businesses. This workstream envisages a transformation of data to information to knowledge as depicted below. The realisation of this vision is intrinsically linked to the Decision Support Tools workstream. Figure 2-5: Data Management Vision Demand-side Management Initiatives To enable demand-side management on the Unison network a different set of assets will need to be researched and trialed. Moreover, significant collaboration with the Commercial Group will be required. The Workstream Plan for Demand-side Management Initiatives was developed to meet these needs. The plan is closely related to that for Data Management, as the processing of vast quantities of customer time-of-use data is the starting point for realising the network benefits of demand-side management. Some of the assets that will be researched under this workstream plan include smart meters, electric vehicles, the Smart Transformer and micro-generation. 2.4 Period Covered by the Plan This AMP covers a period of 10 years from 1 April 2011 to 31 March Financial projections have been made for this period with more specific details identified for the earlier years. This plan was approved by Unison s Board of Directors (the Board) on 30 March Stakeholders Interests Identification of Stakeholder Interests Identification of stakeholder interests is essential if they are to be accommodated in an equitable manner. Unison is currently part of an interposed arrangement with electricity consumers. This means that while Unison provides a service

30 2-12 SECTION 2 BACKGROUND AND OBJECTIVES directly to consumers, the contractual counterparty is the electricity retailer. This contractual framework does not provide an ideal mechanism for meaningful consultation. To mitigate this shortcoming in the contractual framework, Unison makes a concerted effort through a number of initiatives to understand the requirements and expectations of its customer base. Such initiatives include customer satisfaction surveys, consultation with interest groups and community groups (representing large numbers of consumers) and other forms of research (e.g. learning from experiences of other utility operators). Unison continues to actively participate and engage at all levels within the community s that it operates in. Unison supports a wide variety of community initiatives across its network footprint, these include; sports teams and venues, educational programmes, cultural events, art and food festivals, and health and safety programmes. Community engagement also assists Unison with identifying the interests of its key stakeholders. For example, Unison is a major partner in the promotion and development of promoting Hawke s Bay as a national centre for track cycling including being a key sponsor of the proposed cycling velodrome, and Black White, lets bike campaign. Unison s key stakeholders, the methods used to identify their interests, and the interests themselves are itemised in Table 2-4 below. Stakeholder Method of Identifying Stakeholder Interests Key Interests Consumers Consumer satisfaction surveys and other research initiatives Areas of the business that deal directly with individual consumers (e.g. New Connections and Control Room) Use of System Agreement with retailer Contractors Relationship management meetings Monthly coordination meetings Contractor health and safety meetings Contracting Framework (works planning process) Price (line charges) Quality of supply Public health and safety Connection policies Customer contribution policy Overhead to underground conversion programme Participation in the local communities served Continuity of work Contractual relationship Health and safety in the workplace Construction, operating and maintenance standards Contracts Councils Coordination meetings Strategic meetings Hearings and submissions Property developers Site meetings Liaison through New Connections Team Environmental impact (compliance with RMA, District/Regional Plan, HSNO) Development of local economy Public health and safety Overhead to underground conversion programme Timeliness of network connection Overhead to underground conversion programme Connection policies Customer contribution policy Employees Internal communications Workplace health and safety

31 SECTION 2 BACKGROUND AND OBJECTIVES 2-13 Stakeholder Method of Identifying Stakeholder Interests Key Interests Employee satisfaction survey Performance appraisals Positive, professional working environment Competitive remuneration Energy retailers Use of System Agreement Contractual relationship Equipment and material vendors and manufacturers Meetings between Unison s Networks and Operations Team, Store personnel and sales representatives Regulatory bodies Submissions Contract Relationship meetings Interest groups and community groups Large consumers (see Section 3) Price (line charges) Quality of supply Ongoing custom View of forward order book Statutory obligations Relationship between price and quality Economic efficiency Information disclosure Consultation Relationship between price and quality Community participation Regular relationship meetings Contract Connection policies Price (line charges) Security of supply Quality of supply Safety Landowners Consultation Property values Amenity value Media Media strategy Communications Team Other utilities Site meetings Relationship meetings Shareholders (HBPCT) Regular meetings with Board Statement of Corporate Intent AGM Transpower (Grid and System Operator) Regular communication between planning departments Regular communication between system operators Transpower s Annual Planning Report Unison Board of Directors Regular meetings with the Executive Management Team Table 2-4: Stakeholders' key interests News and public relations Alternative energy sources Environmental issues Crisis management Asset locating services Opportunities for collocation of assets Benchmarking Return on investment OHUG Community representation Network development requirements Real-time operation Shareholders interests (value, quality of supply, community participation) Statutory obligations Growing the business

32 2-14 SECTION 2 BACKGROUND AND OBJECTIVES Accommodation of Interests into Asset Management Planning Stakeholder interests are incorporated into Unison s asset management practices in many ways, particularly when it comes to quality of supply. Unison actively monitors network performance with meetings to review outages on a weekly basis. These meetings are attended by representatives from the wider business and cover investigation of failures, review of response times to outages, suitability of operational restoration procedures and options to improve network configuration (e.g. to minimise recurrence and support improvements in future restoration). Network performance is a standard agenda item for monthly meetings with the contracting market and for the monthly Operational Report prepared for the Board of Directors Conflict Resolution Situations sometimes arise where Unison is required to resolve a conflict in stakeholder interests. In the first instance, Unison will endeavor to work with the interested parties to come to an outcome agreeable to all (consultation, arbitration). If these processes do not resolve the conflict, Unison will adjudicate on the issue. In order to do this, Unison uses a standard toolbox of guidelines to prioritise asset management outcomes in concert with principles of fairness and equity. The guidelines used in order of importance are: Statutory/legal compliance; Statement of Corporate Intent (SCI); Unison standards; Requirements of large consumers (refer to Table 3-1); Least cost; Synergy with network development / asset maintenance programmes of works; Other interests Example of Application of Conflict Resolution Procedure Whether to undertake overhead to underground conversion of assets is a contentious issue and equity concerns are often difficult to resolve (who pays and who benefits?). Because of the many parties interested in this issue, consultation and arbitration processes are generally not possible and therefore Unison s conflict resolution guidelines are applied to reach an outcome. Through the Statement of Corporate Intent, the Hawke s Bay Power Consumers Trust (HBPCT) requires Unison to contribute to the renewal component of the OHUG projects they initiate. Prioritisation of feeders is based upon least cost (most undergrounding per dollar of expenditure) and synergies based upon network development and asset maintenance programmes. Other interests (including those of individual consumers and community groups) are taken into consideration, but may not always be decisive. 2.6 Accountabilities and Responsibilities Ultimate responsibility for the planning and execution of the AMP resides with the Board of Directors and is delegated to thegroup Chief Executive. Each year, the Board approves a level of network investment for Operational Expenditure (OPEX) and Capital Expenditure (CAPEX). Each project in excess of $1,000,000 requires Board approval to commence, with financial approval of individual projects below $1,000,000 delegated to the Group Chief Executive, General Management, or Line Management depending on the value of the project. Unison s progress through the

33 SECTION 2 BACKGROUND AND OBJECTIVES 2-15 annual network investment programme is reported to the Board on a monthly basis. All commitments in excess of $100,000 are specifically itemised. The diagram below displays the roles responsible for asset management at Unison. Each functional group has its own defined and documented responsibilities in relation to the AMP as detailed below: Group Chief Executive GM Operations Support GM Regulatory & Pricin g GM Networks & Operations Chief Financial Officer Chief Executive UCSL Supply Manager Service Delivery Manager Works Performance Manager Smart Grid Manager Operations Manager Asset Manager Network Planning Manager Network Strategy Manager External Contractors UCSL Figure 2-6: Responsibilities for asset management at Unison General Manager Networks and Operations Responsible for network planning, life cycle asset management, the implementation of a smart grid, operation of the network control centre and the public safety responsibilities contained within each of these activities. These responsibilities are further delegated to five Line Managers: Asset Manager, Operations Manager, Planning Manager Smart Grid Manager and Network Strategy Manager The Asset Manager is responsible for the overall coordination of lifecycle asset management at Unison. The Planning Manager is responsible for the planning of the network to meet consumer growth expectations, reliability service levels and power quality requirements. The Operations Manager oversees the real-time operation of the Unison network. The Smart Grid Manager is the owner of the initiative that will transform the Unison network into a smart grid. The Network Strategy Manager is responsible for the development and application of the Network Investment Toolbox to optimise the deployment of network expenditure in support of asset management objectives. General Manager Operations Support In the Asset Management sphere, the General Manager Operations Support is responsible for delivery of designs for works, delivery of the capital and maintenance works programmes, management of GIS systems and material procurement. These responsibilities are further delegated to the Service Delivery Manager, Supply Manager and Works Performance Manager. Unison operates a store and materials are provided to contractors on a free issue basis. General Manager Regulatory and Pricing Provides a regulatory context for Asset Management planning and lobbies for changes to the regulatory environment as it applies to Asset Management.

34 2-16 SECTION 2 BACKGROUND AND OBJECTIVES Chief Financial Officer Responsible for providing a fiscally sustainable level of network investment and the provision of financial reporting where required on Asset Management outcomes. These responsibilities are further delegated to the Financial Controller. Chief Executive UCSL Responsible for fault response and competes for CAPEX and maintenance works across the network. These responsibilities are further delegated to the Chief Operating Officer and Works Managers for Hawke s Bay and the Central Region. 2.7 Asset Management Systems and Processes This section identifies the systems and processes used within the business for: Managing routine asset inspections and network maintenance; Planning and implementation of network development projects; Measuring network performance for disclosure purposes Managing Routine Asset Inspections and Network Maintenance Process Unison s asset inspection and network maintenance process is an integrated chain of theoretical and empirical components. The key elements are strategic analysis models, predictive analysis models and the condition assessment and inspection regime. Unison uses a number of models to optimise the lifecycle of its assets. These models are typically built in either Excel or MATLAB depending on complexity and required computational resources. The most critical and widely applicable of these models are the Renewal Envelope (RE Section 6.4.4), the Triple-R model (Repair/Refurbish/Replace Section 6.4.7) and the Investment Prioritisation Tool (IPT Section 5.2.1). The models are informed by data from the several systems and databases discussed later in this section. Unison has a rigorous asset inspection and condition monitoring regime that is used to establish an understanding of the assets and their service status and is used as one of the key drivers for maintenance and renewal activities (further detail in asset specific section). Importantly, this ensures that models based in theory are informed by reliable, empirically obtained asset data. Inspection processes generating high volumes of data utilise electronic field capture systems to minimise data processing. The field capture devices are predominantly PDA devices using in-house software that allows uploading of data directly into Unison s core business applications and models. The relationship between the models and the condition assessment and inspection regime within the lifecycle asset management process is shown in the diagram below.

35 SECTION 2 BACKGROUND AND OBJECTIVES 2-17 Asset Inspection frequency according to economics / risk trade off Inspection prioritisation informed by asset risk profile RE run annually Asset Condition OK Inspection RE Benefit:Cost ratio of renewal less than 1 Asset condition not satisfactory Asset RLE informed by condition assessment Triple R Benefit:Cost Ratio of renewal exceeds 1 Asset remains in service Repair Refurbish Renew Asset remains in service Maintenance Plan Investment Prioritisation Tool (IPT) Operational Expenditure Plan Capital Expenditure Plan Figure 2-7: Managing routine asset inspections and network maintenance Key Systems WASP Unison s current Asset Management System is EMS WASP. The WASP asset register is the main repository for asset data and stores both current attributes as well as historical information. The asset data that WASP masters is available for viewing by the GIS thus providing consistency of information. WASP supports the following key functions: Primary data source for asset history; Initiation of asset inspection regimes; Asset life cycle management; Recording of actions undertaken on an asset; Initiating maintenance projects. Unison also uses EMS WASP to provide works management. This integrates with the Asset Management module of WASP allowing the recording of actions against Assets as an inherent part of the works project.

36 2-18 SECTION 2 BACKGROUND AND OBJECTIVES Key functions supported are: Project estimation; Work pack creation; Labour, crew, and plant scheduling; Job costing; Work task creation. Given that WASP is at end of life, Unison has elected to use the replacement product from the same vendor (EMS), Electricity Manager, configured to Unisons specific requirements. This new Unison system is branded as ACTIVA and is scheduled to go into production April Woodscan Pole testing is supported by Woodscan, an application that uses ultrasound to map a cross sectional slice of the pole in order to determine structural integrity. The data file is returned to a centralised database. Mobile Asset Inspection Asset Inspection is supported by a bespoke application developed in-house. It utilises IPAQ mobile devices for field use and is interfaced with the WASP Asset Management system. The application supports: Downloading of the asset inspection regimes and previous inspection details from the Asset Management System; Asset inspection results; Uploading of the results to the Asset Management System. This system is being replaced as part of the ACTIVA implementation April The Mobile solution is based on a Windows 7 Mobile solution and will significantly extend the current functionality. Geo-Spatial Information System (GIS) The Geo-Spatial Information System (GIS) stores records of Unison s network assets according to their location and electrical connectivity. This includes the electrical connectivity internal to substations. To support the management of the Communications Fibre infrastructure Unison implemented GE s Physical Network Infrastructure (PNI) module October 2010.

37 SECTION 2 BACKGROUND AND OBJECTIVES 2-19 Figure 2-8: Examples of substation internals within Unison's GIS The GIS supports many of the operational and strategic management activities throughout the business. The GIS system provides the following support functions: Primary data source for asset valuation methodology (ODV and IFRS); Data source for network modeling applications; Reference system for asset locations and planned works; Reference system for roads, properties, easements, topological maps and aerial photography; Reference system for high voltage network schematics (single-line diagrams); Geographic and topological analysis of network data; System for Network and Communications Design and Estimation; Reference system for electrical connectivity (represented geographically or by schematic); Reference system for Fibre Communications connectivity and modeling. PI (Plant Information) This system is a real time data trending and analytical tool. Real-time data is continuously extracted from network devices for analysis within the PI system. PI is an essential asset planning and forecasting tool used by Unison s planning engineers.

38 2-20 SECTION 2 BACKGROUND AND OBJECTIVES This system is used to record and analyse events on the network. These events may be switch events, analogue type data such as transformer oil temperature, cable temperature etc. This information is then used to identify abnormalities or excursions from operating norms, then used to initiate an infield inspection or possible maintenance activity. As Smart Grid devices are rolled out onto the network, real time asset operational information is being processed and presented to assist network decisions. Investment Prioritisation Tool (IPT) The IPT is a multi-criteria decision support tool that enables all asset management drivers for a given portfolio of projects to be compared and trade off with one another, according to a set of specified weights. The IPT was referred to in previous AMP publications as the Network Investment Framework (NIF). See section Renewal Envelope (RE) This model is used to provide a bottom up view of the assets that are due to be replaced according to remaining life expectancy (RLE). RLE is based upon condition assessment data or where this is not available, the standard life of the asset class being considered. The RE was referred to in previous AMP publications as the Network Renewal Investment Model (NRIM). See Section Triple-R The Triple-R tool is a discounted cashflow model used to select the optimal mode of life extension for an asset that has either failed or is operating past its expected life (based upon condition assessment or the standard life assumption). See Section Data Quality The quality of the data obtained from asset inspections is of high quality. Quality and completeness of legacy data from the Central Region (assets acquired from United Networks in 2002) is of a lesser standard than that in the Hawke s Bay. Asset remaining life data (based upon standard life assumptions and inspections) used in RE and Triple-R models is improving, but has some known gaps. The result of this is that assets without an assessed remaining life expectancy are set to defaults based upon assumptions of the overall asset base Data Quality Improvement Initiatives Exception reports are run on a regular basis and identify differences in the data between the GIS and WASP (the Asset management system). Corrections to the data take place on a case by case basis after investigation. These exception reports also look at information around easements to identify where we have easement information which has not been updated in the GIS. Physical audits are carried out by GPS of particular assets to ensure that the process of recording location has been correctly followed. A mobile strategy has been defined which by putting more information in the hands of people in the field, and providing a feedback loop of differences in the field to that on the systems, a more formal and ongoing process of continuous improvement of the data can be implemented. This was delayed from last year to align with the replacement of the Asset management system scheduled for this year.

39 SECTION 2 BACKGROUND AND OBJECTIVES 2-21 Network Feeder Inspections take place to identify any anomalies in SCADA and GIS data. Corrections take place as required. Feedback is provided from contractors and Unison employees when anomalies are found on site when compared to the plan from the GIS or CAD. These are then investigated and corrected when required. This feedback is on an as discovered basis rather than a formal programme of inspection Legacy Data for the Central Region s network held in GIS is not of the same standard or quality as that held for Hawke s Bay. This is a consequence of the acquisition of this network and the original data not being as per the required standard. There is an ongoing programme of work within the GIS team to correct this and bring this into the required standard. This project has been underway for the last three years with dedicated resource in the Central Region. A programme of work has been implemented within Unison to correct specific data issues and to review processes to ensure data quality continues to be improved and measured. This programme includes: 1. Evaluating LV connectivity in Central Region, with field checks and data correction. 2. Redefining Asset Numbering conventions to align across all systems and regions 3. Reviewing proposed legislation around Road Corridor Management and implementing supporting processes. 4. Reviewing Landbase and GPS systems accuracy. The introduction of Smart Technologies allows analysis of actual connectivity vs systems connectivity, which will provide the ability to reconcile and correct errors in recorded connectivity.

40 2-22 SECTION 2 BACKGROUND AND OBJECTIVES Planning and Implementation of Network Development Projects Process Inputs Project Drivers Project Options Project Selection Project List Load Forecast and capacity determination Network Performance Database Network Sensors Network Security Criteria Capacity Headroom Large Customer Needs Quality of Supply Network Strengthening Solutions Non Network Solutions Do Nothing Network Augmentation Envelope Risk Assessment Network Reliability Operational Constraints (Risk Assessment of Option selected) Network Investment Framework Figure 2-9: Planning process Key Systems Geo-Spatial Information System (GIS) As provided in Unison Project Systems (UPS) UPS provides a more formal project and tender management process, with formal workflow and escalation points. This provides a greater level of visibility of project progress, costs and asset creation. Tenders can be evaluated and let to various contractors, and the subsequent project milestones and finances are managed through this system. UPS will be absorbed into ACTIVA when ACTIVA is released April 2011 Plant Information (PI) System As provided in

41 SECTION 2 BACKGROUND AND OBJECTIVES 2-23 CYMCAP - Cable Ampacity Calculation Tool CYMCAP is an engineering tool designed to calculate the thermal rating of underground electrical cables under different temperature, loading and environmental conditions. This supports the determination of maximum ratings for feeders in the network. DIgSILENT DIgSILENT is an electrical network simulation tool used for planning, designing and analysing distribution systems. It enables users to create and analyse power system models and diagrams using a graphical interface and obtain output reports that display the results of engineering analysis. Power flow analysis; Short circuit analysis; Motor starting analysis; Protection and co-ordination; Reliability analysis; Capacitor placement optimisation; Tie open point optimisation; Ripple injection modeling. Unison will be developing a data interface between DIgSILENT and GE SmallWorld GIS to improve the source data for network planning and power flow analysis. The basis for the data extracts is our HV schematic network management display in the GIS. SAP Financials and Materials Management SAP is a multi-module Enterprise Resource Planning (ERP) system which provides the following financials and materials management functions: Planning and Budget Management; Capital Expenditure; Operating Expenditure; Costing/Controlling; General Ledger and Sub Ledger Accounting and Reporting; Purchasing and Material Requirements Planning; Inventory Management. Quantate Corporate Risk Management Quantate risk management system enables improved decisions through greater risk awareness, delivers greater business assurance to our stakeholders and creates a process of continuous learning and improvement.

42 2-24 SECTION 2 BACKGROUND AND OBJECTIVES The Vault Health and Safety system The Vault system consolidates a number of Health and Safety requirements. It provides the following functions: Personnel training records; Skills requirements and certification; Job training analysis; Hazard tracking and mitigation; Accident and Near Miss recording and management; Personal protection equipment requirements and tracking; Safety equipment and plant certification and testing records Data Quality Quality of the data used in network development projects is generally of high quality. Where possible, real time data sources are used in modeling and network simulations are based upon recent extracts of WASP and the GIS Data Quality Improvement Initiatives Project Planning The introduction of UPS into the Project Management cycle has introduced a formal workflow process which ensures required processes around data management are maintained. This has improved the timeliness and quality of data required as part of the project lifecycle. Network Design Design Manager allows network design to follow a life cycle from conceptual design to as built. This improves the timeliness of accurate as built information within the GIS, as well as improving the coordination of multiple projects within similar geographic locations. Mobility The Mobile strategy has been developed to put the data maintenance at the source, e.g. Asset Inspections Information passed real time to the back end systems. This strategy is to enable real time capture of improved asset information based on observation and GPS position for geographic information. Data Quality Programme A number of projects have been initiated to evaluate specific data quality issues with the objective of identifying and implementing corrective actions, and ensuring a process is in place to maintain the quality of this information.. This programme includes: 1. Evaluating LV connectivity in Central Region, with field checks and data correction; 2. Redefining Asset Numbering conventions to align across all systems and regions; 3. Reviewing proposed legislation around Road Corridor Management and implementing supporting processes; 4. Reviewing Landbase and GPS systems accuracy.

43 Feedback loop SECTION 2 BACKGROUND AND OBJECTIVES Measuring Network Performance for Disclosure Purposes Process for Measuring and Analysing Network Performance Information Flow Fault Response Service Provider Key Responsibilities Locate fault Identify cause Report back to Control Room Control Room Log all relevant fault data Measure consumer minutes lost I.T. Reporting Systems Extract data from faults database Maintain and audit systems and data quality Network & Operations Analyse fault data Produce reports for stakeholders Provide information for disclosure Figure 2-10: Process for measuring and analysing network performance Systems PI (Plant Information) With the introduction of Smart technologies into the network and smart meters into the household, PI provides analysis and presentation of events occurring in the network or at the household, including last gasp detection. As the rollout of this technology continues, the source data for recording of fault events and asset performance will come direct from the network assets themselves, vastly improving the timeliness and accuracy of network performance statistics and monitoring.

44 2-26 SECTION 2 BACKGROUND AND OBJECTIVES Faults Management System The Faults Management System is a bespoke application developed in-house for the management of consumer, retail and network faults. The system also provides functionality for supporting network switching activities. The complete range of functions is: Logging of retailer action requests; Logging of customer fault calls and issuing of work requests to the internal Service Group or external contractors; Logging of network fault calls and issuing of work requests to the internal Service Group or external contractors; Logging of switching requests to allow efficient programming of the internal Service Group and external contractors action requests; Issuing of switching instruction ID numbers for switching activities; Provision of source data for network performance reporting; Reliability reporting including SAIDI and SAIFI. Call and Dispatch The Call and Dispatch System (TVDs CSC) provides for mobile dispatch, call logging, customer faults tracking, and retailer communications. The functions supported are: Logging of retailer action requests; Logging of customer fault calls and issuing of work requests to the internal Service Group or external contractors; Vehicle location of faults vehicles; Remote logging of faults; Remote logging of action and status changes to fault calls; Customer Service statistics; Automated communication to / from retailers of fault requests and their statuses.

45 SECTION 2 BACKGROUND AND OBJECTIVES 2-27 Figure 2-11: Call & dispatch geographic view Figure 2-12: Call & dispatch detail map view

46 2-28 SECTION 2 BACKGROUND AND OBJECTIVES SCADA System Unison operates a Realflex SCADA system. The SCADA system is used for: Control and monitoring of remote system devices, such as circuit breakers, remote controlled switches, and transformer tap changers and protective devices; Gathering historical analogue and digital data from remote terminal units (RTUs), including energy transported through Grid Exit Points (GXPs); Load control, automatic load shedding, emergency load shedding; Logging of changes to system device states, authorisation to work and information for SAIDI calculations. This system was upgraded to Realflex 6 over IP Data Network Recently Unison has standardised its data network, and has implemented a data network based on the hierarchical internetworking model. The redesigned network combined the multiple networks that were previously implemented for specific purposes in to a single network, with logical separation, rather than physical separation where segregation is required. The redundant Core/Distribution layer ensures that the network is able to provide the uptime demands that services such as SCADA require, and allow the network to be used for other business critical services such as VoIP and VSIP in the future. The standardised network utilises switching hardware from hp Procurve and firewall technologies from Juniper Networks. The Core/Distribution network is connected to over 30 remote sites, including zone substations, branch offices, and other companies utilising services obtained from Airnet NZ Limited, Kordia Limited and Telecom New Zealand Limited. Telephone Communications Telecommunication services are provided to Unison sites typically via a TDM based PBX. Over the upcoming year it is planned to upgrade the TDM based PBXs to a centralised IP PBX. The IP PBX will service the requirements of the Hastings head office, and Hawke s Bay substations (via the IP WAN Links). Server Infrastructure Unison utilises server hardware from HP, and utilises virtualisation technology from VMware. The virtualisation programme will continue into the coming years as servers reach their replacement date, or when adding new servers. Where possible the server will be a virtual guest due to the increase availability, reduced power usage, and overall total cost of ownership that is leveraged from VMware Virtual Infrastructure. Storage Infrastructure The storage area network (SAN) used by Unison is provided by HP. The SAN enables Unison to provide an adaptable storage environment, where the forever increasing storage requirements can be met. Unison has utilised the EVA technology from HP for the past five years, and will be completing a technology refresh on the SAN hardware within the next 12 months. This will provide added redundancy within the storage platform, and upgrade the hardware to current standards.

47 SECTION 2 BACKGROUND AND OBJECTIVES 2-29 Infrastructure Monitoring All aspects of the Unison server, storage and network infrastructure are monitored for exceptions. An on-call engineer is paged in the event of abnormality, and service level agreements are in place with key hardware suppliers and service providers to provide extended support when required Data Quality Unison s Fault Database contains high quality data from 2003 (integration of Hawke s Bay and Central Region Fault Databases). Current fault logging and network performance monitoring processes mean that all data collected is accurate and of high quality. This will improve with the roll-out of the Outage Management System which will add further functionality to the Faults Database Data Quality Improvement Initiatives The Faults database is currently used to provide SAIDI SAIFI statistics. Faults have not always been recorded against assets which can be identified in the GIS Improvements have been made to the Faults database to provide validation against assets to ensure faults are recorded against known assets, and historic faults have been retroactively allocated to the relevant asset where it is known. This is also then integrated with the Asset Management system (ACTIVA) to maintain a history of these events against the asset. In previous AMPs there was reference to the rollout of an Outage Management System. With the advent of new Smart Grid technologies this has been delayed while the systems and vendors implement these new technologies and philosophies into their offerings. To address the higher priority improvements expected to be delivered from the OMS, systems in place which manage switching and faults are being enhanced.

48 section 3 Assets covered Assets covered Sub-transmission circuits form the backbone of Unison s distribution network. Pictured are the two circuits that deliver power to the Tamatea suburb of Napier.

49 SECTION 3 ASSETS COVERED Assets Covered Distribution Area Areas Covered Unison s Large Consumers Load Characteristics for Different Parts of the Network Peak Demand and Total Electricity Delivered Description of Network Assets Hawke s Bay Rotorua Taupo Network Assets Overhead Lines Underground Cables Power Transformers Circuit Breakers Other Substation Equipment and Buildings Distribution Transformers and Voltage Regulators Distribution Switchgear Load Control Plant Miscellaneous Distribution Equipment SCADA Control and Communications Generation Plant Power Factor Correction Equipment and Metering Systems Justification for the Assets High Level Justification ODV Optimisation Sub-transmission Assets Zone Substation Assets kV Distribution Assets Distribution Transformers/Substations Low Voltage SCADA, Communication and Control

50 3-2 SECTION 3 ASSETS COVERED Figure 3-1: Unison electricity distribution coverage area Figure 3-2: Napier sub-transmission network Figure 3-3: Hastings sub-transmission network Figure 3-4: Hawke s Bay region point of supply and 33kV sub-transmission Figure 3-5: Hawke s Bay 11kV distribution system Figure 3-6: Rotorua region point of supply and 33kV sub-transmission Figure 3-7: Rotorua sub-transmission network Figure 3-8: Rotorua 11kV distribution system Figure 3-9: Taupo region point of supply and 33kV sub-transmission Figure 3-10: Taupo sub-transmission network Figure 3-11: Taupo 11kV distribution system Table 3-1: Unison s large consumers Table 3-2: Load characteristics Table 3-3: Peak demand and total electricity delivered Table 3-4: Supply points and embedded generation in the Hawke s Bay region Table 3-5: Zone substation capacity and security level in the Hawke s Bay region Table 3-6: UG portion of 11kV and LV network in the Hawke s Bay region Table 3-7: Supply points and embedded generation in the Rotorua region Table 3-8: Zone substation capacity and security level in the Rotorua region Table 3-9: UG portion of 11kV and LV network in the Rotorua region Table 3-10: Supply points and embedded generation in the Taupo region Table 3-11: Zone substation capacity and security level in the Taupo region Table 3-12: UG portion of 11kV and LV network in the Taupo region Table 3-13: Overhead lines quantities and valuations Table 3-14: Underground cables quantities and valuations Table 3-15: Power transformers quantities and valuations Table 3-16: Zone substations quantities and valuations Table 3-17: Distribution transformers quantities and valuations Table 3-18: Distribution switchgear quantities and valuations Table 3-19: Load control plant quantities and valuations Table 3-20: Miscellaneous distribution equipment quantities and valuations

51 SECTION 3 ASSETS COVERED 3-3 Graph 3-1: Overhead lines Graph 3-2: Wooden poles Graph 3-3: Concrete poles Graph 3-4: Underground cables Graph 3-5: Power transformers Graph 3-6: Zone substation circuit breakers Graph 3-7: Distribution transformers Graph 3-8: Overhead distribution switchgear Graph 3-9: Ring main switches Graph 3-10: Load control plant Graph 3-11: SAIDI Performance Graph 3-12: SAIFI Performance

52 3-4 SECTION 3 ASSETS COVERED 3 Assets Covered 3.1 Distribution Area Areas Covered Unison is 100% owned by the Hawke's Bay Power Consumers' Trust. The Trust was established in 1993, and there are five trustees who are elected for a three-year term. Unison owns, manages and operates distribution networks in the Hawke s Bay, Taupo and Rotorua regions covering an area of 12,181 sq km and serving approximately 108,000 consumers. The coverage area is shown in the map below. Figure 3-1: Unison electricity distribution coverage area Unison s Large Consumers Large consumers are defined as consumers that either have a peak load of over 1 MVA or take supply at high voltage. Eighteen consumers meet this definition across the Unison network. The size of these consumers, and the unique network configurations that are employed to supply them, mean that Unison takes special measures to ensure the appropriateness of maintenance scheduling, and the compatibility of network operations. Furthermore, Unison ensures that these consumers do not have adverse effect on the quality of supply experienced by other consumers on the same feeder by enforcing a compliant power factor of Table 3-1 below identifies Unison s large consumers.

53 SECTION 3 ASSETS COVERED 3-5 Consumer GXP Zone Substation Dedicated Feeder Impact on Network Operations and Asset Management Prioritisation Alto Plastics Fernhill Irongate No The plant is sensitive to feeder faults, auto recloses and surges beyond the connection point. Apollo Pac Whakatu Rangitane No The consumer is located in close proximity to the Rangitane substation. Any planned works will be conducted during off peak periods to minimise interruptions to the business. Enza: Mahora Site Whakatu Mahora Yes Any planned works will be conducted during off peak periods to minimise interruptions to the business. Consumer owns all 11kV cables and switchgear within premises. Enza: Whakatu Site Whakatu Rangitane No Any planned works will be conducted during off peak periods to minimise interruptions to the business. Consumer owns all 11kV cables and switchgear within the premises. Watties: Tomoana Site Whakatu Tomoana Yes The consumer has n-1 security of supply and therefore planned works can be undertaken without interruption of supply. Consumer owns all 11kV cables and switchgear within the premises. Watties: King Street Whakatu Mahora Yes The consumer has n-1 security of supply and therefore planned works can be undertaken without interruption of supply. Consumer owns all 11kV cables and switchgear within the premises. McCain Fernhill McCain Yes Any planned works will be conducted during off peak periods to minimise interruptions to the consumer. Consumer owns all 11kV cables and switchgear within the premises. Port of Napier Whakatu Bluff Hill Yes The consumer takes dedicated supply direct from the Bluff Hill zone substation. Unison owns all the 11kV assets on the site. Maintenance is conducted during off peak periods to minimise interruptions. PPCS Whakatu Rangitane No Maintenance is conducted during off peak periods to minimise interruptions. The 11kV cables within the premises are owned by the consumer. Ravensdown Napier Redclyffe Awatoto Yes The consumer is supplied by a dedicated feeder with onsite generator as backup. The generator is not a reliable backup source as it cannot be guaranteed 100 percent of the time. This is due to the amount of sulphur on site. Any maintenance to the feeder is undertaken after consultation with the consumer to ensure availability of onsite generation. Whakatu Cool Stores Whakatu Rangitane Yes Maintenance is conducted during off peak periods to minimise interruptions. The 11kV cables within the premises are owned by the consumer. Peak Load (MVA)

54 3-6 SECTION 3 ASSETS COVERED Consumer GXP Zone Substation Whakatu Industrial Park Dedicated Feeder Impact on Network Operations and Asset Management Prioritisation Whakatu Rangitane Yes The consumer has n-1 security of supply and therefore planned works can be undertaken without interruption of supply. Consumer owns all 11kV cables and switchgear within the premises. Laminex Wairakei Fletchers Yes Laminex and Tenon are supplied by a dedicated zone substation. The substation has dual 33kV feeders and power transformers. Unison liaises with the consumer to identify suitable times to undertake maintenance works on 11kV assets. Peak Load (MVA) Tenon Whakatu Fletchers Yes Same as Laminex. 3.5 Fonterra Red Stag Timber Ltd Tachikawa Products(NZ) Forest Rotorua 33kV Rotorua 33kV Table 3-1: Unison s large consumers Fernleaf Yes The consumer is supplied by the Fernleaf substation that is connected to the network by a radial 33kV feeder. This means that any planned maintenance on the 33kV feeder or the substation will result in an interruption of supply to the consumer. Where planned maintenance is necessary, Unison consults with the consumer in order to minimise the impact of the interruption. Network faults on the 33kV feeder result in a loss of supply to the consumer. Rotorua 11kV No Any planned works will be conducted during off peak periods to minimise interruptions to the consumer. Consumer has on site generation as back up. However it cannot cater for the whole site s demand. Consumer owns all 11kV cables and switchgear and transformers within the premises. Owhata Owhata No Any planned works will be conducted during off peak periods to minimise interruptions to the business. Unison owns the switchgear, transformers and 11kV cable feeding the customer Load Characteristics for Different Parts of the Network Region GXP/POS Load Characteristics Napier Redclyffe Combination of residential, commercial, industrial and agricultural loads. Majority load: Residential/Commercial Peak: Winter The GXP supplies more urban substations than rural. In recent times, a number of dairy loads and wineries have connected on substation supplied by Redclyffe. This has shrunk the gap between traditional winter peak and summer peak. It is expected there will be increases in power quality issues due to an increase in air conditioning loads across residential and commercial consumers. Hastings Fernhill Combination of residential, commercial, industrial and agricultural loads. Majority load: Residential Peak: Winter although summer loads are near the winter peak Until relatively recently, rural feeders supplied an almost purely agricultural load. This has changed in recent

55 SECTION 3 ASSETS COVERED 3-7 Region GXP/POS Load Characteristics years, largely due to a proliferation of vineyards and wineries and increased population density as farmland is converted into lifestyle blocks. Increased loading and different load profiles are being experienced on these feeders. Moreover, the traditional winter peak scenario is being replaced by summer peaks on some rural feeders due to high demand from irrigation systems. Hastings Whakatu Combination of residential, commercial, industrial and agricultural loads. Majority load: Residential Peak: Winter The winter peak is slightly higher than the summer peak. This is because it supplies urban substations which have winter characteristics. Due to high increases in heat pumps and air condition loads, the summer load requirement has increased recently. This GXP mainly supplies the industrial consumers in the Hawke s Bay whose load profile is constant. Taupo Ohaaki Combination of residential and agricultural loads. Majority is agricultural load. Majority load: Agricultural Peak: Summer In recent times, the forestry has been converted into dairying. This increases the reactive demand on the network, and is likely to contribute towards high harmonics on the network. Taupo Wairakei Combination of residential, commercial, industrial and agricultural loads. High embedded generation (33kV). Majority load: Residential Peak: Winter The summer peak tends to be during the Christmas holiday period due to high number of holiday homes in the Kinloch region and special events such as Taupo A1 GP Motor Racing. There are currently 3 embedded generators injecting at 33kV. The installed capacity of these generators is close to the maximum Taupo demand. Rotorua Atiamuri Combination of residential and agricultural loads. Majority load: Agricultural Peak: Summer Rotorua Owhata Combination of residential, commercial, industrial and agricultural loads. Majority load: Residential Peak: Winter Rotorua Rotorua 11kV Combination of residential, commercial, and industrial loads. Majority load: Industrial and Residential Peak: Winter Rotorua Rotorua 33kV Combination of residential, commercial, industrial and agricultural loads. Majority load: Residential/CBD Peak: Winter This GXP supplies mainly the CBD and Urban areas (Winter Peak) and Rural substations (Summer Peak). There are also high number of baches and holiday homes surrounding the lakes of Rotorua. There is high demand during the holiday periods. Rotorua Tarukenga Combination of residential, industrial and agricultural loads. Majority load: Residential Peak: Winter Table 3-2: Load characteristics

56 3-8 SECTION 3 ASSETS COVERED Peak Demand and Total Electricity Delivered Energy Supplied (GWh) Hawke s Bay 980 Energy Supplied (GWh) Taupo 209 Energy Supplied (GWh) Rotorua 476 Peak Demand (MVA) Hastings (1) 120 Peak Demand (MVA) Napier (1) 69 Peak Demand (MVA) Taupo (1) 23 Peak Demand (MVA) Rotorua (1) 116 (1) Aggregated demand at GXPs and embedded generators and assuming a total power factor of 0.95 Table 3-3: Peak demand and total electricity delivered 3.2 Description of Network Assets Hawke s Bay Supply Points and Embedded Generation The Hawke s Bay region is supplied from a double circuit 220kV tower line from Wairakei to Whirinaki and Redclyffe. From Redclyffe the remainder of the region is supplied by 110kV transmission, connected to the 220kV via two 220/110kV 100 MVA interconnecting transformers. Regional grid generation from the Waikaremoana hydro scheme provides up to 137MW at full output, and during drought conditions may provide limited dynamic voltage support at zero power output. A double circuit 110kV tower line from Redclyffe via Fernhill and Woodville connects to Bunnythorpe, Palmerston North. These circuits are operated split at Fernhill due to poor sharing with the 220kV connection to Wairakei, and can only be used for very limited back-up supply in conjunction with generation from Waikaremoana for a double circuit contingency on the Redclyffe to Wairakei 220kV line. Supply Type 2009/10Peak Demand (MVA) Firm Capacity Winter (MVA) (1) Fernhill 33kV GXP (3) 39 Ravensdown 11kV Embedded Generator Unison Generation Embedded Generator 0 (2) - Redclyffe 33kV GXP 62.7 (3) 43 Whakatu 33kV GXP (2) (3) 81 (1) Winter post contingency (n-1) rating. (2) Unison has 1.2MVA of generation located on a consumer s premises that is capable of operating as an embedded generator, although not operated in this mode during 2009/10. (3) Load can be transferred between these GXPs Table 3-4: Supply points and embedded generation in the Hawke s Bay region

57 SECTION 3 ASSETS COVERED Sub-transmission Network Urban areas in the Hawke s Bay region are supplied by a meshed sub-transmission network and provide a high level of security (n-1). A radial sub-transmission network supplies the rural zone substations (n security). The following diagrams illustrate the network topology, both in schematics and geographical view. Patoka Springfield Tutira Bluff Hill Redclyffe GXP Esk Faraday Street Tamatea Onekawa Marewa Church Road Tannery Road Powdrell Awatoto Whakatu GXP Figure 3-2: Napier sub-transmission network

58 3-10 SECTION 3 ASSETS COVERED Maraekakaho Sherenden Fernhill Fernhill GXP McCain Rangitane Flaxmere Irongate Camberley Whakatu GXP Mahora Tomoana Hastings Windsor Havelock North Arataki Figure 3-3: Hastings sub-transmission network

59 Figure 3-4: Hawke s Bay region point of supply and 33kV sub-transmission SECTION 3 ASSETS COVERED 3-11

60 3-12 SECTION 3 ASSETS COVERED The table below indicates the level of sub-transmission security at each zone substation and installed capacity in the Hawke s Bay region. Zone Substation Supply Voltage Sub-transmission Security Installed Capacity (MVA) Arataki 33kV n Awatoto 33kV n-1 24 Bluff Hill 33kV n 30 Camberley 33kV n Church Road 33kV n Esk 33kV n 10 Faraday Street 33kV n-1 40 Fernhill 33kV n 10 Flaxmere 33kV n-1 20 Hastings 33kV n-1 40 Havelock North 33kV n-1 20 Irongate 33kV n-1 20 Mahora 33kV n-1 30 Maraekakaho 33kV n 1 12 Marewa 33kV n-1 40 McCain 33kV n 20 Patoka 33kV n 3 Rangitane 33kV n-1 48 Sherenden 33kV n 3 Springfield 33kV n-1 15 Tamatea 33kV n-1 15 Tannery Road 33kV n-1 40 Tomoana 33kV n-1 15 Tutira 33kV n 1.3 Windsor 33kV n Table 3-5: Zone substation capacity and security level in the Hawke s Bay region Distribution and Low Voltage Network The sub-transmission network is supported through an 11kV distribution network. The distribution networks in urban areas have a high level of interconnectivity with neighbouring 11kV networks and provide a lot of flexibility during contingency events. This results in a high security of supply in these areas. Rural areas are supplied predominantly by overhead radial feeders with wooden poles. 11kV interconnectivity is limited and supply could be compromised under a single contingency event. The figure below illustrates the extent of Unison s 11kV network in the Hawke s Bay region. 1 A project to install a 12 MVA transformer at Maraekakaho is in progress. 2 We are planning to install a second power transformer at Windsor substation in 2011/12

61 Figure 3-5: Hawke s Bay 11kV distribution system SECTION 3 ASSETS COVERED 3-13

62 3-14 SECTION 3 ASSETS COVERED The LV network in the urban areas has interconnectivity with adjacent distribution transformers. The majority of the CBD and urban LV reticulations tend to be underground. However, the LV network in the rural and remote rural areas is predominately radial, aerial conductors and the transformers are sized to the connection party s requirement unless a sub-division is connected. The following table outlines the portion of the 11kV and LV networks that are underground. Portion of the 11kV Network Underground Hawke s Bay (1) 17% Portion of the Low Voltage Network Underground Hawke s Bay (1) 75% (1) Underground proportion of the total system length for 11kV and LV Networks Table 3-6: UG portion of 11kV and LV network in the Hawke s Bay region Rotorua Supply Points and Embedded Generation Grid supply to Rotorua region originates from Tarukenga substation, which is interconnected to the 220kV grid. The Tarukenga regional 110kV transmission supplies the Unison network from grid exit points at Rotorua and Owhata. The grid supply arrangement to Rotorua GXP is via two 110kV circuits from Tarukenga with a split 110kV busbar at Rotorua. Supply Type 2009/10 Peak Demand (MVA) Firm Capacity (MVA) (1) Atiamuri 11kV Point of Supply Ohaaki 11kV GXP (2) Owhata 11kV GXP 15.3 (4) 12 Rotorua 33kV GXP 49.4 (4) 66 Rotorua 11kV GXP 27.5 (4) 26 Tarukenga 11kV GXP 8.49 (4) 0 (3) Wheao 110kV Embedded Generator (1) Winter post contingency (n-1) rating (2) Single transformer bank supply point, although 11kV back-feed capability exists (3) Single transformer bank supply point (4) Load can be transferred between these GXPs under n-1 contingencies Table 3-7: Supply points and embedded generation in the Rotorua region Sub-transmission Network The Rotorua sub-transmission network consists of double circuits supplying urban substations and radial circuits supplying rural substations. This method of reticulation currently conforms to Unison s security criteria for rural consumers, but does not adequately cater for the several large industrial consumers operating in the rural region. Meeting the needs of these consumers will require significant investment. The following diagrams illustrate the network topology, both in schematics and geographical view.

63 Figure 3-6: Rotorua region point of supply and 33kV sub-transmission SECTION 3 ASSETS COVERED 3-15

64 3-16 SECTION 3 ASSETS COVERED ROTORUA GXP 33kV ROTORUA Arawa Biak Street TARUKENGA OWHATA Rainbow Legend Fernleaf Transpower Site Unison Substations Figure 3-7: Rotorua sub-transmission network The table below indicates the level of sub-transmission security at each zone substations and installed capacity in the Rotorua region. Zone Substation Supply Voltage Sub-transmission Security Installed Capacity (MVA) Arawa 33kV n-1 40 Atiamuri 11kV N/A (1) 2 (2) Biak Street 33kV n-1 40 Fernleaf 33kV n 7.5 Rainbow 33kV n 5 (1) No sub-transmission system, fed directly from Mighty River Power (MRP) generating station (2) Assets are owned by Mighty River Power Table 3-8: Zone substation capacity and security level in the Rotorua region Distribution and Low Voltage Network The distribution networks in urban areas have a high level of interconnectivity with neighbouring 11kV networks and provide a lot of flexibility during contingency events. This results in a high security of supply in these areas. Rural areas are supplied predominantly by overhead radial feeders with wooden poles. 11kV interconnectivity is limited and supply could be compromised under a single contingency event. Overhead to underground projects continue to be initiated by the Rotorua District Council.

65 Figure 3-8: Rotorua 11kV distribution system SECTION 3 ASSETS COVERED 3-17

66 3-18 SECTION 3 ASSETS COVERED The LV network in the Rotorua region is similar to that of the Hawke s Bay where the urban networks have interconnectivity with adjacent distribution transformers. The majority of the CBD and Urban LV reticulations tend to be underground and are run in parallel to avoid non-compliant voltages to consumers. The LV network in the rural and remote rural areas is predominately radial, aerial conductors and the transformers are sized to the connection party s requirement unless a sub-division is connected. The following table outlines the portion of the 11kV and LV networks that are underground. Portion of the 11kV Network Underground Rotorua (1) 11% Portion of the Low Voltage Network Underground Rotorua (1) 50% (1) Underground proportion of the total system length for 11kV and LV Networks Table 3-9: UG portion of 11kV and LV network in the Rotorua region Taupo Supply Points and Embedded Generation The main supply to the Taupo region is presently via two 220/33kV supply transformers at Wairakei GXP, with a significant contribution from the embedded Rotokawa geothermal generation, Contact Tauhara Plant and to a lesser extent the Hinemaiaia hydro generation. Small areas of the region are supplied by 11kV point of supplies from Atiamuri Power Station and Ohaaki Power Station. Supply Type 2009/10/ Peak Demand (MVA) Firm Capacity Winter (MVA) (1) Hinemaiaia 33kV Embedded Generator Rotokawa 33kV Embedded Generator Wairakei 33kV GXP (2) 65 Contact Tauhara Plant 33kV Embedded Generator (1) Winter post contingency (n-1) rating. (2) The Wairakei GXP peak demand assumes embedded generation set at zero. The demand is split between the Wairakei GXP and embedded generation in the Taupo area at Rotokawa and Hinemaiaia. Maximum demand at the GXP will vary from year to year dependent on generation over peak periods. Table 3-10: Supply points and embedded generation in the Taupo region Sub-transmission Network The majority of the Taupo network is supplied via a mesh network. The main exception to this is the Taupo South urban area, which is supplied via a radial circuit. Further investment is currently under way to rectify this. A new zone substation at Fleet Street (phase 1) was commissioned in May The second phase of this project will be to connect Fleet Street and Taupo South via a new sub-transmission circuit. On completion this investment will provide Taupo with a full mesh network. The following diagrams illustrate the network topology, both in schematics and geographical view.

67 Figure 3-9: Taupo region point of supply and 33kV sub-transmission SECTION 3 ASSETS COVERED 3-19

68 3-20 SECTION 3 ASSETS COVERED WAIRAKEI GXP 33kV Tauhara Binary Plant Rotokawa Centennial Drive Switching Station 33kV Fletchers Runanga Fleet Street Taupo South Legend Proposed Circuit Existing Circuit Existing Substation/TP 11kV Hinemaiaia Figure 3-10: Taupo sub-transmission network The table below indicates the level of sub-transmission security at each zone substations and installed capacity in the Taupo region. Zone Substation Supply Voltage Sub-transmission Security Installed Capacity (MVA) Fletchers-1 & 2 33kV n-1 30 Runanga Street 33kV n-1 36 Taupo South 33kV n 30 Fleet St 33kV n 15 Table 3-11: Zone substation capacity and security level in the Taupo region

69 SECTION 3 ASSETS COVERED Distribution and Low Voltage Network The distribution networks in urban areas have limited interconnectivity. Projects to improve the distribution interconnectivity are currently being planned. 11kV interconnectivity is limited and supply could be compromised under a single contingency event. Reticulation is mostly by overhead line with small pockets of underground cable present in the CBD and urban areas of Taupo. Overhead to underground projects continue to be initiated by the respective councils in the Taupo region. Long 11kV feeders supply rural and remote rural consumers on the Taupo network, some of which (approximately 100km) are SWER lines. These feeders offer no security of supply under a single contingency scenario. The LV network in the Taupo region has interconnectivity with adjacent distribution transformers. The majority of the CBD and Urban LV reticulations tend to be underground and are run in parallel to avoid non-compliant voltages to consumers. The LV network in the rural and remote rural areas is predominately radial, aerial conductors and the transformers are sized to the connection party s requirement unless a sub-division is connected. Portion of the 11kV Network Underground Taupo % Portion of the Low Voltage Network Underground Taupo (1) 74% Table 3-12: UG portion of 11kV and LV network in the Taupo region 3 Underground proportion of the total system length for 11kV and LV Networks

70 3-22 SECTION 3 ASSETS COVERED Figure 3-11: Taupo 11kV distribution system

71 SECTION 3 ASSETS COVERED Network Assets Overhead Lines Description of Asset Overhead lines are split into three main categories: 33kV sub-transmission, 11kV Distribution and LV Distribution. The Sub-transmission system is the link between the grid exit points (GXP; also known as points of supply) and the distribution network. Unison s standard sub-transmission voltage is 33kV, which connects to the 11kV distribution networks through zone substations. In the Taupo and Rotorua areas some 11kV lines are fed directly from the Owhata, Atiamuri, Ohaaki and Rotorua GXPs. Quantity Quantity FRS-3 (1) Overhead Lines 31/12/09 31/12/10 31/12/10 (km) (km) RC $(000) DRC $(000) Sub-Transmission ,575 4,537 11kV Distribution 3,784 3,818 70,044 34,518 LV Distribution ,198 13,209 (1) All valuations provided are current as at 31/12/2010 and are based upon the FRS-3 valuation of Unison s assets undertaken by PwC on 31/3/2006, indexed by CPI. Table 3-13: Overhead lines quantities and valuations Age Profile 600 Overhead Lines Kilometres of Line Date of Installation LV Overhead Line 11kV Overhead Line 33kV Overhead Line Graph 3-1: Overhead lines

72 3-24 SECTION 3 ASSETS COVERED Condition The system is generally reliable, and increased levels of maintenance have improved the performance levels. Weather conditions throughout the year have generally been benign and a new prioritised feeder section Vegetation Maintenance strategy, which strategically targets primary sections of feeders, has also impacted favorably on system performance. A significant proportion of Network interruptions to supply continue to be caused outside influences such as vehicle accidents, careless use and operation of mobile plant and machinery near lines, indiscriminate tree felling and vandalism. Generally the lines are well configured across the network and match load requirements. New remote automation installed is positively impacting on response times to faults and is reducing the number of consumers affected by such events. Rotorua poses some engineering challenges with metal fittings and components being adversely affected by the corrosive environment. This applies particularly to ferrous hardware fittings and copper conductors and these regionspecific considerations are being incorporated into Unison s design and construction standards. Concrete poles have performed extremely well and, due to the predominantly off-shore winds in Hawke s Bay, no significant deterioration is suffered from salt sprays. Independent assessment has supported Unison s view that the standard life for these assets of 60 years is conservative for the environmental conditions within Unison s operating regions. Consequently, Unison assumes concrete poles will deliver an economic service life of 80 years. This has led to a reduction in the volume of wooden poles installed on the network, and they are now only used where it is economic to do so (e.g. lighter loads allow use of smaller helicopters). Unison is introducing a new pole testing system known as the Deuar MPT 40 (Mechanical Pole Test,) which will provide the remaining service lives for the existing wood pole population. This system will allow Unison to better utilise the residual life of the wood pole population while still maintaining a high level of confidence in the serviceability. Unison also expects the limited number of steel poles installed in the Hawke s Bay to last beyond 80 years. As with the concrete poles the dry climate, with low levels of airborne pollution means the natural degradation rate of the galvanised protective coating is much slower than that experienced in wetter parts of the country. Some poles are showing signs of corrosion at the foundation interface, but in many cases a remedial coating treatment can be successfully applied to extend the service lives. Some life reduction is applied to poles, copper and steel cored conductors in the geothermal regions due to the corrosive nature of the environment.

73 SECTION 3 ASSETS COVERED 3-25 Wooden Poles Units Date of Installation LV Wooden Pole 11kV Wooden Pole 33kV Wooden Pole Graph 3-2: Wooden poles Concrete Poles Units Date of Installation LV Concrete Pole 11kV Concrete Pole 33kV Concrete Pole Graph 3-3: Concrete poles Underground Cables Description of Asset Underground cables are split into three main categories: sub-transmission, 11kV distribution and LV distribution. The sub-transmission system is the link between the grid exit points (points of supply) and the distribution network. Unison s standard sub-transmission voltage is 33kV, connecting to the 11kV distribution networks at zone substations.

74 3-26 SECTION 3 ASSETS COVERED The distribution system is the link between the sub-transmission system and the consumer point of supply. Voltage levels are 11kV and 400V, with connections to consumer s points of supply at both these voltages but normally 230/400V. Cables are either single core or multi cores. The electrical conductors are either copper or aluminium. The 33kV and 11kV cables are either insulated with oil-impregnated paper, inside a lead sheath (PILC), or insulated with cross-linked polyethylene (XLPE). At the 400V level, the cables are mainly insulated with PVC or XLPE, with some older PILC cables still in service. Quantity Quantity FRS-3 (1) Underground Cables 31/12/09 31/12/10 31/12/10 (km) (km) RC $(000) DRC $(000) Sub-transmission ,957 12,112 11kV distribution ,231 78,444 LV distribution 1,433 1, ,449 69,522 (1) All valuations provided are current as at 31/12/2010 and are based upon the FRS-3 valuation of Unison s assets undertaken by PwC on 31/3/2006, indexed by CPI. Table 3-14: Underground cables quantities and valuations Age Profile 300 Underground Cables Kilometres of Cable Date of Installation LV Underground Cable 11kV Underground Cable 33kV Underground Cable Graph 3-4: Underground cables Condition Mass Impregnated Non Draining (M.I.N.D.) impregnated cables were introduced from the 1960s and have proved to be very reliable and durable to date, with an expected service life of 70 years. Pre 1960s (Non-M.I.N.D.) oil insulated cables are beginning to have increased failure due to reduced insulation values as cables dry out. Overall service life is still expected to achieve 70 years.

75 SECTION 3 ASSETS COVERED 3-27 The 1970s XLPE cable is considered less reliable and Unison is carefully monitoring fault rates on these assets. Regions where these assets have been installed in wet environments are experiencing failure rates that are no longer acceptable and significant investment has been allocated to renew these assets. Consequently assets of this type installed in areas identified as high risk have had their standard life reduced from 45 to 30 years. Improvements in manufacturing of XLPE means cables installed after the 1970s are in better condition and should continue to give reliable service for 45 years of operation. 33kV cables (all types) have performed well within the Unison network to date. LV cables have proved very reliable despite increasing age and most failures are currently due to excavation works, jointing failures environmental or overloading. The standard life of 45 years is assumed for asset investment modeling. All non-lead sheathed cables with copper conductors installed in the geothermal regions in Taupo and Rotorua have had their service life estimates reduced by five years due to the corrosive nature of the hydrogen sulphide on copper. Aluminium conductors do not react to the same extent as copper so no life reduction is expected. Unison will now only install AL XLPE cables with tinned copper wire screen within this region to ensure full asset life from new cables Power Transformers Description of Asset Power transformers are used at zone substations to transform the 33kV sub-transmission voltage to a lower distribution voltage suitable for the network. These transformers typically convert 33kV to 11kV and are rated at between 1MVA and 30MVA. With the exception of Rainbow substation, all transformers are three phase units. Substation power transformers have fitted an automatic on load tap changer to keep the output voltage within defined limits. The tap changers operate in a separate oil filled compartment in the transformer. As the tap changer operates to keep the output voltage constant the contacts arc in the oil and therefore the oil and the contacts require frequent maintenance. New transformers are supplied with tap changers that have the contacts operating in a vacuum bottle making these tap changers virtually maintenance free. Four small power transformers of less than 3MVA located at rural substations are fixed tap type and have a separate 11kV voltage regulator to provide voltage control. All Unison s power transformers are filled with mineral insulation oil that provides insulation and cooling. Transformer cooling is enhanced by cooling fans fitted to radiators and some transformers also have oil pumps to more effectively circulate the oil to increase the emergency load rating. On-line temperature monitoring is now being installed on critical transformers to enable more effective overload control as part of the smart network initiative.

76 3-28 SECTION 3 ASSETS COVERED Power Transformers Quantity 31/12/09 Quantity 31/12/10 FRS-3 (1) 31/12/10 RC $(000) DRC $(000) Standard Life (45 yrs) 2 2 1,765 1,041 Extended Life (60yrs) ,508 17,499 Voltage Regulators (1) All valuations provided are current as at 31/12/2010 and are based upon the FRS-3 valuation of Unison s assets undertaken by PwC on 31/3/2006, indexed by CPI. Table 3-15: Power transformers quantities and valuations Age Profile Power Transformers Units Date of Installation Power Transformers Graph 3-5: Power transformers Condition The overall condition of the power transformers is as expected for their age. Good monitoring and maintenance as well as effective management practices over the years have ensured the assets have not been overloaded and this has led to reliable performance overall. Consequently Unison assumes its power transformers will operate for an economic service life of 60 years. An exception is the two transformers at the Arawa substation in Rotorua. These transformers are now 19 years old and are sited within the thermal area of the city. The atmosphere is very corrosive and is attacking paint and steel work, as well as the associated cabinets of both transformers. These assets are only expected to achieve a service life of 45 years. The tap changers are generally all in good condition.

77 SECTION 3 ASSETS COVERED Circuit Breakers Description of Asset Circuit breakers (CBs) are used at zone substations to interrupt electrical power circuits. They are able to interrupt power by an initiated control command or automatically by sensing devices when a fault or abnormal situation occurs. They can interrupt these circuits repeatedly and safely both under normal load and fault conditions. Circuit breakers are manufactured using several types of insulation medium. Older types use a tank filled with mineral insulation oil that houses the main interrupting contacts. The mineral oil acts as an insulation medium and also to extinguish any arc generated by the opening of the main current carrying contacts. This process generates a considerable amount of carbon and by-products from the degradation of the contacts in the oil. These circuit breakers require regular intensive maintenance particularly for contact condition assessment, and oil filtering to prevent insulation failure. Oil circuit breakers are no longer purchased. Modern circuit breakers are designed with contacts opening in either a vacuum or within a chamber filled with sulphur hexafluoride gas (SF 6 ).The vacuum type of circuit breaker has the main interrupting contacts contained within a sealed vacuum bottle which is then insulated in either a tank of mineral insulation oil, or in a tank of SF 6 gas, or moulded into epoxy resin housing. SF 6 circuit breakers use the gas as an insulation medium and for arc extinction. The gas is contained in a sealed chamber, usually at slightly above atmospheric pressure, and is normally sealed for life. During current interruption the gas decomposes and then recombines ready for the next operation. Arc extinction within these types of circuit breakers is very efficient and causes minimal contact degradation. ZS Switchgear Quantity 31/12/09 Quantity 31/12/10 FRS-3 (1) 31/12/10 RC $(000) DRC $(000) 33kV Indoor CB , kV Outdoor CB ,172 1,790 11kV Indoor CB ,697 4,216 11kV Outdoor CB (1) All valuations provided are current as at 31/12/2010 and are based upon the FRS-3 valuation of Unison s assets undertaken by PwC on 31/3/2006, indexed by CPI. Table 3-16: Zone substations quantities and valuations

78 3-30 SECTION 3 ASSETS COVERED Age Profile Zone Substation Circuit Breakers Units Date of Installation 33kV Circuit Breakers 11kV Circuit Breakers Graph 3-6: Zone substation circuit breakers Condition The general condition of the circuit breaker assets is as expected for their age and Unison has experienced few failures. Deterioration shows mainly as contact wear and mechanical wear on mechanisms. Outdoor equipment is subject to normal environmental deterioration. Circuit breakers have been identified in the ODV Handbook as having an operational life of 45 years and life extension to 55 years for modern indoor sealed types (SF 6 or vacuum). Unison supports this as a reasonable estimate of service life for these assets Other Substation Equipment and Buildings Description of Asset This section of the AMP covers all assets located in substations, other than the major components of transformers and circuit breakers. Instrument Transformers Instrument transformers are generally of two types: Voltage Transformers (VT) and Current Transformers (CT). Voltage transformers are used to transform high voltages to lower voltages that can be more safely used for indication, metering and protection. VTs may be located on outdoor or indoor equipment and be either a single phase unit or a three phase unit. Current transformers are used to transform high currents to lower levels that can be used for control, indication, metering and protection. Outdoor CTs are generally stand alone, single phase, oil insulated units and usually form part of a circuit breaker. Indoor CTs are generally single phase, solid insulation and located on each phase of a circuit breaker.

79 SECTION 3 ASSETS COVERED 3-31 DC Systems DC systems at zone substations are used to provide an independent stand-alone power supply that can function if the main AC power fails. The general arrangement is to have battery banks on continuous charge connected to critical equipment for control and indication. Battery bank voltages used are 110, 50, 24 and 12 volt banks of mainly 12 volt batteries. Protection Equipment Protection equipment is used to detect faults on the electrical network, and to selectively operate circuit breakers so as to isolate the faulted section of the network with adequate speed and sensitivity to minimise personal injury or equipment damage. Generally each circuit breaker has its own protection scheme to provide the appropriate and required type of protection. Schemes are generally designed to detect over-current, earth faults, power differential, power direction, under and over voltage and to provide other miscellaneous protection such as detecting transformer oil surges and other equipment monitoring. All protection relays indicate back to the Control Centre if they have operated by sending an alarm and indications on the status of the equipment being monitored. Substation Oil Containment Systems Unison s has an environmental policy committed to protect the environment and oil filled equipment is regularly monitored for oil leaks. New substations are designed to include a transformer oil containment system and containment systems are progressively being installed at old substations. Buildings Buildings house indoor switchgear and in some cases power transformers, control and protection equipment, SCADA, RTU and communications systems. As part of the Smart Network initiative security is to be improved at all substations. Access into substations is to be upgraded with card readers only allowing authorised persons to enter and this will be recorded in the station RTU and a new Registered Key is to be introduced. A surveillance camera now operates at the Fernhill and Tamatea substations and monitors unuthorised entry and possible vandalism. Outdoor Structures These consist of overhead support structures and conductive busbars of either copper or aluminium that allows switchgear and power transformers to be connected together. These are designed to provide isolations and safe distances for maintenance works and operations. Zone Substation Earths Because of the high voltages and currents encountered in zone substations, earthing systems are designed in detail at the time of construction to ensure safety to personnel and equipment. They generally comprise bare copper cables laid in the ground in a grid formation and connected to deep driven earth rods. All station equipment is bonded to it. Arawa substation in Rotorua is located in an area of high geothermal activity and has an aluminium earth grid to provide better

80 3-32 SECTION 3 ASSETS COVERED corrosion resistance than that of copper in the presence of gases in this area. Substation earth grids are inspected and tested periodically. Conductor sizes have to be able to carry the full fault currents likely to be experienced, and the layout is to ensure that step and touch voltages are within acceptable limits as described in the Electrical Code of Practice Age Profile Since this asset category consists of a large number of component systems, an indication of the overall age of the equipment is best represented by the commissioning dates of each zone substation site (refer to Section 3.3.6) Condition General condition of these assets is good, but this is driven by an extensive and frequent condition monitoring programme and any deterioration of equipment is mitigated when found to ensure in-service failure does not occur. With a number of the substations built in the s, the level of maintenance and renewal of the assets is expected to steadily rise as the number of assets reaching end of economic life increases. Standard service lives for these assets are assumed, with the exception of concrete (block or pre-cast) buildings. Extension from 50 to 100 years for these assets has been supported by independent assessment after considering current condition, age, construction styles and environmental conditions Distribution Transformers and Voltage Regulators Description of Asset Distribution transformers are used to convert the distribution voltage to a lower voltage level of 415/230 volts suitable for use by the consumer. These transformers are located throughout the whole network and are either pole or ground mounted. In most cases distribution transformers are connected to the 11kV distribution feeders, but in remote areas where loads are of very low density, conversion from 33kV directly to 415/230 volts is performed where distribution circuits are not available or economic to construct. Transformer size is determined by the consumers connected load and may range from small pole mounted 5kVA single phase transformers up to large ground mounted 2000kVA three phase transformers. The majority of Unison s ground mounted substations are on concrete pads, although some transformers are located on consumer s premises and in some cases within buildings owned by third parties. There are a limited number of pole mount transformers in Central Region that have been adapted to a ground mount environment housed in boxed concrete enclosures. Similarly there are a small number of ground mount transformers in the Hawke s Bay Region enclosed in fiberglass covers. Pole mounted substations are typically secured to wooden or steel support arms attached to poles, but a number of poleand-a-half structures are also used to support the weight of larger transformers. A limited number of two-pole structures exist in the network and are used for larger transformers, although these are no longer part of current design practice.

81 SECTION 3 ASSETS COVERED 3-33 Voltage regulators (11kV/11kV) are used for voltage control on some long or heavily loaded 11kV feeder lines to boost or buck the voltage. Distribution Transformers Quantity 31/12/09 Quantity 31/12/10 FRS-3 (1) 31/12/10 RC $(000) DRC $(000) Voltage Regulators ,475 2,066 Distribution Transformers 9, ,363 63,868 Distribution Substations 9, ,811 14,995 (1) All valuations provided are current as at 31/12/2010 and are based upon the FRS-3 valuation of Unison s assets undertaken by PwC on 31/3/2006, indexed by CPI. Table 3-17: Distribution transformers quantities and valuations Age Profile Distribution Transformers Units Date of Installation Ground Mounted Distribution Transformer Pole Mounted Distribution Transformer Graph 3-7: Distribution transformers Condition Ground mount transformers are in a satisfactory condition overall. A number of assets are replaced each year as a result of condition monitoring reports indicating the general condition of the transformer has deteriorated to a point where maintenance is no longer economic. Distribution transformers are simple and robust and deliver a very high level of service reliability and availability. Overall Unison has extended the assumed life in the ODV handbook from 45 years to 50 years based on analysis of failure rates. Assets located in the geothermal regions are only expected to operate economically for 40 years due to accelerated corrosion. Voltage regulators are of modern design and in good service condition.

82 3-34 SECTION 3 ASSETS COVERED Distribution Switchgear Description of Asset Distribution switchgear includes all the electrical switching equipment in the HV network. They are used for isolating and connecting sections of the network for operational requirements. The main types of switchgear used are described below. Disconnectors Disconnectors or Air Break Switches (ABS) are used as a means to connect or disconnect different sections of 11kV or 33kV overhead lines. All three phases of the switch are mechanically linked so that they operate together. Early model ABS switches were primarily intended for no-load switching, but modern switches have flicker arc horns and/or load break attachments to allow some load switching. ABSs throughout Unison s networks are operated manually. Single phase HV links are also used in the overhead network to provide isolation points at specific locations. These are manually operated with a Hot Stick. Ring Main Switches (RMS) The RMS is an 11kV ground mounted switch used in the underground network to provide a similar function to an ABS. Generally a RMS comprises one, two or three, three phase switches. They are designed to mechanically operate all three phases simultaneously. Magnefix units perform the same function but each phase of each switch has to be operated separately. Most RMS switch contacts are immersed in insulating oil which assists with arc suppression on opening. With new technology manufacturers are now using SF 6 and vacuum insulation for arc control moulded into solid plastic resin housings. RMS units are available in several combinations, the most common being a fused switch with two isolators fed from a common busbar. The fuse switch is used to provide overload and circuit protection for a transformer or circuit. The two isolators are used to provide switching availability from different sources. The whole arrangement is then mounted in a common tank assembly. There are a number of Magnefix switch units installed in the Hawke s Bay network area. These are three phase units that are operated by installing or removing single phase links for circuit isolation. They are manufactured from cast resin insulation material and comprise a number of combinations of switch circuits and fuse units. These units can only be operated single phase and have a limited fault rating. A new Safe link switch with SF 6 insulation medium has been approved which will facilitate replacement of existing switches. In all cases each switch is identified separately with a unique number for operational requirements. Remote Controlled Switches (RCS) Remote Controlled Switches are used to reduce outage times and improve network performance. These are installed on the overhead network at strategic locations and provide remote switching ability to enhance network operations.

83 SECTION 3 ASSETS COVERED 3-35 Unison has until recently used single-phase vacuum-insulated switches that are electrically linked to operate simultaneously across all phases. New three unitised vacuum insulated RCSs have now become available and these are progressively being installed. In some instances these will replace key Air Break Switches where this is seen to fit with planned Smart Network projects. A VHF radio provides the communication link to operate these switches remotely. Reclosers / Sectionalisers Reclosers are installed in the overhead network distribution lines to automatically isolate and restore supply to sections of line after transient faults. They are circuit breakers that are able to interrupt a fault current when set criteria are met. When the circuit breaker trips open it will re-close a predetermined number of times until it locks out and remains open, or if the fault has cleared it will remain closed. Most of these devices reset automatically, but a few old models are still required to be manually reset after operation. Sectionalisers are similar to reclosers in operation but are not able to interrupt fault current. If a fault occurs in the spur line sectionalisers sense this fault as it passes through and will open during the time when the recloser has opened to clear the fault. These devises are usually manually reset once the feeder section controlled by the device has been patrolled and any fault beyond the device has been repaired or isolated. In the Taupo area a Single Wire Earth Return (SWER) 11kV overhead network is used in remote areas. This requires a single phase circuit breaker to protect the SWER circuit from overload. These circuit breakers are manually controlled. Distribution Switchgear Quantity 31/12/09 Quantity 31/12/10 FRS-3 (1) 31/12/10 RC $(000) DRC $(000) Disconnectors 2,139 2,150 15,693 7,850 Dropout Fuses 8,156 8,215 23,949 7,868 Recloser/Sectionaliser ,472 3,292 RMS 3 way ,578 13,231 Extra Oil/Fuse Switch ,591 3,193 Remote Actuators (1) All valuations provided are current as at 31/12/2010 and are based upon the FRS-3 valuation of Unison s assets undertaken by PwC on 31/3/2006, indexed by CPI. Table 3-18: Distribution switchgear quantities and valuations

84 3-36 SECTION 3 ASSETS COVERED Age Profile Overhead Distribution Switchgear Units Date of Installation ABS Fuse Recloser/Sectionaliser Graph 3-8: Overhead distribution switchgear Ring Main Switches Units Date of Installation Extra Fuse/Oil Switch 3 Way Graph 3-9: Ring main switches Condition The general condition of these assets varies considerably and is as expected for their age. Outdoor equipment is subject to normal environmental deterioration. Deterioration is more rapid and invasive in geothermal areas. ABSs receive little maintenance and perform reliably when required. Overall condition of these assets is good however in service failure rates appear to be increasing particularly in the central region due to corrosion. Unison intends to progressively replace many of the key ABSs throughout its networks with new unitised vacuum insulated RCSs which have remote operation capability and fit with the Smart Network requirements.

85 SECTION 3 ASSETS COVERED 3-37 There are however, a large number of assets in the network functioning well beyond their normal expected operating life. Consequently, based on the performance of the existing population, Unison has increased its expected service life from the ODV handbook assumption of 35 to 45 years. The general condition of RMS assets is commensurate with their age and they are generally reliable. The tanks are subject to normal environmental deterioration. Some older RMS units have an operational restriction for safety reasons. These switches are being progressively replaced. Unison has suffered a number of failures in recent years on oil RMS units and is monitoring the situation. Analysis of most of the failures has not indicated fault of the asset itself, but indications are that workmanship and the use of incompatible equipment for terminations are prime causes. Some Magnefix units have failed in the past year, but this type of switch is progressively being replaced. Reclosers, remote controlled switches and sectionalisers are all generally in good condition, and standard service lives as per the ODV handbook are considered reasonable Load Control Plant Description of Asset Load Control Plant is used within the network to provide various equipment control functions. Unison has ripple injection systems in its various regions, and in Hawke s Bay there is also a pilot control system. Ripple Plant Ripple Plant is designed so that a high frequency signal is superimposed into the high voltage network that can be received by specially tuned relays in the low voltage network to provide particular control activities. Equipment controlled by this system includes hot water controls, street, security and under-verandah light control, some remaining night store heating control, and some line recloser circuit breaker controls. The plant consists of a 400 volt frequency generator that is either rotary or solid state equipment, high voltage coupling equipment consisting of voltage transformers and capacitors to tune and inject the frequency signal into the network, and control and signal equipment that provides the controls and functions for the signals. Based on historical performance of ripple plant and Unison s practice of holding appropriate spares to manage technical obsolescence, the standard ODV service life of 20 years has been increased to 30 years. Ripple plants will be phased out over the next few years due to the introduction of smart metering technology. The Cyclo plant in Napier has now been removed. Pilot Wire The total length of hot water hard wire control (which has several different types) is about 1300km, nearly all of which is in Hawke s Bay urban areas. These comprise cascading load bearing conductors and H-wire AC/DC pilot cascading system (frequently associated with an R-wire confirmed operation signalling system). Some of the wired systems are initiated from ripple relays but in most instances initiation is from zone substations or the control room. The system has an advantage of providing a fast

86 3-38 SECTION 3 ASSETS COVERED response to signals and enables a number of smaller blocks of load to be controlled which is advantageous in load restoration. Load Control Plant Quantity 31/12/09 Quantity 31/12/10 FRS-3 (1) 31/12/10 RC $(000) DRC $(000) Load Control Plant ,437 1,747 (1) All valuations provided are current as at 31/12/2010 and are based upon the FRS-3 valuation of Unison s assets undertaken by PwC on 31/3/2006, indexed by CPI. Table 3-19: Load control plant quantities and valuations Age Profile Load Control Plant Units Date of Installation Load Control Plant Graph 3-10: Load control plant Condition The poorest condition plants in Taupo were replaced in 2005, with remaining equipment generally now in good condition. The three rotary plants at Malfroy Road, Arawa and Owhata all in Rotorua are nearing end of life and need to be considered for replacement with modern solid state plant. Due to the intended installation of smart meters, ripple plants will be phased out over the next few years. The plant at Atiamuri failed during the year and has been removed Miscellaneous Distribution Equipment Description Distribution Fuse Units 11kV fuse sets are pole mounted, with some also installed within substations. Some of these fuses are used to control or protect lightly loaded spur lines or 11kV service mains. Unison has also trialed the use of autolinks.

87 SECTION 3 ASSETS COVERED 3-39 Consumer Connections Pedestals are manufactured in various sizes and configuration to suit local requirements. They contain fused LV connections for the network connection point (NCP) between the network and the consumer. They are manufactured from metal, plastic or fibreglass and are fitted out with various size fuses as required. Council and some privately owned street lights are also connected to Unison s low voltage streetlight circuits. Link Pillars Link Pillars house connection and isolation points between low voltage circuits. These are used to provide alternate supply configurations to minimise consumer disruption when faults occur or maintenance of assets is required. Streetlight/Hot Water Circuits Unison has separate LV circuits, both overhead and underground to provide supply for streetlights. These circuits have controls to turn on and off at appropriate times during the day and night. Some consumers have their hot water supplies managed by hard-wired load control circuits. This system is still operational in the Hawke s Bay region, but all future installations will be managed via ripple controls. Streetlight/Hot Water Switches Unison owns a number of relays that control the operation of these services. A number of control systems also allow initiation of control from ripple signals to operate areas of existing hard-wired control systems. Miscellaneous Distribution Equipment Quantity 31/12/09 Quantity 31/12/10 FRS-3 (1) 31/12/10 RC $(000) DRC $(000) Streetlight Cables 1,223 1,234 39,230 16,827 Streetlight Lines ,610 2,034 Link Pillars 2,173 2,184 6,732 2,706 Hot water Lines , Hotwater Cables , Hotwater Switch 2,803 2, Streetlight Switch 1,497 1, Consumer Connection OH 36,849 36,675 3,459 1,388 Consumer Connection UG 68,885 70,029 23,225 10,669 Consumer Connection Light 23,945 24,171 1, (1) All valuations provided are current as at 31/12/2010 and are based upon the FRS-3 valuation of Unison s assets undertaken by PwC on 31/3/2006, indexed by CPI. Table 3-20: Miscellaneous distribution equipment quantities and valuations Age Profile These assets have generally been installed at the same time as the LV reticulation, so age profiles are comparable with those presented above for LV lines and cables.

88 3-40 SECTION 3 ASSETS COVERED Condition Fuses are expected to operate for the life of the asset they are protecting. It is not considered economic to perform condition assessment on these assets so fuses which fail are replaced immediately. Streetlight and hot water lines are all in serviceable condition. In some areas, hot water cabling systems have reached the end of their economic life and are progressively being abandoned and replaced with ripple control systems. Standard service lives for these assets are considered reasonable as per the ODV handbook SCADA Control and Communications Description of Asset Supervisory Control and Data Acquisition (SCADA) is a generic term that covers the system that Unison uses to monitor and control network operations, obtain system information, and create historical records of events. The assets employed for this purpose, in summary, comprise a RealFlex computer application which has a mimic of the system in its database. This is the primary means of sending signals for switch control and other information to field equipment and zone substations. Signals are transmitted through the communications links to Remote Terminal Units (RTUs) located at the substation or field equipment. The RTUs provide the communication interface that allows for central control commands to be conveyed to appropriate plant and for data to be returned. A new Fibre network is being installed in the Hawke s Bay area and will connect to all zone substations. This will enable complex protection and communications schemes to operate between sites. The communication systems used by Unison for network control include: UHF telemetry links; VHF radio links; Fibre Network; Copper Telcon cables; Leased IP links; Fibre links; Meshed radio links; GPRS links. Unison has a strategy for SCADA and communication infrastructure. This includes an extensive programme for replacement and upgrade of RTU s and communication links. More specific comment on each of these follows: SCADA The SCADA system is extensively used by Unison for control, monitoring and events reporting and forms the heart of Unison's network operations. The hardware is individual PCs with Realflex software on each machine. There are two separate systems for Hawke s Bay and Taupo/Rotorua. Communication to the RTUs is generally by IP networks in Hawke s Bay with four remote rural zone substations using the VHF radio network, while in Rotorua/Taupo the predominant medium is leased IP communication network.

89 SECTION 3 ASSETS COVERED 3-41 Communication Cables Four Hawke s Bay zone substations are connected to the SCADA Realflex system in the Unison Control Centre via a network of telcon cables, twentyone by leased or Unison owned IP and four by VHF links. The telcon cables are both buried and overhead and have been in service for a considerable number of years. The following systems use the network of telcon and fibre cables: Control of three ripple plants; SCADA control of substation equipment; Hot water control of pilots; Inter tripping protection systems; Telephones. The leased IP network to Taupo/Rotorua provides the communication backbone for all operational control systems. The link is utilised for VHF radio (VoIP), SCADA and ripple control. Remote Terminal Units With the establishment of a new IP network all remaining RTUs will be changed to new Ethernet RTUs with expected completion December Unison is progressively replacing these old RTU s with SERK RTUs. UHF Links Unison has in Hawke s Bay three UHF links used for the transmission of data from the GXPs at Fernhill, Redclyffe and Whakatu direct to the central control centre in Omahu Road, Hastings. The equipment is now more than 20 years old and will be removed from service during VHF Links VHF is used for the transmission of voice between the control centre and the field operatives. Unison leases the links from Team Talk and uses four different channels and three different repeaters in Hawke s Bay; two channels in the Rotorua region (also leased from Team Talk), with a Unison owned VHF site at Whakaroa providing voice and data for the Taupo area. Automation of field equipment has led to an increase in the number of channels utilised in the last year with five dedicated to communication with one hundred and forty six remote controlled switches and five regulators. Mesh Radio This is a technology currently that has been trialed by Unison. It has a unique system that ensures resiliency in the communication network. Unison will use this extensively as the primary communication medium for switch control and data acquisition.

90 3-42 SECTION 3 ASSETS COVERED GPRS GPRS (General Packet Radio Service) is a communication system which utilises high bandwidth cell phone network. Unison uses this for communicating with fault passage indicators Age Profile The nature of these assets renders a combined age profile inappropriate. The comments made above indicate the age of various parts Condition Regular preventive maintenance has provided reliable operation to date. Whilst the condition of the component parts is reliable it is recognised that the probability of failure of some parts has become unacceptable. Consequently major renewal projects are currently in place to replace existing RTU and communication systems in the network on a prioritised basis Generation Plant Unison owns a number of fixed and mobile generators which are predominately used to minimise disruption to consumers, either by providing an alternative supply boost during maintenance activities on network assets, or as a temporary supply following failure of network assets. Two mobile 500kVA generator units are capable of supporting existing LV supplies or synchronising into the 11kV system with the aid of a transformer to boost distribution supplies. A number of smaller (100kVA, 46kVa, 2kVA) units are also used to provide temporary LV supply as and when needed. Unison also owns 3 x 400kVA generators installed at a key consumer site to maintain supply security. These assets are capable of operating as embedded generation if required Power Factor Correction Equipment and Metering Systems Unison has three power factor correction units connected on the Mangatahi, Royshill and Twyford 11kV feeders. Unison does not currently own or provide metering services for consumers. 3.4 Justification for the Assets Justification of the assets is considered at a high level before focussing on asset specific justification High Level Justification For Unison, justification for the assets employed has three key limbs: Minimisation of lifecycle asset management costs Unison aims to deliver a service to its consumers at an affordable price, as it is clear from customer engagement that price is the predominant concern of the consumer. A key way in which Unison can manage its price is by ensuring that its asset investment decisions minimise lifecycle asset management costs. To achieve this goal, Unison employs a number of decision support tools that guide investment. These tools are detailed in Section 2.6 of the AMP.

91 SECTION 3 ASSETS COVERED 3-43 The exercise of cost minimisation is most difficult in the case of system growth. System growth investments are typically triggered by a shortfall in system capacity or a strong indication that a significant new load will soon require connection. To minimise lifecycle costs it is generally not sufficient to simply install sufficient capacity to cater for the immediate shortfall, rather the network must be future proofed to cater for further growth during the planning period. Although this means that in the period directly following the investment the assets are under utilised, the costly exercise of rebuilding lines and cables or establishing new zone substations need not be repeated until the next planning period (barring unforeseeable load growth). Unison s load forecasting philosophy, techniques and findings are discussed in Section 5 of the AMP. The Smart Grid initiative will provide Unison with an expanded toolbox of non-network solutions to minimise lifecycle asset management costs. Examples of this include capacitor banks that can defer system growth investment and fast protection that will provide enhanced protection of zone substation assets under fault conditions. The benefit of these solutions (in financial terms) is the expenditure that they obviate Delivery of a quality of supply commensurate with consumer expectations The approach of minimising lifecycle asset management costs is tempered by the requirement that assets provide consumers with the quality of supply they can reasonably expect. Section 4 discusses in detail the ways in which consumer expectations are understood and integrated into Unison s planning processes. High level indicators such as SAIDI, SAIFI and Unison s consumer service level targets validate Unison s investment in reliability projects and system security. Commercial arrangements that Unison has with particularly sensitive customers justify investment in additional security in certain areas of the network. Over the last 5 years, Unison has invested in network automation to isolate faulted sections, limit the impact of network outages and ultimately improve the customer experience through improved network performance. The improving SAIDI and SAIFI performance of the network further justify the assets and validate the investment that is being made. The following graphs illustrate the improvement this investment has had in the SAIDI and SAIFI performance over the last 5 years.

92 3-44 SECTION 3 ASSETS COVERED SAIDI Performance SAIDI (minutes) / / / / /10 Graph 3-11: SAIDI Performance SAIFI Performance SAIFI (interruptions) / / / / /10 Graph 3-12: SAIFI Performance Compliance with Unison Standards and all applicable legislation Unison s standards support our objectives of minimising costs subject to an appropriate quality of supply, but also ensure compliance of the asset base with all applicable legislation. External reviews of Unison s network health and safety, environmental and asset management outcomes validate the fact that Unison s standards achieve this objective. In turn, the compliance of the asset base with Unison s standards provides strong justification for the assets.

93 SECTION 3 ASSETS COVERED ODV Optimisation The Commerce Commission s ODV Handbook required a series of optimisation tests to be systematically applied to the whole network to identify stranded assets, excess capacity and over engineering. These tests could also be considered as a basis for justifying assets in the network. The net result of applying these tests was an optimisation of 1% of the asset base in2004, and the network has not changed significantly since then. Unison believes that stranded, over-engineered or assets with excess capacity do not represent a material value in its networks Sub-transmission Assets Unison s sub-transmission assets are operated at 33kV and comprise of an inter-connected network of lines and cables including switches and protection devices. This network is used to transfer power from Transpower s Grid Exit Points (GXPs) and other points of supply to Unison s zone substations. The choice of voltage was made taking into consideration transmission distance, load to be serviced, electrical losses, ease and cost of construction. As the sub transmission circuits supply large consumers, careful consideration has been given to route selection, network configuration arrangements, network reticulation and capacity. Urban supply areas have dual feeder configuration to comply with the security criteria. Some of the urban circuits are undergrounded. Due to poor soil conditions in the Taupo and Rotorua regions, a number of circuits are configured as multi-circuits (2 per phase) for capacity and security requirements. These circuits are designed for existing and forecasted loads well into the next planning period (20+ years). There are varying states of security throughout the network. The cost of aligning standards, however, is high. As a result, as assets are replaced or new assets are added to the network, the new assets are designed to comply with the present standard specifications Zone Substation Assets Zone substations are strategically located at load centers and at larger point loads such as major customer connections. They usually contain indoor 11kV circuit breakers, and load control plants. Unison uses the load control plants to primarily ensure that transmission interconnection costs at Transpower s GXP are minimised and that zone transformers and part of the distribution systems are not overloaded during peak load conditions. Due to lack of capacity in number of 11kV feeders, load control plays a vital role in deferring capital expenditure. Unison recognises that at times, there will be over-capacity network components. However, this is mitigated through careful planning and design. 11kV distribution feeders then radiate from the zone substation to supply distribution and consumers in a mesh or radial configuration kV Distribution Assets The 11kV assets form an extensive distribution network that is used by Unison to distribute electricity to 400V distribution substations. The choice of 11kV voltage is mainly historical and is found to be satisfactory for present technical requirements. The feeders have a high level of interconnectivity to enhance supply reliability. This is particularly true in the urban supply areas. Other voltage levels may be evaluated in the future if 11kV is no longer capable of providing the services required. Some larger consumers are supplied directly from the 11kV distribution network. Recently, Unison has deployed a number of automated switchgear to enhance the reliability for the rural consumers.

94 3-46 SECTION 3 ASSETS COVERED Distribution Transformers/Substations Distribution substations transform 11kV distribution voltage to 400/230V, which is the supply voltage for the majority of end use consumers Low Voltage Low voltage assets comprise lines and cable including associated switchgear operated at 400/230V and these are used to connect end use consumers points of connection to distribution substations SCADA, Communication and Control Unison operates a control centre that is attended 24 hours a day, 365 days a year. Unison utilises its SCADA, communication and control systems to enhance the level of reliability, safety and consumer services it provides.

95 section 4 service levels service levels Unison has installed its first Ground Fault Neutraliser (GFN) at Irongate Zone Substation. This asset improves quality of supply by eliminating outages caused by single phase earth faults. This photo was taken of the Irongate GFN control panel.

96 SECTION 4 SERVICE LEVELS Service Levels Purpose of Service Levels Service Level Planning and Development Consumer Oriented Service Levels Reliability Indices (SAIDI and SAIFI) FAIDI and FAIFI Consumer Service Level Targets Poorest Performing Feeders Asset and Business Efficiency Service Levels Business Efficiency Targets Asset Efficiency Targets Justification for Target Levels of Service Industry Benchmarking Consumer Satisfaction Survey Figure 4-1: Service level planning Figure 4-2: FAIDI and FAIFI vs. Connection Density Figure-4-3: Hawke s Bay service level zones Figure 4-4: Rotorua service level zones Figure 4-5: Taupo service level zones Figure 4-6: Benchmarking business efficiency Figure 4-7: Benchmarking capacity utilisation Figure 4-8: Evidence of a relationship between capacity utilisation and consumer density Figure 4-9: Benchmarking loss ratio Figure 4-10: Some evidence of a relationship between loss ratio and consumer density Figure 4-11: Benchmarking faults per 100km Figure 4-12: Consumer views on most important attributes of power supplier Figure 4-13: Consumer satisfaction survey Figure 4-14: Consumer satisfaction survey

97 4-2 SECTION 4 SERVICE LEVELS Table 4-1: Reliability index service levels Table 4-2: Consumer service levels Table 4-3: Ten poorest performing feeders Table 4-4: Business efficiency service levels Table 4-5: Asset efficiency service levels Table 4-6: Justification of service levels and targets

98 SECTION 4 SERVICE LEVELS Service Levels 4.1 Purpose of Service Levels Excellence in customer service is a cornerstone of Unison s Mission Statement. An important means of realising this goal is through the use of service levels. Service levels provide the objective framework within which Unison s performance as a business can be measured by its stakeholders. There are a number of criteria that must be fulfilled in order for service levels to be effective for the purposes of asset management planning. Service levels should be: Objectively measurable with appropriate targets; Consistently applicable and able to be monitored over a period of time; Relevant to the regulated activities of the business; Easily understood by stakeholders; Directly comparable with the service levels of other electricity distribution businesses (EDB) in New Zealand and abroad; Compliant with the requirements of the Electricity Information Disclosure Handbook Service Level Planning and Development Figure 4-1 below shows how service levels are established and used to ensure stakeholder interests are given appropriate weight in Unison s asset management planning. Identify Stakeholder Interests The approaches employed to identify stakeholder interests are discussed in Section Introduce Appropriate Service Levels Service levels are to recognise specific interests of stakeholders (Section 4). Monitor Performance Service levels are monitored using the systems discussed in Section 2.6. Report Performance in AMP Performance against service levels is reported in Section 8. Continuously Improve Performance Specific improvement initiatives are discussed in Section 8. Continuous improvement is operative throughout Unison's asset management planning process. Inform Service Levels Service levels must to changing stakeholder expectations. Changing stakeholder expectations are accomodated through mechanisms discussed in Section Figure 4-1: Service level planning

99 4-4 SECTION 4 SERVICE LEVELS Unison s service levels were the subject of a paper to the Board of Directors in This paper compared Unison s service levels with those used by other distribution businesses. The paper concluded that while Unison s service levels are compliant with the requirements of the Disclosure Handbook, certain service levels could be added or modified to improve explanatory power and enhance stakeholder understanding. These additional measures will be trialed as part of Unison s Board reporting to judge fitness for purpose, before being introduced to the AMP as service levels. Examples include FAIDI and FAIFI, a network-centric health and safety service level, performance against new connection timeframe commitments and network expenditure to network replacement cost ratio. The service levels published in the AMP can be broadly grouped into two categories, consumer oriented service levels, and asset and business oriented service levels. The former category deals with service levels that measure the consumer experience. The latter category contains service levels that measure asset performance and effectiveness and the efficiency of the distribution business as a whole. It should be noted that the service levels that are published in the AMP are not exhaustive of the overall service level framework that Unison operates within. Examples of service levels that are not published are those within agreements entered into with the contracting market and contractual obligations with individual large consumers. The service levels arising from these agreements are confidential in nature and are relevant to only a limited subset of stakeholders. 4.3 Consumer Oriented Service Levels The intent of consumer oriented service levels is to give stakeholders a picture of how well Unison s network performance compares to the rest of the industry, and to provide consumers with a view of the minimum levels of service they can expect. Unison s consumer oriented service levels are discussed below, beginning with the most general service levels and moving towards service levels that target smaller sections of the network Reliability Indices (SAIDI and SAIFI) At the highest level, the traditional network reliability indices SAIDI and SAIFI are used. These reliability indices form an important part of the regulatory framework that Unison operates within (they are used to assess Unison s compliance with the Quality Path) and are used commonly across the industry, making direct comparison between distribution businesses possible (although in many cases direct comparison may not be appropriate, given underlying differences in network characteristics). These indices provide a view of the reliability of supply experienced by the average consumer. SAIDI is the system average outage duration index and reflects the number of minutes the average consumer would be without supply during the year as a result of a distribution fault; SAIFI is the system average interruption frequency and reflects the number of interruptions the average consumer would experience during a year as a result of a distribution fault. It should be noted that CAIDI has been removed as a service level target. CAIDI is the quotient of SAIDI and SAIFI, meaning that assessing CAIDI is equivalent to assessing the change in SAIDI relative to the change in SAIFI. Due to the fact SAIDI and SAIFI are accorded equal weight under the regulatory regime, CAIDI assessments can lead to perverse outcomes. If SAIFI decreases, while SAIDI remains constant, the CAIDI target may be breached, while in absolute terms system performance (according to regulatory quality indicators) has improved.

100 SECTION 4 SERVICE LEVELS 4-5 The SAIDI and SAIFI service level targets that Unison sets for itself are equivalent to its regulatory limits. These limits changed at the start of the 2010/11 financial year as the quality component of the Default Price Path (DPP) came into effect. Unison s revised limits were audited in October 2010 by PricewaterhouseCoopers. Table 4-1 below provides the DPP current targets and a yearend forecast for the 2011 financial year (as at February 2011). Target Target Actual 2010/11 (YE forecast) SAIDI < SAIFI < Table 4-1: Reliability index service levels FAIDI and FAIFI FAIDI and FAIFI are similar in form to SAIDI and SAIFI, but measure the reliability of supply experienced by the average consumer connected to a particular 11kV feeder. FAIDI is the feeder average outage duration index and reflects the number of minutes the average consumer connected to the feeder would be without supply during the year as a result of distribution faults; FAIFI is the feeder average interruption frequency and reflects the number of interruptions the average consumer connected to the feeder would experience during a year as a result of distribution faults. During 2009, Unison undertook a detailed statistical study that sought to identify and quantify explanatory variables in network reliability. The study confirmed that connection density (ICP/km) and undergrounding (proportion of feeder undergrounded) are strong influencers of FAIDI and FAIFI (with feeder age also statistically significant in some cases) and quantified these statistical relationships. Given a feeder connection density and proportion undergrounded, expected FAIDI and FAIFI values are calculated. Expected values are compared with actual FAIDI and FAIFI being experienced and the difference (residual) is calculated feeder by feeder. This comparison provides an important benchmark for network performance and serves to highlight feeders that are underperforming. The results of this study will in future drive service levels that consider feeder performance in relative terms. Unison had planned to introduce FAIDI and FAIFI as service levels in the 2011 AMP. This has been deferred to rigorously trial the concept internally and to allow time for sensitivity analysis and the development of a methodology to cleanse aberrations from the data. Poorly performing feeders according to the FAIDI and FAIFI metrics have however been reported to the Board of Directors on a monthly basis since June Figure 4-2 shows an example of the semi-logarithmic relationship between FAIDI and FAIFI and connection density for a subset of the network. Each blue dot represents an actual 11kV Unison feeder. Dots that sit above the red line are underperforming given their connection density.

101 4-6 SECTION 4 SERVICE LEVELS FAIDI C (Average 0309), min FAIDI C (Average 0309), min = *log10(x) FAIFI C (Average 0309) FAIFI C (Average 0309) = *log10(x) ConnectionDensity YE0809, ICP/km ConnectionDensity YE0809, ICP/km Figure 4-2: FAIDI and FAIFI vs. Connection Density 4.4 Consumer Service Level Targets Unison recognises that although SAIDI and SAIFI are useful indicators of overall system reliability, they provide little explanatory value in terms of the extremes of the performance spectrum. To address this shortcoming, Unison has a set of consumer service levels that provide an insight into the experience of consumers receiving a level of service below that of the average consumer envisaged by SAIDI and SAIFI. These service levels are complemented by annual identification of underperforming feeders to obtain a more consumer-centric view of system performance. A review of the structure of the consumer service levels and the related targets was undertaken during This review concluded that the structure of these service levels is in line with best practice, and the customer satisfaction survey confirmed that the targets are commensurate with consumer expectations. The consumer base is disaggregated into three groups: urban, rural and remote rural. Different service standards are set for each group due to differences in distance from depots, consumer densities, reticulation methodologies, fault location difficulty and access constraints. The consumer groupings are applied to the network footprint in the diagrams below.

102 SECTION 4 SERVICE LEVELS 4-7 Figure-4-3: Hawke s Bay service level zones Figure 4-4: Rotorua service level zones

103 4-8 SECTION 4 SERVICE LEVELS Figure 4-5: Taupo service level zones Table 4-2 outlines the current consumer service level targets for the three customer groupings used. Customer Group Measure Target Actual 2010/11 (YE forecast) Urban Length of time before supply is restored following an unplanned interruption. Maximum of twenty events to exceed three hours before supply is restored per annum. 18 events Urban Number of unplanned interruptions per annum. Maximum of one feeder to exceed four unplanned interruptions per annum. 2 feeders Rural Length of time before supply is restored following an unplanned interruption. Maximum of ten events to exceed six hours before supply is restored per annum. 32 events Rural Number of unplanned interruptions per annum. Maximum of one feeder to exceed ten unplanned interruptions per annum. 4 feeders Remote rural Length of time before supply is restored following an unplanned interruption. Maximum of five events to exceed six hours before supply is restored per annum. 17 events Remote rural Number of unplanned interruptions per annum. Maximum of one feeder to exceed twenty unplanned interruptions per annum. 0 feeders Table 4-2: Consumer service levels Poorest Performing Feeders The list of poorest performing feeders is not a service level in itself; however it is used to validate the targets for consumer service levels. The table is compiled by comparing actual feeder performance with what would be expected

104 SECTION 4 SERVICE LEVELS 4-9 from a feeder with similar characteristics. The feeders with the highest discrepancy in this comparison are flagged and given attention. Table 4-3 lists the ten poorest performing 11kV feeders on the Unison network and the areas of improvement targeted. Feeder Okere Rotoma Tutukau Washpool Dalbeth Waikite Otamauri Waiotapu Hendley Broadlands Area of Improvement Accelerated vegetation cutting programme initiated. Accelerated vegetation cutting programme initiated plus additional automation to be installed. OPEX and CAPEX renewals currently in planning. Analysis of faults data indicates that the preponderance of FAIDI experienced on this feeder was due to storm events. It is considered that given these events the feeder performed relatively well. Accelerated vegetation cutting programme initiated. Analysis of faults data indicates that the preponderance of FAIDI experienced on this feeder was due to storm events. It is considered that given these events the feeder performed relatively well. OPEX and CAPEX renewals currently in planning. Accelerated vegetation cutting programme initiated. Analysis of faults data indicates that the preponderance of FAIDI experienced on this feeder was due to storm events. It is considered that given these events the feeder performed relatively well. Accelerated vegetation cutting programme initiated. Table 4-3: Ten poorest performing feeders 4.5 Asset and Business Efficiency Service Levels Business Efficiency Targets Unison uses total cost per ICP and total cost per circuit kilometre as indicative measures of the cost effectiveness of its asset management planning. These measures are benchmarked across the industry (see Section 4.6.1). Service Level Target (2012 dollars) Actual 2010/11 (YE forecast) Total cost per ICP <$271 $270 Total cost per km <$3,159 $3,128 Table 4-4: Business efficiency service levels Asset Efficiency Targets Three indicators of the underlying efficiency of the asset base are used. The capacity utilisation ratio is calculated by dividing maximum system demand (MW) by total installed capacity of distribution transformers (kva). Although highly dependent on network characteristics (e.g. consumer density), this measure provides an indication of the quality of network development planning and LV design standards. The network loss ratio is calculated by dividing the difference between total energy entering the system and energy supplied to consumers by total energy entering the system. This measure indicates the efficiency of the asset base in transporting energy. A lower loss ratio means that less energy needs to be distributed to satisfy consumer demand, thereby lessening the load on upstream assets such as transmission and generation.

105 4-10 SECTION 4 SERVICE LEVELS Faults per 100km of system length are an indicator of the resilience of the sub-transmission and distribution networks to unplanned outages. Targets for these indicators are provided in Table 4-5 below: Service Level Target Actual 2010/11 (forecast) Capacity Utilisation (%) 31% 28% Loss Ratio (%) 6.0% 4.0% Faults per 100km < Table 4-5: Asset efficiency service levels 4.6 Justification for Target Levels of Service This section provides the justification for each of the service levels and related targets discussed above. A description of key elements of the justifications including industry benchmarking, and the results of the Consumer Satisfaction Survey 2009 are also provided. Service Level Justification for Service Level Justification for Target SAIDI and SAIFI SAIDI and SAIFI provide a high level measure of network performance as experienced by the average consumer. Stakeholders can use SAIDI and SAIFI to easily compare network performance across the distribution industry (although it should be noted these indices are dependent upon a range of network specific factors). Regulatory SAIDI and SAIFI limits have been adopted as the targets for consumer service levels. The limits for the regulatory period beginning 2011 were derived with reference to long term average performance but are nuanced by the removal of major outages from the dataset and the addition of a deadband to mitigate the risk of breach due to statistical variation. FAIDI and FAIFI Consumer Service Level Targets SAIDI and SAIFI are used by the regulator to assess compliance with the quality path. The FAIDI and FAIFI service levels proposed will provide a more granular means of assessing duration and frequency of unplanned interruptions. They will also give the ability to assess performance in relative terms between feeders with differing characteristics. Consumer service levels supplement the high level view provided by the indices (SAIDI, SAIFI, FAIDI, and FAIFI) by accounting for extremes on the performance spectrum. These service levels provide consumers with a view of the minimum level of service that can be expected from a reliability perspective. The use of a single set of SAIDI and SAIFI limits for regulatory and consumer service levels provides consistency and clarity. Furthermore the introduction of dead-bands and normalisation of major outages under the DPP mean that the targets can be readily justified on a statistical basis. Targets under development. The targets under the draft approach are objectively determined through the statistical derivation of FAIDI and FAIFI curves. The targets are the expected FAIDI and FAIFI values given the characteristics of the feeder. The targets were derived by applying the following criteria to Unison s network signature: Depot location; Service level agreement with first response service provider;

106 SECTION 4 SERVICE LEVELS 4-11 Service Level Justification for Service Level Justification for Target Distance between depot and most remote ICP; Operator and first response provider effectiveness; Historical frequency of faults in different geographical areas; Probability principles. The analysis undertaken is validated by analysis of Unison s poorest performing feeders (as a boundary value) and the consumer satisfaction survey (see section below). Poorest Performing Feeders Total cost per ICP Total cost per km Capacity utilisation Loss ratio Faults per 100km Despite not being a service level, poorest performing feeder analysis informs other service levels. This analysis highlights areas of the network where the consumer experience falls far below the average. Total cost per ICP is a measure that can be readily benchmarked across the industry and is scalable. It represents the cost effectiveness of the business. This service level is particularly important for shareholders who have an interest in the business performing in a financially sustainable manner. Total cost per km is a measure that can be readily benchmarked across the industry and is scalable. It represents the cost effectiveness of the business. This service level is particularly important for shareholders who have an interest in the business performing in a financially sustainable manner. Capacity utilisation is a measure that can readily be benchmarked across like distribution businesses. It provides the ability to assess the quality of network development planning and LV design standards. The use of loss ratio as a service level is justified as it can be used to ensure that assets deployed are selected appropriately and are operating optimally. This service level is of interest to stakeholders such as environmental interest groups. Furthermore there has been some discussion in the industry of enforcing the use of low loss assets. In the future this service level may become a regulatory instrument. Faults per 100km of system length are an indicator of the resilience of the sub-transmission and distribution networks to unplanned outages. It is an asset efficiency service level that No target. Each feeder in the list is subjected to an engineering study to identify solutions to rectify poor performance. The target is derived by considering the total of the direct and indirect OPEX costs with reference to the fiscal constraint imposed to ensure sustainability. This approach is justified as it implicitly makes a tradeoff between price and quality. The target is derived by considering the total of the direct and indirect OPEX costs with reference to the fiscal constraint imposed to ensure sustainability. This approach is justified as it implicitly makes a tradeoff between price and quality. The target is derived by consideration of the capacity utilisation ratios of lines businesses in Unison s peer group. This metric is highly dependent on network characteristics and the target is justifiable on this basis (see benchmarking section below). The target is derived with reference to Unison s network characteristics, knowledge of the assets employed (particularly the population of distribution transformers), and planning criteria. The loss ratio target places Unison in the lowest third of the New Zealand distribution industry for losses (see benchmarking section below). The target is derived using forecasting methods to predict (within a level of confidence) the number of faults and the level of network extension on each feeder, each

107 4-12 SECTION 4 SERVICE LEVELS Service Level Justification for Service Level Justification for Target complements the consumer oriented service levels related to network performance. As well as providing an indication of service quality, this service level is of interest to the first response service provider, as it provides a view of the resourcing required to respond to the predicted level of unplanned interruptions. year. These forecasts are aggregated to provide a total faults per 100km figure for the network. This methodology is justified as it takes into account the network signature, asset specific failure modes and historical fault data. Unison s faults per 100km target places Unison around the median of the New Zealand distribution industry (see benchmarking section below). Table 4-6: Justification of service levels and targets Industry Benchmarking Industry benchmarking is a key part of the development of and target setting for service levels. Unison s position relative to its peer group (distribution businesses with similar characteristics relevant to the service level being considered) is a consideration when setting service level targets. The diagrams below show Unison s position relative to the other New Zealand distribution businesses for the asset and business efficiency service levels Total Costs per ICP $ per km Total Costs per ICP Industry Median per ICP Total Costs per ICP (Real) Industry Med per ICP (Real) Figure 4-6: Benchmarking business efficiency

108 SECTION 4 SERVICE LEVELS 4-13 Unison s business efficiency as measured by the costs per ICP metric has been strong relative to the industry. Unison s target for 2010/11 is set at a level to ensure that this trend is preserved. This is a strong justification for the target. Capacity Utilisation Capacity Utilisation (%) Northpower Mainpower NZ Buller Electricity Westpower Centralines Top Energy Marlborough Lines Horizon Eastland Network Scanpower Network Tasman Waipa Alpine Energy Powerco The Lines Company Unison Network Waitaki Electra The Power Orion Elecreicity Otago Net Counties Power Aurora Energy Nelson Electricity WEL Vector Wellington Electricity Electricity Figure 4-7: Benchmarking capacity utilisation 50 Capacity Utilisation vs. Consumer Density Capacity Utilisation (%) Consumer Density (ICP/km) Figure 4-8 below shows that Unison s capacity utilisation target is close to what would be expected for a network of similar consumer density. This provides justification for the service level target.

109 4-14 SECTION 4 SERVICE LEVELS Capacity Utilisation vs. Consumer Density Capacity Utilisation (%) Consumer Density (ICP/km) Figure 4-8: Evidence of a relationship between capacity utilisation and consumer density Loss Ratio Loss Ratio (%) The Lines Company Buller Electricity Top Energy Electra Network Waitaki Centralines Elecreicity Ashburton Scanpower Otago Net The Power Company Eastland Network Waipa Marlborough Lines Powerco Network Tasman Counties Power Mainpower NZ Nelson Electricity Electricity Invercargill Wellington Electricity WEL Aurora Energy Westpower Vector Orion Unison Horizon Northpower Alpine Energy Figure 4-9: Benchmarking loss ratio Loss Ratio (%) Loss Ratio vs. Consumer Density Consumer Density (ICP/km)

110 SECTION 4 SERVICE LEVELS 4-15 Figure 4-10 below shows that Unison s loss ratio target is close to what would be expected for a network of similar consumer density. This provides justification for the service level target. Loss Ratio vs. Consumer Density Loss Ratio (%) Consumer Density (ICP/km) Figure 4-10: Some evidence of a relationship between loss ratio and consumer density Faults per 100 km Faults/100km The Lines Company Vector Powerco Marlborough Lines Buller Electricity WEL Wellington Electricity Orion Aurora Energy Eastland Network Centralines Waipa Unison Electricity Invercargill Scanpower Top Energy Northpower The Power Company Westpower Horizon Electra Elecreicity Ashburton Network Waitaki Network Tasman Nelson Electricity Alpine Energy Otago Net Counties Power Mainpower NZ Figure 4-11: Benchmarking faults per 100km Consumer Satisfaction Survey Consumer Satisfaction Survey as a Justification for Service Levels Unison uses consumer surveys as a means of understanding stakeholder interests. The most important of these interests have been entrenched using service levels. Further surveys ensure that these service levels remain relevant, and that targets are set appropriately. Over the past eight years, Unison has found that the most important attribute to consumers is a low charge for electricity distribution. This interest is manifest in the business efficiency service levels that are aimed at keeping costs to run the network down, and the asset efficiency service levels that provide an indicator of network optimisation. Keeping prices down has also been a major driver for investment in the Smart Grid. The Smart Grid will increase the utilisation of

111 4-16 SECTION 4 SERVICE LEVELS Unison s network, meaning capital investment can be deferred and maintenance costs will reduce over time. Smart metering is an integral part of the Smart Grid and Unison will offer time of use pricing to enable consumers to take advantage of this technology as it is deployed. This will mean consumers can exercise choice in their energy management to reduce costs. The next three most important attributes to consumers all relate to quality of supply (in order of importance: reliability, fast restoration in the event of a fault and power quality voltage and harmonics). SAIDI, SAIFI and the Consumer Service Level Agreement form the basis for quality of supply service levels. These are complemented by monitoring of poorest performing feeders. Soon to be added will be analysis of relative 11kV feeder performance using FAIDI and FAIFI measures (see Section 4.3.2). Targets for these service levels are also justified by the consumer surveys. While consumers have consistently rated quality of supply as important, price remains the overriding concern. As material improvements in quality of supply require significant incremental investment, keeping targets steady matches consumer responses. The Smart Grid initiative will have an impact on this trade off in the longer term, as gains to quality of supply will be possible with less incremental investment than would be required in traditional network assets.

112 SECTION 4 SERVICE LEVELS 4-17 Results of Consumer Satisfaction Survey 2010 The most recent Consumer Satisfaction Survey took place in December The survey polled 900 respondents from throughout Unison s geographic footprint and from all consumer segments. The overall level of satisfaction with Unison s performance was 73%. A selection of results from the 2010 survey is provided in the charts below. The percentages represent the proportion of respondents giving the respective response. What are the three most important attributes to you in a power supplier? Community Involvement Helpful/ friendly Power Quality Provide Info Quick Response Reliable Price 0% 10% 20% 30% 40% 50% 60% 70% 2010/11 Figure 4-12: Consumer views on most important attributes of power supplier

113 4-18 SECTION 4 SERVICE LEVELS 60% I would like to see an improvement in my quality of supply 50% 40% 30% 20% 10% 0% Hawke's Bay Taupo Rotorua Residential Business/ Commercial Rural Remote Rural Total 2009/ /11 Figure 4-13: Consumer satisfaction survey 100% 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% How much would you be willing to pay for an improvement in quality of supply? 2009/ /11 An extra $100 / year An extra $200 / year An extra $300 / year Any increase would be too much Figure 4-14: Consumer satisfaction survey

114 section 5 network development plans Smart Network Specialists Gagan Chadha and Chris Reid collaborate in the development of a prototype solution for calculating and visualising dynamic ratings for overhead lines. network development plans

115 SECTION 5 NETWORK DEVELOPMENT PLANS Network Development Plans Planning Criteria and Assumptions Planning Process Security Criteria Capacity Determination Performance and Quality of Supply Prioritisation Methodology Investment Prioritisation Tool (IPT) Envelope tools Demand Forecasts Load Forecasting Methodology Impact of Embedded and Distributed Generation on Load Forecast Impact of Developments and Large Consumer Projects on Load Forecast Load Forecast Assumptions - Uncertain load types and external factors Impact of Demand Side Management on Load Forecast Reactive Demand District Load Forecasts GXP Load Forecasts Zone Substation Load Forecasts Distributed Generation Non Network (Smart Grid) Solutions Network Development Options Available Options Available Meeting Service Level Targets Network Development Plan Central Region Hawke s Bay Expenditure Forecasts and Reconciliation

116 5-2 SECTION 5 NETWORK DEVELOPMENT PLANS Figure 5-1: Planning process Figure 5-2: Network Investment Toolbox Figure 5-3: Distribution of Individual CAPEX projects according to their individual score/mix Figure 5-4: Load Forecast Tool Figure 5-5: Self healing concept Figure 5-6: Shunt Capacitor bank Figure 5-7: Line Differential Relay Figure 5-8: Transformer Differential Installation Figure 5-9: Unison s Ground Fault Neutraliser Figure 5-10: Smart Meter Figure 5-11: DTS Overview Figure 5-12: Powersense Current Sensor Figure 5-13: Kaharoa feeder automation Figure 5-14: Okere feeder automation Figure 5-15: Taupo North feeder reconfiguration Figure 5-16: Fleet Street fast transfer scheme Figure 5-17: Fleet Street fast transfer scheme Figure 5-18: Owhata fast transfer scheme Figure 5-19: Overview of existing and proposed network assets Reporoa Figure 5-20: Proposed Te Toke substation Figure 5-21: Reporoa 33kV sub-transmission - proposed Figure 5-22: Overview of existing and proposed network assets Reporoa Figure 5-23: Rotorua 33kV sub-transmission - proposed Figure 5-24: Overview of existing and proposed network assets - Rotorua Figure 5-25: Taupo 33kV sub-transmission - proposed Figure 5-26: Overview of existing and proposed network assets Taupo Figure 5-27: Proposed Feeder Upgrade - Camberley Zone Substation Figure 5-28: Proposed New Feeder Route Rangitane Zone Substation Figure 5-29: Proposed location Automated Switches Haumoana Feeder Figure 5-30: Location of Proposed Automated Switch Sites Pakowhai Feeder Figure 5-31: Proposed Current Sensor Sites Arataki Feeders Figure 5-32: Zone substations that surround Windsor zone substation Figure 5-33: Proposed work detail Bridge Pa and Raureka Figure 5-34: Hastings future network configuration Figure 5-35: Napier 33kV sub-transmission proposed

117 SECTION 5 NETWORK DEVELOPMENT PLANS 5-3 Graph 5-1: Hastings district load forecast Graph 5-2: Napier district load forecast Graph 5-3: Rotorua district load forecast Graph 5-4: Taupo district load forecast Graph 5-5: GXP load forecasts Graph 5-6: Zone substation load forecasts Central region Graph 5-7: Zone substation load forecasts Hawke s Bay region Table 5-1: Unison supply classification and security criteria Table 5-2: Definition of security levels Table 5-3: Capacity determination for network assets utilised Table 5-4: Voltage performance criteria Table 5-5: Investment Prioritisation Tool Drivers Table 5-6: Network option toolbox

118 5-4 SECTION 5 NETWORK DEVELOPMENT PLANS 5 Network Development Plans The development plans and options presented in this section of the AMP reflect a network development philosophy that attempts to balance consumer needs, Unison s strategic objectives and industry best practices. As a result, this planning period sees a continuation of capital investment in the network to meet customer driven growth, maintain network security and customer service levels, meet network reliability targets, and ensure compliance with regulatory (health, safety and environmental) requirements. However, as articulated in Section 2, Unison s strategic objective to maximise the benefits of smart technology in the planning period will see a continued focus on the development and larger scale installation of smart technology. Smart devices, real time data, dynamic ratings, fast load transfer schemes, and self healing are some of the technologies that will be introduced in the planning period to ensure compliance to consumer service levels within fiscal constraints. The introduction of smart devices and control systems reinforces Unison s plan to introduce more non-network options as mitigation solutions for network constraints over the planning period. The projects beyond 2013 are indicative at this stage due to the uncertainty around future growth. All proposed investments are reviewed annually and consequently may not proceed as currently envisaged. 5.1 Planning Criteria and Assumptions The distribution network currently owned by Unison has previously been operated by a number of different companies. The different planning philosophies applied in the past have resulted in a distinctly variable network configuration across the Central and Hawke s Bay regions. Unison adopted a standard planning philosophy across all regions in 2006, which will result in a homogenous network configuration in the long term Planning Process Unison uses a five stage process to plan and develop the network. The figure below provides a high level breakdown of the key areas involved in Unison s Planning Process. Inputs Project Drivers Project Options Project Selection Project List Load Forecast and capacity determination Network Security Criteria Capacity Headroom Network Strengthening Solutions Network Augmentation Envelope Network Performance Database Network Sensors Large Customer Needs Quality of Supply Network Reliability Operational Constraints Customer Service Levels Non Network Solutions Do Nothing (Risk Assessment of Option selected) Risk Assessment Investment Prioritisation Tool Figure 5-1: Planning process

119 SECTION 5 NETWORK DEVELOPMENT PLANS 5-5 In brief, the process employed involves: 1. Inputs Updating of systems and databases to ensure current data is used during the planning process. 2. Project Drivers - Having a comprehensive understanding of the project outcomes to be achieved. 3. Projects Options - Investigation of the potential options available to enable achievement of the outcomes required and selection of the most appropriate option for each project. 4. Project Selection Prioritisation of projects through the use of prioritisation and envelope tools. 5. Project List The finalisation of a project list Security Criteria Security of supply is the ability of a network to meet the demand for electricity in circumstances when electrical equipment fails. Unison has adopted the following security of supply criteria as set out below. Maximum Demand (MD) Load Type <1 MVA 1-5 MVA 5-15 MVA >15 MVA CBD Industrial L4 L3 L2 L1 Urban Residential/Commercial L4 L3 L3 L2 Green Belt/Rural Commercial/Residential L4 L4 L4 L3 Remote Rural L5 L4 L4 L3 Table 5-1: Unison supply classification and security criteria Level For a Single Contingent Event (N-1) For a Double Contingent Event (N-2) L1 L2 L3 L4 No Break Restore 100% MD within 1 Minute Restore 100% MD within 30 Minutes Restore 100% MD within 4 Hours 75% MD Restored within the 1st Hour 25% after repair time 50% MD Restored within the 1st Hour 50% after repair time 50% MD Restored within the 1st Hour 50% after repair time 100% after repair time L5 100% restoration after repair time 100% after repair time Table 5-2: Definition of security levels

120 5-6 SECTION 5 NETWORK DEVELOPMENT PLANS Capacity Determination Introduction Capacity determination is one of the key aspects included in the planning process, as it provides a view of network capacity to supply new customer loads, existing load growth, and capacity for security of supply. The availability of network capacity headroom is based on the difference between the maximum allowable capacity (rating) of the asset and the maximum load measured through the asset during peak load conditions. During peak load conditions and under emergency circumstances (such as when a failure occurs in a segment of the network and power must be shifted to other sections to compensate) it often becomes necessary to load assets right up to their maximum ratings. In most cases maximum loading occurs for short periods of time during the year, which leads to poor asset utilisation and investment in network reinforcement projects. In order to improve asset utilisation and defer network investment Unison is utilising load peak shifting techniques, e.g. load management and demand side management. The recent developments in smart technology have provided Unison with further options to improve asset utilisation through the installation of sensors. The determination of capacity is not only limited to the capacity headroom available on transformers, overhead lines and underground cables, but includes assets that support these infrastructures, e.g. poles, LV circuits and circuit breakers, since all these assets contribute towards the determination of capacity Capacity Determination Consideration The following section discusses assets involved in determining network capacity as well as some of the considerations included in the process. It also provides an insight into the design standard considerations for different assets supplying the various load types supporting customer service levels as specified in Unison s security criteria. Asset Asset Level Load Type Design Standard considerations Capacity Determination Transformer Zone Substation L4, L5 Single transformer The service area that it supplies Urban, Rural, Remote Rural. L1, L2, L3 Double transformer The customer classification Industrial, Commercial or Residential. The degree of security of supply needed. Future growth up to the planning period (20 years). The requirement to provide backup for surrounding zone substations. Circuit Breakers Zone Substation L4, L5 Outdoor switchgear Future growth up to the planning period (20 years). L1, L2, L3 Indoor switchgear Requirements to back feed or support a wide range of switching configurations. Likely fault current rating. The expected duty service. Underground cable 33V L1, L2 500 or 800mm Al XLPE Load growth for the area served. 11kV L1, L2, L3 300 mm 2 Al XLPE The interconnected load requirements for security of supply. In some cases, the load duty cycle. (This may apply to industrial situations). The de-rating effects that other cables buried nearby may have or soil conditions.

121 SECTION 5 NETWORK DEVELOPMENT PLANS 5-7 Asset Asset Level Load Type Design Standard considerations Capacity Determination Overhead lines 11kV & 33kV L1, L2, L3, L4, L5 Poles 11kV & 33kV L1, L2, L3, L4, L5 Distribution Transformer 11kV L1, L2, L3, L4, L5 Ground clearances which in turn are a function of span lengths, conductor size, circuits to be carried and the legal clearances required for the terrain. Design considerations such as ice loading, broken conductor conditions and excessive dynamic wind loads. Height requirements for ground clearances which in turn are a function of span lengths circuits to be carried and the legal clearances required for the terrain. Pole top loadings according to the size, weight and number of conductors on the pole. Permanent loading (due to turn-offs) (permanent loads can produce inelastic deformations over time). Design considerations such as ice loading, broken conductor conditions excessive dynamic wind loads. Whether the pole is to be stayed or unstayed. The degree of security and factors of safety needed based on the importance of the circuit. Environmental issues. (Excessive wind speeds, effects of H2S, shock and impact loads). Transformers are selected based on their required load carrying capability and reliability. Use of transformers up to 1MVA as Unison carries spares. The current rating capacity required. Future growth up to the planning period (20 years). The electrical characteristics of the load supplied. (e.g. power factor, duty cycle). The tolerable voltage drop for the line. Requirement to carry additional load during fault restoration and switching. The importance of reducing losses. Planned future circuit requirements that may be added and the voltages. The degree of security and factors of safety needed based on the importance of the circuit. Customer diversity. Future connections. Voltage drop especially for rural consumers. The load types to avoid quality issues (Household load vs High Reactive Load). Distribution switchgear 11kV L1, L2, L3, L4, L5 Switchgear are selected on their load breaking capability, reliability and functionality. Customer density. Automated switchgear. LV feeder 400V OH L1, L2, L3, L4, L5 400V UG Parallel LV feeder to cater for voltage drop. Radial LV feeders with group breaks. Customer density. Security of supply required. Voltage drop. Capacity required. Table 5-3: Capacity determination for network assets utilised

122 5-8 SECTION 5 NETWORK DEVELOPMENT PLANS Asset Ratings through the utilisation of Smart Technology During peak load conditions and under emergency circumstances (such as when a failure occurs in a segment of the network and power must be shifted to other sections to compensate) it often becomes necessary to load assets right up to the in-design limits. In some cases the five minute emergency rating of equipment can be utilised. The technology available to determine and implement these ratings is summarised in section Performance and Quality of Supply Power quality is evaluated under load forecast and embedded generation scenarios, to ensure adequate performance is maintained. Various planning periods are assumed, with detailed investigations focusing on the short term up to five years ahead and annual development planning reviews for a ten year horizon. As quality of supply issues are often a shared problem between Unison s network and the consumers installation or equipment designs, Unison has published a Network Connection Standard on its website. This standard outlines responsibilities of both Unison and the consumer to ensure that all connected parties receive a supply of electricity to appropriate quality and performance standards. The standard is also referenced in the Use of System Agreement Unison has with all retailers, and the obligations included in the standard form part of the connection agreement each consumer enters into when connecting to Unison s network. Aspects considered in the planning process include: Fault Ratings - Current interruption switchgear and equipment will have ratings sufficient for fault and routine operation. Fault levels in the network are reviewed to ensure that network equipment ratings are not exceeded. Planning for network configuration or supply arrangement changes (particularly point of supply, sub-transmission and embedded generation developments), the impact on fault levels is assessed, and equipment rating issues addressed; Voltage Performance under normal conditions - The voltage regulation guidelines stated below are used for planning purposes to identify potential power quality issues. These take account of Transpower's stated voltage regulation policy: o 220kV and 110kV ± 10% o Unregulated 33kV ± 5% Supply Level Maximum Minimum 33kV substation connection (1) +5% -5% 11kV distribution circuit +2% -3% (2) Distribution transformer low voltage +5% -2% Low voltage distribution circuit, including allowances for service connection (3) +6% -6% (1) Regulated with OLTC equipment on 33/11kV transformers (2) This figure will vary with rural distribution due to sometimes lengthy 11kV radial feeders. LV circuits are designed with these variances taken into consideration. (3) Off-load taps on distribution transformers Table 5-4: Voltage performance criteria Unison has a Quality of Supply Standard which deals with voltage regulation, harmonic voltages and currents, voltage dips, voltage unbalance and flicker. Unison designs and operates the network to supply voltages to consumers in accordance with the regulated limit of 230 volts ± 6%. However, despite these efforts and usually due to unanticipated changes in consumer loads, some

123 SECTION 5 NETWORK DEVELOPMENT PLANS 5-9 consumers may occasionally experience voltages outside these limits. When potential issues are identified, either from customer enquiries or Unison s modeling and/or monitoring, investigation and any required resolution is treated as a matter of priority. In addition to the voltage regulation limits above, Unison also endeavors to keep voltage imbalance on all voltage levels of its networks below 2%. The allowable level of harmonic distortion of the voltages supplied to consumers is also covered by regulation. Tracking the source or cause of harmonic distortion is generally very difficult and often includes investigation of one or more consumers installations, as well as the network configuration. Unison endeavors to work with all affected parties, including external consultants, to identify the problem and work through the most cost effective solutions. As a last resort, if a particular consumer installation is identified as the cause, Unison reserves the right to disconnect that installation to protect other consumer installations from damage. Occasionally, specific consumer installations can cause interference, such as power factor correction capacitors or large motors. This interference can arise in many forms such as voltage sags, flicker and absorption of Unison s load control signals. To ensure that this equipment does not cause problems, the Network Connection Standard provides guidelines for consumers to notify Unison when this type of equipment is to be connected. This allows Unison to assist the consumer by assessing whether a problem is likely to occur before expensive investment decisions are made. Unison is also continuing its proactive approach to maintaining the quality of supply to consumers, and is currently installing intelligent web-enabled energy and power quality meters with full communications capability around the network. This system will provide comprehensive power quality information that will enable the verification of power quality delivered to our consumers against the published power quality levels, and faster resolution of power quality issues. Network Performance under Contingency Conditions Greater variation in network performance is expected under contingency conditions, particularly in terms of voltage. The criteria applied are: The highest system voltage (as specified in the standards applicable for each type of equipment) shall not be exceeded at any point in the network; Zone substation 11kV bus voltages shall not be allowed to fall below 95% of rated voltage during single contingencies; No individual element should carry a sustained load beyond its design rating for the ambient conditions that apply; Protection relays should generally not be used to keep loads within operational limits; A substation busbar fault is considered abnormal; Alternative feeds permit restoration of supply after switching has been undertaken; Radial feeds envisage restoration time dependent on defect repair time; All practical steps are taken to ensure safety of network equipment and people.

124 5-10 SECTION 5 NETWORK DEVELOPMENT PLANS 5.2 Prioritisation Methodology The selection process of investing in the network is based upon the outputs of a suite of decision support tools developed by Unison and referred to as the Network Investment Toolbox (NIT). Two important tools in the NIT are the Investment Prioritisation Tool (IPT) and the Augmentation Envelope (AE). The IPT provides a bottom up approach and the AE provides a top down view. The outcome of both these tools is married and provides a final project list. Network Investment Toolbox Condition Based Monitoring (CBM) Data Repositories Stores Information Register GIS Historian and other databases Asset Register Faults Database Strategic Analysis & Interpretation Works Cost Estimating Tool Triple-R Tool Load Forecast Tool (LFT) Connectivity Model Local Assessment (intra-category) Renewal Envelope (RE) Augmentation Envelope (AE) Global Assessment (inter-category) Investment Prioritisation Tool (IPT) CAPEX Portfolio and Budget OPEX Portfolio and Budget Figure 5-2: Network Investment Toolbox Investment Prioritisation Tool (IPT) Unison has developed a tool to formalise the prioritisation of network projects, known as the IPT. The tool provides a decision-support framework to optimise the wide range of network investment projects considered each year. The benefits of this tool are as follows: Alignment of the capital programme with company strategic intent, consumer needs and regulatory thresholds; Maximisation of the long-term value creation and financial return from the capital investment programme; Sustainable achievement of consumer service levels, network security, reliability and safety targets; Enhanced efficiency of investment process (limit demands on management time). This tool prioritises each project in the programme in terms of its contribution to Unison s strategic drivers, which are summarised in table 5.5 below.

125 SECTION 5 NETWORK DEVELOPMENT PLANS 5-11 Strategic Drivers Financial Quality of Supply Company Policies and Standards Legal & Statutory Stakeholder Satisfaction Shareholder Obligations Strategic Benefit Strategic Sub Drivers Direct financial o Revenues (including probable future revenues) o Consumer contributions o Cost savings by design o Costs (Capex & Opex) Indirect financial o Renewal of network elements o o o Network reliability o o Network security Mitigation of risks Miscellaneous gains Consequential gains/losses Direct impact on network reliability Mitigation of risk of decrease in network reliability Conformance to company policies that must be strictly adhered to Legal & Statutory Gain in stakeholder satisfaction Conformance to shareholder obligations that must be strictly implemented Strategic option value Strategic alignment Table 5-5: Investment Prioritisation Tool Drivers In essence this tool provides a fair comparison across different investment categories (e.g. renewal, growth, performance, consumer, compliance) by consolidation and enhancement of the presently distributed knowledge base and tools relating to the investment decision process. Each project is assessed for its contribution to each driver, and each driver category has a weighting which determines its contribution to the overall evaluation of the project. In this way all proposed projects are allocated a score and can be ranked by order of importance based on the corporate drivers. Individual Project Value Investment Prioritisation Tool CAPEX Project Value Distribution Included Rank Excluded Perf ormance Augmentation Compliance New Technology Renewal Undergrounding Figure 5-3: Distribution of Individual CAPEX projects according to their individual score/mix

126 5-12 SECTION 5 NETWORK DEVELOPMENT PLANS The figure above is an example of the output from the IPT. It shows the distribution of CAPEX projects according to their individual score and ranking. The dotted line indicates the project inclusion threshold according to the approved budget envelope. Projects not included will be moved out into the following year, where they will be re-entered into the IPT and re-assessed and ranked with new projects to compete for inclusion in the following year s CAPEX programme Envelope tools Envelope Tools provide the ability to estimate capital requirements in the short, medium and long term, ensuring sustainable network operation and service delivery, from the perspective in question (i.e. renewal and augmentation). For the two Envelope Tools this means: Renewal Envelope (RE) - preventive renewal capital required to maintain the physical integrity of the network; Augmentation Envelope (AE) - reinforcement capital required for the network to meet growing demand whilst maintaining the required security standards; Each of the above tools should enable sensitivity and scenario analyses with respect to a range of important factors or circumstances. Importantly, the envelope tools are not used in isolation of one another. Instead they are fully integrated, and have the ability for trade-offs to be conducted rigorously between capital to be invested for any of the two purposes. The present version of the AE provides a forecast of assets and capital required to support forecast demand growth over a 20 year time frame. The electricity demand, asset and capital forecasts are based on census derived growth forecasts conducted at a very granular census area unit (CAU) level. As a matter of interest, the same census derived growth forecast is used as a basis to forecast revenue growth and customer capital growth (including connection growth rates), leading to a well-integrated and internally consistent forecasting framework. All the elements of growth forecasting (i.e. demand, assets, capital and revenues) are conducted across the residential, commercial and industrial segments, and can be adjusted for expected increases or decreases in the intensity of usage (i.e. as may result because of consumer behavioral changes such as the increased use of heat pumps, or increased energy efficiency of electrical products). The AE prioritises a programme of proposed augmentation projects using a multi-criteria decision model that includes the following principal criteria: 1. Capacity headroom; 2. Connectivity (backstopping) headroom; 3. Reliability of service (based on FAIDI and FAIFI); 4. Rural voltage level considerations; 5. Synergies, including upstream and downstream linkages (for example if economies of scale will result by simultaneously augmenting two feeders because of their special connectivity and/or physical proximity); 6. Ratio of the above benefits to their associated (augmentation) capital cost. Whereas capacity headroom can be assessed in a relatively straightforward manner, connectivity headroom is assessed rigorously for each feeder using the DIgSILENT model, and the worst constraint is selected for entry into the AE. Capacity headroom and connectivity headroom are combined into a single number using the weight-functions shown in

127 SECTION 5 NETWORK DEVELOPMENT PLANS 5-13 Figure 5-3 below, and which reflect the risks associated with each of these capacities becoming constrained. The exponential increase in priority as capacity headroom becomes negative, is an important feature of this Envelope Tool. Augmentation Priority Profiles Capacity Headroom 300 Connectivity Headroom Priority, % Capacity or Connectivity Headroom, % Figure 5-3: Weight-functions for capacity headroom and connectivity headroom The reliability of service criterion for the AE is comprised of both FAIDI and FAIFI on an equal weighting basis, after accounting for the effect of connection density 1 and using normalised scales bounded by the 5 th and 95 th percentiles of the respective data ranges. The weights of the AE criteria are as follows: Capacity and connectivity headroom: 80% (and combined as per weight-functions shown in Figure 5.5); Reliability of service: 10% ; Synergies: 10%; Rural voltage level: a penalty weight of 100% is added if the rural voltage level is below the set standard. The AE and associated processes require significant manual operation and professional input in its deployment, and does not lend itself to being fully automated (for example in the same way as the RE has been automated). This is simply because professional user input and insights are required at intermediate steps in the process which would be very challenging to automate 2. It is expected that even subsequent versions of the AE and surrounding processes will require similar professional user input and manual operation. 1 Reliability of service is well-known to be strongly dependent on connection density (which is a relatively uncontrollable network attribute). Normalising for connection density is done by conducting appropriate regression analyses for FAIDI and FAIFI relative to connection density, and then by using the outputs of these analyses as input into the AE. 2 A typical example of professional user input is when interaction occurs between two, or among several potential augmentation projects. Any one augmentation project could (positively or negatively) impact the requirements of a number of other potential augmentation projects, because of mutual connectivity in the network. Sophisticated expert systems would be required to automate this type of professional involvement in using the AE and process, and which are not considered to be justified at the present time.

128 5-14 SECTION 5 NETWORK DEVELOPMENT PLANS 5.3 Demand Forecasts Load Forecasting Methodology The Unison demand forecasting model has been updated with the latest growth figures across all consumer classifications. The model forecasts future peak demand based on relationships between key economic indicators and electricity demand. Projections extending out to 2031 are available for those key indicators enabling the model to forecast demand within this time horizon. Forecasts are made at a feeder level based on simple models of domestic, commercial and industrial sectors. They are then rolled up to a zone substation and grid exit point (GXP) level. The following diagram outlines the high level process followed by the LFT: Load Forecast Tool Households Population Past Demands (Summer/Winter) Domestic Model GDP Past Demands (Summer/Winter) Commercial & Industrial Model Feeder Demand Forecast Census Area Units (CAU) Council Planning Zones (CPZ) Feeder length Installed Transformer Capacity Classify Consumer Groups Zone Substation Demand Forecast GXP/ POS Demand Forecast Figure 5-4: Load Forecast Tool

129 SECTION 5 NETWORK DEVELOPMENT PLANS 5-15 The load forecast tool (LFT) utilises Census Area Units (CAU) and Council Planning Zones (CPZ) to identify average load growth profiles for each feeder within Unison s footprint. The Census data provides the growth rates for each CAU by consumer group. Domestic consumers are mapped to household growth, commercial consumers are mapped to business unit growth, and heavy industrial consumers are mapped to individual industry sectors as defined in the Census data. This information is superimposed with CPZ and the 11kV feeders. A feeder can extend over multiple CAUs and have varying composition of consumer groups within a CAU. Distribution transformer installed capacity is used as the first weighting factor to determine the composition of consumer groups within each CAU. The feeder length was used as the second weighting factor to determine composition of the growth profile associated with each CAU. Both of these were used to project a growth profile for each feeder within Unison s footprint. The LFT outputs both summer and winter peaks for each feeder. The summer and winter periods are aligned with those used by Transpower (summer October to April, and winter May to September). The tool incorporates ratings obtained from manufacturers for overhead networks and the CYMCAP results for cables. Traditionally, overhead lines were designed to operate at 50 C conductor temperature. Unison has recently modified the design standards such that new overhead constructions are designed to operate at 75 C. The LFT is ideally suited to assess the impact of load management (LM) and demand side response (DSR) initiatives, arising from the introduction and roll-out of smart network technology, on the forecasting of demand Impact of Embedded and Distributed Generation on Load Forecast The LFT has the flexibility to include any distributed generation (DG) and embedded generation that may occur within the planning period. Each of the distributed generations is assessed individually to determine whether they substitute for network capacity. DGs using fuels such as wind, solar and hydro and single generator sites are deemed to be unreliable as either: Fuel cannot be stored; Capacity cannot be guaranteed. Due to this uncertainty, DGs with unreliable fuel sources are not considered in the LFT unless they are equipped with multiple generators. In such a case, the n-1 capacity of a DG is considered as substitute for network capacity. Embedded generation in the Hawke s Bay and Rotorua regions is minimal compared to the Taupo region. A small number of industrial consumers in both Hawke s Bay and Rotorua have distributed generation installed which tends to match the peak onsite demand. However, they are subject to availability of resources; hence, they are not considered as substitute for capacity due to reasons described earlier. The Taupo region has three embedded generators, hydro (1) and geothermal plants (2) connected to Unison s 33kV system, which at full generation far exceed the maximum area demand. These generator loads will not impact Unison s load forecast as the methodology used to derive the load forecast used a bottom up approach and load has been built up from feeder loads to zone substation to GXP. The second geothermal embedded generator (26MW) in Taupo was commissioned in A small (5MW) hydro scheme in northern Hawke s Bay is being investigated by others.

130 5-16 SECTION 5 NETWORK DEVELOPMENT PLANS Impact of Developments and Large Consumer Projects on Load Forecast The LFT has the flexibility to include any substantial load growth that may occur within the planning period. This information is obtained from reliable sources such as developers, local authorities and existing large consumers etc. The loads in the tool are likely to be accurate; however, the timing of these new connections can be out by a few years due to external influence. These numbers will be reviewed annually and updated where necessary after consultation with respective parties. The uncertain loads and the load types are listed below and are reflected in the load forecast (see Graphs 5.1 to 5.4). New dairy loads along SH5 between Taupo and Rotorua, resulting from the land conversion. In 2010, Unison was advised of plans to resume the establishment of large dairy units. New settlements and recent developments in the Mapara region are driven by the planned construction of WEKA (New highway between Kinloch and Taupo). Due to delays in planning, designation of the WEKA, the growth is likely to be deferred. At present, Unison does not know the precise load growth in the region, but estimates to be around 3MVA. This will likely have an impact on the proposed Kinloch substation for the following reasons: o 33kV supply is reliant on WEKA designation is required; o Substation is reliant on the forecast load growth materialising; o Short term solutions will be implemented until the substation is built (see networks project section). The short term solutions chosen will ensure assets do not become stranded. New light industrial and commercial load on the fringes of Rotorua. This new growth has not eventuated, however, with improving financial conditions it may occur slowly. The exact timing of the growth is unknown. An existing large customer has, with Unison, investigated the establishment of a 33kV substation to the south of Rotorua. The demand from this substation will depend on the longevity of the customer s on site generation. There is no major load growth projected for the Hawke s Bay region Load Forecast Assumptions - Uncertain load types and external factors Energy intensity is likely to increase for household consumers. This is due to affordability of the electronics and redundant devices in use (e.g. using TVs at the same time). As the intensity is unknown, this has not been factored into the load forecast. The LFT assumes a constant load power factor (0.95) throughout the forecast period. The increase in use of compact fluorescent lamps and power electronic devices will create a distorted supply which results in poor power factor and high harmonics (increased feeder loading). The impact of this is unknown and has not been factored into the LFT. There will be no significant shifts in the underlying technology of electricity distribution in the next 20 years Impact of Demand Side Management on Load Forecast Ripple control forms an integral part of Unison s load management strategy and provides a network investment deferral option in areas where asset loading has exceeded its load bearing capabilities. It also provides means of bidding in the reserve market. There are approximately 86,000 water heaters supplied by the Unison networks. The after diversity demand of these heaters in the Unison networks is estimated to total 83MW at the time of the co-incident peak on a cold winter afternoon.

131 SECTION 5 NETWORK DEVELOPMENT PLANS 5-17 Unison has a number of older load control schemes (operating frequencies in the range of 500Hz and 725Hz). Unison does not own ripple control receivers and therefore has limited ability to control their installation and maintenance. As a consequence, Unison s ability to control hot water load is reducing. Unison is reviewing the existing scheme and may adopt a modern ripple technology in the footprint. This would require all existing 500Hz ripple receivers in Rotorua and 725Hz ripple receivers in the Taupo regions to be changed to 317Hz. Unison expects delays in achieving this as discussion with retailers is required. Alternatively, Unison is evaluating smart meter technology that can be used to control not only hot water load but other household appliances, for example delaying the defrost cycle in a refrigerator or to raise or lower the thermostat setting on air conditioning units in both residential and commercial premises. The installation of such technology requires negotiation with retailers and consumers and will likely take several years to achieve. There is uncertainty in the growth of demand due to external influences such as local and global economic conditions. Load control is seen as a main driver in deferring capital expenditure. Unison is working with retailers to ensure a load control scheme remains viable and operable. As a result, the controllable load will decrease until the full benefits of a load control scheme can be realised in 3 to 4 years time. This is highlighted in Graphs 5.1 to 5.4. These graphs also illustrate the impact of known larger developments that are additional to the organic load projection. It should be noted that the major developments are in the Taupo and Rotorua regions as described in Section Reactive Demand At present a constant load power factor of 0.95 is used to forecast demand in all regions. While this assumption is reasonable given that there are no expected major changes to demand composition, this approach does not take into account reactive compensation devices such as capacitors installed or to be installed in the system. The use of shunt capacitors for voltage support in the distribution network has the additional effect of lowering apparent power (MVA) demand and freeing up capacity in the entire distribution chain from 11kV feeder through to GXP. Experience elsewhere in New Zealand shows that for a large GXP with a reasonable installation of capacitors the capacity freed up can be approximately equal to demand growth for one year. Issues with shunt capacitors adversely interacting with load control ripple frequency signals must be considered, however. As Unison implemented power factor penalty charges across its networks from 1 April 2007 to encourage consumers to maintain an efficient power factor, it is expected that more shunt capacitors will be installed within consumer installations during the coming year. The impact of this will be monitored for significance during the year, as will impact on the existing load control ripple signal particularly the higher frequency plants that are more susceptible. With the further implementation of the smart network, the proliferation of measuring devices will allow Unison to study the reactive power flow (VAr) in its 11kV network to determine the loads with poor power factors and to optimise the placement of capacitor banks.

132 5-18 SECTION 5 NETWORK DEVELOPMENT PLANS District Load Forecasts Hastings District Load Forecast 150 Total demand in MVA / / / / / / / / / / / / / / / / / / / / /31 Existing load control Enhanced load control Graph 5-1: Hastings district load forecast Napier District Load Forecast 120 Total demand in MVA / / / / / / / / / / / / / / / / / / / /31 Existing load control Enhanced load control Graph 5-2: Napier district load forecast

133 SECTION 5 NETWORK DEVELOPMENT PLANS 5-19 Rotorua District Load Forecast / / / / / / / / / / / / / / / / / / / / /31 Total demand in MVA Enhanced load control Existing load control Graph 5-3: Rotorua district load forecast Taupo District Load Forecast 50 Total demand in MVA / / / / / / / / / / / / / / / / / / / / /31 Existing load control Enhanced load control Graph 5-4: Taupo district load forecast

134 5-20 SECTION 5 NETWORK DEVELOPMENT PLANS GXP Load Forecasts The following graph indicates the capacity of each Transpower GXP and points of supply connected to the Unison Network. Present and 2031 maximum demands are also shown. The impact of projects incorporated in this plan is not reflected in the GXP load forecasts. The tabled loads are those expected if no development work is undertaken. Firm capacity is capacity of each site should one item of plant fail. Whakatu Wairakei Tarukenga Rotorua 33kV Rotorua 11kV Redclyffe Owhata 2010 Max 2031 Max Firm Capacity Ohaaki Fernhill Atiamuri MVA Graph 5-5: GXP load forecasts Projects have been proposed in project details Section 5.7, to resolve capacity constraints in occurrences where the forecast load exceeds the firm capacity. There are three single transformer sites, Tarukenga, Ohaaki and Atiamuri. The projects identified have a regional impact and are expected to resolve these constraints.

135 SECTION 5 NETWORK DEVELOPMENT PLANS Zone Substation Load Forecasts Central Region Fleet St Biak St Taupo South Runanga Rainbow Fletchers 2010 Max 2031 Max Firm Capacity Fernleaf Arawa MVA Graph 5-6: Zone substation load forecasts Central region Fleet Street Substation was completed in A number of substations are proposed in the next 5-10 years to resolve constraints at both Runanga and Arawa substations. These projects are discussed in depth in Section 5.7. Both Fernleaf and Rainbow substations are single transformer sites and do not require higher security at present (see security standards). Fleet Street substation has a single transformer with security to be provided by a fast load transfer scheme on the 11kV network.

136 5-22 SECTION 5 NETWORK DEVELOPMENT PLANS Hawke s Bay Region Windsor Tomoana Rangitane Marewa Mahora Hastings Bluff Hill Arataki Tutira Tannery Rd Tamatea Springfield Patoka Faraday St Esk Church Rd Awatoto Flaxmere Sherenden Maraekakaho Irongate Havelock North Fernhill Camberley 2010 Max 2031 Max Firm Capacity MVA Graph 5-7: Zone substation load forecasts Hawke s Bay region Projects are discussed in depth in Section 5.7 to resolve capacity constraints in occurrences where forecast load exceeds the firm capacity.

137 SECTION 5 NETWORK DEVELOPMENT PLANS Distributed Generation Unison has a distributed generation (DG) policy which is available for viewing on Unison s website. The regulations categorise DG into two categories; 10kW or less and above 10kW. There are different processes and requirements for connecting each category. Such information and application form is available on the website The key principles of Unison s distributed generation policy are: DG will be able to connect to Unison s electricity distribution network on fair and equitable terms which do not discriminate between different DG schemes; Unison will make the terms under which DG can connect and operate to its electricity distribution network as clear and straightforward as possible and Unison will progress all applications to connect DG to its electricity distribution network as quickly as possible; Technical and safety standards for the connection and operation of DG on Unison s electricity distribution network will be based on best practice and will aim to meet the needs and protect the interests of DG schemes, other consumers and Unison; Unison will comply with all legislation and regulatory requirements regarding the connection and operation of DG on its electricity distribution network. Unison recognises the value of embedded generation in a number of ways and encourages the development of embedded generation that will provide real benefits to both the generator and Unison. However, Unison also recognises that embedded generation can have undesirable affects on the network. Any new embedded generation is modelled and analysed to ensure key policies in the connection documents are met. Connection terms and conditions The embedded network will be metered at 11kV unless supply is taken from a 400V feeder. The customer is responsible for providing their own Electricity Authority code compliant meters and current transformers (CTs). Unison has the right to investigate and/or test the network to ensure the generator operation is not outside technical parameters outlined in the relevant DG policies. Safety Standards A party connecting embedded generation must comply with the Safety Rules & General Safety Handbooks for the Electricity industry, other relevant regulations and codes. Unison has the right to disconnect a connected party, where it believes the installation is hazardous to persons or property, until it has been rectified to a safe condition. Technical Standards All connected parties must demonstrate that the operation of the generation will not interfere with operational aspects of the network, such as network signaling, protection and control. All connected assets at the point of connection must meet the design principles in Unison s design and construction standards. The power factor of the connected party measured at the metering point shall not be less than 0.95 lagging.

138 5-24 SECTION 5 NETWORK DEVELOPMENT PLANS Metering that is capable of recording both imported and exported energy must be installed. These meters will be 4- quardrant meters and shall be Electricity Authority code compliant. 5.5 Non Network (Smart Grid) Solutions Unison views smart network technologies as non-network options and considers them to be an integral part of its Smart Grid Initiative. These new technologies provide an alternative to conventional network strengthening solutions. Conventional network strengthening solutions are costly and under utilised for a number of years, since they need to cater for load growth over most of the planning period. Non network solutions provide a cost effective alternative and in most cases are used as a short-medium term solution in order to defer investment. These new technologies or non network solutions provide the following advantages over conventional network solutions: Easy to plan and construct; Added information about the network, e.g. loadings, fault indication etc. Low installation cost; Low purchase price; Defer investment. The following concepts have been used by Unison over the last few years: Embedded generation; Standby generation; Mobile technology, e.g. mobile regulators; Demand side management; Load control; Improve utilisation by planning based upon the short term ratings of assets, e.g. through fast load transfer schemes; Network automation to allow faster reconfiguration and restoration; Behind the meter options, e.g. a concept specific to a consumer; Notional transmission investments; Improve the reliability of assets, e.g. increased maintenance intervals; Substation earthing compensation equipment, e.g. Neutral Earthing Resistors. In recent times enhancements in smart technology has provided Unison with more non network solution options. The following technologies are currently being tested by Unison with a larger network roll out in mind: Smart technology network automation, e.g. self healing networks; Reactive VAr compensation, e.g. capacitor banks; Fast protection, e.g. line differential and transformer differential protection; Ground fault neutraliser; Fault passage indicators; Smart meter as customer endpoint device; Real time monitoring.

139 SECTION 5 NETWORK DEVELOPMENT PLANS 5-25 Each of the above technologies will be discussed in detail in the next section. Automatic Sectionalisation & Restoration (ASR) ASR allows real time monitoring and control of the distribution network, and automates decision making, while enabling optimised load shifting that manages network constraints, alleviates overloading conditions, reduces outage occurrence and duration, and creates more efficient electricity distribution system. Benefits of ASR are: Centralises remote monitoring of electrical distribution infrastructure; Expedites fault detection, fault location and service restoration; Intelligently reconfigures and sectionalises feeders; Improves reliability; Analyses distribution load flow; Increases infrastructure reliability; Optimises decision making; Reduces operating and maintenance costs; Improves customer satisfaction. Unison has installed pilot ASR schemes on the Neeve feeder out of the Church Road substation and on the Park Island feeder out of the Tamatea zone substation. These Operation Centre Feeder Devices Figure 5-5: Self healing concept Substation Devices trials are ongoing and the schemes are being monitored and optimised to ensure maximum benefit realization. Further ASR projects have been planned and are detailed further on in this section. Reactive VAr Compensation (Capacitor Banks) The installation of capacitor banks provides a cost effective alternative to conventional network strengthening projects. It is predominantly used on 11kV feeders where a large number of irrigation loads are installed. The main benefits are: Improve asset utilisation; Improve voltage profile; No impact on fault level. Unison has now installed a total of three capacitor banks on its Hawke s Bay network. Units have been installed on the Mangatahi, Twyford and Roys Hill feeders. These units are switched in and out based on predetermined VAr thresholds. The effectiveness of these units is currently being monitored and this technology will form part of Unison s non-network solution toolbox to address identified constraints and provide the benefits detailed above. Figure 5-6: Shunt Capacitor bank

140 5-26 SECTION 5 NETWORK DEVELOPMENT PLANS Fast Protection Line Differential protection As a result of a number of double 33kV circuits and 33kV/11kV circuits installed on the same structure across the Unison network, the probability of fault propagation from one circuit to another is high. The network solution to this problem would be to construct each circuit on individual towers which would result in very large investments. Fast protection provides Unison with a cost efficient alternative to this problem. The main benefit of Line differential protection is that it compares currents on both sides of the circuit via a fibre connection. If a mismatch is detected both circuit breakers are immediately opened mitigating the risk of an outage on the other circuit. The rollout of fibre between the majority of Unison s urban substations is an enabler to this technology. Numerous line differential protection relays have been installed in preparation for these schemes and the following line differential protection schemes are expected to be commissioned this year: Figure 5-7: Line Differential Relay Onekawa Church Road, Onekawa Tamatea, Faraday Marewa, Tomoana Mahora, Wairakei Centennial Drive (A & C), Centennial Drive Runanga, Wairakei Runanga Transformer Differential Protection Unison has a number of double transformer substation sites that are only protected via over current and earth fault. Any internal fault to the transformer or a fault between the 33kV and 11kV breaker will cause both transformers to trip. This problem is currently being rectified by the installation of transformer differential protection. Transformer differential protection works in a similar way to line differential protection except it is designed to measure between the HV and the LV side of the transformer. Any current mismatch will result in the immediate opening of circuit breakers in order to limit the amount of electrical energy flowing through the transformer. The benefit of using Transformer Differential Protection in a substation environment is to prevent current discharge within the power transformer which can cause irreversible damage or significantly reduce the life of the asset. Transformer differential protection schemes have been planned, implemented or are in the process of being implemented at the following Unison substations: Figure 5-8: Transformer Differential Installation Church Road, Tannery Road, Tamatea, Tomoana, Mahora, Flaxmere, Hastings, Irongate, Marewa and Arataki.

141 SECTION 5 NETWORK DEVELOPMENT PLANS 5-27 Ground Fault Neutraliser (GFN) The technology reduces the amount of electrical arcing at the point a fault occurs on the network. This reduces the level of threat to human life and risk of fire. It also allows electricity network operators to maintain power supply to homes and businesses, while staff is dispatched to fix the fault. This technology is designed for areas that experience a large number of earth faults. A ground fault neutraliser has been installed at Unison s Irongate substation on Maraekakaho Road Hastings. The majority of the required commissioning checks have been completed. Some minor technical issues are in the process of being resolved prior to the unit being placed in service. Results from this installation will be monitored for 12 months after which time a decision will be made regarding the deployment of this technology elsewhere on Unison s network. Figure 5-9: Unison s Ground Fault Neutraliser Fault Passage Indicators Fault passage indicators (FPI) are well known throughout the industry. They are attached to overhead lines to visually indicate if a fault current has flown past that point. This technology saves time in fault location and is especially useful in rural areas where there are long lines to patrol. Recent developments in this area have provided enhanced functionality. FPIs installed have been connected to SCADA and can also send fault currents and distance to fault functionality. The key benefit is quicker fault response and improved restoration times. Units have been deployed in various sites throughout Unison s network. As more network automation is installed which has this functionality built in, these units are able to be relocated to other areas of the network in order to realise the benefits mentioned above. Smart Meters Smart meters installed on customer premises will provide Unison with a number of benefits. Some of these benefits are: Real-time or near real-time monitoring of power quality; Enhances Unison s ability to manage load control at a granular level; Provides real time outage notification. The trial rollout of 1640 smart meters is planned for June The network information supplied from the meters in this trial will be captured, analysed and utilised in order to realise benefits and develop systems and process for the planned larger rollout. In addition to the installation of Smart Meters on customer premises, Unison plans to install three phase versions into distribution transformers to monitor power quality and load. This will be done in a prioritised manner targeting transformers that we suspect may be overloaded. This information will be made available to the organisation in real time and will assist in operation, maintenance and planning functions within the business. Figure 5-10: Smart Meter

142 5-28 SECTION 5 NETWORK DEVELOPMENT PLANS Real Time Monitoring Underground Circuits Due to the increasing complexity of the thermal relationships along cable routes, the ability to continuously measure the temperatures along the cable has proven invaluable, providing critical operational data to engineers, especially in the case of system faults such as a hot spot that could result in cable failure if they are not corrected. There are currently two types of technology available which are detailed below: The first type DTS utilises fibre optic cables and provides a temperature profile along an entire cable route continuously. This type of installation is to be used when new 33kV circuits are to be installed due to the high associated cost of retrofitting. The second type Thermal Resistivity & Moisture Sensors utilise sensors that are installed at specific hot spots along the cable route and will be used where the cable has been installed for a number of years and has no fibre call installed. Distributed Temperature Sensors The Distributed Temperature Sensing (DTS) system utilises fibre optic sensors. The sensor attached to the end of the fibre optic cable which is run alongside the 33kV cable, makes it possible to record the temperature profile along an entire cable route continuously, and is able to pinpoint the exact location of hot spots within a metre. Since the measuring principle employed is purely optical, the presence of electromagnetic influences, which can result in false sensor signals in other technologies, does not affect the DTS unit. Unison has a policy to install DTS capable fibre optic cable with all new underground 33kV cabling. Unison has purchased a portable DTS monitoring unit and is currently monitoring the Napier 1 & 2 33kV circuits between Onekawa switching station and Faraday substation. The unit will be left on these circuits for a full year in order to monitor temperature variations caused by seasonal load fluctuations and changes to the soil moisture content. The unit will then be moved to other circuits and the cycle repeated. This will assist in the planning of future sub-transmission cabling projects as well as identifying possible hot spots on existing circuits which may have the potential to develop into a future fault. Figure 5-11: DTS Overview

143 SECTION 5 NETWORK DEVELOPMENT PLANS 5-29 Thermal Resistivity & Moisture Sensors Thermal Resistivity Sensors calculate the soil s thermal resistivity by applying power to the heater element of the sensor and measuring the subsequent change in temperature of the soil at every 30 second interval for 30 minutes. The initial and the final measured temperatures are then used to calculate the thermal resistivity. Secondly soil moisture temperature sensors are used to measure the moisture of the soil. This will then be used in conjunction with the thermal resistivity data to come up with a thermal dry-out curve. Unison has deployed this technology on the City 33kV feeder between Windsor substation and the overhead termination structure off the end of Jubilee Street. Data from this trial is currently being collected, interpreted and evaluated in order to validate the results. A larger rollout of this technology is planned for this year. Overhead Lines Providing sufficient electrical power reliably requires ongoing monitoring of temperatures within overhead 33kV lines that are more susceptible to atmospheric changes than buried cables. There are a number of technologies available that provide real time overhead line monitoring. Unison has decided to introduce a lower cost option and will be installing weather stations along some of the main 33kV overhead lines. Weather Stations By installing a number of strategically placed weather stations in the immediate vicinity of overhead sub-transmission conductors, real time wind speeds, wind angles and ambient temperatures can be fed into an algorithm which processes this information and coupled with 2 hour weather forecasts can determine the dynamic rating of the line. This information can be supplied in real time to network operators and can be very useful during a contingency event where the lines static winter or summer rating may need to be exceeded for a period of time. This technology can be used to provide dynamic rating of either critical circuits or an entire sub-transmission network and is relatively inexpensive and highly reliable. Decisions on the upgrading or installation of lines are often based on thermal load. By deploying this technology Unison can accurately determine ratings which may result in the deferral of expensive line upgrades. Progress has been made on this initiative and it is planned to install a significant number of weather stations across Unison s (Hawke s Bay initially) strategic 33kV overhead network this year. Power Transformers Unison is utilising Transformer Monitoring Sensors (TMS) to measure factors that could impact on the set design rating of our power transformer fleet. New TMS systems are being retrofitted to existing transformers and new transformers are ordered with this functionality build in. The TMS sensors can provide the following functionality: Direct oil temperature monitoring; Direct winding temperature monitoring; Load monitoring; Gas monitoring. Progress has been made retrofitting existing transformers with this technology. It is expected that the remaining transformers on Unison s network will be completed this year.

144 5-30 SECTION 5 NETWORK DEVELOPMENT PLANS Powersense Sensors This technology uses state of the art current sensors to provide accurate current, voltage and fault passage information in real time over the mesh radio network back to Unison s information management systems. This equipment can be used on both overhead and underground reticulation. The underground current sensor can be attached non-invasively to MV cables making it an ideal solution for retrofitting to existing network equipment. Unison is currently trialing this technology and if successful will proceed with a larger rollout this year across its entire network. Figure 5-12: Powersense Current Sensor 5.6 Network Development Options Available Options Available Where the target security or reliability levels are not met, improvement options will be investigated. Engineering analysis and judgment is combined with Unison s network standards and systems to determine the following: Likelihood of the contingency under consideration; Cost of the improvement options; Impact of the energy/demand not served; Type of consumers affected. Economic analysis is completed on improvement options to ensure efficient network development and efficient prioritisation of reliability driven upgrades is achieved. Solutions generally fall into the following categories: Do Nothing - This option is normally associated with a thorough risk analysis and will only be considered if the risk is manageable. Non Network Solution A lower cost and in some cases only a short term solution. It provides Unison with time to plan more complex network solution, while deferring investment and mitigating the risk. Network Solution This solution is the conventional network strengthening solution and provides a long term solution. It is normally more expensive, but provides a higher level of security than non network solutions. The following tables provide a tool box with examples to resolve network constraints. It should be noted that solutions are not limited to the examples stated below:

145 SECTION 5 NETWORK DEVELOPMENT PLANS 5-31 Toolbox Constraint Network Solution Non Network Solution Voltage Constraints Upgrading conductor Install additional feeder Install voltage regulators Reactive VAr compensation Mobile technology Load transfer DG Capacity Constraints Upgrading conductor Install additional feeder Install additional transformer Establish new substation Reactive VAr compensation Load transfer DG Demand side Management Real Time Monitoring Breakers Exceeding Ratings Replace breaker Decrease fault level by: Quality of Supply e.g. dips, harmonics, flicker Network Security Install additional feeder Install additional substation transformer Install additional feeders Establish new substation Install additional transformer Install more re-closers Substation earthing compensation ( Network re-configuration DG Consumer specific behind the meter solutions (SVC) Replace mobile technology with reactive VAr compensation Re-configure the network Smart Technology DG Load transfer Reactive VAr compensation Demand Side Management Network reconfiguration Network Reliability Table 5-6: Network option toolbox Install re-closers Install additional feeders Intelligent re-closers Network re-configuration DG Substation earthing compensation Consumer specific behind the meter solutions Fast protection e.g. GFN Self Healing Meeting Service Level Targets A key driver in maintenance activities and project selection is the consideration of Unison s service level targets. One such example is the significant investment planned to replace unreliable cable in Hawke s Bay. Cable faults are major contributor to the number of events beyond the targeted three hours restoration for urban consumers. Augmentation projects are targeted to ensure capacity is available to meet projected load growth, so that connections can be made in a timely manner, satisfying developer needs and to support council interests of economic growth within their respective regions. A sub category of the augmentation investment, reliability, targets improvements to particular portions of the network infrastructure where security, the level of outages (e.g. ten worst feeders) or slow restoration are outside the targets listed in Section 4.

146 5-32 SECTION 5 NETWORK DEVELOPMENT PLANS Reliability, Safety, and compliance projects ensure statutory compliance is met to satisfy Regulator and Board needs. Renewal of assets before they cause environmental damage or represent a safety hazard also ensures compliance to Unison s health and safety obligations to regulators, employees and consumers. The varying price/quality thresholds with the geographic locations identified in Section 4 is also recognised in Unison s planning and security criteria as described above. These criteria help ensure Unison is balancing its investment activities against the service levels required by the various stakeholders. Unison actively monitors network performance against targets with regular meetings to review outages on a fortnightly basis. These meetings are attended by representatives from the wider business and cover investigation of failures, review of response times to outages, suitability of operational restoration procedures and options to improve network configuration to minimise recurrence and support improvements in future restoration. Network performance is a standard agenda item for the monthly meetings with contractors on Unison s network and in monthly reports to the Board.

147 SECTION 5 NETWORK DEVELOPMENT PLANS Network Development Plan Central Region Network Development Programme for 2011/12 Constraint Lack of ability to remotely restore supply to urban consumers following a feeder fault. Okere and Kaharoa feeders are two of the worst performing feeders, with a lack of automated switchgear to sectionalise and restore supply quickly. Description Through feeder reliability analysis Okere and Kaharoa feeders were identified as having a high number of faults and causing significant contribution towards SAIDI and SAIFI. Okere and Kaharoa are of double circuit configuration on the same pole structures for a significant distance. Faults caused by third parties, such as car vs pole incidents, tend to cause faults on both feeders. Further, both feeders have customer numbers in excess of 1,000. There are protection devices on these feeders, however, the ability to isolate the fault, and restore supply to the majority of the customers remotely is lacking. Possible Solutions Class of Option Description Advantages Disadvantages or Risks Cost Network Replace existing manual ABS with remote controlled switches Improves reliability. Ensures Unison s Service Level and Network Reliability Targets can be met. Remote controlled switches are more expensive than a standard ABS. $300k Provides useful planning information from these devices. Change double circuit network topology to single circuit topology Improves reliability. Ensures Unison s Service Level and Network Reliability Targets can be met. Second circuit will need to be undergrounded due to council planning rules in well established urban areas. $700k Easements may be required. Non-Network Implementing self healing technology. This will be implemented in conjunction with the remote controlled switches Improves reliability drastically. Restoration of supply to consumers within one minute. Provides useful planning information from devices. High initial set up cost. Line of sight communication is required between switches. Increase in maintenance costs due to additional equipment. $150k Install a Ground Fault Neutraliser (GFN) Improves reliability drastically, only for earth faults. Quicker identification of faults. Majority of the feeder faults on Rotorua feeders are not earth faults. $400k 3 One GFN per substation site. 3 Cost of installing a single Ground Fault Neutraliser unit

148 5-34 SECTION 5 NETWORK DEVELOPMENT PLANS Class of Option Description Advantages Disadvantages or Risks Cost Do Nothing Least cost option. Contribute towards and can lead to breaching Unison s Service Level and Network Reliability Targets. N/A Preferred Option & Justification The preferred solution to improve reliability on poor performing feeders is to replace existing manual ABSs with automated switches. These switches will also provide useful network planning data that will feed into simulation tools that are employed at Unison. This will give engineers greater ability to understand the load nature on each feeder. Installation of automated switches is also in alignment with Unison s intention to deploy smart networks in the Rotorua Region. The combined solution will improve the reliability drastically as the technology will isolate faulted areas and restore the remaining customers within one minute. These two solutions are considered as the long term solution to improve reliability in the region. The alternative options are discounted for the following reasons: Installation of a GFN is not favoured by Transpower at present as it falls outside of their solution toolbox. The feeders that have been identified as having poor reliability are supplied from Transpower s Owhata GXP. A GFN reduces some of the benefits of Self Healing Technology as earth faults do not require switching. The Self Healing Technology caters for all fault types and is cheaper to implement. Undergrounding one of the double circuits is far more expensive compared to the benefit that can be attained from this option.

149 SECTION 5 NETWORK DEVELOPMENT PLANS Kaharoa Feeder Dalbeth Feeder Replace Manual ABS with Remote controlled switch Figure 5-13: Kaharoa feeder automation

150 5-36 SECTION 5 NETWORK DEVELOPMENT PLANS Rotoma Feeder Kaharoa Feeder Okere Feeder Replace Manual ABS with Remote controlled switch Figure 5-14: Okere feeder automation

151 SECTION 5 NETWORK DEVELOPMENT PLANS 5-37 Constraint Load on Taupo North feeder inhibits security of supply in the surrounding area. Description Taupo North feeder is heavily loaded and has been identified as the most vulnerable feeder in the area by the analysis tools. Taupo North feeder supplies the diverse loads (rural, lifestyle, holiday homes etc) in the Kinloch area, and it is critical that security of supply is maintained especially during the summer holiday load peak. A lack of investment will lead to overloading of the Taupo North feeder, limit the ability to backstop an adjacent feeder given a feeder fault during peak load conditions, and is likely to contribute towards breaching Unison s service level targets for the urban customer classification detailed in Section 8.4. Possible Solutions Class of Option Description Advantages Disadvantages or Risks Cost Network Establish a new 11kV feeder from Runanga zone substation to Mapara Valley. Offloads identified capacity constrained feeder. Ensures feeders are compliant with Unison s security standards, well into the next planning period. Provides additional 11kV interconnectivity. Easements may be required. Requires installation of new circuit breaker at Runanga zone substation. High civil costs in areas that are already established. A long length of cable (approximately 4km) to be installed in urban areas. $1.5M Establish Kinloch Substation. Offloads identified capacity constrained feeders. Expensive. Easements required. $3-4M Ensures feeders are compliant with Unison s security standards, well into the next planning period. Uncertainty with delays in WEKA designation. May mean asset relocation. Provides additional 11kV interconnectivity. Provide new interconnection with a lightly loaded feeder from Runanga Z.S. and transfer load. Offloads identified capacity constrained feeders. Provides additional 11kV interconnection and flexibility to backstop. Due to network architecture, heavily loaded feeders cannot be offloaded substantially. Only a short term option, and will not meet security standards after 5 year period. $250k Easements are required as shorter cable route is through private properties. Non-Network Install pole top capacitor banks to minimise load flow on existing feeders. Cheaper compared to other options. Capacitors compensate for the reactive VAr flow boosting the voltage. Ideal location is hard to identify due to lack of customer installation data (e.g. consumption kw, kvar). $150k Lack of VAr requirements of the feeders. Another investment would be required to ensure feeder is compliant with security standards. Not a long term solution.

152 5-38 SECTION 5 NETWORK DEVELOPMENT PLANS Class of Option Description Advantages Disadvantages or Risks Cost Resonate with ripple signals. Encourage Distributed Generation (DG) Can mitigate present and future feeder capacity constraints. Long term benefits in deferral of capital expenditure. Connections are at ad hoc basis, and cannot be predicted. The connected DG may not be of reliable source such as renewal. Unknown 4 Purchase neighbouring distribution company assets (part of 11kV network) and establish a connection agreement Provides alternative 11kV supply. Improves reliability by splitting up the long, rural feeder. Secure supply to remote areas. Cheaper option. Conductor upgrade is required as the network assets are comprised of smaller conductors. An agreement between both parties is required. Unknown Do Nothing Operate assets up to their maximum limits Least cost option Limitation on back feed capabilities. N/A Non compliant with Unison s security standards. Preferred Option & Justification The long term solution is to establish a new substation at Mapara Road to cater for existing and future loads. There are still uncertainties around the load growth and the timing of the new motorway linking Kinloch and Taupo (WEKA). In the interim, Unison will implement a number of short term solutions. Provide new interconnection with a lightly loaded feeder from Runanga and transfer load. At present, the residential sub-division by Huka Falls is supplied from the Taupo North feeder, which is predominantly a rural feeder. The project proposes to shift the residential load from the Taupo North feeder to Ben Lomond feeder which is an urban feeder. This option would offload Taupo North and allow flexibility to back feed more of the Kinloch load in the event of a fault on Acacia Bay feeder. Install automated switchgear along the feeder to restore supply quickly. 4 DG projects are treated as customer projects and customer contributions are project specific

153 Figure 5-15: Taupo North feeder reconfiguration SECTION 5 NETWORK DEVELOPMENT PLANS 5-39

154 5-40 SECTION 5 NETWORK DEVELOPMENT PLANS Constraint Lack of feeder fault and load information on Rotorua, Tarukenga, Runanga, and Taupo South feeders. Description There is a lack of real time current, voltage and fault information to help planners understand the dynamics along the length of 11kV feeders. With real time information planners can identify capacity constraints and quality of supply issues on a real time basis. Operations can initiate quicker restorations with the additional information and thereby reduce outage durations. Possible Solutions Class of Option Description Advantages Disadvantages or Risks Total Cost Network Install earth fault indicators and temporary data loggers at strategic locations along the feeder route Inexpensive Gives approximate location of a fault between indicator points. Gives feeder load and fault current data if logger happens to be installed at time of fault. Needs personnel on site to identify approximate location of fault. Needs visit to site by technical personnel to setup data loggers and download fault and load current information. $ 40 k Information is not received in real time, it requires human intervention in the field. Non-Network Use data sensors at strategic locations to collect and convey data via the communications network to enable rapid transfer of loads to surrounding feeders Cost effective solution. Real time data available for Planners and Operators. Reduced restoration times. Can be integrated into fast transfer and self healing schemes. Can be used for self healing after network faults. Temporary solution (10-15 years) Increased network complexity. $ 375k Do Nothing Operate assets up to their maximum limits No capital investment required. Unison is likely to breach its service level targets and network reliability targets for the customers. N/A Preferred Option & Justification The preferred solution in the short term is to install current sensors at strategic locations on feeders originating from the above mentioned zone substations. The solution will improve reliability, as the technology will aid the location and isolation of faults and the restoration of supply to customers. These sensors will also provide useful network planning data that will feed into simulation tools that are employed at Unison. This will give the engineers greater ability to understand the load nature on each feeder and plan projects accordingly. Constraint Arawa substation is not compliant with Unison s security standards.

155 SECTION 5 NETWORK DEVELOPMENT PLANS 5-41 Description The peak load at Arawa substation is above the power transformer N-1 emergency rating. As this substation supplies urban and CBD consumers, it does not meet the security criteria. As a new substation has been built at Biak Street, it would be prudent to establish new feeders to offload Arawa feeders, thereby reducing peak load at the substation below the n-1 emergency rating. Possible Solutions Class of Option Description Advantages Disadvantages or Risks Cost Network Establish new 11kV feeders at Biak Street. Offloads identified capacity constrained feeders. Approximately 2 km of cable required. $700k Ensures feeders are compliant with Unison s security standards, well into the next planning period. Provides additional 11kV interconnectivity. Infrastructure already established such as ducts and circuit breakers. Non Network Demand side Management (Increase the ability to control hot water in the region) Reduces the feeder loads during peak load conditions. Deferral in reinforcement of cable. Requires the local retailers to replace ripple relays. N/A Install thermal resistivity sensors every 300m in the trench Increased asset utilisation during contingency scenarios for short periods. The feeder ratings may be lower than what is currently utilised. $100k Deferral of cable upgrade. Do Nothing Increase the asset utilisation of the transformers by using the existing transformer management system Least cost option. Customer outages are likely during fault condition. The feeder ratings may be lower than what is currently utilised. Hence will be overstressing the network. N/A Preferred Option The preferred long term solution is to install new feeder cables from Biak Street substation to offload Arawa substation. The infrastructure required to establish new 11kV feeders is already in place, along with spare ducts and circuit breakers. This limits the cost of installation, and makes this solution viable, and providing a long term solution by increasing the amount of 11kV interconnectivity and increased capacity headroom. However, due to the Rotorua District Council s Lake Road widening project, cables cannot be installed until the road works are completed. In the interim, temporary overhead lines will be established to solve the issue. A fast transfer scheme could not be employed as the available feeder capacities would render the scheme ineffective.

156 5-42 SECTION 5 NETWORK DEVELOPMENT PLANS Constraint Fleet Street substation is not compliant with Unison s security criteria. In addition to this, individual 11kV feeder faults tend to affect large numbers of customers in the Taupo region. Description Fleet Street substation is supplied by a radial 33kV feeder, with a single 33/11kV transformer. Unison s security criteria requires that urban customers should be supplied without an interruption longer than 30 minutes for a single contingency event. This is not possible with the current configuration at Fleet Street substation. In addition to this, a number of 11 kv feeders fed from Runanga substation feed more than 1000 customers each. Some of these feeders are on the same pole structures. Third party faults such as car versus pole incidents tend to affect both feeders, causing significant outages. There are protection devices on these feeders, but the ability to isolate faults and remotely restore supply is lacking. Possible Solutions Class of Option Description Advantages Disadvantages or Risks Cost Network Establish n-1 security of supply at Fleet Street Second 33/11kV transformer Second 33kV feeder Offloads identified capacity constrained feeders. Ensures feeders are compliant with Unison s security standards, well into the next planning period. Provides additional 11kV and 33kV interconnectivity. Requires installation of 33kV switchboard at Fleet Street substation. Requires installation of second transformer. High Cost. $3.5m Easements are not required as ducts have been installed in the new service corridor adjacent to the new Taupo bypass road. Establish additional 11kV feeders between Fleet Street and neighbouring Taupo South and Runanga substations. Offloads identified capacity constrained feeders. Ensures feeders are compliant with Unison s security standards, well into the next planning period. Provides additional 11kV interconnectivity. Can lead to significant outages. Will not provide n-1 security unless high network automation and feeders are installed. $750k Non Network Smart networks Rapidly transfer loads onto other networks during contingencies. Perform self healing after feeder faults. Provide more information about network loading that can be used to optimize the timing of further investments. Increase in network complexity. Slightly increased maintenance needs on the network. $1.2m

157 SECTION 5 NETWORK DEVELOPMENT PLANS 5-43 Class of Option Description Advantages Disadvantages or Risks Cost Install Ground Fault Neutraliser Improves reliability, but only works for earth faults. High unbalanced network in Taupo. $400k Quick location of faults. Only one GFN needed per substation. Do Nothing Least cost option. Lack of back feeding ability during contingencies N/A Breach Unison s security criteria. Preferred Option The short term solution is to use a smart network fast transfer scheme to restore supply to customers from surrounding zone substations if the transformer at Fleet Street substation should fail. This solution will be used as long as it makes good technical and financial sense. Unison will install an additional 33kV feeder and transformer beyond that point. The timing of the second feeder and transformer is dependent on load growth in the region. The smart switches will also provide useful network planning data that will feed into simulation tools that are used at Unison. This will give the engineers greater ability to understand the nature of loads on each feeder. Installing automated switches is also in alignment with Unison s intention to deploy Self Healing Technology in the Taupo Region. This solution will improve the reliability, as the technology will isolate faults and automatically restore supply to customers wherever possible Undergrounding is not regarded as a viable option as it is too expensive.

158 5-44 SECTION 5 NETWORK DEVELOPMENT PLANS Figure 5-16: Fleet Street fast transfer scheme

159 Figure 5-17: Fleet Street fast transfer scheme SECTION 5 NETWORK DEVELOPMENT PLANS 5-45

160 5-46 SECTION 5 NETWORK DEVELOPMENT PLANS Constraint There is a risk of high SAIDI 11kV feeder faults in the region. Description The Taupo 11kV Network has many interconnection points with several back feeds to most feeders in the urban and rural regions. However, there are many instances of double feeders on single pole structures. If there is an incident that affects one of these sections there is a chance of one fault affecting many customers. Possible Solutions Class of Option Description Advantages Disadvantages or Risks Cost Network Underground parts of feeders in the urban areas and introduce alternative Overhead paths in semi rural areas Non-Network Implementing self healing technology. This will be implemented in conjunction with the remote controlled switches Reduces the risk. Improves reliability. Can be used to address capacity constraints. Improves reliability. Automated restoration of supply to consumers within one minute. Provides useful planning information from devices. Enables automated load shifting based on seasonal profile. Improves the Radio Mesh network in the area which in turn improves coverage for smart metering. Very expensive. Geothermal areas will de-rate cables. High initial set up cost. Line of sight communication is required between switches. Increase in maintenance costs due to additional equipment. Do Nothing Least cost option. Contribute towards, and can lead to breaching Unison s Service Level and Network Reliability Targets. $5.6m $3.4m N/A Preferred Option & Justification The preferred solution is to implement a self healing scheme across the region. This option is ideal because of the inherent interconnectivity between the three major substations, Runanga, Fleet and Taupo South. This means that load can be shifted efficiently when faults occur. The self healing scheme effectively builds on the Taupo fast transfer project. It will increase the granularity of load transfer and improve automated fault response. The smart switches introduced by this project will allow for additional data gathering and aligns with Unison s intention of establishing a smart network in Taupo. The additional benefit to introducing these devices is that it will reinforce the Radio mesh network improving all other services in the region. The project will be implemented in several stages as shown in the diagram below. Two of these stages will be installed in 2011/12 and the remaining other two stages will be installed in 2012/13. The alternative options are discounted for the following reasons:

161 SECTION 5 NETWORK DEVELOPMENT PLANS 5-47 Undergrounding feeders is a tried and true method for improving system reliability. However, it is expensive and even more so in Taupo with geothermal hotspots requiring larger cable sizes. Section 4 Taupo Northwest 2012/13 Section 3 Taupo Northeast 2012/13 Section 2 Taupo Central 2011/12 Section 1 Taupo South 2011/12

162 5-48 SECTION 5 NETWORK DEVELOPMENT PLANS Constraint Security constraint at Owhata Point of Supply. Description Load growth over the years has led to an N-1 power transformer constraint at Owhata POS. The second transformer will trip on overload if one faults during peak load times. This can cause a major outage and can lead towards a breach of Unison s service level targets for urban customer classification detailed in section 8.4. Possible Solutions Class of Option Description Advantages Disadvantages or Risks Total Cost Network Upgrade the Transpower owned transformers Long term solution and will ensure substations are compliant with Unison s security standards for future planning periods. Significant costs involved replacing transformers i.e. high civil costs, replacing switchgear etc. $2m Creates capacity for future load growths. Renewal of assets. Non-Network Use smart network to rapidly transfer loads to surrounding zone substations Cost-effective solution. Can be used for self healing after network faults. Fully utilise existing transformers. Temporary solution (approx. 5 years). Increased network complexity. $200k Move normal open points between feeders to permanently shift loads Very low cost. Voltage regulation and conductor capacity limit scope. Bring forward more constraints on other parts of the network. N/A Encourage Distributed Generation (DG) Can mitigate present and future capacity constraints on the transformers. Connections are at ad hoc basis, and cannot be predicted. Unknown 5 Long term benefits in deferral of capital expenditure. The connected DG may not be a reliable source such as renewal. Do Nothing Operate assets up to their maximum limits No capital investment required. Unison is likely to breach its service level targets and network reliability targets for the customers. N/A Preferred Option & Justification The preferred solution consists of a mixture: 5 DG projects are treated as customer projects and customer contributions are project specific

163 SECTION 5 NETWORK DEVELOPMENT PLANS In the short term, Unison will install a fast transfer scheme (smart network) to rapidly transfer excess load to Arawa zone substation if one of the transformers at Owhata should trip. 2. The long term solution is being discussed with Transpower. Options being considered include the upgrading of transformer capacity at Owhata GXP, or the construction of Vaughan Road substation. Upgrading the GXP transformers will impact the need and timing to construct Vaughan Road substation, and vice versa. Figure 5-18: Owhata fast transfer scheme

164 5-50 SECTION 5 NETWORK DEVELOPMENT PLANS Constraint Currently in the Central Region there is no complete secondary communication network in place to enable the transfer of critical data from network devices in the field to Unison s centralised information management system. Without this communication network, Unison would be unable to implement the Distribution Automation (DA) projects detailed in this section. Description Unison is implementing a number of DA (fast transfer / self healing) projects in the central region which is reliant on a secondary communication network to operate. In order to transfer critical data between network devices installed on the network and Unison s information systems thereby enabling these DA projects, a secondary communication network is required. Possible Solutions Class of Option Description Advantages Disadvantages or Risks Total Cost Network Mesh Radio Both DA & AMI Capable. Scalable. Able to prioritize critical data. Operates in free unlicensed bandwidth. Self healing. Good range. Acceptable latency. IP capable backhaul network required. $885K WiMax High data transfer rates. Both DA & AMI Capable. No additional backhaul network required. Radio band licensed and would require commercial arrangement with existing users/ owners. Unknown Not ideal for hilly topography. IP interface required for each AMI or DA device. Limited range. Cellular / GPRS Both DA & AMI Capable. IP interface required for each AMI or DA device. Unknown Limited coverage. Reliant on third party provider. Power Line Carrier (PLC) Low Cost. Limited range subject to frequency. Unknown Lower frequency option has increased range but very low data transfer rates (high latency). Technology still under development and not proven. Not suitable for transfer of IP data streams.

165 SECTION 5 NETWORK DEVELOPMENT PLANS 5-51 Class of Option Description Advantages Disadvantages or Risks Total Cost Do Nothing Have no secondary communication network No capital investment required. DA projects will not operate and all the advantages / benefits of implementing these schemes will not be realised. In addition Unison will be exposed to the disadvantages / risks associated with these projects not proceeding. N/A Preferred Option & Justification The preferred solution is to establish a backbone mesh radio secondary communication network as an enabler for the distribution automation (DA) and any future AMI projects: The mesh radio network will encompass all DA projects detailed in this plan and be capable of being extended as required to include future DA and AMI initiatives. After a robust selection process the Landis+Gyr Series IV Gridstream product was selected as the secondary communication mesh radio solution that will be deployed on Unison s network.

166 5-52 SECTION 5 NETWORK DEVELOPMENT PLANS Network Development Programme for the period 2012/13 to 2016/17 In this section of the AMP, a preferred long term network solution is provided based on the data and models that are currently in place at Unison. However, Unison acknowledges that the outlined plans may change due to the following reasons: Forecast load may not materialise as predicted; Forecast load growth is well below what was predicted; The impact of the non-network solutions are yet to be understood; Uncertainty around new DG connections; Other new technologies that are not in production may be opted as alternatives; Network reconfigurations; Change in customer needs and land use. Constraint Lack of feeder fault and load information on Rotorua, Biak, Owhata and Arawa feeders. Description There is a lack of real time current, voltage and fault information to help planners understand the dynamics along the length of 11kV feeders. With real time information planners can identify capacity constraints and quality of supply issues on a real time basis. Operations can initiate quicker restorations with the additional information and thereby reduce the outage durations. Possible Solutions Class of Option Description Advantages Disadvantages or Risks Total Cost Network Install earth fault indicators and temporary data loggers at strategic locations along the feeder route Inexpensive. Gives approximate location of a fault between indicator points. Gives feeder load and fault current data if logger happens to be installed at time of fault. Needs personnel on site to identify approximate location of fault. Needs visit to site by technical personnel to setup data loggers and download fault and load current information. $ 40 k Information is not received in real time, it requires human intervention in the field. Non-Network Use data sensors at strategic locations to collect and convey data via the communications network to enable rapid transfer of loads to surrounding feeders Cost-effective solution. Real time data available for planners and operators. Reduced restoration times. Can be integrated into fast transfer and self healing. Can be used for self healing after network faults. Temporary solution (10-15 years). Increased network complexity. $ 620 k Do Nothing Operate assets up to their maximum limits No capital investment required. Unison is likely to breach its service level targets and network reliability targets for the customers. N/A

167 SECTION 5 NETWORK DEVELOPMENT PLANS 5-53 Preferred Option & Justification The preferred solution in the short term is to install current sensors at strategic locations on feeders originating from the above mentioned zone substations. The solution will improve reliability, as the technology will expedite to the location and isolation of faults, and the restoration of supply to customers. These sensors will also provide useful network planning data that will feed into simulation tools that are employed at Unison. This will give the engineers greater ability to understand the load nature on each feeder and plan projects accordingly. Constraint During peak load conditions, a number of feeders are forecast not to comply with 11kV voltage regulation levels. Description Through network analysis and modeling, Ngakuru, Kaharoa, Mamaku, Tarawera, Waikato, and Waikete feeders have been identified as having poor 11kV voltage regulation within the next five years. A number of feeders already have a voltage regulator installed on the backbone, however, a second regulator is likely to be installed unless alternative nonnetwork solutions are implemented. A lack of investment to rectify the constraint would mean an increase in customer complaints due to low voltage. Possible Solutions Class of Option Description Advantages Disadvantages or Risks Cost Network Install voltage regulator to improve the 11kV voltage Can be used to solve the voltage constraint irrespective of the load type (inductive, resistive etc). Can cater for long term load growth on the feeder. Expensive. Easements are required at optimal sites. Add additional load on the feeder. $200k each Upgrade conductor Can solve the problem long term and thereby improving back feed reliability. Can cater for long term load growth on the feeder. Very expensive. Easements are required. Substantial amount of conductor upgrade is required on all 3 feeders (approximately 5-10km). $1.2M Non-Network Install capacitor banks Cheapest option. Provide reactive VAr to high reactive loads, thereby reducing the feeder load current. Can be used only near inductive loads. Amplify harmonics and may cause resonance. Can interfere with ripple load control signal. Variable voltage control is not possible. $100k

168 5-54 SECTION 5 NETWORK DEVELOPMENT PLANS Class of Option Description Advantages Disadvantages or Risks Cost Install mobile regulators during peak loading conditions Can provide voltage support during peak demand period. Can be relocated to other parts of the network. Provides flexibility in carrying out maintenance or planned work instead of load dependent. Consent is required from local authorities, Iwi or Transit. Health and safety issues associated. $200k each Do Nothing No capital investment required. The feeders will not comply with the voltage regulations. N/A Increase in customer complaints due to under voltage. Preferred Option The preferred solution is to install voltage regulators on Ngakuru, Mamaku, Tarawera and Waikite. Unison will investigate alternative technologies to measure reactive energy requirements, particularly on Mamaku feeder which has an industrial consumer.

169 SECTION 5 NETWORK DEVELOPMENT PLANS 5-55 Constraint Lack of security of supply to Fonterra Milk Processing Plant at Reporoa. Description Fonterra s Reporoa milk processing plant is supplied by Unison s Fernleaf substation, approximately 40km from Rotorua GXP. This substation is supplied via a single 33kV line feeder which runs through undulating terrain and vegetation. Historically, there have been a number of outages attributed to weather conditions (lightning and wind), trees, and insulator failures. The latter is harder to locate and attend to which prolongs the outage time. At Unison s request, Transpower has enabled the fault distance locator on the circuit breaker at the Rotorua GXP. Although these solutions reduce the outage time, it still causes disruption to Fonterra s production. Fonterra have requested options for an improvement in security of supply, to cater for existing and future load. Possible Solutions Class of Option Description Advantages Disadvantages or Risks Cost Network 33kV Supply from Wairakei via Ohaaki Increased security of supply at Fernleaf substation (N-1). Provides high reliability to the customer. Secure 33kV supply from Wairakei. Agreement with Contact Energy and local iwi is required to establish 33kV infrastructure by Transpower. The land parcel is owned by local iwi. $3-4M Transpower do not have a lease with the local iwi. Easement required to build 33kV circuit between Ohaaki and Fernleaf. Longer feeder route (14km). 33kV Supply from Ohaaki Increased security of supply at Fernleaf substation (N-1). Provides high reliability to the customer. Agreement with Contact Energy and local iwi is required to establish 33kV infrastructure by Contact Energy and Unison. $3-5M Secure 33kV supply from Ohaaki. Upgrade of Contact Energy s infrastructure. Easement required to build 33kV circuit between Ohaaki and Fernleaf. Longer feeder route (14km). 33kV Supply from Otto Road Increased security of supply at Fernleaf substation (N-1). An agreement is required with Trustpower. $5-6M Provides high reliability to the customer. Short 33kV feeder route (5km). Very expensive as 110kV/33kV station is required. New 33kV Feeder from Rotorua GXP Increased security of supply at Fernleaf substation (N-1). Provides high reliability to the customer. Secure 33kV supply from Rotorua GXP. High maintenance and first response cost due to terrain and weather related faults. New infrastructure at Rotorua GXP is required. Fault detection will be difficult. $8M

170 5-56 SECTION 5 NETWORK DEVELOPMENT PLANS Class of Option Description Advantages Disadvantages or Risks Cost Fast protection cannot be implemented due to distance. New 11kV Feeder from Ohaaki Cheaper option. Customer will experience low voltage. $2M Does not provide the same security as other 33kV options. Easement is required. Non-Network Install 6 x 700kVA diesel generators - (Onsite generation) Secure supply. Make before break solution. High running cost. Running time reliant on diesel reserve. $2-3M 6 Environmental issues involved. Do Nothing Least cost option. Strains relationship with one of Unison s largest consumer. N/A Preferred Option & Justification Unison has opted to construct a new 33kV line from Ohaaki to Fernleaf substation. This line will bypass Ohaaki substation to avoid the land issues discussed in the table above. The options to supply from Ohaaki are discounted mainly due to high costs, unknown costs and the uncertainty surrounding the land issues. Establishing a new supply from Otto Road was considered as it provides a shorter 33kV route to Fernleaf substation. Again, this was discounted as the cost of a 110/33kV substation is high. Unison will purchase the Transpower owned 33kV line between Wairakei and Ohaaki, and extend the 33kV network up to the Fernleaf substation along SH5 (approximately 14km). The Fernleaf substation will be reconfigured to cater for the additional feeder. Unison sees the purchase of the Wairakei to Ohaaki line providing benefits solving Fonterra s security of supply constraint, and providing a long term option for the Reporoa area due to load growth. It is proposed that Unison will establish a new zone substation near Te Toke Road to cater for the growing dairy load. 6 Does not include running costs

171 Figure 5-19: Overview of existing and proposed network assets Reporoa SECTION 5 NETWORK DEVELOPMENT PLANS 5-57

172 5-58 SECTION 5 NETWORK DEVELOPMENT PLANS Constraint High load growth on Ohaaki feeders due to new dairy loads. Description There is substantial dairy load growth expected in the next seven years around Broadlands and SH5. The existing feeders cannot cater for the magnitude of the growth as the feeder loads are predicted to exceed their ratings and are forecast to have non-compliant 11kV voltage. Additional feeders cannot be installed from Ohaaki POS because the land is not owned by Transpower, nor do they have any lease agreements with the local Iwi. Transpower have indicated that the likelihood of establishing feeders is unlikely due to the land ownership issues. Possible Solutions Class of Option Description Advantages Disadvantages or Risks Cost Network Upgrade constrained section of the feeder Provides spare capacity on the feeder until end of planning period for present load. Cheaper as 11kV reticulation is simple (approx 100m) cable. Can cater load growth only up to Does not provide backstop flexibility due to high load and limited 11kV interconnectivity. $150k Easement is required. Establish new feeder from Ohaaki POS Offloads identified capacity constrained feeders. Ensures feeders are compliant with Unison s security standards, well into the next planning period. Provides additional 11kV interconnectivity. Easements are required. Requires installation of new CB at Ohaaki zone substation. Approximately 5km of cable is to be installed. $750k Establish a new zone substation at Te Toke Road. Offloads identified capacity constrained feeders. Ensures feeders are compliant with Unison s security standards, well into the next planning period. Substantial investment. Requires land purchase for zone substation site $3M Provides additional 11kV interconnectivity. No major easements required. Non Network Install pole top capacitor banks to reduce the demand on feeders. Cheaper compared to other options. They compensate the reactive VAr and thereby solve the problem rather than just boosting the voltage. Ideal location is hard to identify due to lack of customer installation data (e.g. consumption kw, kvar). $100k Lack of VAR requirements of the feeders. Another investment would be required to ensure feeder is compliant with security standard. Not a long term solution.

173 SECTION 5 NETWORK DEVELOPMENT PLANS 5-59 Class of Option Description Advantages Disadvantages or Risks Cost Install thermal resistivity sensors every 300m in the trench Increased asset utilisation. Deferral of cable upgrade. The feeder ratings may be lower than what is currently utilised. $100k Deferral of load cannot be sustained to cater for load growth. Do Nothing Least cost option. Currently acceptable, but will increase to an unacceptable level within the next two years with organic load growth. N/A Preferred Option The long term solution for the identified constraint is to establish Te Toke substation. This solution provides additional 11kV feeders and interconnectivity in the area where the load growth is expected. Any network alteration is not possible at Ohaaki due to land issues and the distance to the load growth. Upgrading the constrained section of the feeder does not provide a long term solution. The load forecast model indicates that the upgraded feeders will not have sufficient capacity to supply the loads and meet backstopping requirements for neighbouring feeders..

174 5-60 SECTION 5 NETWORK DEVELOPMENT PLANS Figure 5-20: Proposed Te Toke substation

175 SECTION 5 NETWORK DEVELOPMENT PLANS 5-61 Constraint High industrial load growth in the outskirts of Rotorua. Description High load growth is expected in the outskirts of Rotorua with commercial, light industrial and recreational loads. Furthermore, an existing industrial customer has indicated the likelihood of disestablishing their embedded generation, which will have to be supported by the 11kV network. The expected load growth is likely to be 5-10MVA. There is a single 11kV supply that supports the existing industrial customer with one backstop, namely Ngakuru feeder. As described earlier, Ngakuru feeder is forecast to have a voltage constraint in the next 5 years. Possible Solutions Class of Option Description Advantages Disadvantages or Risks Cost Network Establish new feeders from Rotorua POS Offloads identified capacity constrained feeders. Ensures feeders are compliant with Unison s security standards, well into the next planning period. Provides additional 11kV interconnectivity. Easements are required. Requires installation of new circuit breakers at Rotorua zone substation. Approximately 3km of cable is to be installed. High civil costs in areas that are already established. $2M Two feeders are required to meet the load growth. Establish a substation near the industrial customer Offloads identified capacity constrained feeders. Easement is required to establish 33kV supply. $3-4M 7 Ensures feeders are compliant with Unison s security standards, well into the next planning period. Provides additional 11kV interconnectivity. No major easements required Customer driven project. Do Nothing Least cost option. Missed revenue opportunity. N/A Strains relationship with one of Unison s largest consumers. Preferred Option The preferred solution is to establish a new substation in close proximity to the industrial customer. This provides an improved security of supply and ample capacity for the existing industrial customer and forecast load growth. Unison has already upgraded the line to the customer to 33kV construction and operates it at 11kV. This solution is preferred by 7 Customer contribution is yet unknown

176 5-62 SECTION 5 NETWORK DEVELOPMENT PLANS the customer due to increased reliability, capacity, and cost. There is no viable non network solution available to cater for the load growth. Constraint Capacity and security of supply risks are identified for the Transpower 110kV network. Description A number of Rotorua substations, namely Arawa, Biak Street, Fernleaf, and Rainbow, along with Rotorua GXP 11 kv loads are supplied from the Rotorua GXP at Malfroy Road. The forecast loads of these substations are expected to exceed the N-1 emergency rating of the 110kV circuits supplying Rotorua. Possible Solutions Class of Option Description Advantages Disadvantages or Risks Cost Network 1. Establish new 33kV connection at Owhata GXP 2. Establish new substation on eastern side of Rotorua 3. Establish 11kV feeders between Arawa and the new substation Offloads identified capacity constrained feeders. Ensures feeders are compliant with Unison s security standards, well into the next planning period. Provides additional 11 and 33kV interconnectivity. Easements required for 33kV supply. High cost. Longer 11kV network towards northern end of Rotorua from the new zone substation. Additional investment to rectify non compliant 11kV voltage is required. $6M Upgrade dual 110kV circuits into Rotorua Ensures feeders are complaint with Unison s security standards, well into the next planning period. High costs for easements and structural work. $7-8M Non Network Use smart network to shift loads between GXP s when needed Relatively low cost option The smart network can perform self healing after faults on 11 kv feeders. Not a permanent solution. The quantity of load that can be transferred may be insufficient. TBD Owhata transformers already loaded beyond their n-1 capacity. Install capacitor bank at substations to reduce load flow in the feeders They improve the capacity and voltage levels. Offloads identified capacity constrained feeders. New circuit breaker at Arawa substation must be installed. Harmonic resonance can be a problem. $150k Do Nothing Least cost option. Customer outages can be expected if a fault occurs during peak load periods. N/A Preferred Option

177 SECTION 5 NETWORK DEVELOPMENT PLANS 5-63 Unison is currently discussing multiple options as part of a regional plan with Transpower. One customer in particular is planning a large load increase, which could absorb a significant portion of the marginal spare capacity currently available on these 110 kv circuits Network Development Programme for 2017/18 until 2020/21 As with section , a preferred long term network solution is provided for the above-mentioned planning period due to the following reasons. Forecast load may not materialise as predicted; Forecast load growth is well below what was predicted; The impact of the non-network solutions are yet to be understood; Uncertainty around new DG connections; Other new technologies that are not in production that may be opted as alternatives; Network reconfigurations; Change in customer needs and land use.

178 5-64 SECTION 5 NETWORK DEVELOPMENT PLANS Constraint High load growth in the Kinloch and Mapara region and poor reliability to existing customers in Kinloch. Description High load growth is forecast by local developers and Taupo District Council in the Mapara and Kinloch region. The existing farm land will be converted to commercial and residential loads within the next 5-10 years and the load increase is forecast to be 3-5MVA. The development is fast-tracked by the proposed new highway linking Kinloch with Taupo called WEKA (Western Kinloch Arterial). There are currently two feeders that supply the Mapara and Kinloch regions. Both of these feeders are approximately 10km from Runanga zone substation. As discussed earlier, the region has poor security of supply due to lack of backup supplies, and the 11kV voltage regulation is poor when back feeding during contingency scenarios. The existing supply will not be adequate to support the new load growth, and provide a secure supply to the new residential and commercial customers. Possible Solutions Class of Option Description Advantages Disadvantages or Risks Cost Network Establish a new 11kV feeder from Runanga zone substation to Mapara Valley. Offloads identified capacity constrained feeders. Ensures feeders are compliant with Unison s security standards, well into the next planning period. Provides additional 11kV interconnectivity. Easements may be required. Requires installation of new circuit breaker at Runanga zone substation. High civil costs in areas that are already established. Approximately 10km of cable network is to be installed. $ 1.5M Establish Kinloch Substation. Offloads identified capacity constrained feeders. Ensures feeders are compliant with Unison s security standards, well into the next planning period. Substantially expensive. Easement required. Uncertainty with delays in WEKA designation. May mean asset relocation. $3-4M Provides additional 11kV interconnectivity. Install mobile generators during contingencies Ensures feeders are compliant with Unison s security standards. Can mitigate present and future feeder capacity constraints. High running cost. Not a long term solution. Environmental issues associated. $50k Long term benefits in deferral of capital expenditure. Non Network Install pole top capacitor banks to minimize load flow on existing feeders. Cheaper compared to other options. They compensate the reactive VAr and thereby solve the problem rather than just boosting the voltage. Ideal location is hard to identify due to lack of customer installation data (i.e.: consumption kw, kvar). Lack of VAr requirements of the feeders. Another investment would be required to ensure feeder is compliant with security standard. $150k Not a long term solution.

179 SECTION 5 NETWORK DEVELOPMENT PLANS 5-65 Class of Option Description Advantages Disadvantages or Risks Cost Resonate with ripple signals. Connect to the neighboring distribution company assets (11kV network) and establish a connection agreement Provides alternative 11kV supply. Improves reliability by splitting up the long, rural feeder. Secure supply to remote areas. Cheaper option. Conductor upgrade is required as the network assets are comprised of smaller conductors. An agreement between both parties is required. Do Nothing Least cost option. Unison is likely to breach its service level and network reliability targets for the customers. Unknown N/A Preferred Option The long term solution is to establish a new substation at Mapara Road to cater for existing and future loads. Unison owns a suitable site for the zone substation. There are still uncertainties around the load growth and the timing of the new motorway linking Kinloch and Taupo (WEKA). In the interim, Unison will implement a number of short term solutions. Install automated switchgear along the feeder to restore supply quickly; Install mobile generators during peak load conditions (December) for contingency scenarios. These solutions are detailed in Section The main benefit of this long term solution is that the existing long rural feeders such as Waikato, Taupo North and Acacia Bay can be sectionalised and shortened in length with reduced customer numbers. This will increase the 11kV interconnectivity in the region, which is currently inadequate.

180 5-66 SECTION 5 NETWORK DEVELOPMENT PLANS Reporoa Network Architecture Long Term View ROTORUA GXP 33kV ROTORUA Rainbow ATIAMURI 11kV Fernleaf Key Proposed Circuit Existing Circuit Proposed Substation Ohaaki Existing Substation/TP 11kV supply Te Toke WAIRAKEI GXP 33kV Figure 5-21: Reporoa 33kV sub-transmission - proposed

181 Figure 5-22: Overview of existing and proposed network assets Reporoa SECTION 5 NETWORK DEVELOPMENT PLANS 5-67

182 5-68 SECTION 5 NETWORK DEVELOPMENT PLANS Rotorua Network Architecture Long Term View ROTORUA GXP 33kV ROTORUA 11kV Arawa Biak Street TARUKENGA 11kV feeders 2016 State Mill Road TBA Rainbow Vaughan Road Fernleaf Key Proposed Circuit Existing Circuit Proposed Substation OWHATA GXP 33kV OWHATA Existing Substation/TP 11kV supply Figure 5-23: Rotorua 33kV sub-transmission - proposed

183 Figure 5-24: Overview of existing and proposed network assets - Rotorua SECTION 5 NETWORK DEVELOPMENT PLANS 5-69

184 5-70 SECTION 5 NETWORK DEVELOPMENT PLANS Taupo Network Architecture Long Term View WAIRAKEI GXP 33kV Kinloch Tauhara Binary Plant Rotokawa Centennial Drive Switching Runanga Fleet Street Taupo South Legend Proposed Circuit Existing Circuit Hinemaiaia Proposed Substation Existing Substation/TP 11kV Figure 5-25: Taupo 33kV sub-transmission - proposed

185 Figure 5-26: Overview of existing and proposed network assets Taupo SECTION 5 NETWORK DEVELOPMENT PLANS 5-71

186 5-72 SECTION 5 NETWORK DEVELOPMENT PLANS Hawke s Bay Network Development Programme for 2011/12 Constraint Capacity and security issues on Camberley Zone Substation Feeders. Description A number of feeders out of Camberley zone substation do not comply with Unison s security criteria. In particular, Nottingley and Orchard are heavily loaded and Orchard is a backup for the Hawke s Bay Hospital feeder. Due to lack of interconnectivity with feeders from neighboring substations, two out of the five feeders have security constraints. If no action is taken it will lead to overloading of the feeders, limit the ability to backstop an adjacent feeder given a feeder fault during peak load conditions, and is likely to contribute towards breaching Unison s service level targets for the urban customer classification detailed in Section 8.4. Possible Solutions Class of Option Description Advantages Disadvantages or Risks Cost Network Establish new feeder out of Camberley Zone Substation Offloads identified capacity constrained feeders. Ensures feeders are compliant with Unison s security standards, well into the next planning period. Provides additional 11kV interconnectivity. High civil costs in areas that are already established. Requires installation of a new 11kV Circuit Breaker and associated panels at Camberleyy zone substation. Requires the building to be extended and additional land purchased. $ 1.5M Approximately 2 km of cable is to be installed to fully utilize the new feeder. Upgrade the front end section of the four feeders out of the substation (approximately 380m) Provides spare capacity on the feeders until end of planning period for present and forecast load. All but one feeder share the same trench, thereby reducing the civil costs. Disruption to existing 33 kv and 11kV feeders in the same trench and foreseen outages during works. $ 575k Provide new interconnection with a lightly loaded feeder and transfer load Offloads identified capacity constrained feeders. Provides additional 11kV interconnection and flexibility to backstop. Due to network architecture, heavily loaded feeders cannot be offloaded substantially. Only a short term option, and will not meet security standards after 3 years. $ 650k Easements are required as shorter cable route is through private properties.

187 SECTION 5 NETWORK DEVELOPMENT PLANS 5-73 Class of Option Description Advantages Disadvantages or Risks Cost Non-Network Encourage Distributed Generation (DG) Increase the ability to control hot water in the Camberley area Can mitigate present and future feeder capacity constraints. Long term benefits in deferral of capital expenditure. Reduces the feeder loads during peak load conditions. Deferral in reinforcement of cable. Connections are at ad hoc basis, and cannot be predicted. The connected DG may not be of reliable source such as renewal. Requires the local retailers to replace ripple relays. Do Nothing No capital investment required. There are major security issues at present in this area which if not looked at could cause a big outage if a fault occurs. Unknown 8 Ongoing N/A Preferred Option & Justification The preferred option is to upgrade the front end of the feeders from the zone substation through to Omahu Road (380m). By upgrading the front end of the feeders with 3c 300mm 2 Al XLPE MDPE, their current carrying capacity nearly doubles as the existing cables ( 3C 0.25in 2 Al PILC) are too small. Economically, this option is attractive as all but one the feeders that require upgrade run in the same trench. This option has been chosen over network options 1 and 3 due to cost and this will provide spare capacity for future load growth and resolves the existing security constraints on these feeders and to provide spare headroom capacity. The increase in capacity of the feeders will allow the future installation of a smart network fast transfer scheme. The figure below shows the extent of this project. 8 DG projects are treated as customer projects and customer contributions are project specific

188 5-74 SECTION 5 NETWORK DEVELOPMENT PLANS Legend Orchard Nottingley Omahu Raupare Upgrade front end of 11kV feeders. Install 3C 300mm 2 AL Orchard Road Figure 5-27: Proposed Feeder Upgrade - Camberley Zone Substation

189 SECTION 5 NETWORK DEVELOPMENT PLANS 5-75 Constraint Capacity and security constraints on Clive Feeder. Description There is an existing security and capacity constraint on both Clive and Haumoana feeders. This means there is not sufficient spare capacity on either feeder to offload during peak load and they do not comply with Unison s security criteria. Growth in the Brookvale area through which the Clive feeder passes, will add more load to this feeder. The peak load during 2010/11 financial year on Clive and Haumoana feeders was 4.47 MVA (110% of rated capacity) and 3.68 MVA (106% of rated capacity) respectively. Possible Solutions Class of Option Description Advantages Disadvantages or Risks Cost Network Upgrade frontend of Clive and Haumoana Feeders Ensures compliance with Unison s capacity security standards, well into the next planning period. High civil costs in areas that are already established. 2.4 km of circuit will need to be upgraded. $ 780k Establish a new 11kV Feeder out of Rangitane Zone Substation Permanently reduce Clive feeder load by offloading a section of Clive feeder. Provide additional capacity to offload Haumoana feeder loads at peak times. Will allow the use of Smart Grid to transfer Haumoana load to the New and Clive feeders. Requires an additional Circuit Breaker installed at Rangitane ZS. High civil costs in areas that are already established, as 0.75 km of circuit will need to be installed. $ 350k Create interconnection between of Clive and Haumoana Feeders. Smart grid enabler for technologies like self healing by increasing connectivity between feeders. Deferral in reinforcement of cable. Short-medium term solution only. Will require reinforcement in three years time. Both feeders have capacity constraints. $110k Non-Network Shift load through 11kV feeders during peak load times Reduces the load on the Clive feeder thereby keeping the load within the existing ratings of the circuit. Difficult to shift load around as the feeders connected do not have adequate spare capacity to offload Clive feeder. N/A Do Nothing No capital investment required. Unison is likely to breach its service level targets and network reliability targets for the customers. Missed revenue opportunity. N/A Preferred Option & Justification The preferred solution is to install an additional feeder out of Rangitane zone substation and interconnect to the 11kV network at Station Road. This will effectively offload 2.75 MVA from Clive feeder which will resolve the existing capacity and security issues and enable the new feeder to support Clive and Haumoana feeders. The increased capacity will enable a fast transfer or self healing smart network scheme to be installed in the future.

190 5-76 SECTION 5 NETWORK DEVELOPMENT PLANS The figure below shows the extent of the project. New Feeder - Install 3C 300mm 2 Al XLPE Interconnection with 11kV New CCC switch Figure 5-28: Proposed New Feeder Route Rangitane Zone Substation

191 SECTION 5 NETWORK DEVELOPMENT PLANS 5-77 Constraint Capacity and Security constraints on Haumoana feeder. Description Load growth over the years has led to capacity and security constraints on Haumoana feeder during peak load times. This can cause outages and may lead towards a breach of Unison s service level targets for urban customer classification detailed in section 8.4. Possible Solutions Class of Option Description Advantages Disadvantages or Risks Total Cost Network Upgrade Haumoana and its adjacent 11kV feeders. Long term solution and will ensure feeders are compliant with Unison s security standards for future planning periods. Creates capacity for future load growth. High civil costs in areas that are already established. 2.4 km of circuit will need to be upgraded. $ 780k Renewal of assets. Non-Network Use smart network to rapidly transfer loads to surrounding feeders. Cost-effective solution. Can be used for self healing after network faults. Fully utilise adjacent feeders. Temporary solution (10-15 years). Increased network complexity. Reliant on the new feeder from Rangitane ZS project to proceed. $ 422k Move normal open points between feeders to permanently shift loads. Very low cost. Voltage regulation and conductor capacity limit scope. Bring forward more constraints on other parts of the network. N/A Encourage distributed generation (DG). Can mitigate present and future capacity constraints on the transformers. Long term benefits in deferral of capital expenditure. Connections are at ad hoc basis, and cannot be predicted. The connected DG may not be a reliable source such as renewal. Unknown 9 Do Nothing Operate assets up to their maximum limits. No capital investment required. Unison is likely to breach its service level targets and network reliability targets for the customers. N/A Preferred Option & Justification The preferred solution in the short term, is to install automated switches that integrate with a fast transfer scheme (smart network) to rapidly transfer excess load to adjacent 11 kv feeders and zone substations. The long term solution will be to upgrade this feeder and adjacent feeders. 9 DG projects are treated as customer projects and customer contributions are project specific

192 5-78 SECTION 5 NETWORK DEVELOPMENT PLANS The figure below shows the extent of the project. Installation of ENTEC Switch Clive Feeder Installation of Safelink Switch Haumoana Feeder Brookvale Feeder Waimarama Feeder Figure 5-29: Proposed location Automated Switches Haumoana Feeder

193 SECTION 5 NETWORK DEVELOPMENT PLANS 5-79 Constraint Reliability of Pakowhai feeder. Description Pakowhai feeder has had a number of faults in the last 5 years. The reliability of the feeder can be improved by installing automated remote controlled switches. This will lead towards compliance with Unison s service level targets for urban customer classification detailed in section 8.4. Possible Solutions Class of Option Description Advantages Disadvantages or Risks Total Cost Network Replace existing ABS s with Remote Controlled Switches. Improves reliability. Ensures Unison s Service Level and Network Reliability Targets can be met. Expensive. $ 185k Provides useful planning information from these devices. Non-Network Use smart network to rapidly transfer loads to surrounding feeders. Cost-effective solution. Can be used for self healing after network faults. Temporary solution (10-20 years). Increased network complexity. $350k Move normal open points between feeders to permanently shift loads. Very low cost. Voltage regulation and conductor capacity limit scope. Bring forward more constraints on other parts of the network. N/A Encourage Distributed Generation (DG). Can mitigate present and future capacity constraints on the transformers. Long term benefits in deferral of capital expenditure. Connections are on an ad hoc basis, and cannot be predicted. The connected DG may not be a reliable source such as renewal. Unknown 10 Install Ground Fault Neutraliser (GFN). Improves reliability drastically, only for earth faults. One GFN per substation site. $450k 11 Quicker identification of faults. Do Nothing Operate assets up to their maximum limits. No capital investment required. Unison is likely to breach its service level targets and network reliability targets for the customers. N/A Preferred Option & Justification The preferred solution in the short term, is to install RCS s, these will provide real time current, voltage and fault information to help planners understand the dynamics of the feeder. These switches at a later time will be integrated into self healing network. 10 DG projects are treated as customer projects and customer contributions are project specific 11 Cost of installing a single GFN unit

194 5-80 SECTION 5 NETWORK DEVELOPMENT PLANS The figure below shows the extent of the project. Replace Manual ABS with Automated Switches Figure 5-30: Location of Proposed Automated Switch Sites Pakowhai Feeder

195 SECTION 5 NETWORK DEVELOPMENT PLANS 5-81 Constraint Lack of feeder fault location and load information on Arataki zone substation feeders. Description There is a lack of real time current, voltage and fault information to help planners understand the dynamics along the length of 11kV feeders. With real time information planners can see if capacity constraints and quality of supply issues are obvious and take steps to rectify the problem and operations can use this information to initiate quicker restorations after faults occur. Possible Solutions Class of Option Description Advantages Disadvantages or Risks Total Cost Network Install earth fault indicators and temporary data loggers at strategic locations along the feeder route Inexpensive. Gives approximate location of a fault between indicator points. Gives feeder load and fault current data if logger happens to be installed at time of fault. Needs personnel on site to identify approximate location of fault. Needs visit to site by technical personnel to setup data loggers and download fault and load current information. $ 40 k Information is not received in real time, it requires human intervention in the field. Non-Network Use data sensors at strategic locations to collect and convey data via the communications network to rapidly transfer loads to surrounding feeders Cost-effective solution. Real time data available for planners and operators. Reduced restoration times. Can be integrated into fast transfer and self healing. Can be used for self healing after network faults. Temporary solution (10-15 years). Increased network complexity. $ 130 k Do Nothing Operate assets up to their maximum limits No capital investment required. Unison is likely to breach its service level targets and network reliability targets for the customers. N/A Preferred Option & Justification The preferred solution in the short term is to install current sensors at strategic locations on all feeders originating from Arataki zone substation. The sensors will integrate into a future fast transfer scheme (smart network) to rapidly transfer excess load to adjacent 11 kv feeders and zone substation. The figure below shows the extent of the project.

196 5-82 SECTION 5 NETWORK DEVELOPMENT PLANS Installation of current sensors Figure 5-31: Proposed Current Sensor Sites Arataki Feeders

197 SECTION 5 NETWORK DEVELOPMENT PLANS 5-83 Constraint Security constraint at Windsor substation. Description Windsor substation feeds a peak winter load of 8 MVA, which will rise to 9 MVA in the next 20 years according to Unison s Load Forecast Tool. A single 20 MVA transformer is in service at Windsor substation, which is adequate under normal conditions. Recent studies have shown that Windsor substation loads have grown to the extent that the 11kV network would be unable to completely back feed the load from surrounding zone substations if this single transformer at Windsor substation should fail during peak loads. This could cause a major outage and will likely lead towards a breach of Unison s service level targets for urban customers detailed in section 8.4, and also the security criteria detailed in section 5.1. Possible Solutions Class of Option Description Advantages Disadvantages or Risks Total Cost Network Install an additional power transformer Long term solution and will ensure compliance with Unison s security standards for future planning periods. Creates capacity for future load growth. Significant costs involved. Need to purchase and install a 33kV breaker along with the transformer. $1.2M Creates opportunities to off load surrounding zone substations where peak loads approach system ratings. Non-Network Use a smart network to transfer those loads that adjacent networks can support during contingencies A smart network reacts not only to power transformer contingencies, but they also lessen the impact of other faults on the network. Possibly breach reliability thresholds. Insufficient 11kV capacity for a smart network to be effective. $500k Encourage Distributed Generation (DG) Can mitigate present and future capacity constraints on the transformers. Long term benefits in deferral of capital expenditure. Connections are at ad hoc basis, and cannot be predicted. The connected DG may not be of reliable source such as renewal. Unknown 12 Do Nothing Supply Windsor loads from a single transformer No capital investment required. Unison may to breach its service level targets and network reliability targets. >$5M DG projects are treated as customer projects and customer contributions are project specific 13 Possible fine for exceeding reliability thresholds.

198 5-84 SECTION 5 NETWORK DEVELOPMENT PLANS Figure 5-32: Zone substations that surround Windsor zone substation Preferred Option & Justification The preferred solution for the security constraint is to install a new power transformer, along with a new 33kV circuit breaker to connect it, at Windsor substation. This will enhance network security, and the additional capacity can offload surrounding networks that are approaching their limits. Having excess capacity at this central location opens up an array of possibilities for future smart networks to rapidly transfer excess loads during contingencies.

199 SECTION 5 NETWORK DEVELOPMENT PLANS 5-85 Constraint Security constraint at Tamatea zone substation. Description Load growth over the years has led to a power transformer security constraint at Tamatea zone substation. The transformer ratings are not adequate to meet Unison s security criteria. This can cause a major outage and may lead to a breach of Unison s service level targets for urban customers detailed in section 8.4. Possible Solutions Class of Option Description Advantages Disadvantages or Risks Total Cost Network Upgrade the transformers Long term solution and will ensure substations are compliant with Unison s security standards for future planning periods. Significant costs involved replacing transformers e.g. high civil costs, replacing switchgear etc. $2.5M Creates capacity for future load growths. Renewal of assets. Install 11kV bus coupler to split the busbar With split busbar configuration, if one transformer faults, only half the customers are lost which mitigates the risk. This option does not resolve the constraint, it just mitigates the risk. Will make switching on the 11kV level more complex. $120k Non-Network Use a smart network to rapidly transfer loads to surrounding zone substations Cost-effective solution. Can be used for self healing after network faults. Fully utilise existing transformers. Temporary solution (10-20 years). Increased network complexity. $350k Move normal open points between feeders to permanently shift loads Very low cost. Voltage regulation and conductor capacity limit scope. Bring forward more constraints on other parts of the network. N/A Encourage Distributed Generation (DG) Can mitigate present and future capacity constraints on the transformers. Long term benefits in deferral of capital expenditure. Connections are at ad hoc basis, and cannot be predicted. The connected DG may not be a reliable source such as renewal. Unknown 14 Review transformers ratings Effectively capitalise on cooling fans installed previously. Anticipated capacity gains, where applicable, are not sufficient to fully mitigate the problems. $40k Do Nothing Operate assets up to their maximum limits No capital investment required. Unison may breach service level targets and network reliability targets. N/A 14 DG projects are treated as customer projects and customer contributions are project specific

200 5-86 SECTION 5 NETWORK DEVELOPMENT PLANS Preferred Option & Justification The preferred solution includes a mixture of items: 1. Review transformers ratings in 2011/12: Tamatea substation s transformers are rated for 7.5MVA without forced cooling. A rating increase to 9.5 MVA is anticipated as cooling fans have been installed on these transformers. 2. Install a load transfer scheme (smart network) for Tamatea substation in 2011/12 to handle transformer n-1 situations during peak load times. This load transfer scheme will rapidly transfer excess loads to Marewa, Faraday, Tannery and Church Road zone substations if one of the transformers at Tamatea substation faults. It is anticipated that the above solutions will enable the Tamatea transformers to remain in service until they reach the end of their useful life. Figure 5-27: Zone substations and 11kV circuits that surround Tamatea zone substation

201 SECTION 5 NETWORK DEVELOPMENT PLANS 5-87 Constraint Security constraint at Havelock North Zone Substation. Description Load growth over the years has led to a power transformer security constraint at Havelock North zone substation. The transformers are not suitably rated for n-1 situations during peak load times. This can cause a major outage and may lead to a breach of Unison s service level targets for urban customers detailed in section 8.4. Possible Solutions Class of Option Description Advantages Disadvantages or Risks Total Cost Network Upgrade the transformers Long term solution and will ensure substations are compliant with Unison s security standards for future planning periods. Significant costs involved replacing transformers i.e. high civil costs, replacing switchgear etc. $2.5M Creates capacity for future load growth. Renewal of assets. Use existing 11kV bus coupler to split the busbar With split busbar configuration, if one transformer faults, only half the customers are lost which mitigates the risk. This option does not resolve the constraint. Can make switching on the 11kV level more complex. N/A Non-Network Use a smart network to rapidly transfer loads to surrounding zone substations Cost-effective solution. Can be used for self healing after network faults. Better utilise existing transformers. Temporary solution (10-20 years). Increased network complexity. $320k Move normal open points between feeders to permanently shift loads Very low cost. Voltage regulation and conductor capacity limit scope. Bring forward more constraints on other parts of the network. N/A Encourage Distributed Generation (DG) Can mitigate present and future capacity constraints on the transformers. Long term benefits in deferral of capital expenditure. Connections are at ad hoc basis, and cannot be predicted. The connected DG may not be a reliable source such as renewal. Unknown 15 Do Nothing Operate assets up to their maximum limits No capital investment required. Unison may breach service level targets and network reliability targets. N/A 15 DG projects are treated as customer projects and customer contributions are project specific

202 5-88 SECTION 5 NETWORK DEVELOPMENT PLANS Preferred Option & Justification The preferred solution is to install a fast load transfer scheme (smart network) for Havelock North zone substation in 2011/12 to handle n-1 transformer situations during peak load times. This load transfer scheme will rapidly transfer excess loads to Arataki and Irongate zone substations if one of the transformers at Havelock North substation faults. This solution will defer the required transformer upgrade for approximately ten years, and we have the option to add more switches later on to defer the upgrade even further. Figure 5-28: Zone substations and 11kV circuits that surround Havelock North zone substation.

203 SECTION 5 NETWORK DEVELOPMENT PLANS 5-89 Constraint Capacity constraint on Havelock 33kV incomer circuit. Description The 33kV Havelock circuit is predominantly overhead from Fernhill GXP to Havelock North substation. It becomes an underground circuit approximately 250m from the substation. This underground 33 kv section is a constraint because it is not capable of handling Arataki and Havelock substation peak loads simultaneously during contingencies. Also, the cable rating does not match the installed transformer capacity at Havelock North zone substation. Possible Solutions Class of Option Description Advantages Disadvantages or Risks Cost Network Upgrade the constrained section (250m) of the 33kV circuit to 3x 1C 800mm 2 Al XLPE By upgrading this small section, the current carrying capacity of the Havelock 33kV circuit more than doubles. High civil costs in areas that are already established. $250k Relatively inexpensive option. Ensures compliance with Unison s security standards, well into the next planning period. Non-Network Shift load through 11kV feeders during peak load times Reduces the load on the Havelock 33kV circuit thereby keeping the load within the existing current ratings of the cables. Deferral in reinforcement of cable. Short term solution (1-2 years), as there is load growth forecast in the Havelock-Arataki area. Does not resolve all the issues mentioned above. N/A Increase the ability to control hot water in the area Reduces the feeder loads during peak load conditions. Requires the local retailers to replace ripple relays. On going 16 Deferral in reinforcement of cable. Install thermal resistivity and temperature probes Possible increase in current carrying capacity of the existing cables as the existing assumptions to calculate ratings could prove conservative. Short term solution (1-2 years). Even if there is an increase in ratings it will not be enough to resolve the existing shortfall of 8 MVA when supplying both Havelock and Arataki substations. $30k Do Nothing No capital investment required. Security issue can lead to a large scale outage if a fault occurs. N/A Preferred Option & Justification The preferred option is to upgrade the constrained section (approximately 250m) of the Havelock 33kV circuit to 3x1C 800mm 2 Al XLPE. This option is preferred over the rest as it is a long term solution and will cater to the future load growth predicted for this area. The figure below shows the extent of the project. 16 Maintenance cost of the ripple plant equipment at the Zone Substation

204 5-90 SECTION 5 NETWORK DEVELOPMENT PLANS Figure 5-29: Proposed 33kV incoming cables Havelock North substation

205 SECTION 5 NETWORK DEVELOPMENT PLANS 5-91 Constraint Currently in the Hawke s Bay Region there is no complete secondary communication network in place to enable the transfer of critical data from network devices in the field to Unison s centralised information management system. Without this communication network, Unison would be unable to implement the Distribution Automation (DA) projects detailed in this section. Description Unison is implementing a number of DA (fast transfer / self healing) projects in the Hawke s Bay region which is reliant on a secondary communication network to operate. In order to transfer critical data between network devices installed on the network and Unison s information systems thereby enabling these DA projects, a secondary communication network is required. Possible Solutions Class of Option Description Advantages Disadvantages or Risks Total Cost Network Mesh Radio Both DA & AMI Capable. Do Nothing WiMax Scalable. Able to prioritise critical data. Operates in free unlicensed bandwidth. Self healing. Good range. Acceptable latency. High data transfer rates. Both DA & AMI Capable. No additional backhaul network required. IP capable backhaul network required. Radio band licensed and would require commercial arrangement with existing users/ owners. Not ideal for hilly topography. IP interface required for each AMI or DA device. Limited range. Cellular / GPRS Both DA & AMI Capable. IP interface required for each AMI or DA device. Power Line Carrier (PLC)) Have no secondary communication network Low Cost. No capital investment required. Limited coverage. Reliant on third party provider. Limited range subject to frequency. Lower frequency option has increased range but very low data transfer rates (high latency). Technology still under development and not proven. Not suitable for transfer of IP data streams. DA projects will not operate and all the advantages / benefits of implementing these schemes will not be realized. $444K Unknown Unknown Unknown N/A

206 5-92 SECTION 5 NETWORK DEVELOPMENT PLANS Class of Option Description Advantages Disadvantages or Risks Total Cost In addition Unison will be exposed to the disadvantages / risks associated with these projects not proceeding. Preferred Option & Justification The preferred solution is to establish a backbone mesh radio secondary communication network as an enabler for the distribution automation (DA) and any future AMI projects: The mesh radio network will encompass all DA projects detailed in this plan and be capable of being extended as required to include future DA & AMI initiatives. After a robust selection process the Landis+Gyr Series IV Gridstream product was selected as the secondary communication mesh radio solution that will be deployed on Unison s network.

207 SECTION 5 NETWORK DEVELOPMENT PLANS Network Development Programme for 2012/13 until 2016/17 Constraint Capacity constraint on Poukawa feeder. Description Due to load growth over the past few years and with the area around Irongate substation being re-designated as industrial, Poukawa feeder is heavily loaded and does not have any spare capacity to cater for the industrial load in the future. As this feeder supplies major customers, it is essential to resolve this constraint. Possible Solutions Class of Option Description Advantages Disadvantages or Risks Cost Network Upgrade the front end (approximately 150m) of Bridge Pa and Raureka feeders from the substation to pole Shift the prison load from Poukawa to Bridge Pa, thereby offloading Poukawa feeder. Create capacity and security headroom for feeders connected to enable smart grid. Short-medium term solution (3-5 years). $90k Defer installation of a new feeder out of Irongate substation. Install new feeder out of Irongate to offload Poukawa feeder Offloads identified capacity constrained feeders. Ensures feeders are compliant with Unison s security standards, well into the next planning period. Requires installation of new CB at Irongate substation. High civil costs. $350k Provides additional 11kV interconnectivity. Non-Network Shift load through 11kV feeders during peak load times Reduces the load on the constraint feeder. Defer capital investment. Difficult to shift load around as the feeder runs through urban/rural area, thereby causing potential voltage issues. N/A Do Nothing No capital investment required. Unison is likely to breach its service level targets and network reliability targets for the customers. Missed revenue opportunity. n/a Preferred Option & Justification The preferred solution for this capacity constraint is to be resolved in two stages as detailed below: 1. Stage 1: Upgrade Bridge Pa and Raureka feeders. This will enable Bridge Pa to take over the prison load from Poukawa feeder which is quite substantial, thereby offloading Poukawa and deferring the capital expenditure required to install a new feeder. Another advantage of this option is that it increases capacity of both Bridge Pa and Raureka which then aids in enabling a smart network. Raureka feeder is upgraded because it runs in the same trench as Bridge Pa therefore the cost of installation will be minimal. The figure below shows the extent of this stage.

208 5-94 SECTION 5 NETWORK DEVELOPMENT PLANS 2. Stage 2: This will only come into effect if there is a substantial load growth in this area in the near future. This involves installing a new feeder out of Irongate which will then further split Poukawa feeder. Planning for this stage has not been completed as yet. Upgrade Bridge Pa from existing through joint to pole Upgrade Raureka from pole to pole Maraekakaho Road IRONGATE Figure 5-33: Proposed work detail Bridge Pa and Raureka

209 SECTION 5 NETWORK DEVELOPMENT PLANS 5-95 Constraint Capacity constraint on 33kV Arataki-Havelock Tie. Description In recent years there has been high load growth in Havelock and Arataki areas. Due to this, the Havelock-Arataki tie is overloaded when back feeding Havelock substation, under the n-1 contingency situation, during peak loads. This circuit is of strategic importance as it allows Unison to shift load from Fernhill to Whakatu GXP during maintenance and contingency situations. Possible Solutions Class of Option Description Advantages Disadvantages or Risks Total Cost Network Upgrade the Arataki-Havelock tie from 185mm2 Al PILC to 3x1C 630mm2 Al XLPE Ensures compliance with Unison s capacity standards, well into the next planning period. Creates capacity for future load growths. High civil costs in areas that are already established, 2.5 km of circuit requires replacement. $2.0M Renewal of assets. Non-Network Install soil thermal resistivity and moisture sensors Calculate accurate cable ratings which will likely be higher than the existing ratings. Deferral in reinforcement of cable. Short term solution. Depending on the test results, the reinforcement can be deferred by 1-3 years. $75k Shift some load on the 11kV network to mitigate the risk of overloading the circuit Deferral of capital expenditure. Short term solution (1-2years). N/A Do Nothing Operate assets up to their maximum limits No capital investment required. Non-compliant with Unison s capacity criteria. N/A Limitation on back feed capabilities. Preferred Option & Justification The preferred solution for this capacity constraint is to be resolved in two stages as detailed below: 1. Stage 1: Soil thermal resistivity and moisture sensors have been deployed in 2010/11. The information provided by these sensors will determine the timing of stage Stage 2: Upgrade the Havelock-Arataki tie to 3x1C 630mm 2 Al XLPE cables. This is a long term network solution which will be implemented when the project cannot be deferred anymore using non-network solutions e.g. fast transfer schemes.

210 5-96 SECTION 5 NETWORK DEVELOPMENT PLANS Constraint Capacity and security constraint on feeders out of Awatato and Springfield zone substations. Description A number of feeders in the Hawke s Bay region do not comply with Unison s capacity and security criteria. In particular, Taradale A and B and Bowen are most vulnerable in the region through the analysis tools. These feeders predominantly supply commercial and industrial loads and it is critical that supply is maintained. Lack of investment will lead to overloading of these feeders which limits the ability to back stop adjacent connected feeders during a contingency condition. These will likely lead towards a breach of Unison s service level targets for urban customer classification detailed in section 8.4. Possible Solutions Class of Option Description Advantages Disadvantages or Risks Total Cost Network Establish new feeders out of Awatato and Springfield Zone Substations Offloads identified capacity constraint feeders. Ensures feeders are compliant with Unison s security standards, well into the next planning period. Provides additional 11kV interconnectivity. High civil costs in areas that are already established. Requires installation of new 11kV circuit breaker at appropriate zone substation. $1.7M Upgrade constrained sections of the three feeders Provides spare capacity on the feeder until end of planning period for present and forecasted load. Cheaper than installing new feeders as there are no civil costs to extend/modify the building and installing CBs. Disruption to existing 11kV feeders in the same trench and foreseen outages during works. $ 550k Provide new interconnection with a lightly loaded feeder and transfer load Offloads identified capacity constraint feeders. Provides additional 11kV interconnection and flexibility to backstop. Due to network architecture, heavily loaded feeders cannot be offloaded substantially. Only a short term option, and will not meet security standards after 2-3 years. $700k Easements are required as shorter cable route is through private properties.

211 SECTION 5 NETWORK DEVELOPMENT PLANS 5-97 Class of Option Description Advantages Disadvantages or Risks Total Cost Non-Network Install capacitor banks to reduce feeder loadings Reduces feeder loadings. Ideal location is hard to identify due to lack of customer installation data (e.g. consumption kw, kvar). $400k Lack of VAr requirements of the feeders. Another investment would be required to ensure feeder is compliant with security standard. Encourage Distributed Generation (DG) Can mitigate present and future feeder capacity constraints. Long term benefits in deferral of capital expenditure. Connections are at ad hoc basis, and cannot be predicted. The connected DG may not be of reliable source such as renewal. Unknown 17 Install soil thermal resistivity and moisture sensors Calculate accurate cable ratings which will likely be higher than the existing ratings. Deferral in reinforcement of cable. Short term solution (1-2 years). $100k Increase the ability to control hot water in the Hawke s Bay region Reduces the feeder loads during peak load conditions. Deferral in reinforcement of cable. Requires the local retailers to replace ripple relays. Ongoing 18 Do Nothing Operate assets up to their maximum limits No capital investment required. Unison is likely to breach its service level targets and network reliability targets for the customers. N/A Preferred Option & Justification The preferred solution for the capacity and security constraint are: 1. For Awatato Substation: Upgrade the constrained section of Bowen feeder (approximately 175m of 0.1in 2 Al PLIC). This will also provide spare capacity for back feeding the Philips feeder. 2. For Springfield substation: To resolve the security and capacity constraints on Taradale A and B feeders, it is optimal to upgrade their front end (approximately 1.2km). These feeders were installed in 1939, therefore it is prudent to upgrade these cables rather than installing new feeders. 17 DG projects are treated as customer projects and customer contributions are project specific 18 Maintenance cost of the ripple plant equipment at the Zone Substation

212 5-98 SECTION 5 NETWORK DEVELOPMENT PLANS Constraint Ability to remotely restore supply to rural/urban consumers given a feeder fault on Waimarama Feeder. Description Waimarama feeder was identified as one of the worst ten performing feeders on the network. Waimarama is a long, rural feeder with a high number of coastal consumers towards the end of the feeder. There are a number of reclosers on Waimarama feeder. Fault detection is a major constraint on this feeder, as a fault tends to operate two reclosers. The engineers cannot analyse the fault data as the existing reclosers do not have the ability to communicate fault data. The fault database indicates that there have been a number of outages contributing to a large impact on reliability. This is because there is no automated switchgear on this feeder. Possible Solutions Class of Option Description Advantages Disadvantages or Risks Cost Network Replace existing KFE Series Re-closers with Nova Reclosers Improves reliability. Ensures Unison s Service Level and Network Reliability Targets can be met. High cost. $250 k Provides useful planning information from these devices. Non-Network Implementing self healing technology. Improves reliability drastically. Restoration of supply to consumers within 1 minute. Provides useful planning information from devices. High initial set up cost. Line of sight communication is required between switches. Increase in maintenance costs due to additional gear. N/A Install Ground Fault Neutraliser (GFN) Improves reliability drastically, only for earth faults. Quicker identification of faults. High cost Health and Safety. One GFN per substation site. $450k 19 Do Nothing Least cost option. Contribute towards and can lead to breaching Unison s Service Level and Network Reliability Targets. N/A Preferred Option & Justification The preferred solution to improve the reliability on Waimarama feeder is to replace existing McGraw Edison KFE Reclosers with Cooper Power systems Nova 15 Re-closers. This will enable the engineers to analyse and understand the nature of the faults. This will aid in replacing aged equipment such as insulators that are contributing to faults, or improve restoration and isolation of fault. 19 Cost of installing a single GFN unit

213 SECTION 5 NETWORK DEVELOPMENT PLANS 5-99 Constraint Voltage constraint on Waimarama Feeder. Description The Waimarama feeder has a voltage constraint, due to the fact that it is a long, rural feeder with a high number of coastal consumers towards the end of the feeder. It is prudent to resolve these constraints to ensure compliance with the Electricity Regulations Act. Possible Solutions Class of Option Description Advantages Disadvantages or Risks Total Cost Network Upgrade the section of line that is causing the voltage issue Resolves the issue by installing a bigger conductor which has a lower voltage drop across it. Significant costs involved in upgrading conductors. 5km needs to be upgraded. $ 1.22M Creates capacity for future load growth. Renewal of assets. Install voltage regulators on the constraint feeders Significantly cheaper than upgrading lines. Medium term solution, as the problem could worsen if a big load is added at the end of the line. $ 250k Non-Network Install capacitor banks to reduce feeder loadings Reduces feeder loadings thereby lifting the voltage profile. Significantly cheaper than the network solutions mentioned above. Ideal location is hard to identify due to lack of customer installation data (E.g. consumption kw, kvar). Will only be useful if high reactive loads are connected to the feeder. $250k Encourage Distributed Generation (DG) Can mitigate present and future feeder capacity constraints. Long term benefits in deferral of capital expenditure. Connections are at ad hoc basis, and cannot be predicted. The connected DG may not be of reliable source such as renewal. Unknown 20 Do Nothing Operate assets up to their maximum limits No capital investment required. This is not a feasible option as Unison would be breeching the Electricity Regulation Act. N/A Limitation on back feed capabilities. Preferred Option & Justification The preferred solution is to install an additional regulator on the Waimarama feeder as there is mainly resistive and light reactive loads connected to the feeder. 20 DG projects are treated as customer projects and customer contributions are project specific

214 5-100 SECTION 5 NETWORK DEVELOPMENT PLANS Constraint Voltage constraints on feeders out of Maraekakaho, Fernhill, Patoka and Arataki. Description Feeders out of the four above-mentioned substations have voltage constraints on them. These constraints have become evident due to the high number of dairy conversions taking place in the Hawke s Bay region. It is prudent to resolve these constraints for the following reasons: 1. To be compliant with the Electricity Regulations Act. 2. Due to the advancements in technology, the dairy units have machines which are quite sensitive to voltage and if the voltage is not compliant they trip quite often. Possible Solutions Class of Option Description Advantages Disadvantages or Risks Total Cost Network Upgrade the section of line that is causing the voltage issue Resolves the issue by installing a bigger conductor which has a lower voltage drop across it. Significant costs involved in upgrading conductors. $2.1M Creates capacity for future load growth. Renewal of assets. Install voltage regulators on the constraint feeders Significantly cheaper than upgrading lines. Medium term solution, as the problem could worsen if a big load is added at the end of the line. $500k Non-Network Install capacitor banks to reduce feeder loadings Reduces feeder loadings thereby lifting the voltage profile. Significantly cheaper than the network solutions mentioned above. Ideal location is hard to identify due to lack of customer installation data (e.g. consumption kw, kvar). Will only be useful if high reactive loads are connected to the feeder. $255k Encourage Distributed Generation (DG) Can mitigate present and future feeder capacity constraints. Long term benefits in deferral of capital expenditure. Connections are at ad hoc basis, and cannot be predicted. The connected DG may not be of reliable source such as renewal. Unknown 21 Do Nothing Operate assets up to their maximum limits No capital investment required. This is not a feasible option as Unison would be breeching the Electricity Regulation Act.. N/A 21 DG projects are treated as customer projects and customer contributions are project specific

215 SECTION 5 NETWORK DEVELOPMENT PLANS Preferred Option & Justification The preferred solution for the voltage constraint is to be resolved in two stages as detailed below: 1. Stage 1: Install capacitor banks wherever applicable. This is a cost effective solution which can be used to lift the voltage profile where the feeders have high reactive loads connected. 2. Stage 2: Where capacitor banks cannot be used, install voltage regulators or upgrade the conductor if future load growth is forecast.

216 5-102 SECTION 5 NETWORK DEVELOPMENT PLANS Constraint Capacity and security constraint on Clive Feeder. Description Load growth over the years has led to capacity and security constraints on Clive feeder during peak load times. This can cause outages and will likely lead towards a breach of Unison s service level targets for urban customer classification detailed in section 8.4. Possible Solutions Class of Option Description Advantages Disadvantages or Risks Total Cost Network Upgrade this and adjacent 11kV feeders Long term solution and will ensure feeders are compliant with Unison s security standards for future planning periods. Significant costs involved replacing transformers i.e. high civil costs, replacing switchgear etc. $ 1.22M Creates capacity for future load growth. Renewal of assets. Non-Network Use a smart network to rapidly transfer loads to surrounding feeders Cost-effective solution. Can be used for self healing after network faults. Fully utilise adjacent feeders. Temporary solution (10-15 years). Increased network complexity. Reliant on the new feeder from Rangitane ZS project to proceed. $ 206k Move normal open points between feeders to permanently shift loads Very low cost. Voltage regulation and conductor capacity limit scope. Bring forward more constraints on other parts of the network. N/A Encourage distributed generation (DG) Can mitigate present and future capacity constraints on the transformers. Long term benefits in deferral of capital expenditure. Connections are at ad hoc basis, and cannot be predicted. The connected DG may not be a reliable source such as renewal. Unknown 22 Do Nothing Operate assets up to their maximum limits No capital investment required. Unison is likely to breach its service level targets and network reliability targets for the customers. N/A Preferred Option & Justification The preferred solution in the short term is to install a fast transfer scheme (smart network) option to rapidly transfer excess load to adjacent 11kV feeders and zone substations. 22 DG projects are treated as customer projects and customer contributions are project specific

217 SECTION 5 NETWORK DEVELOPMENT PLANS Constraint Lack of automation on Napier CBD feeders. Description Napier CBD has a number of distribution substations where after hours access is difficult. The replacement of the existing RMUs at these sites, with RMUs that have remote controlled functionality, load and fault current sensors would enhance feeder reliability and reduce reinstatement time after faults. This will lead towards compliance with Unison s service level targets for urban customer classification detailed in section 8.4. Possible Solutions Class of Option Description Advantages Disadvantages or Risks Total Cost Network Relocate all RMUs outside the building where the distribution substation is installed Improves reliability. Improves access for operation and maintenance. Ensures Unison s Service Level and Network Reliability Targets can be met. Expensive. Due to shortage of available land and berm sites in the CBD new locations could be a considerable distance from the transformer. $ 5.0 M Non-Network Use a smart network to rapidly transfer loads to surrounding feeders Cost-effective solution. Provides useful planning information from these devices. Can be used for self healing after network faults. Temporary solution (10-20 years). Increased network complexity. No allowance for immediate reinstatement if fault is at the transformer or on the LV Network. $800k Fully utilize adjacent feeders. Move normal open points between feeders to permanently shift loads Very low cost. Voltage regulation and conductor capacity limit scope. Bring forward more constraints on other parts of the network. N/A Encourage Distributed Generation (DG) Can mitigate present and future capacity constraints on the transformers. Long term benefits in deferral of capital expenditure. Connections are at ad hoc basis, and cannot be predicted. The connected DG may not be a reliable source such as renewal. Unknown 23 Install Ground Fault Neutraliser (GFN) Improves reliability drastically, only for earth faults. One GFN per substation site. $450k 24 Quicker identification of faults. Do Nothing Operate assets up to their maximum limits No capital investment required. Unison is likely to breach its service level targets and network reliability targets for the customers. N/A 23 DG projects are treated as customer project; customer contribution are project specific 24 Cost of installing a single GFN unit

218 5-104 SECTION 5 NETWORK DEVELOPMENT PLANS Preferred Option & Justification The preferred solution is to use a smart network, by replacing the existing RMUs with RMUs that have remote control functionality and have load and fault current sensors. These RMU s will allow remote operation, provide real time current, voltage and fault information to help planners understand the dynamics of the feeder and use the smart network to rapidly transfer loads to surrounding feeders. These switches at a later time will be integrated into self healing network.

219 SECTION 5 NETWORK DEVELOPMENT PLANS Constraint Lack of feeder fault and load information on Havelock zone substation feeders. Description There is a lack of real time current, voltage and fault information to help planners understand the dynamics along the length of 11kV feeders. With real time information planners can see if capacity constraints and quality of supply issues are obvious and take steps to rectify the problem and operations can with this information initiate quicker restorations after faults occur. Possible Solutions Class of Option Description Advantages Disadvantages or Risks Total Cost Network Install earth fault indicators and temporary data loggers at strategic locations along the feeder route Inexpensive. Gives approximate location of a fault between indicator points. Gives feeder load and fault current data if logger happens to be installed at time of fault. Needs personnel on site to identify approximate location of fault. Needs visit to site by technical personnel to setup data loggers and download fault and load current information. $ 40 k Information is not received in real time, it requires human intervention in the field. Non-Network Use data sensors at strategic locations to collect and convey data via the communications network to rapidly transfer loads to surrounding feeders Cost-effective solution. Real time data available for planners and operators. Reduced restoration times. Can be integrated into fast transfer and self healing schemes. Temporary solution (10-15 years). Increased network complexity. $ 185 k Do Nothing Operate assets up to their maximum limits No capital investment required. Unison is likely to breach its service level targets and network reliability targets for the customers. N/A Preferred Option & Justification The preferred solution in the short term is to install current sensors at strategic locations on mainly underground feeders originating from Havelock zone substation. The sensors will integrate into a fast transfer scheme (smart network) to rapidly transfer excess load to adjacent 11 kv feeders and zone substations.

220 5-106 SECTION 5 NETWORK DEVELOPMENT PLANS Constraint Security constraints on Fernhill and Redclyffe GXPs. Description The Transpower owned transformers at Fernhill and Redclyffe GXPs are mismatched. At Fernhill, the transformer sizes are 30MVA and 50MVA, at Redclyffe they are 40MVA and 50MVA. The existing load on the GXPs is 47MVA and 62MVA respectively. Therefore, if any 50MVA transformer goes out of service at either site during peak load times, Unison will struggle to shift load onto the Whakatu GXP. This would cause a major outage and will lead towards a breach of Unison s service level targets for urban customer classification detailed in section 8.4. Possible Solutions Class of Option Description Advantages Disadvantages or Risks Total Cost Network Upgrade the transformers to cater for existing future load growth. Long term solution. Will ensure the GXPs are complaint with Unison s security standards for future planning periods. High cost option. TBA Creates capacity for future load growths. Renewal of assets. Relatively cheaper solution than establishing a new GXP. Establish a new GXP in Napier Long term solution. Defer capital expenditure for transformer upgrades at both Fernhill and Redclyffe. Significant amounts of capital required to establish a new GXP. Easements are required as shorter cable route is through private properties. TBA Non-Network Encourage Distributed Generation (DG) Can mitigate present and future capacity constraints on the transformers. Long term benefits in deferral of capital expenditure. Connections are at ad hoc basis, and cannot be predicted. The connected DG may not be of reliable source such as renewal. Unknown 25 Do Nothing Operate assets up to their maximum limits No capital investment required. Unison would be likely to breach its service level and network reliability targets. N/A 25 DG projects are treated as customer projects and customer contributions are project specific

221 SECTION 5 NETWORK DEVELOPMENT PLANS Preferred Option & Justification The preferred option is for Transpower to upgrade the transformers at Redclyffe to 100MVA units, and upgrade the 30 MVA unit at Fernhill to 60 MVA. This is a more economically viable option than establishing a new GXP. The existing 33kV circuits out of Redclyffe GXP will need upgrading and reconfiguration over time. This option will make supply to Marewa and Bluff Hill zone substations more secure, as they are currently feed from Whakatu GXP via the North Tie 33kV feeder.

222 5-108 SECTION 5 NETWORK DEVELOPMENT PLANS Constraint High load on City 33 kv feeder in Hastings. Description Load in Hastings has grown to the extent that the City 33kV feeder, which feeds Hastings zone substation, is heavily loaded at peak times. Furthermore, the load forecast predicts load growth of roughly 1 MVA on this circuit over the next 20 years. The existing 300mm 2 33 kv Aluminum PILC cable was installed in 1977, which means that it probably has a lot of useful asset life left. Given the above mentioned age of the cable, Unison s engineers have opted to install distributed temperature sensors on it in the 2010/11 financial year, since nominal cable ratings tend to be conservative. Initial indications are that there is still some spare capacity left on this cable. Close monitoring will continue to optimally time network strengthening. Possible Solutions Class of Option Description Advantages Disadvantages or Risks Cost Network Install a higher rated cable Enhanced network security. Provides additional spare capacity into Hastings for future planning periods. Easements are required, since new cable will probably follow a different route. Approximately 2km of cable to be installed. High civil costs in areas that are already established. $1.2M Non Network Smart Network: Load Transfer scheme Offloads identified capacity constrained feeder. Uses available 11kV and / or 33kV interconnectivity. No major easements required. Not a long term solution. Using spare capacity on other parts of the network can influence other future constraints. Increase in complexity of the network. $400k 26 Manually shift normal open points on 11 kv feeders to transfer load to other zone substations Offloads identified capacity constraint feeder. Uses available 11kV interconnectivity. Not a long term solution. Using spare capacity on other parts of the network may bring other constraints forward. N/A No major easements required. Split the 33kV bus bar at Hastings zone substation Offloads identified capacity constraint feeder. Uses available 33kV interconnectivity. No major easements required. Not a long term solution. Makes switching at the 11kV level complex, since adjacent feeders are fed off different GXP s. Fernhill GXP not suitably rated for additional load prior to an anticipated transformer upgrade in the near future. N/A 26 Customer contribution is yet unknown

223 SECTION 5 NETWORK DEVELOPMENT PLANS Class of Option Description Advantages Disadvantages or Risks Cost Do Nothing Least cost option, if no penalties are incurred. Can strain relationships with customers. Possibly breach reliability thresholds, for which a $5m fine is possible. $5m 27 Preferred Option The preferred solution, in the short term, is to temporarily shift load to surrounding zone substations by manually moving normal open points between interconnecting 11kV feeders. These load shifts can be automated using a smart network to gain further deferral and alleviate other possible constraints in the longer term if needed. The planned additional power transformer at Windsor zone substation will be useful in this regard, as the two zone substations are not far apart. The longer term solution will be to install a higher rated 33kV cable once the above mentioned solutions are no longer technically or financially viable. The existing 33kV cable can then be used to strengthen supply from Whakatu GXP to Windsor substation. 27 A breach of reliability thresholds can see a $5M fine imposed in the worst case.

224 5-110 SECTION 5 NETWORK DEVELOPMENT PLANS Constraint Security constraint at Camberley zone substation. Description Load growth over the years has led to a power transformer security constraint at Camberley zone substation. The smaller transformer is not suitably rated for a power transformer n-1 situation during peak load times. This can cause a major outage and will likely lead towards a breach of Unison s service level targets for urban customers as detailed in section 8.4. Possible Solutions Class of Option Description Advantages Disadvantages or Risks Total Cost Network Install a higher rated transformer Long term solution and will ensure substations are compliant with Unison s security standards for future planning periods. Creates capacity for future load growths. Significant costs involved replacing transformer i.e. high civil costs, yard extensions etc. $1M Renewal of assets. Install a bus coupler to split the 11kV busbar With split busbar configuration, if one transformer faults, only half the customers are lost. This option does not resolve the constraint. It will make switching on the 11kV level more complex. $100k Non-Network Use a smart network to rapidly transfer loads to surrounding zone substations Cost-effective solution. Can be used for self healing after network faults. Optimally utilise existing transformers. Temporary solution (10-20 years). Increased network complexity. $100k Move normal open points between feeders to permanently shift loads to other zone substations Very low cost. Voltage regulation and conductor capacity limit scope. Bring forward more constraints on other parts of the network. N/A Encourage Distributed Generation (DG) Can mitigate present and future capacity constraints on the transformers. Long term benefits in deferral of capital expenditure. Connections are at ad hoc basis, and cannot be predicted. The connected DG may not be a reliable source such as renewal. Unknown 28 Revise transformer rating Effectively capitalise on cooling fans installed previously. Anticipated capacity gain not sufficient to fully mitigate the problem. $40k 28 DG projects are treated as customer projects and customer contributions are project specific

225 SECTION 5 NETWORK DEVELOPMENT PLANS Class of Option Description Advantages Disadvantages or Risks Total Cost Do Nothing Operate assets up to their maximum limits No capital investment required. Unison may breach service level and network reliability targets. N/A Preferred Option & Justification The preferred solution for the capacity constraint will be implemented in two stages: 1. Review rating of transformer T1 at Camberley zone substation 2011/ Install a load transfer scheme (smart network) for Camberley in subsequent years to transfer the excess load to surrounding networks. It is anticipated that the rating review will increase this transformer s capacity from 7.5MVA to approximately 10MVA when the cooling fans are taken into consideration. This increase can be attained at a relatively small cost. Suitable transformer capacities at zone substations enable the smart networks to function effectively.

226 5-112 SECTION 5 NETWORK DEVELOPMENT PLANS Constraint Security constraints at Mahora and Springfield zone substations. Description Load growth over the years has led to marginal n-1 power transformer constraints at Mahora and Springfield zone substations. The second transformer will be slightly overloaded if the first one faults during peak load times. This can cause a major outage, which may lead towards a breach of Unison s service level targets. Possible Solutions Class of Option Description Advantages Disadvantages or Risks Total Cost Network Upgrade the transformers Long term solution and will ensure substations are compliant with Unison s security standards for future planning periods. Significant costs involved replacing transformers i.e. civil costs, replacing switchgear etc. $4M Creates capacity for future load growths. Renewal of assets. Opportunity costs incurred if we cannot re-deploy the used transformers. Use existing 11kV bus couplers to split the busbars Only half the customers are lost if one transformer faults. Very low cost option. This option does not resolve the constraint. Can make switching on the 11kV level more complex. N/A Non-Network Use a smart network to rapidly transfer excess loads to surrounding zone substations Cost-effective solution. Can be used for self healing after feeder faults. Fully utilise existing transformers. Temporary solution. Increased network complexity. $250k Manually move normal open points between feeders to permanently shift loads Very low cost. Voltage regulation and conductor capacity limit scope. Bring forward more constraints on other parts of the network. N/A Revise transformer ratings where applicable Effectively capitalise on cooling fans installed previously. Not applicable in all cases. $40k Run transformers to 120% of their capacity and shift loads within two hours in emergencies Very low cost option. Utilise existing assets very well. Standard industry practice. High load on second transformer during contingency. Human intervention required to remedy the situation. N/A Do Nothing Operate assets up to their maximum limits No capital investment required. Unison may breach service level and network reliability targets. N/A

227 SECTION 5 NETWORK DEVELOPMENT PLANS Preferred Option & Justification The preferred solution consists of a mixture of items: 1. Review the ratings of Springfield substation s transformers in 2011/12 to capitalise on cooling fans that were installed in the past. 2. Install load transfer schemes (smart network) for Mahora and Springfield substations in approximately 2012/13 to automatically handle contingencies under peak loads. These load transfer schemes will rapidly transfer excess loads to surrounding zone substations if one of the transformers faults. It is anticipated that the rating reviews will place these 7.5 MVA transformers capacities close to 10MVA when the cooling fans are taken into consideration. These increases can be attained at a relatively small cost. Suitable transformer capacities at zone substations enable the smart networks to function effectively.

228 5-114 SECTION 5 NETWORK DEVELOPMENT PLANS Network Development Programme for 2017/18 until 2020/21 Constraint At present, in the Hawke s Bay region there are a number of substations being supplied from two GXPs. As Transpower does not allow lines companies to have closed ring supply when a substation is fed from two GXPs, it is prudent to reconfigure the 33kV circuits. This will increase the security of supply to critical substations like Hastings, Havelock and Camberley substations. Majority of the load on these substations is either commercial or industrial with sensitive customers. The figure below shows the planned future configuration. Class of Option Description Advantages Disadvantages or Risks Total Cost Network Create a closed ring between Hastings substation, Windsor substation and Whakatu GXP No break in supply even under contingency situation. High costs related to reconfiguration of circuits. TBA Create a closed ring between Havelock substation, Arataki substation and Whakatu GXP Ensures Unison complies with its customer service levels. Create a closed ring between Camberley substation, Irongate substation and Fernhill GXP Establish a new GXP in Napier Long term solution. Will resolve all existing GXP constraints. Defer capital expenditure for transformer upgrades at both Fernhill and Redclyffe. Significant amounts of capital required to establish a new GXP. Easements are required as shorter cable route is through private properties. TBA Do Nothing Operate assets up to their maximum limits No capital investment required. Unison is likely to breach its service level targets and network reliability targets for the customers. N/A Preferred Option The preferred option is to reconfigure the network as shown in Figure 5-34.

229 SECTION 5 NETWORK DEVELOPMENT PLANS Maraekakaho Sherenden Circuit Change or Capacity Upgrade Fernhill GXP Flaxmere Fernhill Rangitane Irongate Camberley Whakatu GXP Mahora Tomoana Hastings Windsor Havelock North Arataki Figure 5-34: Hastings future network configuration

230 5-116 SECTION 5 NETWORK DEVELOPMENT PLANS Constraint Bluff Hill and Marewa zone substations are fed from Whakatu GXP via the North Tie 33kV feeder due to a power transformer security constraint at Redclyffe GXP. Supply is lost to these two zone substations simultaneously when the North Tie feeder trips. Class of Option Description Advantages Disadvantages or Risks Total Cost Network Extend Gilligan's feeder into, and out of Powdrells road switching station. Onekawa B feeder will bypass Powdrells Road switching station. Improved network security. Increased network capacity for future planning periods. Ensures Unison complies with its customer service levels. Easements required. $300k Relatively short distance of 33kV overhead network needed to effect the change. Use existing infrastructure to significantly improve network capacity. Non Network Encourage Distributed Generation (DG) Can mitigate present and future capacity constraints all network elements. Connections are at ad hoc basis, and cannot be predicted. Unknown 29 Long term benefits in deferral of capital expenditure. The connected DG may not be of reliable source such as renewal. Do Nothing Operate assets up to their maximum limits No capital investment required. Unison is likely to breach its service level targets and network reliability targets for the customers. $5m fine for breaching reliability thresholds Preferred solution Increased capacity at Redclyffe GXP will enable the use of multiple existing 33kV feeders to feed Marewa and Bluff Hill zone substations respectively, which will lead to an improvement in network security. The solution utilises the connectivity that the Gilligan s feeder offers between Redclyffe GXP and Powdrells Road switching station. This will require the extension of the Gilligan s feeder by approximately 2km to connect it to Powdrells Road switching station. This network alteration will improve the network s ability to transmit energy from Redclyffe GXP to the rest of Napier, and thereby improve spare capacity for future planning periods at a relatively small cost. 29 DG projects are treated as customer projects and customer contributions are project specific

231 SECTION 5 NETWORK DEVELOPMENT PLANS Patoka Redclyffe GXP Springfield Esk Tutira Bluff Hill Faraday Street Church Rd Tamatea Onekawa Marewa Gilligans Feeder Tannery Road Powdrells Awatoto Rangitane Figure 5-35: Napier 33kV sub-transmission proposed

232 5-118 SECTION 5 NETWORK DEVELOPMENT PLANS 5.8 Expenditure Forecasts and Reconciliation

233 SECTION 5 NETWORK DEVELOPMENT PLANS 5-119

234 section 6 LIFE CYcle asset management planning Hendrix insulated conductor system is a critical element of the Smart Grid toolbox. This technology is deployed in areas that are prone to vegetation and animal contact. life cycle asset management planning

235 SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN Life Cycle Asset Management Plan Maintenance Planning Criteria and Assumptions Objective Determining Optimal Level of Maintenance Expenditure Maintenance Practices Standard Life Risk Routine and Preventative Inspection and Maintenance Policies Maintenance Strategy Systemic Asset Failures Maintenance Budget Procurement Practices and New Asset Technical Evaluation Non Network (Smart Grid) Solutions Risk Management CAPEX Renewal Planning Criteria and Assumptions Asset Renewal Policy Assumptions Made in Renewal Expenditure Modelling Replacement Costs Renewal Envelope Indirect Renewals External Review Alternatives to Renewal Life Cycle Asset Management Expenditure Forecasts Renewal Expenditure Forecast Summary of Renewals Projects Planned Summary Description of Proposed Renewal Projects ( ) High Level Summary of Proposed Renewal Projects ( ) Renewal and Refurbishment Projects Overhead Line Renewal Maintenance Projects Refurbishment of Zone Substation Transformers Refurbishment of Distribution Transformers Expenditure Forecasts and Reconciliation

236 6-2 SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN Figure 6-1: DTS Overview Figure 6-2: Powersense Current Sensor Figure 6-3: Insulator Pollution Monitoring Table 6-1: Overhead lines Table 6-2: Underground cables Table 6-3: Zone substations Table 6-4: Distribution transformers and voltage regulators Table 6-5: Distribution switchgear Table 6-6: Miscellaneous distribution equipment Table 6-7: SCADA control and communications Table 6-8: Unison maintenance standards Table 6-9: Maintenance budget Table 6-10: Risk Management of Major Project deferrals Table 6-11: Proposed renewal capex projects 2011/ Table 6-12: Summary description of proposed renewal projects ( ) Table 6-13: Overhead line renewal maintenance projects Graph 6-1: Overhead line faults Graph 6-2: Annual motor accident-related faults Graph 6-3: Bird strikes on overhead lines Graph 6-4: Underground cable failures Graph 6-5: Distribution transformer faults Graph 6-6: Distribution switchgear faults Graph 6-7: Vegetation related faults Graph 6-8: Regional renewal investment Graph 6-9: Overhead lines renewal investment Graph 6-10: Underground cables renewal investment Graph 6-11: Distribution transformer renewal investment Graph 6-12: Distribution switchgear renewal investment Graph 6-13: Other distribution equipment renewal investment

237 SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN Life Cycle Asset Management Plan 6.1 Maintenance Planning Criteria and Assumptions Objective Unison s key objective in managing the life cycle of its assets is to ensure that assets perform their required function throughout the duration of their engineering lives, at least cost, while conforming to Unison standards and remaining compliant with applicable legislation. The 2011/12 maintenance programme and ten year forecast are driven by the following principles: Reliable operation to meet the needs of the consumer; Ensure existing assets are safe and compliant with all applicable legislation; Reach the least cost trade-off between different modes of maintenance (repair, refurbishment, replacement); Reach the optimal reactive: preventative maintenance ratio for the Unison asset base; Condition monitoring and predictive analysis form the foundation of asset maintenance; The optimal mode of managing assets varies between asset classes; Determining Optimal Level of Maintenance Expenditure At a macro level, comparative analysis of Unison s total maintenance spend to asset value is regularly compared to other distribution utilities. At a lower level, the effectiveness of each maintenance strategy is carefully and regularly monitored to ensure it is delivering tangible benefits to Unison. Asset failure rates are monitored and maintenance cycles are modified appropriately to balance failure risks against maintenance cost. Combining different maintenance regimes (e.g. opportunistic maintenance vs. cyclical maintenance) to reduce travel costs and the use of alternate technologies are also considered for potential efficiency gains. It should be noted that safety is a significant driver for Unison s maintenance plans and the obligation to ensure public safety is taken very seriously. Maintenance plans will be expected to be compliant with Safety Management Systems implemented as required under the new Electricity Safety Regulations. The 2012 Asset Management Plan will cover in detail the requirements of the Safety Management Systems Maintenance Practices An overview of Unison s maintenance practices is provided below. The asset specific sections provide further detail on maintenance practices Routine and Preventative Maintenance Condition Monitoring and Asset Inspection Condition assessment and inspection is performed to establish an understanding of the assets and their service status and is used as one of the key drivers for maintenance and renewal activities. Unison runs an extensive programme of condition monitoring and assessment on its assets. Inspection processes generating high volumes of data utilise electronic field capture systems to minimise data processing. The field capture devices are predominantly PDA devices using in-house software that allows uploading of data directly into Unison s core

238 6-4 SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN business applications. New condition monitoring technology will be introduced during the next few years as part of the smart network initiative to alert Unison in advance of any potential asset failures. Routine Servicing Time-based cycles of routine servicing are undertaken where condition-based monitoring is not practical or possible. The application of these techniques is based on manufacturer s recommendations, industry practice and Unison s own experience. Corrective and Preventive Maintenance Work is initiated as a result of: Asset condition assessments; Performance analysis of the assets in terms of failures and defects; Predicting asset failures as a result of failure mode analysis; Asset operational importance; Consequences of failure (asset and consumer) Refurbishment and Renewal Maintenance The decision to repair, refurbish or replace an asset will be based on the outcomes of the new Repair, Refurbish or Replace (Triple-R) model. The development of this model was completed during 2008 and was implemented in the 2009/10 year. Incremental improvements of the model have been implemented since its introduction. Renewal maintenance, as prescribed in the Commerce Commission Information Disclosure Regime, will take the form of preventative like for like replacement of assets Emergency/Fault Response Fault and emergency maintenance is usually initiated after a system failure. The initial finding and isolation of the fault, and ensuring that the fault site is electrically safe, is categorised as First Response. Faults are classified as either urgent, requiring immediate action, or repair, which can be delayed after the temporary repairs are completed Standard Life Unison s analysis in a number of areas has supported a number of variations to the asset standard lives stated in the Commerce Commission s 2004 ODV Handbook. The changes have been based on actual performance, and form the basis for valuation and future modelling of investment requirements Risk Where condition assessments indicate increasing likelihood of failure and the consequences of such a failure would be significant, an asset will be considered for replacement.

239 SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN Routine and Preventative Inspection and Maintenance Policies Maintenance Strategy Overhead Lines Asset Class Maintenance Type Action Related Standards (1) 33kV Asset Inspection/ Condition Assessment Annual visual inspection. 5 yearly detailed inspections. Annual aerial inspection for worst performing feeders. NK5020 Routine and Preventative Maintenance Preventative Maintenance: Maintenance identified by inspections and the defect process. Vegetation Control: Tree maintenance identified by inspections and the defect process. NK5119 NK1003 Refurbishment and Renewal Maintenance Refurbishment Not applicable. Renewal Preventative like for like replacements of non-capital assets. NK5119 Fault and Emergency Maintenance First response. Reactive repairs. NK kV Asset Inspection/ Condition Assessment 5 yearly detailed inspections. NK5020 Routine and Preventative Maintenance Preventative Maintenance: Maintenance identified by inspections and the defect process. Vegetation Control: Tree maintenance identified by inspections and the defect process. NK5119 NK1003 Refurbishment and Renewal Maintenance Refurbishment Not applicable. Renewal Preventative like for like replacements of non-capital assets. NK5119 Fault and Emergency Maintenance First response. Reactive repairs. NK5119 Low Voltage Asset Inspection/ Condition Assessment 5 Yearly detailed inspection. NK5020 Routine and Preventative Maintenance Preventative Maintenance: Maintenance identified by inspections and the defect process. NK5119 Vegetation Control: NK1003 Tree maintenance identified by inspections and the defect process.

240 6-6 SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN Asset Class Maintenance Type Action Related Standards (1) Refurbishment and Renewal Maintenance Refurbishment Not applicable. Renewal Preventative like for like replacements of non-capital assets. NK5119 Fault and Emergency Maintenance First response. Reactive repairs. NK5119 Poles (All Voltages) Asset Inspection/ Condition Assessment Annual visual inspection (33kV). 5 yearly detailed inspection (all voltages). Wood poles Deuar Mechanical Partial Load Deflection Testing (MPT 40). NK5020 Other poles Visual inspection. Routine and Preventative Maintenance Preventative Maintenance: Maintenance identified by inspections and the defect process. NK5119 Refurbishment and Renewal Maintenance Refurbishment - Not applicable. Renewal Capital asset. N/A Fault and Emergency Maintenance First response. Minor reactive repairs. NK5119 (1) Unison Maintenance Standards Table 6-1: Overhead lines Underground Cables Asset Class Maintenance Type Action Related Standards (1) 33kV 11kV Low Voltage Streetlight and Security Asset Inspection/ Condition Assessment 5 yearly visual inspection of High Voltage Pole Rise Cable Terminations (as part of the Overhead Line Feeder Inspection). Annual visual or detailed inspection (depending on accessibility) of High Voltage Cable Terminations to Ground Mounted Equipment (as part of GMI-Inspection). NK5020 NK5017 Annual inspection of 33kV gas cable. Cable testing. MS5200 NK4020 Routine and Preventative Maintenance Preventative Maintenance: Maintenance identified by inspections and the defect process. Manufacturer s Standard Refurbishment and Renewal Maintenance Refurbishment - Not applicable. Renewal - Capital asset. N/A Fault and Emergency Maintenance First response. Reactive repairs. Manufacturer s Standards (1) Unison Maintenance Standards Table 6-2: Underground cables

241 SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN 6-7 Zone Substations Asset Class Maintenance Type Action Related Standards (1) Power Transformers (including Tap Changer and Voltage Regulator): 33kV/11kV Asset Inspection/ Condition Assessment Station Inspections: Level 1 Weekly visual inspection. Level 2 2 monthly detailed inspection. Transformer Annual DGA Oil Test. Regulator Oil test when serviced. NK5012 NK5013 NK5042 NK5043 Routine and Preventative Maintenance Routine Services: Transformer 2 yearly. Tap changers 2 yearly or 6 yearly, depending on tap changer type. Regulator 2 yearly, 5 yearly or 10 yearly depending on make and model. Preventative Maintenance: NK5042 Maintenance identified by inspections and the defect process. Refurbishment and Renewal Maintenance Refurbishment Transformer and oil refurbishment. Renewal Capital asset. NK5043 Fault and Emergency Maintenance First response. Reactive repairs. NK5042 Circuit Breakers: 33kV (Indoor and Outdoor) 11kV (Indoor and Outdoor) Asset Inspection/ Condition Assessment Station Inspections: Level 1 Weekly visual inspection. Level 2 2 monthly detailed inspection. Partial Discharge Test 2 yearly. Oil Test When serviced. NK5012 NK5013 Outsourced NK5043 Routine and Preventative Maintenance Routine Services: SF6 3 yearly. Vacuum 3 yearly. Oil 2 yearly. Oil Fault service after every fault operation. Preventative Maintenance: NK5038 & NK5040 Maintenance identified by inspections and the defect process. Refurbishment and Renewal Maintenance Refurbishment Not applicable. Renewal Capital asset. N/A Fault and Emergency Maintenance First response. Reactive repairs. NK5038 & NK5040

242 6-8 SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN Asset Class Maintenance Type Action Related Standards (1) Load Control Plants: Ripple Injection Plants Asset Inspection/ Condition Assessment Station Inspections: Level 1 Weekly visual inspection. NK5012 Level 2 2 monthly detailed inspection. NK5013 Routine and Preventative Maintenance Routine Services: Annual service. Preventative Maintenance: NK5024 Maintenance identified by inspections and the defect process. Refurbishment and Renewal Maintenance Refurbishment Not applicable. Renewal Capital asset. N/A Fault and Emergency Maintenance First response. Reactive repairs. NK5024 Substation Buildings and Equipment: Station Batteries and Battery Chargers Protection relays Station Control Indicators and Alarms Earth Testing Thermovision Grounds and Buildings Asset Inspection/ Condition Assessment Routine and Preventative Maintenance Station Inspections: Level 1 Weekly visual inspection. Level 2 2 monthly detailed inspection. Routine Services: Batteries 2 monthly general service, 6 monthly discharge tests. Relays Electro-Mechanical (4 yearly), Electronic (6 yearly), Microprocessor (6 yearly). Station Control Indicators and Alarms 4 yearly. Earth Tests 5 yearly. NK5012 NK5013 NK5041 NK5022 NK5023 Outsourced Thermovision Annually. NK5080 Preventative Maintenance: Maintenance identified by inspections and the defect process. Refurbishment and Renewal Maintenance Refurbishment Not applicable. Renewal Preventative like for like replacements of non-capital assets. Fault and Emergency Maintenance First response. Reactive repairs. NK5041 NK5022 NK5023 (1) Unison Maintenance Standards Table 6-3: Zone substations

243 SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN 6-9 Distribution Transformers and Voltage Regulators Asset Class Maintenance Type Action Related Standards (1) Transformers: Ground Mounted Pad Mounted Asset Inspection/ Condition Assessment Routine and Preventative Maintenance Annual GMI-Inspection. Earth Test 5 yearly. Routine Service: Corrective maintenance (asset alive) as part of the annual GMI-Inspection. Preventative Maintenance: NK5017 NK5011 NK5017 Shutdown Maintenance identified by the GMI- Inspection and the defect process. Refurbishment and Renewal Maintenance Refurbishment Transformer refurbishment and painting. NK6001 Renewal Capital asset. Fault and Emergency Maintenance First response. Reactive repairs. NK5017 Pole Mounted Transformers Asset Inspection/ Condition Assessment 5 yearly visual inspection (as part of the Overhead Line Feeder Inspection). NK5020 Earth test 5 yearly. NK5011 Routine and Preventative Maintenance Preventative Maintenance: Maintenance identified by inspections and the defect process. NK5020 Refurbishment and Renewal Maintenance Refurbishment Not applicable. Renewal Capital asset. N/A Fault and Emergency Maintenance First response. Reactive repairs. NK5020 Voltage Regulators Asset Inspection/ Condition Assessment 2 monthly detailed inspections. Oil test - When serviced. Earth test 5 yearly. NK5015 NK5043 NK5011 Routine and Preventative Maintenance Routine Service: 2 yearly or 5 yearly depending on make and model. Preventative Maintenance: NK5042 Maintenance identified by inspections and the defect process. Refurbishment and Renewal Maintenance Refurbishment Not applicable. Renewal Capital asset. N/A Fault and Emergency Maintenance First response. Reactive repairs. NK5075 (1) Unison Maintenance Standards Table 6-4: Distribution transformers and voltage regulators

244 6-10 SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN Distribution Switchgear Asset Class Maintenance Type Action Related Standards (1) Ring Main Switches: ABB Asset Inspection/ Condition Assessment Annual GMI-Inspection. Earth Test 5 yearly. NK5017 NK5011 Andelect Magnefix Statter Other Routine and Preventative Maintenance Routine Service: Corrective maintenance (asset alive) as part of the annual GMI-Inspection. Preventative Maintenance: NK5017 Shutdown Maintenance identified by the GMI- Inspection and the defect process. Refurbishment and Renewal Maintenance Refurbishment Painting. Renewal Capital asset. NK6001 Fault and Emergency Maintenance First response. Reactive repairs. NK5017 Air Break Switches Asset Inspection/ Condition Assessment Annual visual inspection (33kV). 5 yearly visual inspection (11kV). NK5020 NK5020 Both inspections form part of the overhead Line Feeder Inspection. NK5036 Earth Test 5 yearly. NK5011 Routine and Preventative Maintenance Preventative Maintenance: Maintenance identified by inspections and the defect process. NK5020 Refurbishment and Renewal Maintenance Refurbishment Not applicable. Renewal Capital asset. N/A Fault and Emergency Maintenance First response. Reactive repairs. NK5020 Reclosers/ Sectionalisers Asset Inspection/ Condition Assessment Reclosers/Sectionalisers Annual detailed inspection. NK5016 (including Auto Links) Auto Links Annual visual inspection. NK5016 Earth Test 5 yearly. NK5011 Routine and Preventative Maintenance Routine Service: 2 yearly or 5 yearly depending on make and model Preventative Maintenance: NK5034 Maintenance identified by inspections and the defect process. Refurbishment and Renewal Maintenance Refurbishment Not applicable. Renewal Capital asset. N/A Fault and Emergency Maintenance First response. Reactive repairs. NK5034 (1) Unison Maintenance Standards Table 6-5: Distribution switchgear

245 SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN 6-11 Miscellaneous Distribution Equipment Asset Class Maintenance Type Action Related Standards (1) Pedestals: Lo-Ped Hi-Ped Asset Inspection/ Condition Assessment Inspection of Ground-mounted Low Voltage Distribution Equipment as and when required by Unison (including minor repairs). NK5019 Steel PVC Routine and Preventative Maintenance Preventative Maintenance: Maintenance identified by inspections and the defect process. NK5019 Refurbishment and Renewal Maintenance Refurbishment Not applicable. Renewal Preventative like for like replacements of non-capital assets. NK5019 Fault and Emergency Maintenance First response. Reactive repairs. NK5019 (1) Unison Maintenance Standards Table 6-6: Miscellaneous distribution equipment SCADA Control and Communications Asset Class Maintenance Type Action Related Standards (1) SCADA Control and Communications Equipment Asset Inspection/ Condition Assessment General Communications Equipment Inspections 2 monthly. Station UHF Equipment Inspections 6 monthly. NK5028 Station VHF SCADA Equipment Inspection 6 monthly. Routine and Preventative Maintenance Preventative Maintenance: Maintenance identified by inspections and the defect process. NK5028 Refurbishment and Renewal Maintenance Refurbishment Not applicable. Renewal Capital asset. N/A Fault and Emergency Maintenance First response. Reactive repairs. NK5028 (1) Unison Maintenance Standards Table 6-7: SCADA control and communications

246 6-12 SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN Unison Maintenance Standards Reference No NK1003 NK4020 NK5011 NK5012 NK5013 NK5015 NK5016 NK5017 NK5019 NK5020 NK5022 NK5024 NK5035 NK5036 NK5038 NK5040 NK5041 NK5042 NK5043 NK5070 NK5080 NK5119 NK6001 Title Vegetation Control Procedure Testing of Cable Assets Inspection and Testing of Standard and SWER Earths Station Level 1 Inspections Station Level 2 Inspections Voltage Regulator Inspections Line Recloser Inspections Ground-mounted Distribution Equipment Inspection Standard Safety Inspection Standard for Ground-mounted Assets Low Voltage Feeder Survey and Condition Monitoring Standard Protection Relay Maintenance and Testing Ripple Plant Inspection and Maintenance Outdoor Instrument Transformer Maintenance Disconnector and Earth Switch Maintenance Metalclad Switchgear Maintenance Outdoor Circuit Breaker Maintenance Station Battery Maintenance Power Transformer Maintenance Insulating Oil Maintenance Sulphur Hexafluoride (sf6) Use and Handling Procedures Thermovision Inspection Basic Distribution Line Maintenance Network Painting Standard NK5034 NK5075 Line Recloser Maintenance Network Voltage Regulator Maintenance NK5023 Station Control Indication and Alarm Testing MS5200 NK5028 Gas Insulated Cable Sheath Testing and Repair Radio and Communications Maintenance Standard Table 6-8: Unison maintenance standards

247 SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN Systemic Asset Failures Overhead Lines Failure Modes and Risks Bi-metal and under-rated joints, in conjunction with under-rated or old system assets, (i.e. figure 6 compressions, preformed line splices and old braided type air break switch flexible leads) installed within the network, are prone to failure under periods of high system loads or fault currents. The existence of hazard trees outside the line corridor poses risks in high winds, with the risk increasing if high soil moisture levels are present at the same time. Animal or bird contacts such as opossums accessing conductors through the lack of an effective guard, or line clashes through bird strikes, or bird contacts that create insulator failures are common problems. There is some steel core corrosion in the ACSR lines and significant deterioration of copper conductors within areas where geothermal gasses (H 2 S and SO 2 ) are present. Some softwood poles with poor preservative retention are piping, causing premature failures. Insulator failures are occurring due to the corrosion of the steel head pins. These failures are difficult to locate and can cause outages. Considerable asset damage is occurring from motor accidents in all regions of Unison s network, both urban and rural. Maintenance Philosophy and Practice Unison s philosophy is to use condition based maintenance and asset renewals based on asset condition surveys completed in accordance with Unison technical standards. The surveys are also used to assess remaining asset life, and are conducted on a five year cycle for distribution circuits and annually for sub-transmission. The results of these RLE assessments are fed back into the RE model. Unison is currently replacing the existing WoodScan ultra-sound pole testing system with a new Deuar Pty Ltd - Mechanical Pole Testing system known as Partial Load Deflection Testing or (MPT 40). Recent in house destructive evaluation tests undertaken by independent Consulting Engineers, on poles tested by the new technology, have provided compelling evidence that this system can provide reliable, quantifiable data on the residual strength and serviceability of wood pole assets. The system also provides an estimation of remaining service life. The MPT 40 system can detect forms of pole degradation that are not detectable by using the current Woodscan system. In Taupo and Rotorua, because of the corrosive effects of geothermal gasses, Unison intends to systematically replace copper conductors with aluminium conductors.

248 6-14 SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN Infra-red photography is being used more extensively as another means of non invasive condition monitoring. This method uses an infra-red heat detecting device to create an image that locates hot spots. Unison has also successfully trialled the use of corona discharge mapping for identification of failing binders and cracked insulators and other failure modes that are almost impossible to identify from ground-based inspections. Unison s maintenance practice is to inspect 33kV and high risk 11kV feeders annually, and all other feeders on a five year cycle. Frequency of inspection is increased if fault rates in particular areas increase to an unacceptable level. 600 Overhead Line Faults 500 Fault Count kV Overhead 11kV Overhead Year Graph 6-1: Overhead line faults Over the past few years the number of overhead line related faults has decreased. Unison has undertaken aerial inspections of some rural feeders over the last few years and has found this method of inspection to be extremely effective in identification of defective components, pole top deterioration and vegetation related issues. It is Unison s intention to expand this system of inspection to cover all rural feeders and a proportion (estimated 50%) of Urban/Rural feeders. This method of survey is a lot quicker than ground-based inspections meaning the time between identification, prioritisation and remedial action is a lot shorter. 50% of rural poles are concrete and do not require ground based inspection. The current five yearly ground based inspection programme is to be restructured to focus on inspection and testing of Wood pole assets and those assets within urban areas plus small pockets of rural lines that cannot be aerially inspected for reasons such as sensitive stock. Unison is adopting the use of Hendrix Spacer Cable system where traditional bare wire circuits require high ongoing maintenance and there are reliability concerns.

249 SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN 6-15 Areas have been identified that will benefit from the use of the Hendrix system, particularly sections of sub-transmission and 11kV double circuit lines, also within forestry areas where line corridors are compromised. The system has been adopted by Unison as a Smart Technology initiative that offers significant improvements in system reliability. 60 Motor Accident Related Faults 50 Fault Count Year Graph 6-2: Annual motor accident-related faults The number of motor accident related faults had a significant reduction in 2010/11.. A number of initiatives have either been implemented or are being investigated to reduce the number of occurrences. High incident areas have also been investigated to see what action can be taken to minimise further asset damage. The use of reflective markers is to be expanded along with the painting of lower pole sections to increase visibility of poles on high volume traffic areas.

250 6-16 SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN Bird Strike Faults Fault Count Year Graph 6-3: Bird strikes on overhead lines The number of bird strikes on overhead lines, which has been decreasing in recent years, increased this year and is still a significant contributor to overhead line faults. This increase has occurred despite the installation of bird flight diverters, the replacement of copper conductor with more visible aluminium conductors, and changing from flat to delta construction in high incident areas. It is likely that this increase is a one off phenomenon Underground Cables Failure Modes and Risks 1970s XLPE cables are prone to water treeing when installed in wet environments. The rate of treeing is related to a number of factors including age, service conditions and environmental factors such as moisture levels in the surrounding soils. LV failures are only likely to occur where the cables are disturbed (e.g. damaged by third party excavation) or at formed joints or terminations where incorrect techniques have been employed at the time of installation. In some instances such faults may take a number of years to manifest. At some stage the insulation will reach the end of its operational life, but at present there is no evidence of this starting to occur. Sheath testing the Faraday to Bluff 33kV gas filled cable monitors any breach in the PVC sheath causing potential corrosion to the aluminium gas sheath. This cable is also exposed to damage from third party excavation and only limited spares are available. The Rotorua Malfroy Road to Arawa 33kV sub-transmission cable is similarly sheath tested and has been previously damaged by third party directional drilling and excavations.

251 SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN 6-17 Older, particularly the old Power Board epoxy type joints and terminations fail over time usually because of moisture ingress. These failures generally occur earlier than actual cable failure. The use of non-pressure rated PILC cable terminations on pole risers has caused some failures. This has tended to occur during high summer temperatures which cause the impregnated oil to expand and the hydraulic pressure on the termination insulation can cause the lead sheath to fracture which then allows moisture to enter. Single cored 11kV interruption cables do fail due to the treeing phenomenon mentioned previously. This category of assets was purchased from and their manufacture consists of a very light braided screen over the insulated core. Consequently exposure to system fault currents also presents another common failure mode to these cables. Prior to the 2003 acquisition of the Taupo /Rotorua network the common practice on 11kV cables was to break out the screens and earth only one end. This presents problems during earth faults. Older style cast iron pot head cable terminations are not displaying the level of failure rates reported by other utilities. Unison is monitoring any failures of these terminations but has no immediate plans for programmed replacement. Aluminium sheaths on earlier XLPE cables have also suffered due to corrosion as moisture enters the cables over time. Excavators and contractors operating directional drilling equipment represent considerable risk to cable assets. Maintenance Philosophy and Practice Asset condition inspections of all cable terminations and risers are undertaken in accordance with Unison standards. As maintenance on a buried asset is very difficult in practice, Unison s focus is to ensure that high standards of workmanship are used when laying, jointing and terminating cables. Consequently contractor approved access to the network requires stringent and ongoing assessment. This is mainly done through setting technical standards and auditing of contracted work. The question of the contractor liability is being evaluated with regard to the liability period and the tagging of workmanship for completed works. Recent 33kV cable installations have had fibre optic cables installed to allow future mapping of the operating temperatures down the length of the cable. The 33kV gas cable is inspected annually to monitor degradation of the outer PVC sheath which may expose the aluminium sheath to possible corrosion. Gas consumption is also monitored to identify failure points in the aluminium casing. Maintenance to identify and repair any segments is performed as required. Unison has experienced a high number of faults on 1970s 11kV XLPE cable. The Company has implemented a condition monitoring programme on 33kV and 11kV cables identified in network critical zones and prioritised on expected risks of failure. This programme involves development of a comprehensive regime of diagnostic and proof tests including, insulation resistance, polarisation index, tan delta, and VLF pressure testing. While assessing the condition of a cabling system is technically challenging, it is an essential element of Unison s asset management practices to effectively manage this asset class in the coming years as a large portion of the cables near end of life.

252 6-18 SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN kV Underground Cable Faults Fault Count Year Graph 6-4: Underground cable failures LV cables tend to be repaired or renewed reactively or in conjunction with associated HV work. Unison is conscious of the aging nature of LV cables in the business districts of its area. Some LV cabling will be renewed in conjunction with HV cable replacements where it makes practical and economic sense, but programmed replacement of these assets is not currently planned to start in the next nine years. Other practices to mitigate the potential risks of damage to critical cable assets, particularly 33kV circuits, have included installation of additional route location markers and the assistance of the Rotorua District Council to prohibit excavation activities within sub-transmission areas without supervision Power Transformers Failure Modes and Risks Transformers and their associated tap changers are regularly maintained and have few failures. The main cause of transformer failure is either an insulation failure causing short circuit or a winding failure causing an open circuit. The probability of either of these occurring is very low provided good maintenance regimes are kept. The paper insulation in the transformer can be tested for strength in a laboratory and this test is completed when a transformer is refurbished or when internally inspected for any reason. Deterioration of the insulation materials will occur at a much faster rate if the transformer is run for long periods at higher operating temperatures. Some transformer tap changers have a history of failure from excessive carbon deposits in the tap changer compartment. The manufacturer has investigated this and completed upgrades on all the affected transformers. These upgrades included the replacement of internal operating shafts and installation of a continuous oil filtration plant for the tap changer insulation oil. Replacement parts for tap changers, particularly contact replacement, will become a problem for some of the older model tap changers in the future.

253 SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN 6-19 Oil leaks continue to be a nuisance in old transformers as gaskets and seals deteriorate with age. Leaks from bushings and cover gaskets are costly to repair as they take considerable time. Risks from failure are generally mitigated by the security planning guidelines used on the network and effective protection systems to restrict the likelihood of consequential damage to other assets. Maintenance Philosophy and Practice Due to the operational importance and age profile of these assets, extensive condition monitoring and maintenance programmes are in place to ensure reliability of service. Unison s power transformers are subject to a cyclic time-based preventive maintenance programme. A two year cycle is used for the transformer and associated protective devices, and two year or six year cycle for the tap changer maintenance depending on the type and model of tap changer. Two new Pauwels manufactured transformers installed at Biak Street in Rotorua have tap changers fitted with vacuum bottle tap changer switching and these tap changers are generally maintenance free. Of major concern is the availability of experienced staff familiar with these assets to carry out maintenance works on these valuable and intricate assets. The exterior condition of most transformers is reasonable with rust treatment and paint touch up work being completed as part of the regular maintenance activities. Some transformers now require full painting to enhance transformer life. Dissolved gas analysis (DGA) tests are performed on all zone substation transformers on an annual basis. This test monitors the internal condition of the transformer by assessment of the gasses that are generated in the insulating oil. DGA testing has now been performed for a number of years and the trends emerging from the results give valuable insight into the state of the transformer. Poor results would require that the transformer be closely monitored or that the oil be refurbished on site to remove gases and chemicals back to new oil levels. Furans in the insulation oil have been tested for the first time. This test provides an indication of the aging of the paper insulation without having to take a sample of the paper from inside the transformer. Future oil samples will provide a trend that we will be able to assess and determine the remaining life of the transformer. A study has been initiated into the benefit of installing cooling fans onto transformers that are without forced air cooling. It is considered that with the addition of the cooling fans, this will allow an increase in maximum loading and may defer replacement. Unison is currently installing on line temperature monitoring on critical transformers so that the transformer load and temperature can be remotely monitored from the Unison office. In previous AMPs Unison had indicated an intention to refurbish a number of older transformers in the coming years. A review of the economics of this practice has questioned whether the approach is in fact, the most economic proposition, as there is some uncertainty as to how much life extension this practice delivers. On review of the potential upgrades required to support future load growth in a number of substations, it has been assessed that holding a full size system spare and running a number of assets to near failure would yield a lower cost strategy. Future transformer refurbishments will be considered on evaluation of the transformers future requirements.

254 6-20 SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN Infra-red scanning is used as another means of non-invasive condition monitoring. This method uses an infra-red heat detecting device to create an image that locates hot spots on external connections. It is also useful in confirming effective operation of cooling radiators by temperature measurement over the surface of the radiator. Invasive preventive maintenance and transformer outages are planned together with maintenance of other associated equipment to minimise outage time Circuit Breakers Failure Modes and Risks Circuit breakers are regularly maintained to ensure their reliability. They are required to operate quickly as required by their protection scheme to limit the outage area. Some older circuit breakers nearing end of life are becoming slow in their operation and require more frequent maintenance to ensure they operate within the required parameters. Some 11kV circuit breakers have indicated partial discharge in the current transformers within the solid resin insulation of the fixed part of the circuit breaker cubicle. This is being monitored with bi-annual partial discharge testing. There are two old minimum oil type English Electric 33kV outdoor circuit breakers that have a known potential failure mode which can arise if moisture ingresses through gaskets and seals into the paper insulation, eventually causing insulation failure. These last two circuit breakers are at non-critical sites and can be by-passed if required. They will progressively be replaced. The consequence of a catastrophic circuit breaker failure is widespread outages and possibly fire damage to buildings and other equipment. The chances of personal injury are greatly lessened by remote operation and the infrequent proximity of personnel. Unison takes all practicable steps with its maintenance and safety procedures to mitigate this possibility. For these reasons Unison places a strong emphasis on replacement of older circuit breakers with modern vacuum or gas insulated types. Unison is currently investigating the use of operator Arc Flash protection when operating circuit breakers and other equipment. Maintenance Philosophy and Practice Circuit breakers are subject to a cyclic preventive maintenance programme based on insulation type, previous history and experience. Unison s documented maintenance standards provide information on maintenance periods based on make and model, and provide information on service and condition monitoring requirements. Unison has a policy of purchasing circuit breakers of proven manufacture and reliability and recognises that reliable service life can only be achieved by sound condition monitoring and maintenance procedures. Some circuit breakers may never operate between maintenance intervals and this may cause the mechanisms to be slow to operate from a lack of operation. Oil circuit breakers require more intensive maintenance than vacuum or SF 6 gas insulated circuit breakers. This is because insulating oil and internal parts must be regularly maintained to ensure proper insulation levels. The main causes of insulation deterioration are carbon deposits in the insulation oil, and moisture ingress through breathers and vents into the paper and wood insulation material. Oil circuit breakers are serviced after a predetermined number of fault operations have occurred in addition to the scheduled service.

255 SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN 6-21 Two substation 11kV indoor circuit breaker boards in the Taupo region are due for replacement as they require manual spring charging that limits operational flexibility and are near the end of serviceable life. Several old 33kV AEI JB424 circuit breakers are at end of life or are under rated. These are to be progressively replaced. Outages are planned in conjunction with the maintenance requirements of other associated equipment so as to minimise outage time. Partial Discharge Test This is a relatively new tool for non-invasive condition assessment of insulation. It measures internal and surface discharges from insulation which is analysed and the location of the discharge identified. This is used on all indoor switchgear and some defects have been found and repaired. This testing is now integrated into a regular maintenance schedule. Infra-red Scan Infra-red thermography is used as another means of non-invasive condition assessment. This method uses a heat detecting thermo-vision camera to obtain an image that can identify hot spots around cable termination boxes. Condition, age, function, location, criticality, fault levels, performance and cost history are all taken into account before replacing the asset Other Substation Equipment and Buildings Failure Modes and Risks Current transformers installed in old Reyrolle indoor circuit breakers show some insulation deterioration when subjected to partial discharge testing. This is being monitored as failure can cause considerable damage. Buildings and fences are regularly inspected to ensure they remain in good condition to provide site security and protect equipment. The outdoor insulators at the Awatoto substation are cleaned six monthly of salt deposits to prevent flash over from contamination. The substation earth grid at Arawa substation is constructed from aluminium conductor as is in an area of severe corrosion from underground gases where the usual copper conductor is not suitable. This aluminium conductor requires regular inspection to monitor corrosion. Risks associated with failure of other equipment are generally considered minor as alternative operating modes exist, or repair/replacement can be affected in a timely manner.

256 6-22 SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN Maintenance Philosophy and Practice Substations are inspected weekly to monitor station and equipment security with a further more extensive inspection at two monthly intervals that includes minor maintenance activities. Maintenance standards provide information on station inspections and condition monitoring requirements. Substation security is to be upgraded throughout the network with the installation of a magnetic lock operated by personal access card, in addition to a new common substation specific lock and intruder detection. Some substation sites will also be monitored by surveillance camera for addition security. A thermo-vision survey of all substation HV equipment is completed annually to locate hot spots that may indicate possible areas of failure Distribution Transformers and Voltage Regulators Failure Modes and Risks Ground-mounted transformers are often situated in locations frequented by the general public and therefore require adequate locking devices to prevent unauthorised access. Signs and notices are also placed on equipment to advise of the electrical danger. The main causes of failure for pole-mounted transformers are lightning strike and failure from general age and condition. Ground-mounted transformers generally fail from deterioration of the structure due to rust although there are a number of assets being damaged by motor accidents. Some transformer sites are protected with a fibre glass cover and these have been identified as needing replacement with structures providing a higher level of safety and security. The main environmental issues are exceeding noise limits as defined in town planning controls and oil discharge when tanks fail from rust or damage. Some transformers mounted on pole and a half structures could become unstable in a seismic event. Consequently, Unison is progressively replacing at risk assets with ground-mounted equivalents. Voltage regulators have had problems with motor capacitor failure rendering the regulator inoperable. This defect has been identified with the manufacturer who is providing assistance in repairing this failure mode. Maintenance Philosophy and Practice Transformers are inspected and their condition assessed on a time-based cycle completed on a feeder by feeder basis. Defects are identified and action taken as required. The main cause for the replacement of transformers is from rust deterioration of the tank and oil leakage. There are a number of transformers at the end of their expected operational life, but still in reasonable condition and therefore there are no current plans to replace these. In-service failures due to internal electrical failure are extremely rare for groundmount assets, but some assets need to be replaced due to external influence such as motor accidents.

257 SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN 6-23 Distribution Transformer Faults Faults Count Year Graph 6-5: Distribution transformer faults Transformers that are removed from service are condition assessed for refurbishment. Refurbishment generally includes dry out of windings, tank repairs, repainting, replacing gaskets and seals, checking bushings and oil maintenance. Refurbishment of transformers is expensive and only the higher kva-rated transformers are considered for this. The population of 11kV line voltage regulators are of new technology and are in good condition and performing well. A series of motor capacitor failures which render the tap changer inoperative have been experienced. Replacement capacitors fitted in the control box are progressively being installed as a modification and with the assistance of the manufacturer. Regular invasive condition monitoring of transformers under 750kVA are not strategically placed with regard insulation testing, insulation oil testing and maintenance are not considered economic for these assets unless specifically required. However a new oil testing regime on transformers is in place for all important customers and strategic units above 750kVA, and to date has proven invaluable. Repainting of transformers is performed when the asset is assessed as deteriorating because of protective coating failure. Several ground mount transformers with specialised coatings have been installed in hostile environments and will be evaluated over time. Unison has committed to improving the security of all of its ground-mounted transformers against accidental entry by members of the public. Part of this initiative requires that all assets will have two security devices on each door to ensure that if one mechanism (padlock or bolt) fails, the second device will still ensure safety of the public. In previous years Unison had performed invasive inspection of all ground-mount transformers on a two yearly cycle. This has been reviewed in conjunction with the requirements to ensure site security on a regular basis, and the maintenance programme is now on an annual cycle. This has resulted in earlier identification of potential problems. All earths are tested on a five year cycle. Assets located over shingle or pumice areas where the amount of conductive organic soil material is small pose challenging locations to achieve earthing cost effectively.

258 6-24 SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN Distribution Switchgear Failure Modes and Risks Over the years RMS units have been supplied by a number of manufacturers with a consequent variation of quality. Generally the oil type switchgear has provided reliable performance considering the number of units installed in the network. There have been mechanism failures in some of the older units usually caused by defective welding. The manufacturers have since eliminated these failures. Early retirement of RMS units can be due to oil leaks from gaskets and seals or damage from motor accident. A number of failures have occurred in the past couple of years which are believed to be due to poor workmanship. Installation of wrong HV HRC fuse types has also caused fuse switch failures. Incorrect fuses in these switches are being identified and progressively replaced. The Statter type RMS units are now 40 years old and no longer manufactured or supplied in New Zealand. The VL type fuse switch has in place an operational safety restriction to prevent it being operated while live. These switches are being progressively replaced in Unison s network. Magnefix RMS units have suffered badly from humidity and harsh environments. This has caused the links to corrode and jam, and also allowed tracking to occur over the insulating surfaces. Old cable terminations are another source of failure in these units. These switches are only able to be operated single phase and this restricts operational usefulness. This type of switchgear is now over 35 years old and is being progressively replaced. The Long and Crawford RMS units manufactured in the early 1970s have a problem with the deterioration of the fuse clips. These have a potential of falling into the tank during operation. An operational safety restriction to prevent the fuse switch being operated while the unit is live has been placed on these units. Cable termination failure and subsequent damage to the attached RMS has also been a major cause of replacement for these assets. Specifically in the Taupo Rotorua area this impacts on network performance, where historically 7 switches are attached to one bus due to the RMU bus extension system. Steps are in place to identify such sites and reconfigure the network in this regard. A small number of reclosers have suffered from a manufacturing defect, but control boards have now been replaced on the affected units. Occasionally ABS contacts may not align correctly, or the operating rods have insufficient ability to close the contacts properly. These events are rare and usually happen on switches of the older type that have not been operated for a long time. Environmental conditions have caused failure of these assets. Corrosion in the thermal areas deteriorates copper conductor and contacts and galvanised steel considerably. Motor accidents causing damage to these assets has also risen in recent years.

259 SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN 6-25 Maintenance Philosophy and Practice Overhead and ground-mounted switchgear assets are visually inspected and condition assessed as part of the feeder inspections on a time-based cycle. Defects are identified and actions taken as required Distribution Switchgear Faults Fault Count Year Graph 6-6: Distribution switchgear faults RMSs are inspected as part of the annual ground-mount inspection (GMI) regime. ABS s are inspected as part of the five yearly feeder inspections. Maintenance of these switches is carried out in conjunction with remedial works from the feeder inspections. Repainting of switchgear is only done where the asset itself is deemed to be deteriorating because of protective coating failure. Distribution earths are resistance tested on a five year cycle and the condition of these earths varies widely. Some additional attention is required in the Rotorua area to combat the effects of corrosive geothermal gases. However there are still ongoing issues with workmanship and the contractor liability period is being reviewed. Due to the risks associated with failure of oil insulated switchgear, Unison has introduced a new SF 6 type 11kV SafeLink switch as a reliable and cost effective alternative product replacing the use of oil insulated switchgear Load Control Plant Failure Modes and Risks The ripple plant in Hawke s Bay continues to provide good service however there have been a few failures with the HV capacitors and the cause is unknown. It is possible to have one plant out of service and still send a satisfactory signal into its area from the other plants. With increases in system load this will be less effective but should be satisfactory for the forecast period.

260 6-26 SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN New plant installed at the Fleet Street substation in Taupo also provides a reasonable level of redundancy should any individual asset fail. Rotorua is covered by a number of individual plants. The three rotary plants in Rotorua are the most at risk as they are operated regularly and are subject to deterioration in bearings, rotor binding failure and vibrations from out of balance. Maintenance Philosophy and Practice Load control plant is inspected on a regular time-based cycle. Defects are identified and actions taken as required. From time to time Unison will commission a report by suppliers and will make choices based on the outcome of those reports. Unison has a maintenance contract with Landis+Gyr Ltd for the Taupo and Rotorua static plant. This is to be extended to cover the rotary plants in Rotorua and the three Hawke s Bay plants Miscellaneous Distribution Equipment Failure Modes and Risks There are no major issues with asset performance in this category, principally because the consequences of failure (loss of supply) associated with these items are usually localised. Old DDO fuses with the double open ended tubes allow water to enter and corrode the link, leading to premature fuse operation. These are being replaced by more substantial drop out fuses when they fail. Problems with corrosion in the geothermal areas of Rotorua increase failure and replacement rates in localised regions. There are a number of sets of old glass type 11kV fuses still in operation in the Rotorua network. These are deemed to be a health and safety risk and are being replaced as and when they are identified. Failures are generally due to old age and corrosion, with low risk to network operations due to the localised impact of failures. Maintenance Philosophy and Practice There is limited ability to undertake preventative maintenance work on assets in this category and it would generally be uneconomic to do so. Pole-mounted fuses are visually inspected as part of the line inspection programmes, but most replacements are identified when faultmen visit the assets to service a unit that has operated under fault. General condition of fuse sets located inside transformer housings are checked as part of Unison s GMI inspection regime Vegetation Description From a network perspective vegetation is not an asset, but the management of vegetation in close proximity to power networks has a profound impact on network performance.

261 SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN 6-27 For Unison s lines to function reliably they require minimum clearances to be maintained. Any intrusion into this space by conductive materials can lead to an electrical failure. Vegetation is the most frequent cause of intrusion into this space. The Electricity (Hazards from Trees) Regulations 2003 means network lines now have defined clearance zones in which vegetation must not encroach. Liaising with tree owners to maintain these zones is Unison s responsibility, and monitoring and controlling vegetation problems is an ongoing requirement. Condition Hawke s Bay has been subject to a reasonable vegetation management programme over the last decade and line corridors are generally clear. The Taupo region is generally good with only a small number of areas where line security is being compromised by growth in close proximity. In the Rotorua region Unison s focus is to regain control and bring the area to the same standard as other parts of its network. Unison has had to increase its expenditure dramatically in the last three years to mitigate the increasing levels of faults occurring on the network from vegetation. Occurrences of vegetation growing into ground-mount transformer cabinets and causing flashovers are rare, with existing inspection practices providing good preventative measures to vegetation problems on ground-mount assets. Failure Modes and Risks Risks to performance of the network from vegetation-related issues come from the following areas: Falling Hazard Trees Falling hazard trees are those individual trees outside the immediate line corridor, but within falling distance, and considered a risk in a severe weather event. These tend to be species and/or age related situations. Shelterbelts Shelterbelt trees in close proximity to the line corridors and not maintained are a common threat in parts of Unison s region. Relationships with cutting contractors and shelterbelt owners over previous years have improved the management of these trees and now represent lower risks to network operation. Severe Weather Events Debris can be blown over significant distances in severe storms. There is little preventative work that can be done to prevent problems arising from this cause. Fire There is potential risk to property and assets associated with tree contact or sometimes with short circuit faults causing hot metal to fall into dry vegetation. Forest plantings are particularly vulnerable and the economic consequences of fire can be very high.

262 6-28 SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN Maintenance Philosophy and Practices Unison has made a strategic business decision to terminate its external vegetation contracts and to bring vegetation contracting services back within the UNL group. The contractor has a zero tolerance for unplanned vegetation related outages on all the sub-transmission lines written into the contracts. This provision encourages the contractor to regularly patrol all the sub-transmission lines and ensure all necessary cutting is completed. Relationships with councils, forestry and Department of Conservation representatives are evolving with more cooperation between parties enabling better tree management. Unison s strategy for vegetation control will result in an initial first cut for the whole network is to be completed within three years. This has resulted in a considerable increase to operational costs in the short term, but it is expected that some recovery will be made in cutting costs by transferring the ongoing financial responsibility of cutting and trimming to the tree owner(s) on future maintenance cycles. The significant administration costs incurred to comply with the regulations will offset this benefit to some extent. Significant improvements in the risk management framework and prioritisation of vegetation across the network have occurred in the past year. The feeder sections are prioritised for cutting based on feeder backbones out to protective recloser devices and beyond, and on customer densities within feeder sections Vegetation Related Faults Fault Count Year Graph 6-7: Vegetation related faults Strong winds in December 2010 and the recent cyclonic events have had a negative impact on the vegetation faults in recent months.

263 SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN SCADA Control and Communications Failure Modes and Risks There is a variety of component asset types and consequentially of failure modes. The most common causes of failures are: Faults, typical of overhead and underground lines and cables; Electronic component failures due to age, voltage spikes, or ambient heat; Loss of power supplies; Outages on the VHF channels -usually due to weather; Outages on the leased IP networks. Failure of these systems causes a considerable inconvenience but generally will not compromise safety as manual systems can be used for switching and other functions. Maintenance Philosophy and Practice Routine maintenance and condition monitoring ensure these assets perform reliably and future renewal requirements are identified promptly. The heat generated from electronic components is causing some equipment to fail in some locations. Air conditioners are being installed at locations where the ambient heat is a problem. Unison is currently replacing obsolete RTUs and upgrading the communications infrastructure across the Taupo, Rotorua, and Hawke s Bay regions. This project will provide a TCP/IP platform to each substation to support future communication needs and allow the introduction of the DNP-3 communications protocol Maintenance Budget Unison s Maintenance budget for the 10 year planning period is presented by asset category in Table 6-9. Maintenance Forecast ($000) Asset Category Year Year Year Year Year Year Year Year Year Year OVERHEAD LINES 4,060 4,060 4,060 4,060 4,646 4,646 4,510 4,265 4,244 4,114 UNDERGROUND CABLES CIRCUIT BREAKERS OTHER SUBSTATION EQUIP & BUILDINGS ZONE TRANSFORMERS DISTRIBUTION TRANSFORMERS/REGULATORS DISTRIBUTION SWITCHGEAR LOAD CONTROL MISC DIST EQUIPMENT VEGETATION 1,287 1,287 1,287 1,287 1,048 1,048 1,048 1,048 1, SCADA COMMS POWER QUALITY TOTAL 9,587 9,587 9,587 9,587 9,482 9,482 9,264 8,862 8,837 8,457 Table 6-9: Maintenance budget

264 6-30 SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN Procurement Practices and New Asset Technical Evaluation Unison employs a product approval process on all products entering its networks. This is to ensure that all operational and life cycle considerations are taken into account before a product is permitted on the network. This allows Unison to ensure rapid response to outages ( like for like replacements), minimise inventory and spares holding levels, confirm sufficient after sales support is available and ensure that short term cost saving drivers do not lead to a higher overall life cycle cost of operating the network. The Technical Evaluation Committee (TEC) has a pivotal role in the approval of new products with the authority to consider and if seen fit, recommend products for approval. The TEC is a cross-functional committee with members from design, asset management, operations, UCSL (contracting), project management, and network planning sections. Final approval for the introduction of new products is issued by the General Manager Networks and Operations. In the future, the Committee will be asked to consider the use of solid dielectric vacuum switchgear (both pole and ground mounted) and fully screened 11kV fuse holders for transformer HV cabinets as an alternative to exposed 11kV fuses. 6.3 Non Network (Smart Grid) Solutions In section 5.5 Unison discusses the benefit of smart network technologies as non-network options and considers them to be an integral part of its smart grid initiative. These new technologies also apply to life cycle asset management by providing improved information on asset health through online condition monitoring and diagnostic information to predict remaining asset life. Through enhanced asset information Unison is able to make informed risk adverse decisions on the asset remaining life and optimise the renewal investment programme. These technologies are discussed in detail below. Real Time Monitoring Underground Circuits Due to the increasing complexity of the thermal relationships along cable routes, the ability to continuously measure the temperatures along the cable has proven invaluable, providing critical operational data to engineers, especially in the case of system faults such as a hot spot that could result in cable failure if they are not corrected. There are currently two types of technology available which are detailed below: 1. Distributed Temperature Sensors utilise fibre optic cables and provide a temperature profile along an entire cable route continuously. This type of installation is to be used when new 33kV circuits are to be installed due to the high associated cost of retrofitting. 2. Thermal Resistivity and Moisture Sensors utilise sensors that are installed at specific hot spots along the cable route and will be used where the cable has been installed for a number of years and has no fibre call installed. Distributed Temperature Sensors (DTS) The DTS system utilises fibre optic sensors. The sensor attached to the end of the fibre optic cable which is run alongside the 33kV cable, makes it possible to record the temperature profile along an entire cable route continuously, and is able to pinpoint the exact location of hot spots within a meter. Since the measuring principle employed is purely optical, the presence of electromagnetic influences, which can result in false sensor signals in other technologies, does

265 SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN 6-31 not affect the DTS unit. Unison has a policy to install DTS capable fibre optic cable with all new underground 33kV cabling. Unison has purchased a portable DTS monitoring unit and is currently monitoring the Napier 1 & 2 33kV circuits between Onekawa Switching Station and Faraday Substation. The unit will be left on these circuits for a full year in order to monitor temperature variations caused by seasonal load fluctuations and changes to the soil moisture content. The unit will then be moved to other circuits and the cycle repeated. This will assist in the planning of future sub transmission cabling projects as well as identifying possible hot spots on existing circuits which may have the potential to develop into a future fault. Figure 6-1: DTS Overview Thermal Resistivity & Moisture Sensors Thermal Resistivity Sensors calculate the soil s thermal resistivity by applying power to the heater element of the sensor and measuring the subsequent change in temperature of the soil at every 30 second interval for 30 minutes. The initial and the final measured temperatures are then used to calculate the thermal resistivity. Secondly soil moisture temperature sensors are used to measure the moisture of the soil. This will then be used in conjunction with the thermal resistivity data to come up with a thermal dry-out curve. Unison has deployed this technology on the City 33kV feeder between Windsor substation and the overhead termination structure off the end of Jubilee St. Data from this trial is currently being collected, interpreted and evaluated in order to validate the results. A larger rollout of this technology is planned for this year. Overhead Lines Providing sufficient electrical power reliably requires ongoing monitoring of temperatures within overhead 33kV lines that are more susceptible to atmospheric changes than buried cables. There are a number of technologies available that provide real time overhead line monitoring. Unison has decided to introduce a lower cost option and will be installing weather stations along some of the main 33kV overhead lines. Weather Stations By installing a number of strategically placed weather stations in the immediate vicinity of overhead sub-transmission conductors, real time wind speeds, wind angles and ambient temperatures can be fed into an algorithm which processes

266 6-32 SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN this information and coupled with 2 hour weather forecasts can determine the dynamic rating of the line. This information can be supplied in real time to network operators and can be very useful during a contingency event where the lines static winter or summer rating may need to be exceeded for a period of time. This technology can be used to provide dynamic rating of either critical circuits or an entire sub-transmission network and is relatively inexpensive and highly reliable. Decisions on the upgrading or installation of lines are often based on thermal load. By deploying this technology we can accurately determine ratings which may result in the deferral of expensive line upgrades. Progress has been made on this initiative and it is planned to install a significant number of weather stations across Unison s (Hawke s Bay initially) strategic 33kV overhead network this year. Power Transformers Unison is utilising Transformer Monitoring Sensors (TMS) to measure factors that could impact on the set design rating of our power transformer fleet. New TMS systems are being retrofitted to existing transformers and new transformers are ordered with this functionality build in. The TMS sensors can provide the following functionality: Direct oil temperature monitoring; Direct winding temperature monitoring; Load monitoring; Gas monitoring. Progress has been made retrofitting existing transformers with this technology. It is expected that the remaining transformers on Unison s network will be completed this year. Powersense Sensors This technology uses state of the art current sensors to provide accurate current, voltage and fault passage information in real time over the mesh radio network back to Unison s information management systems. This equipment can be used on both overhead and underground reticulation. The underground current sensor can be attached non-invasively to MV cables making it an ideal solution for retrofitting to existing network equipment. Unison is currently trialing this technology and if successful will proceed with a larger rollout this year across its entire network. Figure 6-2: Powersense Current Sensor Insulator Pollution Monitoring (IPM) This technology is a complete system designed to monitor the level of pollution on high voltage insulators, to avoid flashovers and serious disturbance to the power supply.

267 SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN 6-33 In many areas, pollution causes flashovers on overhead lines and substation insulators, resulting in serious disturbances of the electric power supply. Cleaning insulators can prevent problems, but it is a costly practice, especially if the timing is wrong. IPM is designed to perform continuous online monitoring of external pollution effects on high-voltage insulators and other insulator housings, like surge arresters and bushings. By measuring the surface leakage current of the insulators, IPM can classify the severity of the pollution. This information can be used to make decisions on insulator maintenance. Data is stored in the data acquisition unit and will be communicated back into Unison s information management systems. The data can be downloaded for further analysis with dedicated software or a spreadsheet. The system can be set to issue alerts when certain threshold values are exceeded. IPM is designed to assess site severity and to give an alarm when pollution levels exceed predefined threshold values. The threshold values can be obtained by experience and/or laboratory tests. Typical application areas for the IPM: Along coastal areas exposed to salt pollution; Areas with heavy industrial pollution; The system is suitable for use on all kinds of insulators: glass, porcelain, polymeric and voltage levels from 11kV to 765kV. Benefits Allows optimise cleaning and maintenance of insulators to prevent pollution flashovers; Reduces insulator maintenance cost by enabling cleaning of insulators only when necessary; Validates performance characteristics of different insulator designs (shape and length) and/or insulator materials under polluted environments; Allows to define the pollution severity in local areas for pollution class specification of equipment. Unison will be installing trial units on the 33kV Mahora - Camberley and North Tie 33kV feeders to monitor insulator pollution levels. Insulator pollution has been problematic on these feeders, and the impact of faults can be severe. It is planned to monitor the results for a 12 month period prior to an evaluation of the device being carried out. Based on this evaluation a decision will be made on any further rollout of this technology.

268 6-34 SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN Figure 6-3: Insulator Pollution Monitoring Risk Management The implementation of these smart network solutions enables the deferral of seven major renewal projects by between three and five years. During the deferral period the assets involved will become increasingly susceptible to age related failures. To mitigate the risk of failure in service, specific lifecycle asset management techniques have been identified for each deferral. This is summarised in the table below, along with a probability of having to undertake the project earlier than estimated. Project Mitigation Deferred Expenditure ($k) Probability Runanga Zone Substation - 11kV Switchboard Replacement Increased inspection frequency 1,100 10% Taupo South Zone Substation 11kV Switchboard Replacement Increased inspection frequency % Hastings Zone Substation- 11kV Switchboard Replacement Increased inspection frequency 1,100 10% Flaxmere Zone Substation Power Transformer Replacement Increased inspection frequency Transformer sensors Load reduced with McCains now supplied from a dedicated zone substation Network spare transformer to be purchased in 2011/12 2,100 10% Fernleaf 33kV Feeder Replacement Increased inspection frequency 1,500 20%

269 SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN 6-35 Project Mitigation Deferred Expenditure ($k) Probability Line thermal sensor Windsor Zone substation - City 33kV Feeder cables Tan Delta Tests and remedial works to cable terminations. 1,200 10% Faraday-Bluff Hill 33kV gas filled cable Installed cable markers over route. Informed land owners and NCC of implications of damage. 1,300 10% Table 6-10: Risk Management of Major Project deferrals As well as these mitigation strategies, an additional provision of $1M has been made available for reactive renewals. This provision is informed by the quantum of project values and the assigned probability of having to undertake the project during the deferral window Transformer Spare In 2011 the system spare transformer was installed at McCain s, providing a dedicated substation for a key customer. To ensure a network spare is retained, a new transformer will be purchased and installed at Windsor zone substation. This transformer will be installed in a manner that will allow easy removal if it is needed elsewhere on the network Flaxmere Zone Substation Due to the establishment of the McCain s substation, the load at Flaxmere has been reduced to a level well within the rating of a single transformer bank. This means a major reduction in the risk of losing load if one of the aging Flaxmere transformers were to fail. To further mitigate this risk, a fast transfer scheme is being investigated for implementation in 2012/ CAPEX Renewal Planning Criteria and Assumptions Asset Renewal Policy Asset renewal is like for like replacement of assets and encompasses two distinct modes: reactive renewal and preventative renewal. Preventative renewal is a planned project that replaces an asset based upon a number of factors, such as condition and probability of failure. Reactive renewal is affected after an asset has failed in service. On average, reactive renewal costs approximately 150% of the cost of preventative renewal. Factors such as the consequence of failure, cost of inspection, and difference in cost between renewal modes are used to determine the optimal renewal mode for each category of asset. Although renewals are seen as an inevitable stage in the life cycle of assets, they are undertaken only if supported by condition assessment as well as the economic tradeoff between the future cost of maintenance and the cost of renewal. Unison s Renewal Envelope (RE), the Triple-R Model (Repair, Replace, or Refurbish) and engineering judgment are used in concert to choose the optimal time for renewal of each asset.

270 6-36 SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN Assumptions Made in Renewal Expenditure Modelling The key assumptions underlying Unison s approach to modelling renewals are: At a very high level, long run investment levels should be equal to the rate of depreciation; Network assets become less reliable as they age (as per Weibull Distribution); There is a risk management trade-off between replacing assets preventatively (i.e. pre-failure) and replacing assets reactively (i.e. post-failure) Replacement Costs Replacement cost (RC) values are based on Unison s revised 2006 FRS-3 valuation, adjusted by CPI, or updated based on latest market pricing where sufficient project history is available Renewal Envelope Unison uses the Renewal Envelope (RE) to determine the optimal level of renewal for its asset base. The RE envisages individual assets stepping through time and calculates a benefit:cost ratio of renewal for each year on the planning horizon. Where this ratio exceeds 1 the asset is flagged for renewal (or other remedial action depending on asset class, see section 6.2.4). The key input into calculation of the benefit:cost ratio is the cost differential between replacing assets reactively and replacing assets preventatively. To determine this, each type of asset is assigned a bespoke reactive:preventative cost ratio (R:P ratio). R:P ratios are calculated using a combination of historical project costs and careful assumptions about the points of differentiation between the two modes of renewal. The capital weighted R:P ratio across the total asset base tells us that on average it is 56% more costly to replace assets post failure. Inputs to the RE are: R:P ratio for each asset type; Remaining life expectancy for each asset; Replacement cost for each asset type; Scope of renewal for each asset type (is the whole asset renewed, or can some components be reused?); Discount rate; Expenditure constraints (optional). Outputs from the RE as at December 2010 at both total network and asset class levels are provided in sections below Indirect Renewals There is potential for other categories of network expenditure to contribute to the asset renewal programme indirectly. Unison s renewal modelling formally recognises and quantifies this contribution. Categories that have the potential to contribute are: Augmentation; Customer driven works; OHUG; OPEX renewals (i.e. renewals that cannot be capitalised due to Unison s capitalisation policy).

271 SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN 6-37 For each of these categories a decision rule is in place to allow the indirect renewal contribution to be quantified. The decision rules have been formulated using samples of historical project data and assumptions about Unison s forward looking network expenditure programmes External Review Unison s renewal investment modelling practices have been extensively reviewed by external parties to ensure they represent best practice Alternatives to Renewal Replacement is only one option to restore asset performance. Other options that are evaluated include refurbishment, relocation, retrofitting or de-rating the assets and retaining them in service. In order to arrive at the optimal solution, Unison uses two models. The Triple-R model performs a comparative discounted cashflow analysis at the asset class level for the life cycle of each applicable solution. The key inputs for this model are: The cost of each solution for the asset; Standard life expectancy of the asset; Expected increase in life expectancy of the asset; Annual maintenance cost of the asset. Relocation, retrofitting or de-rating of many asset classes are sometimes economically viable options but have not been included in the modelling to date. These options are however investigated on an ad hoc basis where engineering judgment suggests these modes may present an optimal solution. The Power Transformer Management Model is a multivariate prioritisation tool that specifically recognises the criticality, high replacement cost and long lead-time associated with power transformers. The model is cognisant of opportunities to relocate, retrofit and de-rate these assets. The key features specific to this model are: Optimisation of deployment and non-replacement solutions for the power transformer asset base; Probabilistic time to failure analysis; Integration with overall renewal expenditure plan. 6.5 Life Cycle Asset Management Expenditure Forecasts Unison s life cycle asset management expenditure forecasts are a direct result of the life cycle asset management policy of the company. These forecasts are informed therefore by the life cycle asset management process (see section 2, Figure 2.7), including the inspection and condition assessment regime (bottom up, project specific) and the predictive analysis and strategic analysis tools (top down, strategic and probabilistic perspective). The life cycle asset management policy and resulting strategies have undergone no significant change since 2005; however improved life cycle asset management techniques and modelling have meant several changes to the expenditure forecasts over this time.

272 6-38 SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN Key improvements to the forecasting approach since the last published AMP 2010 are: Improvements to the Renewal Envelope Asset replacement costs updated from Unison s revised 2006 FRS-3 valuation by indexing factor informed by market conditions over this period; Taking into account scope of renewal (optimum mode of asset renewal for a particular asset class may not involve renewal of the entire asset); Alteration of standard lives of selected assets based upon empirical data and industry practice. Improvements to Condition Assessment and Inspection Regime Ground mounted equipment inspection frequency changed from biennial to annual; Increased use of infrared (thermal imaging and basic heat detection) and ultrasound (partial discharge detection) technologies to identify non-visual defects in overhead and ground mounted equipment; RLE for poles now being assessed in the field during feeder inspections as a continuous improvement strategy to enhance the accuracy of the Renewal Envelope (RE) Renewal Expenditure Forecast The initial step in deriving a renewal expenditure forecast at Unison is to run the RE unconstrained (i.e. no bound on CAPEX from year to year). This provides a top down view of the renewal needs of the asset base (Graph 6.8). Features of the curve include the large spike in year one, reflecting a large number of assets operating beyond their expected engineering lives, and an upward trend in required investment over the planning period culminating in a second large spike in years sixteen and seventeen. This second spike is partially attributable to the fact that where age and condition data has been unavailable for assets, standard lives (and therefore RLE) have been set at default values. As asset condition data is collected for these assets over the planning period, it is expected that this spike will be spread. The spike does however illustrate the fact that a step change in renewal investment will be required towards the end of the planning period.

273 SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN 6-39 Regional Renewal Investment Renewal Investment Required ($m) Rotorua Taupo Hastings Napier Year Graph 6-8: Regional renewal investment Overhead Lines Unison s philosophy is to use condition based maintenance and asset renewals based on asset condition surveys completed in accordance with Unison technical standards. The surveys are also used to assess remaining asset life, and are conducted on a five year cycle for distribution circuits and annually for sub-transmission. The results of these RLE assessments are fed back into the RE model Overhead Lines Renewal Investment Renewal Investment Required ($m) Year Graph 6-9: Overhead lines renewal investment

274 6-40 SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN Renewal Investment Required ($m) Underground Cables Renewal Investment Year Graph 6-10: Underground cables renewal investment Renewal Investment Required ($m) Distribution Transformer Renewal Investment Year Graph 6-11: Distribution transformer renewal investment

275 SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN 6-41 Renewal Investment Required ($m) Distribution Switchgear Renewal Investment Year Graph 6-12: Distribution switchgear renewal investment Other Distribution Equipment Renewal Investment Renewal Investment Required ($m) Year Graph 6-13: Other distribution equipment renewal investment 6.6 Summary of Renewals Projects Planned The following section lists the proposed renewal Capex projects for the 2011 financial year. Unison also retains a provision to manage urgent projects that may be identified during the course of the year. Budgetary provisions for planned and reactive renewals have been included in the table below and an assumption has been made to include these in the overhead lines asset category.

276 6-42 SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN 2011/12 Asset Category Description Detailed Description Total Distribution Subs and Regulators Replace Sub 2565 Yarmouth Road Flaxmere Replace existing 34 year old ground mount 100 kva transformer. There are oil leaks at the HV bushings. 40 Distribution Subs and Regulators Distribution Switchgear Distribution Switchgear Replace Sub 4854 Vautier St Napier. Replace Statter F3185 Vautier St Napier Replace Statter Cnr Lighthouse and Seapoint Rd Napier Distribution Switchgear Replace RMS 1679/1680/1681 Guppy Burness Rd Replace existing ground mount 24 year 300kVA transformer. This unit has extensive rust. Unison is progressively removing all Statter type switches from its network due to safety concerns. This switch is 39 years old. Replacement of a Statter type switch which is 40 years old. Replacement of 30 year old Andelect type switch in poor condition Distribution Switchgear Replace Magnfix 1247/875/1248/1246 Southampton St Hastings Unison is progressively removing all Magnefix type switches from its network due to safety and environmental concerns. 62 Distribution Switchgear Replace Magnefix F880/1288/1289 Sunderland Dr Flaxmere Unison is progressively removing all Magnefix type switches from its network due to safety and environmental concerns. 44 Distribution Subs and Regulators Upgrade Sub T Aquarius Drive Replace existing ground mount 200kVA transformer, due to extensive rust 130 Distribution Subs and Regulators Replace Transformer 2152 Montrose Place Replacement of a 27 year old 60 kva ground mount transformer, with extensive rust and vandalism damage. 35 Distribution Subs and Regulators Replace Magnefix 1368/1369/F892 with Safe Link switch Unison is progressively removing all Magnefix type switches from its network due to safety and environmental concerns. 159 Distribution Subs and Regulators Replace 2 pole structure sub 1259 Williams St, Hastings Replacement of a pole mount 200kVA transformer, leaking oil, and supported on a 2 pole structure with both poles nailed. 129 Distribution Switchgear Replace existing Magnefix 1427/1429/1428 Unison is progressively removing all Magnefix type switches from its network due to safety and environmental concerns. 48 Distribution Subs and Regulators Replace Transformer T2831 Lockwood Industrial Site Replace existing 300kVA ground mount transformer with exposed 11kV and LV bushings. Compliance with NZECP 34: Lines Pole Renewals after Deuar Pole Testing Rotorua Area Pole Renewals after Deuar Pole Testing Rotorua Area. 272 Lines 11kV & LV Reconstruction, Thomas 11kV and LV Reconstruction, Thomas 443

277 SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN 6-43 Asset Category Description Detailed Description Total Crescent, Turner Drive, Leslie Avenue and Spencer Street Crescent, Turner Drive, Leslie Avenue and Spencer Street. Distribution Subs and Regulators Replace transformer T3669 at 15 Neri Place Rotorua Replace existing ground mount 200kVA transformer. The unit is badly rusted. 42 Lines Rotoma Feedder Pole Renewals Rotoma Feeder Pole Renewals. 142 Cables Distribution Subs and Regulators Replace 11kV cable on Lake Terrace feeder Replace transformer 1884 Durham Drive Distribution Switchgear Replace Magnefix switch Distribution Switchgear Replace Andelect switch 3306/3303/F3304/3305 Distribution Switchgear Replace Magnefix situate at Transflormer 2122 Replace the existing 11kV cable at Taupo South zone substation. An XLPE cable installed in 1976 with evidence treeing, which failed on the VLF test. This transformer was originally enclosed with a fibre glass housing. The housing had breached safety conditions and was replaced with a metal aluminum cover. Residents were not happy with the larger replacement cover, consequently it was agreed to replace the transformer with a pad mount unit. Unison is progressively removing all Magnefix type switches from its network due to safety and environmental concerns. This Andelect switch is over 30 years old and requires replacement due to oil leaks. Unison is progressively removing all Magnefix type switches from its network due to safety and environmental concerns. Distribution Switchgear Replace Magnefix 1406/1407/1408 Unison is progressively removing all Magnefix type switches from its network due to safety and environmental concerns. Distribution Switchgear Replace Magnefix 2021/2022/2023 Unison is progressively removing all Magnefix type switches from its network due to safety and environmental concerns. Distribution Switchgear Replace Magnefix 2024/2025/2026 Unison is progressively removing all Magnefix type switches from its network due to safety and environmental concerns. Lines Crownthorpe Feeder Pole Renewals Crownthorpe Feeder Pole Renewals. 55 Lines Grove Feeder Pole Renewals Grove Feeder Pole Renewals. 4 Lines Williams Feeder Pole Renewals Williams Feeder Pole Renewals. 28 Lines Cornwall Feeder Pole Renewals Cornwall Feeder Pole Renewals. 4 Lines Southampton Feeder Pole Renewals Southampton Feeder Pole Renewals. 4 Lines 11/12 reactive renewal and renewal bucket projects 11/12 reactive renewal and renewal bucket projects ,800

278 6-44 SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN Asset Category Description Detailed Description Total Reactive Renewals Smart Grid Initiative contingency sum Provision for the unplanned early replacement of deferred renewal projects discussed in section ,000 Lines PaoraHape Feeder Pole Renewals PaoraHape Feeder Pole Renewals. 46 Lines Taupo North Feeder Pole Renewals Taupo North Feeder Pole Renewals. 42 Lines Ngakuru Feeder Pole Renewals Ngakuru Feeder Pole Renewals. 205 Lines Tutukau Feeder Pole Renewals Tutukau Feeder Pole Renewals. 143 Lines Haumoana Feeder Pole Renewals Haumoana Feeder Pole Renewals. 71 Lines Iona Feeder Pole Renewals. Iona Feeder Pole Renewals. 43 Lines Oreka Feeder Pole Renewals Oreka Feeder Pole Renewals. 28 Lines Otamauri Feeder Pole Renewals Otamauri Feeder Pole Renewals. 87 Lines Raureka Feeder Pole Renewals Raureka Feeder Pole Renewals. 34 Lines Riverslea Feeder Pole Renewals Riverslea Feeder Pole Renewals. 26 Lines St Andrews Feeder Pole Renewals St Andrews Feeder Pole Renewals. 34 Lines Park Island Feeder Pole Renewals Park Island Feeder Pole Renewals. 34 Lines Rigemount Feeder Pole Renewals Rigemount Feeder Pole Renewals. 88 Lines Patoka 33kV Feeder Pole Renewals Patoka 33kV Feeder Pole Renewals. 61 Lines Ben Lomond Feeder Pole Renewals Ben Lomond Feeder Pole Renewals. 12 Lines Geddis Feeder Pole Renewals Geddis Feeder Pole Renewals. 42 Power Transformers Lines Windsor Zone Substation - 33/11kV Power Transformer purchase and installation Okere Feeder Automation - Smartgrid renewal Lines Kaharoa Feeder Automation - Smartgrid renewal Lines Pakowhai Feeder Automation - Smartgrid renewal Zone Substation Protection Marewa Zone Substation - Transformer Protection Relay Replacement - Smartgrid renewal Install a new 15/20 MVA transformer and 33kV Circuit Breaker at Windsor Substation to improve security and be used as Network Strategic Spare. Replace selected switches with new automated switches to facilitate rapid load transfer between feeders during contingencies. Replace selected switches with new automated switches to facilitate rapid load transfer between feeders during contingencies. Replace selected switches with new automated switches to facilitate rapid load transfer between feeders during contingencies. Replace the existing electromechanical, electronic and numeric relays with new numeric transformer differential, voltage regulating relays and transformer management relays. 1,

279 SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN 6-45 Asset Category Description Detailed Description Total Zone Substation Protection Zone Substation Protection Lines Distribution Switchgear Lines Lines Faraday Zone Substation - 33kV Feeder Protection Relay Replacement - Smartgrid renewal Arataki Zone Substation - Transformer Protection Relay Replacement - Smartgrid renewal Taupo DA Project - Smartgrid renewal Install smart switches in Napier to transfer Tamatea post contingency load - Smartgrid renewal Haumoana feeder - Install Automated Switches and Current Sensors - Smartgrid renewal Install Entec Switches in Owhata Region to aid Fast Transfer of load - Smartgrid renewal Lines Taupo Self Healing (Phase 1) - Smartgrid renewal Lines Taupo Self Healing (Phase 2) - Smartgrid renewal Replace the existing electromechanical relays with new numeric feeder current differential protection relays. Install 3x 33kV outdoor voltage transformers onto existing 33kV busbar. Replace the existing electronic and numeric relays with new numeric transformer differential, voltage regulating relays and transformer management relays. Replace selected switches with new automated switches to facilitate rapid load transfer between Runanga, Fleet and Taupo south zone substations during contingencies. Replace selected switches with new automated switches to facilitate rapid load transfer between zone substations during contingencies. Replace selected switches with new automated switches to facilitate rapid load transfer between feeders during contingencies. Replace selected switches with new automated switches to facilitate rapid load transfer between zone substations during contingencies. Automate selected switch locations to facilitate rapid fault sectionalising on feeders between Fleet and Taupo south substations. Automate selected switch locations to facilitate rapid fault sectionalising on feeders between Runanga and Fleet substations Power Transformers Rebuild Maraekakaho Substation Replace and upgrade the deteriorated 33kV equipment with a refurbished 7.5 MVA transformer and new 33kV CB and protection and to provide better security and manage the increasing load. 800 Table 6-11: Proposed renewal capex projects 2011/12

280 6-46 SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN Summary Description of Proposed Renewal Projects ( ) Financial Year Project Name 2012/2013 Fenton Park Feeder Extension Replace Arataki 33kV Tie Reconfigure Awatoto subtrans to ring supply Windsor Zone Substation - Install T2 Irongate-Camberley 33kV Tie Arawa Zone Substation - New feeder Mahora-Whakatu 33kV conductor upgrade Maraekakaho-Sherenden 11kV tie upgrade Hastings-Windsor 33kV ring circuit Bluff Hill Zone Substation - Transformer oil containment Windsor Zone Substation - New feeder Upgrade Wairakei A Tannery Rd Zone Substation - Replacement 11kV switch board State Mill Rd Zone Substation (stage 1) - Find suitable land Mahora Zone Substation - New feeder into Pakowhai/Lyndhurst Road SWER Upgrade in Taupo Plains Sherenden Zone Substation - Replace 33kV CB2245 Patoka Zone Substation - Replace 33kV CB1020 Rangitane Rd-Whakatu 33kV ring circuit Havelock North-Arataki-Whakatu 33kV ring circuit Hastings Zone Substation - 11kV Switchboard and Feeder Protection Relay Replacement Tamatea-Marewa Zone Substation - 11kV Load rebalance Tamatea Zone Substation - 33kV Outdoor CB 1055, CB 1057 & CB 1059 Replacement Flaxmere Zone Substation - 33kV Outdoor CB 1071 & CB 1076 Replacement Upgrade Wairakei C Springfield Zone Substation - Uprade 33kV ODS State Mill Rd Zone Substation (stage 3) - Sub trans State Mill Rd Zone Substation (stage 2) - Dist and commissioning Anderson Feeder - Capacity and Contingency Headroom Alexandra Feeder Pole Renewals Valley Feeder Pole Renewals Tangoio Feeder Pole Renewals Puketitiri Feeder Pole Renewals Puketapu Feeder Pole Renewals Iona Feeder Upgrade Broadlands Feeder Pole Renewals Kaiwaka Feeder Pole Renewals Clayton Feeder Pole Renewals Twyford Feeder Pole Renewals Western Heights Feeder Pole Renewals Te Mata Feeder Pole Renewals Te Aute Feeder Pole Renewals

281 SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN 6-47 Financial Year Project Name Rochfort Feeder Pole Renewals Orchard Feeder Pole Renewals Omahu Feeder Pole Renewals Meihana Feeder Pole Renewals Clive Feeder Pole Renewals Pohokura Feeder Pole Renewals Richmond Feeder Pole Renewals Phillips Feeder - Contingency headroom Barnes Feeder - Omahu Road 11kV cable upgrade Chatham - Flaxmere Avenue 11kV feeder upgrade Artiamuri Feeder Pole Renewals Watties A Feeder Upgrade Heuheu Drive Pole Renewals Acacia Bay Feeder Pole Renewals Taupo South Replace 33kV CB Ongaroto Feeder Pole Renewals Okere Feeder Pole Renewals Kaharoa Feeder Pole Renewals Fordlands Feeder Pole Renewals Wharewhaka Feeder Pole Renewals Puketitiri Feeder - Voltage Regulator Otamauri Feeder - Voltage Regulator Fast transfer scheme for Springfield Zone Substation Vaughn Zone Substation - Stage 3 Whakapirau Feeder Pole Renewals Ohaaki Replace CB1152 and Transformer Control Te Toki Zone Substation - Stage 3 Relocation of switch S1227/S1228/6260/S1229/S1230/S1231 at Pukuatua Street Salisbury Road Reconstruction and Upgrade of 3ph Section Puketapu Feeder Conductor Upgrade Stage 3 (5.0km) Flag Range Road to Waihau Road 11kV Tie Kaimanawa Street - O/H to U/G Conversion (Stage 1) Conductor Upgrades Waterhouse Street Taradale Tarewa Road OHUG Increase cable capacity in Irongate, Hastings, Havelock and Arataki loop Awatoto Zone Substation - New 11kV feeder McLeod Road Dunkirk Rd - 11kV Upgrade Tarawera Rd - 11kV Back feed Extend St Mary s Feeder - Puketitiri Road Omahu Road Line Upgrade Otto Road Zone Substation (stage 2) Rainbow Sub Upgrade Replace Transformer Install Inline RCS at S1115 Te Ngae Feeder - Vaughan Road

282 6-48 SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN Financial Year Project Name Arawa Zone Substation - New feeder Install Paralleling RCS at S1117 between Te Ngae and Ngapuna Feeders - Vaughan Road 2013/2014 Establish second line between Taupo South and Fleet Street substations Havelock Zone Substation - install 33kV VT Design Pirimai cable overlay - Stage 1 Windsor Zone Substation - Transformer oil containment Norton Road OHUG Pirimai cable overlay - Stage 2 Conductor Replacement Ohurakura Road Napier Kelvin Road OHUG Tamatea Zone Substation - Upgrade Transformers Replace Statter RMS 3182/F3181/3010 Fernhill GXP - Capacity upgrade Tarukenga Zone Substation - Install T2 Windsor Zone Substation - 33kV relay replacement Establish 11kV ring feed at Bay View water front Waipuna Street OHUG Replace Haumoana cable - Rangitane to first switch Otto Zone Substation - Stage 3 Flaxmere-Camberley-Irongate 33kV reinforcement Clifton Road Haumoana 11kV OHUG Install CB in place of ABS 1931 at Faraday Street 33kV Bus Powdrells Road - Reconfigure 33kV switching station 11kV link between O'Dowd and Trigg Crescent, Taradale Replace RMS S34/S35/F233 Hinemoa Street Replace City 33kV Feeder cable to Hastings sub Tutira Zone Substation - Replace Tx. Tutukau Road to SH1-11kV tie Awatoto Zone Substation - New feeder to Clive (Stage 1) HV cable alterations Tironui Drive Tannery Zone Substation - New feeder for additional growth Install New ABS at Site Of Links L494 Elsthorpe Road Arawa Zone Substation - 33kV Security 2014/2015 New Zone Substation for Rotorua North Awatoto Zone Substation - Transformer Replacement New 33kV line from Arataki to Whakatu Tamatea Zone Substation - Transformer Oil Containment Upgrade Rotorua-Fernleaf 33kV OHL Second bank at Fernleaf Vaughn Sub - Stage 2 Redclyffe - Whakatu 33kV Inter-tie Automation Replace 11kV Conductor - Rotoma Feeder, Beyond Fuses S Manawahe Road

283 SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN 6-49 Financial Year Project Name 2015/2016 Fernleaf Zone Substation Install T2. Irongate New Feeder towards Paki Paki Upgrade Wairakei-Runanga Replace transformer 1979 Replace sub Ohiti Road (Pump) Replace transformer 3171, Fitzroy Avenue at HCC Nurseries Replace transformer 881 at Whakatu Wool Scourers Replace Sub 2800 Swansea Road Replace Sub T Malfroy Road Table 6-12: Summary description of proposed renewal projects ( ) High Level Summary of Proposed Renewal Projects ( ) Outputs of the RE Model highlight a number of asset categories where significant investment will be required during this planning period. These categories include: Underground cables; Overhead lines; Distribution transformers; Distribution switchgear. Projects will be verified once condition assessment and analysis using the Triple R model has been completed. 6.7 Renewal and Refurbishment Projects Overhead Line Renewal Maintenance Projects Unison s philosophy is to use condition based maintenance and asset renewals based on asset condition surveys completed in accordance with Unison technical standards. The surveys are also used to assess remaining asset life, and are conducted on a five year cycle for distribution circuits and annually for sub-transmission. The following projects have been identified for renewal maintenance on the overhead network for the next twelve months:

284 6-50 SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN Area Feeder Operating Voltage Hastings Crownthorpe 11kV Grove Haumoana Iona Oreka Otamauri Raureka Southampton St Andrews Williams 11kV 11kV 11kV 11kV 11kV 11kV 11kV 11kV 11kV Napier Geddis 11kV Park Island Patoka Ridgemount 11kV 11kV 11kV Rotorua and Taupo Ngakuru 11kV Reporoa Tutukau Paora Hapi Taupo North 11kV 33kV 11kV 11kV Table 6-13: Overhead line renewal maintenance projects As Unison has adopted a 5 year cycle to assess the condition of its Overhead Network, renewal projects will be identified on a year to year basis based on the outcome of these inspections. This process will repeat itself every five years Refurbishment of Zone Substation Transformers Although Unison has indicated an intention in the past to refurbish a number of older transformers in the coming years, a review of the economics of this practice has raised questions whether the approach is in fact the most economic proposition, as there is some uncertainty as to how much life extension this practice delivers. On review of the potential upgrades required to support future load growth in a number of substations, it has been assessed that holding a full size system spare asset and running a number of assets to near failure would yield a lower cost strategy. Transformer refurbishment requires the transformer to be transported off site to the Transfield transformer facility in Bunnythorpe where the transformer can be de-tanked, dried out, core tightened, and oil refurbished. All other transformer components are checked and tested and repairs completed before the transformer is repainted, reassembled and tested.

285 SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN 6-51 Minor refurbishment generally includes repainting, replacing gaskets and seals, checking bushings and oil maintenance and this can be completed in-house on site. Transformer insulating oil can be refurbished on site and on line by a specialist company. This service cleans the oil and brings it back to near new standards Refurbishment of Distribution Transformers Only distribution transformers that are removed from service are condition assessed for refurbishment or to be scrapped. Refurbishment generally includes dry out of windings, tank repairs, repainting, replacing gaskets and seals, checking bushings and oil maintenance. Refurbishment of transformers is expensive and only the higher kva-rated transformers are considered for this. Unison is investigating the cost effectiveness and technical issues associated with the re tanking of transformers condemned due to external damage/corrosion.

286 6-52 SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN 6.8 Expenditure Forecasts and Reconciliation

287 SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN 6-53

288 risk management section 7 risk management Unison Contracting Services staff out in the field.

289 SECTION 7 RISK MANAGEMENT Risk Management Introduction Risk Management Policy Policy Objective Statement of Policy Risk Management Framework Risk Responsibility and Governance Risk Tolerance Risk Management Tools Risk Identification Key Risks Asset Risks Risk Assessment Evaluation Process Risk Mitigation Natural Hazard Mitigation Engineering Solutions Equipment Failure Mitigation Maintenance Programmes Risk Readiness Development, Maintenance, Review and Testing of Response Plans Civil Defence Emergency Management Engagement Response to Network Incidents and Emergencies Specific Contingency Plans Health and Safety Health and Safety Policy and Company Commitment Workplace Safety Key Performance Indicators

290 7-2 SECTION 7 RISK MANAGEMENT Figure 7-1: Environmental audit framework Table 7-1: Key Risk Examples Table 7-2: Asset risks Table 7-3: Management of the risks associated with the Smart Grid initiative Graph 7-1: Lost time injury frequency rate (LTIFR) - Dec 2009 YTD

291 SECTION 7 RISK MANAGEMENT Risk Management 7.1 Introduction Risk management is an integral part of Unison s overall business philosophy. The Company s business objectives are achieved by sound and systematic risk management practices. In the training and outlook of its employees and in its daily business operations, all Unison activities are moderated by risk management. Unison s Risk Management Policy incorporates the key elements of the risk management process detailed in AS/NZS ISO 31000:2009 Risk Management Principles and Guidelines. 7.2 Risk Management Policy Policy Objective The objective of Unison s risk management policy is to safeguard Unison s assets and interests, including certain interests of employees and the general public, during the planning and conduct of the Company s business Statement of Policy It is Unison s policy to: Through its business processes systematically identify and assess major risks to its assets, interests, employees and the general public; Reduce or eliminate those risks to the extent this is cost effective having regard to the Company s tolerance for risk as defined in the policy; Minimise and contain the costs and consequences in the event of harmful or damaging incidents arising from those risks; and Provide for the continued provision of services through adequate and timely response, restoration and recovery. 7.3 Risk Management Framework The risk management framework adopted by Unison is linked to the strategic planning process and the annual business planning and budgeting rounds. This has been done to ensure the successful achievement of the Company s key strategic objectives and to deliver the effective implementation of identified risk management activities. Unison has adopted four strategic business dimensions as the cornerstones for all operations and decision-making: Build and grow an efficient, profitable business; Stakeholder management and customer service; Processes, systems and operational performance; Employee commitment, motivation and performance.

292 7-4 SECTION 7 RISK MANAGEMENT Key performance indicators underpin this strategy. Particularly pertinent from a risk management perspective are: Proactive management of key business risks; and Ensuring best practice health and safety Risk Responsibility and Governance The Board, through its Audit and Risk Committee, sets and monitors the high level parameters for risk management across the business. The Operations Support Group facilitates the risk management framework. The Asset Management team within the Networks and Operations Group implements and monitors all asset risk management strategies within the Company. Group General Managers are responsible for managing the risks, both generic and those unique to their area of operation, in accordance with established parameters and guidelines Risk Tolerance The electricity lines business has a relatively low tolerance to risk exposure, as is appropriate for the essential service it provides. Critical features are safety, the responsibility for conveying electricity virtually continuously and the need to maintain the Company s reputation and its trading position in the long term. The level of acceptable risk has been clearly defined within the risk management policy and communicated throughout the Company. Consistent with AS/NZS ISO risks are assessed in terms of the Likelihood of occurrence and the impact or Consequence of the occurrence. Acceptable Risks Acceptable risks are those that do not warrant additional resources by way of further management, mitigation or transfer and have either: A low impact/consequence or a low likelihood or A medium impact/consequence and a medium likelihood. Risk Rating Risks are presented on a chart similar to this: IR = Inherent risk The uncontrolled risk prior to any treatment or controls; or the risk level where the controls/treatments are ineffective. RR = Residual risk The level of risk remaining provided all controls were functioning and effective.

293 SECTION 7 RISK MANAGEMENT 7-5 The colour-coding of risks is as follows: Risk Level Very High Risk High Risk Medium Risk Low Risk Meaning Unacceptable level of risk treat immediately. Immediate management action is required to bring the risk to an acceptable level. Controls are to be subject to regular monitoring by senior management. Control plans required. Additional controls (risk treatment action plans) are to be developed and implemented. Risk only acceptable if the cost of treatment outweighs the benefit delivered. Monitoring plans are required to ensure controls remain effective. Risk is acceptable provided that the risk has been managed to a level as low as reasonably practicable (ALARP). Requires operational monitoring with annual review. Risk is acceptable and no further risk treatment is required. Not subject to review. Controls are recorded for all risks. In addition to the description of controls Unison assesses the level of confidence in the control/risk treatment and the reliance placed upon the control. Criteria used for evaluating the relative importance of controls are as follows: Confidence Assessment Effective Satisfactory Indicators Control is appropriately planned and designed and is operating as intended to address the relevant business risks. The control environment is providing a high level of assurance that business objectives will be achieved. Operating at % effectiveness for the risk. Control is appropriately planned and designed, however there are still additional improvement opportunities in the control environment. The control environment is providing an acceptable level of assurance that business objectives will be achieved. Operating at 50% to 75% effectiveness for the risk. Control is not operating as intended or has not been designed appropriately to address the relevant risks. Improvement Required Ineffective Improvements are required in order to achieve an acceptable level of assurance that business objectives will be achieved. Operating at 25% to 50% effectiveness for the risk. Control is not yet in place or is fundamentally deficient in addressing the relevant risk. Control is not contributing to an assurance that business objectives will be achieved. Operating at < 25% effectiveness for the risk.

294 7-6 SECTION 7 RISK MANAGEMENT Reliance Assessment Critical Important Significant Routine Indicators Operation of this control is critical to management of the risk. Without this control this risk would revert to its inherent risk status. This control plays a key role in the management of the risk. The presence of other controls (significant or routine) means that management of the risk in not totally dependent on this control. This control provides comfort that a particular component of the risk is managed, e.g. the likelihood or the impact has been reduced. Control could be considered important were it not for the presence of other controls. The absence of this control would not change the classification of the risk Risk Management Tools Key Risk Register Unison utilises an on-line tool for monitoring the Company s key risks the risks which have been singled out as significant because they have the greatest potential impact on the ability of Unison to operate the business and to grow stakeholder value. The key risks therefore tend to be those with low Likelihood but very high Consequence. Examples are set out in The reports generated for the Unison Board of Directors Audit and Risk Committee highlight those instances where the current level of risk is greater than the level of risk Unison is comfortable accepting. The reports provide an oversight of the control measures for each key risk; and track progress in continuous improvement. Use of this tool has not only contributed to greater understanding of the context of individual risks but has also facilitated more effective control monitoring programmes, resulting in improved overall risk management and governance. Use of this risk management tool has now been extended to operational areas of the business specifically network development and asset management Legislative Compliance Programme The Unison Legislative Compliance Programme (LCP) provides an overview of the Company s current state of compliance with its key legislative obligations. The LCP provides information for the Board on a 6 monthly reporting cycle in relation to corrective actions taken to address non-compliance issues, together with a summary of any general matters which may have arisen during the reporting period. Unison utilises a web-based LCP which has achieved greater visibility and knowledge of compliance issues within Unison and has also assisted in reducing the risk of non-compliance Safety Management Systems The Electricity Amendment Act 2006 established new requirements for the electricity sector in terms of public safety. Electricity distribution companies must now develop, implement and maintain a Safety Management System (SMS) to ensure their network will not pose a significant risk of serious harm to members of the public or significant damage to property owned by persons other than the company.

295 SECTION 7 RISK MANAGEMENT 7-7 The objective of the SMS is to ensure that the electricity industry takes responsibility for the safety and integrity of its assets designing for safety and managing assets so that the potential for, and consequences of, their failure will be minimised. The four elements of the SMS as set out in NZS 7901:2008 Electricity and Gas Industries Safety Management Systems for Public Safety are: Asset description; Hazard identification, risk assessment, and control of significant hazards; Safety and operating processes; and Performance monitoring. The SMS must be fully implemented and have been externally audited by 31 March The SMS will be discussed in detail in sections 3, 6 and 7of the 2012 Asset Management Plan. In the first stages of the development and implementation of its SMS Unison has ensured that the risk management process adopted in scrutinising asset risk includes public safety and property damage. Refer below. 7.4 Risk Identification In this section we focus on those risks which are specific to asset management. These risks are primarily those which impact on safety and on security of supply by affecting not only the quality of service delivery to the consumer (frequency and duration of outages) but also the reliability of the network itself Key Risks The Company s Key Risk Register includes the following asset-related risks: Risk Title Public Safety Death or Serious Harm Injury Ref Workplace Safety Employees and Contractors Definition Risk of fatality or serious harm to a member of the Public - through unauthorised access to network assets, or as a result of a third party workplace accident or incident involving network assets. Risk of fatality or serious harm injury to a Unison employee or contractor. Ref Network Performance Deterioration of Network Ref. Section 4 Risk of a drop in network performance that is unacceptable to stakeholders and may place Unison in breach of regulatory quality thresholds due to: - A deterioration in network performance, as measured by SAIDI, CAIDI and SAIFI; - Failure to plan or to plan ineffectively; - Failure to develop, review and implement best practice EI standards as Unison Network Standards; - Impaired asset condition (network equipment failure), as a result of

296 7-8 SECTION 7 RISK MANAGEMENT Risk Title Loss of Mission Critical Systems IT or SCADA Definition inappropriate prioritisation of identified risks and the associated allocation of resources at the operational level. Loss or failure of either the IT network or the SCADA system. Ref Catastrophic event with significant damage to network assets Ref Loss of Human Resources due to a natural event Ref Lack of Skilled Contractors to support both existing network and future plans Ref Risk of a natural disaster (such as a major earthquake or volcanic event) may at any time affect a significant portion of the network area, destroying or damaging assets. This considers a widespread/worldwide pandemic, with a closed border situation. Likelihood that Unison would be unable to continue to deliver critical business activities in the event of an influenza (or other virus-based) pandemic due to high levels of absenteeism and/or supply interruptions affecting materials and fuel. An inadequate contracting resource would have the following impacts on Unison: - Inability to spend allocated/planned CAPEX/OPEX; - Increase in faults; - Inadequate response to general faults. NB: Ref = References to specific Mitigation Projects/Initiatives and Response Plans Table 7-1: Key Risk Examples Asset Risks Asset Failure Risk The risk of network equipment failure is assessed regularly by the Asset Management team with a focus on whether the nature of the risk has altered in any way or whether new risks have been introduced. Unison draws on records of incidents, experience and historical data to inform their assessment. Lifecycle forecasts also play an important part in determining the risk of equipment failure and the team draws on both the inspection and condition assessment regime (bottom up, project specific) and the use of predictive analysis and strategic analysis tools (top down, strategic and probabilistic) to guide them. More recently the planned introduction of Smart Networks is expected to significantly alter the profile of asset failure risk. (Refer below.) Currently the asset categories with the highest inherent risk ratings (Low Likelihood and High Consequence) are: GXP Substations The control and ownership of Grid Exit Points (GXP) rests with the National Operator (Transpower) and supply loss to GXPs are under their control. An event leading to an outage of a GXP will have an impact on Unison s zone substations, as discussed below.

297 SECTION 7 RISK MANAGEMENT 7-9 Zone Substations Part of Unison s security criteria (refer Section 5) includes mitigating options for the loss of supply from a zone substation or zone substations (more than one substation can for instance be impacted by a GXP outage). Because different levels of security exist for different areas affected (refer Section 4 for different consumer groupings), substations supplying critical load areas (e.g. hospitals and CBDs) have a higher level of redundancy than substations supplying remote rural areas where outages can be managed. Substations supplying critical load have more than one supply point and good 11kV interconnectivity to ensure sufficient capacity from neighbouring substations. A detailed operational management plan exists for each of Unison s zone substations and supply is governed by consumer grouping targets. An example of a zone substation closure occurred in Rotorua in Indications that a fire had broken out in the Arawa zone caused the station to be closed down. The closure resulted in the loss of power to the Rotorua CBD with in excess of 6000 ICPs affected. Restoration was managed as per Unison s incident management plan (operational response) and supply to affected consumers was restored from adjacent zone substations by closing normally open points to neighbouring 11kV feeders. Overhead 33kV feeders The impact on consumers following an outage of a 33kV overhead line depends on the applicable level of security based on the security criteria. An outage to a 33kV overhead line supplying a CBD area will go unnoticed as redundancy exists and supply will continue through a second line. If the affected line supplies a rural substation, an outage will occur and supply will be restored within the times specified in the consumer grouping targets. Overhead 11kV feeders The level of interconnectivity between 11kV feeders of neighbouring substations will depend on the supply area and consumer grouping. The more critical the load, the more interconnected the 11kV network will be. An outage to an 11kV feeder supplying CBD load will last only a few seconds as breakers will be operated remotely to ensure continuity of supply. An outage to load supplying a remote rural load will not have the same level of automation or 11kV connectivity to neighboring 11kV feeders and supply will be restored based on the consumer grouping targets (refer Section 4). Load Control (Ripple System) Ripple system plant failure The trend for retailers to opt not to install ripple receivers for new connections; or to fail to maintain existing receivers, could result in Unison progressively losing the ability to control system load at times of peak load. This would result in an increase of up to 30% in maximum demand, requiring Unison to increase investment in the network. More substations, 33kV feeders, 11kV feeders, and transformers will have to be installed to enable the network to cope with the increase in demand. Unison is continuously reviewing the age and operability of existing ripple injection plants by maintaining these plants on a regular basis and investigating new technology to ensure their on-going effectiveness. SCADA System SCADA is a key tool for monitoring and operating our distribution network in real time. The alarms notify potential; or actual equipment failure. Without SCADA we would be blind in real time to what is happening on the network, thus jeopardising the safety of those working on the network and impacting on Unison s response capability. To counter this

298 7-10 SECTION 7 RISK MANAGEMENT risk we have established an alternative operations centre (AOC) with SCADA, radio, phone and corporate computer systems to be used when the main control centre is not accessible or non-operational. FC9005 Activation of the AOC describes the operational steps for activation of the AOC Risks Associated with Asset Categories When some assets fail they have a significant impact on Unison s reliability indices affecting the network and, customers. Other assets may pose dangers to people (either workers or the public) if they fail or fail to operate correctly. Table 7-3 below describes the assets, their associated risks and the mitigating actions that Unison puts in place to counteract potential problems. Asset Category Asset Location Level Risk Type Failure Mode/Risk Network Zone Substations Network Security breach by intruder / unauthorised access and contact with live parts. Customer Unison/Contractor Personnel safety Interruption to supply caused by intruder accessing live parts. Risk of contact with live parts; Risk to personnel without required competencies. Consequences Injury or death of the intruder Loss of supply Loss of Supply resulting in loss of productivity, impact on medical dependencies and loss of security. Injury/death. Mitigating actions Network competency and supervision procedures. Network security including: - Controlled locks and keys; - Alarms linked to Control Room; - Surveillance camera; - Protocol for access - Restricted Area Entry; - Station Entry Log to record legitimate visitors. Operational procedures for re-routing supply. All of the above measures; Operating Contingency Plans. Protocols for issuing Network controlled locks and keys; Restricted Area Entry protocols; Unison Competency requirements (incl. supervision); Unison operating procedures; Contract terms and conditions.

299 SECTION 7 RISK MANAGEMENT 7-11 Asset Category Asset Location Level Risk Type Failure Mode/Risk Consequences Mitigating actions Public Safety / Property damage Security Breach by a member of the public (unauthorised access) resulting in contact with live parts. Injury or Death. Security arrangements: - Security Fence;Intruder Alarms;Surveillance camera;protocols for issuing Network controlled locks and keys; - Warning Signs; - Emergency Contact Phone number displayed at station. Public Education programmes. Monitoring adjoining structures and vegetation to eliminate access opportunities. Power Transformers Zone Substation Network INTERNAL FAILURES: Massive loss of oil Environmental contamination. Installation of oil containment system (bunding). Oil leaks Transformer outage. Regular inspections and repairs; Availability of oil spill response kits. Internal fault/s Transformer outage. Annual DGA survey indication of potential problem from gas analysis. Insulation Breakdown Transformer outage. Insulation testing; Depolarisation test; Refurbishment. Overload Overheating Transformer outage. On-Line monitoring by Control Room. Failure from old age Transformer Outage. Transformer Management Plan; Replacement Programme; Availability of Critical Network Spares. EXTERNAL IMPACTS: Corrosive environment General mechanical deterioration. Regular Inspections; Preventive maintenance; Asset renewal. General deterioration Mechanical failure of Tap Changer. Painting; Refurbishment; Regular Maintenance. Work by inexperienced personnel (Lack Damage during maintenance. Training and/or supervision.

300 7-12 SECTION 7 RISK MANAGEMENT Asset Category Asset Location Level Risk Type Failure Mode/Risk Consequences Mitigating actions of Qualified Staff) Customer Transformer outage Network Outage. N-1 Security. Oil Spill Environmental contamination. Installation of oil containment system; Availability of oil spill response kits. Unison/Contractor Personnel safety Live Equipment; Mechanical danger Personal injury or death. Use of appropriate PPE Operating standards; Training and supervision. Oil spill Environmental contamination. Oil spill response kits. Inexperience of maintenance staff Damage to equipment, i.e. tap changers. Staff training/supervision and use of experienced maintenance personnel. Public Safety / Property damage Unauthorised access to substation contact with live parts Access to live parts. As for substations above Physical asset security incl. fences, locks, monitored alarms; Public education programmes; Control of alternative methods of access (adjoining structures and vegetation). Contamination of ground water by oil. Environmental damage; Drinking water affected. Installation of oil containment system; Oil spill response kits. 33kV Porcelain Insulators Zone Substation; Sub-transmission lines Network Type Failure Network Outage. Ultrasonic Survey of installed same-type insulators. Insulation Failure Flying materials Cleaning programme. porcelain. Contamination Outage. Feeder Inspections. Customer Insulation or type failure Outages. As above (Network). Unison/Contractor Personnel safety Insulation failure Being hit by flying materials (porcelain). Appropriate PPE and work procedures. Public Safety/ Property damage Insulation failure Being hit by flying materials (porcelain). Substation and worksite security; Follow-up on type failure; Maintenance programmes. Circuit breakers Zone Substation / Sub-transmission lines Distribution lines Network Fail to operate Slow to operate Network Outages Operation of next upstream device causing larger outage. Regular preventive maintenance.

301 SECTION 7 RISK MANAGEMENT 7-13 Asset Category Asset Location Level Risk Type Failure Mode/Risk Consequences Mitigating actions Insulation Failure Network Outage. Partial Discharge Survey. Protective gear: Batteries and battery chargers Protection Relays and Schemes Old XLPE cables Zone Substation 11 kv Switches Zone Substation Sub-transmission network Distribution network Underground in Hawke s Bay Customer Equipment failure Network Outages. Back feed; Unison/Contractor Personnel Safety Public Safety / property damage Work by inexperienced personnel Contact with live equipment Damage during maintenance. Injury or death. Network Battery Failure Loss of SCADA control. Parallel supplies; Provision of generators. Training / supervision; Deployment of experienced staff for maintenance work. Testing, inspection and maintenance programmes. Regular Inspections. Loss of protection. Battery Testing; Battery Monitoring. Customer Above failure Network outages. As above. Unison/Contractor Personnel safety Contact with battery acid Injury/burns. Use of task-specific PPE. Public safety Property damage Network Loss of protection risk of contact with live parts Mechanical relays fail or slow to operate Injury /death. Operation of upstream device causing larger outage than necessary. Regular inspections; Battery testing regime. Fault Analysis; Regular Testing; Protection Relay Upgrade to Microprocessor Relays.. Customer Above failure Network outages As above (Network). Unison/Contractor Personnel safety Public safety/ Property damage Network - - No exposure as able to download fault info on-line. Loss of protection risk of contact with live parts HV cable failure from ingression of water into cable sheath Injury /death. Network outages. Customer Above failure Network outages. As above. Regular inspections; Monitoring and testing of protection schemes. Progressive replacement of cable type. Unison/Contractor Personnel safety HV for Testing On-site Injury. Use of task-specific PPE; Following Test Procedures. Public Safety / Property damage Public access to worksite Injury. Control of site. Fencing off of hazards. Hawke s Bay: 33kV nitrogen gas cable between Faraday and Bluff Hill zone UG cable in road reserve and private property Network Damage by third party excavation Bluff Hill Outage. No Spares Regular on-site gas monitoring. Cable markers installed NCC awareness.

302 7-14 SECTION 7 RISK MANAGEMENT Asset Category Asset Location Level Risk Type Failure Mode/Risk Consequences Mitigating actions substations available. Technical Assistance Contract with contractor. Customer Loss of supply Port of Napier Outage; Large Industrial sites affected. Regular Testing. Parallel or back feed from Faraday; Generator use. Unison/Contractor Personnel safety Gas under pressure Injury from high pressure gas. Reduce pressure prior to work. Rotorua: Arawa 33kV cable UG Cable in Road Reserve Public Safety/ Property damage Network HV Electrical injury. De-energised when being repaired; Exposure to gas and/or live cable particularly on private property Damage by third party excavation Injury or death. Network Outage. Customer Loss of supply Outage Rotorua CBD - Business interruption. Unison/Contractor Personnel safety Public Safety / Property damage Hazards from road opening Serious harm injury. Procedure for identification of cable. Public awareness; NCC awareness and warnings to residents; Warning signage; Annual testing. Regular Testing. RDC awareness for road openings; Regular Unison/RDC meetings Parallel feeds. Feeds from Biak Street. De-energised when repairing third party damage. H2S Gas Gas Hazard. Use of gas detection equipment and procedures. Access to Injury. Secure, enclosed worksites; worksite Fenced off hazards. Rotorua: Rotary ripple control plants Statter switches Zone Substation Network Old Age Inability to control loads for energy retailers. Distribution Equipment Customer Loss of control No hot water, No lighting. Unison/Contractor Personnel safety Public Safety/ Property damage Network Injury from rotating plant HV Capacitor Discharge Injury Auto Fuse Switch slow to operate Operation of upstream device; Regular Inspections. Replacement strategy. Possible change in frequency. Manual operation. Use of appropriate PPE Observing Operating Procedures. Progressive replacement of switches;

303 SECTION 7 RISK MANAGEMENT 7-15 Asset Category Magnefix switches Mark I Andelect switches Table 7-2: Asset risks Asset Location Level Distribution Equipment Distribution Equipment Risk Type Failure Mode/Risk Pitch-filled Cable Boxes and Bus Chambers Consequences Larger outage than necessary; Failure of pitch insulation. Mitigating actions Inspection and maintenance; Partial discharge Customer As above Outage. Parallel supplies. Unison/Contractor Personnel safety Public Safety / Property damage Network Customer Unison/Contractor Personnel safety Public safety/ Property damage Network Operating Switch failure Death or injury. Operational restriction on switching; Utilising full PPE. Public in vicinity Death or injury. Operational restriction; Power surge Cable Termination Insulation Failure Corrosion of contacts Single Phase operation Damage to consumer s plant, equipment, or appliances. Termination failure. Plugs corroded in position. Requires large outage to repair. Secure/enclosed worksite. Public education in regard to RCD protection. A two programme has been put in place to replace these switches by 2014 As above. Operating Hazard Death or injury. Utilising specialist PPE and observing correct operating procedures. Public in vicinity of the work site. Poor design; plus history of welding failures Oil Leaks Cable Termination Failure Death or injury. Switch failure and outage; Environmental damage; Outage. Customer As above Network Outage. As above. Unison/Contractor Personnel safety Public safety/ Property damage Secure, enclosed worksite. Progressive Replacement of the remaining 242 switches on the network. Oil spill clean-up procedures and kit; Partial Discharge Survey or Ultrasonic Survey. Operating Hazard Death or injury. Utilising specialist PPE and following correct operating procedures. Public in vicinity when there is a cable termination failure Death or injury. Secure the worksite from public.

304 7-16 SECTION 7 RISK MANAGEMENT Natural Hazard Risks Earthquake risk continues to be regarded as the maximum credible natural hazard threat to Unison s network. This is in line with the findings of hazard studies undertaken by the regional Civil Defence and Emergency Management Groups within the network area. In an event of catastrophic proportions Unison s business continuity arrangements would be triggered and the Company s response would be managed under the Unison Crisis Management Plan. Storms and flooding are the natural hazard events that most frequently impact the network area and for which the Company maintains an Emergency Response Plan (refer 7.8 Response to Network Incidents and Emergencies). Other potentially significant risk events that have been considered are volcanic activity, tsunami, lightning, forest fire, wind and snow storms, landslide and fire. Hawke s Bay Hawke s Bay is one of the most seismically active regions in New Zealand. Its location above the subduction boundary between the Pacific and Australian plates means that it is within a zone of high deformation resulting in many earthquakes. Consequently the following effects add to the vulnerability of the electricity network: Ground shaking; Grounds ruptures and heave; Liquefaction; Slope instability. As the Hawke s Bay region is reasonably distant from any active volcano it is not at risk from the highly damaging nearsource effects of a volcanic eruption, however it is likely to be affected by volcanic ash fall and associated hazards should an eruption occur in the Tongariro National Park. Any significant eruption would affect the Hawke s Bay region if the wind were blowing from the volcano towards Hawke s Bay (as occurred to a limited extent in the events). The impact of natural hazard events are regularly tested in regional civil defence exercises in which the Company participates (BayShake, BayWash, AshBay and most recently, BayVac). Unison itself also conducts annual exercises in emergency and crisis response for Network-wide scenarios with the objective of: Evaluating the impact of such an event on network assets; Identifying asset exposure and improvements; Testing the Company s crisis response planning. Taupo/Rotorua This area of network is located in two active volcanic fields the Taupo and Okataina volcanic zones. It is important to note that volcanic eruption from either of these areas is classified as a hazard of national significance. Network planning for the impacts of a volcanic event on the network area requires additional future study and is expected to be initiated as

305 SECTION 7 RISK MANAGEMENT 7-17 part of a work programme introduced by the Waikato and Bay of Plenty Engineering Lifelines Groups (of which Unison is an active member) addressing lifeline vulnerabilities in these areas. Because earthquake remains a high or moderate risk in this part of the network, mitigation work has focused on the seismic risk. Go to for natural hazard mitigation activities Smart Network Risks The main risks that have been identified in delivering the smart grid initiative are: Network risk caused by CAPEX deferrals; Regulatory risk (meeting SAIDI and SAIFI targets under the quality path); Sustainability of the contracting market; Availability of the required employee skill sets; Financial risk. The ways in which these risks are being/will be managed are itemised in Table 7.4, below. Risk Network risk caused by CAPEX deferrals Regulatory risk (SAIDI and SAIFI) Sustainability of the contracting market Risk Management Detailed network analysis has been undertaken to ensure that the risk created by project deferral will not result in the network becoming overloaded or old age equipment failures beginning to increase exponentially. Most notably: o Output from the Renewal Envelope (RE) predicts the remaining life expectancy (RLE) of the network to reduce by 0.75 years per annum during the period in which renewal expenditure is constrained. This is an acceptable risk as the RLE of the network will remain at over 26 years after the five year period has elapsed meeting international benchmarks. o Early results from the Deuar MPT40 mechanical pole testing device have indicated that previously used methods of testing pole integrity have had a tendency to over-condemn (significantly in some cases). This lessens the impact of a reduction in renewal expenditure. o Load growth on the network has slowed over the past twelve months. This has meant that network capacity headroom has been taken up at a slower rate than expected meaning system growth projects can be deferred with a lower risk profile. o The implementation of the smart grid initiative itself will mitigate network risk to some degree. Once commissioned, assets will have immediate effect data will begin to be collected and the level of automation across the network will increase. It is well understood in reliability engineering that asset performance is correlated with asset age. The deferral of renewal projects will result in a reduction of asset RLE. The associated regulatory risk can be managed for the following reasons: o The network has demonstrated increased resilience to significant meteorological events through increased automation and improved design standards since o The smart grid initiative will deliver reliability benefits as equipment is deployed. The deployment will target areas where the largest gains can be made as a priority. The strategy that has been selected will ensure the sustainability of the contracting market by meeting (and in some cases exceeding) minimum expenditure requirements of the market. The phasing proposal will mean that a consistent level of contracting revenue will be available annually over the planning period mitigating the risk of resource-shocks where required contractor resources vary

306 7-18 SECTION 7 RISK MANAGEMENT Risk Availability of required skill-sets Risk Management significantly year on year. The contracting market has been informed of the smart grid initiative and is working with Unison to ensure that the correct skill sets are available to deliver the works required. Expert assistance for the installation of particular technologies has been arranged and will perform an educational role (Hendrix system, ground fault neutraliser). Provision of a forward work plan on smart grid projects will allow the market time to react to the deployment of equipment. Financial Risk The way in which the smart grid initiative will be funded makes it inherently a low financial risk. The quantum of the overall CAPEX programme will not be affected, meaning that the business fiscal constraint can be met. In many cases the initiative will dovetail with the renewals and system growth programmes resulting in synergies. The smart grid initiative is strongly NPV positive over the life cycle of the asset. Table 7-3: Management of the risks associated with the Smart Grid initiative Environmental Risk As a network utility operator Unison is afforded special status under the Resource Management Act 1991 and associated district plans. Although this has significant benefit for Unison s operations, ongoing compliance with the conditions of site designations and resource consents is a significant risk for the business. A rigorous environmental auditing regime has been established to identify and develop strategies to mitigate this risk. Many of Unison s assets contain hazardous substances in varying quantities. Mitigation of both the likelihood of asset rupture and consequence are a focus area for the business. Particular attention is being paid to sensitive areas such as the Heretaunga Plains Aquifer and thermally active areas in the Central Region. Fire in the event of faulting assets is also a risk, predominantly in rural and forestry areas where fire may not immediately be noticed, potentially resulting in damage to land and assets. Unison has recently made improvements to inspection techniques of overhead assets (partial discharge testing and infrared imaging) to mitigate the risk of failure in service and subsequent fire. Unison Environmental Policy In the Environmental Policy Unison has committed to conduct all operations in an environmentally sound manner, satisfying all applicable legal and regulatory requirements, as well as industry codes of practice and company standards. Specifically the policy addresses establishing and maintaining responsible standards, objectives and targets for managing the environmental impacts of Unison s products, services and processes; supporting where feasible the production of electricity that minimises the harmful effects on the environment; waste reduction and disposal; sourcing of materials; improvements to processes; and community liaison on issues of environmental impact. An annual Environmental Management Report must be provided to the Audit and Risk Committee confirming the steps taken to implement the policy.

307 SECTION 7 RISK MANAGEMENT 7-19 Environmental Management at Unison As a responsible member of the New Zealand business community, Unison aims to achieve and maintain a high standard of environmental care. The Legislative Compliance Programme (LCP) regularly assesses Unison s compliance with the Resource Management Act 1991 and other relevant legislation. (Refer Section ). This has shown that Unison is consistently compliant in this area. Environmental Management Plan The Environmental Management Plan provides the top-down structure for environmental management at Unison. Key elements of the plan are the environmental policy, the biennial auditing regime and international environmental standards. The environmental audit framework is depictederror! Reference source not found. below: Figure 7-1: Environmental audit framework Environmental Audit The table below summarises progress through Unison s environmental auditing programme to date: Year Scope Outcome 2006 Comprehensive Environmental Audit All premises audited were deemed to be of a high standard and a general awareness of environmental issues was noted. Several minor issues were discovered relating to resource consents Business Planning Audit Key focus areas of the audit included management of hazardous substances, compliance with ongoing conditions of site designations and ensuring Unison has acquired all the resource consents required for its operations. The outcome of the audit was favourable with only several minor non-compliances noted.

308 7-20 SECTION 7 RISK MANAGEMENT Year Scope Outcome 2010 Follow-up Environmental Audit A re-visit to all sites deemed non-compliant in the 2008 audit confirmed Unison had corrected the minor issues previously noted. A high standard of environmental management was noted with very few minor issues noted Environmental Audit Site audits were completed at a selection of sites chosen by MWH and Unison staff. A report on findings has been produced for Unison s reference and is summarised below: Site Number Audited Percent Compliant Notes Few minor issues were noted at various depots: Storage of old transformers in drip trays; Depot / Stores Facility 3 100% Lack of spill plan on site. Zone Substations 7 100% Switching Stations 2 100% Pole Mounted Distribution Transformers Ground Mounted Distribution Transformers High Risk Sites noted in 2006 audit % % 5 100% Possible Consent issue with Hawke s Bay truck wash facility. All zone substation transformers appeared to be leaking oil in extremely minor amounts. These amounts were deemed insignificant with no improvement needed. Minor oil leaks were noticed on various switches. These were deemed insignificant with no improvement needed. All pole-mounted distribution transformers inspected were deemed compliant. One transformer was identified to be sweating oil. All ground mounted distribution transformers inspected were deemed compliant. Graffiti was noted on several ground mounted transformers. All high risk sites noted in the 2006 audit were re-visited and deemed to be compliant. 7.5 Risk Assessment Evaluation Process The Investment Prioritisation Tool (IPT) is the primary mechanism for assessing and prioritising risks pertaining to network assets (refer Section 5). The tool is a multi criteria decision tool and prioritises projects across categories (system growth, asset replacement and renewal, reliability, safety and environment). The tool makes use of key drivers prioritised by Unison to ensure a managed risk profile for prioritising capital projects. 7.6 Risk Mitigation Unison proactively works to reduce exposure to identified risks. This has been made clear in the preceding sections where mitigation actions are recorded alongside the identified risks.

309 SECTION 7 RISK MANAGEMENT Natural Hazard Mitigation Substations - Mitigation Seismic strengthening Strategic location Network security Fire detection systems Strengthening all electrical equipment to protect assets from the impact of an earthquake. Selecting substation sites away from areas at risk from landslides and/or serious flooding. Shutdown individual substations and backfeed supply, in the event of an emergency (e.g. fire, malicious damage, flooding, tsunami etc.). Provision of fire detection and fire prevention systems in substations. Network Design, Materials and Construction Load-shifting capacity Improved design Improvement in load-shifting capability in the Taupo/Rotorua area where the feeders are largely radial, making load shifting problematic. Unison Standards require adequate clearances to cope with wind, snow, volcanic ash etc. Bunding Installation of oil bunding at all new sites where significant quantities of oil are held. Refer Section Environmental Risk Engineering Solutions Mitigation through Engineering Projects and Programmes Unison Engineering Standards Project to provide a high-level overview of key engineering standards in order to assess their coverage and adequacy and to identify new requirements and improvements. Condition Programme Assessment As part of the Company s continuous improvement programme, assets are inspected at defined intervals for condition including Heath, Safety and Environmental risk. These are effective tools, supplying information on aspects of current practice that could be improved. New technology Smart grid technology (refer ). Network Design Obsolescence Reviewed to ensure that current engineering practice and network configuration is delivering satisfactory performance, providing sufficient operational flexibility, and allowing sufficient alternate configurations in the event of asset failure, thereby mitigating high risks from reliance on key assets. Assets for which spare parts are no longer available represent an operational risk. Increased outage times may result from failures due to longer manufacturing times for unique parts or the time to carry out a total change out to modern equivalents. This is mitigated as far as is reasonably practicable by the Company s holdings of critical spares Equipment Failure Mitigation Maintenance Programmes Reactive Maintenance Unison Networks has assigned the responsibility for the restoration of service and supply throughout its regions to Unison s Contracting Services Group, with backup from external contractors as necessary. The first response capability is supported by a comprehensive second response capability. Where faults, defects and/or losses suggest asset

310 7-22 SECTION 7 RISK MANAGEMENT replacement or augmentation is required then a risk assessment is instigated (involving Network Development engineers) to determine the appropriate permanent solution Preventative Maintenance The inspection regime, part of the network preventative maintenance programme, ensures that all assets are inspected on a regular basis for statutory compliance and public safety, with repairs completed as necessary. The inspections include: Ground-mounted Asset Inspection Programme this has a particular focus on security and public safety; Network condition assessments of feeders conducted from the ground and air, using specialised camera equipment and techniques to highlight potential defects on the overhead distribution network in rural areas and over land; Poles - non-destructive testing, visual inspections and compliance with minimum clearances; Earthing installations assessing compliance to earthing standards and carrying out remedial action as required; Substations Cyclic inspections and maintenance activities at all zone substations. Specific Renewal Projects to mitigate risk of failure include: A programme to ground-mount higher risk urban transformers that are presently situated above ground on two-pole structures; Replacement of the Magnefix ring main switches over the next two years and progressive replacement of Statter ring main switches in the Hawke s Bay by 2015; Progressive replacement of glass type fuses in the Rotorua network Specific Development Projects The following development projects were initiated in 2009 specifically to mitigate identified equipment failure risks: Establish Biak Street zone substation in Rotorua - Completed and commissioned; Establish Fleet Street zone substation in Taupo - Completed and commissioned; Upgrading of Maraekakaho zone substation in Hastings Scope has been reviewed with planned implementation in Skilled Contractor Dependency Unison recognises the need for skilled contractors to operate its network both from a planned maintenance and fault management perspective. Having identified this as a key business risk Unison has put in place controls to mitigate the Company s exposure. These range from the Human Resource Strategy, its Asset Management planning, the Contracting Strategy, through to the Company s Health and Safety Management Systems.

311 SECTION 7 RISK MANAGEMENT Risk Readiness Risk readiness encompasses all aspects of preparedness for network incidents, emergencies and/or disasters. This entails the development, maintenance, testing and reviewing of response plans as well as engagement with the Civil Defence Emergency Management sector through networking, joint planning and Lifelines Group participation Development, Maintenance, Review and Testing of Response Plans Unison response plans have been developed under the umbrella of the Company s Business Continuity Management Plan (refer Section 7.8). Each is a controlled document and is governed by the requirements applying to all Emergency Plans. They must be: Authorised by a General Manager; Approved by the Chief Executive; Tested annually; Subject to review following every exercise and/or actual activation of the plan. Each plan also requires that a debriefing be conducted after each activation of the plan (whether an exercise or actual event) and that a report of the issues raised be submitted as a report to the Executive Management Team with recommendations for improvements and an action plan for their implementation Civil Defence Emergency Management Engagement Because of their importance to the nation, lifeline utilities (which include by definition the electricity sector) have clear responsibilities and roles stipulated in the Civil Defence Emergency Management Act Unison recognises its statutory obligation to: Plan for and be able to ensure continuity of supply, particularly in support of critical Civil Defence Emergency Management (CDEM) activities; Be capable of managing its own response to emergencies; Develop plans cooperatively to coordinate across the electricity industry and with other sectors; Establish relationships with CDEM Groups, consistent across regions. Unison is not only an active participant in Civil Defence Emergency Management (CDEM) arrangements within the network area but is also a financial member of each of the Engineering Lifelines Groups within the network area. These groups recognise the high degree of interdependence between the service providers of electricity, water, telecommunications, drainage, road transport routes, air and sea transport etc and work together on plans to support one another in emergency events. At the Hawke s Bay CDEM Group level, the Unison Operations Manager holds the Regional Electricity Adviser role and in a state of local emergency would act as a conduit between the regional electricity industry participants and the Group Controller with information on the status of supply across all of the networks.

312 7-24 SECTION 7 RISK MANAGEMENT In the Waikato and Bay of Plenty CDEM Group areas Unison is an active participant in all lifeline projects, and utilises the relevant Communications Plan in events that require communication of asset status or centralised coordination of information and response actions. 7.8 Response to Network Incidents and Emergencies Unison operates a tiered emergency response system: Level 3 - Incident Response Type: Operational An incident is treated as an occurrence that is an expected but unforeseeable/unplanned event and falls within the Company s normal system tolerance levels. Contingency plans or pre-planned response procedures are in place. Responsibilities: o Concentrate on completion of tasks assigned/set down in procedures to deal with the incident and return to business as usual. Examples: o Third party damage to a network asset; Triggers: o Awareness that a (developing) situation requires a targeted response, or o Activation of a pre-planned procedure (e.g. an outage or accident response). o After-hours faults; and o Minor storm damage etc. Level 2 - Emergency Response Type: Tactical An emergency is an unplanned event that requires an immediate and significant response by the Company. It presents or has the potential to present, a major disruption to the normal operation of the business and is too problematic to be handled in a timely manner using business-asusual resources and capabilities. Responsibilities: o Provide early and effective emergency damage limitation response; o Activate Unison s FC9003 Emergency Response Plan and FC9002 Crisis Communication Plan if required; o Determine priorities in allocating resources; o Coordinate and manage on-going Level 3 incident response; and Triggers: o Existing resources are stretched and the situation is deteriorating; or o The Company s reputation may be at stake. o Obtain resources as required. Level 1 - Crisis Response Type: Strategic An adverse event or series of events, that due to its magnitude, impact and associated risks requires executive involvement or specific management coordination. The Executive adopt all command, control and coordination functions, delegating tasks they deem appropriate to the crisis event. Responsibilities: o Activate FC9001 Crisis Management Plan; Trigger: o CEO s decision that strategic direction is required. The event may be a major natural or man-made disaster or some other event involving Unison that results in the loss of life, serious injury or severe distress to staff, o Identify, confront and resolve the crisis; o Determine how the Level 2 Emergency Response is to proceed; o Determine priorities; consumers or members of the public, and/or disruption to o Provide direction and make executive decisions; services, significant damage to equipment, or a potential loss of o Provide resources; o Prioritise demands;

313 SECTION 7 RISK MANAGEMENT 7-25 confidence in Unison s ability to safely supply energy. o Provide forward planning for returning to business as usual after the crisis has been resolved; and o Identify and maximise opportunities or advantages arising from the crisis Specific Contingency Plans Crisis Management Plan Should a major natural disaster affect a significant portion of Unison s network area, it is anticipated that it would destroy and/or damage a considerable portion of the network in the process. Unison has to have positioned itself to maintain supply to unaffected network areas while at the same time initiating not only an assessment of the damage to the affected area and but also response and restoration plans. Accordingly the company has Business Continuity arrangements in place and would coordinate all actions under its Crisis Management Plan (Level 1 Response) Emergency Restoration Plans The loss of a zone substation or a GXP is regarded as an event of significance, for which restoration of supply is preplanned. Each zone substation has its own emergency restoration plan. Each has a switching procedure stored on the system and available for access by the Operator in the event of the total loss of a substation. Unison has similar plans for the loss of GXPs Activation of the Alternate Network Operational Control Centre The control functions at risk through the loss of the Operational Control Centre are: Monitoring of supply the process of electronically monitoring the performance and status of equipment in the network; and Continuity of supply the ability to manage assets as part of the network, in order to maintain supply and to deenergise and re-energise equipment before and after physical work is done to the assets. Having identified the potential loss of control systems fundamental to Unison s core business of maintaining continuity of electricity supply, the Company has established an Alternate Operational Control Centre from which network operations would continue in the event the principal site became inaccessible or was damaged. While the alternate site is still located in Hastings it is approximately 4kms from the Omahu Road site and has been assessed by engineers for structural integrity vis à vis significant hazards and risks. Automatic fail-over systems are in place to ensure continuity of operations IT Disaster Recovery Plan An IT Disaster Recovery facility is co-located with the Company s Alternate Operational Control Centre.

314 7-26 SECTION 7 RISK MANAGEMENT A recent Unison Business Continuity exercise successfully tested (as far as was possible without impacting on Supply and Service Agreements) the ability of the Company to switch to the back-up site and maintain overall control and management of the network. With the sign-off of the departmental business continuity arrangements, the next phase will be to review the current capability and capacity of the IT-DR site to deliver against the newly revised minimum acceptable downtimes for critical business systems Unison Pandemic Influenza Contingency Plan The purpose of this plan is to manage the impact of an influenza pandemic on both employees and on the business, by addressing: Containment of the disease (reducing the risk of its being spread from employee to employee) including health measures and social distancing, and; Continued delivery of critical business activities (taking into account the increase in absenteeism caused by the pandemic). This has covered identification of key staff, provision of remote access to IT systems, and re-evaluation of stock levels and fuel supplies for such an event. 7.9 Health and Safety Best practice health and safety is one of Unison s strategic objectives and reflects the seriousness and significance assigned by the Company to workplace safety and public safety Health and Safety Policy and Company Commitment In line with its commitment to best practice health and safety, Unison provides the following undertakings in HS0001 Health and Safety Policy: To provide and maintain a safe work environment for its employees, contractors, the public and visitors to any Unison workplace; To address public safety through all aspects of asset design, construction and maintenance; To achieve continuous improvement in health and safety management through consultation with employees, contractors and management; To identify specific health and safety responsibilities for each employee in their job descriptions and to measure their performance against these reviewed annually; To ensure that all employees comply with relevant health and safety legislation, regulations, codes of practice, guidelines and safe operating procedures; To support the right of employees and their representatives to be involved in managing workplace hazards and to participate in regular reviews of health and safety management policies and performance; To provide targeted health and safety training to employees and their representatives; To ensure immediate and accurate reporting of all workplace injuries and incidents and to investigate all incidents to

315 SECTION 7 RISK MANAGEMENT 7-27 ensure that any contributing factors are identified and corrective actions are assigned and implemented; To support the safe and early return to work of their injured employees.

316 7-28 SECTION 7 RISK MANAGEMENT Workplace Safety Key Performance Indicators Graph 7-1: Lost time injury frequency rate (LTIFR) - Dec 2009 YTD Lost Time Injuries Unison s commitment to safety in the workplace has been reflected in improved performance relative to the industry and as measured against the company s previous year s performance WSMP Accreditation Unison is accredited at the Tertiary Level of the ACC Workplace Safety Management Practices (WSMP) programme. Amongst many aspects of safety subject to audit by the ACC, Unison has demonstrated that it has systems in place to systematically identify, assess and manage hazards in the workplace and to ensure the safety of not only employees but also contractors, sub-contractors and the public. The tertiary accreditation achieved in 2009 is for the combined operations of Unison Networks Limited and Unison Contracting Services Limited and will be subject to audit again in Contractor Engagement Our responsibilities under the Health and Safety in Employment Act 1992 as the Principal to the contractors we engage to work on our network are fully recognised and actively met through on-going scrutiny of health and safety documentation and audit of contractor worksites. The Unison Safety On-Site booklet which was designed with safety in mind for all employees and contractors working in the field is issued as part of the Unison induction programme. The booklet addresses issues such as worksite safety plans, use of appropriate personal protective equipment (PPE), electrical safety and customer service.

317 SECTION 7 RISK MANAGEMENT 7-29 The programme of Contractor Induction and refreshers conducted by Company s Works Performance Group reinforces Unison s safety focus. This Unison Group is also responsible for renewal of contracts and places a strong emphasis on safety requirements and on performance standards. The Company also continues to chair three monthly safety meetings attended by Unison and representatives of each of the contractors engaged to work on the Unison distribution network. These meetings have proven to be a valuable mechanism for sharing safety information, including safety alerts following incidents and investigations, training techniques and providers, and the introduction of improved safety techniques, equipment and PPE for use on our network Training, Induction and Network Access Particular mitigation activities to ensure a safe working environment include: Restriction of access to the network to personnel with Work Task Competency Certificates. Field personnel are deemed competent by their respective employers in accordance with the Electricity Act and associated Regulations pertinent to their particular trade or discipline. Targeted training of all personnel whose work requires reference to Unison s operation, design and construction standards. These standards comply with industry safety requirements and relevant regulations. Induction programmes for all new personnel including contractors and sub-contractors. The programmes focus on the needs of the worker/contractor and the safety requirements associated with his or her role. Contractor worksite auditing. Auditing contractor competency and safe workplace practices is undertaken continually and consistently with the outcomes reported and documented for reference during the contract performance review process. Training programmes. These are facilitated by Unison for field staff including contractors. A focus on public safety and property protection ensuring that the public does not access live electrical equipment and the Company s equipment does not cause damage to private property Design and Public Safety In 2007 Unison introduced a new Standard to guide every service provider engaged for the purposes of providing design and construction services to Unison. The Standard NK3030 Design Requirements for Public Safety defines the public safety requirements that must be considered and implemented in all Unison network engineering designs and construction. It also requires that Unison s FC0003 Risk Management Policy be read in conjunction with this Standard. The Standard addresses the selection of sites for electrical plant, restricting public access to parts/equipment with potentially fatal voltages, plus issues of electrical protection and auto-reclosing Security, Barriers and Signage Unison also has in place stringent procedures governing the security of assets and the restriction of physical access to Unison s electrical network and associated Schools Programme In the public arena Unison continues to out-perform its annual objective of presenting its Be Safe with Electricity programme to school children in the Hastings, Napier, Rotorua and Taupo areas. The objective has been endorsed by

318 7-30 SECTION 7 RISK MANAGEMENT management and the Board and remains current. The importance of child safety is reflected in this programme now targeting 2500 children up from 2000 in the previous year Non-Electrical Workers Safety A strategy has been developed by Unison to reduce the number of live-line contact incidents by third party contractors, agricultural workers and others. The resulting award-winning training programme is targeted at companies with employees working in the vicinity of power lines and poles or in close proximity to underground cables. The focus of the Be Aware - Electricity Kills programme is to heighten awareness of the apparently benign presence of electricity throughout a range of work environments and the deadly consequences of making contact with our live assets.

319 section 8 evaluation of performance evaluation of performance Electrical Fitter Gordon Trotter operates a REG-DA relay. These relays form an integral part of Unison s power transformer management systems (TMS).

320 SECTION 8 EVALUATION OF PERFORMANCE Evaluation of Performance Purpose Progress against 2010/11 Capital Expenditure Plan Financial Progress Physical Progress Progress against 2010/11 Maintenance Expenditure Plan Financial Progress Physical Progress Progress against Maintenance Initiatives Performance against Service Levels for 2009/ Explanations for Service Level Targets not Met Time Series Data Progress through Asset Management Initiatives Gap Analysis and Improvement Initiatives Review of Quality of Asset Management Planning and the AMP Figure 8-1 SAIDI Performance time series Figure 8-2 SAIFI performance time series Figure 8-3 Total Costs per ICP time series Figure 8-4 Total Costs per km time series Figure 8-5 Capacity utilisation time series Figure 8-6 Loss ratio time series Figure 8-7 Faults per 100km performance time series Table 8-1 Progress against 2010/11 CAPEX budget Table 8-2 Variances to 2010/11 CAPEX budget as projected February Table 8-3 Status of renewal projects planned for 2010/ Table 8-4 Status of network development projects planned for 2010/ Table Progress against 2010/11 maintenance budget as projected February Table 8-6 Variances to 2010/11 OPEX budget as projected February Table 8-7 Physical Progress through maintenance programmes...8-9

321 8-2 SECTION 8 EVALUATION OF PERFORMANCE Table 8-8 Progress against maintenance initiatives Table 8-9 Performance against service levels 2010/ Table 8-10 Asset management initiatives 2011/

322 SECTION 8 EVALUATION OF PERFORMANCE Evaluation of Performance 8.1 Purpose The purpose of the Evaluation of Performance section of the Asset Management Plan (AMP) is to compare Unison s annual results against its targets, and to identify areas for improvement. The targets that are assessed are financial (budgets), physical progress through programmes of works (CAPEX and maintenance), service levels and progress through major asset management initiatives. Areas for improvement are considered across the asset management process, including asset management planning and the AMP itself. 8.2 Progress against 2010/11 Capital Expenditure Plan Financial Progress The projection to the end of the 2010/11 financial year sees Unison below budget for CAPEX. There are some significant variances within the categories due to changes in priorities during the financial year. CAPEX Category Budget Actual Variance System Growth 2,200,000 3,445,968 57% Asset Replacement and Renewal 8,800,000 9,278,692 5% Reliability, Safety and Environment 7,100,000 4,704,258-34% Customer Connection 9,600,000 9,356,549-3% Asset Relocations 1,500,000 1,231,169-18% TOTAL 29,200,000 28,016,636-4% Table 8-1 Progress against 2010/11 CAPEX budget Table 8-2 below provides an explanation for variances to budget of greater than 10%. CAPEX Category System Growth Asset Replacement and Renewal Reliability, Safety and Environment Customer Connection Asset Relocations TOTAL Explanation for Variance Over expenditure in the System Growth category is due to a higher than forecast project carryover from 2009/10 (Fleet Street Zone Substation). Expenditure in this category was not curtailed, to ensure the sustainability of the contracting market, after several Smart Grid Initiative projects were deferred (see below). Minor variance. Smart Grid Initiative CAPEX is captured in the Reliability, Safety and Environment category. The 2010/11 expenditure in this category was lower than forecast to enable the rephasing of the Smart Grid Initiative. This was deemed necessary to allow further development of several core technologies that will be widely deployed on the network. These technologies are crucial to realising the benefits set out in Section 2.3. Minor variance. The forecast under expenditure on Asset Relocations is due primarily to the Maraeroa Road Passing Lane Project (Rotorua). This project was forecast to take place in 2010/11 but was deferred to 2011/12. Minor variance Table 8-2 Variances to 2010/11 CAPEX budget as projected February 2011

323 8-4 SECTION 8 EVALUATION OF PERFORMANCE Physical Progress In 2010/11 Unison constructed a dedicated zone substation for a key customer at short notice. This resulted in the deferral of a number of planned Asset Replacement and Renewal Projects. Despite this, good progress was made against the works programme. Asset Replacement and Renewal Projects Table 8-3 below shows the progress on each of the renewal projects that were planned for the 2010/11 financial year. Asset Category Description Status Cables Neeve Road OHUG In Progress Cables Henry Charles Crescent and Terrace OHUG In Progress Cables Murdoch Road East OHUG In Progress Cables Cambridge Terrace OHUG In Progress Cables Copeland Road OHUG Complete Cables Southland Road OHUG Complete Cables Nelson Street North / Williams Street OHUG Complete Cables Rotorua CBD street light cable design and installation (Tutanekai Road) In Progress Cables Replace cable Sanders Road Complete Cables Replace Hastings feeder cables Complete Cables Replace Southland Road cable termination and re instate cable with single joint and termination Complete Distribution Switchgear Replace RMS Cnr Outram and Riverslea Roads Hastings In Progress Distribution Switchgear Replace Statter Shakespeare Road Napier Complete Distribution Switchgear Remove RMU Unit from Loft above Sub - Taupo Complete Distribution Switchgear Replace RMS Eastbourne Street Hastings Complete Distribution Switchgear Remove Statter Cnr Kennedy Road & Douglas McLean Avenue Complete Distribution Switchgear Replace Magnefix Southampton Street Hastings Complete Distribution Switchgear Replace RMS Hinemaru Street Complete Distribution Switchgear Replace ABS Tukairangi Road Complete Distribution Switchgear Replace ABS Vaughan Road Complete Distribution Switchgear Replace RMS Units Cnr Rangiuru and Whakaue Streets Complete Distribution Switchgear Replace fuse cabinets Karamu Road Complete Distribution Switchgear Replace Bay View feeder Complete Distribution Transformers and Regulators Distribution Transformers and Regulators Distribution Transformers and Regulators Distribution Transformers and Regulators Replace Sub, Cnr Sale and Munroe Streets, Napier Replace Transformer Keitha Place Kinloch Replace Sub Hitchings Avenue, Napier Replace groundmount sub, Steeles Lane - Rotorua In Progress In Progress Complete Complete

324 SECTION 8 EVALUATION OF PERFORMANCE 8-5 Asset Category Description Status Distribution Transformers and Regulators Distribution Transformers and Regulators Distribution Transformers and Regulators Distribution Transformers and Regulators Distribution Transformers and Regulators Distribution Transformers and Regulators Distribution Transformers and Regulators Distribution Transformers and Regulators Distribution Transformers and Regulators Distribution Transformers and Regulators Replace Transformer, Hastings Replace groundmount sub Meadowbank Avenue Replace Transformer Wairakei Resort Hotel Replace Transformer Kotare Street Taupo Replace Transformer Hinemaru Street Replace Fibreglass transfomer covers Replace Transformer with Padmount Replace groundmount sub Corlett Street - Rotorua Replace sub Huia Street, Camberley Install Earth banks at Transformers - Rotorua Complete Complete Complete Complete Complete Complete Complete Complete Complete Complete Lines Onekawa A & B Upgrade, Powdrell Road to Waiohiki Road In Progress Lines Install Hendrix Spacer Cable on Esk feeder - Vicinity Woolshed Road across Estuary. In Progress Lines Fernleaf Feeder Pole Renewals In Progress Lines Golf Course Feeder Pole Renewals In Progress Lines Reconstruction Apirana Road - Rotorua In Progress Lines Replace conductor Huiarangi Road In Progress Lines Waikite Feeder Pole Renewals Complete Lines Rissington Feeder Pole Renewals Complete Lines Reconstruction Stage 2. Plateau Road Complete Lines Conductor Upgrade Pole Replacements - Plateau Road (Stage 1) Complete Lines MAPT Nuffield feeder Cancelled Lines MAPT Tangoio feeder Complete Lines LV network re-configuration at Fryer Road Complete Lines Broovale Road Havelock Replace LV pole Complete Lines Kaharoa Feeder Replace glass type fuses Complete Lines MAPT Poukawa feeder Complete Lines Mangatahi Feeder Pole Renewals Complete Lines Belmont Feeder Pole Renewals Complete Lines Elwood Feeder Pole Renewals Complete Lines State Mill Feeder Pole Renewals Complete Lines Fenton Park Feeder Pole Renewals Complete

325 8-6 SECTION 8 EVALUATION OF PERFORMANCE Asset Category Description Status Lines Vaughan Feeder Pole Renewals Complete Lines Tikokino Feeder Pole Renewals Complete Lines Omaranui Feeder Pole Renewals Complete Lines Underground overhead LV road crossing Raukawa Road Complete Lines Karamu Feeder Pole Renewals Complete Lines Relocate line Dartmoor Road Complete Lines Neeve Feeder Pole Renewals Complete Lines MAPT Currie Feeder Complete Lines Opepe Feeder PFM - Pole Renewals Complete Lines Ohaaki Tie Feeder - Pole Renewals Complete Lines Replace Broken Pole Cnr Pohutukawa & Te Ngae Roads Complete Lines Replace Crossing Pole Middle Road Complete Lines MAPT St Mary Feeder Complete Lines Pukehangi Feeder Pole Renewals Complete Lines Pakowhai Feeder Pole Renewals Complete Lines Washpool Feeder Pole Renewals Complete Lines Waiotapu Feeder Pole Renewals Complete Lines Replace S52 auto links with NOVA on Valley feeder Complete Lines Planned Renewal CR Budget Provision Lines Planned Renewal HB Budget Provision Lines Reactive Renewal CR Budget Provision Lines Reactive Renewal HB Budget Provision SCADA, Control and Comms SCADA, Control and Comms Zone Subs, Buildings and Equipment Zone Subs, Buildings and Equipment Zone Subs, Buildings and Equipment Zone Subs, Buildings and Equipment Zone Subs, Buildings and Equipment Zone Subs, Buildings and Equipment Zone Subs, Buildings and Equipment HB RTU Replacement 10/11 HB RTU Replacement 09/10 Flaxmere Zone Substation Transformer Protection Relay Replacement Tomoana Zone Substation Transformer Protection Relay Replacement Mahora Zone Substation Transformer Protection Relay Replacement Tannery Road transformer protection replacement Tomoana feeder relay replacement Tannery Road Substation Replace Line Disconnectors Rainbow Zone Substation - Feeder Protection Relay Replacement In Progress Complete In Progress In Progress In Progress In Progress In Progress In Progress Complete Zone Subs, Buildings and Fernleaf Zone Substation - Feeder Protection Relay Replacement Complete

326 SECTION 8 EVALUATION OF PERFORMANCE 8-7 Asset Category Description Status Equipment Table 8-3 Status of renewal projects planned for 2010/11 Network Development Projects Table 8-4 below shows the progress on each of the network development projects that were planned for the 2010/11 financial year (and listed in the 2010 AMP). Asset Category Project Name Status Capacitor banks Install capacitor bank on Twyford feeder Complete Distribution switchgear Replace existing manual ABS's with automated switches on Western Heights, Fordlands, Clayton, Pukehangi, Taupo North and Acacia Bay feeders In progress Distribution switchgear Replace existing Nulec Reclosers with Nova Reclosers on Iona and Te Aute feeders Complete Distribution switchgear Replace existing Nulec Reclosers with Nova Reclosers on Waimarama feeder Deferred DTS Install soil thermal resistivity and moisture sensors - Havelock-Arataki tie In progress Lines Botanical and Richmond feeder interconnection Complete Lines Create more interconnections to alleviate constraints on Greenmeadows and Taradale B feeders Complete Lines Extend network from Ohaaki to the Fernleaf substation along SH6 Deferred Lines Paora Hapi and Opepe feeder extension along Gilles Avenue Complete Lines Purchase the Transpower owned 33kV line between Wairakei and Ohaaki In progress Lines Upgrade Bridge Pa and Raureka feeders Deferred Lines Upgrade constrained 33kV incomer cables at Havelock North substation Deferred Lines Upgrade constrained sections of Flaxmere feeders near the substation In progress Lines Upgrade Ngapuna and Vaughan feeders In progress Lines Upgrade Pukehangi feeder Complete Lines Upgrade sections of cable on Mission and Neeve feeders Complete Protection Install differential protection relays on the Centennial Drive Taupo South and Centennial Drive Fleet Street 33kV feeders In progress Voltage regulators Install voltage regulators on Acacia Bay, Dalbeth and Okere feeders In progress Table 8-4 Status of network development projects planned for 2010/11

327 8-8 SECTION 8 EVALUATION OF PERFORMANCE 8.3 Progress against 2010/11 Maintenance Expenditure Plan Financial Progress The projection to the end of the 2010/11 financial year sees Unison s maintenance spend approximately 8% under budget. The budget split by maintenance activity is provided in Table 8-5. Maintenance Activity Budget Actual Variance Overhead Lines 4,060,000 3,969,992-2% Underground Cables 836, ,106-42% Circuit Breakers 282, ,447-3% Other Substation Equipment & Buildings 642, ,392-12% Zone Transformers 215, ,947 6% Distribution Transformers/Regulators 1,050,000 1,024,658-2% Distribution Switchgear 177, ,142-14% Load Control 92,000 55,222-40% Miscellaneous Distribution Equipment 565, ,718-9% Vegetation 1,250,000 1,250,000 0% SCADA Communications 477, ,281-4% Power Quality 390, ,037-10% TOTAL 10,036,000 9,331,942-7% Table Progress against 2010/11 maintenance budget as projected February 2011 Table 8-6 Variances to 2010/11 OPEX budget as projected February 2011 below provides an explanation for variances to budget of greater than 10% by asset category. OPEX Category Underground Cables Other Substation Equipment & Buildings Distribution Switchgear Load Control TOTAL Explanation for Variance The reliability of the underground network continues to improve meaning that reactive costs for cables were below budget. Furthermore, the survey of LV underground circuits in the Rotorua area was completed more quickly than expected, resulting in a lower cost. Planned maintenance on these assets came in under budget as technician resources were deployed on CAPEX protection projects. Inspection frequency was increased to compensate. Some planned maintenance of distribution switchgear was deferred to enable contractor resource to be deployed in other areas (such as high priority CAPEX projects). These maintenance workpacks have been given priority for the 2011/12 financial year. Due to the age profile of Unison s load control plant a large reactive budget provision was made for these assets. No major failures meant that this budget was underutilised. Minor variance. Table 8-6 Variances to 2010/11 OPEX budget as projected February 2011

328 SECTION 8 EVALUATION OF PERFORMANCE Physical Progress Physical progress through the planned maintenance programmes is provided in Table 8-7 below. Maintenance Programme Overhead Lines Inspection Overhead Lines Preventative Maintenance Circuit Breakers Preventative Maintenance Other Substation Equipment & Buildings Preventative Maintenance Zone Transformers Preventative Maintenance Ground Mounted Assets Inspection Distribution Transformers/Regulators Preventative Maintenance Distribution Switchgear Preventative Maintenance Load Control Preventative Maintenance Miscellaneous Distribution Equipment Inspection and Preventative Maintenance Vegetation Progress The five year inspection programme is on target through the use of ground based and aerial inspections. Overall the preventative maintenance programme is on target. Some projects in this area were deferred to enable contractor resource to be deployed in other areas (such as high priority CAPEX projects). The preventative maintenance programme is on target as per the cyclical zone substation inspection and maintenance regime. The preventative maintenance programme is on target as per the cyclical zone substation inspection and maintenance regime. The preventative maintenance programme is on target as per the cyclical zone substation inspection and maintenance regime. The GMI programme is on target. The preventative maintenance programme is on target. The preventative maintenance programme is on target. The preventative maintenance programme is on target as per the cyclical zone substation inspection and maintenance regime. The pedestal inspection work issued for the year has again been impacted by the reprioritisation of inspection resources, however it is expected that most, if not all, will be completed by year end. Progress through the vegetation management plan is behind target. Table 8-7 Physical Progress through maintenance programmes Progress against Maintenance Initiatives Maintenance Initiative Progress Effectiveness Vegetation management Introduction of Deuar mechanical (non-destructive) pole tester. The vegetation management initiative is behind in a number of areas. Unison is working closely with the vegetation management service provider to ensure that the next quarter sees good progress against the plan. Four testers are to be introduced to asset inspection team. Recent storms have impacted heavily on vegetation related faults, however these types of faults are generally attributable to trees outside the managed line corridor. Notable improvement in accuracy of pole tests over ultrasound units (which can often miss rot below ground level). Table 8-8 Progress against maintenance initiatives

329 8-10 SECTION 8 EVALUATION OF PERFORMANCE 8.4 Performance against Service Levels for 2009/10 This section assesses Unison s performance against its Service Levels as provided in the 2010 AMP. Performance against Service Levels added in the 2011 AMP is also assessed (note that 2010/11 actual figures are projected to year end). Service Standard Target 2010/11 Actual 2010/11 (forecast) Assessment SAIDI < minutes minutes SAIFI < 2.70 interruptions 1.97 interruptions Interruptions occurring in urban areas Interruptions occurring in urban areas Interruptions occurring in rural areas Interruptions occurring in rural areas Interruptions occurring in remote rural areas Interruptions occurring in remote rural areas Maximum of twenty events to exceed three hours before supply is restored per annum Maximum of one feeder to exceed four unplanned interruptions per annum Maximum of ten events to exceed six hours before supply is restored per annum Maximum of one feeder to exceed ten unplanned interruptions per annum Maximum of five events to exceed six hours before supply is restored per annum Maximum of one feeder to exceed twenty unplanned interruptions per annum 18 events 1 feeder 32 events 4 feeders 17 events 0 feeders Total cost per ICP <$271 $270 Total cost per km <$3,159 $3,128 Capacity utilisation >31% 28% Loss ratio <6% 4.0% Faults per 100km <7.97 faults per 100km 6.15 faults per 100km Table 8-9 Performance against service levels 2010/11

330 SECTION 8 EVALUATION OF PERFORMANCE Explanations for Service Level Targets not Met Service Level Interruptions occurring in remote rural areas Capacity Utilisation Explanation In 2010/11 the performance of the Unison network was heavily affected by weather events driven by the La Niña weather system. High winds resulted in damage to assets and widespread outages in exposed areas. The feeders breaching the service level targets in rural and remote rural were all impacted by the wind storms. The Unison network experienced a relatively warm winter meaning that peak demand was suppressed. This in turn meant that Unison s capacity utilisation for 2010/11 decreased. This phenomenon seems to have occurred across New Zealand EDBs as shown in Figure 4-8 the following was sourced from NIWA1: Winter temperatures were above average (between 0.5 C and 1.2 C above average) in parts of the north and east of the North Island, in Nelson, along the West Coast and in Fiordland. Below average winter temperatures (between 0.5 C and 1.2 C below average) were observed for parts of eastern Otago. In other regions, winter temperatures were close to average (within 0.5 C of seasonal average). The New Zealand national average temperature was 8.7 C (0.5 C above the winter average) Time Series Data The following diagrams show Unison s performance in a selection of Service Levels over a five year period SAIDI Performance SAIDI (minutes) / / / / / /11 SAIDI B SAIDI C Regulatory Target Figure 8-1 SAIDI Performance time series 1 National Climate Summary Winter data/assets/pdf_file/0018/106542/climate_summary_winter2010.pdf

331 8-12 SECTION 8 EVALUATION OF PERFORMANCE 4 SAIFI Performance SAIFI (interruptions) / / / / / /11 SAIFI B SAIFI C Regulatory Target Figure 8-2 SAIFI performance time series 300 Total Costs per ICP 250 $ per km / / / / / /11 Total Costs per ICP Total Costs per ICP (Real) Service Level Target Figure 8-3 Total Costs per ICP time series

332 SECTION 8 EVALUATION OF PERFORMANCE Total Costs per km $ per km / / / / / /11 Total Costs per km Total Costs per km (Real) Service Level Target Figure 8-4 Total Costs per km time series 35% Capacity Utilisation 30% Capacity Utilisation 25% 20% 15% 10% 5% 0% 2005/ / / / / /11 Capacity Utilisation Service Level Target Figure 8-5 Capacity utilisation time series

333 8-14 SECTION 8 EVALUATION OF PERFORMANCE 7.0% Loss Ratio 6.0% 5.0% Loss Ratio 4.0% 3.0% 2.0% 1.0% 0.0% 2005/ / / / / /11 Loss Ratio Service Level Target Figure 8-6 Loss ratio time series 10 Faults per 100km Total Faults per 100km / / / / / /11 Faults per 100km Service Level Target Figure 8-7 Faults per 100km performance time series

334 SECTION 8 EVALUATION OF PERFORMANCE Progress through Asset Management Initiatives The table below provides detail on key company initiatives within asset management planning. The list includes new initiatives as well as initiatives in progress at the time the last AMP was published. Initiative Description Status Expected completion date Smart Suburb Proof of concept trial for a network-wide smart grid rollout. A number of new technologies will be introduced to the network in this trial. Complete Complete Expenditure modeling tools V2 Version two of the Network Investment Toolbox has been completed, meaning each of the decision support tools that it comprises has been upgraded. This version is currently in service. Complete Complete Core process review The core process review has been completed. This review has resulted in a number of major changes to CAPEX planning and the interface with the contracting market. Complete Complete Investment Prioritisation Tool (IPT) upgrade Decision Support Tools Workstream Service levels Probabilistic planning An upgrade of the IPT was planned for 2010/11. This has been deferred to coincide with formal reconceptualisation of the Network Investment Toolbox in light of data from the Smart Grid Initiative. The Smart Grid Initiative will increase the scope and volume of data available. This will in turn enable further upgrade of the tools (Decision Support Tools Workstream of Smart Grid Initiative, Section 2.3). The introduction of FAIDI and FAIFI as service levels has been deferred to allow further trials of these metrics internally (with the Board of Directors), and to enable further time for data aberrations to be ironed out. The review of Unison s planning philosophy (deterministic to probabilistic planning) has been deferred as this initiative will leverage on the data streams made available by the Smart Grid initiative. Commencing December 2011 Commencing April 2015 Deferred June 2011 Deferred April 2011 Customer relationship management system Introduction of a customer relationship management system (CRM) to allow Unison to respond better to consumer queries, provide an outage notification service and enhance the new connection process. Complete Complete Asset management system review Review of the core systems used by Unison to maintain its asset register and create maintenance programmes. Complete Complete Outage management system Introduction of an outage management system to provide an improved faults database and integrate with the TVD call and dispatch system. (This is now deferred pending supplier integration with Smart Grid technology). Deferred Deferred Data Management Workstream An initiative to process the data received from assets in the Smart Grid and turn it into useful information for asset management planning processes (Data Management Workstream of Smart Grid Initiative, Section 2.3). Commencing April 2015

335 8-16 SECTION 8 EVALUATION OF PERFORMANCE Initiative Description Status Expected completion date Smart Network and Communications Workstreams Demand-side Management Initiatives Workstream A major initiative that will involve a rollout of smart grid technologies across the Unison network. This will include distribution automation, asset sensors, online condition monitoring technologies, as well as a fit for purpose communication medium (Smart Network and Communcations Workstreams, Section 2.3). An aspect of the Smart Grid Initiative focusing on reducing peak demand through DSM and energy efficiency (Section 2.3). In progress April 2015 Commencing April 2015 Table 8-10 Asset management initiatives 2011/ Gap Analysis and Improvement Initiatives Table 8-11 Gap analysis and improvement initiatives itemises key gaps as identified by service levels that were not met, as well as initiatives that have been introduced to close these gaps. Service Level Gap Analysis Improvement Initiatives Interruptions occurring in rural and remote rural areas Capacity utilisation In 2010/11 the performance of the Unison network was heavily affected by weather events driven by the La Niña weather system. High winds resulted in damage to assets and widespread outages in exposed areas. The feeders breaching the service level targets in rural and remote rural were all impacted by the wind storms. Analysis of fault data reveals that vegetation continues to cause the largest number of sustained outages during prolonged windstorms. Trees from outside the growth limit zone falling across lines are relatively commonplace, especially in forestry areas. In areas of dense vegetation such as around the Rotorua Lakes, vegetation encroachment into line corridors is a constant problem. Capacity utilisation was affected by the relatively warm winter. Aside from this external influence, the opportunity to improve capacity utilisation across the Unison network has been identified. Currently planning standards are deterministic and necessarily conservative. Revision of vegetation management strategy to focus on wider clearance corridors to eliminate trees falling on lines and where possible, removal of the trees. Vegetation management and liaison are now performed by Unison Contracting Services Limited. These duties have only recently been taken up; meaning that coordination between EDB and contractor can be improved. The focus for 2011/12 will be on negotiating for the removal of at risk trees within falling distance of lines. Other overhead system options are also being deployed on the network. These include Hendrix insulated spacer system and composite poles. Hendrix system means that some degree of vegetation encroachment will not cause the loss of power. Composite poles mean that in the case of widespread damage to poles, especially in areas where access is a problem, replacements can be undertaken in the quickest possible time. One of the key benefits of the Smart Grid Initiative will be improving the utilisation of assets. This will be made possible through the proliferation of sensors and the ability to rapidly shift load. These factors will influence design and network planning standards meaning that capacity utilisation will improve over the planning period. Table 8-11 Gap analysis and improvement initiatives

336 SECTION 8 EVALUATION OF PERFORMANCE Review of Quality of Asset Management Planning and the AMP The past five years have seen considerable effort put into improving Unison s asset management planning, with a view to reaching, and in many cases exceeding, industry best practice. To this end, a comprehensive suite of asset management processes, systems, tools and models have been introduced. Unison has never known so much about its asset base, its stakeholders or the environment that it operates within. It is recognised that while significant progress has been made, there are still a number of areas where further improvement is possible. The Smart Grid Initiative is something that will have a significant impact in this regard, as evidenced in the plans provided throughout the AMP. Throughout the recent development of Unison s asset management planning, a number of external specialists have been engaged to review the progress that has been made. Comments received have reinforced Unison s views that either best practice has been achieved, or appropriate steps are being taken to ensure this standard will be reached in time. These opinions are further validated by dialogue that Unison has engaged in with other EDBs, both in New Zealand and overseas. Unison s 2009 AMP received a favourable review from Strata Consulting (Strata) on behalf of the Commerce Commission. The AMP was rated as the third best document produced by the twenty-nine New Zealand EDBs, providing a strong foundation for the 2011 AMP. Unison s 2009 AMP was also reviewed by an external expert who echoed Strata s commendation and provided specific comments on how the document might be improved. In planning the 2011 AMP, a strong emphasis was placed on correcting the areas of partial compliance or noncompliance in the 2009 AMP. Unison considers that areas of concern have been addressed. The 2011 AMP also attempts to take the consumer focus of the 2009 AMP a step further by enhancing the accessibility of the document. The steps taken in this regard include a more comprehensive Key Stakeholder Information section in Section 1, enhanced clarity of Sections 4 and 8, a simpler layout of project plans in Sections 5 and 6 and an expanded glossary.

337 section 9 expenditure forecasts and reconciliation expenditure forecasts and reconciliation Weather stations are being installed across the Unison network. The data collected will be used to calculate dynamic ratings on overhead circuits, providing the ability to increase asset utilisation.

338 SECTION 9 EXPENDITURE FORECASTS Expenditure Forecasts Expenditure Forecasts and Reconciliation

339 9-2 SECTION 5 EXPENDITURE FORECASTS 9 Expenditure Forecasts 9.1 Expenditure Forecasts and Reconciliation

340 APPENDIX A GLOSSARY OF TERMS appendix a Unison s distributed temperature sensor (DTS) uses fibre optics to provide a temperature profile along critical underground 33kV circuits.

341 APPENDIX A GLOSSARY OF TERMS A-1 Appendix A Glossary of Terms ABS Air Break Switch AC Alternating Current ACC Accident Compensation Corporation ACSR Aluminium Conductor Steel Reinforced AE Augmentation Envelope AMP Asset Management Plan AOC Alternative Operations Centre BCP Business Continuity Planning CAD Computer Aided Design CAU Census Area Units CAIDI Customer Average Interruption Duration Index CAPEX Capital Expenditure CB Circuit Breaker CBD Central Business District CDEM Civil Defence Emergency Management Central Region Rotorua / Taupo CML Customer Minutes Lost CPI Consumer Price Index CPZ Council Planning Zone CT Current Transformer DC Direct Current DG Distributed Generation DGA Dissolved Gas Analysis DRC Depreciated Replacement Cost EDB Electricity Distribution Business ELB Electricity Lines Business EVA Ethylene Vinyl Asotote GIS Geo-spatial Information System GM General Manager GMI Ground Mount Inspection GPS Global Positioning System GWh Giga Watt-hours GXP Grid Exit Point H&S Health and Safety HBPCT Hawke s Bay Power Consumers Trust HV High Voltage H2S Hydrogen Sulphide ICP Installation Control Point IFRS International Financial Reporting Standards LCP Legislative Compliance Programme LV Low Voltage MD Maximum Demand

342 A-2 APPENDIX A GLOSSARY OF TERMS Glossary of Terms MIND Mineral Insulated Non Draining MVA Mega Volt-Amps NIF Network Investment Framework NRIM Network Renewal Investment Model NPV Net Present Value ODRC Optimised Deprival Replacement Cost ODV Optimised Deprival Value OH Overhead OHUG Overhead to Underground Conversion OPEX Operational Expenditure PDA Personal Digital Assistant PILC Paper Insulated, Lead Covered PLC Programmable Logic Controller POS Point of Supply PVC Polyvinyl Chloride RC Replacement Cost RCS Remote Controlled Switch RLE Residual Life Expectancy RMS Ring Main Switch RRR Repair, Refurbish Replace RTU Remote Terminal Unit SAIFI System Average Interruption Frequency Index SAIDI System Average Interruption Duration Index SCADA Supervisory Control and Data Acquisition SCI Statement of Corporate Intent SF6 Sulphur Hexaflouride SLT Service Level Target SO2 Sulphur Dioxide Sys Op System Operator SWER Single Wire Earth Return UCSL Unison Contracting Services Limited UG Underground UHF Ultra High Frequency VHF Very High Frequency UPS Unison Project Systems VoIP Voice over Internet Protocol VT Voltage Transformer WASP Works, Assets, Scheduling and People (Software Package) WEKA Western Kinloch Arterial WSMP Workplace Safety Management Practices XPLE Cross Linked Polyethylene ZS Zone Substation

343 APPENDIX B REQUIREMENT 7(2) Fenton Street, Rotorua at night. Along with Hawke s Bay and Taupo, Rotorua is part of the Unison network. appendix b

344 APPENDIX B REQUIREMENT 7(2) B-1 Appendix B 1 Requirement 7(2)... B Assumption 1. HBPCT initiate and fund OHUG projects (Section 1)...B Assumption 2. Integrity of asset data (Section 2)...B Assumption 3. The contracting market - Unison s planned and reactive works (Section 2)...B Assumption 4. Continuity of Large Consumers (Section 3)...B Assumption 5. Transpower supply configuration (Section 3)...B Assumption 6. Stability of Customers view on Price-Quality trade off (Section 4)...B Assumption 7. Accuracy of Load Forecast (Section 5)...B Assumption 8. Uncertain load types and external factors (Section 5)...B Assumption 9. Accuracy of network planning outputs from simulation models (Section 5)...B Assumption 10. Benefits of the Smart Grid Initiative (Section 5)...B Assumption 11. Accuracy of presently utilised condition assessment techniques (Section 6)...B Assumption 12. ODV asset standard lives (Section 6)...B Assumption 13. Quantification of WACC used in Renewal Envelope (Section 6)...B Assumption 14. Expenditure forecast as published in the AMP (Section 9)...B-8

345 B-2 APPENDIX B REQUIREMENT 7(2) Appendix B 1 Requirement 7(2) of the Electricity Distribution (Information Disclosure) Requirements 2008 In any case where prospective information is required by subclause (1) to be Publicly disclosed the Distribution business must also Publicly disclose the following (as at the date of the Asset Management Plan): a. All significant assumptions, clearly identified in a manner that makes their significance understandable to electricity consumers, and quantified where possible; b. A description of changes proposed where the information is not based on the Distribution business s existing business; c. The basis on which significant assumptions have been prepared, including the principal sources of information from which they have been derived; d. The factors that may lead to a material difference between the prospective information disclosed and the corresponding actual information recorded in future disclosures; e. The assumptions made in relation to these sources of uncertainty and the potential effect of the uncertainty on the prospective information. 1.1 Assumption 1. Hawke s Bay Power Consumers Trust (HBPCT) continue to initiate and fund overhead to underground conversion (OHUG) projects (Section 1) a. Unison s asset replacement and renewal expenditure forecast is formulated on the assumption that the HBPCT will continue to initiate and fund OHUG projects (see AMP section 1.3.3). b. No changes are proposed. c. The assumption has been derived on the basis of the Statement of Corporate Intent. d. A change in the SCI would lead to a material difference between forecast and actual expenditure. e. Given Hawke s Bay consumers preference for OHUG projects to continue (as per consumer engagement initiatives AMP section 2.4.1); it is believed that the assumption of the HBPCT continuing to fund these projects is an appropriate one. 1.2 Assumption 2. Integrity of asset data within the Fixed Asset Register and GIS (Section 2) a. Unison s asset management practices are highly reliant on the quality of data within the fixed asset register (WASP) and GIS. In order to run simulations and models, advise consumers, and implement maintenance plans, good data quality is required. b. In 2011 WASP will be replaced with Activa, a more advanced asset management system. Over the longer term this will tend to improve the integrity of asset data.

346 APPENDIX B REQUIREMENT 7(2) B-3 c. The assumption of the quality of the data is based upon the fact that inaccuracies within the system are rare (empirical evidence) and that as the system is used errors are identified and corrected. d. Greatest potential for material impact is with the assumed standard life of assets where the installation date is unknown. This is mitigated by condition assessment estimated remaining life from condition assessment is preferred to the standard life assumption. e. The potential impact of inaccuracies in asset data are inaccuracies in the expenditure forecasts that the data drives. In order to reduce uncertainty in this area, condition assessment is prioritised in areas where present data quality is poor. 1.3 Assumption 3. The contracting market remains solvent and able to complete Unison s planned and reactive works (Section 2) a. As an electricity distribution business, Unison is highly reliant upon a contracting market that can complete its planned and reactive maintenance and capital works programmes. The Smart Grid Initiative is driving a change in the contractor skillsets that are required to complete the capital works programme. b. No changes are proposed to Unison s current contracting philosophy, however Unison has engaged with the contracting market to ensure that appropriate skillsets will be available. c. Through top down analysis of contractor revenue requirements and engagement with the market as a stakeholder in Unison s business, Unison is confident that the contracting market within Unison s footprint is sustainable, and that the individual businesses that it comprises will remain solvent and able to complete Unison s works programmes throughout the planning period. d. Unison s ability to meet its expenditure forecasts would be affected greatly by material change to the contracting capability available on the network. Such change could come about due to attractive job opportunities for contracting employees in other regions of New Zealand or abroad or the unplanned exit of one of the contracting businesses operating in Unison s footprint. e. In the former case set out above, Unison would seek to retain its contracting capability by matching a market rate for contracting employees. This would likely have a significant impact on expenditure forecasts (less work completed per dollar of expenditure). In the latter case, Unison expects a notice period from the contracting market if exit is to occur. This will allow Unison to transition seamlessly between contracting service providers. 1.4 Assumption 4. Continuity of Large Consumers (Section 3) a. It is assumed that Unison s large consumers (Section 3.1.2) will continue to require electricity supply at the same or similar levels throughout the planning period. Any non-notified material change to the requirements of these consumers could potentially have a significant impact on Unison s network development plans, risk management techniques, revenues and expenditure forecasts. b. No changes are proposed. c. Unison regularly engages with its large consumers to ensure that their needs are being met. d. Any such decision rests entirely with the companies concerned.

347 B-4 APPENDIX B REQUIREMENT 7(2) e. Potentially the loss of Unison s large consumers would substantially impact the regulated revenue of Unison, which may place considerable pressure on the capital and to a lesser extent the operating forecasts proposed in this AMP. It is possible that capital expenditure would be curtailed for discretionary projects, and maintenance plans reduced where assets are no longer required to operate at forecast levels. 1.5 Assumption 5. Transpower supply configuration will remain unchanged and any changes will be notified to Unison (Section 3) a. Unison s network development plan and energy consumptions are based on existing Transpower network configuration. b. No changes are proposed. c. This assumption is based on changes to Unison s network requirements from forecasted load growths, land use changes that would require additional sub-transmission network in Unison s footprint. Any new supply arrangements are Unison driven. They are published in Transpower s Annual Planning Report, and Unison does not foresee any future requirements. d. The Transpower supply configuration can be changed if unforeseen land activities eventuate within the planning horizon requiring additional capacity on the network. e. This may result in reduction in security and quality of supply for new load growths. This is likely to increase the expenditure forecast to provide the same level of service as other Unison consumers. 1.6 Assumption 6. Stability of Customers view on Price-Quality trade off (Section 4) a. It is assumed that the consumers and shareholders expectations in terms of acceptable reliability and appropriate price of electricity supplied remain relatively stable throughout the planning period. b. No changes are proposed. c. This assumption is based on representative customer research that has indicated that Unison s customers are generally comfortable with the current levels of performance, in consideration of current price. Furthermore, customers have indicated that generally they are not willing to trade off improved or lesser performance for price increases or decreases respectively. This assumption was further reinforced by the 2010 customer satisfaction survey. d. Changes in energy consumption patterns through differing energy requirements may well lead to changed expectations of acceptable levels of reliability and quality of electricity supply. This could be driven by changes in technology, or a significant reduction in cost of some technologies. e. Potentially this may result in a requirement for Unison to improve performance against service levels beyond those planned, as detailed in section 4. This would require additional forecast expenditure, dependent upon the extent of improvement required.

348 APPENDIX B REQUIREMENT 7(2) B Assumption 7. Accuracy of Load Forecast (Section 5) a. The Load Forecast is used to estimate the rate at which the different parts of Unison s network are growing. The Load Forecast is a vital tool as it is used to plan future capacity and network architecture requirements, which in turn drive network expenditure forecasts. The information and data used in the Load Forecast is the most current available. The Load Forecast is based upon rigorous analytical principles and has been reviewed by modelling experts. b. No changes are proposed. c. The Load Forecast is built up using Census data, GDP data (Statistics New Zealand), local knowledge, and information from large consumers (both existing and prospective) and zonings of respective District Councils. d. Load growth is inherently difficult to forecast due to the volatile nature its many inputs (e.g. regional economic conditions, property market, Central Government). Large fluctuations in these inputs will result in material differences between the load forecasts as disclosed in this AMP and information recorded in future disclosures. e. The Load Forecast is rerun annually to incorporate the most recent data and market insights available. This minimises the impact of sources of uncertainty. The uncertainty associated with the assumptions driving the load forecast can affect forward expenditure forecasts (especially Customer Connection CAPEX). 1.8 Assumption 8. Uncertain load types and external factors (Section 5) a. The Load Forecast implicitly assumes static energy intensity, constant power factor of 0.95 and no significant shifts in the underlying technology of electricity distribution in the next twenty years. b. Validation of these assumptions through studies by Transpower and international utilities and customer surveys may result in changes to these assumptions. c. These assumptions are the default position in the absence of improved information. They represent a conservative precautionary approach to forecasting. d. Changing energy use and the proliferation of distributed generation are the two main factors that could act to render the assumptions incorrect. e. The assumption is that the sources of uncertainty will not have a material effect within the twenty year planning horizon. Increasing energy intensity will cause the load forecast to be an underestimate. Increasing proliferation of distributed generation will cause the load forecast to be an overestimate. 1.9 Assumption 9. Accuracy of network planning outputs from simulation models (e.g. CYMCAP, DIgSILENT) (Section 5) a. Unison uses several tools to simulate network conditions under different scenarios. It is assumed that the simulations undertaken provide information of a quality level that will allow the best network planning decisions to be made. b. No changes are proposed. c. To date this assumption has been validated through comparison of simulation results with empirical data, and other quality audits.

349 B-6 APPENDIX B REQUIREMENT 7(2) d. Factors that may invalidate simulation results include inaccuracy in load forecast and inaccuracy in asset data. e. The disclosed network development plan is based upon simulated results using forecasted load. Uncertainties in load prediction would result in minor differences between the long term project plan and the actual plan being executed Assumption 10. Benefits of the Smart Grid Initiative (Section 5) a. It is assumed that the Smart Grid Initiative that Unison has embarked upon will deliver a number of benefits to the business, to consumers and to the local communities that Unison serves. The most notable benefits are improvements to the quality of supply delivered to consumers and the deferral of expenditure (both maintenance expenditure and capital expenditure) that will impact favourably on consumers distribution charges. b. No changes are proposed. c. Detailed analysis has been undertaken that quantifies the benefits of implementation of the different types of equipment that comprise the Smart Grid initiative. These analyses form the principal sources of information that inform the assumption. Further support for the assumption comes from international experience of implementations of the technology that is being investigated as well as the following internal measures: Development of the Data Management and New Technology Prioritisation Frameworks. Decision support matrices that guide the development of asset management solutions, and the selection of smart grid technologies; Compilation of a comprehensive Smart Grid Project Management Plan (Section 2.3); Development of objective decision rules to guide asset deployment. For each area of the network and each technology these rules provide a sound basis for optimising placement and quantity of smart grid assets to install; Proof of concept data management solutions such as dynamic ratings for overhead lines; Further detailed research into several new technologies. Most notably these include ASR (Automated Sectionalisation and Restoration) to allow self-healing and fast load transfer, RF mesh and distributed sensors. d. The implementation of the new technology is contingent on the availability of contracting resources equipped and competent to install this equipment. The initiative is also strongly reliant on the ability of the various manufacturers to meet Unison s procurement timelines. e. Based upon detailed discussions with the contracting market there is confidence that both contractors within Unison s footprint will be able to upskill existing personnel or attract new skillsets to install and maintain the new equipment. Contractual commitments from equipment suppliers suggest that procurement will proceed on time. Slippage in implementation timeframes will result in a delay to the realisation of the benefits of the Smart Grid initiative.

350 APPENDIX B REQUIREMENT 7(2) B Assumption 11. Accuracy of presently utilised condition assessment techniques (Section 6) a. Unison uses a number of asset condition assessment techniques in order to understand the nature of its asset base. Robustness of data derived from condition assessment techniques is vital to the lifecycle asset management planning process and expenditure forecasting. b. No changes are proposed. c. This assumption has been made on the basis that the condition assessment techniques employed represent industry best practice and the fact that the different techniques utilised validate each other. d. A material difference may occur if a failure mode of a particular class of asset is unable to be detected by present condition assessment techniques. This may lead to unanticipated reactive network expenditure. e. Given the experience of Unison s condition assessment team, as well as the rigor of the techniques employed, it is thought that the sources of uncertainty are very minor. To mitigate uncertainty, budget provisions for reactive maintenance are included in forecasts Assumption 12. ODV asset standard lives represent a good starting point for assessing renewal expenditure requirements (Section 6) a. Unison s Renewal Envelope (RE, Section 6.3.1) is one of the tools used to assess Unisons renewal expenditure requirements over the planning period. Currently, in the absence of quality inspection data across the entire network, ODV standard lives inform the tool. b. As Unison s asset inspection data matures, and smart network technologies with diagnostic capabilities are deployed this assumption will become less influential. c. ODV standard lives are incorporated into modelling from the ODV Handbook d. Standard lives are idealised figures and do not take into account operating conditions specific to Unison s environment and network configuration. They may therefore understate or overstate the engineering life of the asset base. e. Unison has sought modification of a number of standard lives for its asset base. These modifications were validated by external experts and were notified to the Commerce Commission through the 2004 ODV process and the 2006 administrative settlement process. The remaining uncertainty has the potential to alter Unison s renewal expenditure forecasts Assumption 13. Quantification of WACC used in Renewal Envelope (Section 6) a. Unison s long term cost of capital is assumed to be 8.5% (nominal, post tax) for the purposes of calculating its renewal expenditure forecast. b. No changes are proposed. c. The cost of debt, the cost of equity capital and the corporate tax rate are principal sources of information. d. The cost of capital can vary significantly over time.

351 B-8 APPENDIX B REQUIREMENT 7(2) e. A higher cost of capital implies that the RE will defer replacement of assets, since the benefit of avoiding reactive costs is discounted at a higher rate Assumption 14. Expenditure forecast as published in the AMP (Section 9) a. Unison s expenditure forecast is built up using a number of tools and models, each of which are reliant on quality of data. b. No changes are proposed. c. Principle information sources used to create expenditure forecast are: asset data (age, remaining life, and condition), network simulation outputs, load forecast, regulatory requirements and fault data. d. Variances in factors driving expenditure forecast, as discussed above. e. Material changes to the expenditure forecast can be expected if factors driving the forecast change significantly between Asset Management Plan disclosures.

352

353

354 UNISON NETWORKS LIMITED 1101 Omahu Road PO Box 555 Hastings 4156 P F