Asset Management Plan 2012-22 Front Cover: Unison - lighting the Rotorua Night Market Unison Networks Limited | Asset Management Plan 2012-22
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 2012 to 31 March 2022. The AMP is reviewed each year and a revised AMP is expected to be available for public disclosure by 1 April 2013.
© UNISON NETWORKS LIMITED 2012
1 SUMMARY OF THE PLAN
Communications enabled 11kV ENTEC switches form a vital part of Unison’s automated sectionalisation and restoration programme. Communications enabled 11kV ENTEC switches form a vital part of Unison’s SUMMARY OF THE PLAN OF 1 SUMMARY SECTION
SECTION 1 SUMMARY OF THE PLAN 1-1 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
1 Summary ...... 1-2
1.1 Company Profile ...... 1-2 1.1.1 Overview ...... 1-2 1.1.2 Corporate Goals ...... 1-2 1.1.3 Ownership and Governance ...... 1-2 1.1.4 Electricity Distribution Network ...... 1-2 1.1.5 Unison Fibre Limited ...... 1-3 1.1.6 Contracting Services ...... 1-4 1.1.7 ETEL Limited ...... 1-4 1.1.8 Facilities Management ...... 1-4
1.2 Asset Management Plan Structure ...... 1-4 1.2.1 Background and Objectives ...... 1-4 1.2.2 Assets Covered ...... 1-5 1.2.3 Service Levels ...... 1-5 1.2.4 Network Development Planning ...... 1-5 1.2.5 Lifecycle Asset Management Planning...... 1-6 1.2.6 Risk Management ...... 1-6 1.2.7 Evaluation of Performance ...... 1-7 1.2.8 Expenditure Forecasts and Reconciliation ...... 1-7 1.2.9 Appendix A: Glossary of Terms ...... 1-7 1.2.10 Appendix B: Assumptions in Asset Management Planning ...... 1-7
1.3 Key Stakeholder Information ...... 1-8 1.3.1 Customer Service Levels ...... 1-8 1.3.2 Major Projects to Improve Customer Service ...... 1-10 1.3.3 Overhead to Underground Conversion Projects ...... 1-12 1.3.4 Stakeholder Feedback ...... 1-13
1.4 Financial Summary of Asset Expenditure and Reconciliation ...... 1-14
Table 1-1: Unison network according to key industry metrics ...... 1-3 Table 1-2: Summary of Unison's consumer oriented service targets ...... 1-9 Table 1-3: Summary of Unison’s asset and business oriented performance targets ...... 1-9 Table 1-4: Major projects to improve customer service ...... 1-12 Table 1-5: HBPCT OHUG programme 2012/13 ...... 1-12
1-2 SECTION 1 SUMMARY OF THE PLAN UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
1 Summary
1.1 Company Profile
1.1.1 Overview Unison Networks Limited (‘Unison') and its subsidiaries (together ‘the Group’) provide electricity distribution and line function services to consumers and businesses, as well as fibre optic network interconnections and related services throughout the Hawke’s Bay, Rotorua and Taupo regions. The Group also provides electrical, fibre, civil and vegetation contracting services and manufactures electrical products for the Australia, Pacific and New Zealand markets.
1.1.2 Corporate Goals Unison’s key corporate goals are published in its Statement of Corporate Intent and are provided below. 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”
These goals are critically relevant to the approach Unison takes to the lifecycle management of its asset base.
1.1.3 Ownership and Governance The Unison Group is wholly owned by the Hawke’s Bay Power Consumers’ Trust (HBPCT) on behalf of Hawke’s Bay electricity consumers. The Unison Group’s Board of Directors are appointed by the HBPCT.
1.1.4 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 provided at 33kV from Transpower’s grid exit points (GXP) and is connected 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 are involved in delivering this service.
The Unison network is comprised of over $420m worth of assets, is 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.
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The following table provides further information on the Unison network according to key industry metrics.
Metric Description Value 2010/11 Five Year Financial Year Trend
Consumers Total installation control points (ICP) connected to the network. 108,978 connected System length Total length of all energised circuits. 9,610km Sub-transmission Total length of all energised 33kV circuits. 446km system length Distribution system Total length of all energised 11kV circuits. 4,451km length Low voltage system Total length of all energised LV circuits. 4,584km length Percentage The proportion of total system length that is undergrounded. 39% - underground Asset value Unison’s Regulatory Asset Base. $477m Faults per 100km Average number of unplanned interruptions per 100km of high 7.6 voltage circuits per annum. SAIDI System Average Interruption Duration Index. A measure of the 128.0 minutes number of minutes per year the average consumer is without (147.9) electricity supply. (Regulatory limit in parentheses). SAIFI System Average Interruption Frequency Index. A measure of the 1.83 interruptions number of interruptions per year that affect the average consumer. (2.70) (Regulatory limit in parentheses). Electricity supplied Electricity entering system for supply to consumers. 1,678GWh Loss factor Proportion of electricity lost on the high voltage network. 5.3% Capacity utilisation Maximum demand on distribution transformers as a proportion of 28.2% installed capacity.
Table 1-1: Unison network according to key industry metrics
Unison Networks Limited is comprised of five business groups: Commercial, Corporate Services, Information Management, Networks and Operations, and Business Assurance. Networks and Operations is the business area 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 trade-offs that exist between these business areas and drivers are considered in more detail in Section 2.1.2.
1.1.5 Unison Fibre Limited Unison Fibre Limited is a wholly owned subsidiary of Unison. It provides fibre optic services to Unison for connecting zone substations and operational sites, and metro-fibre for external customers. UnisonFibre has a comprehensive fibre network deployed in Hastings and Napier with a backbone connecting the two cities. Backbone infrastructure has been deployed in both Rotorua and Taupo.
1-4 SECTION 1 SUMMARY OF THE PLAN UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
1.1.6 Contracting Services Unison Contracting Services Limited (UCSL) is a wholly owned subsidiary of Unison. UCSL provides a comprehensive range of contracting services to Unison and UnisonFibre in all regions, as well as to other electricity distribution businesses. UCSL has depots located in Hawke’s Bay, Rotorua and Taupo.
1.1.7 ETEL Limited ETEL Ltd is wholly owned by Unison. ETEL is a leading manufacturer of electricity distribution equipment and produces a range of transformers for the New Zealand and Australian markets.
1.1.8 Facilities Management Since October 2002, Unison has provided facility management services to Centralines - the EDB that supplies electricity consumers in Central Hawke’s Bay. The facilities management service includes asset management, network planning, design and operation of the control room.
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.
1.2.1 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 Description Section 2.3.5 Learning’s from the Smart Grid strategy that led to the establishment of a strategic initiative to entrench lifecycle asset management (LCAM) as the operating philosophy and modus operandi of Unison Ltd has been included. Section 2.7.1.2 Change of asset management system. Unison has moved from WASP to ACTIVA as its primary asset management system.
SECTION 1 SUMMARY OF THE PLAN 1-5 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
1.2.2 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:
Section Changed Description - No material changes.
1.2.3 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 Section 4.3.2 A service level based on the FAIDI metric has been added and will come into effect from 2013. The service level will monitor the performance of Unison’s 11kV feeders over time and show improving or declining performance. Section 4.5.1 The business efficiency targets have been revised to include both a industry median and a budget target as well as actual performance. These inclusions add transparency to the calculation of the targets and ensure the targets reflect industry best practice while aligning with Unison fiscal commitments. Section 4.6 Justification for service level targets has been revised to enhance the clarity of the role that benchmarking plays in determining suitable targets.
1.2.4 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. Tools 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.
1-6 SECTION 1 SUMMARY OF THE PLAN UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Changes made in the Network Development Planning section since the previous disclosure:
Section Changed Description Section 5.3.1 The load forecast tool diagram and explanation have been modified and expanded. Section 5.3.2 Updated to include Trustpower’s Esk hydro scheme in Hawke’s Bay. Section 5.3.3 Further explanation of how uncertain loads have been addressed in the load forecast has been added. The potential impact technology uncertainties i.e. MDG, PEVs and energy storage will have on the network has been Section 5.3.4 included. Section 5.3.8 Removed Ohaaki from the graph showing GXP Load Forecasts. Section 5.3.9 Changed graph to include Ohaaki as a zone substation. Section 5.4 A summary of the impact and benefit of distributed generation has been added. Section 5.5 Updated to reflect the latest equipment, concepts, and progress for the roll out of the smart network.
1.2.5 Lifecycle Asset Management Planning The Lifecycle 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 Lifecycle Asset Management Planning section since the previous disclosure:
Section Changed Description Section 6.3 This section provides an update on the rollout of non network (smart grid) solutions. The various technologies are discussed with an update on the phased rollout.
1.2.6 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 Description Section 7.3.1 Change to Unison’s internal responsibility for the Facilitation of the risk management framework. Section 7.3.3.2 Change to reflect the use of Quantate software to manage the LCP. Section 7.3.3.3 Information update to reflect the current status of the Public Safety Management System. Section 7.9.2 Graphical representation of LTIFR revised. Section 7.9.2.1 Section updated to reflect current benchmarks and targets. Section 7.9.2.8 Update on the development of the electrical safety DVD.
SECTION 1 SUMMARY OF THE PLAN 1-7 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
1.2.7 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.
1.2.8 Expenditure Forecasts and Reconciliation Unison’s expenditure forecasts and reconciliation 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:
Section Changed Description - No material changes.
1.2.9 Appendix A: Glossary of Terms Appendix A provides a glossary of terms used in the AMP.
1.2.10 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 Description Appendix B 1.14 Assumptions relating to the creation of expenditure forecasts have been more comprehensively articulated to provide an indication of the materiality of these assumptions.
1-8 SECTION 1 SUMMARY OF THE PLAN UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
1.3 Key Stakeholder Information Unison firmly believes 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 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 Hawke’s Bay. To this end, this section provides an executive summary of these three areas. Under each sub-heading a reference to the more detailed discussion later in the plan is provided.
1.3.1 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:
1.3.1.1 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 Performance Targets is provided in section 4.3. Evaluation of performance against targets for the previous year is provided in Section 8.
The 2012 AMP sees the inclusion of the ‘FAIDI’ service level. This service level is discussed in detail in section 4.3.2.
SECTION 1 SUMMARY OF THE PLAN 1-9 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Service Standard Measure Target SAIDI System Average Interruption Duration Index. A 2011-2015: < 147.9 minutes measure of the number of minutes per year the average consumer is without electricity supply. SAIFI System Average Interruption Frequency Index. A 2011-2015: < 2.70 interruptions measure of the number of interruptions per year that affect the average consumer. FAIDI Sum of residual (excess) FAIDI for feeders above Monitor performance across years and provide threshold. explanation for significant change in performance. Interruptions occurring in Length of time before supply is restored following an Maximum of twenty events to exceed three urban areas unplanned interruption. hours before supply is restored per annum. Interruptions occurring in Number of unplanned interruptions per annum. Maximum of one feeder to exceed four urban areas unplanned interruptions per annum. Interruptions occurring in Length of time before supply is restored following an Maximum of ten events to exceed six hours rural areas unplanned interruption. before supply is restored per annum. Interruptions occurring in Number of unplanned interruptions per annum. Maximum of one feeder to exceed ten rural areas unplanned interruptions per annum. Interruptions occurring in Length of time before supply is restored following an Maximum of five events to exceed six hours remote rural areas unplanned interruption. before supply is restored per annum. Interruptions occurring in Number of unplanned interruptions per annum. Maximum of one feeder to exceed twenty remote rural areas unplanned interruptions per annum.
Table 1-2: Summary of Unison's consumer oriented service targets
1.3.1.2 Asset and Business Efficiency Service Levels 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 Efficiency Service Levels is provided in Section 4.5.
Evaluation of performance against targets for the previous year is provided in Section 8. Table 1-3 below summarises Unison’s Asset and Business Efficiency Service Levels:
Service Standard Measure Target Total cost per ICP Total direct and indirect cost per electricity consumer <$286 Total cost per km Total direct and indirect cost per circuit km <$3,052 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 <8.0 faults per 100km
Table 1-3: Summary of Unison’s asset and business oriented performance targets
1-10 SECTION 1 SUMMARY OF THE PLAN UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
1.3.2 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).
1.3.2.1 Smart Grid The smart grid is the electricity network of the future, representing the confluence of intelligent network assets, two-way communications and advanced software applications. It is the electricity industry’s response to global change drivers which include:
Drive for carbon neutrality;
Reduction in dependence on increasingly scarce fossil fuels for the generation of electricity;
Replacing base-load fossil fuel generation with intermittent renewable generation;
Emergence of micro distributed generation and the ‘producer-consumer’;
Energy policy focus on energy efficiency;
New forms of electrical demand, such as electric vehicles.
The smart grid provides the means for progressive electricity utilities to respond to these drivers, but this will require significant investment and innovation at a time where existing infrastructure is reaching the end of its life. The step changes in terms of asset management practices, utilisation of new technology and engagement with the customer are major challenges facing the industry.
Unison is actively deploying smart network technologies as part of its Smart Grid Initiative. The Initiative will significantly improve the business’ ability to provide a high quality customer service. This means improving quality of supply, reducing the frequency and duration of outages and providing customers with additional real-time information relating to their electricity connection. A number of the projects that are itemised in Table 1-4 have been initiated as part of the Smart Grid Initiative.
1.3.2.2 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.
SECTION 1 SUMMARY OF THE PLAN 1-11 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Project Name Description Completion Year New power transformer at Windsor loads have grown to the extent that the 11kV network cannot back feed 2012 Windsor zone substation 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. Taupo fast transfer scheme This project utilises automated switches (overhead and ground mounted) to quickly 2013 transfer load between zone substations using the 11kV network. Taupo self healing scheme This project builds on the fast transfer scheme with the addition of a substantial 2013 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. Install voltage regulators on Voltage regulation on these feeders is below Unison’s standards. Voltage 2013 Kaharoa, Mamaku, Otamauri, regulators are a cost-effective way to address voltage regulation problems on high Puketitiri and Waikato feeders voltage feeders.
New sub-transmission circuit The introduction of a new sub-transmission circuit between Ohaaki and Fernleaf 2014 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. Establish a zone substation at Substantial dairy conversion is expected within the planning period in the vicinity of 2014 Te Toki 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. Install Powersense sensors to This technology uses state of the art current sensors to provide accurate current, Ongoing aid fault finding and voltage and fault passage information in real time over the mesh radio network restoration back to Unison’s information management systems. This will enable Unison to expedite the location and isolation of faults thus reducing customer outage times. Deployment of ENTEC The Smart Grid rollout will focus on the deployment of automated ENTEC switches Ongoing switches in Rotorua and to replace existing manually operated air break switches (ABS). The ENTEC Taupo 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. Establish a zone substation at High industrial load is forecast for the southern outskirts of Rotorua. A constraint Timing determined State Mill Road, Rotorua arises early in the planning period, meaning a significant upgrade of the network by customer will be required. The optimal solution is to establish a new zone substation. This requirements will also increase the security of supply in the area. Self healing trial, Hawke’s Bay The trial of self healing networks commenced in 2010/11. This technology, Complete complemented by automated switches, was aimed at optimising load shifting, managing network constraints and reducing outage occurrence and duration. Replace distribution fusing Ongaroto feeder is a remote 11kV circuit with reliability issues, predominately Complete with ENTEC switches on related to vegetation and extreme weather events. Deployment of the ENTEC Ongaroto feeder, Taupo switch in place of distribution dropout fuses (DDO) was selected as the optimal solution. Installation of feeder current Protection relays operate to minimise the damage to assets in the event of a fault. Complete differential protection relays in Relays with differential protection enhance this capability by reducing the risk of Taupo 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.
1-12 SECTION 1 SUMMARY OF THE PLAN UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Project Name Description Completion Year Fault Passage Indicator (FPI) FPIs are portable devices used to determine the location of faults on overhead Complete networks. The deployment of FPIs on the network will enable Unison to quickly identify transient faults, reducing recurrence. Ground Fault Neutraliser The GFN reduces the amount of electrical arcing in the event of an earth fault, Complete (GFN), Irongate zone decreasing the risk of electrocution and fire. It will also enable Unison to maintain substation 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. Capacitor bank trial, Hawke’s Capacitor banks provide a cost effective alternative to improving feeder capacity Complete Bay 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.
Table 1-4: Major projects to improve customer service
1.3.3 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 2012/13.
Project Name Description Indicative Cost Francis Hicks Avenue & Phase 1 Section from Townshend Street to Pepper Street. $307,000 of Townshend Hillary Crescent Section from Lodge Road to Bledisloe Road. $295,000 Richmond Street Full length. $459,000 Sussex Street Full length. $410,000 Mayfair Avenue Full length. $368,000
Table 1-5: HBPCT OHUG programme 2012/13
SECTION 1 SUMMARY OF THE PLAN 1-13 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
1.3.4 Stakeholder Feedback 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 Networks Limited
1101 Omahu Road PO Box 555 Hastings 4156 New Zealand
1-14 SECTION 1 SUMMARY OF THE PLAN UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
1.4 Financial Summary of Asset Expenditure and Reconciliation
SECTION 1 SUMMARY OF THE PLAN 1-15 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Expenditure and Reconciliation
2 BACKGROUND & OBJECTIVES
Smart Network Engineer Jennifer Wen discusses the decision rules guiding smart network asset deployment with Network Strategy Wen Smart Network Engineer Jennifer Analyst Josh Lloyd. BACKGROUND & OBJECTIVES 2 BACKGROUND SECTION
SECTION 2 BACKGROUND AND OBJECTIVES 2-1 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
2 Background and Objectives ...... 2-3
2.1 Purpose ...... 2-3 2.1.1 Purpose of the Asset Management Plan ...... 2-3 2.1.2 Objectives of Asset Management Planning ...... 2-3
2.2 Relationship with Other Business Plans and Goals ...... 2-4 2.2.1 Mission and Vision Statements as they relate to Asset Management ...... 2-4 2.2.2 Documented Plans Produced in Annual Planning Process ...... 2-5 2.2.3 Relationships between Plans, Processes, Models and Stakeholders ...... 2-7
2.3 Smart Grid Initiative ...... 2-8 2.3.1 Background and Purpose ...... 2-8 2.3.2 Objective ...... 2-8 2.3.3 A Definition of Smart Grid ...... 2-9 2.3.4 Network Benefits ...... 2-9
2.4 Period Covered by the Plan ...... 2-10
2.5 Stakeholders’ Interests ...... 2-10 2.5.1 Identification of Stakeholder Interests ...... 2-10 2.5.2 Accommodation of Interests into Asset Management Planning ...... 2-12 2.5.3 Conflict Resolution ...... 2-12
2.6 Accountabilities and Responsibilities ...... 2-13
2.7 Asset Management Systems and Processes ...... 2-15 2.7.1 Managing Routine Asset Inspections and Network Maintenance ...... 2-15 2.7.2 Planning and Implementation of Network Development Projects ...... 2-22 2.7.3 Measuring Network Performance for Disclosure Purposes ...... 2-25
2-2 SECTION 2 BACKGROUND AND OBJECTIVES UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Figure 2-1: Competing Drivers ...... 2-3 Figure 2-2: Information flows in Unison’s asset management and business planning processes ...... 2-7 Figure 2-3: The Smart Grid Initiative ...... 2-8 Figure 2-4: Responsibilities for asset management at Unison ...... 2-13 Figure 2-5: Managing routine asset inspections and network maintenance ...... 2-16 Figure 2-6: Examples of substation internals within Unison's GIS ...... 2-19 Figure 2-7: Planning process ...... 2-22 Figure 2-8: Process for measuring and analysing network performance ...... 2-25 Figure 2-9: Call & dispatch geographic view ...... 2-27 Figure 2-10: Call & dispatch detail map view ...... 2-27
Table 2-1: Relationship between AMP and other documented plans ...... 2-6 Table 2-2: High Level Benefits of Smart Grid Initiative ...... 2-9 Table 2-3: Twelve Stated Network Benefits of the Smart Grid Initiative ...... 2-10 Table 2-4: Stakeholders' key interests ...... 2-12
SECTION 2 BACKGROUND AND OBJECTIVES 2-3 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
2 Background and Objectives
2.1 Purpose
2.1.1 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 to 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 2004.
2.1.2 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 trade-off 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.
Financial Sustainability Network CAPEX Asset maintenance Business indirect costs Customer Experience Regulatory Compliance Customer service Default Price Path (DPP) Quality of supply Disclosure requirements Customised service offerings H&S and environmental
Optimal Asset Management Planning
Figure 2-1: Competing Drivers 2-4 SECTION 2 BACKGROUND AND OBJECTIVES UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
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.
2.2.1 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 SECTION 2 BACKGROUND AND OBJECTIVES 2-5 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
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 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.
2.2.2 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 Unison’s SCI is published annually and approved The AMP describes the ways in which the goals (SCI) by the Hawke’s Bay Power Consumers’ Trust and objectives embodied in the SCI will be (HBPCT) on behalf of shareholders. The SCI achieved from an asset management sets out key goals and objectives for the business perspective. and includes the Vision and Mission statements (Section 2.2.1).
Business Plan (CAPEX & OPEX The Business Plan sets annual goals, objectives A subset of the key performance indicators Forecasts) and key performance indicators for the business. published in the Business Plan is adopted into It also contains expenditure forecasts for approval the published AMP (Section 4). The expenditure by the Board of Directors. forecasts published in the AMP are based upon the forecasts approved annually by the Board of Directors within the Business Plan.
Smart Grid Project Management This document provides a comprehensive The SG PMP is a critical input to the 2012 AMP Plan (SG PMP) strategic roadmap for the deployment of new and will be continue to be important in technology (including distribution assets, subsequent AMP publications, as smart grid communications and demand side management concepts continue to shape Unison’s asset devices) , the development of data management management practices. 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.
Network Development Plan A key output of the Network Planning Team is the The Network Development Plan is drawn upon to Network Development Plan. This document complete Section 5 of the AMP. The Network provides the long term view of how the network Development Plan is a critical input into the risk will look at intervals through the planning period management framework Unison operates, and of twenty years. The Network Development Plan therefore Section 7 of the AMP. also considers the impact that energy use changes will have on the Unison network based upon scenario planning. An example of this is electric vehicle uptake. 2-6 SECTION 2 BACKGROUND AND OBJECTIVES UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Name of Planning Document Description Relationship with AMP
Contracting Framework The Contracting Framework is Unison’s strategy The expenditure forecasts that are produced for for having works built, upgraded and maintained the Business Plan and are adopted by the AMP by the contracting market. Key objectives of the are checked for consistency with the Contracting Contracting Framework are competitive Framework. outcomes, contractor efficiency and quality workmanship.
Risk Register The Risk Register is a live database that is used Risks related to asset management within the to document key business risks. Risk mitigation Risk Register inform Section 7 of the AMP. strategies are reviewed annually.
Environmental Management Plan The EMP is a set of planning documents that The EMP informs Section 7 of the AMP. (EMP) manage environmental outcomes on the Unison network. The plan includes guidelines on environmental best practice, management of hazardous substances and the environmental audit regime.
Health and Safety Management The HSMP defines health and safety protocol on The HSMP informs Section 7 of the AMP. Plan (HSMP) the Unison network.
Table 2-1: Relationship between AMP and other documented plans
SECTION 2 BACKGROUND AND OBJECTIVES 2-7 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
2.2.3 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.
Figure 2-2: Information flows in Unison’s asset management and business planning processes
2-8 SECTION 2 BACKGROUND AND OBJECTIVES UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
2.3 Smart Grid Initiative Unison’s Smart Grid Initiative is an important piece of background to this Asset Management Plan. 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 this broader strategy.
2.3.1 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 improve the efficiency of Unison’s business model, enhance asset management and empower the customer. Figure 2-3 shows the key elements of Unison’s Smart Grid Initiative.
Ubiquitous Communication Platform
Asset Management and Enterprise Information Systems
Data Management and Decision Support
Figure 2-3: The Smart Grid Initiative
2.3.2 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. Importantly in the asset management context, the Smart Grid Initiative provides the means for Unison to greatly enhance its knowledge about its assets. Improved knowledge is an enabler for better lifecycle asset management decision making.
SECTION 2 BACKGROUND AND OBJECTIVES 2-9 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
2.3.3 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.
2.3.4 Network Benefits The Smart Grid Initiative has been designed to deliver benefits 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
CAPEX deferral (where supported by network information). Reduction in network expenditure Optimisation of maintenance expenditure.
Enhanced network performance. Improvement in customer service Improved power quality. Customised service offerings.
Health and safety. Safer and more sustainable network 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 2-10 SECTION 2 BACKGROUND AND OBJECTIVES UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Twelve Stated Benefits
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
2.4 Period Covered by the Plan This AMP covers a period of 10 years from 1 April 2012 to 31 March 2022. 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 23 March 2012.
2.5 Stakeholders’ Interests
2.5.1 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 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. 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 entering its fourth year as the major sponsor of Hawke’s Bay Junior Rugby. Unisons sponsorship aims to help grow the game locally by supporting rugby at a grass roots level. Unison will be providing Junior rugby players with a goodie bag, as well as supplying clubs and coaches with key equipment. The popular Unison Medal will again recognise players who have consistently shown great work ethic, discipline and sportsmanship.
Unison’s key stakeholders, the methods used to identify their interests, and the interests themselves are itemised in Table 2-4 below.
SECTION 2 BACKGROUND AND OBJECTIVES 2-11 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Stakeholder Method of Identifying Stakeholder Interests Key Interests
Consumers Consumer satisfaction surveys and other Price (line charges) research initiatives Quality of supply Areas of the business that deal directly with Public health and safety individual consumers (e.g. New Connection policies Connections and Control Room) Customer contribution policy Use of System Agreement with retailer Overhead to underground conversion programme Participation in the local communities served
Contractors Relationship management meetings Continuity of work Monthly coordination meetings Contractual relationship Contractor health and safety meetings. Health and safety in the workplace Contracting Framework (works planning Construction, operating and maintenance process) standards Contracts
Councils Coordination meetings Environmental impact (compliance with RMA, Strategic meetings District/Regional Plan, HSNO) Hearings and submissions Development of local economy Public health and safety Overhead to underground conversion programme
Property developers Site meetings Timeliness of network connection Liaison through New Connections Team Overhead to underground conversion programme Connection policies Customer contribution policy
Employees Internal communications Workplace health and safety Employee satisfaction survey Positive, professional working environment Performance appraisals Competitive remuneration
Energy retailers Use of System Agreement Contractual relationship Price (line charges) Quality of supply
Equipment and material Meetings between Unison’s Networks and Ongoing custom vendors and manufacturers Operations Team, Store personnel and View of forward order book sales representatives
Regulatory bodies Submissions Statutory obligations Contract Relationship between price and quality Relationship meetings Economic efficiency Information disclosure
Interest groups and Consultation Relationship between price and quality community groups Community participation
Large consumers (see Regular relationship meetings Connection policies Section 3) Contract Price (line charges) 2-12 SECTION 2 BACKGROUND AND OBJECTIVES UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Stakeholder Method of Identifying Stakeholder Interests Key Interests Security of supply Quality of supply Safety
Landowners Consultation Property values Amenity value
Media Media strategy News and public relations Communications Team Alternative energy sources Environmental issues Crisis management
Other utilities Site meetings Asset locating services Relationship meetings Opportunities for collocation of assets Benchmarking
Shareholders (HBPCT) Regular meetings with Board’ Return on investment Statement of Corporate Intent OHUG AGM Community representation
Transpower (Grid and Regular communication between planning Network development requirements System Operator) departments Real-time operation Regular communication between system operators Transpower’s Annual Planning Report Unison Board of Directors Regular meetings with the Executive Shareholders’ interests (value, quality of Management Team supply, community participation) Statutory obligations Growing the business
Table 2-4: Stakeholders' key interests
2.5.2 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.
2.5.3 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: SECTION 2 BACKGROUND AND OBJECTIVES 2-13 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Statutory/legal compliance, health and safety;
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.
2.5.3.1 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 the Group 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 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:
Figure 2-4: Responsibilities for asset management at Unison 2-14 SECTION 2 BACKGROUND AND OBJECTIVES UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
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, Network Planning Manager, Smart Networks Manager and Network Strategy Manager
The Asset Manager is responsible for the overall coordination of lifecycle asset management at Unison.
The Network 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 Networks 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 Business Assurance Provides a regulatory context for Asset Management planning and lobbies for changes to the regulatory environment as it applies to Asset Management. The Business Assurance Group is also responsible for risk and environmental management.
Chief Financial Officer Responsible for providing a fiscally sustainable level of network investment, material procurement and the provision of financial reporting where required on Asset Management outcomes. These responsibilities are further delegated to the Financial Controller and Supply Manager. Unison operates a store and materials are provided to contractors on a free issue basis.
Chief Executive UCSL In the Asset Management sphere, the Chief Executive UCSL is responsible for delivery of designs for works and delivery of the capital and maintenance works programmes. These responsibilities are further delegated to the General Manager Operations.
General Manager Commercial The General Manager Commercial is the executive manager who represents the interests of the customer and other stakeholders in the asset management planning process. These interests are considered in all parts of the process, but are most prominent in Section 4, Service Levels.
General Manager Information Management The General Manager Information Management is the executive manager responsible for the provision of the appropriate systems, data respositories and processes to enable asset management. Information management is seen as an essential part of lifecycle asset management and will continue to grow in importance at Unison as the Smart Grid Initiative continues. SECTION 2 BACKGROUND AND OBJECTIVES 2-15 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
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.
2.7.1 Managing Routine Asset Inspections and Network Maintenance
2.7.1.1 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 moving from IPAQ based PDA devices to Windows Mobile 7 Devices supported by Kern mobile 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.
2-16 SECTION 2 BACKGROUND AND OBJECTIVES UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Asset
Inspection frequency Inspection prioritisation RE run according to economics informed by asset risk profile annually / risk trade‐off
Inspection RE Asset Benefit:Cost Condition ratio of OK renewal less than 1
Asset condition Asset RLE informed by Benefit:Cost not satisfactory condition assessment Ratio of renewal exceeds 1 Triple ‐ R
Asset remains in Repair Refurbish Renew Asset remains in service service
Maintenance Investment Prioritisation Tool Plan (IPT)
Operational Capital Expenditure Plan Expenditure Plan
Figure 2-5: Managing routine asset inspections and network maintenance
2.7.1.2 Key Systems
ACTIVA Unison’s Asset Management System is ACTIVA. ACTIVA is based on the BASIX platform supplied by EMS, the providers of Unisons previous Asset Management system WASP. The ACTIVA asset register is the main repository for asset data and stores both current attributes as well as historical information. The asset data that ACTIVA masters is available for viewing by the GIS thus providing consistency of information. ACTIVA 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. SECTION 2 BACKGROUND AND OBJECTIVES 2-17 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Unison also uses ACTIVA to provide works management. This integrates with the Asset Management module of ACTIVA allowing the recording of actions against Assets as an inherent part of the works project.
Key functions supported are:
Project Workflow
Project estimation;
Work pack creation;
Job costing;
Work task creation.
MOS MOS (Management Operating System) is based on Microsoft’s Project Server product, integrated with both ACTIVA and SharePoint (for project documentation)
The MOS provides programme management with scheduling of resource across the project. 2-18 SECTION 2 BACKGROUND AND OBJECTIVES UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
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 KERN Mobile solutions, utilising Windows Mobile 7 devices for field use and is interfaced with the ACTIVA 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.
Inspection Types include:
Pole Testing;
Earth Testing (2012);
Pedestals (2012);
Ground Mounted (2012).
Inspection types and other mobile applications are being expanded onto the new platform through 2012.
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. SECTION 2 BACKGROUND AND OBJECTIVES 2-19 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
To support the management of the Communications Fibre infrastructure Unison implemented GE’s Physical Network Infrastructure (PNI) module October 2010.
Figure 2-6: 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.
2-20 SECTION 2 BACKGROUND AND OBJECTIVES UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
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.
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.
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.
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 6.4.7.
2.7.1.3 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.
2.7.1.4 Data Quality Improvement Initiatives Exception reports are run on a regular basis and identify differences in the data between the GIS and ACTIVA (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. SECTION 2 BACKGROUND AND OBJECTIVES 2-21 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
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.
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.
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. The introduction of Smart Technologies allows analysis of actual connectivity against systems connectivity, which will provide the ability to reconcile and correct errors in recorded connectivity. 2-22 SECTION 2 BACKGROUND AND OBJECTIVES UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
2.7.2 Planning and Implementation of Network Development Projects
2.7.2.1 Process
Pro j Project ect List Inputs Project Drivers Project Options Selection
Load Forecast and Network Network Augmentation Network Security capacity Strengthening Envelope Criteria determination Solutions Capacity Headroom Network Non Network
Performance Large Customer Solutions Risk Assessment Database Needs Do Nothing Network Sensors Quality of Supply
Network Reliability (Risk Assessment of Investment Prioritisation Option selected) Operational Tool Constraints
Figure 2-7: Planning process
2.7.2.2 Key Systems
Geo-Spatial Information System (GIS) As provided in 2.7.1.2.
ACTIVA ACTIVA provides a formal project management process, with formal workflow and escalation points. This provides a greater level of visibility of project progress, costs and asset creation. Project milestones and finances are managed through this system.
Plant Information (PI) System As provided in 2.6.1.2.
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.
SECTION 2 BACKGROUND AND OBJECTIVES 2-23 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
DIgSILENT Power Factory Power Factory 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.
There is a data interface between Power Factory and GE SmallWorld GIS to ensure alignment of the source data for network planning and power flow analysis. The basis for the data extracts is the 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.
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; 2-24 SECTION 2 BACKGROUND AND OBJECTIVES UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
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.
2.7.2.3 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 ACTIVA and the GIS.
2.7.2.4 Data Quality Improvement Initiatives
Project Planning The introduction of ACTIVA and MOS 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.
SECTION 2 BACKGROUND AND OBJECTIVES 2-25 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
2.7.3 Measuring Network Performance for Disclosure Purposes
2.7.3.1 Process for Measuring and Analysing Network Performance
Information Flow Key Responsibilities
Locate fault Fault Response Service Provider Identify cause Report back to Control Room
Log all relevant fault data Control Room Measure consumer minutes lost
Feedback loop Extract data from faults database I.T. Reporting Systems Maintain and audit systems and data quality
Analyse fault data Network & Operations Produce reports for stakeholders Provide information for disclosure
Figure 2-8: Process for measuring and analysing network performance
2.7.3.2 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.
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.
2-26 SECTION 2 BACKGROUND AND OBJECTIVES UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
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. SECTION 2 BACKGROUND AND OBJECTIVES 2-27 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Figure 2-9: Call & dispatch geographic view
Figure 2-10: Call & dispatch detail map view
2-28 SECTION 2 BACKGROUND AND OBJECTIVES UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
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 2010.
Distribution Management System Part of Unison’s Smart Grid Initiative is to replace the existing SCADA system and the Control Room’s operational management systems with a new Advanced Distribution Management System (ADMS). This application is mission critical for the success of LCAM as it will enable operational information to be exposed to decision makers throughout the business. The ADMS will replace the following control room applications:
Realflex SCADA
TVD- Call and Dispatch
Fault Management System
Planned Outage Notification Database
Sensitive Customer Database
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).
SECTION 2 BACKGROUND AND OBJECTIVES 2-29 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
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 six years, and has completed a technology refresh on the SAN hardware over the last 12 months. This has provided added redundancy within the storage platform, and upgraded the hardware to current standards.
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.
2.7.3.3 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.
2.7.3.4 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.
3 ASSETS COVERED
ASSETS COVERED Weather stations are used to capture environmental information to help with loading calculations on overhead network assets. stations Weather SECTION 3 SECTION
SECTION 3 ASSETS COVERED 3-1 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
3 Assets Covered ...... 3-4
3.1 Distribution Area ...... 3-4 3.1.1 Areas Covered ...... 3-4 3.1.2 Unison’s Large Consumers ...... 3-4 3.1.3 Load Characteristics for Different Parts of the Network ...... 3-6 3.1.4 Peak Demand and Total Electricity Delivered ...... 3-8
3.2 Description of Network Assets ...... 3-8 3.2.1 Hawke’s Bay ...... 3-8 3.2.2 Rotorua ...... 3-14 3.2.3 Taupo ...... 3-18
3.3 Network Assets ...... 3-23 3.3.1 Overhead Lines ...... 3-23 3.3.2 Underground Cables ...... 3-25 3.3.3 Power Transformers ...... 3-27 3.3.4 Circuit Breakers ...... 3-29 3.3.5 Other Substation Equipment and Buildings ...... 3-31 3.3.6 Distribution Transformers and Voltage Regulators ...... 3-33 3.3.7 Distribution Switchgear ...... 3-34 3.3.8 Load Control Plant...... 3-38 3.3.9 Service Mains ...... 3-39 3.3.10 Miscellaneous Distribution Equipment ...... 3-39 3.3.11 SCADA Control and Communications ...... 3-41 3.3.12 Generation Plant ...... 3-43 3.3.13 Power Factor Correction Equipment and Metering Systems ...... 3-43
3.4 Justification for the Assets ...... 3-43 3.4.1 High Level Justification ...... 3-43 3.4.2 ODV Optimisation ...... 3-46 3.4.3 Sub-transmission Assets ...... 3-46 3.4.4 Zone Substation Assets ...... 3-46 3.4.5 11kV Distribution Assets ...... 3-46 3.4.6 Distribution Transformers/Substations ...... 3-47 3.4.7 Low Voltage ...... 3-47 3.4.8 SCADA, Communication and Control ...... 3-47
3-2 SECTION 3 ASSETS COVERED UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Figure 3-1: Unison electricity distribution coverage area ...... 3-4 Figure 3-2: Napier sub-transmission network ...... 3-9 Figure 3-3: Hastings sub-transmission network ...... 3-10 Figure 3-4: Hawke’s Bay region point of supply and 33kV sub-transmission ...... 3-11 Figure 3-5: Hawke’s Bay 11kV distribution system ...... 3-13 Figure 3-6: Rotorua region point of supply and 33kV sub-transmission ...... 3-15 Figure 3-7: Rotorua sub-transmission network ...... 3-16 Figure 3-8: Rotorua 11kV distribution system ...... 3-17 Figure 3-9: Taupo region point of supply and 33kV sub-transmission ...... 3-19 Figure 3-10: Taupo sub-transmission network ...... 3-20 Figure 3-11: Taupo 11kV distribution system ...... 3-22
Table 3-1: Unison’s large consumers ...... 3-6 Table 3-2: Load characteristics ...... 3-7 Table 3-3: Peak demand and total electricity delivered ...... 3-8 Table 3-4: Supply points and embedded generation in the Hawke’s Bay region ...... 3-8 Table 3-5: Zone substation capacity and security level in the Hawke’s Bay region ...... 3-12 Table 3-6: UG portion of 11kV and LV network in the Hawke’s Bay region ...... 3-14 Table 3-7: Supply points and embedded generation in the Rotorua region ...... 3-14 Table 3-8: Zone substation capacity and security level in the Rotorua region ...... 3-16 Table 3-9: UG portion of 11kV and LV network in the Rotorua region ...... 3-18 Table 3-10: Supply points and embedded generation in the Taupo region ...... 3-18 Table 3-11: Zone substation capacity and security level in the Taupo region ...... 3-21 Table 3-12: UG portion of 11kV and LV network in the Taupo region ...... 3-21 Table 3-13: Overhead lines quantities and valuations ...... 3-23 Table 3-14: Underground cables quantities and valuations ...... 3-26 Table 3-15: Power transformers quantities and valuations ...... 3-28 Table 3-16: Zone substations quantities and valuations ...... 3-29 Table 3-17: Distribution transformers quantities and valuations ...... 3-33 Table 3-18: Distribution switchgear quantities and valuations...... 3-36 Table 3-19: Load control plant quantities and valuations ...... 3-38 Table 3-20: Miscellaneous distribution equipment quantities and valuations ...... 3-40
SECTION 3 ASSETS COVERED 3-3 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Graph 3-1: Overhead lines ...... 3-23 Graph 3-2: Wooden poles ...... 3-25 Graph 3-3: Concrete poles ...... 3-25 Graph 3-4: Underground cables ...... 3-26 Graph 3-5: Power transformers update ...... 3-28 Graph 3-6: Zone substation circuit breakers ...... 3-30 Graph 3-7: Distribution transformers ...... 3-34 Graph 3-8: Overhead distribution switchgear ...... 3-36 Graph 3-9: Ring main switches ...... 3-37 Graph 3-10: Load control plant ...... 3-39 Graph 3-11: SAIDI Performance ...... 3-45 Graph 3-12: SAIFI Performance ...... 3-45
3-4 SECTION 3 ASSETS COVERED UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
3 Assets Covered
3.1 Distribution Area
3.1.1 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
3.1.2 Unison’s Large Consumers Large consumers are defined as consumers that either have a peak load of over 1MVA 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 0.95. Table 3-1 below identifies Unison’s large consumers.
SECTION 3 ASSETS COVERED 3-5 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Consumer GXP Zone Dedicated Impact on Network Operations and Asset Peak Load Substation Feeder Management Prioritisation (MVA) Alto Plastics Fernhill Irongate No The plant is sensitive to feeder faults, auto 1.1 recloses and surges beyond the connection point. Apollo Pac Whakatu Rangitane No The consumer is located in close proximity to the 2.7 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 3.6 peak periods to minimise interruptions to the business. Consumer owns all 11kV cables and switchgear within premises. Turners and Growers: Whakatu Rangitane No Any planned works will be conducted during off 2.6 Whakatu Site peak periods to minimise interruptions to the business. Consumer owns all 11kV cables and switchgear within the premises. Watties: Tomoana Whakatu Tomoana Yes The consumer has n-1 security of supply and 4.1 Site 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 5.3 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 5.1 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 4.1 the Bluff Hill zone substation. Unison owns all the 11kV assets on the site. Maintenance is conducted during off peak periods to minimise interruptions. Silver Fern Farms Whakatu Rangitane No Maintenance is conducted during off peak periods 3.1 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 3.7 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 2.2 to minimise interruptions. The 11kV cables within the premises are owned by the consumer.
3-6 SECTION 3 ASSETS COVERED UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Consumer GXP Zone Dedicated Impact on Network Operations and Asset Peak Load Substation Feeder Management Prioritisation (MVA) Hawke’s Bay Whakatu Rangitane Yes The consumer has n-1 security of supply and 2.6 Industrial Park 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 3.5 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. Tenon Wairakei Fletchers Yes Same as Laminex. 3.9 Fonterra Rotorua Fernleaf Yes The consumer is supplied by the Fernleaf substation 4.1 33kV 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. Red Stag Timber Ltd Rotorua Rotorua 11kV No Any planned works will be conducted during off 4.1 33kV 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. Tachikawa Forest Owhata Owhata No Any planned works will be conducted during off 2.3 Products(NZ) peak periods to minimise interruptions to the business. Unison owns the switchgear, transformers and 11kV cable feeding the customer.
Table 3-1: Unison’s large consumers
3.1.3 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 SECTION 3 ASSETS COVERED 3-7 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
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 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 region and major sporting events. There are currently 3 embedded generators injecting at 33kV. The installed capacity of these generators exceeds 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
3-8 SECTION 3 ASSETS COVERED UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
3.1.4 Peak Demand and Total Electricity Delivered Energy Supplied (GWh) Hawke’s Bay 978 Energy Supplied (GWh) Taupo 246 Energy Supplied (GWh) Rotorua 454 Peak Demand (MVA) Hastings (1) 144 Peak Demand (MVA) Napier (1) 65 Peak Demand (MVA) Taupo (1) (24) Peak Demand (MVA) Rotorua (1) 106 (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
3.2.1 Hawke’s Bay
3.2.1.1 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 2010/11Peak Demand (MVA) Firm Capacity Winter (MVA)(1) Fernhill 33kV GXP 50.77(3) 39 Ravensdown 11kV Embedded Generator 1.24 - Unison Generation Embedded Generator 0 (2) - Hawke’s Bay Hospital Embedded Generator 0.20 Redclyffe 33kV GXP 61.35(3) 43 Whakatu 33kV GXP 85.95(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
SECTION 3 ASSETS COVERED 3-9 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
3.2.1.2 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
Rangitane Whakatu GXP
Figure 3-2: Napier sub-transmission network 3-10 SECTION 3 ASSETS COVERED UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Maraekakaho Sherenden
Fernhill Redclyffe GXP
Fernhill GXP
McCain Rangitane Flaxmere
Irongate Camberley Whakatu GXP
Mahora Tomoana
Hastings Windsor
Havelock North Arataki
Figure 3-3: Hastings sub-transmission network
SECTION 3 ASSETS COVERED 3-11 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Legend
GXP Zone Substation Switching Station
Figure 3-4: Hawke’s Bay region point of supply and 33kV sub-transmission 3-12 SECTION 3 ASSETS COVERED UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
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-1 17.5 Awatoto 33kV n-1 24 Bluff Hill 33kV n 30 Camberley 33kV n-1 17.5 Church Road 33kV n-1 20.0 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 n1 10 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-12 40
Table 3-5: Zone substation capacity and security level in the Hawke’s Bay region
3.2.1.3 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 12MVA transformer at Maraekakaho is in progress. 2 We have installed a second power transformer at Windsor substation in 2011/12 SECTION 3 ASSETS COVERED 3-13 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Figure 3-5: Hawke’s Bay 11kV distribution system 3-14 SECTION 3 ASSETS COVERED UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
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) 16% 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
3.2.2 Rotorua
3.2.2.1 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 2010/11Peak Demand (MVA) Firm Capacity (MVA)(1) Atiamuri 11kV Point of Supply 1.8 2 Owhata 11kV GXP 15.3(4) 12 Rotorua 33kV GXP 40.8(4) 66 Rotorua 11kV GXP 31.0(4) 26 Tarukenga 11kV GXP 9.70(4) 0(3) Wheao 110kV Embedded Generator 25.29 - (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
3.2.2.2 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.
SECTION 3 ASSETS COVERED 3-15 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Legend
GXP Zone Substation Supply Point
Figure 3-6: Rotorua region point of supply and 33kV sub-transmission 3-16 SECTION 3 ASSETS COVERED UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
ROTORUA GXP 33kV ROTORUA
TARUKENGA OWHATA Arawa Biak Street
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
3.2.2.3 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. SECTION 3 ASSETS COVERED 3-17 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Figure 3-8: Rotorua 11kV distribution system 3-18 SECTION 3 ASSETS COVERED UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
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) 10% Portion of the Low Voltage Network Underground Rotorua (1) 49%
(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
3.2.3 Taupo
3.2.3.1 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 2010/11 Peak Demand (MVA) Firm Capacity Winter (MVA)(1)
Hinemaiaia 33kV Embedded Generator 5.3 - Rotokawa 33kV Embedded Generator 37.2 - Wairakei 33kV GXP 42(2) 65 Contact Tauhara Plant 33kV Embedded Generator 25.9 -
(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
3.2.3.2 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 2010. 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 schematic and geographical view.
SECTION 3 ASSETS COVERED 3-19 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Legend
GXP Zone Substation Switching Station Power Station
Figure 3-9: Taupo region point of supply and 33kV sub-transmission 3-20 SECTION 3 ASSETS COVERED UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
WAIRAKEI GXP 33kV
Tauhara Ohaaki Binary Plant Rotokawa
Centennial Drive Switching Station 33kV Fletchers
Runanga
Fleet Street
Legend 2015-16 Proposed Circuit Taupo South Existing Circuit
Existing Substation/TP 11kV Hinemaiaia
Figure 3-10: Taupo sub-transmission network
SECTION 3 ASSETS COVERED 3-21 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
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 Ohaaki 33kV n 13
Table 3-11: Zone substation capacity and security level in the Taupo region
3.2.3.3 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 3 17% 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 3-22 SECTION 3 ASSETS COVERED UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Figure 3-11: Taupo 11kV distribution system SECTION 3 ASSETS COVERED 3-23 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
3.3 Network Assets
3.3.1 Overhead Lines
3.3.1.1 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 31/12/10 31/12/11 31/12/11 (km) (km) RC $(000) DRC $(000) Sub-Transmission 347 369 10,156 4,593 11kV Distribution 3,818 3,806 69,936 33,733 LV Distribution 940 936 28,062 12,817
(1) All valuations provided are current as at 31/12/2011 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
3.3.1.2 Age Profile
Overhead Lines 600 500 400 300 200
Kilometres of Line 100 0 1940 1944 1948 1952 1956 1960 1964 1968 1972 1976 1980 1984 1988 1992 1996 2000 2004 2008 Date of Installation
LV Overhead Line 11kV Overhead Line 33kV Overhead Line
Graph 3-1: Overhead lines
3-24 SECTION 3 ASSETS COVERED UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
3.3.1.3 Condition The system is generally reliable, and current levels of maintenance are maintaining favourable performance levels. A severe wind storm in April caused significant damage to sections of the Taupo Network when large sections of forest stands were felled through lines during the event. The recently introduced 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 by outside influences such as indiscriminate tree felling, figures as the most common External Influence category contributing to Network interruptions. Interruptions to supply from vehicle accidents, careless use and operation of mobile plant and machinery near lines, and vandalism have not been significant contributors to SAIDI in the 11/12 year.
Generally the lines are well configured across the network and match load requirements. New remote automation is being installed at an accelerated rate and this is expected to impact positively 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 region- specific 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 where wheeled vehicle access is not available).
Unison is intending to introduce a new pole testing system known as the Deuar MPT 40 (Mechanical Pole Test,) which can provide an estimate on 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 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. SECTION 3 ASSETS COVERED 3-25 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Wooden Poles 4000 3500 3000 2500 2000 Units 1500 1000 500 0 1940 1944 1948 1952 1956 1960 1964 1968 1972 1976 1980 1984 1988 1992 1996 2000 2004 2008 Date of Installation
LV Wooden Pole 11kV Wooden Pole 33kV Wooden Pole
Graph 3-2: Wooden poles
Concrete Poles 2000 1800 1600 1400 1200 1000 Units 800 600 400 200 0 1940 1944 1948 1952 1956 1960 1964 1968 1972 1976 1980 1984 1988 1992 1996 2000 2004 2008 Date of Installation
LV Concrete Pole 11kV Concrete Pole 33kV Concrete Pole
Graph 3-3: Concrete poles
3.3.2 Underground Cables
3.3.2.1 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.
3-26 SECTION 3 ASSETS COVERED UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
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 aluminum. 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 31/12/10 31/12/11 31/12/11 (km) (km) RC $(000) DRC $(000) Sub-transmission 37 37 17,991 11,757 11kV distribution 627 639 128,573 78,267 LV distribution 1,444 1,459 159,942 67,600
(1) All valuations provided are current as at 31/12/2011 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
3.3.2.2 Age Profile
Underground Cables 300 250 200 150 100
Kilometres of Cable 50 0 1940 1944 1948 1952 1956 1960 1964 1968 1972 1976 1980 1984 1988 1992 1996 2000 2004 2008 Date of Installation
LV Underground Cable 11kV Underground Cable 33kV Underground Cable
Graph 3-4: Underground cables
3.3.2.3 Condition Mass Impregnated Non Draining (M.I.N.D.) impregnated cables were introduced from the 1960’s and have proved to be very reliable and durable to date, with an expected service life of 70 years.
The 1970’s XLPE cable is considered less reliable and Unison is carefully monitoring fault rates on these assets. Test results on cables in regions where these assets have been installed in wet environments are trending toward the need SECTION 3 ASSETS COVERED 3-27 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
for replacement. These will be strategically identified for replacement and significant investment will be allocated to their renewal. 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 processes of XLPE cables means those installed after the 1970’s 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, insulation, and jointing failures, together with 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. Aluminum 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.
3.3.3 Power Transformers
3.3.3.1 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.
All Unison’s power transformers are filled with mineral insulation oil that provides both insulation and cooling of the transformer. 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 and thereby improve the life cycle management of these transformers.
During this period two transformers at Maraekakaho substation, a 3MVA and a 1.25MVA were removed and replaced with a refurbished 7MVA transformer as part of the upgrade of this substation.
A 33/11kV 10/13MVA transformer was purchased as part of the Ohaaki substation purchase from Transpower and a new 15/20MVA Wilson transformer was purchased and installed at Windsor substation as a network spare.
3-28 SECTION 3 ASSETS COVERED UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
FRS-3(1) Quantity Quantity Power Transformers 31/12/11 31/12/10 31/12/11 RC $(000) DRC $(000) Standard Life (45 yrs) 2 2 2,060 1,167 Extended Life (60yrs) 56 56 42,467 20,126 Voltage Regulators 4 3 393 317
(1) All valuations provided are current as at 31/12/2011 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
3.3.3.2 Age Profile
Power Transformers 6 5 4 3 Units 2 1 0 1940 1944 1948 1952 1956 1960 1964 1968 1972 1976 1980 1984 1988 1992 1996 2000 2004 2008
Date of Installation
Power Transformers
Graph 3-5: Power transformers update
3.3.3.3 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 20 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.
Oil samples are taken from each transformer each year for analysis. This provides an indication of the transformer internal condition by trend of results and will indicate deterioration of the internal insulation. Six transformers had oil refurbishment in the last period to enhance the condition of the oil back to new. Furan testing has been completed for a second time and this will further indicate the estimated DP and condition of the insulation paper. SECTION 3 ASSETS COVERED 3-29 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
3.3.4 Circuit Breakers
3.3.4.1 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 (SF6). 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 SF6 gas, or moulded into epoxy resin housing.
SF6 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.
FRS-3(1) Quantity Quantity ZS Switchgear 31/12/11 31/12/10 31/12/11 RC $(000) DRC $(000) 33kV Indoor CB 21 21 1,239 1,005 33kV Outdoor CB 87 88 4,619 1,982 11kV Indoor CB 272 277 9,764 4,426 11kV Outdoor CB 17 19 637 318
(1) All valuations provided are current as at 31/12/2011 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
With the purchase of the Ohaaki assets from Transpower the following additional circuit breakers have been added to the network - one outdoor 33kV circuit breaker and six 11kV indoor circuit breakers.
Two new circuit breakers have been installed as part of the Maraekakaho upgrade, one 33kV CB and one 11kV CB. 3-30 SECTION 3 ASSETS COVERED UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
3.3.4.2 Age Profile
Zone Substation Circuit Breakers 30 25 20 15 Units 10 5 0 1940 1944 1948 1952 1956 1960 1964 1968 1972 1976 1980 1984 1988 1992 1996 2000 2004 2008 Date of Installation
33kV Circuit Breakers 11kV Circuit Breakers
Graph 3-6: Zone substation circuit breakers
3.3.4.3 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 (SF6 or vacuum). Unison supports this as a reasonable estimate of service life for these assets.
The indoor 11kV circuit breakers at Runanga and Taupo South substations in Taupo are to be replaced. This is mainly due to no automated spring charging. These circuit breakers require attention after an operation to recharge the closing springs so that the circuit breaker can close again.
The circuit breakers at the Tannery Road substation are in the poorest condition and are to be replaced in the 13/14 year.
Some 33kV sub-transmission circuit breakers are in need of replacement. As the protection schemes get more sophisticated and operate faster, older circuit breakers cannot keep up with these requirements. Three 33kV circuit breakers are planned to be replaced at Centennial Drive substation in the next period.
SECTION 3 ASSETS COVERED 3-31 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
3.3.5 Other Substation Equipment and Buildings
3.3.5.1 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.
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. Unison prefers to use 110 volts DC for equipment operation and 50 volt DC for SCADA.
The Maintenance Free type of battery is preferred to the Lead Acid car type battery as these require regular maintenance. Also as the DC load requirement increases a bigger Amp Hour battery is required.
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 and 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 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 to minimise insulation oil leaks and spills from oil filled equipment with regularly monitoring for oil leaks. New substations are designed to include a transformer oil containment system and containment systems are progressively being installed at old substations.
3-32 SECTION 3 ASSETS COVERED UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Oil containment will be installed at Windsor and Bluff Hill stations in the 12/13 planning period.
Buildings Buildings house indoor switchgear and in some cases power transformers, control and protection equipment, SCADA, RTU and communications systems. All Unison substation buildings are to be acce by a Civil Engineer to provide Unison with a plan for upgrading any building where strength for seismic compliance is an issue.
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 has been introduced. A surveillance camera now operates at the Fernhill and Tamatea substations and monitors unauthorised entry and possible vandalism.
Outdoor Structures These consist of overhead support structures and conductive busbars of either copper or aluminum that allows switchgear and power transformers to be connected together. These are designed to provide isolations and safe distances for maintenance works and operations. Older substations are found to have an increasing number of deteriorating insulators. These insulators are located by an Ultrasonic scan of the outdoor equipment. Thermovision is a useful tool for finding poor connections before they become a problem.
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 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.
3.3.5.2 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).
3.3.5.3 Condition General condition of these assets is good, but this is driven by an extensive and frequent, condition monitoring plan. Asset deterioration is a problem as many substations were built in the 1960 – 70’s.
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. SECTION 3 ASSETS COVERED 3-33 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
3.3.6 Distribution Transformers and Voltage Regulators
3.3.6.1 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 pole-and-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.
Voltage regulators (11kV/11kV) are used for voltage control on some long or heavily loaded 11kV feeder lines to boost or buck the voltage.
FRS-3(1) Quantity Quantity Distribution Transformers 31/12/11 31/12/10 31/12/11 RC $(000) DRC $(000) Voltage Regulators 23 25 3,136 2,603 Distribution Transformers 9,215 9,272 135,442 73,560 Distribution Substations 9,167 9,224 30,236 17,068
(1) All valuations provided are current as at 31/12/2011 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
3-34 SECTION 3 ASSETS COVERED UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
3.3.6.2 Age Profile
Distribution Transformers 400 350 300 250 200 Units 150 100 50 0 1940 1944 1948 1952 1956 1960 1964 1968 1972 1976 1980 1984 1988 1992 1996 2000 2004 2008 Date of Installation
Ground Mounted Distribution Transformer Pole Mounted Distribution Transformer
Graph 3-7: Distribution transformers
3.3.6.3 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.
Several sites identified as potentially corrosive have had specially coated transformers installed and their condition will be monitored over time.
Voltage regulators are of modern design and in good service condition.
3.3.7 Distribution Switchgear
3.3.7.1 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.
SECTION 3 ASSETS COVERED 3-35 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
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 SF6 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.
The remaining Magnefix switch units installed in the Hawke’s Bay network area are all planned for replacement during the 2012/13 planning period. A new Safe link switch with SF6 insulation medium has been approved which will facilitate replacement of existing switches.
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.
Unison has, until recently, used single-phase vacuum-insulated switches that are electrically linked to operate simultaneously across all phases.
Three new unitised vacuum insulated RCS’s 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. 3-36 SECTION 3 ASSETS COVERED UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
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.
FRS-3(1) Quantity Quantity Distribution Switchgear 31/12/11 31/12/10 31/12/11 RC $(000) DRC $(000) Disconnectors 2,150 2,156 18,356 9,174 Dropout Fuses 8,215 8,265 28,108 8,893 Recloser/Sectionaliser 154 211 7,099 5,374 RMS – 3 way 812 831 24,566 15,732 Extra Oil/Fuse Switch 394 391 5,311 3,603 Remote Actuators 56 112 415 200
(1) All valuations provided are current as at 31/12/2011 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
3.3.7.2 Age Profile
Overhead Distribution Switchgear 450 400 350 300 250
Units 200 150 100 50 0 1940 1944 1948 1952 1956 1960 1964 1968 1972 1976 1980 1984 1988 1992 1996 2000 2004 2008 Date of Installation
ABS Fuse Recloser/Sectionaliser
Graph 3-8: Overhead distribution switchgear
SECTION 3 ASSETS COVERED 3-37 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Ring Main Switches 120 100 80 60 Units 40 20 0 1940 1944 1948 1952 1956 1960 1964 1968 1972 1976 1980 1984 1988 1992 1996 2000 2004 2008 Date of Installation
Extra Fuse/Oil Switch 3 Way
Graph 3-9: Ring main switches
3.3.7.3 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.
ABS’s 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 RCS’s which have remote operation capability and fit with the Smart Network requirements.
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 with new type SF6 safe link switches.
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 a combination of both switch design and workmanship, together with the use of incompatible equipment for terminations are prime causes.
Reclosers, remote controlled switches and sectionalisers are all generally in good condition, and standard service lives as per the ODV handbook are considered reasonable.
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3.3.8 Load Control Plant
3.3.8.1 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.
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 response to signals and enables a number of smaller blocks of load to be controlled which is advantageous in load restoration.
FRS-3(1) Quantity Quantity Load Control Plant 31/12/11 31/12/10 31/12/11 RC $(000) DRC $(000) Load Control Plant 15 15 4,058 2,063
(1) All valuations provided are current as at 31/12/2011 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
SECTION 3 ASSETS COVERED 3-39 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
3.3.8.2 Age Profile
Load Control Plant 3.5 3 2.5 2
Units 1.5 1 0.5 0 1940 1944 1948 1952 1956 1960 1964 1968 1972 1976 1980 1984 1988 1992 1996 2000 2004 2008 Date of Installation
Load Control Plant
Graph 3-10: Load control plant
3.3.8.3 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.
A maintenance contract is being redrafted by Landis+Gyr and will include the three additional plants in Hawke’s Bay.
3.3.9 Service Mains Unison does not currently own the connection between the street asset and the meter located on the customer’s premises, known as the service main. Unison recognises that owning the service main and the meter, would enable its end-to-end service to improve, through economies of scale, lifecycle management of these assets, and enhanced availability of data. This would in turn lead to better quality of supply outcomes and a lower cost to serve over the long term. Unison will investigate this option and consult comprehensively with customers over the next few years.
3.3.10 Miscellaneous Distribution Equipment
3.3.10.1 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.
3-40 SECTION 3 ASSETS COVERED UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
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 concrete, metal, plastic or fibreglass and are fitted out with various size fuses as required.
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.
FRS-3(1) Quantity Quantity Miscellaneous Distribution Equipment 31/12/11 31/12/10 31/12/11 RC $(000) DRC $(000) Streetlight Cables 1,234 1,244 39,447 16,231 Streetlight Lines 379 375 4,554 1,955 Link Pillars 2,184 2,097 7,675 3,019 Hot water Lines 270 267 1,443 720 Hot water Cables 235 235 2,091 504 Hot water Switch 2,916 2,905 514 88 Streetlight Switch 1,852 1,922 340 78 Consumer Connection OH 36,675 36,589 4,033 1,528 Consumer Connection UG 70,029 70,875 27,434 12,170 Consumer Connection Light 24,171 24,322 1,703 665
(1) All valuations provided are current as at 31/12/2011 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
3.3.10.2 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.
SECTION 3 ASSETS COVERED 3-41 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
3.3.10.3 Condition Fuses are expected to operate for the life of the asset they are protecting. Recent LV fuse failures on service connections has increased and is attributed to both asset selection and the environment. Corrective measures are in place to address this. 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 attributing to increase in maintenance costs but are progressively being abandoned and replaced with ripple control systems. Standard service lives for these assets are considered reasonable as per the ODV handbook.
3.3.11 SCADA Control and Communications
3.3.11.1 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 has been installed in the Hawke’s Bay area and connected to all major 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;
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 which is 96% complete. 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. 3-42 SECTION 3 ASSETS COVERED UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
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 medium is leased IP communication network.
Communication Cables One Hawke’s Bay zone substation is connected to the SCADA Realflex system in the Unison Control Centre via a network of telcon cables, twenty four by 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 2012. 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 2012.
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.
SECTION 3 ASSETS COVERED 3-43 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
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.
3.3.11.2 Age Profile The nature of these assets renders a combined age profile inappropriate. The comments made above indicate the age of various parts.
3.3.11.3 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.
3.3.12 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.
3.3.13 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 focusing on asset specific justification.
3.4.1 High Level Justification For Unison, justification for the assets employed has three key limbs:
3.4.1.1 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 3-44 SECTION 3 ASSETS COVERED UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
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.
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.
3.4.1.2 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.
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SAIDI Performance 160
140
120
100
80
60 SAIDI (minutes) 40
20
0 2006/07 2007/08 2008/09 2009/10 2010/11
Graph 3-11: SAIDI Performance
SAIFI Performance 2.5
2
1.5
1
SAIFI (interruptions) 0.5
0 2006/07 2007/08 2008/09 2009/10 2010/11
Graph 3-12: SAIFI Performance
3.4.1.3 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.
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3.4.2 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 in 2004, 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.
3.4.3 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.
3.4.4 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.
3.4.5 11kV 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. SECTION 3 ASSETS COVERED 3-47 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
3.4.6 Distribution Transformers/Substations Distribution substations transform 11kV distribution voltage to 400/230V, which is the supply voltage for the majority of end use consumers.
3.4.7 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.
3.4.8 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.
4 SERVICE LEVELS
Unison’s first smart transformer was installed in the new Napier suburb of Parklands. first smart Unison’s SERVICE LEVELS 4 SERVICE SECTION
SECTION 4 SERVICE LEVELS 4-1 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
4 Service Levels ...... 4-3
4.1 Purpose of Service Levels ...... 4-3
4.2 Service Level Planning and Development ...... 4-3
4.3 Consumer Oriented Service Levels ...... 4-4 4.3.1 Reliability Indices (SAIDI and SAIFI) ...... 4-4 4.3.2 Performance of 11kV Feeders According to the FAIDI Metric ...... 4-5
4.4 Consumer Service Level Targets ...... 4-7
4.5 Asset and Business Efficiency Service Levels ...... 4-9 4.5.1 Business Efficiency Targets ...... 4-9 4.5.2 Asset Efficiency Targets ...... 4-9
4.6 Justification for Target Levels of Service ...... 4-10 4.6.1 Industry Benchmarking ...... 4-12 4.6.2 Consumer Satisfaction Survey 2011 ...... 4-15
Figure 4-1: Service level planning ...... 4-3 Figure 4-2: FAIDI vs. Connection Density ...... 4-6 Figure 4-3: FAIDI performance against baseline ...... 4-6 Figure-4-4: Hawke’s Bay service level zones ...... 4-7 Figure 4-5: Rotorua service level zones ...... 4-8 Figure 4-6: Taupo service level zones ...... 4-8 Figure 4-7: Benchmarking business efficiency ...... 4-13 Figure 4-8: Benchmarking capacity utilisation ...... 4-13 Figure 4-9: Evidence of a relationship between capacity utilisation and consumer density ...... 4-14 Figure 4-10: Benchmarking loss ratio ...... 4-14 Figure 4-11: Some evidence of a relationship between loss ratio and consumer density ...... 4-15 Figure 4-12: Benchmarking faults per 100km ...... 4-15 Figure 4-13: Consumer views on most important attributes of power supplier ...... 4-16 Figure 4-14: Consumer satisfaction survey ...... 4-17 Figure 4-15: Consumer satisfaction survey ...... 4-17
4-2 SECTION 4 SERVICE LEVELS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Table 4-1: Reliability index service levels ...... 4-5 Table 4-2: Consumer service levels ...... 4-9 Table 4-3: Business efficiency service levels ...... 4-9 Table 4-4: Asset efficiency service levels ...... 4-10 Table 4-5: Justification of service levels and targets ...... 4-12
SECTION 4 SERVICE LEVELS 4-3 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
4 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 2004.
4.2 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 2.4.1.
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 2.5.1. Figure 4-1: Service level planning 4-4 SECTION 4 SERVICE LEVELS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Unison’s service levels were the subject of a paper to the Board of Directors in 2009. 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. This paper has led to the development of a new service level based on the FAIDI metric. The service level will seek to examine the experience of consumers on individual 11kV feeders and will be reported against from 2013.
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.
4.3.1 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 Default Price 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.
SECTION 4 SERVICE LEVELS 4-5 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
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 2011-2020 Actual 2010/11 (YE forecast) SAIDI < 147.9 minutes 130.0 minutes SAIFI < 2.70 interruptions 2.30 interruptions
Table 4-1: Reliability index service levels
4.3.2 Performance of 11kV Feeders According to the FAIDI Metric FAIDI and FAIFI are similar in form to SAIDI and SAIFI, but measure the reliability of supply experienced by consumers 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 performed regression analysis to identify and quantify explanatory variables in network reliability. The analysis 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. Since this time FAIDI has been an indicator used by Unison to compare the performance of 11kV feeders. This has resulted in the ability to rigorously compare the performance of feeders and prioritise remedial work. FAIDI is also used as a secondary input to the Augmentation Envelope (Section 5.2.2).
The formulation of the service level is described below:
The regression analysis provides an expected FAIDI value for a feeder with a given connection density and proportion of underground circuit. Figure 4.2 shows an example of the semi-logarithmic relationship between FAIDI and connection density for a subset of the network. Each blue dot represents an actual 11kV Unison feeder. Feeders above the red line (the ‘upper bound’) are underperforming given their connection density. 4-6 SECTION 4 SERVICE LEVELS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Figure 4-2: FAIDI vs. Connection Density
A ‘deadband’ is applied to remove statistical variation. This creates an ‘upper bound’.
Actual FAIDI is calculated normalising for outlying data points1. The normalising of data removes outliers that are usually caused by events beyond Unison’s control such as extreme weather.
Expected values are compared with actual FAIDI allowing the calculation of residual FAIDI (the difference between expected and actual FAIDI). Residual FAIDI is summed across all feeders for a given financial year.
The same procedure is performed for historic years of data and the results are averaged for the 05-092 years. This average is turned into an index with value 1 to allow following years to be compared. From 2013, FAIDI performance compared with the index will be measured as a service level.
FAIDI - Sum of residual for feeders above upper bound 1.6
1.4
1.2
1
0.8
0.6 Performance Index 0.4
0.2
0 05-09 average 2009/10 2010/11 Performance 05-09 average (index)
Figure 4-3: FAIDI performance against baseline
1 The FAIDI impact from faults occurring on Major Event Days as determined by the 2.5 beta method incorporated in the DPP is removed, as is the impact from state (back-feeding another feeder at the time feeders operating in an abnormal of an outage). 2 This is the set of data used to calculate Default Price Path quality limits for SAIDI and SAIFI. Because FAIDI is strongly correlated with SAIDI, the DPP reference period provides a ‘baseline’ for FAIDI performance. SECTION 4 SERVICE LEVELS 4-7 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
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 2009. 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.
Figure-4-4: Hawke’s Bay service level zones 4-8 SECTION 4 SERVICE LEVELS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Figure 4-5: Rotorua service level zones
Figure 4-6: Taupo service level zones SECTION 4 SERVICE LEVELS 4-9 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Table 4-2 outlines the current consumer service level targets for the three customer groupings used.
Customer Actual 2011/2012 Measure Target Group (YE forecast) Length of time before supply is restored Maximum of twenty events to exceed three hours Urban 23 events following an unplanned interruption. before supply is restored per annum. Number of unplanned interruptions per Maximum of one feeder to exceed four Urban 4 feeders annum. unplanned interruptions per annum. Length of time before supply is restored Maximum of ten events to exceed six hours Rural 22 events following an unplanned interruption. before supply is restored per annum. Number of unplanned interruptions per Maximum of one feeder to exceed ten unplanned Rural 2 feeders annum. interruptions per annum. Length of time before supply is restored Maximum of five events to exceed twelve hours Remote rural 13 events following an unplanned interruption. before supply is restored per annum. Number of unplanned interruptions per Maximum of one feeder to exceed twenty Remote rural 0 feeders annum. unplanned interruptions per annum.
Table 4-2: Consumer service levels
4.5 Asset and Business Efficiency Service Levels
4.5.1 Business Efficiency Targets Unison uses total cost per ICP and total cost per circuit kilometer as indicative measures of the cost effectiveness of its asset management planning. Unison benchmarks its own planned and actual performance against the industry median and where significant variance exists, explanation is required. By in large Unison expects its costs to be on average 10% greater than the industry median over the planning horizon as it continues with its Smart Grid deployment.
Target 2013 (industry Budget 2013 Target 2012 Actual 2012 Service Level median3) (2013 dollars) (2013 dollars) (2012 dollars) (2012 dollars) Total cost per ICP <$286 $285 <$271 $264
Total cost per km <$3,052 $3,148 <$3,159 $2,942
Table 4-3: Business efficiency service levels
4.5.2 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.
3 Electricity Line Business 2011 Information Disclosure Compendium. 4-10 SECTION 4 SERVICE LEVELS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
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.
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 4-4 below:
Service Level Target 2012-2021 Actual 2011/12 (forecast) Capacity Utilisation (%) ≥ 31% 29%
Loss Ratio (%) 6.0% 5% Faults per 100km < 8.0 7.2
Table 4-4: 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 Regulatory SAIDI and SAIFI limits have been network performance as experienced by the adopted as the targets for consumer service average consumer. levels. The limits for the regulatory period Stakeholders can use SAIDI and SAIFI to easily beginning 2011 were derived with reference to compare network performance across the long term average performance but are distribution industry (although it should be noted nuanced by the removal of major outages these indices are dependent upon a range of from the dataset and the addition of a ‘dead- network specific factors). band’ to mitigate the risk of breach due to SAIDI and SAIFI are used by the regulator to statistical variation. assess compliance with the quality path. 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. FAIDI FAIDI provides insight into the experience of The methodology used for calculating actual customers on individual 11kV feeders on the and expected FAIDI aligns with the regulatory Unison network. By highlighting improving or reporting requirements. Similar inclusions and declining performance at the feeder level over exclusions to the dataset are used to those time, Unison is able to make targeted required for SAIDI or SAIFI reporting. improvements to problem feeders. This Unison has used performance across financial ‘targeted’ improvement scheme allows Unison to years 2005-09 to create an index to be used most efficiently improve the customer as a target. This is the period over which the SECTION 4 SERVICE LEVELS 4-11 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Service Level Justification for Service Level Justification for Target
experience. Commerce Commission based its default FAIDI also provides insight into the extremes of price path determination. To align with the Unison’s performance spectrum. Where indices regulators intent, Unison aims to have no such as SAIDI and SAIFI average performance material deterioration against this index. across the network and a large number of consumers, FAIDI allows Unison to examine performance and improve the experience of consumers receiving below average service. FAIDI allows Unison to be measured, and base improvements on, the experience of consumers receiving the worst service. Consumer Service Level Targets Consumer service levels supplement the high The targets were derived by applying the level view provided by the indices (SAIDI, SAIFI, following criteria to Unison’s network FAIDI, and FAIFI) by accounting for extremes on signature: the performance spectrum. These service levels Depot location; provide consumers with a view of the minimum Service level agreement with first response level of service that can be expected from a service provider; reliability perspective. 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). Total cost per ICP Total cost per ICP is a measure that can be The target is the industry median in present readily benchmarked across the industry and is dollar terms. This is an appropriate target scalable. It represents the cost effectiveness of because by setting the target with reference to the business. This service level is particularly the industry peer group Unison can compare important for shareholders who have an interest its cost to serve with other NZ EDB’s. in the business performing in a financially sustainable manner. Total cost per km Total cost per km is a measure that can be The target is the industry median in present readily benchmarked across the industry and is dollar terms. This is an appropriate target scalable. It represents the cost effectiveness of because by setting the target with reference to the business. This service level is particularly the industry peer group Unison can compare important for shareholders who have an interest its cost to serve with other NZ EDB’s. in the business performing in a financially sustainable manner. Capacity utilisation Capacity utilisation is a measure that can readily The target is derived by consideration of the be benchmarked across like distribution capacity utilisation ratios of lines businesses in businesses. It provides the ability to assess the Unison’s peer group. This metric is highly quality of network development planning and LV dependent on network characteristics and the design standards. target is justifiable on this basis (see benchmarking section below). 4-12 SECTION 4 SERVICE LEVELS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Service Level Justification for Service Level Justification for Target
Loss ratio The use of loss ratio as a service level is justified The target is derived with reference to as it can be used to ensure that assets deployed Unison’s network characteristics, knowledge are selected appropriately and are operating of the assets employed (particularly the optimally. This service level is of interest to population of distribution transformers), and stakeholders such as environmental interest planning criteria. The loss ratio target places groups. Furthermore there has been some Unison in the lowest third of the New Zealand discussion in the industry of enforcing the use of distribution industry for losses (see low loss assets. In the future this service level benchmarking section below). may become a regulatory instrument. Faults per 100km Faults per 100km of system length are an The target is derived using forecasting indicator of the resilience of the sub-transmission methods to predict (within a level of and distribution networks to unplanned outages. confidence) the number of faults and the level It is an asset efficiency service level that of network extension on each feeder, each complements the consumer oriented service year. These forecasts are aggregated to levels related to network performance. provide a total faults per 100km figure for the As well as providing an indication of service network. This methodology is justified as it quality, this service level is of interest to the first takes into account the network signature, response service provider, as it provides a view asset specific failure modes and historical fault of the resourcing required to respond to the data. Unison’s faults per 100km target places predicted level of unplanned interruptions. Unison around the median of the New Zealand distribution industry (see benchmarking section below).
Table 4-5: Justification of service levels and targets
4.6.1 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.
SECTION 4 SERVICE LEVELS 4-13 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Total Costs per ICP 300
270
240
210 $ per ICP 180
150 2005/06 2006/07 2007/08 2008/09 2009/10 2010/11 2011/12 Total Costs per ICP Total Costs per ICP (Real) Industry Median per ICP Industry Median per ICP (real)
Figure 4-7: Benchmarking business efficiency
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 50 40 30 20 10 Capacity Utilisation (%) Capacity Utilisation Northpower Westpower Zealand MainPower New Centralines Marlborough Lines Top Energy Scanpower Powerco Company The Lines Waipa Networks Company The Power Aurora Energy Counties Power Vector 0 Buller Electricity DistributionHorizion Energy Eastland Network Network Tasman Network Waitaki Alpine Energy Unison Networks OtagoNet Joint Venture Electricity Ashburton Electra WEL Networks Electricity Nelson Wellington ElectricityLines Invercargill Electricity
Figure 4-8: Benchmarking capacity utilisation
Figure 4-9 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.
4-14 SECTION 4 SERVICE LEVELS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Capacity Utilisation vs. Consumer Density 50 45 40 35 30 25 20 15 10 Capacity Utilisation (%) Capacity Utilisation 5 0 0 5 10 15 20 25 30 35 40 Consumer Density (ICP/km)
Figure 4-9: Evidence of a relationship between capacity utilisation and consumer density
Loss Ratio 10 8 6 4 2 Loss Ratio (%) Vector Wellington ElectricityLines Unison Networks Network Tasman Scanpower Electra Powerco Alpine Energy Northpower Electricity Nelson WEL Networks Westpower Marlborough Lines Zealand MainPower New Electricity Ashburton Counties Power Waipa Networks Aurora Energy Eastland Network Company The Power Centralines OtagoNet Joint Venture Network Waitaki Buller Electricity Company The Lines Top Energy 0 Invercargill Electricity DistributionHorizion Energy
Figure 4-10: Benchmarking loss ratio
Figure 4-11 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.
SECTION 4 SERVICE LEVELS 4-15 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Loss Ratio vs. Consumer Density 10 9 8 7 6 5 4
Loss Ratio (%) 3 2 1 0 0 5 10 15 20 25 30 35 40 Consumer Density (ICP/km)
Figure 4-11: Some evidence of a relationship between loss ratio and consumer density
Faults per 100 km 25
20
15
10 Faults/100km 5 Westpower Centralines Aurora Energy Company The Lines Scanpower OtagoNet Joint Venture Zealand MainPower New Waipa Networks Northpower Counties Power Network Tasman Electricity Ashburton Company The Power Unison Networks WEL Networks Top Energy Powerco Wellington ElectricityLines Eastland Network Marlborough Lines Invercargill Electricity Vector Nelson Electricity Nelson Electra Alpine Energy Buller Electricity 0 Network Waitaki DistributionHorizion Energy
Figure 4-12: Benchmarking faults per 100km
4.6.2 Consumer Satisfaction Survey 2011 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 nine years, Unison has found that the two most important attributes to consumers are reliability of supply and a low charge for electricity distribution. These interests are manifest in the business efficiency service levels that are aimed at keeping costs to run the network down, and the consumer oriented service levels aimed at measuring and improving the experience of consumers on the Unison network. Keeping prices down remains a major driver for 4-16 SECTION 4 SERVICE LEVELS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
investment in the Smart Grid. The Smart Grid will increase the utilisation of network assets allowing investment deferral and decreased maintenance costs through the full asset lifecycle. 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 two most important attributes to consumers relate to quality of supply (in order of importance: fast restoration in the event of a fault and power quality). SAIDI and SAIFI and the Consumer Service Level Agreement currently form the basis for quality of supply service levels.
Targets for these service levels are also justified by the consumer surveys. While consumers have consistently rated quality of supply as important, price remains an important 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 using traditional network solutions.
Results of Consumer Satisfaction Survey 2011 The most recent Consumer Satisfaction Survey took place in December 2011/January 2012. 900 electricity consumers were surveyed from throughout Unison’s geographic footprint and from all consumer segments. The overall level of satisfaction with Unison’s performance was 82%.
A selection of results from the 2011 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
Provide Information
Dividends
Power Quality
Quick Response
Price
Reliable
0% 10% 20% 30% 40% 50% 60% 70% 80%
Figure 4-13: Consumer views on most important attributes of power supplier
SECTION 4 SERVICE LEVELS 4-17 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
I would like to see an improvement in my quality of supply 60%
50%
40%
30%
20%
10%
0% Hawke's Bay Taupo Rotorua Residential Business / Rural Remote Rural Commercial
2009/10 2010/11 2011/12
Figure 4-14: Consumer satisfaction survey
How much would you be willing to pay for an improvement in quality of supply 120%
100%
80%
60%
40%
20%
0% Residential Business / Commercial Rural Remote Rural
An extra $25 / year An extra $50 / year An extra $100 / year An extra $200 / year An extra $300 / year Any increase would be too much
Figure 4-15: Consumer satisfaction survey
5 NETWORK DEVELOPMENT PLANS
Power sensing equipment installed in ground mounted assets improve Unison’s real time monitoring of the network. Power sensing equipment installed in ground mounted assets improve Unison’s NETWORK DEVELOPMENT PLANS DEVELOPMENT 5 NETWORK SECTION
SECTION 5 NETWORK DEVELOPMENT PLANS 5-1 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
5 Network Development Plans ...... 5-4
5.1 Planning Criteria and Assumptions ...... 5-4 5.1.1 Planning Process ...... 5-4 5.1.2 Security Criteria ...... 5-5 5.1.3 Capacity Determination ...... 5-5 5.1.4 Performance and Quality of Supply ...... 5-8
5.2 Prioritisation Methodology ...... 5-10 5.2.1 Investment Prioritisation Tool (IPT) ...... 5-10 5.2.2 Envelope tools ...... 5-12
5.3 Demand Forecasts ...... 5-14 5.3.1 Load Forecasting Methodology ...... 5-14 5.3.2 Impact of Embedded and Distributed Generation on Load Forecast ...... 5-15 5.3.3 Impact of Developments and Large Consumer Projects on Load Forecast ...... 5-16 5.3.4 Load Forecast Assumptions - Uncertain load types and external factors ...... 5-17 5.3.5 Impact of Demand Side Management on Load Forecast ...... 5-19 5.3.6 Reactive Demand ...... 5-20 5.3.7 District Load Forecasts ...... 5-21 5.3.8 GXP Load Forecasts ...... 5-23 5.3.9 Zone Substation Load Forecasts ...... 5-24
5.4 Distributed Generation ...... 5-26
5.5 Non Network (Smart Grid) Solutions ...... 5-27
5.6 Network Development Options Available ...... 5-34 5.6.1 Options Available ...... 5-34 5.6.2 Meeting Service Level Targets ...... 5-36
5.7 Network Development Plan ...... 5-37 5.7.1 Central Region ...... 5-37 5.7.2 Hawke’s Bay...... 5-76
5.8 Expenditure Forecasts and Reconciliation ...... 5-146
5-2 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Figure 5-1: Planning process ...... 5-4 Figure 5-2: Network Investment Toolbox ...... 5-10 Figure 5-3: Typical Distribution of Individual CAPEX projects according to their individual score/mix ...... 5-11 Figure 5-4: Load Forecast Tool ...... 5-14 Figure 5-5: 4 Plug in Electric Vehicle ...... 5-18 Figure 5-6: Interplay of Technological Uncertainties ...... 5-19 Figure 5-7: Self healing concept ...... 5-28 Figure 5-8: Shunt Capacitor bank ...... 5-30 Figure 5-9: Line Differential Relay ...... 5-30 Figure 5-10: Transformer Differential Installation ...... 5-30 Figure 5-11: Unison’s Ground Fault Neutraliser ...... 5-31 Figure 5-12: Smart Meter ...... 5-31 Figure 5-13: DTS Overview ...... 5-32 Figure 5-14: Powersense Current Sensor ...... 5-34 Figure 5-15: Install voltage regulator on Waikato feeder ...... 5-39 Figure 5-16: Install voltage regulator on Kaharoa feeder ...... 5-40 Figure 5-17: Upgrade the front ends of Owhata feeders ...... 5-43 Figure 5-18: Upgrade the front ends of Owhata feeders ...... 5-44 Figure 5-19: Automated switches in Fleet Street zone substation's 11kV network ...... 5-46 Figure 5-20: Automated switches in Taupo South 11kV network ...... 5-47 Figure 5-21: Automated switches in Runanga 11kV network ...... 5-48 Figure 5-22: Overview of smart network in Taupo ...... 5-49 Figure 5-23: Identified switches to be replaced in Rotorua ...... 5-51 Figure 5-24: Switches to be replaced in Rotorua ...... 5-51 Figure 5-25: Overview of existing and proposed network assets at Reporoa ...... 5-70 Figure 5-26: Reporoa 33kV sub-transmission - proposed ...... 5-71 Figure 5-27: Overview of existing and proposed network assets - Rotorua ...... 5-72 Figure 5-28: Rotorua 33kV sub-transmission - proposed ...... 5-73 Figure 5-29: Overview of existing and proposed network assets – Taupo ...... 5-74 Figure 5-30: Taupo 33kV sub-transmission – proposed ...... 5-75 Figure 5-31: Upgrade Taradale A and B feeders ...... 5-78 Figure 5-32: New feeder - Marewa zone substation ...... 5-81 Figure 5-33: Interconnection between Ada and Grove feeders ...... 5-84 Figure 5-34: Fast transfer scheme for Flaxmere zone substation ...... 5-86 Figure 5-35: Bowen feeder upgrade...... 5-100 Figure 5-36: Proposed upgrade Haumoana feeder route – Rangitane zone substation ...... 5-104 SECTION 5 NETWORK DEVELOPMENT PLANS 5-3 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Figure 5-37: Proposed work details for Bridge Pa and Raureka feeders ...... 5-106 Figure 5-38: Havelock North zone substation, and the area that it serves ...... 5-112 Figure 5-39: Tamatea zone substation and its 11kV feeders ...... 5-115 Figure 5-40: Shows where Unison will install the new 33kV circuit breakers at Marewa zone substation ...... 5-117 Figure 5-41: Shows where Unison will install additional 33kV circuit breakers at Faraday zone substation ...... 5-119 Figure 5-42: Gilligans feeder extended and connected to Powdrells Road switching station ...... 5-121 Figure 5-43: Hastings future network configuration ...... 5-141 Figure 5-44: New zone substation fed from the Onekawa D feeder ...... 5-145
Graph 5-1: Hastings district load forecast ...... 5-21 Graph 5-2: Napier district load forecast ...... 5-21 Graph 5-3: Rotorua district load forecast ...... 5-22 Graph 5-4: Taupo district load forecast ...... 5-22 Graph 5-5: GXP load forecasts ...... 5-23 Graph 5-6: Zone substation load forecasts – Central region ...... 5-24 Graph 5-7: Zone substation load forecasts – Hawke’s Bay region ...... 5-25
Table 5-1: Unison supply classification and security criteria ...... 5-5 Table 5-2: Definition of security levels ...... 5-5 Table 5-3: Capacity determination for network assets utilised ...... 5-7 Table 5-4: Voltage performance criteria ...... 5-8 Table 5-5: Investment Prioritisation Tool Drivers ...... 5-11 Table 5-6: Network option toolbox ...... 5-35
5-4 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
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 previous AMPs, 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 utilised in the planning period to ensure compliance to consumer service levels within fiscal constraints. The use of smart devices and control systems reinforces Unison’s plan to implement more non-network options as mitigation solutions for network constraints over the planning period.
The projects beyond 2012/13 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.
5.1.1 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. Project List Project List
Inputs Project Drivers Project Options Project Selection
Network Augmentation Load Forecast and Network Security Criteria Network Strengthening Envelope capacity determination Capacity Headroom Solutions Network Performance Large Customer Needs Non Network Solutions Database Quality of Supply Do Nothing Network Sensors Network Reliability
Risk Assessment Operational Constraints (Risk Assessment of Option Customer Service Levels selected)
Investment Prioritisation Tool
Figure 5-1: Planning process SECTION 5 NETWORK DEVELOPMENT PLANS 5-5 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
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.
5.1.2 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)
75% MD Restored within the 1st Hour L1 No Break 25% after repair time 50% MD Restored within the 1st Hour L2 Restore 100% MD within 1 Minute 50% after repair time 50% MD Restored within the 1st Hour L3 Restore 100% MD within 30 Minutes 50% after repair time
L4 Restore 100% MD within 4 Hours 100% after repair time
L5 100% restoration after repair time 100% after repair time
Table 5-2: Definition of security levels
5.1.3 Capacity Determination
5.1.3.1 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.
5-6 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
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.
5.1.3.2 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. The customer classification – Industrial, Commercial or Residential. The degree of security of supply needed. L1, L2, L3 Double transformer. 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). Requirements to back feed or support a wide range of switching configurations. L1, L2, L3 Indoor switchgear. Likely fault current rating. The expected duty service. Underground 33kV L1, L2 500 or 800mm Al XLPE. Load growth for the area served. cable The interconnected load requirements for security of supply. In some cases, the load duty cycle. (This 11kV L1, L2, L3 300 mm2Al XLPE. may apply to industrial situations). The de-rating effects that other cables buried nearby may have or soil conditions. SECTION 5 NETWORK DEVELOPMENT PLANS 5-7 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Asset Asset Level Load Type Design Standard considerations Capacity Determination
Overhead lines 11kV & 33kV L1, L2, L3, L4, Ground clearances which in turn The current rating capacity required. L5 are a function of span lengths, Future growth up to the planning period conductor size, circuits to be (20 years). carried and the legal clearances The electrical characteristics of the load required for the terrain. supplied. (e.g. power factor, duty Design considerations such as cycle). ice loading, broken conductor The tolerable voltage drop for the line. conditions and excessive dynamic wind loads. Requirement to carry additional load during fault restoration and switching. The importance of reducing losses. Poles 11kV & 33kV L1, L2, L3, L4, Height requirements for ground Planned future circuit requirements that L5 clearances which in turn are a may be added and the voltages. function of span lengths circuits to be The degree of security and factors of carried and the legal clearances safety needed based on the importance required for the terrain. of the circuit. 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). Distribution 11kV L1, L2, L3, L4, Transformers are selected based Customer diversity. Transformer L5 on their required load carrying Future connections. capability and reliability. Voltage drop especially for rural Use of transformers up to 1MVA consumers. as Unison carries spares. The load types to avoid quality issues (Household load vs High Reactive Load).
Distribution 11kV L1, L2, L3, L4, Switchgear are selected on their Customer density. switchgear L5 load breaking capability, reliability Automated switchgear. and functionality.
LV feeder 400V OH L1, L2, L3, L4, Parallel LV feeder to cater for Customer density. L5 voltage drop. Security of supply required. Radial LV feeders with group Voltage drop. 400V UG breaks. Capacity required.
Table 5-3: Capacity determination for network assets utilised 5-8 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
5.1.3.3 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 5.5.
5.1.4 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 SECTION 5 NETWORK DEVELOPMENT PLANS 5-9 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
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 intends to install 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 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.
5-10 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
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
Data Repositories Strategic Analysis Local Assessment Global & Interpretation (intra-category) Assessment (inter-category) Stores Information Register Works Cost Estimating Tool GIS Renewal Envelope (RE) Triple-R Tool Investment Historian and other CAPEX Augmentation Prioritisation Tool Portfolio and databases Envelope (AE) Budget Load Forecast Tool (IPT) (LFT) Condition Asset Register OPEX Portfolio and Based Budget Monitoring Connectivity Model (CBM) Faults Database
Figure 5-2: Network Investment Toolbox
5.2.1 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.
Strategic Drivers Strategic Sub Drivers Financial Direct financial o Revenues (including probable future revenues) o Consumer contributions o Cost savings by design o Costs (Capex & Opex) Indirect financial SECTION 5 NETWORK DEVELOPMENT PLANS 5-11 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Strategic Drivers Strategic Sub Drivers o Renewal of network elements o Mitigation of risks o Miscellaneous gains o Consequential gains/losses
Quality of Supply Network reliability o Direct impact on network reliability o Mitigation of risk of decrease in network reliability Network security Company Policies and Standards Conformance to company policies that must be strictly adhered to Legal & Statutory Legal & Statutory Stakeholder Satisfaction Gain in stakeholder satisfaction Shareholder Obligations Conformance to shareholder obligations that must be strictly implemented Strategic Benefit 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.
Investment Prioritisation Tool CAPEX Project Value Distribution 200 Included Excluded 150
100
50
0 Individual Project Value Individual Project 0 20 40 60 80 100 120 140 160 180 200 Rank
Performance Augmentation Compliance New Technology Renewal Undergrounding
Figure 5-3: Typical Distribution of Individual CAPEX projects according to their individual score/mix
The previous figure 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.
5-12 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
5.2.2 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 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.
SECTION 5 NETWORK DEVELOPMENT PLANS 5-13 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Augmentation Priority Profiles 450 400 350 Capacity Headroom
300 Connectivity Headroom 250 200 150 Priority, % 100 50 0 2030 10 0 -20-10 -30 -50-40 -60 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 density1 and using normalised scales bounded by the 5th and 95th 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 automate2. 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. 5-14 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
5.3 Demand Forecasts
5.3.1 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 2032 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
Household
11kV/33kV Feeder Network Information Information Feeder Demand Forecast
Installed Transformer Capacity per CAU Zone Substation Demand Forecast
GDP Projections Growth Profile GXP/POS Demand Household Building Consent Applications Forecast
Population Growth Projections
Figure 5-4: Load Forecast Tool
The existing household information is extracted from Unison commercial database. 11kV/33kV network information is extracted from the asset record database. Installed transformer capacity per Census Area Unit (CAU) is extracted from Unison Geographic Information System (GIS). Each transformer is dedicated to one industry type, which allows the types to be grouped into industrial, residential, and commercial categories. All the data combines to form the “network information” and is updated annually. SECTION 5 NETWORK DEVELOPMENT PLANS 5-15 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
GDP projections, household building consents applications, and population growth forecasts are provided by New Zealand Institute of Economic Research (NZIER) and the data is updated every 3-5 years. All forecasts are calculated for a 20-year horizon.
GDP growth forecasts are split by regions and then by industry types. The heavy industries such as manufacturing and construction are grouped into the industrial category, the lighter industries such as business and health and community services are grouped into the commercial category.
Residential growth forecasts are calculated from household building consent applications and population growth projections over a 20-year horizon. These forecasts are then split into territorial authority level within Unison’s footprint. The residential, industrial, and commercial forecasts are combined to form the “Growth Profile”.
A feeder can extend over multiple CAUs and have varying customer categories within each CAU. This requires the industrial, residential, and commercial forecasts to be further broken down to CAU level. The Load Forecast Tool (LFT) superimposes network information with the growth profile to form the feeder demand forecast.
The zone substation demand forecasts are calculated by applying a diversity factor to the sum of the feeder forecasts. The GXP/POS demand forecasts are calculated by applying a diversity factor on the sum of the substation demand forecasts.
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 50C conductor temperature. Unison has recently modified the design standards such that new overhead constructions are designed to operate at 75C.
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.
5.3.2 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 generators 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 DG is considered as substitute for network capacity.
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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. A small (5MW) hydro scheme in northern Hawke’s Bay is under construction with commissioning expected in early 2013.
5.3.3 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. During 2011, Unison was advised of plans to continue the development of large dairy units. The load forecast contains the estimated loads and timing which are updated as new information comes to hand.
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 and the designation of the WEKA route, the growth is likely to be deferred. At present, Unison does not know the precise load growth in the region, but estimates it 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 for the overhead line; o Substation is reliant on the forecast load growth materialising; o Short term solutions continue to be implemented prior to the substation being built. The short term solutions chosen will ensure assets do not become stranded.
The load forecast places increased load on the relevant feeders at assumed time intervals to ensure that the long term forecast reflects the development.
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. As the exact timing of the growth is unknown, the load forecast contains an allowance which is updated annually.
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 and demand for wood products. Unison is in regular contact with the customer and the load forecast is updated as the information changes.
The Hawke’s Bay region is beginning to see the load from the food processing industry increase. An allowance has been specifically entered into the load forecast for the relevant feeders. SECTION 5 NETWORK DEVELOPMENT PLANS 5-17 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
5.3.4 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. One of the main areas of uncertainty EDB’s will be facing over the next twenty years are the so-called ‘game changing’ technologies: micro distributed generation (MDG) and advanced batteries for use in applications such as plug-in electric vehicles (PEV) and local energy storage. From the research done by Unison, it has become clear that long standing norms and the conventional wisdom in electricity distribution and associated industries are shifting. Where once electricity distribution was a technologically static industry with merely organic load growth expectations, there is now uncertainty and dynamism. There is growing recognition of the significant potential for advancement in technologies that will cause step changes in electricity demand (both ‘up’ and ‘down’), as well as raising the fundamental question of whether there is a future for electricity distribution as we know it.
Due to the technological uncertainties that exist (scale of impact and time of impact), as well as the highly interrelation of the technologies, the potential impact on Unison’s load forecast is uncertain and has therefore not been included. More work needs to be done in this area, but it is Unison’s intention to complete impact studies over the next 12 months and include findings as well as the impact on Unison’s load forecast in the next AMP.
The following section describes at a high level the “game changing” technologies and the potential impact it can have on EDB’s:
Micro Distributed Generation (MDG) Distributed generation (DG) is the concept of using a large number of relatively small electricity generators distributed throughout a power system to meet demand. If DG becomes increasingly cost effective with improved technology, production volumes and manufacturing techniques, then transmission and distribution infrastructure will gradually cease to be renewed or constructed and will slowly decline in use.
The main problem presently facing proponents of MDG is its cost per unit of energy, which at present is far higher than that for centralised generation. However the combined effect of increasing energy cost and improving technology means 5-18 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
that economic viability of MDG in the future is likely. The MED predicts that solar PV cost per unit parity with centralised generation will occur within the next decade3.
Plug in Electric Vehicles (PEVs) Plug-in electric vehicles (PEVs) are personal motor vehicles containing rechargeable battery packs that drive an electric motor connected to the wheels. When the battery charge is low, the PEV can be plugged into an external source of electricity such as a wall socket in a house, or a public charging station, such as at a supermarket.
Figure 5-5: 4 Plug in Electric Vehicle
Although future uptake rates are an unknown, it is already clear that a material uptake in PEVs will have a significant impact on the New Zealand power system. For illustrative purposes, the charging options for the Mitsubishi i-MiEV are provided below:
A slow charge draws 3kW for seven hours (residential dwelling); and A fast charge draws 30kW for forty minutes (charging stations).
To put these numbers into perspective, when determining the supply requirements for a new sub-division, Unison applies a maximum demand of 4kW per household. In today’s terms this means that if charging of PEVs coincides with the daily peak, network demand could almost double. On the face of it, a step change in peak demand of this magnitude will necessitate large system growth investment. Moreover, such high demand will greatly diminish the ability of MDG technology to provide consumers with the capacity they require.
Local Energy Storage Predictions are that local energy storage will be an integral part of future MDG implementations. It is seen as the solution for the intermittency of renewable MDG and will allow electricity to be available twenty-four hours a day, regardless of the weather. For example:
Storage of solar energy collected by photovoltaic panels during the day to be used at night; and
3 Assessment of the Future Costs and Performance of Solar Photovoltaic Technologies in New Zealand, IT Power Australia Pty Ltd and Southern Perspectives Ltd on behalf of MED, April 2009 SECTION 5 NETWORK DEVELOPMENT PLANS 5-19 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Ensure the consistency of electricity supply from micro wind turbines, even through constant fluctuations in wind speed.
PEVs also represent a potential local energy storage solution. A parked PEV could sell the electricity from the battery during peak loads and recharge during off-peak times (assuming advancements in battery technology to mitigate the effect on life of large numbers of charge-discharge cycles).
Interplay The technological uncertainties described above are highly interrelated and while they can be discussed in isolation, Unison’s response to them must be unified and integrated.
MDG is a potential solution to the high energy intensity of charging PEVs. Local energy storage may be the panacea for the intermittency of MDG. PEVs could be the technology that finally makes MDG and microgrids viable. This interplay can be conceptualised as a two-by-two matrix (see Figure 5.5). Each quadrant represents a plausible future that Unison could face and will form part of the impact study.
Figure 5-6: Interplay of Technological Uncertainties
5.3.5 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. 5-20 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
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 continuing to reduce. 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 5.3.3.
5.3.6 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.
SECTION 5 NETWORK DEVELOPMENT PLANS 5-21 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
5.3.7 District Load Forecasts
Hastings District Load Forecast 150
100
50 Total Demand in MVA
0 2011/12 2012/13 2013/14 2014/15 2015/16 2016/17 2017/18 2018/19 2019/20 2020/21 2021/22 2022/23 2023/24 2024/25 2025/26 2026/27 2027/28 2028/29 2029/30 2030/31 2031/32
Existing Load Control Enhanced Load Control
Graph 5-1: Hastings district load forecast
Napier District Load Forecast 120
90
60
Total Demand in MVA 30
0 2011/12 2012/13 2013/14 2014/15 2015/16 2016/17 2017/18 2018/19 2019/20 2020/21 2021/22 2022/23 2023/24 2024/25 2025/26 2026/27 2027/28 2028/29 2029/30 2030/31 2031/32
Existing Load Control Enhanced Load Control
Graph 5-2: Napier district load forecast
5-22 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Rotorua District Load Forecast 120
90
60
Total Demand in MVA 30
0 2011/12 2012/13 2013/14 2014/15 2015/16 2016/17 2017/18 2018/19 2019/20 2020/21 2021/22 2022/23 2023/24 2024/25 2025/26 2026/27 2027/28 2028/29 2029/30 2030/31 2031/32
Existing Load Control Enhanced Load Control
Graph 5-3: Rotorua district load forecast
Taupo District Load Forecast 50
40
30
20 Total Demand in MVA 10
0 2011/12 2012/13 2013/14 2014/15 2015/16 2016/17 2017/18 2018/19 2019/20 2020/21 2021/22 2022/23 2023/24 2024/25 2025/26 2026/27 2027/28 2028/29 2029/30 2030/31 2031/32
Existing Load Control Enhanced Load Control
Graph 5-4: Taupo district load forecast
SECTION 5 NETWORK DEVELOPMENT PLANS 5-23 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
5.3.8 GXP Load Forecasts The following graph indicates the capacity of each Transpower GXP and points of supply connected to the Unison Network. Present and 2031/2032 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.
GXP Load Forecasts
Whakatu
Wairakei
Tarukenga
Rotorua 33kV
Rotorua 11kV 2011/12 Max 2031/32 Max Redclyffe Firm Capacity Owhata
Fernhill
Atiamuri
0 20 40 60 80 100 120 140 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 two single transformer sites, Tarukenga, and Atiamuri. The projects identified have a regional impact and are expected to resolve these constraints.
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5.3.9 Zone Substation Load Forecasts
Central Region
Central Region Zone Substation Load Forecast
Fleet St
Biak St
Taupo South
Runanga
Rainbow 2011/12 Max 2031/32 Max Fletchers Firm Capacity Fernleaf
Arawa
Ohaaki
0 5 10 15 20 25 30 35 MVA
Graph 5-6: Zone substation load forecasts – Central region
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.
SECTION 5 NETWORK DEVELOPMENT PLANS 5-25 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Hawke’s Bay Region
Hawkes Bay Zone Substation Load Forecast
Windsor Tomoana Rangitane Marewa Mahora Hastings Bluff Hill Arataki Tutira Tannery Rd Tamatea Springfield 2011/12 Patoka 2031/32 Faraday St Firm Capacity Esk Church Rd Awatoto Flaxmere Sherenden Maraekakaho Irongate Havelock North Fernhill Camberley McCain
0 5 10 15 20 25 30 35 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.
5-26 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
5.4 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 www.unison.co.nz. The key principles of Unison’s distributed generation policy are:
DG can be connected 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 be connected and operated within 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. SECTION 5 NETWORK DEVELOPMENT PLANS 5-27 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
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.
Impacts and benefits of Distributed Generation The advantages of DG are that generation and demand are closer together, reducing the cost of infrastructure to transmit power and the fact that a large number of distributed nodes is an inherently more resilient network architecture.
The downside of DG is that it can be intermittent in nature (i.e. solar and wind) and can lead to voltage fluctuations on the network, adding cost to EDB’s to control voltage and power quality.
Battery storage is seen as the solution for the intermittency of renewable DG and will allow electricity to be available twenty-four hours a day, regardless of the weather. For example:
Storage of solar energy collected by photovoltaic panels during the day to be used at night; and
Ensure the consistency of electricity supply from micro wind turbines, even through constant fluctuations in wind speed.
Another downside to DG is that electricity generated by wind and solar do not necessarily coincides with the daily peak and won’t enable the deferral of network infrastructure to support the daily peaks. Again the solution to this problem might be energy storage.
As part of the Smart Grid strategy, Unison is committed to investigate the impact of these technology uncertainties and a number of initiatives have been identified to investigate the impact on Unison’s network of the future.
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; Lower life cycle cost; Defer investment.
The following concepts have been used by Unison over the last few years:
Embedded generation; Standby generation; 5-28 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
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 have or are currently being trialed by Unison with the objective of determining if a larger network roll out can be justified:
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.
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 a more efficient electricity distribution system.
Benefits of ASR are: Operation Centre Feeder Devices 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. Substation Devices
Figure 5-7: Self healing concept SECTION 5 NETWORK DEVELOPMENT PLANS 5-29 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Unison has installed pilot ASR schemes on the Neeve feeder out of the Church Road substation and on the St Mary’s feeder out of the Church Road zone substation. Over the last two years these pilot schemes have operated successfully, thereby reducing SAIDI and outage times experienced by consumers. Following the trial, plans have been put in place (see project list for details) to roll out ASR across the Unison footprint focusing on areas where there are existing security constraints at the substation level. This will enable Unison to defer capital expenditure on power transformer replacements by up to 10 years.
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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 reactive power thresholds. During the trial period the capacitors banks operated as expected and have improved the voltage on the above mentioned feeders. This technology will not be rolled out across the Unison network but will form part of Unison’s non-network Figure 5-8: Shunt Capacitor bank solution toolbox utilised to address identified constraints and provide the benefits detailed above.
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 to Unison’s urban substations is an enabler for this technology.
Numerous line differential protection relays have been installed in Figure 5-9: Line Differential Relay preparation for these schemes. A significant number of the line differential protection schemes have now been commissioned and it is envisaged that all critical feeders will have line differential protection installed by the end of the 2015/16 financial year.
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
Figure 5-10: Transformer Differential Installation SECTION 5 NETWORK DEVELOPMENT PLANS 5-31 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
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 on all power transformers rated at 7.5MVA or higher by the end of the 2015/16 financial year.
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 GFN has been in service for the past six months and has successfully compensated for a number of earth faults which have occurred on 11kV feeders supplied by the Irongate substation.
This technology will form part of Unison’s non-network toolbox and will be Figure 5-11: Unison’s Ground Fault Neutraliser utilised as the need arises.
Smart Meters Smart meters installed on customer premises will provide Unison with a number of network related benefits. Some of these benefits include:
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 1,640 smart meters is planned for mid 2012. 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 Figure 5-12: Smart Meter 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.
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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 Distributed Temperature Sensing (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 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 cable installed.
Distributed Temperature Sensing 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. 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 5-13: DTS Overview
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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 10 second interval for 30 minutes. The initial and the final measured temperatures are then used to calculate the thermal resistivity.
Unison has deployed this technology on the City 33kV feeder between Windsor substation and the overhead termination structure off the end of Jubilee Street. Initial data from this trial has been analysed and results appear promising. The data will be peer reviewed and validated by an external consultant. A larger rollout of this technology has been planned and will target highly loaded sub-transmission cables across the Unison network.
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.
A pilot project is underway consisting of thirteen weather stations and twenty line temperature sensors on a critical 33kV line (Onekawa D). The data from these weather stations will be fed into an algorithm to determine the lines dynamic rating and the outputs validated in conjunction with the temperature sensor data. Analysis of the data is ongoing and subject to the success of the pilot, weather stations will be installed on other overhead 33kV feeders which will allow the control room to maximise the utilisation of critical sub-transmission circuits.
Power Transformers Unison is utilising Transformer Monitoring Sensors (TMS) to measure factors that could impact on the set design rating of its 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.
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Progress has been made retrofitting existing transformers with this technology. It is expected that the remaining transformers on Unison’s network will be completed by the end of 2012/13 financial year.
Powersense Sensors This technology uses state of the art fibre sensors to provide accurate current, voltage and fault passage information in real time 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. Over the past six months, Unison has successfully trialed both the overhead line and underground cable sensors and plans have been put in place to strategically deploy these sensors across Unison’s network. Once commissioned, these sensors will help the control room operators find faults quickly thereby reducing outage times experienced by consumers. Furthermore, the data will be used by engineers to determine which parts of the network need augmenting.
Figure 5-14: Powersense Current Sensor
5.6 Network Development Options Available
5.6.1 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. SECTION 5 NETWORK DEVELOPMENT PLANS 5-35 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
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:
Toolbox
Constraint Network Solution Non Network Solution
Voltage Constraints Upgrading conductor Reactive VAr compensation Install additional feeder Mobile technology Install voltage regulators Load transfer DG Capacity Constraints Upgrading conductor Reactive VAr compensation Install additional feeder Load transfer DG Install additional transformer Demand side Management Establish new substation Real Time Monitoring Breakers Exceeding Ratings Replace breaker Decrease fault level by: Substation earthing compensation Network re-configuration DG Quality of Supply, e.g. dips, Install additional feeder Consumer specific behind the meter solutions harmonics, flicker Install additional substation (SVC) transformer Replace mobile technology with reactive VAr compensation GFN Re-configure the network Network Security Install additional feeders Smart Technology Establish new substation DG Install additional transformer Load transfer Install more re-closers Reactive VAr compensation Demand Side Management Network reconfiguration Network Reliability Install re-closers Network re-configuration Install additional feeders DG Intelligent re-closers Substation earthing compensation Consumer specific behind the meter solutions Fast protection GFN Self Healing
Table 5-6: Network option toolbox 5-36 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
5.6.2 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 a 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.
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. SECTION 5 NETWORK DEVELOPMENT PLANS 5-37 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
5.7 Network Development Plan
5.7.1 Central Region
5.7.1.1 Network Development Programme for 2012/13
Constraint No. 1 During peak load conditions, a number of feeders do not comply with 11kV voltage regulation.
Description Through network analysis and modeling, Kaharoa and Waikato feeders have been identified as having poor 11kV voltage regulation under peak loading conditions. Waikato is of particular importance as it provides back feeding capability to the Taupo North feeder which supplies a high number of customers. Historically, given a feeder fault on Taupo North, back feeding via Waikato has been unsuccessful due to low voltage. Kaharoa is a long rural feeder which requires voltage support due to new connections at the end of the feeder. Moreover, Kaharoa provides back feeding options for Dalbeth feeder. The risk of not rectifying the constraint is that it will lead to an increase in customer complaints due to low voltage, and increase in interruption to customers particularly in the Kinloch region.
Possible Solutions Class of Option Description Advantages Disadvantages or Risks Cost
Network Install voltage Can be used to solve the voltage Expensive. $200k each regulator to constraint irrespective of the load Easements are required at improve the 11kV type (inductive, resistive etc). optimal sites. voltage Can cater for long term load growth Add additional load on the feeder. on the feeder.
Upgrade Can solve the problem long term Very expensive. $1.5m conductor and thereby improving back feed Easements are required. reliability. Substantial amount of conductor Can cater for long term load growth upgrade is required on all 3 on the feeder. feeders (approximately 5-10km).
Non-Network Install pole top Cheapest option. Can be used only near inductive $150k capacitor banks Provide reactive VAR to high loads. reactive loads, thereby, reducing Amplify harmonics and may the feeder load current. cause resonance. Can interfere with ripple load control signal on Waikato feeder (725Hz). Variable voltage control is not possible.
Install mobile Can provide voltage support during Consent is required from local $200k each regulators during peak demand period. authorities, Iwi or Transit. peak loading Can be utilised elsewhere on the Health and safety issues conditions network. associated. Provides flexibility in back feeding capability. 5-38 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Class of Option Description Advantages Disadvantages or Risks Cost
Do Nothing No capital investment required. The feeders will not comply with N/A the voltage regulations. Increase in customer complaints due to under voltage.
Preferred Option & Justification Install Voltage Regulator on Waikato feeder on SH1 ($200k). Install Voltage Regulator on Kaharoa feeder on Hoko Road ($200k).
This option is selected as the preferred solution, since it provides back-feed capability to the adjacent feeders such as Taupo North and Dalbeth which have high number of faults. This solution will cater for future load growth on the above- mentioned feeders. The alternative solutions were discounted for the following reasons:
Installation of capacitor bank will somewhat relieve the load flow on the feeders providing they are installed at strategic locations (closer to high reactive sources). These capacitors will be rated to meet the kVAr of irrigation loads. Hence, the size of the capacitor banks is likely to be smaller. This however does not provide the flexibility to back-feed the adjacent feeders given a feeder fault.
Conductor upgrade is uneconomic and will not provide the same voltage support as other options detailed in the table above.
Installation of mobile regulators is not an ideal solution, because concerned feeders have identical load profiles and same peak load periods. This means that a number of mobile regulators will need to be designed and manufactured. This becomes much more expensive than installing voltage regulators at permanent locations.
Do nothing is an option, however, the number of customer complaints will rise, and contribute towards exceeding of Unison’s customer complaint threshold. The cost to provide compliant voltage to rural customers will cumulate and exceed the cost of installing voltage regulators on the 11kV backbone.
SECTION 5 NETWORK DEVELOPMENT PLANS 5-39 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Voltage Regulator
1
Figure 5-15: Install voltage regulator on Waikato feeder
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Voltage Regulator
Owhata GXP
Figure 5-16: Install voltage regulator on Kaharoa feeder
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Constraint No. 2 Load on a number of 11kV feeders exceed firm capacity.
Description A number of feeders in the Owhata Region do not comply with Unison’s security criteria. In particular, Te Ngae, Lynmore and Kaharoa are heavily loaded and have been identified as the most vulnerable feeders in the region through the analysis tools. Te Ngae and Kaharoa feeders supply the industrial and sensitive loads in the region, and it is critical that continuous supply is maintained to those customers. Furthermore, these feeders from Owhata have to provide back feeding options for Arawa feeders. The lack of investment will lead overloading of the abovementioned 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 Offloads identified capacity High civil costs in areas that $1m from Owhata and constrained feeders. are already established. Arawa substations Ensures feeders are compliant with Requires installation of new Unison’s security standards, well into CB at Arawa zone substation the next planning period. and Owhata POS. Provides additional 11kV Approximately 2km of cable is interconnectivity. required from Arawa substation and 2.5km of cable/overhead from Owhata is required.
Upgrade constrained Provides spare capacity on the feeder Disruption to existing 11kV $520k section of the feeder until end of planning period for present feeders in the same trench and forecasted load. and foreseen outages during Shared civil costs. works. Defers the capital expenditure required for establishing Vaughan Road ZS.
Provide new Offloads identified capacity constrained Due to network architecture, $250k interconnection with a feeders. heavily loaded feeders cannot lightly loaded feeder Provides additional 11kV be offloaded substantially. from Biak Street interconnection and flexibility to Only a short term option, and feeder(s) and transfer backstop. will not meet security load standards after 5 year period.
Easements are required as shorter cable route is through private properties.
Non-Network Install capacitor bank at Reduces feeder loadings Requires additional circuit $150k Owhata POS Will reduce loading on all feeders breaker at Owhata POS. 5-42 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Class of Option Description Advantages Disadvantages or Risks Cost supplied from both substations. Only a short term solution (1- 5 years) as the reactive consumption is not high on these feeders.
Encourage Distributed Can mitigate present and future feeder Connections are at ad hoc Unknown4 Generation (DG) capacity constraints. basis, and cannot be Long term benefits in deferral of capital predicted. expenditure. The connected DG may not be of reliable source such as renewal.
Increase the ability to Reduces the feeder loads during peak Requires the local retailers to Ongoing5 control hot water in the load conditions. replace ripple relays. Owhata region Deferral in reinforcement of cable.
Do Nothing Operate assets up to Least cost option Limitation on back feed N/A their maximum limits capabilities. Non compliant with Unison’s security standards.
Preferred Option & Justification The preferred options for increasing the capacity headroom for the constrained feeders are:
1. Upgrade constrained section of Kaharoa and Te Ngae feeders from Owhata GXP to the Corner of Gee Road and Fairbank Road ($320k); 2. Upgrade Lynmore, Owhata, Rotoma and Okere feeders from Owhata GXP to the termination structure on Gee Road ($200k). 3. Improve hot water control.
The first two options combined provide a long-term solution to the constrained feeders, and other feeders in the region. Upgrading the constrained section of the feeder cable is economical compared to other options because a short length needs to be augmented and the civil cost will be shared.
Option 3 is considered to be implemented within the next 5 years, as it requires the retailer to replace the ripple relays. Unison sees a good probability of this occurring due to SMART meter rollouts, and the maintenance program of the retailers.
4 DG projects are treated as customer projects; customer contributions are project specific 5 Maintenance cost of the ripple plant equipment at the Zone Substation SECTION 5 NETWORK DEVELOPMENT PLANS 5-43 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Owhata GXP
Figure 5-17: Upgrade the front ends of Owhata feeders
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Owhata GXP
Figure 5-18: Upgrade the front ends of Owhata feeders
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Constraint No. 3 There is a risk of high SAIDI impact on 11kV feeders due to faults in the Taupo region.
Description There are a number of factors in the Taupo network which make this region particularly prone to faults causing high SAIDI. Fleet Street substation contains only one transformer meaning supply security for this substation comes solely via the 11kV network. Currently there are many switch points capable of connecting to the 11kV feeders of Fleet Street to the adjacent feeders of Runanga and Taupo South substations. However, these are manually operated causing delays in supply restoration and contributing to high SAIDI.
The 11kV network itself is vulnerable to faults, particularly long overhead feeders. In some cases two feeders can be on the same pole structure making them high risk to third party damage such as car versus pole incidents. In order to restore supply the damaged portion of network must be isolated. There is some protection equipment in Taupo for this purpose but in general the ability to remotely restore supply is lacking.
Possible Solutions
Class of Description Advantages Disadvantages or Risks Cost Option
Network Underground parts of feeders Reduces the risk. Very expensive. $5.6m in the urban areas and Improves reliability. Geothermal areas will de-rate introduce alternative Overhead Can be used to address cables. paths in semi rural areas capacity constraints.
Non-Network Implementing self healing Improves reliability. High initial set up cost. $900k technology. This will be Automated restoration of supply Line of sight communication is implemented in conjunction to consumers within one minute. required between switches. with the remote controlled Provides useful planning Increase in maintenance costs due switches information from devices. to additional equipment. Enables automated load shifting based on seasonal profile. Improves the Radio Mesh network in the area which in turn improves coverage for smart metering.
Do Nothing Least cost option. Contribute towards, and can lead N/A to breaching Unison’s Service Level and Network Reliability Targets.
Preferred Option & Justification Installing automated switches is in alignment with Unison’s intention to deploy Self Healing and fast transfer technology in the Taupo Region. This will increase the granularity of load transfer and improve automated fault response. The smart switches will also provide useful network planning data that will feed into simulation tools used at Unison. This will give the engineers greater ability to understand the nature of loads on each feeder.
5-46 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Much of Taupo Central and Taupo South districts were completed in 2011/12. The project work for 2012/13 will complete the work in these regions and focus on the Northern feeders from out of Runanga zone substation.
Undergrounding is not regarded as a viable option as it is too expensive
Fleet Street Substation Ashwood Taharepa Miro Hilltop
Fletchers
Taupo
South
Taupo South
Runanga
Figure 5-19: Automated switches in Fleet Street zone substation's 11kV network
SECTION 5 NETWORK DEVELOPMENT PLANS 5-47 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Switch normally closed, 2011/12
Switch normally open, 2011/12
Switch normally closed, 2012/13
Switch normally open, 2012/13
Taupo South Substation
Richmond Botanical Wharewaka Rainbow Lake Tce
Fleet Fleet
Street Street Runanga
Figure 5-20: Automated switches in Taupo South 11kV network
5-48 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Runanga Substation
Heuheu Heuheu Paora Hapi Opepe Waikato Lomond Ben Nukuhau Horomatangi Roberts Acacia Bay Taupo North
Taupo South Fletchers Fleet Street
Ohaaki Fleet Street
Fletchers
Fleet Fleet Street Street
Figure 5-21: Automated switches in Runanga 11kV network
SECTION 5 NETWORK DEVELOPMENT PLANS 5-49 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Section 4 Taupo Northeast 2012/13 Section 3 Taupo Northwest 2012/13
Section 2 Taupo Central 2011/12
Section 1 Taupo South 2011/12
Figure 5-22: Overview of smart network in Taupo
5-50 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Constraint No. 4 Risks associated with common bus configuration switches in Rotorua region.
Description The majority of RMU sites in the Rotorua CBD area have 5 or more common bus switch configurations, with two or more feeders connected to them. This configuration is vulnerable to multiple tripping of 11kV feeders in the event of bus faults or third party damage which would affect a large number of customers. Moreover, most of the switches are manually operated with no fault passage indication which causes delays in supply restoration and contributes to a high SAIDI.
Possible Solutions
Class of Description Advantages Disadvantages or Risks Cost Option
Network Change open points to Reduces the risk of multiple Loose interconnectivity between N/A minimise risks. tripping of 11kV feeders in the 11kV feeders. event of bus faults. Option limited by network Improves reliability. topology. Can be used to address capacity constraints. No cost option.
Non-Network Replace the identified RMU Improves reliability. High initial set up cost. $1m sites with automated safelink Automated restoration of supply Increase in maintenance costs due switches. to consumers within one minute. to additional equipment. Provides useful planning Easements may be required from information from devices. land owners to install new Enables automated load shifting equipment. based on seasonal profile. Improves the Radio Mesh network in the area which in turn improves coverage for smart metering.
Do Nothing Least cost option. Contribute towards, and can lead to N/A breaching Unison’s Service Level and Network Reliability Targets.
Preferred Option & Justification The preferred option is to replace the identified RMU sites in Rotorua CBD with automated safelink switches to improve reliability.
Installing automated switches is in alignment with Unison’s intention to deploy smart network in the Rotorua Region. It will increase the granularity of load transfer and improve automated fault response. The smart switches will also provide useful network planning data that will feed into simulation tools used at Unison. This will give the engineers greater ability to understand the nature of loads on each feeder.
SECTION 5 NETWORK DEVELOPMENT PLANS 5-51 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Figure 5-23: Identified switches to be replaced in Rotorua
Figure 5-24: Switches to be replaced in Rotorua 5-52 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
5.7.1.2 Network Development Programme for the period 2013/14 to 2017/18 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 No. 1 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 Inexpensive. Needs personnel on site to identify $40k indicators and Gives approximate location of a fault approximate location of fault. temporary data between indicator points. Needs visit to site by technical loggers at strategic Gives feeder load and fault current personnel to setup data loggers locations along the data if logger happens to be installed and download fault and load feeder route at time of fault. current information. Information is not received in real time, it requires human intervention in the field.
Non-Network Use data sensors at Cost-effective solution. Temporary solution (10-15 years). $620k strategic locations to Real time data available for planners Increased network complexity. collect and convey and operators. data via the Reduced restoration times. communications Can be integrated into fast transfer network to enable rapid transfer of loads and self healing. to surrounding feeders Can be used for self healing after network faults.
Do Nothing Operate assets up to No capital investment required. Unison is likely to breach its N/A their maximum limits service level targets and network reliability targets for the customers.
SECTION 5 NETWORK DEVELOPMENT PLANS 5-53 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
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.
5-54 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Constraint No. 2 Unison cannot feed new loads from Fletchers zone substation due to land issues.
Description Unison currently supplies 1MVA (peak load) toward Solid Energy’s premises from Fletchers zone substation in Taupo. They have indicated that they expect to increase their maximum demand to 8.5MVA by 2016/17. Only the Carter Holt 11kV feeder is fed from Fletchers at the moment. Land issues prevent Unison from adding more 11kV feeders to Fletchers zone substation. The single existing 11kV feeder is not able to handle the increased load, and neither does it provide N-1 security to Solid Energy.
Possible Solutions Class of Description Advantages Disadvantages or Risks Total Cost Option
Network Install a dedicated 33kV Easement issues avoided. N-1 security is a major $3.8m feeder and 33/11kV Spare capacity for load growth concern. power transformer to elsewhere in the network. Interconnectivity, needed to feed Solid Energy. Place Ability to meet the customer’s demand offload other zone substations the transformer on their of 8.5MVA and more. and feeders not good. premises Difficulty to handle load growth in the area.
Build a new zone Defer the installation of the second Major Capex work. $2.7m substation next to transformer at Fleet Street. Centennial Drive, and Offload Runanga onto the new move Fletchers’ Rakaunui Road zone substation. transformers to the new Avoid land issues around Fletchers site (Rakaunui Road) zone substation. New zone substation favorably located to supply new loads in its vicinity.
Install three new 11kV Conventional solution. New 11kV circuit breakers $3.1m cables to feed Solid Not the most expensive option. required, and Unison does not Energy from Fletchers own the entire 11kV zone substation switchboard at Fletchers. Overload 33kV cables to Fletchers; reinforcement needed. Potential easement issues to supply Solid Energy from Fletchers.
Preferred option Construct Rakaunui zone substation next to Centennial Drive, and move Fletchers substation’s existing transformers to the new site.
The investment deferrals that it brings about in other parts of the network, along with the fact that it is suitably located to accommodate new loads, make the investment worthwhile. It also happens to be the least cost option.
SECTION 5 NETWORK DEVELOPMENT PLANS 5-55 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Constraint No. 3 During peak load conditions, a number of feeders are forecast to breach 11kV voltage regulation thresholds.
Description Through network analysis and modeling, Ngakuru, Mamaku, Tarawera and Waikite 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 non-network 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 Can be used to solve the voltage Expensive. $200k to improve the 11kV constraint irrespective of the load type Easements are required at each voltage (inductive, resistive etc). optimal sites. Can cater for long term load growth on Add additional load on the the feeder. feeder.
Upgrade conductor Can solve the problem long term and Very expensive. $1.2m thereby improving back feed reliability. Easements are required. Can cater for long term load growth on Substantial amount of the feeder. conductor upgrade is required on all 3 feeders (approximately 5-10km).
Non-Network Install capacitor banks Cheapest option. Can be used only near $100k Provide reactive VAr to high reactive inductive loads. loads, thereby reducing the feeder load Amplify harmonics and may current. cause resonance. Can interfere with ripple load control signal. Variable voltage control is not possible.
Install mobile regulators Can provide voltage support during peak Consent is required from $200k during peak loading demand period. local authorities, Iwi or each conditions Can be relocated to other parts of the Transit. network. Health and safety issues Provides flexibility in carrying out associated. maintenance or planned work instead of load dependent.
Do Nothing No capital investment required. The feeders will not comply N/A with the voltage regulations. Increase in customer complaints due to under voltage.
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Preferred Option & Justification 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.
SECTION 5 NETWORK DEVELOPMENT PLANS 5-57 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Constraint No. 4 Problematic network security to Fonterra Milk Processing Plant at Reporoa.
Description Fonterra’s Reporoa milk processing plant is supplied from Unison’s Fernleaf substation, approximately 40km from Rotorua GXP. This substation is supplied via a single 33kV overhead 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 times. 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 has requested options for an improvement in security of supply to cater for existing and future load.
Fernleaf is classified as a “L4”-type load in terms of Unison’s security criteria. This means that Unison would have to restore 100% of the maximum demand within 4 hours for a single contingency event. This is quite possible for a line fault, but unlikely for a transformer fault. Installing a second transformer at Fernleaf therefore makes sense from a security as well as a capacity (voltage regulation) point of view, since the two transformers, in parallel, are expected to boost voltages by two less taps under peak load conditions.
Possible Solutions Class of Option Description Advantages Disadvantages or Risks Cost
Network 33kV Supply from Improved security of supply at Fernleaf Easement required to build 33kV $2-3m Wairakei via Ohaaki substation (N-1). circuit between Ohaaki and Provides high reliability to the Fernleaf. customer. Longer feeder route.
33kV Supply from Improved security of supply at Fernleaf Upgrade of Contact Energy’s $3-5m Ohaaki substation (N-1). infrastructure. Provides high reliability to the Easement required to build 33kV customer. circuit between Ohaaki and Fernleaf.
33kV Supply from Improved security of supply at Fernleaf An agreement is required with $5-6m Otto Road substation (N-1). TrustPower. Provides high reliability to the Very expensive as 110kV/33kV customer. station is required. Short 33kV feeder route (5km).
New 33kV feeder from Improved security of supply at Fernleaf High maintenance and first $8m Rotorua GXP substation (N-1). response cost due to terrain and Provides high reliability to the weather related faults. customer. New infrastructure at Rotorua GXP is required. Fault detection will be difficult. Fast protection cannot be implemented due to distance. 5-58 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Class of Option Description Advantages Disadvantages or Risks Cost
Network Install second Mitigates looming voltage regulation More expensive than adding a $1.5m transformer at problems at Fernleaf 11kV. single capacitor bank to enhance Fernleaf to enhance Enhances network security – power voltage regulation. capacity and network transformer N-1. security in the interim Ties in well with plans for a 33kV feed from Wairakei. Installing a capacitor bank does not enhance network security.
Network New 11kV feeder from Lower cost option. Customer will experience low $2m Ohaaki voltage. Does not provide the same level of security as other 33kV options. Easement is required.
Non-Network Install 6 x 700kVA Secure supply. High running cost. $2-3m6 diesel generators - Running time reliant on diesel (Onsite generation) reserve. Environmental issues involved.
Do Nothing No capital expenditure. Customer relations will suffer. N/A
Preferred Option & Justification Construct a new 33kV line from Ohaaki to Fernleaf substation. This line will bypass Ohaaki substation to avoid land issues. 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 has purchased the Transpower owned 33kV line between Wairakei and Ohaaki, and plans exist to extend the 33kV network up to the Fernleaf substation along SH5 (approximately 12km). Fernleaf substation will be reconfigured to accommodate an additional 33kV 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.
It is proposed to install a second transformer (a new unit; associated switchgear included) at Fernleaf zone substation in 2016/2017 at a cost of $1.5 million. This investment will enhance network security and mitigate looming voltage regulation problems. Very importantly, it ties in well with plans to establish a second 33kV feed into Fernleaf substation from Wairakei GXP.
6 Does not include running costs SECTION 5 NETWORK DEVELOPMENT PLANS 5-59 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Constraint No. 5 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 11kV feeders cannot cater for the magnitude of the growth due to existing feeders’ ratings and projected voltage regulation issues. Additional feeders cannot be installed from Ohaaki due to the land ownership issues.
Possible Solutions Class of Option Description Advantages Disadvantages or Risks Cost
Network Upgrade constrained Provides spare capacity on the feeder Can cater load growth only $150k section of the feeder until end of planning period for present up to 2015. loads. Does not provide backstop Lower cost, since 11kV reticulation is flexibility due to high load simple (approx 100m) cable. and limited 11kV interconnectivity. Easement is required.
Establish new feeder from Offloads identified capacity constrained Easements are required. $750k Ohaaki POS feeders. Requires installation of new Ensures feeders are compliant with CB at Ohaaki zone Unison’s security standards, well into the substation. next planning period. Approximately 5km of cable Provides additional 11kV is to be installed. interconnectivity.
Establish a new zone Offloads identified capacity constrained Substantial investment. $3m substation at Te Toke feeders. Requires land purchase for Road. Ensures feeders are compliant with zone substation site. Unison’s security standards, well into the next planning period. Provides additional 11kV interconnectivity. No major easements required.
Non Network Install pole top capacitor Low cost option. Ideal location is hard to $100k banks to manage feeder Capacitors counteract reactive power identify due to lack of loads flow and thereby solve the core problem customer installation data rather than just boosting the voltage. (e.g. consumption – kW, kVAr). 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.
Install thermal resistivity Increased asset utilisation. The feeder ratings may be $100k sensors every 300m in the lower than expected. 5-60 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Class of Option Description Advantages Disadvantages or Risks Cost
trench Deferral of cable upgrade. Insufficient capacity gain to sustain load growth.
Do Nothing Least cost option. Currently acceptable, but N/A will increase to an unacceptable level within the next two years due to organic load growth.
Preferred Option & Justification The long-term solution for the identified constraint is to establish Te Toke zone substation. This solution provides additional 11kV feeders and interconnectivity in the exact area where the load growth is expected. Network alteration at Ohaaki is not viable due to land issues along with the distance between Ohaaki and the expected loads.
Upgrading the constrained section of the feeder does not provide a long-term solution. Unison’s load forecast indicates that the upgraded feeders will not have sufficient capacity to sustain the load growth and meet backstopping requirements for neighboring feeders.
SECTION 5 NETWORK DEVELOPMENT PLANS 5-61 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Constraint No. 6 High industrial load growth in the outskirts of Rotorua.
Description High load growth is expected in the outskirts of Rotorua, which consists of commercial, light industrial and recreational loads. Furthermore, an existing industrial customer considers disestablishing embedded generation, which will add load to Unison’s 11kV network. The expected load increase is likely to be 5-10MVA. There is a single 11kV supply that feeds this customer, with one backstop, namely the 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 Offload identified capacity Easements are required. $2m Rotorua POS constrained feeders. Requires installation of new Ensures feeders are compliant circuit breakers at Rotorua zone with Unison’s security standards substation. well into the next planning period. Approximately 3km of cable to Provides additional 11kV be installed. interconnectivity. High civil costs in established areas. Two feeders are required to meet the expected load growth.
Establish a substation near Offload identified capacity Easement is required to $3-4m7 the industrial customer constrained feeders. establish 33kV supply. Ensures feeders are compliant Fernleaf 33kV feeder will with Unison’s security standards require an upgrade to sustain well into the next planning period. the increased load. Provides additional 11kV interconnectivity. No major easements required. Customer driven project.
Do Nothing Least cost option. Missed revenue. N/A Strain relationship with one of Unison’s largest consumers.
7 Customer contribution is yet unknown 5-62 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Preferred Option & Justification The preferred solution is to establish a new substation in close proximity to the industrial customer. This will bring about improved security of supply and ample capacity for the forecast load growth. Unison has already upgraded a section of line to 33kV construction, and is operating it at 11kV.
The customer prefers this solution due to improved reliability, capacity, and cost. There is no viable non-network solution available to cater for the load growth. Having a zone substation at the southern end of Rotorua opens an opportunity for Unison to feed other loads in close proximity from it, which will relieve more predicted future constraints.
SECTION 5 NETWORK DEVELOPMENT PLANS 5-63 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Constraint No. 7 Capacity and security risks on the dual 110kV feeders between Rotorua and Tarukenga GXP’s. These lines belong to Transpower.
Description A number of Rotorua substations, namely Arawa, Biak Street, Fernleaf, and Rainbow, along with Rotorua POS 11kV loads are supplied via the Rotorua GXP at Malfroy Road. The sum of these substations’ loads is expected to exceed the N-1 emergency rating of the individual 110kV circuits that supply Rotorua GXP.
Possible Solutions Class of Option Description Advantages Disadvantages or Risks Cost
Network 1. Establish new 33kV Offloads identified 110kV feeders. Easements required for 33kV $6m connection at Owhata Ensures feeders are compliant supply. GXP with Unison’s security standards, High cost. 2. Establish new well into the next planning period. substation on eastern Improve network interconnectivity. side of Rotorua 3. Establish 11kV feeders between Arawa and the new substation
Re-rate dual 110kV Ensures feeders are compliant Risk: Dual 110kV circuits on $0.7m circuits into Rotorua with Unison’s security standards, the same pole structures well into the next planning period. support a significant part of the Fits well into plans to upgrade network in Rotorua. 110/11kV transformers at Owhata POS.
Non Network Install capacitor bank at They improve network capacity New circuit breaker required at $150k substations to reduce load and voltage levels. Arawa substation. flow in the feeders Offloads identified capacity Harmonic resonance can be a constrained feeders. problem.
Do Nothing Least cost option. Customer outages can be N/A expected if a fault occurs during peak load periods.
Preferred Option & Justification The option to re-rate the dual 110kV feeders between Rotorua GXP and Tarukenga GXP yield very good value for money. It is expected the enhanced capacities will be adequate for the next planning period.
5-64 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Constraint No. 8 Rotorua POS peak loads exceed the existing transformers’ post-contingency ratings.
Description The peak loads at Rotorua POS exceed 27MVA, while the existing 110/11kV transformers can sustain 26MVA for two hours. The existing transformers consist of single-phase units that are interconnected to form three-phase units.
Possible Solutions Class of Option Description Advantages Disadvantages or Risks Cost
Network Off-load Rotorua POS Use spare capacity that exists at Possible problems with old N/A 11kV loads to surrounding Biak Street. transformers and tap changers zone substations at Rotorua POS. Arawa substation also loaded to capacity.
Install new 30MVA Resolves problems associated with The load fed from Rotorua POS $2m 110/11kV transformers at old transformers. becomes significant, which can Rotorua POS Creates spare capacity for future make back-feeding difficult. load growth. Harvest synergy between renewal and augmentation expenditure.
Non Network Use smart network to shift Low cost option. Not a permanent solution. TBD loads between GXP’s The smart network can perform Transformers not renewed. when needed self-healing after faults on 11kV feeders.
Do Nothing Least cost option. Large scale customer outages N/A can be expected if a fault occurs during peak load periods.
Preferred Option & Justification Renew the 110/11kV transformers at Rotorua POS. Transpower will replace the single-phase transformer banks with three-phase units as a policy conversion. The capacity of the new transformers will be agreed with Transpower. The increased transformer capacity will be in line with future demand from Rotorua POS, and looming problems with aged tap changers can be avoided.
SECTION 5 NETWORK DEVELOPMENT PLANS 5-65 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Constraint No. 9 The 33kV network security for Taupo South and Fleet Street zone substations will become problematic due to load growth in the future.
Description Taupo South zone substation supplies a peak load in excess of 6.5MVA, while Fleet Street zone substation’s peak load is 6.8MVA. Unison should therefore be able to restore supply to all affected customers from either substation within thirty minutes for a single contingency event as prescribed by the network security criteria.
Unison’s smart network can offload Taupo South and Fleet Street zone substations, but the existing smart infrastructure will become inadequate by the time that Taupo South’s load has increased by another 1MVA.
Possible Solutions Class of Description Advantages Disadvantages or Risks Total Cost Option
Network Install a new 33kV tie to Create a new 33kV ring that can feed Cost. $2.4m link Fleet Street and from both bus sections at Centennial Taupo South at the 33kV Drive Switching Station. level One feeder resolves two network security constraints. Costs and work load can be spread over multiple financial years. Ducts are in place already.
Create new 11kV feeders Can be done as a sequence of smaller Difficulty with easements. TBD to enhance fast transfer projects. Complexity. capabilities between Not the ideal long term Taupo South and Fleet solution. Street substations
Install a second Long term solution. Cost. $1.1m transformer at Fleet Street Selectively upgrade the network by to enhance N-1 ability of adding an item that takes the longest to the network repair or replace.
Non-Network Offload Fleet Street and No capital investment needed. Peak loads at Runanga $0 Taupo South Loads to already problematic. other zone substations Timing for Rakaunui Road zone substation not 100% certain.
Do nothing No investment needed. Breach our network security $0 criteria. Harm Unison’s public image. Potentially breach network reliability thresholds.
5-66 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Preferred Option & Justification Construct a 33kV tie between Fleet Street and Taupo South zone substations circa 2015-17. Unison’s strategy is to install the circuit breakers first, the cables in the next year, and spread the expenditure and workload in doing so. The new 33kV ring network created by this project will tie in well with the bus zone protection that Unison plans to install at Centennial Drive 33kV switching station.
Unison will install the second transformer at Fleet Street substation when the smart network’s ability to transfer load away from it becomes problematic.
This long-term solution will enhance the flexibility and reliability of Unison’s sub-transmission network in Taupo for many years to come.
SECTION 5 NETWORK DEVELOPMENT PLANS 5-67 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
5.7.1.3 Network Development Programme for 2018/19 until 2021/22 As with section 5.7.1.2 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.
5-68 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Constraint No. 1 Load growth in the Kinloch and Mapara regions and network reliability issues for existing customers in Kinloch.
Description Substantial long-term load growth is forecast by local developers and Taupo District Council (TDC) for the Mapara and Kinloch region. The zoning will allow existing farmland to be converted to lifestyle and residential areas within the next 5-10 years, and the resulting load increase is expected to be 3-5MVA. The delayed development of WEKA (Western Kinloch Arterial) may slow load growth. TDC has indicated that it may take ten more years before WEKA will be constructed.
There are two feeders that supply the Mapara and Kinloch regions at the moment. Both feeders are approximately 10km from Runanga zone substation. As discussed earlier, the region has security of supply issues due to the lack of backup supplies, and the 11kV voltage regulation is problematic when back feeding during contingencies. The existing supplies will not be adequate to support the new load growth. Neither will it provide a secure supply to new residential and commercial customers.
Possible Solutions Class of Option Description Advantages Disadvantages or Risks Cost
Network Establish a new 11kV Offloads identified capacity Easements may be required. $1.5m feeder from Runanga constrained feeders. Requires installation of new circuit zone substation to Ensures feeders are compliant with breaker at Runanga zone Mapara Valley Unison’s security standards, well substation. into the next planning period. High civil costs in areas that are Provides additional 11kV already established. interconnectivity. Complex river crossings Approximately 10km of underground/overhead network to be installed.
Establish Kinloch Offloads identified capacity High cost. $3-4m substation constrained feeders. Easement required. Ensures feeders are compliant with Uncertainty with delays in WEKA Unison’s security standards well into designation and construction. the next planning period. May require asset relocation. Provides additional network interconnectivity. Unison owns the land already.
Install mobile generators Ensures feeders are compliant with High running cost. $50k during contingencies Unison’s security standards. Not a long-term solution. Can mitigate present and future Environmental issues. feeder capacity constraints. Noise. Long term benefits in deferral of capital expenditure.
Non Network Install pole- top Low cost option. Ideal location is hard to identify $150k capacitor banks to Capacitors counteract reactive due to lack of customer installation minimise reactive power power flow and thereby solve the data (i.e.: consumption – kW, SECTION 5 NETWORK DEVELOPMENT PLANS 5-69 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Class of Option Description Advantages Disadvantages or Risks Cost flow on existing feeders core problem rather than just kVAr). boosting the voltage. VAr requirements of the feeders not fully understood. Another investment possibly required to ensure feeder is compliant with security standard. Not a long-term solution. Resonance with ripple signals.
Connect to the Provides alternative 11kV supply. Conductor upgrade is required as TBD neighbouring distribution Improves reliability by splitting up the the network assets are comprised company assets (11kV lengthy rural feeder. of smaller conductors. network) and establish a Secure supply to remote areas. An agreement between both connection agreement parties is required. Lower cost option.
Do Nothing Least cost option. Unison is likely to breach service $0 levels and network reliability thresholds.
Preferred Option & Justification The long-term solution is to establish a new zone substation at Mapara Road to cater for load growth. Unison already owns a suitable site for the new zone substation. There are still uncertainties surrounding 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 periods to handle contingencies.
The main benefit of the long-term solution is that long rural feeders such as Waikato, Taupo North and Acacia Bay can be shortened, and customer numbers on these feeders consequently reduced. This will improve the 11kV interconnectivity in the region, which is currently problematic.
5-70 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
5.7.1.4 Reporoa Network Architecture – Long Term View
Rotorua POS Arawa ZS
Rainbow ZS
Fernleaf ZS
Circa
Ohaaki ZS
Te Toke ZS – Circa’14/15
Wairakei GXP
Figure 5-25: Overview of existing and proposed network assets at Reporoa SECTION 5 NETWORK DEVELOPMENT PLANS 5-71 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
ROTORUA GXP 33kV ROTORUA
Rainbow
ATIAMURI 11kV
Fernleaf Key Proposed Circuit Circa 2020/21 Existing Circuit
Proposed Substation Ohaaki Existing Substation
Circa 2014/15
Te Toke
WAIRAKEI GXP 33kV
Figure 5-26: Reporoa 33kV sub-transmission - proposed
5-72 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
5.7.1.5 Rotorua Network Architecture – Long Term View
Tarukenga POS
Vaughan Road ZS - circa 2019/20
Owhata POS Biak Street ZS Circa 2013
Rotorua POS Owhata GXP Circa 2019/20 Arawa ZS
State Mill ZS - circa 2014/15
Figure 5-27: Overview of existing and proposed network assets - Rotorua SECTION 5 NETWORK DEVELOPMENT PLANS 5-73 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
ROTORUA GXP 33kV ROTORUA 11kV
TARUKENGA 11kV Arawa Biak Street
State Mill Road
Circa 2014/15 Rainbow
Fernleaf Key Proposed Circuit
Existing Circuit
Proposed Substation
Existing Substation/TP 11kV supply
Vaughan Road
Circa
2019/20
OWHATA GXP 33kV OWHATA 11kV
Circa 2019/20
Figure 5-28: Rotorua 33kV sub-transmission - proposed
5-74 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
5.7.1.6 Taupo Network Architecture – Long Term View
Wairakei GXP
Kinloch ZS: Circa 2018 Rakaunui Rd ZS: Circa 2014
Fletchers ZS
Centennial Drive S/S
Runanga ZS
Fleet St ZS
33kV Tie: 2015-17
Taupo South ZS
Figure 5-29: Overview of existing and proposed network assets – Taupo SECTION 5 NETWORK DEVELOPMENT PLANS 5-75 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
WAIRAKEI GXP 33kV
Rakaunui Rd Tauhara 2013-14 Kinloch Binary Plant
2017-19
Centennial Drive Switching Rotokawa
Runanga Fleet Street
2015-17
Taupo South
Hinemaia Generation
Figure 5-30: Taupo 33kV sub-transmission – proposed
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5.7.2 Hawke’s Bay
5.7.2.1 Network Development Programme for 2012/13
Constraint No. 1 Capacity and security constraint on 11kV feeders supplied from Springfield zone substation.
Description Taradale A and B feeders do not comply with Unison’s capacity and security criteria and 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.
This 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 Offloads identified capacity constraint High civil costs in areas that $1.7m out of Springfield zone feeders. are already established. substation Ensures feeders are compliant with Requires installation of new Unison’s security standards, well into the 11kV circuit breaker at next planning period. appropriate zone substation. Provides additional 11kV interconnectivity. May require building to be extended.
Upgrade the constrained Provides spare capacity on the feeder until Disruption to existing 11kV $400k sections of the two end of planning period for present and feeders in the same trench feeders forecasted load. and foreseen outages Cheaper than installing new feeders as during works. there are no civil costs to extend/modify the building and installing CBs.
Provide new Offloads identified capacity constraint Due to network architecture, $700k interconnection with a feeders. heavily loaded feeders lightly loaded feeder and Provides additional 11kV interconnection cannot be offloaded transfer load and flexibility to backstop. substantially. Only a short term option, and will not meet security standards after 2-3 years. Easements are required as shorter cable route is through private properties. SECTION 5 NETWORK DEVELOPMENT PLANS 5-77 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Class of Option Description Advantages Disadvantages or Risks Total Cost
Non-Network Install capacitor banks to Reduces feeder loadings. Ideal location is hard to $400k reduce feeder loadings identify due to lack of customer installation data (e.g. consumption – kW, kVAr). Lack of VAr requirements of the feeders. Another investment would be required to ensure feeder is compliant with security standard.
Encourage Distributed Can mitigate present and future feeder Connections are at ad hoc Unknown8 Generation (DG) capacity constraints. basis, and cannot be Long term benefits in deferral of capital predicted. expenditure. The connected DG may not be of reliable source such as renewal.
Install soil thermal Calculate accurate cable ratings which will Short term solution $100k resistivity and moisture likely be higher than the existing ratings. (1-2 years). sensors Deferral in reinforcement of cable.
Increase the ability to Reduces the feeder loads during peak load Requires the local retailers Ongoing9 control hot water in the conditions. to replace ripple relays. Hawke’s Bay region Deferral in reinforcement of cable.
Do Nothing Operate assets up to No capital investment required. Unison is likely to breach its N/A their maximum limits service level targets and network reliability targets for the customers.
Preferred Option & Justification The preferred solution for the capacity and security constraint is to upgrade the front end (approximately 1.2km) of the Taradale A and B feeders. These feeders were installed in 1939, therefore it is prudent to upgrade these cables rather than installing new feeders.
The figure following shows the extent of this project
8 DG projects are treated as customer projects and customer contributions are project specific 9 Maintenance cost of the ripple plant equipment at the Zone Substation 5-78 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Pole No. 112130
Pole No. 112148
Pole No. 112140
Pole No. 112149 Legend
Taradale A 11kV Overhead Taradale B 11kV Overhead Taradale A 11kV Underground Taradale B 11kV Underground
Figure 5-31: Upgrade Taradale A and B feeders
SECTION 5 NETWORK DEVELOPMENT PLANS 5-79 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Constraint No. 2 Capacity and security problems at Tamatea zone substation.
Description To provide a partly dedicated 11kV feeder, between Tamatea and Marewa zone substations to assist with the fast transfer, relieve capacity and security constraints at Tamatea zone substation.
The existing Westshore feeder splits in two directions after it leaves Marewa zone substation. It is planned to create a new feeder from the western section of the Westshore feeder by cabling from the feeder split to a new circuit breaker at Marewa zone substation. This will provide a clean dedicated circuit that will link with Durham feeder out of Tamatea zone substation.
Possible Solutions Class of Option Description Advantages Disadvantages or Risks Cost
Network Establish a dedicated Offloads capacity constrained High civil costs in areas that are $2.5m feeder between feeders. already established. Marewa and Tamatea Ensures feeders are compliant with Requires installation of two 11kV zone substations Unison’s security standards, well Circuit Breaker and associated into the next planning period. panels at Marewa and Tamatea Provides additional 11kV zone substations. interconnectivity. Requires building to be extended. Easements are required as shorter cable route is through private properties. Approximately 5 km of cable is to be installed to fully utilise the new feeder.
Spilt Westshore Provides capacity for fast transfer Foreseen outages during works. $190k feeder, install a front between zone substations. end section of cable to Utilises existing 11 kV circuit for the northern branch of the majority of the route. the feeder and install a additional Circuit Break for the new feeder (approximately 180m)
Provide new Offloads identified capacity Due to network architecture, heavily $650k interconnection with a constrained feeders. loaded feeders cannot be offloaded lightly loaded feeder Provides additional 11kV substantially. and transfer load interconnection and flexibility to Only a short term option, and will not backstop. meet security standards after 3 years. Easements are required as shorter cable route is through private properties. 5-80 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Class of Option Description Advantages Disadvantages or Risks Cost
Non-Network Encourage Distributed Can mitigate present and future Connections are at ad hoc basis, Unknown10 Generation (DG) feeder capacity constraints. and cannot be predicted. Long term benefits in deferral of The connected DG may not be of capital expenditure. reliable source such as renewal.
Increase the ability to Reduces the feeder loads during Requires the local retailers to Ongoing control hot water in the peak load conditions. replace ripple relays. Tamatea and Marewa Deferral in reinforcement of cable. area
Do Nothing No capital investment required. There are major security issues at N/A present in this area which if not looked at could cause a large outage if a fault occurs.
Preferred Option & Justification The preferred option is to split the Westshore feeder, create a new feeder and install a front end section of cable to the northern branch of the Westshore feeder.
The figure below shows the extent of this project.
10 DG projects are treated as customer projects and customer contributions are project specific SECTION 5 NETWORK DEVELOPMENT PLANS 5-81 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Figure 5-32: New feeder - Marewa zone substation
5-82 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Constraint No. 3 Security constraint, on isolated section of Ada 11kV feeder.
Description This section of the Ada feeder has no alterative feed facility on the 11kV Network and very limited on the LV Network. There is a connected load of 2.25MVA and 192 customers. The load is greater than can be supplied by a nominal generator and there are critical and commercial consumers on this section of the circuit. Lack of investment will lead to non compliance as there is no ability to back stop to an adjacent feeders during a contingency condition.
This 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 feeder out Offloads identified capacity constraint High civil costs in areas that $1.5m of Windsor zone feeders. are already established. substation Ensures feeders are compliant with Requires installation of new Unison’s security standards, well into the 11kV circuit breaker at next planning period. appropriate zone substation. Provides additional 11kV interconnectivity. May require building to be extended. Approximately 1.2 km of cable to be installed to fully utilise the new feeder.
Upgrade constrained Provides spare capacity on the feeder until Disruption to existing 11kV $400k sections of the feeder end of planning period for present and feeders in the same trench forecasted load. and foreseen outages Cheaper than installing new feeders as during works. there are no civil costs to extend/modify the building and installing CBs.
Provide new Improves security of feeder. Foreseen outages during $150k interconnection with an Provides additional 11kV interconnection works. adjacent feeder and flexibility to backstop. Only a short term option, Easy access along carriageway. and will not meet security standards after 2-3 years. Only 450m of cable to be installed. Easements are required as shorter cable route is through private properties. SECTION 5 NETWORK DEVELOPMENT PLANS 5-83 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Class of Option Description Advantages Disadvantages or Risks Total Cost
Non-Network Install capacitor banks to Reduces feeder loadings. Ideal location is hard to N/A reduce feeder loadings identify due to lack of customer installation data (e.g. consumption – kW, kVAr). Lack of VAr requirements of the feeders. Another investment would be required to ensure feeder is compliant with security standard.
Encourage Distributed Can mitigate present and future feeder Connections are at ad hoc Unknown11 Generation (DG) capacity constraints. basis, and cannot be Long term benefits in deferral of capital predicted. expenditure. The connected DG may not be of reliable source such as renewal.
Install soil thermal Calculate accurate cable ratings which will Short term solution (1-2 N/A resistivity and moisture likely be higher than the existing ratings. years). sensors Deferral in reinforcement of cable.
Increase the ability to Reduces the feeder loads during peak load Requires the local retailers Ongoing12 control hot water in the conditions. to replace ripple relays. Hawke’s Bay region Deferral in reinforcement of cable.
Do Nothing Operate assets normally No capital investment required. If section faults, Unison is N/A likely to breach its service level targets and network reliability targets for the customers.
Preferred Option & Justification The preferred solution for the security constraint is to provide new interconnection with an adjacent feeder.
The figure following shows the extent of this project.
11 DG projects are treated as customer projects and customer contributions are project specific 12 Maintenance cost of the ripple plant equipment at the Zone Substation 5-84 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Figure 5-33: Interconnection between Ada and Grove feeders
SECTION 5 NETWORK DEVELOPMENT PLANS 5-85 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Constraint No. 4 Flaxmere zone substation’s transformers are old, and loaded to capacity.
Description The 2012 peak load for Flaxmere zone substation is 12.6MVA, while the existing transformers are rated for 10MVA continuously. Unison’s standard planning protocol makes provision to load transformers to 120% of their nominal rating for two hours in N-1 situations, which translates to 12MVA in this case.
Given the age and condition of Flaxmere’s transformers, it is urgent to attend to the situation.
Possible Solutions Class of Description Advantages Disadvantages or Risks Total Cost Option
Network Upsize power transformers Long term solution. Cost. $2-3m Renewal of assets.
Transfer loads to other zone No capital investment needed. Create longer feeders, which $0 substations on a permanent are difficult to manage basis operationally. Network reliability will suffer due to longer feeders.
Non-Network Introduce dynamic ratings for Small capital investment needed. Uncertainty: Exact dynamic TBD power transformers ratings under development.
Install a fast transfer scheme Low cost option. Not a long-term solution. $70k to manage contingencies Smart grid facilitates self-healing. Increase network complexity.
Do nothing No investment needed. Breach network security $0 criteria. Potentially harm Unison’s reputation. Potentially breach network reliability thresholds.
Preferred Option & Justification Install a fast transfer scheme in 2012/13 to manage Flaxmere zone substation’s load. Only one automated switch is required for this purpose, which makes it particularly cost-effective. This scheme will create the ability to transfer the Barnes 11kV feeder from Flaxmere to McCain zone substation when needed. The 2012/13 peak load on the Barnes feeder is 2MVA.
5-86 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Barnes Feeder McCainFeeder
Install Automated Switch
Figure 5-34: Fast transfer scheme for Flaxmere zone substation
SECTION 5 NETWORK DEVELOPMENT PLANS 5-87 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Constraint No. 5 Windsor power transformer N-1contingencies potentially problematic.
Description Windsor zone substation currently feeds a peak load of 7MVA. In line with this, Unison’s network security criteria require the ability to restore supply to all affected customers within 30 minutes after a single contingency event.
Unison recently installed a second power transformer at Windsor substation to satisfy the requirements of their network security criteria. Further to this, Unison’s transformer management strategy makes provision to re-deploy Windsor substation’s second transformer elsewhere if another transformer should fail within Unison’s network (similar to a system spare).
It is unlikely that Unison will be able to restore supply to all affected customers within 30 minutes if the second transformer at Windsor substation should fail while the first is deployed elsewhere.
Possible Solutions
Class of Option Description Advantages Disadvantages or Risks Total Cost
Network Buy another system Conventional solution. High cost. $700k spare transformer Ease to deploy system spare Acquire an asset that does transformer. not yield a return on investment immediately.
Non-Network Install a fast transfer Lower cost option. Increase network complexity. $390k scheme to manage Smart grid facilitates self-healing contingencies after network faults.
Do nothing No investment needed. Breach network security $0 criteria. Potentially harm Unison’s reputation. Potentially breach network reliability thresholds.
Preferred Option & Justification Install a fast transfer scheme in 2012/13 to help manage loads when Unison deploys one of Windsor substation’s transformers elsewhere. The automated switches will help to reduce customer interruptions during 11kV feeder faults, and they will also help Unison to gather real-time data about feeder loads at a more granular level.
5-88 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Constraint No. 6 Undersized power transformers at Redclyffe GXP.
Description Transpower has two 110/33kV transformers in service at Redclyffe GXP: One is rated at 40MVA and the other 50MVA continuously. The current peak load fed from this GXP is in excess of 60MVA (Marewa and Bluff Hill zone substations’ loads excluded). These transformers are therefore too small, and an upgrade is required.
Marewa and Bluff Hill zone substations are fed from Whakatu GXP via the North Tie 33kV feeder to alleviate the situation. Multiple faults on the North Tie 33kV feeder in recent years have highlighted the vulnerability of the network in this configuration.
Possible Solutions Class of Option Description Advantages Disadvantages or Risks Cost
Network Install new 110/33kV Ability to operate sub-transmission Cost ±$2-3m power transformers at network in its intended state. Redclyffe GXP Better handle power transformer and 33kV feeder contingencies. New transformers will have on-load tap changers.
Non-Network Encourage Distributed Can mitigate present and future Connections are at ad hoc basis, Unknown13 Generation (DG) feeder capacity constraints. Long and cannot be predicted. term benefits in deferral of capital The connected DG may not be as expenditure. reliable as the new network assets.
Smart meters to Reduces the feeder loads during Simulations have shown a Ongoing improve hot water peak load conditions. potential gain of 11MW in load control control due to smart meters, which is insufficient.
Do Nothing Feed Marewa and No capital investment required. Network reliability issues. $0 Bluff Hill from Whakatu Potentially harm Unison’s via North Tie 33kV reputation. feeder
Preferred Option & Justification Upgrade the power transformers at Redclyffe. This will enable Unison to utilise the existing two 33kV feeders between Marewa and Onekawa switching station, which will enhance network reliability in the end. Using the additional transformer capacity, Unison can extend the Gilligans 33kV feeder into Powdrells Road switching station to enhance network capacity and security even further.
13 DG projects are treated as customer projects and customer contributions are project specific SECTION 5 NETWORK DEVELOPMENT PLANS 5-89 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Very importantly, the new transformers will have on-load tap changers that will alleviate a looming voltage regulation problem at Tutira zone substation. The new on-load tap changers will also enhance voltages delivered to a new generation station near Tutira during generator outages.
5-90 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
5.7.2.2 Network Development Programme for 2013/14 until 2017/18 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 No. 1 Voltage constraints, on the feeders supplied from Tutira zone substation.
Description Feeders out of Tutira substation have voltage constraints on them, due to the long lengths of Galvanized Steel Conductors in the final third section of the feeders. 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 Act and Electrical Safety Regulations. 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 Resolves the issue by installing a Significant costs involved in $2.1m causing the voltage issue bigger conductor which has a upgrading conductors. lower voltage drop across it. Creates capacity for future load growth. Renewal of assets.
Install 11kV voltage regulators on Significantly cheaper than Medium term solution, as $630k the constrained feeders upgrading lines. the problem could worsen if a large load is added at the end of the line.
Non-Network Install capacitor banks to reduce Reduces feeder loadings thereby Ideal location is hard to $275k feeder loadings lifting the voltage profile. identify due to lack of Significantly cheaper than the customer installation data network solutions mentioned (e.g. consumption – kW, above. kVAr). Will only be useful if high SECTION 5 NETWORK DEVELOPMENT PLANS 5-91 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Class of Option Description Advantages Disadvantages or Risks Total Cost reactive loads are connected to the feeder.
Encourage Distributed Generation Can mitigate present and future Connections are at ad hoc Unknown14 (DG) feeder capacity constraints. basis, and cannot be Long term benefits in deferral of predicted. capital expenditure. The connected DG may not be of reliable source such as renewal.
Do Nothing Operate assets up to their No capital investment required. This is not a feasible option N/A maximum limits as Unison would be breaching the Electricity Act and Electrical Safety Regulations.
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 only where the feeders have high reactive loads connected.
2. Stage 2: Where capacitor banks cannot be used or is not appropriate due to the largely resistive loads, install voltage regulators or upgrade the conductor if future load growth is forecast.
14 DG projects are treated as customer projects and customer contributions are project specific 5-92 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Constraint No. 2 Voltage constraints on feeders supplied out of Patoka zone substation.
Description Feeders out of Patoka substation have voltage constraints on them, due to the long lengths of Galvanized Steel Conductors in the final third section of the feeders. 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 Act and Electrical Safety Regulations. 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 Resolves the issue by installing a Significant costs involved in $2.1m causing the voltage issue bigger conductor which has a upgrading conductors. lower voltage drop across it. Creates capacity for future load growth. Renewal of assets.
Install voltage regulators on the Significantly cheaper than Medium term solution, as $660k constrained feeders upgrading lines. the problem could worsen if a large load is added at the end of the line.
Non-Network Install capacitor banks to reduce Reduces feeder loadings thereby Ideal location is hard to $275k feeder loadings lifting the voltage profile. identify due to lack of Significantly cheaper than the customer installation data network solutions mentioned (e.g. consumption – kW, above. kVAr). Will only be useful if high reactive loads are connected to the feeder.
Encourage Distributed Generation Can mitigate present and future Connections are at ad hoc Unknown15 (DG) feeder capacity constraints. basis, and cannot be Long term benefits in deferral of predicted. capital expenditure. The connected DG may not be of reliable source such as renewal.
Do Nothing Operate assets up to their No capital investment required. This is not a feasible option N/A maximum limits as Unison would be
15 DG projects are treated as customer projects and customer contributions are project specific SECTION 5 NETWORK DEVELOPMENT PLANS 5-93 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Class of Option Description Advantages Disadvantages or Risks Total Cost breaching the Electricity Act and Electrical Safety Regulations
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 only where the feeders have high reactive loads connected.
2. Stage 2: Where capacitor banks cannot be used or is not appropriate due to the largely resistive loads, install voltage regulators or upgrade the conductor if future load growth is forecast.
5-94 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Constraint No. 3 Voltage constraint on Otamauri feeder out of Sherenden zone substation.
Description Otamauri feeder has a voltage constraint on it, due mainly to the long lengths of Galvanized Steel Conductors in the final third section of the feeders and only a two bank voltage regulator. 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 Act and Electrical Safety Regulations. 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 Resolves the issue by Significant costs involved in $750k causing the voltage issue installing a bigger conductor upgrading conductors. which has a lower voltage drop across it. Creates capacity for future load growth. Renewal of assets.
Install second 3 Phase bank Cheaper than upgrading lines. Medium term solution, as $210k Voltage regulators on the the problem could worsen if constrained feeder a big load is added at the end of the line.
Upgrade the existing Voltage Significantly cheaper than May not correct the problem $75k Regulator to a 3 Phase Bank upgrading lines. fully and additional remedial regulator work would be required.
Non-Network Install capacitor bank to reduce Reduces feeder loadings Ideal location is hard to $95k feeder loadings thereby lifting the voltage identify due to lack of profile. customer installation data Significantly cheaper than the (e.g. consumption – kW, network solutions mentioned kVAr). above. Will only be useful if high reactive loads are connected to the feeder.
Encourage Distributed Generation Can mitigate present and Connections are at ad hoc Unknown16 (DG) future feeder capacity basis, and cannot be constraints. predicted. Long term benefits in deferral The connected DG may not
16 DG projects are treated as customer projects and customer contributions are project specific SECTION 5 NETWORK DEVELOPMENT PLANS 5-95 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Class of Option Description Advantages Disadvantages or Risks Total Cost of capital expenditure. be of reliable source such as renewal.
Do Nothing Operate assets up to their No capital investment required. This is not a feasible option N/A maximum limits as Unison would be breeching the Electricity Act and Electrical Safety Regulations.
Preferred Option & Justification The preferred solution for the voltage constraint is to be resolved in three stages as detailed below: 1. Stage 1: Upgrade existing 2 Phase bank Voltage Regulator to a 3 Phase bank. This is a cost effective solution which can be used to lift the voltage profile if the feeder has low reactive loads connected.
2. Stage 2: Install capacitor banks wherever applicable. This is an effective solution which can be used to lift the voltage profile only if the feeder has high reactive loads connected.
3. Stage 3: Where capacitor banks cannot be used or is not appropriate due to the largely resistive loads, install additional voltage regulators or upgrade the conductor if future load growth is forecast.
5-96 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Constraint No. 4 Security constraint on Greenmeadows feeder out of Tannery zone substation.
Description This feeder does not comply with Unison’s security criteria. This feeder predominantly supplies commercial loads and it is critical that supply is maintained. Lack of investment will lead to overloading of adjacent feeders which limits the ability to backstop this feeder 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 feeder out Offloads identified capacity constrained High civil costs in areas that $1.75m of Tannery zone feeders. are already established. substation and off load Ensures feeders are compliant with Requires installation of new sections of Unison’s security standards, well into the 11kV circuit breaker at zone Greenmeadows feeder next planning period. substation. Provides additional 11kV interconnectivity. May require building to be extended.
Provide new Offloads identified capacity constrained Due to network architecture, $700k interconnection with a feeders. heavily loaded feeders lightly loaded feeder and Provides additional 11kV interconnection cannot be offloaded transfer load and flexibility to backstop. substantially. Only a short term option, and will not meet security standards after 2-3 years. Easements are required as shorter cable route is through private properties.
Upgrade constrained Provides spare capacity on the adjacent Foreseen outages during $400k sections of adjacent feeders until end of planning period for works. feeders present and forecasted load. Cheaper than installing new feeders as there are no civil costs to extend/modify the building and installing CBs.
Upgrade constrained Provides spare capacity on the feeder until Will not improve security $315k sections of this feeder end of planning period for present and backfeed capacity from forecasted load. adjacent feeders. Cheaper than installing new feeders as Foreseen outages during there are no civil costs to extend/modify works. the building and installing CBs. SECTION 5 NETWORK DEVELOPMENT PLANS 5-97 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Class of Option Description Advantages Disadvantages or Risks Total Cost
Non-Network Install capacitor banks to Reduces feeder loadings. Ideal location is hard to $400k reduce feeder loadings identify due to lack of customer installation data (e.g. consumption – kW, kVAr). Lack of VAr requirements of the feeders. Another investment would be required to ensure feeder is compliant with security standard.
Encourage Distributed Can mitigate present and future feeder Connections are at ad hoc Unknown17 Generation (DG) capacity constraints. basis, and cannot be Long term benefits in deferral of capital predicted. expenditure. The connected DG may not be of reliable source such as renewal.
Install soil thermal Calculate accurate cable ratings which will Short term solution N/A resistivity and moisture likely be higher than the existing ratings. (1-2 years). sensors Deferral in reinforcement of cable.
Increase the ability to Reduces the feeder loads during peak load Requires the local retailers Ongoing18 control hot water in the conditions. to replace ripple relays. Hawke’s Bay region Deferral in reinforcement of cable.
Do Nothing Operate assets up to No capital investment required. Unison is likely to breach its N/A their maximum limits service level targets and network reliability targets for the customers.
Preferred Option & Justification The preferred solution for the security constraint is to upgrade the constrained sections of adjacent feeders. This will provide contingency head room, for this feeder and capacity headroom until the end of planning period for present and forecast load.
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 5-98 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Constraint No. 5 Capacity and security constraint on a section of Bowen feeder out of Awatoto zone substation.
Description This feeder does not comply with Unison’s capacity and security criteria. This feeder predominantly supplies commercial and industrial loads and it is critical that supply is maintained. Lack of investment will lead to overloading of this section of the feeder which limits the ability to backstop 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 feeder out Offloads identified capacity constrained High civil costs in areas that $1.7m of Awatato feeders. are already established. Ensures feeders are compliant with Requires installation of new Unison’s security standards, well into the 11kV circuit breaker at zone next planning period. substation. Provides additional 11kV interconnectivity. May require building to be extended.
Provide new Offloads identified capacity constrained Due to network architecture, $700k interconnection with a feeders. heavily loaded feeders lightly loaded feeder and Provides additional 11kV interconnection cannot be offloaded transfer load and flexibility to backstop. substantially. Only a short term option, and will not meet security standards after 2-3 years. Easements are required as shorter cable route is through private properties.
Upgrade constrained Provides spare capacity on the feeder until Foreseen outages during $135k sections of the feeder end of planning period for present and works. forecast load. Cheaper than installing new feeders as there are no civil costs to extend/modify the building and installing CBs.
Non-Network Install capacitor banks to Reduces feeder loadings. Ideal location is hard to $400k reduce feeder loadings identify due to lack of customer installation data (e.g. consumption – kW, kVAr). Lack of VAr requirements of the feeders. Another investment would be required to ensure feeder is compliant with security standard. SECTION 5 NETWORK DEVELOPMENT PLANS 5-99 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Class of Option Description Advantages Disadvantages or Risks Total Cost
Encourage Distributed Can mitigate present and future feeder Connections are at ad hoc Unknown19 Generation (DG) capacity constraints. basis, and cannot be Long term benefits in deferral of capital predicted. expenditure. The connected DG may not be of reliable source such as renewal.
Install soil thermal Calculate accurate cable ratings which will Short term solution N/A resistivity and moisture likely be higher than the existing ratings. (1-2 years). sensors Deferral in reinforcement of cable. Increase the ability to Reduces the feeder loads during peak load Requires the local retailers Ongoing20 control hot water in the conditions. to replace ripple relays. Hawke’s Bay region Deferral in reinforcement of cable.
Do Nothing Operate assets up to No capital investment required. Unison is likely to breach its N/A their maximum limits service level targets and network reliability targets for the customers.
Preferred Option & Justification The preferred solution for the capacity and security constraint is to upgrade the constrained section of the Bowen feeder (approximately 175m of 0.1in2 Al PILC). This will also provide spare capacity for back feeding the Philips feeder.
The figure following shows the extent of this project.
19 DG projects are treated as customer projects and customer contributions are project specific 20 Maintenance cost of the ripple plant equipment at the Zone Substation 5-100 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Legend
Bowen Overlay
Figure 5-35: Bowen feeder upgrade
SECTION 5 NETWORK DEVELOPMENT PLANS 5-101 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Constraint No. 6 Voltage constraint on Twyford feeder out of Fernhill zone substation.
Description Fernhill feeder has voltage constraints on it, due mainly to numerous spur lines constructed of Galvanized Steel or light Copper Conductors. There is presently a 3 bank Voltage Regulator and Capacitor Bank in the backbone of the feeder. 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 Act and Electrical Safety Regulations. 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 sections of line that Resolves the issue by installing a Significant costs involved in $1.2m are causing the voltage issue bigger conductor which has a upgrading conductors. lower voltage drop across it. Creates capacity for future load growth. Renewal of assets. Install a second 3 Phase bank Cheaper than upgrading lines. Medium term solution, as $350k Voltage regulator on the the problem could worsen if constrained feeder and relocate a big load is added at the the existing regulator bank to a end of the line. more appropriate location that will better utilise it
Non-Network Install 2nd capacitor bank of the Reduces feeder loadings thereby Due to the resistive nature $95k same kVAr rating to reduce lifting the voltage profile. of the feeder there is a very feeder loadings Significantly cheaper than the small voltage gain. network solutions mentioned Will only be useful if high above. reactive loads are connected to the feeder.
Encourage Distributed Generation Can mitigate present and future Connections are at ad hoc Unknown21 (DG) feeder capacity constraints. basis, and cannot be Long term benefits in deferral of predicted. capital expenditure. The connected DG may not be of reliable source such as renewal.
Do Nothing Operate assets up to their No capital investment required. This is not a feasible option N/A maximum limits as Unison would be
21 DG projects are treated as customer projects and customer contributions are project specific 5-102 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Class of Option Description Advantages Disadvantages or Risks Total Cost breaching the Electricity Act and Electrical Safety Regulations.
Preferred Option & Justification The preferred solution for the voltage constraint is to be resolved is to
1. Stage 1: Install a second Regulator bank and relocate the existing Regulator bank to a more appropriate location that can regulate supply to the spur lines that have the voltage constraints.
2. Stage 2: Where regulator bank or capacitor bank cannot be used, upgrade the conductor if future load growth is forecast.
SECTION 5 NETWORK DEVELOPMENT PLANS 5-103 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Constraint No. 7 Capacity and security constraints on Haumoana feeder.
Description There is an existing capacity constraint on Haumoana feeder. There is in-sufficient spare capacity in the circuit to afford offload requirements for adjacent feeders during peak load and it does not comply with Unison’s security criteria. The peak loads during 2010/11 and 2011/2012 financial years on the Haumoana feeders were 3.44MVA (100% of rated capacity) and 3.57MVA (103% of rated capacity) respectively.
Possible Solutions Class of Option Description Advantages Disadvantages or Risks Cost
Network Establish a new 11kV feeder Permanently reduce Haumoana feeder Requires an additional Circuit $780k out of Rangitane zone load by offloading a section of the Breaker installed at Rangitane substation feeder. ZS. Provide additional capacity to offload High civil costs in areas that Haumoana feeder loads at peak times. are already established. Will allow the use of Smart Grid to transfer Haumoana load to the new feeder.
Upgrade front end of Ensures compliance with Unison’s High civil costs in areas that $450k Haumoana feeder capacity security standards, well into are already established. the next planning period. 2.4 km of circuit will need to be upgraded.
Create interconnection Smart grid enabler for technologies like Short-medium term solution $110k between of Haumoana and self healing by increasing connectivity only. Will require adjacent feeders between feeders. reinforcement in two years Deferral in reinforcement of cable. time. Can only be used one way, that is to support Haumoana feeder only
Non-Network Shift load through 11kV feeders Reduces the load on the Haumoana Difficult to shift load around as N/A during peak load times feeder thereby keeping the load within the feeder interconnectivity at the existing ratings of the circuit. front end is limited.
Do Nothing No capital investment required. Unison is likely to breach its N/A service level targets and network reliability targets for the customers. Missed revenue opportunity.
Preferred Option & Justification The preferred solution is to upgrade the frontend of the feeder out of Rangitane zone substation. This will effectively resolve the existing capacity and security issues and enable the feeder to support Clive and Station feeders. The increased capacity will enable the fast transfer or self healing smart network scheme to be operated in the future.
5-104 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
The figure below shows the extent of the project.
Upgrade Haumoana Feeder
RANGITANE RD Interconnection with 11kV
Legend Haumoana Overlay
Figure 5-36: Proposed upgrade Haumoana feeder route – Rangitane zone substation
SECTION 5 NETWORK DEVELOPMENT PLANS 5-105 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Constraint No. 8 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 Shift the prison load from Poukawa Short-medium term solution $90k 150m) of Bridge Pa and Raureka to Bridge Pa, thereby offloading (3-5 years). feeders from the substation to pole Poukawa feeder. 127175 Create capacity and security headroom for feeders’ connected to enable smart grid. Defer installation of a new feeder out of Irongate substation.
Install new feeder out of Irongate to Offloads identified capacity Requires installation of new $350k offload Poukawa feeder constrained feeders. CB at Irongate substation. Ensures feeders are compliant with High civil costs. Unison’s security standards, well into the next planning period. Provides additional 11kV interconnectivity.
Non-Network Shift load through 11kV feeders during Reduces the load on the constraint Difficult to shift load around as N/A peak load times feeder. the feeder runs through Defer capital investment. urban/rural area, thereby causing potential voltage issues.
Do Nothing No capital investment required. Unison is likely to breach its N/A service level targets and network reliability targets for the customers. Missed revenue opportunity.
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 following figure shows the extent of this stage.
5-106 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
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 pole127175
Upgrade Raureka from pole 148676 to pole 127173
Maraekakaho Road
IRONGATE
Figure 5-37: Proposed work details for Bridge Pa and Raureka feeders
SECTION 5 NETWORK DEVELOPMENT PLANS 5-107 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Constraint No. 9 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 re-closers on Waimarama feeder. Fault detection is a major constraint on this feeder, as a fault tends to operate two re-closers. The engineers cannot analyse the fault data as the existing re-closers 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 Improves reliability. High cost. $250k Re-closers with Nova Re-closers Ensures Unison’s Service Level and Network Reliability Targets can be met. Provides useful planning information from these devices.
Non-Network Implementing self healing Improves reliability drastically. High initial set up cost. N/A technology Restoration of supply to Line of sight consumers within 1 minute. communication is required between switches. Provides useful planning information from devices. Increase in maintenance costs due to additional gear.
Install Ground Fault Neutraliser Improves reliability drastically, only High cost. $450k22 (GFN) for earth faults. One GFN per substation Quicker identification of faults. site.
Do Nothing Least cost option. Contribute towards and N/A can lead to breaching Unison’s Service Level and Network Reliability Targets.
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 Reclosers. 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 faults.
22 Cost of installing a single GFN unit 5-108 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Constraint No. 10 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 Resolves the issue by installing a Significant costs involved in $1.22m that is causing the voltage bigger conductor which has a upgrading conductors. issue lower voltage drop across it. 5km needs to be upgraded. Creates capacity for future load growth. Renewal of assets.
Install voltage regulators Significantly cheaper than Medium term solution, as the $250k on the constrained feeder upgrading lines. problem could worsen if a big load is added at the end of the line.
Non-Network Install capacitor banks to Reduces feeder loadings thereby Ideal location is hard to identify due $250k reduce feeder loadings lifting the voltage profile. to lack of customer installation data Significantly cheaper than the (e.g. consumption – kW, kVAr). network solutions mentioned Will only be useful if high reactive above. loads are connected to the feeder.
Encourage Distributed Can mitigate present and future Connections are at ad hoc basis, Unknown23 Generation (DG) feeder capacity constraints. and cannot be predicted. Long term benefits in deferral of The connected DG may not be of capital expenditure. reliable source such as renewal.
Do Nothing Operate assets up to their No capital investment required. This is not a feasible option as N/A maximum limits Unison would be breaching the Electricity Act and Electrical Safety. 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.
23 DG projects are treated as customer projects and customer contributions are project specific SECTION 5 NETWORK DEVELOPMENT PLANS 5-109 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Constraint No. 11 Voltage constraints on feeders supplied out of Maraekakaho zone substation.
Description Feeders out of the Maraekakaho zone substation 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 Resolves the issue by installing a Significant costs involved in $2.1m causing the voltage issue bigger conductor which has a upgrading conductors. lower voltage drop across it. Creates capacity for future load growth. Renewal of assets. Install voltage regulators on the Significantly cheaper than Medium term solution, as $960k constrained feeders upgrading lines. the problem could worsen if a big load is added at the end of the line.
Non-Network Install capacitor banks to reduce Reduces feeder loadings thereby Ideal location is hard to $255k feeder loadings lifting the voltage profile. identify due to lack of Significantly cheaper than the customer installation data network solutions mentioned (e.g. consumption – kW, above. kVAr). Large amount of capacitance required for minimal voltage gain. Will only be useful if high reactive loads are connected to the feeder.
Encourage Distributed Generation Can mitigate present and future Connections are at ad hoc Unknown24 (DG) feeder capacity constraints. basis, and cannot be Long term benefits in deferral of predicted. capital expenditure. The connected DG may not be of reliable source such as renewal.
24 DG projects are treated as customer projects and customer contributions are project specific 5-110 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Class of Option Description Advantages Disadvantages or Risks Total Cost
Do Nothing Operate assets up to their No capital investment required. This is not a feasible option N/A maximum limits as Unison would be breaching the Electricity Act and Electrical Safety Regulations.
Preferred Option & Justification The preferred solution for the voltage constraint is to be resolved in two stages as detailed below: 1. Stage 1: Install voltage regulators wherever applicable. 2. Stage 2: Upgrade the conductor if future load growth is forecast.
SECTION 5 NETWORK DEVELOPMENT PLANS 5-111 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Constraint No.12 The existing power transformers at Havelock North are too small for N-1 contingencies.
Description Unison has two 10MVA transformers in service at Havelock North zone substation. This means that they can sustain up to 12MVA for two hours during N-1 contingencies. The 2010/11 peak winter load was 14.1MVA (141% of the individual transformer capacity).
Possible Solutions Class of Option Description Advantages Disadvantages or Risks Cost
Network Permanent load transfers Very low cost. Havelock North somewhat No Capex cost to surrounding zone secluded, which limits options substations for permanent load transfers. Back feeding heavily loaded 11kV feeders is difficult. Reliability indices will suffer adversely due to longer feeders.
Install two new 15/20MVA Permanent solution High cost. $2.1m transformers in 2015/16 Redeploy existing units at Flaxmere.
Non-Network Use smart meters to In line with Unison’s smart Load control capacity gain N/A control peak loads network proposition. only marginal.
Do nothing Operate assets to their No capital spent. Breach security criteria. No Capex cost maximum limits Potentially breach regulatory SAIDI and SAIFI thresholds.
Preferred Option & Justification Install two new power transformers at Havelock North in 2015/16 to address the capacity constraints. The existing transformers at Havelock North are 11 years old, which makes them highly suitable to be redeployed at Flaxmere zone substation.
Unison has a fast transfer scheme in operation to mitigate the risk until the transformers are upgraded. This fast transfer scheme will rapidly transfer loads to other zone substations if one transformer trips during a peak load period. 5-112 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Figure 5-38: Havelock North zone substation, and the area that it serves
SECTION 5 NETWORK DEVELOPMENT PLANS 5-113 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Constraint No. 13 The power transformers at Flaxmere zone substation are near the end of their useful life, and one of them is exceptionally noisy.
Description Unison has two 10MVA power transformers in service at Flaxmere zone substation, manufactured in 1961 and 1962 respectively. One of these transformers is exceptionally noisy, which is believed to point toward loose windings. Loose windings present a danger in the sense that they might be easily deformed when very strong magnetic fields associated with fault currents impose large mechanical forces on them. A deformity in a winding greatly increases the risk of insulation breakdown to either the core or other windings of the unit.
Possible Solutions Class of Option Description Advantages Disadvantages or Risks Cost
Network Permanent load transfers to Very low cost. Decline in network reliability No Capex cost surrounding zone due to longer feeders, difficulty substations to take feeders out of service for maintenance.
Install two ex-Havelock Permanent solution. The replacements have the $0.6m 10MVA transformers at same capacity as the old unit. Flaxmere
Non-Network Use smart meters to control In line with Unison’s Second transformer also old, N/A peak loads smart network hence apprehension to rely proposition. too much on it in the long term.
Do nothing Operate assets to failure Utilise asset to the very Potential difficulty to fit existing No Capex cost end of its life. system spare at Flaxmere.
Preferred Option & Justification Install the ex-Havelock North transformers at Flaxmere circa 2016/17. Flaxmere’s peak load is about 12MVA, but McCain zone substation is in close proximity to accommodate rapid load transfers if needed.
Unison will install a fast transfer scheme, which can transfer 2MVA worth of load from Flaxmere to McCain zone substation in 2012/13.
Unison plans to upsize the two transformers at Havelock North zone substation circa 2015/16. These transformers are well suited for Flaxmere zone substation.
5-114 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Constraint No. 14 A customer currently fed from Marewa zone substation has requested a major upgrade. Our best option is to feed this customer from Tamatea zone substation. The existing power transformers at Tamatea are too small to handle the additional load.
Description Unison has two 7.5MVA ONAN power transformers installed at Tamatea substation. This means that they can accommodate loads up to 9MVA for two hours during contingencies. Tamatea substation’s 2010/11 peak winter load was 14.1MVA. Rapid load growth is forecast for the new developments fed from Tamatea.
A financial/engineering study has shown that the best option is to upgrade Tamatea zone substation with two new 20MVA transformers. In addition, a new 11kV switch room and switchboard is required as the existing switchboard at Tamatea is under-sized (800A), it contains old circuit breakers, and the switch room is at risk of flood. It furthermore requires seismic work, and is too small for additional circuit breakers.
Possible Solutions Class of Option Description Advantages Disadvantages or Risks Cost
Network Permanent load transfers to Very low cost. Decline in network reliability No Capex cost surrounding zone due to longer feeders, difficulty substations to take feeders out of service for maintenance.
Install two new 20MVA Permanent solution High cost. $3.5m transformers along with a Creates capacity for new 11kV switchboard and future load growth switch room at Tamatea Ex-Tamatea transformers can be used as system spares Non-Network Use smart meters to control In line with Unison’s Load control capacity gain N/A peak loads smart network only marginal. proposition. Do nothing Operate assets to their No capital spent. Breach security criteria. No Capex cost maximum limits Potentially harm Unison’s public image.
Preferred Option & Justification Install two new 20MVA transformers at Tamatea in 2013/14. This will create the capacity that is needed to support the required demand upgrade. The upgrade will also support a number of impending new residential developments near Tamatea zone substation. In addition to this, an opportunity is created to attend to the problems that affect the 11kV switchboard and switch room. SECTION 5 NETWORK DEVELOPMENT PLANS 5-115 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Figure 5-39: Tamatea zone substation and its 11kV feeders
5-116 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Constraint No. 15 A shortage of 33kV circuit breakers at Marewa zone substation.
Description There are no 33kV circuit breakers at the Marewa end of the Marewa One and Marewa Two 33kV feeders.
Description Marewa and Bluff Hill zone substations are fed from Whakatu via the North Tie 33kV feeder due to a capacity constraint at Redclyffe GXP. Unison furthermore liven Marewa One and Marewa Two 33kV feeders from the Marewa end. A fault on any of these two feeders between Marewa and Onekawa substation will therefore result in an outage to both Marewa and Bluff Hill zone substations.
An option exists to liven the above-mentioned two feeders from Onekawa, in which case two air break switches could be manually operated at the Marewa end. Unison does however use these feeders on a daily basis to tie Redclyffe and Whakatu GXP’s at the 33kV level to facilitate switching at the 11kV level. Having to operate these air break switches manually on a daily basis is labour-intensive, costly and counter-productive.
Recent faults on the Marewa 33kV feeders have highlighted the need to install these new circuit breakers.
Possible Solutions Class of Option Description Advantages Disadvantages or Risks Cost
Network Install new 33kV circuit Enhanced network reliability. Most expensive option. $0.4m breakers at Marewa Fit well into future development zone substation plans for Unison’s sub-transmission network.
Liven Marewa 1 & 2 No capital investment required. Air break switches at Marewa N/A feeders from Onekawa manually operated, which is labour Switching station intensive and slow. Fault restoration after network faults gets complex and slow.
Do Nothing Feed Marewa and Bluff No capital investment required. Network reliability issues. $0 Hill from Whakatu via Potentially harm Unison’s North Tie feeder reputation.
Preferred Option & Justification The preferred option is to install two new 33kV circuit breakers at Marewa zone substation circa 2013/14. These circuit breakers will help Unison to improve network reliability and enable a fast protection scheme. They also fit well into future development plans for Unison’s sub-transmission network in Napier.
SECTION 5 NETWORK DEVELOPMENT PLANS 5-117 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Figure 5-40: Shows where Unison will install the new 33kV circuit breakers at Marewa zone substation
5-118 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Constraint No. 16 Shortage of 33kV circuit breakers at Faraday zone substation.
Description Unison has no 33kV circuit breakers in service at the Faraday end of the Napier One and Napier Two 33kV feeders. This will become problematic in the future when Unison intends to use these feeders, along with the Marewa-Faraday Tie, to feed Faraday and Bluff Hill zone substations. This proposed configuration will produce three 33kV feeders to supply these two zone substations in normal situations, while there will be two feeders in N-1 situations.
In its current configuration, a line fault on the Napier One or Napier Two feeder will cause an outage to the entire Faraday zone substation.
Possible Solutions Class of Option Description Advantages Disadvantages or Risks Cost
Network Install two new 33kV Enhanced network reliability. Cost. $0.4m circuit breakers at Fit well into future development Faraday zone substation plans for Unison’s sub-transmission network.
Do Nothing Feed Marewa and Bluff No capital investment required. Network reliability issues. $0 Hill from Whakatu via Potentially harm Unison’s North Tie feeder reputation. Future plans for sub-transmission network compromised.
Feed Marewa from No capital investment required. Network security to Bluff Hill zone $0 Onekawa S/S and substation not improved. continue to feed Bluff Hill Larger energy losses on our sub- via North Tie 33kV transmission network. feeder Future plans for sub-transmission network compromised.
Preferred Option & Justification The preferred option is to install two new 33kV circuit breakers at Faraday zone substation in 2014/15. These circuit breakers will help to improve network reliability, and they fit well into future development plans for Unison’s sub- transmission network in Napier.
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Figure 5-41: Shows where Unison will install additional 33kV circuit breakers at Faraday zone substation
5-120 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Constraint No. 17 Onekawa B feeder overload during 33kV feeder outages.
Description Unison plans to feed Marewa and Bluff Hill zone substations from Redclyffe GXP when the planned power transformer upgrade at the GXP is complete. Given this amendment, the Onekawa B feeder will be severely overloaded if any of the other Onekawa 33kV feeders should trip during peak load times. Increased feeder capacity is required to match the planned increase in transformer capacity at Redclyffe GXP.
Possible Solutions Class of Option Description Advantages Disadvantages or Risks Cost
Network Extend Gilligans Ability to operate sub-transmission Fully utilise a feeder intended to $650k feeder into Powdrells network in its intended state. be a tie between two GXP’s. Rd switching station Better handle 33kV feeder outages.
Upgrade conductors Better handle 33kV feeder outages High cost. $1.5m on the Onekawa B Ability to operate sub-transmission feeder network in its intended state.
Non-Network Encourage Distributed Can mitigate present and future Connections are at ad hoc basis, Unknown Generation (DG) feeder capacity constraints. and cannot be predicted. Long term benefits in deferral of DG may not be as reliable as the capital expenditure. upgraded assets.
Install smart meter s to Reduce the feeder loads during peak Reaction time of smart meter Ongoing improve hot water load conditions. intervention potentially too slow. control
Do Nothing Feed Marewa and No capital investment required. Network reliability issues. $0 Bluff Hill from Whakatu Potentially harm Unison’s via North Tie feeder reputation.
Preferred Option & Justification Extend Gilligans 33kV feeder into Powdrells Road Switching Station to enhance connectivity in the Redclyffe 33kV network. This will enable Unison to use existing twin 33kV feeders between Marewa and Onekawa switching station to feed Marewa and Bluff Hill substations.
The project will also yield the following benefits: Unison becomes less dependent on Onekawa switching station for network security purposes.
Utilise existing network capacity offered by the Gilligans 33kV feeder.
The project enables Unison to make better use increased transformer capacity at Redclyffe GXP.
Construct only one kilometer of 33kV overhead feeder to link the Gilligans feeder to Powdrells Road switching station, which makes it a cost-effective solution.
SECTION 5 NETWORK DEVELOPMENT PLANS 5-121 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Figure 5-42: Gilligans feeder extended and connected to Powdrells Road switching station
5-122 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Constraint No. 18 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 Improves reliability. Expensive. $5.0m outside the building Improves access for operation and Due to shortage of available land where the distribution maintenance. and berm sites in the CBD new substation is installed Ensures Unison’s Service Level locations could be a considerable and Network Reliability Targets distance from the transformer. can be met.
Non-Network Use a smart network to Cost-effective solution. Temporary solution (10-20 years). $800k rapidly transfer loads to Provides useful planning Increased network complexity. surrounding feeders information from these devices. No allowance for immediate Can be used for self healing after reinstatement if fault is at the network faults. transformer or on the LV Network. Fully utilise adjacent feeders.
Move normal open Very low cost. Voltage regulation and conductor N/A points between feeders capacity limit scope. to permanently shift Bring forward more constraints on loads other parts of the network.
Encourage Distributed Can mitigate present and future Connections are at ad hoc basis, Unknown25 Generation (DG) capacity constraints on the and cannot be predicted. transformers. The connected DG may not be a Long term benefits in deferral of reliable source such as renewal. capital expenditure.
Install Ground Fault Improves reliability drastically, only One GFN per substation site. $450k26 Neutraliser (GFN) for earth faults. Quicker identification of faults.
Do Nothing Operate assets up to No capital investment required. Unison is likely to breach its service N/A
25 DG projects are treated as customer project; customer contribution are project specific 26 Cost of installing a single GFN unit SECTION 5 NETWORK DEVELOPMENT PLANS 5-123 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Class of Option Description Advantages Disadvantages or Risks Total Cost
their maximum limits level targets and network reliability targets for the customers.
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 new 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.
There is a renewal benefit to replacing old and obsolete RMU’s.
5-124 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Constraint No. 19 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 Inexpensive. Needs personnel on site to $40k indicators and temporary Gives approximate location of a fault identify approximate location of data loggers at strategic between indicator points. fault. locations along the feeder Gives feeder load and fault current Needs visit to site by technical route data if logger happens to be installed personnel to setup data at time of fault. loggers and download fault and load current information. Information is not received in real time, it requires human intervention in the field.
Non-Network Use data sensors at Cost-effective solution. Temporary solution (10-15 $185k strategic locations to Real time data available for planners years). collect and convey data and operators. Increased network complexity. via the communications Reduced restoration times. network to rapidly transfer Can be integrated into fast transfer loads to surrounding feeders and self healing schemes.
Do Nothing Operate assets up to their No capital investment required. Unison is likely to breach its N/A maximum limits service level targets and network reliability targets for the customers.
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 11kV feeders and zone substations.
SECTION 5 NETWORK DEVELOPMENT PLANS 5-125 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Constraint No. 20 Security constraint at Fernhill GXP.
Description The Transpower-owned transformers at Fernhill are mismatched with capacities of 30MVA and 50MVA respectively. In addition to this, the existing peak load on the GXP is 48MVA, which translates to difficulty for Unison if the 50MVA transformer should trip during peak load times - Unison will struggle to shift load onto Whakatu GXP.
This security constraint could cause a major outage and may lead to a breach of Unison’s service level targets and network reliability indices.
Possible Solutions Class of Option Description Advantages Disadvantages or Risks Total Cost
Network Upgrade the transformers to Long-term solution. Cost. $2-3m accommodate load growth Creates capacity for future load growth. Renewal of assets. On-load tap changers on new transformers.
Transfer load to other GXP’s Adequate transformer capacity 33kV feeders get heavily loaded >$2m exists at Whakatu GXP. and capacity constrained. 33kV network security become problematic. No on-load tap changers at Fernhill GXP.
Non-Network Encourage Distributed Can mitigate capacity Connections are at ad hoc basis, Unknown Generation (DG) constraints on the and cannot be predictedThe transformers. connected DG may not be of Long term benefits in deferral reliable enough. of capital expenditure.
Do Nothing Operate assets up to their No capital investment required. Potentially breach service level N/A maximum limits and network reliability targets.
Preferred Option & Justification The preferred option is for to upgrade the 30MVA unit at Fernhill to 60MVA. Having on-load tap changers at Fernhill will assist 33kV voltage levels in the sub-transmission network. Discussions between Unison and Transpower are ongoing.
5-126 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Constraint No. 21 The City 33kV feeder in Hastings is heavily loaded.
Description Loads in Hastings have 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 1MVA on this circuit over the next 20 years. The existing 300mm2 33kV 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, 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 time the required network strengthening optimally.
Possible Solutions Class of Option Description Advantages Disadvantages or Risks Cost
Network Install a higher rated cable Enhanced network security. Easements are required, since new $1.2m Provides additional spare cable will probably follow a different capacity into Hastings for future route. planning periods. Approximately 2km of cable to be installed. High civil costs in areas that are already established.
Non Network Smart Network: Load Offloads identified capacity Not a long-term solution. $400k Transfer scheme constrained feeder. Using spare capacity on other parts Uses available 11kV and / or of the network can influence other 33kV interconnectivity. future constraints. Increase in complexity of the network.
Manually shift normal open Offloads identified capacity Not a long-term solution. N/A points on 11kV feeders to constraint feeder. Using spare capacity on other parts transfer load to other zone Uses available 11kV of the network may bring other substations interconnectivity. constraints forward. No easements required.
Split the 33kV bus bar at Offloads identified capacity Not a long-term solution. N/A Hastings zone substation constraint feeder. Makes switching at the 11kV level Uses available 33kV complex, since adjacent feeders interconnectivity. are fed from different GXP’s. No easements required. Fernhill GXP not suitably rated for additional load prior to an anticipated transformer upgrade in the near future.
Do Nothing Least cost option - if no Can strain relationships with $0 penalties are incurred. customers. Potentially breach reliability thresholds, for which a $5M fine is possible. SECTION 5 NETWORK DEVELOPMENT PLANS 5-127 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Preferred Option & Justification The preferred solution, in the short term, monitor the cable’s temperature, and to calculate accurate cable ratings from the newly obtained information.
The longer-term solution will be to install a higher rated 33kV cable once the above-mentioned short term 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.
5-128 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
5.7.2.3 Network Development Programme for 2018/19 until 2021/22 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.
SECTION 5 NETWORK DEVELOPMENT PLANS 5-129 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Constraint No. 1 Voltage constraints on feeders emanating from Sherenden zone substation.
Description Crownthorpe and Otamauri feeders have voltage constraints on them, due to the long lengths of Galvanized Steel or light Copper Conductors in the final third section of the feeders. These constraints have become evident due to organic load growth and a number of dairy conversions taking place in this area of Hawke’s Bay region.
It is prudent to resolve these constraints for the following reasons:
1. To be compliant with the Electricity Act and Electrical Safety Regulations. 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 sections of line that Resolves the issue by installing a Significant costs involved in TBA are causing the voltage issue bigger conductor which has a upgrading conductors. lower voltage drop across it. Creates capacity for future load growth. Renewal of assets.
Install 11kV voltage regulators on Significantly cheaper than Medium term solution, as TBA the constrained feeders upgrading lines. the problem could worsen if a big load is added at the end of the line.
Non-Network Install capacitor banks to reduce Reduces feeder loadings thereby Ideal location is hard to TBA feeder loadings lifting the voltage profile. identify due to lack of Significantly cheaper than the customer installation data network solutions mentioned (e.g. consumption – kW, above. kVAr). Will only be useful if high reactive loads are connected to the feeder.
Encourage Distributed Generation Can mitigate present and future Connections are at ad hoc Unknown27 (DG) feeder capacity constraints. basis, and cannot be Long term benefits in deferral of predicted. capital expenditure. The connected DG may not be of reliable source such as renewal.
27 DG projects are treated as customer projects and customer contributions are project specific 5-130 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Class of Option Description Advantages Disadvantages or Risks Total Cost
Do Nothing Operate assets up to their No capital investment required. This is not a feasible option N/A maximum limits as Unison would be breaching the Electricity Act and Electrical Safety Regulations.
Preferred Option & Justification The preferred solution for the voltage constraint is to install voltage regulators banks wherever applicable.
SECTION 5 NETWORK DEVELOPMENT PLANS 5-131 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Constraint No. 2 Voltage constraints on Omarunui feeder emanating from Springfield zone substation.
Description Omarunui feeder has voltage constraints on it, even thought it has a Voltage Regulator in circuit, due to the long lengths of light Copper Conductors. These constraints have become evident due to organic load growth.
It is prudent to resolve these constraints to be compliant with the Electricity Act and Electrical Safety Regulations.
Possible Solutions Class of Option Description Advantages Disadvantages or Risks Total Cost
Network Upgrade the sections of line that Resolves the issue by installing a Significant costs involved in TBA are causing the voltage issue bigger conductor which has a upgrading conductors. lower voltage drop across it. Creates capacity for future load growth. Renewal of assets. Install 11kV voltage regulators on Significantly cheaper than Medium term solution, as TBA the constrained feeder upgrading lines. the problem could worsen if a big load is added at the end of the line.
Non-Network Install capacitor banks to reduce Reduces feeder loadings thereby Ideal location is hard to TBA feeder loadings lifting the voltage profile. identify due to lack of Significantly cheaper than the customer installation data network solutions mentioned (e.g. consumption – kW, above. kVAr). Will only be useful if high reactive loads are connected to the feeder.
Encourage Distributed Generation Can mitigate present and future Connections are at ad hoc Unknown28 (DG) feeder capacity constraints. basis, and cannot be Long term benefits in deferral of predicted. capital expenditure. The connected DG may not be of reliable source such as renewal.
Do Nothing Operate assets up to their No capital investment required. This is not a feasible option N/A maximum limits as Unison would be breaching the Electricity Act and Electrical Safety Regulations.
28 DG projects are treated as customer projects and customer contributions are project specific 5-132 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Preferred Option & Justification The preferred solution for the voltage constraint is to install a second Regulator Bank wherever applicable. There is also the possibility of Distributed Generation in this area within the next 5 years which may negate the need for the second Regulator Bank.
SECTION 5 NETWORK DEVELOPMENT PLANS 5-133 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Constraint No. 3 Capacity and security issues on feeders emanating from Rangitane zone substation.
Description Based on future load predictions there will be security and capacity constraint on both the Anderson and Pacific feeders within this period. If no action is taken it will lead to overloading of the feeders, limit the ability to backstop, there will be no spare capacity on either feeder to offload during peak load and they will not comply with Unison’s security criteria. Growth in the Whakatu Industrial area will add more load to these and adjacent feeders.
Possible Solutions Class of Option Description Advantages Disadvantages or Risks Cost
Network Establish new feeders Offloads identified capacity High civil costs in areas that are TBA out of Rangitane zone constrained feeders. already established. substation Ensures feeders are compliant with Requires installation of a new 11kV Unison’s security standards, well Circuit Breaker and associated into the next planning period. panels at Rangitane zone substation. Provides additional 11kV Requires the building to be extended interconnectivity. and additional land purchased. Approximately 2 km of cable is to be installed to fully utilise the new feeder.
Upgrade the front end Provides spare capacity on the Disruption to existing 33kV and 11kV TBA section of the two feeders until end of planning period feeders in the same trench. feeders out of the for present and forecast load. Foreseen outages during works. substation
Provide new Offloads identified capacity Due to network architecture, heavily TBA interconnection with a constrained feeders. loaded feeders cannot be offloaded lightly loaded feeder Provides additional 11kV substantially. and transfer load interconnection and flexibility to Only a short term option, and may backstop. not meet security standards at the time. Easements are required as cable route is through private properties.
Non-Network Encourage Distributed Can mitigate present and future Connections are at ad hoc basis, Unknown29 Generation (DG) feeder capacity constraints. and cannot be predicted. Long term benefits in deferral of The connected DG may not be of capital expenditure. reliable source such as renewal.
Increase the ability to Reduces the feeder loads during Requires the local retailers to Ongoing control hot water in the peak load conditions. replace ripple relays. Rangitane area Deferral in reinforcement of cable.
29 DG projects are treated as customer projects and customer contributions are project specific 5-134 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Class of Option Description Advantages Disadvantages or Risks Cost
Do Nothing No capital investment required. There are major security issues at N/A present in this area which if not looked at could cause a big outage if a fault occurs.
Preferred Option & Justification The preferred option is to upgrade the front end of the feeders out from Rangitane zone substation. The increase in capacity of the feeders will allow the future installation of a smart network fast transfer scheme.
SECTION 5 NETWORK DEVELOPMENT PLANS 5-135 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Constraint No. 4 Capacity and security issues on feeders supplied from Arataki zone substation.
Description Based on future load predictions there will be security and capacity constraint on both the Brookvale and Palmbrook feeders within this period. If no action is taken it will lead to overloading of the feeders, limit the ability to backstop, there will be no spare capacity on either feeder to offload during peak load, they will not comply with Unison’s security criteria and are likely to contribute towards breaching Unison’s service level targets for the urban customer classification detailed in Section 8.4. Growth in the Havelock North area will add more load to these and adjacent feeders.
Possible Solutions Class of Option Description Advantages Disadvantages or Risks Cost
Network Establish new feeders Offloads identified capacity High civil costs in areas that are TBA out of Arataki zone constrained feeders. already established. substation Ensures feeders are compliant with Requires installation of a new 11kV Unison’s security standards, well Circuit Breakers and associated into the next planning period. panels at Arataki zone substation. Provides additional 11kV Requires the building to be extended interconnectivity. and additional land purchased.
Upgrade the front end Provides spare capacity on the Disruption to existing 11kV feeders TBA section of the two feeders until end of planning period in the same trench. feeders out of the for present and forecast load. Foreseen outages during works. substation Feeders share the same trench, thereby reducing the civil costs.
Provide new Offloads identified capacity Due to network architecture, TBA interconnection with a constrained feeders. heavily loaded feeders cannot be lightly loaded feeder Provides additional 11kV offloaded substantially. and transfer load interconnection and flexibility to Only a short term option, and may backstop. not meet security standards at the time. Easements are required as cable route is through private properties.
Non-Network Encourage Distributed Can mitigate present and future Connections are at ad hoc basis, Unknown30 Generation (DG) feeder capacity constraints. and cannot be predicted. Long term benefits in deferral of The connected DG may not be of capital expenditure. reliable source such as renewal.
Increase the ability to Reduces the feeder loads during Requires the local retailers to Ongoing control hot water in the peak load conditions. replace ripple relays. Rangitane area Deferral in reinforcement of cable.
30 DG projects are treated as customer projects and customer contributions are project specific 5-136 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Class of Option Description Advantages Disadvantages or Risks Cost
Do Nothing No capital investment required. There are major security issues at N/A present in this area which if not looked at could cause a big outage if a fault occurs.
Preferred Option & Justification The preferred option is to upgrade the front end of the feeders out from the Arataki zone substation. The increase in capacity of the feeders will allow the future installation of a smart network fast transfer scheme.
SECTION 5 NETWORK DEVELOPMENT PLANS 5-137 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Constraint No. 5 Capacity and security issues on feeders supplied from Havelock North zone substation.
Description Based on future load predictions there will be capacity, security and voltage constraint on the Iona, St Andrew’s and Te Aute within this period. If no action is taken it will lead to overloading of the feeders, limit the ability to backstop, there will be no spare capacity on either feeder to offload during peak load, and they will not comply with Unison’s security criteria and are likely to contribute towards breaching Unison’s service level targets for the urban customer classification detailed in Section 8.4. Growth in the Havelock North area will add more load to these and adjacent feeders.
Possible Solutions Class of Option Description Advantages Disadvantages or Risks Cost
Network Establish new feeders Offloads identified capacity High civil costs in areas that are TBA out of Havelock North constrained feeders. already established. zone substation Ensures feeders are compliant with Requires installation of a new 11kV Unison’s security standards, well Circuit Breakers and associated into the next planning period. panels at Havelock North zone Provides additional 11kV substation. interconnectivity. Requires the building to be extended and additional land purchased.
Upgrade the front end Provides spare capacity on the Disruption to existing 11kV feeders TBA section of the two feeders until end of planning period in the same trench. feeders out of the for present and forecast load. Foreseen outages during works. substation Feeders share the same trench, thereby reducing the civil costs.
Provide new Offloads identified capacity Due to network architecture, heavily TBA interconnection with a constrained feeders. loaded feeders cannot be offloaded lightly loaded feeder Provides additional 11kV substantially. and transfer load interconnection and flexibility to Only a short term option, and may backstop. not meet security standards at the time.
Upgrade the sections Resolves the issue by installing a Significant costs involved in TBA of line that are causing bigger conductor which has a lower upgrading conductors. the voltage issue voltage drop across it. Creates capacity for future load growth. Renewal of assets. Install 11kV voltage Significantly cheaper than Medium term solution, as the TBA regulators on the upgrading lines. problem could worsen if a big load is constrained feeders added at the end of the line. 5-138 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Class of Option Description Advantages Disadvantages or Risks Cost
Non-Network Encourage Distributed Can mitigate present and future Connections are at ad hoc basis, Unknown31 Generation (DG) feeder capacity constraints. and cannot be predicted. Long term benefits in deferral of The connected DG may not be of capital expenditure. reliable source such as renewal.
Increase the ability to Reduces the feeder loads during Requires the local retailers to Ongoing control hot water in the peak load conditions. replace ripple relays. Rangitane area Deferral in reinforcement of cable.
Do Nothing No capital investment required. There are major security issues at N/A present in this area which if not looked at could cause a big outage if a fault occurs.
Preferred Option & Justification The preferred option is to upgrade the front end of the feeders out from the zone substation. The increase in capacity of the feeders will allow the future installation of a smart network fast transfer scheme.
31 DG projects are treated as customer projects and customer contributions are project specific SECTION 5 NETWORK DEVELOPMENT PLANS 5-139 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Constraint No. 6 Only one power transformer in service at Bluff Hill zone substation (future security constraint).
Description Unison has a single 33/11kV power transformer in service at Bluff Hill zone substation. This transformer is fed via a single 33kV feeder from Faraday zone substation. Unison expects to feed a peak load in excess of 13MVA from Bluff Hill in 2012/13.
Unison’s network security criteria prescribe that 100% of the maximum demand should be restored within thirty minutes for a single contingency event. There is a rapid changeover scheme in service that will automatically transfer Bluff Hill’s load to Faraday zone substation at the 11kV level when the 33kV supply is lost. It is anticipated that load growth will exceed the changeover scheme’s ability to cope in the future.
The 33kV feed into Bluff Hill consists of a gas-filled cable, which could potentially be difficult and time consuming to repair if a fault occurs on it.
Possible Solutions
Class of Option Description Advantages Disadvantages or Risks Total Cost
Network Install a second 33kV feeder and Ensures compliance with Unison’s Fitting a additional $2.3m 33/11kV transformer to enhance standards well into the next equipment into Bluff Hill network security planning period. and Faraday zone Creates capacity for future load substations potentially growth. challenging as space is confined.
Non-Network Install a fast transfer scheme at the Low cost. Short term solution. TBD 11kV level to aid the existing chop- Integrates well with existing over scheme equipment.
Smart meters to control load in No additional Capex expenditure. Response time for load Ongoing addition to the chop over scheme control not very fast.
Reconfigure 11kV feeders to shift Defer capital expenditure. Short to medium term N/A loads to mitigate the risk of Spare capacity is available at solution. overloading network elements Faraday zone substation. Longer feeders difficult to manage. Reliability impact due to longer feeders.
Do Nothing Operate assets in their present No capital investment required. Future non-compliance N/A configuration with Unison’s security criteria.
Preferred Option & Justification The preferred solution for this problem is a mixture of items: Shift loads from Bluff Hill to Faraday substation by re-configuring interconnecting feeders as needed in the short to medium term. 5-140 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Deploy smart meters to control loads to such an extent that the changeover scheme can handle 33kV contingencies. Add a load transfer scheme to shift additional load away from Bluff Hill later on when needed.
Install a second 33kV feeder and power transformer at Bluff Hill zone substation when the above-mentioned measures become inadequate.
SECTION 5 NETWORK DEVELOPMENT PLANS 5-141 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Constraint No. 7 At present, in the Hawke’s Bay region there are a number of substations individually connected to two GXP’s. As Transpower does not allow lines companies to tie GXP’s, it is prudent to reconfigure 33kV circuits. This will improve the security of supply to critical substations like Hastings, Havelock and Camberley. The majority of the load on these substations is either commercial or industrial with sensitive customers. The figure below shows the planned future configuration.
Possible Solutions Class of Option Description Advantages Disadvantages or Risks Total Cost
Network Create a closed ring between No break in supply even under High costs related to TBA Hastings substation, Windsor contingency situations. reconfiguration of circuits. substation and Whakatu GXP Ensures Unison complies with Create a closed ring between its customer service levels. Havelock substation , Arataki substation and Whakatu GXP Create a closed ring between Camberley substation, Irongate substation and Fernhill GXP
Do Nothing Operate assets up to their maximum No capital investment required. Unison is likely to breach its N/A limits service level targets and network reliability targets for the customers.
Preferred Option & Justification The preferred option is to reconfigure the network as shown in Figure 5-43.
Maraekakaho Sherenden Circuit Change or Capacity Upgrade
Fernhill Redclyffe GXP Fernhill GXP
McCain Rangitane
Flaxmere
Camberley Irongate Whakatu GXP
Mahora Tomoana
Hastings Windsor
Havelock North Arataki
Figure 5-43: Hastings future network configuration 5-142 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Constraint No. 8 Second power transformer needed at McCain zone substation.
Description There are two 10MVA transformers in service at Flaxmere zone substation, and a single 20MVA unit at McCain zone substation. The peak loads at Flaxmere and McCain zone substations are 12.6MVA and 2MVA respectively. Unison’s standard planning protocol makes provision to load transformers to 120% of their nominal capacity for two hours in N-1 situations.
In addition to this, Unison will deploy a fast transfer scheme to shift the Barnes feeder, normally fed from Flaxmere, rapidly to McCain zone substation when needed.
The availability of land along Omahu Road suggests that industrial developments will continue within the footprint that Unison could serve from either McCain or Flaxmere zone substation. Given the above-mentioned security constraint at Flaxmere, new developments should be fed from McCain zone substation in the future.
Unison’s network security criteria require that supply to industrial loads above 1MVA must be restored within thirty minutes for a single contingency event.
Possible Solutions
Class of Option Description Advantages Disadvantages or Risks Total Cost
Network Install second power Long term solution and will ensure Cost. $1.5m transformer ay McCain substation is compliant with Unison’s zone substation security standards for future planning periods. Creates capacity for future load growth.
Install second Helps to better manage loads on the Cost. $1.5m transformer at Fernhill Flaxmere and Camberley 33kV feeders. Limited number of 11kV Long term solution. feeders to supply new developments.
Non-Network Further develop our Low cost solution. Temporary solution. TBD smart network to Can be used for self-healing after feeder Increased network complexity. rapidly transfer excess faults. loads between zone Utilise existing transformers for longer. substations
Do Nothing Operate assets No capital investment required. Unison may breach service $0 beyond their N-1 level and network reliability limits, and risk targets. cascaded trips Possibly harm Unison’s reputation.
Preferred Option & Justification Use the smart network to manage load growth, and install a second transformer at McCain zone substation circa 2019/20. McCain zone substation is a better location to place a second transformer for the following reasons: SECTION 5 NETWORK DEVELOPMENT PLANS 5-143 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
McCain zone substation is geographically closer to the new developments.
The existing transformer at McCain is a suitably sized – 20MVA.
Better 11kV feeder connectivity between the expected new developments and McCain zone substation.
5-144 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Constraint No. 9 Future capacity constraint on Onekawa D feeder.
Description Esk, Tutira and Tamatea zone substations are fed via the Onekawa D feeder. Tamatea zone substation, along with the Onekawa D feeder will become constrained in about ten years’ time when the peak loads, fed from Tamatea, exceed 22MVA.
Possible Solutions
Class of Option Description Advantages Disadvantages or Risks Total Cost
Network Construct another zone Creates capacity for future load Significant cost $9m substation, and feed it from growth the Onekawa C feeder
Non-Network Use smart meters to control Low cost solution. Temporary solution. Ongoing loads Utilise existing equipment for longer. Increased network complexity.
Use dynamic ratings for Defer significant investment Increase complexity of the TBD transformers and feeders network
Preferred Option & Justification Use smart meters to control peak loads, and dynamic equipment ratings for the 33kV feeder and transformer to defer the investment. Construct a new zone substation closer to the load centre when the investment cannot be deferred any further.
SECTION 5 NETWORK DEVELOPMENT PLANS 5-145 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Figure 5-44: New zone substation fed from the Onekawa D feeder
5-146 SECTION 5 NETWORK DEVELOPMENT PLANS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
5.8 Expenditure Forecasts and Reconciliation
SECTION 5 NETWORK DEVELOPMENT PLANS 5-147 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
6 LIFE CYCLE ASSET MANAGEMENT PLANNING Power sensing equipment installed on overhead lines to improve Unison’s real time monitoring of the network. Power sensing equipment installed on overhead lines to improve Unison’s LIFE CYCLE ASSET MANAGEMENT MANAGEMENT ASSET 6 LIFE CYCLE SECTION PLANNING
SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN 6-1 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
6 Life Cycle Asset Management Plan ...... 6-3
6.1 Maintenance Planning Criteria and Assumptions ...... 6-3 6.1.1 Objective ...... 6-3 6.1.2 Determining Optimal Level of Maintenance Expenditure ...... 6-3 6.1.3 Maintenance Practices ...... 6-3 6.1.4 Standard Life ...... 6-4 6.1.5 Risk ...... 6-5
6.2 Routine and Preventative Inspection and Maintenance Policies ...... 6-5 6.2.1 Maintenance Strategy ...... 6-5 6.2.2 Systemic Asset Failures ...... 6-13 6.2.3 Maintenance Budget (to be updated as per 2012/13 Business Plan) ...... 6-31 6.2.4 Procurement Practices and New Asset Technical Evaluation ...... 6-31
6.3 Non Network (Smart Grid) Solutions ...... 6-31 6.3.1 Risk Management ...... 6-36
6.4 APEX Renewal Planning Criteria and Assumptions ...... 6-37 6.4.1 Asset Renewal Policy ...... 6-37 6.4.2 Assumptions Made in Renewal Expenditure Modelling ...... 6-37 6.4.3 Replacement Costs ...... 6-37 6.4.4 Renewal Envelope ...... 6-37 6.4.5 Indirect Renewals ...... 6-38 6.4.6 External Review ...... 6-38 6.4.7 Alternatives to Renewal ...... 6-38
6.5 Life Cycle Asset Management Expenditure Forecasts ...... 6-39 6.5.1 Renewal Expenditure Forecast ...... 6-40
6.6 Summary of Renewals Projects Planned ...... 6-44 6.6.1 Summary Description of Proposed Renewal Projects (2013 - 2016) ...... 6-48 6.6.2 High Level Summary of Proposed Renewal Projects (2017 - 2021) ...... 6-49
6.7 Renewal and Refurbishment Projects ...... 6-49 6.7.1 Overhead Line Renewal Maintenance Projects ...... 6-49 6.7.2 Refurbishment of Zone Substation Transformers ...... 6-50 6.7.3 Refurbishment of Distribution Transformers ...... 6-51
6.8 Expenditure Forecasts and Reconciliation ...... 6-52
6-2 SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Figure 6-1: DTS Overview ...... 6-32 Figure 6-2: Powersense Current Sensor ...... 6-34 Figure 6-3: Insulator Pollution Monitoring ...... 6-35
Table 6-1: Overhead lines ...... 6-6 Table 6-2: Underground cables ...... 6-7 Table 6-3: Zone substations ...... 6-8 Table 6-4: Distribution transformers and voltage regulators ...... 6-9 Table 6-5: Distribution switchgear ...... 6-10 Table 6-6: Miscellaneous distribution equipment ...... 6-11 Table 6-7: SCADA control and communications ...... 6-11 Table 6-8: Unison maintenance standards ...... 6-12 Table 6-9: Maintenance budget ...... 6-31 Table 6-10: Risk Management of Major Project deferrals ...... 6-36 Table 6-11: Proposed renewal capex projects 2012/13 ...... 6-47 Table 6-12: Summary description of proposed renewal projects (2013-2016) ...... 6-49 Table 6-13: Overhead line renewal maintenance projects ...... 6-50
Graph 6-1: Overhead line faults ...... 6-14 Graph 6-2: Annual motor accident-related faults ...... 6-15 Graph 6-3: Bird strikes on overhead lines ...... 6-16 Graph 6-4: Underground cable failures ...... 6-18 Graph 6-5: Distribution transformer faults ...... 6-24 Graph 6-6: Distribution switchgear faults ...... 6-26 Graph 6-7: Vegetation related faults ...... 6-30 Graph 6-8: Regional renewal investment ...... 6-40 Graph 6-9: Overhead lines renewal investment ...... 6-41 Graph 6-10: Underground cables renewal investment ...... 6-41 Graph 6-11: Distribution transformer renewal investment ...... 6-42 Graph 6-12: Distribution switchgear renewal investment ...... 6-42 Graph 6-13: Other distribution equipment renewal investment ...... 6-43
SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN 6-3 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
6 Life Cycle Asset Management Plan
6.1 Maintenance Planning Criteria and Assumptions
6.1.1 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 2012/13 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.
6.1.2 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 Risk Management section of the 2012 Asset Management Plan covers the requirements of the Safety Management Systems.
6.1.3 Maintenance Practices An overview of Unison’s maintenance practices is provided below. The asset specific sections provide further detail on maintenance practices.
6.1.3.1 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.
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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 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).
6.1.3.2 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.
6.1.3.3 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.
6.1.4 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.
SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN 6-5 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
6.1.5 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.
6.2 Routine and Preventative Inspection and Maintenance Policies
6.2.1 Maintenance Strategy Overhead Lines
Asset Class Maintenance Type Action Related Standards(1)
33kV Asset Inspection/ Annual visual inspection. Condition Assessment 5 yearly detailed inspections. NK5020 Annual aerial inspection for worst performing feeders.
Routine and Preventative Maintenance: NK5119 Preventative Maintenance identified by inspections and the defect Maintenance process. Vegetation Control: NK1003 Tree maintenance identified by inspections and the defect process. Feeder Section Priorities set by the Vegetation Prioritisation Tool (VPT).
Refurbishment and Refurbishment – Not applicable. Renewal Maintenance Renewal – Preventative ‘like for like’ replacements of NK5119 non-capital assets.
Fault and Emergency First response. NK5119 Maintenance Reactive repairs.
11kV Asset Inspection/ 5 yearly detailed inspections. NK5020 Condition Assessment
Routine and Preventative Maintenance: NK5119 Preventative Maintenance identified by inspections and the defect Maintenance process. Vegetation Control: NK1003 Tree maintenance identified by inspections and the defect process. Feeder Section Priorities set by the Vegetation Prioritisation Tool (VPT).
Refurbishment and Refurbishment – Not applicable. Renewal Maintenance Renewal – Preventative ‘like for like’ replacements of NK5119 non-capital assets.
Fault and Emergency First response. NK5119 Maintenance Reactive repairs. Low Voltage Asset Inspection/ 5 Yearly detailed inspection. NK5020 Condition Assessment Routine and Preventative Maintenance: NK5119 Preventative
6-6 SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Asset Class Maintenance Type Action Related Standards(1) Maintenance Maintenance identified by inspections and the defect process. Vegetation Control: NK1003 Tree maintenance identified by inspections and the defect process. Feeder Section Priorities set by the Vegetation Prioritisation Tool (VPT).
Asset Class Maintenance Type Action Related Standards(1)
Refurbishment and Refurbishment – Not applicable. Renewal Maintenance Renewal – Preventative ‘like for like’ replacements of NK5119 non-capital assets.
Fault and Emergency First response. NK5119 Maintenance Reactive repairs.
Poles (All Voltages) Asset Inspection/ Annual visual inspection (33kV). Condition Assessment 5 yearly detailed inspection (all voltages). Wood poles – Deuar Mechanical Partial Load Deflection NK5020 Testing (MPT 40). Other poles – Visual inspection. Routine and Preventative Maintenance: Preventative Maintenance identified by inspections and the defect NK5119 Maintenance process.
Refurbishment and Refurbishment - Not applicable. N/A Renewal Maintenance Renewal – Capital asset.
Fault and Emergency First response. NK5119 Maintenance Minor reactive repairs.
(1) Unison Maintenance Standards Table 6-1: Overhead lines
Underground Cables
Asset Class Maintenance Type Action Related Standards(1)
33kV Asset Inspection/ 5 yearly visual inspection of High Voltage Pole Rise NK5020 11kV Condition Assessment Cable Terminations (as part of the Overhead Line Low Voltage Feeder Inspection). Streetlight and Annual visual or detailed inspection (depending on NK5017 accessibility) of High Voltage Cable Terminations to Security Ground Mounted Equipment (as part of GMI-Inspection). Annual inspection of 33kV gas cable. MS5200 Cable testing. NK4020 Routine and Preventative Maintenance: Manufacturer’s Preventative Maintenance identified by inspections and the defect Standard Maintenance process.
Refurbishment and Refurbishment - Not applicable. N/A Renewal Maintenance Renewal - Capital asset.
SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN 6-7 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Asset Class Maintenance Type Action Related Standards(1)
Fault and Emergency First response. Manufacturer’s Maintenance Reactive repairs. Standards
(1) Unison Maintenance Standards Table 6-2: Underground cables
Zone Substations
Asset Class Maintenance Type Action Related Standards(1) Power Transformers Asset Inspection/ Station Inspections: (including Tap Changer Condition Assessment Level 1 – Weekly visual inspection. NK5012 and Voltage Regulator): Level 2 – 2 monthly detailed inspection. NK5013 33kV/11kV Transformer – Annual DGA Oil Test. NK5042 Regulator – Oil test when serviced. NK5043 Routine and Routine Services: Preventative Transformer – 2 yearly. Maintenance Tap changers – 2 yearly or 6 yearly, depending on tap changer type. Regulator – 2 yearly, 5 yearly or 10 yearly depending on NK5042 make and model. Preventative Maintenance: Maintenance identified by inspections and the defect process.
Refurbishment and Refurbishment – Transformer and oil refurbishment. NK5043 Renewal Maintenance Renewal – Capital asset.
Fault and Emergency First response. NK5042 Maintenance Reactive repairs. Circuit Breakers: Asset Inspection/ Station Inspections: 33kV (Indoor and Condition Assessment Level 1 – Weekly visual inspection. NK5012 Outdoor) Level 2 – 2 monthly detailed inspection. NK5013 11kV (Indoor and Partial Discharge Test – 2 yearly. Outsourced Outdoor) Oil Test – When serviced. NK5043 Routine and Routine Services: Preventative SF6 – 3 yearly. Maintenance Vacuum – 3 yearly. Oil – 2 yearly. NK5038 & Oil – Fault service after every fault operation. NK5040 Preventative Maintenance: Maintenance identified by inspections and the defect process.
Refurbishment and Refurbishment – Not applicable. N/A Renewal Maintenance Renewal – Capital asset.
Fault and Emergency First response. NK5038 & Maintenance Reactive repairs. NK5040
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Asset Class Maintenance Type Action Related Standards(1) Load Control Plants: Asset Inspection/ Station Inspections: NK5012 Ripple Injection Plants Condition Assessment Level 1 – Weekly visual inspection. NK5013 Level 2 – 2 monthly detailed inspection. Routine and Routine Services: Preventative Annual service. Maintenance Preventative Maintenance: NK5024 Maintenance identified by inspections and the defect process.
Refurbishment and Refurbishment – Not applicable. N/A Renewal Maintenance Renewal – Capital asset.
Fault and Emergency First response. NK5024 Maintenance Reactive repairs. Substation Buildings and Asset Inspection/ Station Inspections: Equipment: Condition Assessment Level 1 – Weekly visual inspection. NK5012 Station Batteries and Level 2 – 2 monthly detailed inspection. NK5013 Battery Chargers Routine and Routine Services: Protection relays Preventative Batteries – 2 monthly general service, 6 monthly NK5041 Station Control Maintenance discharge tests. Indicators and Alarms Relays – Electro-Mechanical (4 yearly), Electronic (6 NK5022 Earth Testing yearly), Microprocessor (6 yearly). Thermovision Station Control Indicators and Alarms – 4 yearly. NK5023 Grounds and Buildings Earth Tests – 5 yearly. Outsourced
Thermovision – Annually. NK5080 Preventative Maintenance: Maintenance identified by inspections and the defect process.
Refurbishment and Refurbishment – Not applicable. Renewal Maintenance Renewal – Preventative ‘like for like’ replacements of non-capital assets.
Fault and Emergency First response. NK5041 Maintenance Reactive repairs. NK5022 NK5023
(1) Unison Maintenance Standards Table 6-3: Zone substations
SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN 6-9 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Distribution Transformers and Voltage Regulators
Asset Class Maintenance Type Action Related Standards(1)
Transformers: Asset Inspection/ Condition Annual GMI-Inspection. NK5017 Assessment Ground Mounted Earth Test – 5 yearly. NK5011 Pad Mounted Routine and Preventative Routine Service: Maintenance Corrective maintenance (asset alive) as part of the annual GMI-Inspection. NK5017 Preventative Maintenance: Shutdown Maintenance identified by the GMI- Inspection and the defect process.
Refurbishment and Renewal Refurbishment – Transformer refurbishment and NK6001 Maintenance painting. Renewal – Capital asset.
Fault and Emergency First response. Maintenance NK5017 Reactive repairs.
Pole Mounted Asset Inspection/ Condition 5 yearly visual inspection (as part of the Overhead NK5020 Transformers Assessment Line Feeder Inspection). Earth test – 5 yearly. NK5011 Routine and Preventative Preventative Maintenance: Maintenance Maintenance identified by inspections and the defect NK5020 process.
Refurbishment and Renewal Refurbishment – Not applicable. Maintenance N/A Renewal – Capital asset.
Fault and Emergency First response. Maintenance NK5020 Reactive repairs.
Voltage Regulators Asset Inspection/ Condition 2 monthly detailed inspections. NK5015 Assessment Oil test - When serviced. NK5043 Earth test – 5 yearly. NK5011 Routine and Preventative Routine Service: Maintenance 2 yearly or 5 yearly depending on make and model. Preventative Maintenance: NK5042 Maintenance identified by inspections and the defect process.
Refurbishment and Renewal Refurbishment – Not applicable. Maintenance N/A Renewal – Capital asset.
Fault and Emergency First response. Maintenance NK5075 Reactive repairs.
(1) Unison Maintenance Standards Table 6-4: Distribution transformers and voltage regulators
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Distribution Switchgear
Asset Class Maintenance Type Action Related Standards(1)
Ring Main Switches: Asset Inspection/ Condition Annual GMI-Inspection. NK5017 ABB Assessment Earth Test – 5 yearly. NK5011 Andelect Routine and Preventative Routine Service: Magnefix Maintenance Corrective maintenance (asset alive) as part of the Statter annual GMI-Inspection. NK5017 Other Preventative Maintenance: Shutdown Maintenance identified by the GMI- Inspection and the defect process.
Refurbishment and Renewal Refurbishment – Painting. NK6001 Maintenance Renewal – Capital asset. Fault and Emergency First response. NK5017 Maintenance Reactive repairs. Air Break Switches Asset Inspection/ Condition Annual visual inspection (33kV). NK5020 Assessment 5 yearly visual inspection (11kV). NK5020 Both inspections form part of the overhead Line NK5036 Feeder Inspection. Earth Test – 5 yearly. NK5011 Routine and Preventative Preventative Maintenance: Maintenance Maintenance identified by inspections and the defect NK5020 process.
Refurbishment and Renewal Refurbishment – Not applicable. N/A Maintenance Renewal – Capital asset. Fault and Emergency First response. NK5020 Maintenance Reactive repairs. Reclosers/ Asset Inspection/ Condition Reclosers/Sectionalisers – Annual detailed NK5016 Sectionalisers Assessment inspection. (including Auto Links) Auto Links – Annual visual inspection. NK5016 Earth Test – 5 yearly. NK5011 Routine and Preventative Routine Service: Maintenance 2 yearly or 5 yearly depending on make and model Preventative Maintenance: NK5034 Maintenance identified by inspections and the defect process.
Refurbishment and Renewal Refurbishment – Not applicable. N/A Maintenance Renewal – Capital asset.
Fault and Emergency First response. NK5034 Maintenance Reactive repairs. (1) Unison Maintenance Standards Table 6-5: Distribution switchgear
SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN 6-11 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Miscellaneous Distribution Equipment
Asset Class Maintenance Type Action Related Standards(1)
Pedestals: Asset Inspection/ Condition Inspection of Ground-mounted Low Voltage Lo-Ped Assessment Distribution Equipment as and when required by NK5019 Hi-Ped Unison (including minor repairs). Steel Routine and Preventative Preventative Maintenance: PVC Maintenance Maintenance identified by inspections and the defect NK5019 process.
Refurbishment and Renewal Refurbishment – Not applicable. Maintenance Renewal – Preventative ‘like for like’ replacements of NK5019 non-capital assets.
Fault and Emergency First response. NK5019 Maintenance Reactive repairs.
(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 Asset Inspection/ Condition General Communications Equipment Inspections – Communications Assessment 2 monthly. Equipment Station UHF Equipment Inspections – 6 monthly. NK5028 Station VHF SCADA Equipment Inspection – 6 monthly. Routine and Preventative Preventative Maintenance: Maintenance Maintenance identified by inspections and the defect NK5028 process.
Refurbishment and Renewal Refurbishment – Not applicable. N/A Maintenance Renewal – Capital asset.
Fault and Emergency First response. NK5028 Maintenance Reactive repairs.
(1) Unison Maintenance Standards
Table 6-7: SCADA control and communications
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Unison Maintenance Standards
Reference No Title NK1003 Vegetation Control Procedure NK4020 Testing of Cable Assets NK5011 Inspection and Testing of Standard and SWER Earths NK5012 Station Level 1 Inspections NK5013 Station Level 2 Inspections NK5015 Voltage Regulator Inspections NK5016 Line Recloser Inspections NK5017 Ground-mounted Distribution Equipment – Inspection Standard NK5019 Safety Inspection Standard for Ground-mounted Assets – Low Voltage NK5020 Feeder Survey and Condition Monitoring Standard NK5022 Protection Relay Maintenance and Testing NK5024 Ripple Plant Inspection and Maintenance NK5035 Outdoor Instrument Transformer Maintenance NK5036 Disconnector and Earth Switch Maintenance NK5038 Metalclad Switchgear Maintenance NK5040 Outdoor Circuit Breaker Maintenance NK5041 Station Battery Maintenance NK5042 Power Transformer Maintenance NK5043 Insulating Oil Maintenance
NK5070 Sulphur Hexafluoride (SF6) Use and Handling Procedures NK5080 Thermovision Inspection NK5119 Basic Distribution Line Maintenance NK6001 Network Painting Standard NK5034 Line Recloser Maintenance NK5075 Network Voltage Regulator Maintenance NK5023 Station Control Indication and Alarm Testing MS5200 Gas Insulated Cable Sheath Testing and Repair NK5028 Radio and Communications Maintenance Standard
Table 6-8: Unison maintenance standards
SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN 6-13 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
6.2.2 Systemic Asset Failures
6.2.2.1 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 possums 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. It should be noted however, that the incidence of opossum contacts has dropped dramatically over the last few years with the intense Pest Destruction activities directed at these pests.
There is some steel core corrosion in the ACSR lines and significant deterioration of copper conductors within areas where geothermal gasses (H2S and SO2) are present.
Some softwood poles with poor preservative retention are “piping” although at this stage these are generally not failing in service.
Insulator failures are occurring due to the corrosion of the steel head pins. These failures are difficult to locate and can cause outages.
Where these incidents are occurring the use of Corona (ultra sound type technology) is being used more frequently to detect this failure mode and, where there is an identified trend of this type of failure occurring, blanket replacement of these old style insulators is being undertaken with new Sold Post Porcelain insulators.
Asset damage from motor accidents in all regions of Unison’s network remains at a stable number of incidents per year.
Maintenance Philosophy and Practice Unison’s philosophy is to use condition based maintenance and undertake asset renewals based on asset condition surveys completed in accordance with Unison technical standards. These surveys are also used to assess remaining asset life, and are conducted on a five year cycle for all distribution and sub-transmission circuits.
In addition to these surveys, sub-transmission circuits are visually inspected on an annual basis.
The results of these RLE assessments are fed back into the RE model. Frequency of inspections may be increased if fault rates in particular areas increase to an unacceptable level.
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).
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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.
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.
Overhead Line Faults 450 400 350 300 250 200 33kv Overhead Fault Count 150 11kv Overhead 100 50 0 2006/07 2007/08 2008/09 2009/10 2010/11
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 for identifying and quantifying vegetation related issues. This method of survey is a lot quicker than ground-based inspections meaning the time between identification, prioritisation and remedial action is condensed. 50% of all rural poles are concrete and do not require ground based inspection.
The current five yearly ground based inspection programme has been 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.
SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN 6-15 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Unison is adopting the use of Hendrix Spacer Cable system where traditional bare wire circuits require high ongoing maintenance and there are reliability concerns.
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 non network solution that potentially offers significant improvements in system reliability.
Motor Accident Related Faults 50 45 40 35 30 25
Fault Count 20 15 10 5 0 2006/07 2007/08 2008/09 2009/10 2010/11 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 placement of reflective markers along with the painting of lower pole sections to increase the visibility of poles on high volume traffic areas will continue.
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Bird Strike Faults 35
30
25
20
15 Fault Count 10
5
0 2006/07 2007/08 2008/09 2009/10 2010/11 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.
Some research is being considered into whether there is any correlation between overall bird populations and the number of bird strikes on an annual basis.
A study would look to see if the bird populations vary to any great degree annually and as to whether this is due to differing climatic conditions.
6.2.2.2 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. Cables of this era when implicated with network construction requiring isolation from service for lengthily periods invariably return below standard test results before being energised, prompting cable replacement or repair.
Aluminium sheaths on these XLPE cables have also suffered due to corrosion as moisture enters the cables over time resulting in eventual insulation degradation.
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
SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN 6-17 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
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 occurring on a regular scale.
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.
Older, particularly the old “Power Board” epoxy type joints and terminations fail over time usually because of moisture ingress in some cases more prematurely due to cable core manipulation during construction works. These failures generally occur earlier than actual cable failure.
Single cored 11kV “interruption” cables do fail due to the treeing phenomenon mentioned previously. This category of assets was purchased from 1962-1977 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. This type of cable presents similar problems as mentioned with 1970’s XLPE cable when exposed to prolonged periods of being out of service.
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.
There have been several 11kV heat shrink terminations in the Central Region affected by surface partial discharge resulting in insulation degradation. The discharge prompted by cable termination location and environmental conditions.
Excavators and contractors operating directional drilling equipment continue to represent considerable risk to cable assets. This will be exacerbated by the directional drilling associated with the national fibre roll out specific to urban areas. Unison is taking steps to mitigate this risk.
Maintenance Philosophy and Practice Asset condition inspections of all cable terminations and risers are undertaken in accordance with Unison standards. Recently introduced non invasive partial discharge testing of cable terminations has proven invaluable, and will be included in the ground mount inspection programme. 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 has been evaluated resulting in the introduction of an extended liability period and electronic capture of workman identification for all cable joints and terminations.
Recent 33kV cable installations have had fibre optic cables installed to allow future mapping of the operating temperatures down the length of the cable.
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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 life cycle management practices to effectively manage this asset class in the coming years as a large portion of the cables near end of life.
11kV Underground Cable Faults 30
25
20
15 Fault Count 10
5
0 2006/07 2007/08 2008/09 2009/10 2010/11 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 and where the opportunity presents itself, installs ducts for network future proofing in conjunction with roading rehabilitation work. 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.
6.2.2.3 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.
SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN 6-19 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
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.
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.
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 assistance of manufacturer’s maintenance agents will be more regularly required to have this equipment correctly maintained.
New transformers recently purchased have tap changers fitted with vacuum bottle tap changer switching and these tap changers are generally maintenance free.
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.
Insulation testing of the transformer windings remains the primary test for all transformers. Values are recorded so that any deterioration can be investigated.
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. Six transformers had oil refurbishment in 2011 as high acidity, increasing moisture, total combined gasses and other parameters were outside the recommended limits.
Furans in the insulation oil have been tested for the second 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.
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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 that this may defer transformer 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 transformer’s future requirements. It has been decided that the two Flaxmere transformers be sent for refurbishment work to provide future life extension transformers of a similar age and type that have been refurbished have had loose windings and packing dislodged and it is expected that these transformers will be in a similar condition. 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.
6.2.2.4 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 biennial partial discharge testing.
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 implementing the use of operator Arc Flash protection when operating circuit breakers and other equipment. Also safety improvements to the RPS indoor switch boards are being investigated to provide maximum operator protection when required to operating this equipment. The RPS circuit breaker is the most common circuit breaker in use by Unison.
A failure of a surge arrestor fitted inside a 33kV outdoor circuit breaker caused major damage to that circuit breaker. Investigation indicated that a lightning storm had passed the substation the night before and may have caused the arrestor to fail. Arrestors were removed from similar model circuit breakers and relocated externally.
SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN 6-21 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
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 SF6 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. 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.
The Tannery Road switch board is in the poorest condition in the network and will be recommended for replaced in the 2013 period.
Several old 33kV AEI JB424 circuit breakers are at end of life or are under rated. Three of these circuit breakers are programmed to be replaced in Centennial Drive substation in 2012.
Condition, age, function, location, criticality, fault levels, performance and cost history are all taken into account before replacing the asset.
Outages are planned in conjunction with the maintenance requirements of other associated equipment so as to minimise outage time.
Partial Discharge Test This has become a regular tool for non-invasive condition assessment of circuit breaker 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.
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6.2.2.5 Other Substation Equipment and Buildings Failure Modes and Risks Current transformers installed in old Reyrolle LMT indoor circuit breakers show some insulation deterioration when subjected to partial discharge testing. This is being monitored as failure can cause considerable damage.
The outdoor insulators used to support bus bars and on disconnectors are regularly inspected with an ultrasonic locator. This equipment will detect noise from insulators which indicates that the insulator may be faulty.
The outdoor insulators at the Awatoto substation are cleaned six monthly of salt deposits to prevent flash over from contamination.
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 at joints in the bus bar or on disconnector contacts.
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.
Buildings and fences are regularly inspected to ensure they remain in good condition to provide site security and protect equipment.
Substation security is progressively being upgraded with new doors and locks being installed at some substations and new intruder detection being installed.
A risk assessment of the Hawke’s Bay Substations was completed in January 2012 and a remedial works programme will be carried out over the next 2 years to bring substation buildings up to the requirements of the New Building Standard. The remaining substation buildings will be assessed later in 2012 by a civil engineer for seismic compliance following the events in Christchurch. Other major substation equipment such as transformers and control panels will also be included in this investigation. The investigation will include risk assessment from liquefaction, flooding and tsunami.
Bunding of transformers is also continuing at substations. This work includes the installation of drainage equipment designed to prevent transformer insulation oil from entering the environment.
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.
SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN 6-23 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
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 and ultrasonic survey of all substation HV equipment is completed annually to locate hot spots and insulation leakage that may indicate possible areas of failure.
6.2.2.6 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.
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 ground- mount assets, but some assets need to be replaced due to external influence such as motor accidents.
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Distribution Transformer Faults 10
8
6
4 Faults Count
2
0 2006/07 2007/08 2008/09 2009/10 2010/11 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. Additionally the triple-R investment tool is utilised to evaluate the option of refurbishment.
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.
Regular invasive condition monitoring of transformers under 750kVA that 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.
Unisons invasive inspection of all ground-mount transformers is now on an annual cycle. This has ensured site security and 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.
SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN 6-25 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
6.2.2.7 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.
Of recent several RMS units of the SD range have failed in service due to insulation breakdown at the bus couplers. The bus coupler design facilitates the addition of extra switches to existing switch sites. These failures were attributed to the installation of non guro- flex couplers associated with a combination of inherent switch design, workmanship and environmental issues.
A partial discharge testing regime and preventative maintenance plan will be introduced to mitigate the frequency of these failures.
Cable termination failure and subsequent damage to the associated RMS has also contributed to the replacement for these assets, specifically in the Central Region (refer underground cables section 6-2).
Early retirement of RMS units can be due to smart grid initiatives, oil leaks from gaskets and seals or damage resulting from motor accidents.
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. It is planned to have all magnefix type switches replaced by the end of 2012.
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.
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.
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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 25
20
15
10 Faults Count
5
0 2006/07 2007/08 2008/09 2009/10 2010/11 Year
Graph 6-6: Distribution switchgear faults
RMS’s are inspected as part of the annual ground-mount inspection (GMI) regime with the now newly included partial discharge testing regime. This non invasive test now quantifies the level of partial discharge at switch sites providing a measure of seriousness in determining a time based priority to affect any remedial work.
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.
Due to the risks associated with failure of oil insulated switchgear, Unison has introduced a new SF6 type 11kV Safe Link switch as a reliable and cost effective alternative product replacing the use of oil insulated switchgear.
SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN 6-27 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
6.2.2.8 Load Control Plant Failure Modes and Risks The ripple plant in Hawke’s Bay and Taupo Rotorua continues to provide good service.
In Hawke’s Bay 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.
New plant installed at the Fleet Street substation in Taupo also provides a reasonable level of redundancy should any individual asset fail in Taupo.
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.
6.2.2.9 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.
Recent failures of LV fuses installed in pedestals in Central Region, more specifically in Rotorua are of concern and under investigation.
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.
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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.
6.2.2.10 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.
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 defines the 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.
A significant amount of the growth entering into line corridors is now subject to CTN notices and the number of sites where this is occurring is increasing.
The Taupo region is generally good with only a small number of areas where line security is being compromised by growth in close proximity.
As in the Hawke’s Bay region, many of these sites have trees subject to CTN notices that are re-entering the line corridor.
In the Rotorua region Unison’s focus has been to regain control and bring the area to the same standard as other parts of its network.
This has primarily been achieved and as with the other two regions CTN related trees figure prominently in the growth re- entering into the line corridor.
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:
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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. This was the situation that arose in the severe wind storm event in the Taupo Region in April 2011, when in excess of twenty five poles were broken and extensive lengths of line were downed by falling forest stands.
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.
Maintenance Philosophy and Practices 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.
To effectively manage the feeder section priorities Unison has developed a Vegetation Prioritisation Tool (VPT) to identify the most urgent cutting priorities. This tool looks at the network performance, associated with vegetation related faults and adjusts the priorities on a monthly basis in conjunction with the contractors achieved cutting statistics for that month.
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Vegetation Related Faults 100 90 80 70 60 50 40 Fault Count 30 20 10 0 2006/07 2007/08 2008/09 2009/10 2010/11 Year
Graph 6-7: Vegetation related faults
6.2.2.11 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.
SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN 6-31 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
6.2.3 Maintenance Budget (to be updated as per 2012/13 Business Plan)
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 1 Year 2 Year 3 Year 4 Year 5 Year 6 Year 7 Year 8 Year 9 Year 10 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 First Response 1,360 1,360 1,360 1,272 1,272 1,188 1,025 1,025 1,025 1,025 Overhead Lines 2,760 2,760 2,760 3,385 3,385 3,331 3,226 3,215 3,090 3,090 Underground Cables 638 638 638 576 576 547 491 491 481 481 Circuit Breakers 241 241 241 200 200 198 194 194 182 182 Zone Substation Buildings and Equipment 529 529 529 437 437 435 430 430 401 401 Power Transformers 196 196 196 172 172 170 165 165 156 156 Distribution Transformers and Regulators 1,072 1,072 1,072 1,111 1,111 1,103 1,087 1,085 1,026 1,026 Distribution Switchgear 335 335 335 322 322 318 310 309 293 293 Load Control Plant 60 60 60 49 49 49 49 49 45 45 Miscellaneous Distribution Equipment 565 565 565 489 489 474 445 445 426 426 Vegetation 1,226 1,226 1,226 998 998 998 998 998 926 926 System Control 56 56 56 48 48 47 44 44 42 42 Communications 332 332 332 299 299 284 256 256 250 250 TOTAL 9,370 9,370 9,370 9,358 9,358 9,141 8,720 8,706 8,344 8,344 Table 6-9: Maintenance budget
6.2.4 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. The Committee will continue to evaluate new products that are potentially useful to improving network performance, or save on costs to Unisons Networks. The TEC will also be involved in a review of the types and sizes of cables used on Unisons Networks.
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.
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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 cable 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 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. 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
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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 10 second interval for 30 minutes. The initial and the final measured temperatures are then used to calculate the thermal resistivity.
Unison has deployed this technology on the City 33kV feeder between Windsor substation and the overhead termination structure off the end of Jubilee Street. Initial data from this trial has been analysed and results appear promising. The data will be sent to and validated by an external consultant. A larger rollout of this technology has been put into place and will target highly loaded sub-transmission cables across the Unison network.
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 we can accurately determine ratings which may result in the deferral of expensive line upgrades.
A pilot project consisting of thirteen weather stations and twenty line temperature sensors has been commissioned on a critical 33kV line (Onekawa D). The data from the weather stations in conjunction with the temperature sensors will be fed into an algorithm to determine its dynamic rating. Based on the success of the pilot project, weather stations will be installed on other overhead 33kV feeders which will allow the network control operators to maximise the utilisation of the feeders.
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 by the end of 2012/13 financial year.
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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.
During the 2011/12 planning period, Unison had successfully trialed both the overhead line and underground cable sensors and plans have been put in place to install these sensors across the Unison network. Once commissioned, these sensors will help the control room operators find faults quickly and thereby reducing the outage times experienced by consumers. Furthermore, the data will be used by engineers to determine which parts of the network require augmenting.
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.
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.
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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 has installed 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. If the trial is successful, these units will be rotated to gather data from different parts of the network, thereby allowing Unison to create an effective maintenance plan.
Figure 6-3: Insulator Pollution Monitoring
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6.3.1 Risk Management The implementation of these smart network solutions enables the deferral of five 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.
Deferred Project Mitigation Probability Expenditure ($k) Hastings zone substation- 11kV Increased inspection frequency. 1,100 10% Switchboard Replacement Increased inspection frequency. Transformer sensors. Load reduced with McCain’s now Flaxmere zone substation power supplied from a dedicated zone 2,100 10% transformer replacement substation. Network spare transformer purchased in 2011/12. Increased inspection frequency. Fernleaf 33kV feeder replacement 1,500 20% Line thermal sensor. Windsor zone substation - City 33kV Tan Delta Tests and remedial works to 1,200 10% feeder cables cable terminations. Installed cable markers over route. Faraday-Bluff Hill 33kV gas filled cable Informed land owners and NCC of 1,300 10% implications of damage.
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.
6.3.1.1 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 has been purchased and installed at Windsor zone substation. This transformer has been installed in a manner that will allow easy removal if it is needed elsewhere on the network.
6.3.1.2 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 2012/13.
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6.4 APEX Renewal Planning Criteria and Assumptions
6.4.1 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.
6.4.2 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).
6.4.3 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.
6.4.4 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 one 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;
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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 January 2012 at both total network and asset class levels are provided in sections below.
6.4.5 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).
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.
6.4.6 External Review Unison’s renewal investment modelling practices have been extensively reviewed by external parties to ensure they represent best practice.
6.4.7 Alternatives to Renewal Replacement is only one option to restore asset performance. Other options that are evaluated include repair, 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.
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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.
Key improvements to the forecasting approach since the last published AMP 2011 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).
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6.5.1 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.
Regional Renewal Investment 100 90 80 70 Rotorua 60 Taupo 50 Hastings 40 Napier 30 20 Renewal Investment Required ($m) Renewal Investment 10 0 1234567891011121314151617181920 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.
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Overhead Lines Renewal Investment 60
50
40
30
20
10 Renewal Investment Required ($m) Renewal Investment
0 1234567891011121314151617181920 Year
Graph 6-9: Overhead lines renewal investment
Underground Cables Renewal Investment 30
25
20
15
10
5
Renewal Investment Required ($m) Renewal Investment 0 1234567891011121314151617181920 Year
Graph 6-10: Underground cables renewal investment
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Distribution Transformers Renewal Investment 7
6
5
4
3
2
1
Renewal Investment Required ($m) Renewal Investment 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Year
Graph 6-11: Distribution transformer renewal investment
Distribution Switchgear Renewal Investment 1.4
1.2
1.0
0.8
0.6
0.4
0.2 Renewal Investment Required ($m) Renewal Investment 0.0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Year
Graph 6-12: Distribution switchgear renewal investment
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Other Distribution Equipment Renewal Investment 9 8 7 6 5 4 3 2 1 Renewal Inestment Required ($m) Renewal Inestment 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Year
Graph 6-13: Other distribution equipment renewal investment
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6.6 Summary of Renewals Projects Planned The following section lists the proposed renewal Capex projects for the 2012/13 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.
2012/13 Asset Category Description Detailed Description Total ($000) Circuit Breakers Fernleaf ZS - Replace 33kV PMB Replace the old 33kV Nu-Lec PMB with a new 33kV outdoor 189 with new Breaker and install 33kV circuit breaker and post type CT’s. CT’s Circuit Breakers Runanga ZS - 11kV Switchboard Replace the old Reyrolle LMT oil insulated switchboard with a new 1,650 and Protection Relay Replacement 11kV 2-1250A LMVP 14-breaker/bay vacuum insulated switchboard and new arc-flash protection relays. Protection Relay Runanga ZS - Transformer Tap Replace the old voltage regulator and transformer management 220 Change Control Relay relay with new numeric relays. Replacement Circuit Breakers Replace Taupo South 11kV Replace the old remaining GEC BVP oil insulated switchboard 45 Switchboard with a new 11kV 1250A LMVP 5-breaker/bay vacuum insulated switchboard and new arc-flash protection relays. Circuit Breakers Centennial Drive Sw/Stn - 33kV Replace the old 33kV JB424 AEI circuit breakers with new 33kV 655 Outdoor CB 309, CB 512 & CB outdoor circuit breakers and post type CT’s. 542 Replacement Protection Relay Rangitane ZS - 11kV feeder Replace the old electronic RACID OC/EF protection relays on the 247 Protection Relay Replacement existing 11kV switchboard with new numeric OC/EF protection relays. Lines Reconductor 11kV at extension of Reconductor 11kV at extension of Gordon Road - Te Awanga. 15 Gordon Road - Te Awanga Lines 33kV Structure Replacement 33kV Structure Replacement Powdrell Road. 1,300 Powdrell Road Lines Meihana feeder Pole Renewals Meihana feeder Pole Renewals. 6 Lines Artiamuri feeder Pole Renewals Artiamuri feeder Pole Renewals. 121 Lines Kaiwaka feeder Pole Renewals Kaiwaka feeder Pole Renewals. 31 Lines Ongaroto feeder Pole Renewals Ongaroto feeder Pole Renewals. 67 Distribution Replace 10x Fibreglass Several existing ground mount transformers have fibreglass 135 Transformers transformer covers in Hastings, covers, which have deteriorated. Napier, Rotorua & Taupo area Lines Te Aute feeder Pole Renewals Te Aute feeder Pole Renewals. 65 Lines Omahu feeder Pole Renewals Omahu feeder Pole Renewals. 14 Lines Te Mata feeder Pole Renewals Te Mata feeder Pole Renewals. 18 Lines Acacia Bay feeder Pole Renewals Acacia Bay feeder Pole Renewals. 28 Lines Twyford feeder Pole Renewals Twyford feeder Pole Renewals. 134
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Asset Category Description Detailed Description Total ($000) Lines Pohokura feeder Pole Renewals Pohokura feeder Pole Renewals. 131 Lines Puketapu feeder Pole Renewals Puketapu feeder Pole Renewals. 85 Lines Puketitiri feeder Pole Renewals Puketitiri feeder Pole Renewals. 95 Lines Tangoio feeder Pole Renewals Tangoio feeder Pole Renewals. 71 Lines Valley feeder Pole Renewals Valley feeder Pole Renewals. 208 Lines Clayton feeder Pole Renewals Clayton feeder Pole Renewals. 76 Lines Kaharoa feeder Pole Renewals Kaharoa feeder Pole Renewals. 140 Lines Okere feeder Pole Renewals Okere feeder Pole Renewals. 162 Lines Whakapirau feeder Pole Renewals Whakapirau feeder Pole Renewals. 77 Lines Orchard feeder Pole Renewals Orchard feeder Pole Renewals. 30 Lines Richmond feeder Pole Renewals Richmond feeder Pole Renewals. 15 Distribution Replacement of Statter Switch Replacement of an aged 11kV switch with extensive oil leaks. 93 Switchgear 3151/F3152/3153/3220 Distribution Replacement of Statter Switch Replacement of an aged 11kV switch with continued oil leaks. 81 Switchgear 3182/F3181/3010 Lines Western Heights feeder Pole Western Heights feeder Pole Renewals. 80 Renewals Distribution Replace Magnefix Unison is progressively removing all Magnefix type switches from 160 Switchgear F838/1430/1431 its network due to safety and environmental concerns. Distribution Replace Magnefix 722/1785/2083 Unison is progressively removing all Magnefix type switches from 100 Switchgear its network due to safety and environmental concerns. Distribution Replace Magnefix Unison is progressively removing all Magnefix type switches from 190 Switchgear F886/1312/1313 its network due to safety and environmental concerns. Distribution Replace Magnefix 2473/2471/2472 Unison is progressively removing all Magnefix type switches from 80 Switchgear its network due to safety and environmental concerns. Distribution Replace Magnefix 1835/1834/1836 Unison is progressively removing all Magnefix type switches from 140 Switchgear its network due to safety and environmental concerns. Distribution Replace Magnefix 1509/1510/1689 Unison is progressively removing all Magnefix type switches from 80 Switchgear its network due to safety and environmental concerns. Distribution Replace Magnefix 1243/1244/1245 Unison is progressively removing all Magnefix type switches from 93 Switchgear its network due to safety and environmental concerns. Distribution Replace Magnefix 1903/1904/1905 Unison is progressively removing all Magnefix type switches from 80 Switchgear its network due to safety and environmental concerns. Lines Alexandra feeder Pole Renewals Alexandra feeder Pole Renewals. 12 Lines Albert feeder Pole Renewals Albert feeder Pole Renewals. 12 Distribution Replace sub 2599 at 18 Walton Replacement of transformer due to rust related issues. 60 Transformers and Way, opposite Ardrossan Avenue Regulators Distribution Replace sub 4177 at Oliver Road Replace transformer due to extensive oil leaks. 60 Transformers and and Enfield Road Regulators
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Asset Category Description Detailed Description Total ($000) Distribution Replace transformer 2713 at Replacement of transformer due to rust related issues. 45 Transformers and 46 Ullyat Road Regulators Distribution Replace transformer 1555 at Replacement of transformer due to rust related issues. 95 Transformers and 500 Kiwi Street Camberley Regulators Distribution Replace transformer 1831 at Replacement of transformer due to rust related issues. 55 Transformers and 812 Kiwi Street Camberley Regulators Distribution Replace sub 4423 at Marine Replace transformer due to extensive oil leaks. 65 Transformers and Parade & Albion Street Regulators (Cosmopolitan Club) Distribution Replace transformer 96 at Replacement of transformer due to rust related issues. 55 Transformers and 8 Selwyn Road Havelock North Regulators Transformers and Replace transformer 2106 at Replacement of transformer due rust related issues. 55 Regulators 29 Frickleton Street Transformers and Replace transformer 1930 at Replacement of transformer due rust related issues. 55 Regulators 85 Clarence Cox Crescent Transformers and Replace sub 2000 at 1005 Replacement of transformer due rust related issues. 60 Regulators Oliphant Road. Lines Fordlands feeder Pole Renewals Fordlands feeder Pole Renewals. 76 Lines Broadlands feeder Pole Renewals Broadlands feeder Pole Renewals. 121 Lines Heuheu feeder Pole Renewals Heuheu feeder Pole Renewals. 46 Lines Clive feeder Pole Renewals Clive feeder Pole Renewals. 42 Lines Wharewhaka feeder Pole Wharewhaka feeder Pole Renewals. 35 Renewals Lines Waitangi feeder Pole Renewals Waitangi feeder Pole Renewals. 10 Lines Rochfort feeder Pole Renewals Rochfort feeder Pole Renewals. 8 Transformers and Replace transformer 2496 Valerie Replacement of transformer due rust related issues. 55 Regulators Street, Hastings Transformers and Replace Transformer Transformer requires relocation and replacement due to location. 55 Regulators 1248 Prebensen Drive Napier Provisional Sum for Reactive and Provisional Sum for Reactive and Unplanned Renewals. 2,800 Unplanned Renewals Lines Conductor Replacement Harper Conductor Replacement Harper Road Waimarama. 165 Road Waimarama Underground Cables Clinkard Avenue LV mains cable The existing LV mains cable traverses private property and 105 made redundant. requires relocation to the road reserve area. Underground Cables Rotorua CBD Street Light cable The existing design of the street light system and cable type is not 120 design and installation T3811, conducive to the harsh underground environment and CBD area T2512 and T4006 (Tutanekai and requires to be redesigned and replaced. Road
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Asset Category Description Detailed Description Total ($000) Replace temporary overhead line A previous cable fault was overcome by installing a temporary 150 built in 2008 between subs 1828 overhead 11kV line. This line now requires replacement with and and 1825 Henley Crescent underground cable. Protection Relay Tomoana ZS - Transformer Replace the old ASEA electronic transformer protection schemes 86 Protection Relay Replacement with new numeric transformer differential protection schemes. Protection Relay Mahora ZS - Transformer Replace the old ASEA electronic transformer protection schemes 84 Protection Relay Replacement with new numeric transformer differential protection schemes. Protection Relay Irongate ZS - Transformer Replace the first generation numeric transformer protection 82 Protection Relay Replacement schemes with new numeric transformer differential protection schemes. Protection Relay Hastings ZS - 33kV feeder Replace the old ASEA electronic feeder protection schemes with 38 Protection Relay Replacement new numeric feeder differential protection schemes. Protection Relay Irongate ZS - 33kV feeder Replace the first generation numeric feeder protection schemes 36 Protection Relay Replacement with new numeric feeder differential protection schemes. Protection Relay Marewa ZS - 33kV feeder Replace the old ASEA electronic feeder protection schemes with Protection Relay Replacement new numeric feeder differential protection schemes. 38 Protection Relay Hastings ZS - Transformer Replace the old ASEA electronic transformer protection schemes Protection Relay Replacement with new numeric transformer differential protection schemes. 94 Protection Relay Camberley ZS - 33kV feeder Replace the numeric OC/EF feeder protection schemes with new Protection Relay Replacement numeric feeder differential protection schemes. 46 Distribution Mitigation of common bus config Mitigation of common bus config problem and Rotorua N-1 issues. Switchgear problem and Rotorua N-1 issues 30 Distribution Automation of switches to transfer Automation of switches to transfer load from Arawa to Rotorua Switchgear load from Arawa to Rotorua and and Biak in case of A sub-transmission cable failure. Biak in case of A sub-transmission cable failure 70 Zone Substation Seismic Strengthening of Zone Seismic strengthening of selected zone substation buildings to 1,000 Buildings Substation Buildings comply with the new building code standard.
Table 6-11: Proposed renewal capex projects 2012/13
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6.6.1 Summary Description of Proposed Renewal Projects (2013 - 2016)
Financial Year Project Name 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 off 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
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Financial Year Project Name Second bank at Fernleaf Vaughan Sub - Stage 2 Redclyffe - Whakatu 33kV inter-tie automation Replace 11kV conductor - Rotoma feeder, beyond fuses S1051 - Manawahe Road 2015/2016 Fernleaf zone substation – install T2 Irongate new feeder towards Paki Paki Upgrade Wairakei-Runanga Replace transformer 1979 Replace sub 3771 - 588 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 T2487 - Malfroy Road
Table 6-12: Summary description of proposed renewal projects (2013-2016)
6.6.2 High Level Summary of Proposed Renewal Projects (2017 - 2021) 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
6.7.1 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:
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Area Feeder Operating Voltage Hastings Albert 11kV Alexandra 11kV Clive 11kV Meihana 11kV Orchard 11kV Simla 11kV Te Aute 11kV Te Mata 11kV Twyford 11kV Napier Puketapu 11kV Puketitiri 11kV Tangoio 11kV Valley 11kV Waitangi 11kV Rotorua and Taupo Atiamuri Village 11kV Broadlands 11kV Clayton 11kV Fordlands 11kV Kaharoa 11kV Pururu 11kV Western Heights 11kV Fernleaf 33kV
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.
6.7.2 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.
SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN 6-51 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
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.
6.7.3 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.
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6.8 Expenditure Forecasts and Reconciliation
SECTION 6 LIFE CYCLE ASSET MANAGEMENT PLAN 6-53 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
7 RISK MANAGEMENT
RISK MANAGEMENT Faultman Paul Jones discusses the dangers of electricity with a class of primary school children. SECTION 7 SECTION
SECTION 7 RISK MANAGEMENT 7-1 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
7 Risk Management ...... 7-3
7.1 Introduction ...... 7-3
7.2 Risk Management Policy ...... 7-3 7.2.1 Policy Objective ...... 7-3 7.2.2 Statement of Policy ...... 7-3
7.3 Risk Management Framework ...... 7-3 7.3.1 Risk Responsibility and Governance ...... 7-4 7.3.2 Risk Tolerance ...... 7-4 7.3.3 Risk Management Tools ...... 7-6
7.4 Risk Identification ...... 7-8 7.4.1 Key Risks ...... 7-8 7.4.2 Asset Risks ...... 7-9
7.5 Risk Assessment...... 7-22 7.5.1 Evaluation Process ...... 7-22
7.6 Risk Mitigation ...... 7-22 7.6.1 Natural Hazard Mitigation ...... 7-23 7.6.2 Engineering Solutions ...... 7-23 7.6.3 Equipment Failure Mitigation – Maintenance Programmes ...... 7-24
7.7 Risk Readiness ...... 7-25 7.7.1 Development, Maintenance, Review and Testing of Response Plans ...... 7-25 7.7.2 Civil Defence Emergency Management Engagement ...... 7-25
7.8 Response to Network Incidents and Emergencies ...... 7-26 7.8.1 Specific Contingency Plans ...... 7-27
7.9 Health and Safety ...... 7-29 7.9.1 Health and Safety Policy and Company Commitment ...... 7-29 7.9.2 Workplace Safety – Key Performance Indicators ...... 7-30
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Figure 7-1: Environmental audit framework ...... 7-21
Table 7-1: Key Risk Examples ...... 7-9 Table 7-2: Asset risks ...... 7-17 Table 7-3: Management of the Risks associated with the Smart Grid initiative ...... 7-19
Graph 7-1: Lost time injury frequency rate (LTIFR) - July 2010 – June 2011 ...... 7-30
SECTION 7 RISK MANAGEMENT 7-3 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
7 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
7.2.1 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.
7.2.2 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 is 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 key business strategies as the cornerstones for all operations and decision-making:
Build and grow an efficient, profitable business;
Deliver stakeholder management and customer service;
Actively and continuously improve processes, systems and operational performance;
Support employee commitment, motivation and performance. Key performance indicators underpin this strategy. Particularly pertinent from a risk management perspective are: 7-4 SECTION 7 RISK MANAGEMENT UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Proactive management of key business risks; and
Ensuring best practice health and safety.
7.3.1 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 Business Assurance 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.
7.3.2 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 31000 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.
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The colour-coding of risks is as follows:
Risk Level Meaning Very High Risk 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. High Risk 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. Medium Risk 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. Low Risk 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 Indicators Control is appropriately planned and designed and is operating as intended to address the relevant business risks. Effective The control environment is providing a high level of assurance that business objectives will be achieved. Operating at 75-100% effectiveness for the risk. Control is appropriately planned and designed, however there are still additional improvement opportunities in the control environment. Satisfactory 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. Improvements are required in order to achieve an acceptable level of assurance that business objectives will be Improvement Required 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. Ineffective Control is not contributing to an assurance that business objectives will be achieved. Operating at < 25% effectiveness for the risk.
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Reliance Assessment Indicators Operation of this control is critical to management of the risk. Without this control this risk would revert to its Critical inherent risk status. This control plays a key role in the management of the risk. The presence of other controls (significant or Important 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 Significant has been reduced. Control could be considered important were it not for the presence of other controls. The absence of this control Routine would not change the classification of the risk.
7.3.3 Risk Management Tools
7.3.3.1 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 7.4.1. 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.
7.3.3.2 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 an in-house Sharepoint 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.
7.3.3.3 Public 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 Public Safety Management System (PSMS) 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. SECTION 7 RISK MANAGEMENT 7-7 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
The objective of the PSMS 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 PSMS 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 PSMS must be fully implemented and have been externally audited by 31 March 2012.
Unison underwent Stage 1 of the auditing process on 21 December 2011. This initial audit achieved a good report with only 3 partial attainments (PA) and 1 unattained (UA). The UA statement is “A procedure relating to the identification and management of records relating to the SMS must be documented and implemented.” In order to meet this requirement Unison has undertaken a full review of the document management system and a project has been commissioned to fully document these processes. This project will be completed by March 2012.
Stage 2 of the audit will be undertaken in March 2012.
Unison has developed the Public Safety Management System utilising Sharepoint. The Sharepoint portal houses the main PSMS documents and hyperlinks to Policies, Procedures, AMP and the Hazard Identification data source.
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The General Manager Business Assurance is named in the PSMS as being responsible for the management and maintenance of the system. The Business Assurance Group is also responsible for risk and environmental management. The Health and Safety Manager as the administrator of the system is responsible for ensuring continuous improvement actions and internal auditing are progressed.
Unison has adopted the EEA and GANZ developed hazard management toolkit to monitor and report on identified hazards to the public and their property. As part of continuous improvement to the PSMS the hazard management tool may migrate to the Quantate system that Unison uses to manage key corporate risks.
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.
7.4.1 Key Risks The Company’s Key Risk Register includes the following asset-related risks:
Risk Title Definition Risk of fatality or serious harm to a member of the Public - Public Safety – Death or Serious Harm Injury through unauthorised access to network assets, or as a result of Ref. 7.9.1 a third party workplace accident or incident involving network assets. SECTION 7 RISK MANAGEMENT 7-9 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Risk Title Definition Workplace Safety – Employees and Contractors Risk of fatality or serious harm injury to a Unison employee or Ref. 7.9.2 contractor. 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 Network Performance – Deterioration of Network SAIFI; Ref. Section 4 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 inappropriate prioritisation of identified risks and the associated allocation of resources at the operational level. Loss of Mission Critical Systems – IT or SCADA Loss or failure of either the IT network or the SCADA system. Ref. 7.8.1 Catastrophic event with significant damage to Risk of a natural disaster (such as a major earthquake or volcanic network assets event) may at any time affect a significant portion of the network Ref. 7.8.1 area, destroying or damaging assets. This considers a widespread/worldwide pandemic, with a closed border situation. Likelihood that Unison would be unable to Loss of Human Resources due to a natural event continue to deliver critical business activities in the event of an Ref. 7.8.1 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 Lack of Skilled Contractors to support both Unison: existing network and future plans Inability to spend allocated/planned CAPEX/OPEX; Ref. 7.6.3.4 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
7.4.2 Asset Risks
7.4.2.1 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 7-10 SECTION 7 RISK MANAGEMENT UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
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 7.4.2.4 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.
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 2008. 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).
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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 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.
7.4.2.2 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 Risk Type Failure Consequences Mitigating actions Level Mode/Risk Network Zone Substations Network Security breach Injury or death of Network competency and by intruder / the intruder. supervision procedures. unauthorised Network security – including: access and Controlled locks and contact with live keys; parts. Alarms linked to Control Room; Surveillance camera; Protocol for access - Restricted Area Entry; Station Entry Log to record legitimate visitors. Loss of supply. Operational procedures for re-routing supply. 7-12 SECTION 7 RISK MANAGEMENT UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Asset Category Asset Location Risk Type Failure Consequences Mitigating actions Level Mode/Risk Customer Interruption to Loss of supply – All of the above measures; supply caused by resulting in loss of Operating Contingency intruder accessing productivity, Plans. live parts. impact on medical dependencies and loss of security. Unison/Contractor Risk of contact Injury/death. Protocols for issuing Personnel safety with live parts; Network controlled locks and keys; Risk to personnel Restricted Area Entry without required protocols; competencies. Unison Competency requirements (incl. supervision); Unison operating procedures; Contract terms and conditions. Public Safety / Security Breach Injury or Death. Security arrangements: Property damage by a member of Security Fence;Intruder the public Alarms;Surveillance (unauthorised camera;Protocols for access) resulting issuing Network in contact with live controlled locks and keys; parts. Warning Signs; Emergency Contact Phone number displayed at station. Public Education programmes. Monitoring adjoining structures and vegetation to eliminate access opportunities.
Power Zone Substation Network INTERNAL FAILURES: Transformers Massive loss of oil Environmental Installation of oil containment contamination. system (bunding).
Oil leaks Transformer Regular inspections and outage. repairs; Availability of oil spill response kits. Internal fault/s Transformer Annual DGA survey outage. indication of potential problem from gas analysis. Insulation Transformer Insulation testing; Breakdown outage. Depolarisation test; Refurbishment. SECTION 7 RISK MANAGEMENT 7-13 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Asset Category Asset Location Risk Type Failure Consequences Mitigating actions Level Mode/Risk Overload – Over- Transformer On-Line monitoring by heating outage. Control Room.
Failure from old Transformer Transformer Management age Outage. Plan; Replacement Programme; Availability of Critical Network Spares.
EXTERNAL IMPACTS: Corrosive General Regular Inspections; environment mechanical Preventive maintenance; deterioration. Asset renewal.
General Mechanical failure Painting; deterioration of Tap Changer. Refurbishment; Regular Maintenance. Work by Damage during Training and/or supervision. inexperienced maintenance. personnel (Lack of Qualified Staff) Customer Transformer Network Outage. N-1 Security. outage Oil Spill Environmental Installation of oil containment contamination. system; Availability of oil spill response kits. Unison/Contractor Live Equipment; Personal injury or Use of appropriate PPE Personnel safety Mechanical death. Operating standards; danger Training and supervision. Oil spill Environmental Oil spill response kits. contamination. Inexperience of Damage to Staff training/supervision and maintenance staff equipment, i.e. use of experienced tap changers. maintenance personnel. Public Safety / Unauthorised Access to live As for substations above Property damage access to parts. Physical asset security – substation – incl. fences, locks, monitored contact with live alarms; parts Public education programmes; Control of alternative methods of access (adjoining structures and vegetation). Contamination of Environmental Installation of oil containment ground water by damage; system; oil. Drinking water Oil spill response kits. affected. 33kV Porcelain Zone Substation; Network Type Failure Network Outage. Ultrasonic Survey of installed Insulators Sub-transmission same-type insulators. 7-14 SECTION 7 RISK MANAGEMENT UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Asset Category Asset Location Risk Type Failure Consequences Mitigating actions Level Mode/Risk lines Insulation Failure Flying materials – Cleaning programme. porcelain. Contamination Outage. Feeder Inspections. Customer Insulation or type Outages. As above (Network). failure Unison/Contractor Insulation failure Being hit by flying Appropriate PPE and work Personnel safety materials procedures. (porcelain). Public Safety/ Insulation failure Being hit by flying Substation and worksite Property damage materials security; (porcelain). Follow-up on type failure; Maintenance programmes. Circuit breakers Zone Substation / Network Fail to operate Network Outages Regular preventive Sub-transmission Slow to operate Operation of next maintenance. lines upstream device Distribution lines causing larger outage. Insulation Failure Network Outage. Partial Discharge Survey.
Customer Equipment failure Network Outages. Back feed; Parallel supplies; Provision of generators. Unison/Contractor Work by Damage during Training / supervision; Personnel Safety inexperienced maintenance. Deployment of experienced personnel staff for maintenance work. Public Safety / Contact with live Injury or death. Testing, inspection and property damage equipment maintenance programmes. Protective gear: Zone Substation Network Battery Failure Loss of SCADA Regular Inspections. Batteries and 11 kV Switches control. battery chargers Loss of Battery Testing; protection. Battery Monitoring. Customer Above failure Network outages. As above. Unison/Contractor Contact with Injury/burns. Use of task-specific PPE. Personnel safety battery acid Public safety Loss of protection Injury /death. Regular inspections; Property damage – risk of contact Battery testing regime. with live parts Protection Relays Zone Substation Network Mechanical relays Operation of Fault Analysis; and Schemes Sub-transmission fail or slow to upstream device Regular Testing; network operate causing larger Protection Relay Upgrade to Distribution network outage than Microprocessor Relays.. necessary. Customer Above failure Network outages As above (Network). Unison/Contractor - - No exposure as able to Personnel safety download fault info on-line. Public safety/ Loss of protection Injury /death. Regular inspections; Property damage – risk of contact Monitoring and testing of with live parts protection schemes. SECTION 7 RISK MANAGEMENT 7-15 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Asset Category Asset Location Risk Type Failure Consequences Mitigating actions Level Mode/Risk Old XLPE cables Underground in Network HV cable failure Network outages. Progressive replacement of Hawke’s Bay from ingression of cable type. water into cable sheath Customer Above failure Network outages. As above.
Unison/Contractor HV for Testing On-site Injury. Use of task-specific PPE; Personnel safety Following Test Procedures.
Public Safety / Public access to Injury. Control of site. Property damage worksite Fencing off of hazards. Hawke’s Bay: 33kV UG cable in road Network Damage by third Bluff Hill Outage. Regular on-site gas nitrogen gas cable reserve and private party excavation monitoring. between Faraday property Cable markers installed and Bluff Hill zone No Spares NCC awareness. substations available. Technical Assistance Contract with contractor. Regular Testing. Customer Loss of supply Port of Napier Parallel or back feed from Outage; Faraday; Large Industrial Generator use. sites affected. Unison/Contractor Gas under Injury from high Reduce pressure prior to Personnel safety pressure pressure gas. work. HV Electrical injury. De-energised when being repaired; Procedure for identification of cable. Public Safety/ Exposure to gas Injury or death. Public awareness; Property damage and/or live cable – NCC awareness and particularly on warnings to residents; private property Warning signage; Annual testing. Rotorua: Arawa UG Cable in Road Network Damage by third Network Outage. Regular Testing. 33kV cable Reserve party excavation RDC awareness for road openings; Regular Unison/RDC meetings Customer Loss of supply Outage Rotorua Parallel feeds. CBD - Business Feeds from Biak Street. interruption. Unison/Contractor Hazards from Serious harm De-energised when repairing Personnel safety road opening injury. third party damage.
H2S Gas Gas Hazard. Use of gas detection equipment and procedures. Public Safety / Access to Injury. Secure, enclosed worksites; Property damage worksite Fenced off hazards. 7-16 SECTION 7 RISK MANAGEMENT UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Asset Category Asset Location Risk Type Failure Consequences Mitigating actions Level Mode/Risk Rotorua: Rotary Zone Substation Network Old Age Inability to control Regular Inspections. ripple control plants loads for energy Replacement strategy. retailers. Possible change in frequency. Customer Loss of control No hot water, Manual operation. No lighting. Unison/Contractor Injury from Injury. Use of appropriate PPE. Personnel safety rotating plant Observing Operating HV Capacitor Procedures. Discharge Public Safety/ - - - Property damage Statter switches Distribution Network Auto Fuse Switch Operation of up- Progressive replacement of Equipment slow to operate stream device; switches; Larger outage Inspection and maintenance; than necessary; Pitch-filled Cable Failure of pitch Partial discharge Boxes and Bus insulation. Chambers Customer As above Outage. Parallel supplies. Unison/Contractor Operating Switch Death or injury. Operational restriction on Personnel safety failure switching; Utilising full PPE. Public Safety / Public in vicinity Death or injury. Operational restriction; Property damage Secure/enclosed worksite. Power surge Damage to Public education in regard to consumer’s plant, RCD protection. equipment, or appliances. Magnefix switches Distribution Network Cable Termination A two part programme has Equipment Termination failure. been put in place to replace Insulation Failure these switches by 2014. Corrosion of Plugs corroded in contacts position. Customer Single Phase Requires large As above. operation outage to repair. Unison/Contractor Operating Hazard Death or injury. Utilising specialist PPE and Personnel safety observing correct operating procedures. Public safety/ Public in vicinity Death or injury. Secure enclosed worksite. Property damage of the work site. Mark I Andelect Distribution Network Poor design; plus Switch failure and Progressive Replacement of switches Equipment history of welding outage; the remaining 242 switches failures on the network. Oil Leaks Environmental Oil spill clean-up procedures damage; and kit; SECTION 7 RISK MANAGEMENT 7-17 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Asset Category Asset Location Risk Type Failure Consequences Mitigating actions Level Mode/Risk Cable Outage. Partial Discharge Survey or Termination Ultrasonic Survey. Failure Customer As above Network Outage. As above. Unison/Contractor Operating Hazard Death or injury. Utilising specialist PPE and Personnel safety following correct operating procedures. Public safety/ Public in vicinity Death or injury. Secure the worksite from Property damage when there is a public. cable termination failure
Table 7-2: Asset risks
7.4.2.3 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. A volcanic or tsunami event would trigger the Crisis Management Plan, while the remaining natural hazard events trigger the Emergency Response Plan operated by the Unison Control Centre.
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.
The recent Canterbury earthquakes have been a reminder of the vulnerability of buildings and the network to these effects. As a result Unison has commissioned engineering surveys of all of its buildings – including zone substations. As part of these surveys the soil is being tested and graded (assisting in determination of site vulnerability to liquefaction) and the buildings are being assessed for seismic compliance with the current Building Code. Because most have been built to earlier Building Code requirements, these findings will assist in the prioritisation of any identified remedial work.
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As the Hawke’s Bay region is reasonably distant from any active volcano it is not at risk from the highly damaging near- source 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 1995-1996 events).
The impact of natural hazard events are regularly tested in regional civil defence exercises in which the Company participates (BayShake, BayWash, AshBay and 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.
The most recent Crisis Management exercise was conducted in October 2011.
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 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 7.6.1 for natural hazard mitigation activities.
7.4.2.4 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.
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Risk Risk Management
Network risk caused Detailed network analysis has been undertaken to ensure that the risk created by project deferral will not by CAPEX deferrals result in the network becoming overloaded, or in an exponential increase in equipment failures due to old age. Most notably: 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. 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. 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. 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.
Regulatory risk (SAIDI It is well understood in reliability engineering that asset performance is correlated with asset age. The and SAIFI) deferral of renewal projects will result in a reduction of asset RLE. The associated regulatory risk can be managed for the following reasons: The network has demonstrated increased resilience to significant meteorological events through increased automation and improved design standards since 2004. 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.
Sustainability of the The strategy that has been selected will ensure the sustainability of the contracting market by meeting contracting market (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 significantly year on year.
Availability of required The contracting market has been informed of the smart grid initiative and is working with Unison to ensure skill-sets 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
7.4.2.5 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 7-20 SECTION 7 RISK MANAGEMENT UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
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.
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 7.3.3.2). 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.
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The environmental audit framework is depicted in Figure 7-1 below:
Biennial, alternating Underaken as required
Field Audit Planning Audit Discreet Audit
Asset Audit of systems Audit of specific inspections and records assets or sites Site inspections Analysis of District Following material changes in legislative Work practices Plans environment
Overlap in critical areas for more frequent Inform periodic auditing regime by flagging assurance: high risk sites and assets
Hazardous substance management
Resource consents Conditions of designations High risk areas identified may drive further discrete audits
Figure 7-1: Environmental audit framework
Environmental Audit The table below summarises progress through Unison’s environmental auditing programme to date:
Year Scope Outcome All premises’ audited were deemed to be of a high standard and a general awareness of Comprehensive 2006 environmental issues was noted. Several minor issues were discovered relating to resource Environmental Audit consents. Business Planning Key focus areas of the audit included management of hazardous substances, compliance with Audit ongoing conditions of site designations and ensuring Unison has acquired all the resource consents 2008 required for its operations. The outcome of the audit was favourable with only several minor non- compliances noted. A re-visit to all sites deemed non-compliant in the 2008 audit confirmed Unison had corrected Follow-up 2010 the minor issues previously noted. A high standard of environmental management was noted Environmental Audit with very few minor issues noted.
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2010 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. Possible Consent issue with Hawke’s Bay truck wash facility. All zone substation transformers appeared to be leaking oil in Zone Substations 7 100% extremely minor amounts. These amounts were deemed insignificant with no improvement needed. Minor oil leaks were noticed on various switches. These were Switching Stations 2 100% deemed insignificant with no improvement needed. All pole-mounted distribution transformers inspected were Pole Mounted Distribution 11 100% deemed compliant. One transformer was identified to be Transformers ‘sweating’ oil. All ground mounted distribution transformers inspected were Ground Mounted 13 100% deemed compliant. Graffiti was noted on several ground Distribution Transformers mounted transformers. High Risk Sites – noted in All high risk sites noted in the 2006 audit were re-visited and 5 100% 2006 audit deemed to be compliant.
7.5 Risk Assessment
7.5.1 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.
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7.6.1 Natural Hazard Mitigation
Substations – Mitigation Seismic strengthening Strengthening all electrical equipment to protect assets from the impact of an earthquake. This includes a 2 year substation building strengthening programme to achieve compliance with the New Building Code Standard (Section 6.2.2.5). Strategic location Selecting substation sites away from areas at risk from landslides and/or serious flooding. Network security Shutdown individual substations and backfeed supply, in the event of an emergency (e.g. fire, malicious damage, flooding, tsunami etc.). Fire detection systems Provision of fire detection and fire prevention systems in substations.
Network Design, Materials and Construction Load-shifting capacity Improvement in load-shifting capability in the Taupo/Rotorua area where the feeders are largely radial, making load–shifting problematic. Improved design 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 7.4.2.3 Environmental Risk.
7.6.2 Engineering Solutions
Mitigation through Engineering Projects and Programmes Unison Engineering Project to provide a high-level overview of key engineering standards in order to assess Standards their coverage and adequacy and to identify new requirements and improvements. Condition Assessment As part of the Company’s continuous improvement programme, assets are inspected at Programme 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 7.4.2.4). Network Design 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. Obsolescence 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.
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7.6.3 Equipment Failure Mitigation – Maintenance Programmes
7.6.3.1 Reactive Maintenance Unison Networks has assigned the responsibility for the restoration of service and supply throughout its regions to Unison’s Contracting Services Limited, 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 replacement or augmentation is required then a risk assessment is instigated (involving Network Development engineers) to determine the appropriate permanent solution.
7.6.3.2 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.
7.6.3.3 Specific Development Projects The following development projects are planned to mitigate identified equipment failure risks:
Upgrading of Maraekakaho zone substation in Hastings – completed and commissioned;
Following a review of the earthquake resilience of equipment and buildings, a programme of strengthening and refurbishment projects will be established;
Installation of a second transformer at Fernhleaf zone substation – planned for 2013/2014 commissioning;
Reinforcement of Tamatea zone substation – planned for 2013/2014 commissioning.
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7.6.3.4 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.
7.7 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.
7.7.1 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 Group 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.
7.7.2 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 2002.
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.
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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.
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 An incident is treated as an Responsibilities: Triggers: Response Type: occurrence that is an Concentrate on completion of tasks Awareness that a (developing) Operational expected but assigned/set down in procedures to situation requires a targeted unforeseeable/unplanned deal with the incident and return to response, or business as usual. event and falls within the Activation of a pre-planned Examples: procedure (e.g. an outage or Company’s normal system Third party damage to a network asset; accident response). tolerance levels. After-hours faults; and Contingency plans or pre- Minor storm damage etc. planned response procedures are in place. Level 2 - Emergency An emergency is an Responsibilities: Triggers: Response Type: unplanned event that Provide early and effective emergency Existing resources are Tactical requires an immediate and damage limitation response; stretched and the situation is significant response by the Activate Unison’s FC9003 Emergency deteriorating; or Company. It presents or has Response Plan and FC9002 Crisis The Company’s reputation Communication Plan if required; may be at stake. the potential to present, a Determine priorities in allocating major disruption to the resources; normal operation of the Coordinate and manage on-going business and is too Level 3 incident response; and problematic to be handled in Obtain resources as required. a timely manner using business-as-usual resources and capabilities. SECTION 7 RISK MANAGEMENT 7-27 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Level 1 - Crisis An adverse event or series The Executive adopt all command, Trigger: Response Type: of events, that due to its control and coordination functions, Group CEO’s decision that Strategic magnitude, impact and delegating tasks they deem strategic direction is required. associated risks requires appropriate to the crisis event. executive involvement or Responsibilities: specific management Activate FC9001 Crisis Management coordination. Plan; The event may be a major Identify, confront and resolve the crisis; natural or man-made Determine how the Level 2 Emergency disaster or some other event Response is to proceed; involving Unison that results Determine priorities; in the loss of life, serious Provide direction and make executive decisions; injury or severe distress to Provide resources; staff, consumers or Prioritise demands; members of the public, Provide forward planning for returning and/or disruption to services, to “business as usual” after the crisis significant damage to has been resolved; and equipment, or a potential Identify and maximise opportunities or loss of confidence in advantages arising from the crisis. Unison’s ability to safely supply energy.
7.8.1 Specific Contingency Plans
7.8.1.1 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 recognises that it must position 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).
7.8.1.2 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 pre- planned.
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.
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7.8.1.3 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 de- energise 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.
7.8.1.4 IT Disaster Recovery Plan An IT Disaster Recovery facility is co-located with the Company’s Alternate Operational Control Centre.
Unison Business Continuity exercises have 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 departmental business continuity arrangements in place, the Company plans 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.
7.8.1.5 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.
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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.
7.9.1 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 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.
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7.9.2 Workplace Safety – Key Performance Indicators
Rolling 12 Month Lost Time Injury Frequency Rate (LTIFR) 16
14
12
10
8
6 4.7 3.8 4 2.3 2.3 2.0 2.0
Lost Time Injuries/Million Hours worked 2 0.0 0.0 0.0 0.0 0.0 0.0 0 Jul-10 Aug-10 Sep-10 Oct-10 Nov-10 Dec-10 Jan-11 Feb-11 Mar-11 Apr-11 May-11 Jun-11
Number of LTI's Rolling 12 Month LTIFR Industry Benchmark
Graph 7-1: Lost time injury frequency rate (LTIFR) - July 2010 – June 2011
7.9.2.1 Lost Time Injuries Unison monitors performance in this area by reporting on the Lost Time Injury Frequency Rate (LTIFR). The target set by the Electrical Engineers Association of New Zealand is derived from the industry for the industry and is reset annually to incorporate continuous improvements. The benchmark set for an electricity distribution business the size of Unison for the July 2010 to June 2011 period was 14. Unison’s results were well below the benchmark level within this period. The recent review and subsequent benchmark reset has seen the Unison target decrease to 1.9. This new target will be a challenge for the Company to achieve.
7.9.2.2 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 renewed in 2011 is for the combined operations of Unison Networks Limited and Unison Contracting Services Limited and will be subject to audit again in 2013.
7.9.2.3 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. SECTION 7 RISK MANAGEMENT 7-31 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
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.
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 quarterly 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.
7.9.2.4 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.
7.9.2.5 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. 7-32 SECTION 7 RISK MANAGEMENT UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
7.9.2.6 Security, Barriers and Signage Unison has in place stringent procedures governing the security of assets and the restriction of physical access to Unison’s electrical network and associated equipment.
7.9.2.7 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 management and the Board and remains current. The importance of child safety is reflected in this programme now targeting 2500 children a year.
7.9.2.8 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.
Unison has recently produced an educational DVD based on the “Be Aware – Electricity Kills” presentation. Unison plans to supply this DVD to the above-mentioned target companies as well as to plant and equipment hire firms. The DVD was produced locally and features Unison staff in authentic scenarios. It carries a testimonial from a local company whose employee accidently came into contact with live electricity lines.
SECTION 8 EVALUATION OF PERFORMANCE 8 EVALUATION OF PERFORMANCE
Soil temperature monitoring on 33kV underground cables improves cable utilisation of Unison’s underground network assets.
SECTION 8 EVALUATION OF PERFORMANCE 8-1 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
8 Evaluation of Performance ...... 8-3
8.1 Purpose ...... 8-3
8.2 Progress against 2011/12 Capital Expenditure Plan ...... 8-3 8.2.1 Financial Progress ...... 8-3 8.2.2 Physical Progress ...... 8-4
8.3 Progress against 2011/12 Maintenance Expenditure Plan ...... 8-7 8.3.1 Financial Progress ...... 8-7 8.3.2 Physical Progress ...... 8-8 8.3.3 Progress against Maintenance Initiatives ...... 8-9
8.4 Performance against Service Levels for 2011/12 ...... 8-9 8.4.1 Explanations for Service Level Targets not Met ...... 8-10 8.4.2 Time Series Data ...... 8-10
8.5 Progress through Asset Management Initiatives ...... 8-14
8.6 Gap Analysis and Improvement Initiatives ...... 8-15
8.7 Review of Quality of Asset Management Planning and the AMP ...... 8-16
Figure 8-1: SAIDI Performance time series...... 8-10 Figure 8-2: SAIFI performance time series ...... 8-11 Figure 8-3: Total Costs per ICP time series ...... 8-11 Figure 8-4: Total Costs per km time series ...... 8-12 Figure 8-5: Capacity utilisation time series ...... 8-12 Figure 8-6: Loss ratio time series ...... 8-13 Figure 8-7: Faults per 100km performance time series ...... 8-13
Table 8-1: Progress against 2011/12 CAPEX budget ...... 8-3 Table 8-2: Variances to 2011/12 CAPEX budget as projected February 2012 ...... 8-4 Table 8-3: Status of renewal projects planned for 2011/12 ...... 8-5 Table 8-4: Status of network development projects planned for 2011/12 ...... 8-6 Table 8-5: Progress against 2011/12 maintenance budget as projected February 2012 ...... 8-7 Table 8-6: Variances to 2011/12 OPEX budget as projected February 2012 ...... 8-8 Table 8-7: Physical Progress through maintenance programmes ...... 8-8 8-2 SECTION 8 EVALUATION OF PERFORMANCE UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Table 8-8: Progress against maintenance initiatives ...... 8-9 Table 8-9: Performance against service levels 2011/12 ...... 8-9 Table 8-10: Asset management initiatives 2011/12 ...... 8-14 Table 8-11: Gap analysis and improvement initiatives ...... 8-15
SECTION 8 EVALUATION OF PERFORMANCE 8-3 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
8 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 2011/12 Capital Expenditure Plan
8.2.1 Financial Progress The projection to the end of the 2011/12 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 (YE forecast) Variance System Growth 1,890 1,500 -21% Asset Replacement and Renewal 12,630 11,120 -12% Reliability, Safety and Environment 7750 5,290 -32% Customer Connection 8,435 6,376 -24% Asset Relocations 1000 1,760 76% TOTAL 29870 25,680 -14%
Table 8-1: Progress against 2011/12 CAPEX budget
Table 8-2 below provides an explanation for variances to budget of greater than 10%.
CAPEX Category Explanation for Variance System Growth The 2011/12 expenditure in this category was lower than forecast due to a shortage in contracting resources with the appropriate skill set to complete planned projects. This is a national issue and plans are in place to recruit new staff with the appropriate skills in order to deliver the CAPEX programme in 2013 and beyond. To this end, a number of projects in this category will still be in progress at the beginning of the 12/13 period. Asset Replacement and The 2011/12 expenditure in this category which includes overhead to underground conversion projects was Renewal lower than forecast due to a shortage in contractor resources with the appropriate skill. This was exacerbated by the deployment of contracting resources to address reactive maintenance and renewal work following asset failures Reliability, Safety and The Smart Grid Initiative CAPEX is captured in the Reliability, Safety and Environment category. The Environment 2011/12 expenditure in this category was lower than forecast due to a shortage in contractor resources with the appropriate skill set to deploy Unison’s Smart Grid. The CAPEX forecast for the Smart Grid rollout has been re-phased to allow the recruit of necessary staff and to compensate for the delay in the deployment of the mesh radio network. 8-4 SECTION 8 EVALUATION OF PERFORMANCE UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
CAPEX Category Explanation for Variance Customer Connection Asset purchases which forms part of this category is behind forecast due to the fact that several budgeted asset purchases have not gone ahead. Asset Relocations The number of customer initiated asset relocation jobs were underestimated which resulted in the variance.
Table 8-2: Variances to 2011/12 CAPEX budget as projected February 2012
8.2.2 Physical Progress Asset Replacement and Renewal Projects
Table 8-3 below shows the progress on each of the renewal projects that were planned for the 2011/12 financial year (and listed in the 2011 AMP).
Asset Category Description Status Distribution Subs and Replace Sub 2565 Yarmouth Road Flaxmere Complete Regulators Distribution Subs and Replace Sub 4854 Vautier Street Napier Complete Regulators Distribution Switchgear Replace Statter F3185 Vautier Street Napier Complete Distribution Switchgear Replace Statter Cnr Lighthouse and Seapoint Roads Napier Complete Distribution Switchgear Replace RMS 1679/1680/1681 Guppy Burness Road Complete Distribution Switchgear Replace Magnfix 1247/875/1248/1246 Southampton Street Hastings In Progress Distribution Switchgear Replace Magnefix F880/1288/1289 Sunderland Drive Flaxmere In Progress Distribution Subs and Upgrade Sub T2562 - Aquarius Drive In Progress Regulators Distribution Subs and Replace Transformer 2152 Montrose Place Complete Regulators Distribution Subs and Replace Magnefix 1368/1369/F892 with Safe Link switch Complete Regulators Distribution Subs and Replace 2 pole structure sub 1259 Williams Street, Hastings Complete Regulators Distribution Switchgear Replace existing Magnefix 1427/1429/1428 Complete Distribution Subs and Replace Transformer T2831 Lockwood Industrial Site Complete Regulators Lines Pole Renewals after Deuar Pole Testing Rotorua Area Complete Lines 11kV & LV Reconstr, Thomas Cres, Turner Drive, Leslie Ave & Spencer Street Complete Distribution Subs and Replace transformer T3669 at 15 Neri Place Rotorua Complete Regulators Lines Rotoma feeder Pole Renewals Complete Cables Replace 11kV cable on Lake Terrace feeder Complete Distribution Subs and Replace transformer 1884 Durham Drive Complete Regulators Distribution Switchgear Replace Magnefix switch 1632 1631 1630 Complete Distribution Switchgear Replace Andelect switch 3306/3303/F3304/3305 Complete SECTION 8 EVALUATION OF PERFORMANCE 8-5 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Asset Category Description Status Distribution Switchgear Replace Magnefix 898 982 983 situate at Transformer 2122 - Avenue Road East Complete Distribution Switchgear Replace Magnefix 1406/1407/1408 Cartier Street Flaxmere In Progress Distribution Switchgear Replace Magnefix 2021-2022-2023 - Cnr Kiwi and Takahe Street Flaxmere Hastings Complete Distribution Switchgear Replace Magnefix 2024/2025/2026 Complete Lines Crownthorpe feeder Pole Renewals Complete Lines Ada & Grove feeder Tie In Progress Lines Install Reclosers on Williams feeder Complete Lines Cornwall feeder Pole Renewals Complete Lines Southampton feeder Pole Renewals Complete Lines 11/12 reactive renewal and renewal bucket projects Complete Lines Paora Hapi feeder Pole Renewals Complete Lines Ngakuru feeder Pole Renewals In Progress Lines Tutukau feeder Pole Renewals Complete Lines Haumoana feeder Pole Renewals Complete Lines Iona feeder Pole Renewals Complete Lines Oreka feeder Pole Renewals Complete Lines Otamauri feeder Pole Renewals Complete Lines St Andrews feeder Pole Renewals Complete Lines Park Island feeder Pole Renewals Complete Lines Ridgemount feeder Pole Renewals Complete Lines Patoka 33kV feeder Pole Renewals Complete Lines Geddis feeder Pole Renewals Complete Power Transformers Windsor Zone Substation - 33/11kV Power Transformer purchase and installation In Progress Lines Okere Feeder Automation Complete Lines Kaharoa feeder Automation Complete Lines Pakowhai feeder Automation Complete Zone Substation Marewa ZS - Transformer Protection Relay Replacement In Progress Protection Zone Substation Faraday ZS - 33kV feeder Protection Relay Replacement In Progress Protection Zone Substation Arataki ZS - Transformer Protection Relay Replacement In Progress Protection Distribution Switchgear Install smart switches in Napier to transfer Tamatea post contingency load Complete Lines Haumoana feeder - Install Automated Switches and Current Sensors Complete Lines Install Entec Switches in Owhata Region to aid Fast Transfer of load. Complete Lines Taupo Self healing phase 1 Complete Lines Taupo Self healing phase 2 Complete Power Transformers Rebuild Maraekakaho Substation Complete
Table 8-3: Status of renewal projects planned for 2011/12 8-6 SECTION 8 EVALUATION OF PERFORMANCE UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Network Development Projects Table 8-4 below shows the progress on each of the network development projects that were planned for the 2011/12 financial year (and listed in the 2011AMP).
Asset Category Project Name Status Distribution switchgear Replace existing ABS with automated Entec Switches on Okere and Kaharoa feeders In progress Distribution switchgear Install current sensors at strategic locations on Central feeders In progress Distribution switchgear Establish a smart fast transfer scheme at Taupo to ensure Fleet Street ZS is In progress compliant to Unison’s security criteria Distribution switchgear Establish a self healing network in Taupo Region In progress Distribution switchgear Establish a smart load transfer scheme to address security constraint at Owhata POS In progress Distribution switchgear Establish a back bone mesh communication network in central region Deferred Distribution switchgear Install automated switches on Haumoana feeder Complete Distribution switchgear Install automated switches on Pakowhai feeder to improve reliability Complete Distribution switchgear Install current sensors on all feeders originating from Arataki ZS Cancelled Distribution switchgear Establish a smart load transfer scheme to address security constraint at Tamatea ZS In progress Distribution switchgear Establish a smart load transfer scheme to address security constraint at Havelock ZS In progress Distribution switchgear Establish a back bone mesh communication network in Hawke’s Bay region Deferred Lines Upgrade Bridge Pa and Raureka feeders Deferred Cables Upgrade the front end of feeders feeding from Camberley ZS In progress Cables Install a new feeder out of Rangitane ZS Complete Cables Offload Taupo North feeder onto Ben Lomond feeder by extending 11kV network In progress Cables Upgrade constrained 33kV incomer cables at Havelock North substation In progress Cables Upgrade Ngapuna and Vaughan feeders In progress Zone Subs, Buildings and Install a power transformer at Windsor zone substation In progress Equipment
Table 8-4: Status of network development projects planned for 2011/12
SECTION 8 EVALUATION OF PERFORMANCE 8-7 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
8.3 Progress against 2011/12 Maintenance Expenditure Plan
8.3.1 Financial Progress The projection to the end of the 2011/12 financial year sees Unison’s maintenance spend approximately 2% over budget. The budget split by maintenance activity is provided in Table 8-5.
Maintenance Activity Budget Actual Variance First Response 1,300,000 1,460,472 12% Overhead Lines 2,760,000 2,629,599 -5% Underground Cables 700,000 560,121 -20% Circuit Breakers 295,000 280,923 -5% Zone Substation Buildings and 602,000 729,065 21% Equipment Power Transformers 205,000 295,340 44% Distribution Transformers and 891,680 936,386 5% Regulators Distribution Switchgear 205,900 266,229 29% Load Control Plant 90,000 51,776 -42% Miscellaneous Distribution Equipment 520,000 554,582 7% Vegetation 1,287,500 1,224,950 -5% System Control 70,000 84,178 20% Communications 350,000 380,675 9% Property 310,000 303,905 -2% TOTAL 9,587,080 9,758,202 2%
Table 8-5: Progress against 2011/12 maintenance budget as projected February 2012
Table 8-6 provides an explanation for variances to budget of greater than 10% by asset category.
OPEX Category Explanation for Variance First Response First response costs are higher than expected as a result of the significant events experienced over the course of the year. Underground Cables Reactive costs for cables were below budget due to the generally good performance of the underground network. Although there has been a rise in the number of faults caused by directional drilling, these incidents typically result in replacement of damaged cable sections which means the jobs are categorised as reactive renewals and as such do not impact on the maintenance budget. Also contributing to the underspend is the re-scheduling of cable testing that had been planned for 2011/2012 - this is now programmed for 2012/2013. Zone Substation Buildings and Expenditure on zone substation buildings and equipment was higher than expected due to the Equipment requirement for work and equipment that had not initially been planned for - these include the earthquake-proofing of control panels, lighting upgrade, replacement of access door at Bluff Hill Zone Substation and the purchase of arc-flash PPE. Power Transformers The variance in this category stems from the online oil refurbishment carried out on 8 zone substation transformers in the 2010/2011 year. A delay in the invoicing for this activity meant that 8-8 SECTION 8 EVALUATION OF PERFORMANCE UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
OPEX Category Explanation for Variance the cost impact was incurred on the 2011/2012 budget. Distribution Switchgear The primary cause of the overspend in this category is the pro-active partial discharge testing program initiated for all ring main switch units following a series of in service failures. Although the result of this was a significant variance against the maintenance budget, the program identified at least 2 units that were otherwise certain to have also failed in service incurring a far more significant impact in terms of reactive costs and network performance. Load Control Plant The underspend in this category is due to the deferral of the backup services agreement with Landis+Gyr. A new agreement will come into effect for the 2012 year. System Control Reactive maintenance costs for SCADA and RTU systems were higher than expected contributing to the overspend in this category. TOTAL Minor variance.
Table 8-6: Variances to 2011/12 OPEX budget as projected February 2012
8.3.2 Physical Progress Physical progress through the planned maintenance programmes is provided in Table 8-7 below.
Maintenance Programme Progress Overhead Lines Inspection The five year inspection programme is on target through the use of ground based and aerial inspections. Overhead Lines Preventative Overall the preventative maintenance programme is on target. Some projects in this area were Maintenance deferred as measures to manage planned maintenance expenditure. Circuit Breakers Preventative The preventative maintenance programme is on target as per the cyclical zone substation Maintenance inspection and maintenance regime. It is expected that the circuit breaker scheduled maintenance will be completed by the end of the period. Other Substation Equipment & The preventative maintenance programme is on target as per the cyclical zone substation Buildings Preventative Maintenance inspection and maintenance regime. Zone Transformers Preventative The preventative maintenance programme in Hawke’s Bay is on target as per the cyclical zone Maintenance substation inspection and maintenance regime. Transformer maintenance in the Central region is marginally behind as contractor resources and skill base are limited but this is expected to be completed by the end of the period. Ground Mounted Assets Inspection The GMI programme is on target. Distribution Transformers/Regulators The preventative maintenance programme is on target. Preventative Maintenance Distribution Switchgear Preventative The preventative maintenance programme is on target. Maintenance Load Control Preventative The preventative maintenance programme has slipped behind schedule as a new maintenance Maintenance contract is being negotiated with Landis+Gyr. Miscellaneous Distribution Equipment The pedestal inspection work issued for the year has been completed and the associated remedial Inspection and Preventative work is expected to be completed by year end. Maintenance Vegetation Progress through the vegetation management plan is behind target.
Table 8-7: Physical Progress through maintenance programmes
SECTION 8 EVALUATION OF PERFORMANCE 8-9 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
8.3.3 Progress against Maintenance Initiatives
Maintenance Initiative Progress Effectiveness Vegetation Management The Vegetation Prioritisation Tool (VPT) has been Limited by Tree Regulations the Vegetation introduced to assist with vegetation that requires Programme can only manage the trees that are clearance to prevent it from impacting on the encroaching into the growth limit zones, however the network. It is expected that the VPT will take two types of faults experienced are generally attributable years to complete a full cutting cycle. to trees outside the vegetation managed line corridor. Introduction of Deuar Two testers are to be introduced to asset inspection Notable improvement in accuracy of pole tests over mechanical (non-destructive) team. ultrasound units (which can often miss rot below pole tester. ground level).
Table 8-8: Progress against maintenance initiatives
8.4 Performance against Service Levels for 2011/12 This section assesses Unison’s performance against its Service Levels as provided in the 2011 AMP. (Note that 2011/12 actual figures are projected to year end).
Service Standard Target 2011/12 Actual 2011/12 (forecast) Assessment SAIDI < 147.9 minutes 130 minutes SAIFI < 2.70 interruptions 2.3 interruptions Interruptions occurring in Maximum of twenty events to exceed three 23 events urban areas hours before supply is restored per annum Interruptions occurring in Maximum of one feeder to exceed four 4 feeders urban areas unplanned interruptions per annum Interruptions occurring in rural Maximum of ten events to exceed six hours 22 events areas before supply is restored per annum Interruptions occurring in rural Maximum of one feeder to exceed ten 2 feeders areas unplanned interruptions per annum Interruptions occurring in Maximum of five events to exceed six hours 13 events remote rural areas before supply is restored per annum Interruptions occurring in Maximum of one feeder to exceed twenty 0 feeders remote rural areas unplanned interruptions per annum Total cost per ICP <$271 $264 Total cost per km <$3,159 $2,942 Capacity utilisation >31% 29% Loss ratio <6% 5.0% Faults per 100km <7.97 faults per 100km 7.20 faults per 100km
Table 8-9: Performance against service levels 2011/12
8-10 SECTION 8 EVALUATION OF PERFORMANCE UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
8.4.1 Explanations for Service Level Targets not Met
Service Level Explanation Restoration of supply service levels 2011/12 has been a year of numerous unpredictable faults. Higher than average motor vehicle and other third party impacts on the network have played a significant role in breaching our service levels. The other large contributing factor in 2011/12 has been vegetation related faults brought about by the stronger than normal winds experienced in a La Nina weather pattern. Proactive and targeted vegetation management programmes have been accelerated to reduce the number of vegetation related faults going forward. Capacity utilisation The predominant cause of lower than expected capacity utilisation is suppressed peak demand caused by a warmer than average winter. The following was sourced from the National Institute of Water and Atmospheric research (NIWA)1: “Winter mean temperatures were well above average (more than 1.2°C above winter average) across much of the north and east of the North Island.”
8.4.2 Time Series Data The following diagrams show Unison’s performance in a selection of Service Levels over a five year period.
SAIDI Performance 180 160 140 120 100 80
SAIDI (minutes) 60 40 20 0 2007/08 2008/09 2009/10 2010/11 2011/12
SAIDI B SAIDI C Regulatory Target
Figure 8-1: SAIDI Performance time series
1 “National Climate Summary Winter 2011”. http://www.niwa.co.nz/climate/summaries/seasonal/winter-2011
SECTION 8 EVALUATION OF PERFORMANCE 8-11 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
SAIFI Performance 3
2.5
2
1.5
1 SAIFI (interruptions)
0.5
0 2007/08 2008/09 2009/10 2010/11 2011/12
SAIFI B SAIFI C Regulatory Target
Figure 8-2: SAIFI performance time series
Total Costs per ICP
300
270
240
$ per ICP 210
180
150 2006/07 2007/08 2008/09 2009/10 2010/11 2011/12 Total Costs per ICP (Real) Total Costs per ICP Service Level
Figure 8-3: Total Costs per ICP time series 8-12 SECTION 8 EVALUATION OF PERFORMANCE UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Total Costs per km
3500
3000
2500
2000
1500 $ per ICP 1000
500
0 2006/07 2007/08 2008/09 2009/10 2010/11 2011/12 Total Costs per km (Real) Total Costs per km Service Level
Figure 8-4: Total Costs per km time series
Capacity Utilisation 35%
30%
25%
20%
15% Loss Ratio
10%
5%
0% 2007/08 2008/09 2009/10 2010/11 2011/12
Capacity Utilisation Service Level Target
Figure 8-5: Capacity utilisation time series
SECTION 8 EVALUATION OF PERFORMANCE 8-13 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Loss Ratio 8.0%
7.0%
6.0%
5.0%
4.0%
Loss Ratio 3.0%
2.0%
1.0%
0.0% 2007/08 2008/09 2009/10 2010/11 2011/12
Loss Ratio Service Level Target
Figure 8-6: Loss ratio time series
Faults per 100km 9 8 7 6 5 4 3
Total Faults per 100km 2 1 0 2007/08 2008/09 2009/10 2010/11 2011/12
Faults per 100km Service Level Target
Figure 8-7: Faults per 100km performance time series
8-14 SECTION 8 EVALUATION OF PERFORMANCE UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
8.5 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 Investment Prioritisation Upgrades were made to the CAPEX Database (key support Complete Complete Tool (IPT) upgrade system to the IPT) in 2011/12. Decision Support Tools The Smart Grid Initiative will increase the scope and volume of Commencing April 2015 Workstream data available. This will in turn enable further upgrade of the tools (Decision Support Tools Workstream of Smart Grid Initiative, Section 2.3). Service levels A service level based on the FAIDI metric has been Complete Complete implemented and reporting against the service level will begin in the 2012/13 planning period. Probabilistic planning Probabilistic Planning as a concept will be integrated into In progress April 2015 Networks and Operations as an operating philosophy and will be part of the overall adoption of Life Cycle Asset Management principles. Data Management An initiative to process the data received from assets in the In progress April 2015 Workstream Smart Grid and turn it into useful information for asset management planning processes (Data Management Workstream of Smart Grid Initiative, Section 2.3). Smart Network and A major initiative that involves a rollout of smart grid In progress April 2015 Communications technologies across the Unison network. This includes Workstreams distribution automation, asset sensors, online condition monitoring technologies, as well as a fit for purpose communication medium (Smart Network and Communications Work streams, Section 2.3). Demand-side An aspect of the Smart Grid Initiative focusing on reducing Commencing April 2015 Management Initiatives peak demand through DSM and energy efficiency (Section Workstream 2.3). Advanced Distribution Part of Unison’s Smart Grid Initiative is to replace the existing Commencing April 2014 Management System SCADA system and the Control Room’s operational (ADMS) management systems with a new Advanced Distribution Management System (ADMS). This application is mission critical for the success of LCAM as it will enable operational information to be exposed to decision makers throughout the business. Lifecycle Asset This initiative involves the development of a formal framework Commencing April 2015 Management to ensure that Unison is able to identify, filter, capture and internally disseminate asset information relevant to its Life Cycle Asset Management Initiative. The information may include: Asset Class Information, Performance trends, Maintenance Standards, Inspection and Condition Assessment Records, Product Selection, Strategic Spares, Asset Valuations and Renewal Strategies.
Table 8-10: Asset management initiatives 2011/12 SECTION 8 EVALUATION OF PERFORMANCE 8-15 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
8.6 Gap Analysis and Improvement Initiatives Table 8-11 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 In 2010/11 the performance of the Unison network Revision of vegetation management strategy to focus rural and remote rural was heavily affected by weather events driven by on wider clearance corridors to eliminate trees falling areas the La Niña weather system. High winds resulted in on lines and where possible, removal of the trees. damage to assets and widespread outages in exposed areas. The feeders breaching the service Vegetation management and liaison are now performed level targets in rural and remote rural were all by Unison Contracting Services Limited. These duties impacted by the wind storms. have only recently been taken up; meaning that coordination between EDB and contractor can be Analysis of fault data reveals that vegetation improved. The focus for 2011/12 will be on negotiating continues to cause the largest number of sustained for the removal of at risk trees within falling distance of outages during prolonged windstorms. Trees from lines. outside the growth limit zone falling across lines are relatively commonplace, especially in forestry areas. Other overhead system options are also being deployed on the network. These include Hendrix In areas of dense vegetation such as around the insulated spacer system and composite poles. Hendrix Rotorua Lakes, vegetation encroachment into line system means that some degree of vegetation corridors is a constant problem. 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. Capacity utilisation Capacity utilisation was affected by the relatively One of the key benefits of the Smart Grid Initiative warm winter. Aside from this external influence, the will be improving the utilisation of assets. This will opportunity to improve capacity utilisation across the be made possible through the proliferation of Unison network has been identified. Currently sensors and the ability to rapidly shift load. These planning standards are deterministic and factors will influence design and network planning necessarily conservative. standards meaning that capacity utilisation will improve over the planning period.
Table 8-11: Gap analysis and improvement initiatives
8-16 SECTION 8 EVALUATION OF PERFORMANCE UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
8.7 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 reach, and in many cases exceeds, industry best practice. As discussed in Table 8-10 above a key initiative for this planning period involves the development of a formal Life Cycle Asset Management framework to ensure that Unison is able to identify, filter, capture and internally disseminate asset information relevant to the whole life management of assets. Through this initiative, Unison will be seeking closer alignment with the processes and standards documentation defined in the internationally recognised PAS 55 Standard. To this end, a comprehensive suite of asset management processes, systems, tools and models have been introduced and will be further refined and formalised through this initiative.
Unison has never known so much about its asset base, its stakeholders or the environment that it operates within.
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 2011 AMP received a highly favourable review from Parsons Brinckerhoff New Zealand Limited (PB), who reviewed all EDB’s AMPs on behalf of the Commerce Commission. The AMP was rated as the fifth most compliant document produced by the twenty nine New Zealand EDBs providing a strong foundation for the 2012 AMP.
In planning the 2012 AMP, a continued emphasis was placed on correcting the areas of partial compliance or noncompliance. Unison considers that areas of concern have been addressed.
The Commerce Commission has recently consulted on changes to Information Disclosure requirements in respect of AMPs. In particular, the Commission has proposed that EDBs would publish AMPs biennially, with an interim update between full AMP disclosures. Additionally, EDBs would be required to publish quantitative information in templates to ease comparison between EDBs and provide a self-assessment using an “Asset Management Maturity Assessment Tool”. This self-assessment addresses the effectiveness of an EDB in translating the AMP into asset management processes and practices. Accordingly, Unison’s future AMP disclosures will evolve from their current presentation.
SECTION 9 EXPENDITURE FORECASTS AND RECONCILIATION 9 EXPENDITURE FORECASTS AND RECONCILIATION AND
Thermal sensors mounted on overhead circuits allow better utilisation of network assets.
SECTION 9 EXPENDITURE FORECASTS 9-1 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
9 Expenditure Forecasts ...... 9-2
9.1 Expenditure Forecasts and Reconciliation ...... 9-2
9-2 SECTION 5 EXPENDITURE FORECASTS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
9 Expenditure Forecasts
9.1 Expenditure Forecasts and Reconciliation
APPENDIX A GLOSSARY OF TERMS A GLOSSARY OF TERMS
Unison’s distributed temperature sensor (DTS) uses fibre optics to provide a temperature profile along critical underground 33kV circuits.
APPENDIX A GLOSSARY OF TERMS A-1 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
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 Acetate 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
A-2 APPENDIX A GLOSSARY OF TERMS UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
MD Maximum Demand 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 XLPE Cross Linked Polyethylene ZS Zone Substation
APPENDIX B REQUIREMENT 7(2) B REQUIREMENT 7(2)
Napier Port at night – Unison services the Hawke’s Bay region, as well as Rotorua and Taupo.
APPENDIX B REQUIREMENT 7(2) B-1 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
Appendix B
1 Requirement 7(2) ...... B-2 1.1 Assumption 1. HBPCT initiate and fund OHUG projects (Section 1) ...... B-2 1.2 Assumption 2. Integrity of asset data (Section 2) ...... B-2 1.3 Assumption 3. The contracting market - Unison’s planned and reactive works (Section 2) ...... B-3 1.4 Assumption 4. Continuity of Large Consumers (Section 3) ...... B-3 1.5 Assumption 5. Transpower supply configuration (Section 3) ...... B-4 1.6 Assumption 6. Stability of Customers’ view on Price-Quality trade off (Section 4) ...... B-4 1.7 Assumption 7. Accuracy of Load Forecast (Section 5) ...... B-5 1.8 Assumption 8. Uncertain load types and external factors (Section 5) ...... B-5 1.9 Assumption 9. Accuracy of network planning outputs from simulation models (Section 5) ...... B-5 1.10 Assumption 10. Benefits of the Smart Grid Initiative (Section 5) ...... B-6 1.11 Assumption 11. Accuracy of presently utilised condition assessment techniques (Section 6) ..... B-7 1.12 Assumption 12. ODV asset standard lives (Section 6) ...... B-7 1.13 Assumption 13. Quantification of WACC used in Renewal Envelope (Section 6) ...... B-7 1.14 Assumption 14. Expenditure forecast as published in the AMP (Section 9) ...... B-8
B-2 APPENDIX B REQUIREMENT 7(2) UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
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 2.5.1); 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 was replaced with Activa, a more advanced asset management system. Over the longer term this will tend to improve the integrity of asset data. APPENDIX B REQUIREMENT 7(2) B-3 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
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. B-4 APPENDIX B REQUIREMENT 7(2) UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
d. Any such decision rests entirely with the companies concerned.
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 2011 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. APPENDIX B REQUIREMENT 7(2) B-5 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
1.7 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. B-6 APPENDIX B REQUIREMENT 7(2) UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
c. To date this assumption has been validated through comparison of simulation results with empirical data, and other quality audits.
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.
1.10 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. APPENDIX B REQUIREMENT 7(2) B-7 UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
1.11 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.
1.12 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 6.4.4) 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 2004.
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.
1.13 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. B-8 APPENDIX B REQUIREMENT 7(2) UNISON NETWORKS LIMITED | ASSET MANAGEMENT PLAN 2012-22
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.
1.14 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 to varying degrees, reliant upon data quality. While it is difficult to quantify the impact of possible data quality issues in each use of the different tools, it is considered a risk that is being proactively managed. The tools have been designed and built in Unison and are inherently cognisant of the Unison data quality environment. Where data quality is known to be poor the tools have the ability to place a low weighting on that metric or to seek alternatives to hard data, such as expert opinion. These features minimise the vulnerability of the tools to data quality issues.
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.
UNISON NETWORKS LIMITED 1101 Omahu Road | PO Box 555 | Hastings 4156 P 0800 2 UNISON - 0800 286 476 | F 06 873 9311 www.unison.co.nz