Asset Management Plan 2011 - 2021
Publicly disclosed in March 2011 CONTENTS
Contents
0. SUMMARY OF THE PLAN ...... 5 0.1 BACKGROUND AND OBJECTIVES...... 5 0.2 DETAILS OF THE ASSETS ...... 6 0.3 PROPOSED SERVICE LEVELS ...... 7 0.4 DEVELOPMENT PLANS ...... 8 0.5 MANAGING THE ASSET’S LIFECYCLE...... 9 0.6 RISK MANAGEMENT ...... 9 0.7 FUNDING THE BUSINESS...... 9 0.8 PROCESSES AND SYSTEMS ...... 9 0.9 RESOURCING THE BUSINESS ...... 10 0.10 PERFORMANCE AND IMPROVEMENT ...... 10 0.11 FEEDBACK AND COMMENTS...... 10 1. BACKGROUND AND OBJECTIVES...... 11 1.1 PURPOSE OF THE ASSET MANAGEMENT PLAN...... 11 1.2 INTERACTION WITH OTHER GOALS AND DRIVERS ...... 12 1.3 KEY PLANNING DOCUMENTS ...... 13 1.4 INTERACTION OF GOALS / STRATEGIES ...... 16 1.5 PERIOD COVERED BY THE ASSET MANAGEMENT PLAN...... 16 1.6 STAKEHOLDER INTERESTS ...... 16 1.7 ACCOUNTABILITIES FOR ASSET MANAGEMENT ...... 20 1.8 SYSTEMS AND PROCESSES ...... 22 2. DETAILS OF THE ASSETS ...... 23 2.1 DISTRIBUTION AREA...... 23 2.2 NETWORK CONFIGURATION ...... 27 2.3 AGE AND CONDITION OF THE ASSETS BY CATEGORY ...... 39 2.4 JUSTIFYING THE ASSETS ...... 47 3. PROPOSED SERVICE LEVELS...... 49 3.1 CREATING SERVICE LEVELS...... 49 3.2 CUSTOMER-ORIENTED SERVICE LEVELS...... 50 3.3 REGULATORY SERVICE LEVELS...... 53 3.4 JUSTIFYING THE SERVICE LEVELS ...... 54 4. DEVELOPMENT PLANS ...... 56 4.1 PLANNING APPROACH AND CRITERIA...... 56 4.2 PRIORITISATION METHODOLOGY ...... 61 4.3 OTAGONET’S DEMAND FORECAST ...... 66 4.4 WHERE ARE OTAGONET NETWORK CONSTRAINTS...... 72 4.5 POLICIES FOR DISTRIBUTED GENERATION...... 73 4.6 USE OF NON-ASSET SOLUTIONS...... 74 4.7 NETWORK DEVELOPMENT OPTIONS...... 74 4.8 DEVELOPMENT PROGRAMME ...... 75 5. MANAGING THE ASSETS’ LIFECYCLE ...... 90 5.1 LIFECYCLE OF THE ASSETS...... 90 5.2 OPERATING OTAGONET’S ASSETS...... 91 5.3 MAINTAINING OTAGONET’S ASSETS...... 93 5.4 OTAGONET’S MAINTENANCE POLICIES ...... 99 5.5 RENEWING OTAGONET’S ASSETS...... 99 5.6 UP-SIZING OR EXTENDING OTAGONET’S ASSETS ...... 102 5.7 ENHANCING RELIABILITY ...... 103 5.8 CONVERTING OVERHEAD TO UNDERGROUND...... 104 5.9 RETIRING OF OTAGONET’S ASSETS ...... 104 5.10 OTAGONET’S MAINTENANCE BUDGET ...... 104 Asset Management Plan Page 2 of 151
CONTENTS
6. RISK MANAGEMENT ...... 106 6.1 RISK METHODS...... 106 6.2 RISK DETAILS...... 107 6.3 CONTINGENCY PLANS...... 111 6.4 INSURANCE ...... 111 7. FUNDING THE BUSINESS ...... 113 7.1 BUSINESS MODEL ...... 113 7.2 REVENUE SOURCE...... 113 7.3 EXPENDITURE ...... 114 7.4 CHANGES IN THE VALUE OF ASSETS...... 114 7.5 DEPRECIATING THE ASSETS ...... 114 8. PROCESSES AND SYSTEMS...... 116 8.1 ASSET KNOWLEDGE...... 116 8.2 IMPROVING THE QUALITY OF THE DATA...... 117 8.3 USE OF THE DATA ...... 117 8.4 DECISION MAKING...... 118 8.5 KEY PROCESSES AND SYSTEMS...... 118 8.6 ASSET MANAGEMENT TOOLS...... 120 9. PERFORMANCE AND IMPROVEMENT ...... 122 9.1 OUTCOMES AGAINST PLANS ...... 122 9.2 PERFORMANCE AGAINST TARGETS ...... 123 9.3 IMPROVEMENT AREAS AND STRATEGIES ...... 124 A. APPENDIX - CUSTOMER ENGAGEMENT SURVEY...... 127 B. APPENDIX - DESCRIPTION OF THE ASSETS ...... 132 B.1 SUBTRANSMISSION ...... 132 B.2 CABLE CIRCUITS ...... 133 B.3 ZONE SUBSTATIONS...... 134 B.4 DISTRIBUTION CIRCUITS ...... 138 B.5 RETICULATION...... 146 B.6 EARTHING ...... 148 B.7 RIPPLE CONTROL...... 148 B.8 TREES ...... 149 C. APPENDIX - ASSUMPTIONS...... 150 10. APPROVAL BY BOARD OF DIRECTORS ...... 151
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CONTENTS
Enquiries Enquiries, submissions or comments about this Asset Management Plan (AMP) can be directed to: OtagoNet Limited c/o PowerNet Ltd PO Box 1642 Invercargill, 9840 Phone (03) 211 1899 Fax (03) 211 1880 Email [email protected]
Liability disclaimer The information and statements made in this AMP are prepared on assumptions, projections and forecasts made by OtagoNet Joint Venture and represent company’s intentions and opinions at the date of issue (31 March 2011). Circumstances may change, assumptions and forecasts may prove to be wrong, events may occur that were not predicted, and OtagoNet Joint Venture may, at a later date, decide to take different actions to those that it currently intends to take. OtagoNet Joint Venture may also change any information in this document at any time. OtagoNet Joint Venture accepts no liability for any action, inaction or failure to act taken on the basis of this AMP.
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SUMMARY
0. Summary of the plan
This section summarises some of the main points from the Asset Management Plan (AMP). 0.1 Background and Objectives The OtagoNet Joint Venture (OtagoNet) owned electricity network supplies 14,768 customers in Otago. It is the least dense network in New Zealand with less than 3 customers per kilometre of line. The lines traverse diverse geographical and climatic areas and are subject to severe snow storms that can make access impossible to repair damaged equipment. Although significant renewal of lines and equipment has occurred over the past few years the network had suffered from inadequate maintenance for many years previously and a higher rate of renewal must be maintained over the next few years to avoid the impact of the wall of wire or an unacceptable deterioration in quality. In recent years considerable effort has been placed on obtaining and recording better information about the network but there are still some gaps which continue to be addressed. The purpose of the AMP is to provide a management framework that ensures that OtagoNet:
• Sets service levels for its electricity network that will meet customer, community and regulatory requirements.
• Understands the network capacity, reliability and security of supply that will be required both now and in the future and the issues that drive these requirements.
• Has robust and transparent processes in place for managing all phases of the network life cycle from commissioning to disposal.
• Has adequately considered the classes of risk OtagoNet’s network business faces and that there are systematic processes in place to mitigate identified risks.
• Has made adequate provision for funding all phases of the network lifecycle.
• Makes decisions within systematic and structured frameworks at each level within the business.
• Has an ever-increasing knowledge of OtagoNet’s asset locations, ages, condition and the assets’ likely future behaviour as they age and may be required to perform at different levels. OtagoNet pursues the strategies at a corporate and asset level listed below: This plan covers the period 1 April 2011 to 31 March 2021, and was approved by the OtagoNet Board on 31 March 2011. Management of the assets is undertaken by PowerNet Limited which uses one main external contractor to operate, maintain, renew, upsize and expand the network. The processes and systems used by PowerNet are described in section 8.
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SUMMARY
Corporate Strategies Deliver to the customers an economic, safe, efficient and quality electricity supply. Maintain and enhance the long term value of assets, business units, products and investments. Deliver a reasonable commercial return to shareholders. Achieve a long term reliable electricity supply.
Asset Management Strategies Improve reliability by sectionalising poorly performing feeders. 9 9 9 Consider differing drivers, for example the relative importance of restoring supply 9 9 to dairy farms or residences. Expand remote controllability of the distribution network. 9 9 9 Replace critical assets near to their technical end-of-life. 9 9 9 Undertake safety, seismic and environmental improvements. 9 9 9 Achieve 100% regulatory compliance. 9
0.2 Details of the assets OtagoNet supplies 14,768 customers in Otago, with a population of 23,885. Key industries within OtagoNet’s network area include sheep, beef and dairy farming, extensive meat processing, gold mining, black and brown coal mining, forestry, tourism and timber processing.
FALLS DAM NASEBY OTUREHUA
WEDDERBURN
RANFURLY
WAIPIATA HYDE MACRAES MINE DEEPDELL GOLDEN POINT PATEAROA PAERAU HYDRO PALMERSTON
PAERAU MIDDLEMARCH
MERTON
CLARKS WAITATI HINDON
LAWRENCE
WAIHOLA
CLYDEVALE GLENORE ELDERLEE STREET PUKEAWA LEGEND: CLINTON NORTH BALCLUTHA
CHARLOTTE ST STIRLING OJV SUBSTATIONS
FINEGAND KAITANGATA TPNZ SUBSTATIONS
PORT MOLYNEUX 33kV LINES OWAKA 66kV LINES
Figure 1 Overview of OtagoNet Subtransmission Network 1 April 2010
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SUMMARY
There are:
• 74km of 66kV lines and 536km of 33kV lines and cables. • 32 zone substations to transform High Voltage (HV) to Medium Voltage (MV). • 253km of 22kV lines, 2,970 km of 11kV lines and 16km of 11kV cables. • 4,170 distribution transformers supplying 14,768 customers. • 23 Voltage regulators, controlling local voltage. • The low voltage (230V) has 485 km of lines and 23km of cable. The age of the network is relatively old with only 46% of standard life remaining for distribution lines, 37% for subtransmission lines and 34% for low voltage lines. Overall the network has 44% standard life (as prescribed in the Commerce Commission ODV Handbook) remaining as the transformers and zone substations are younger. Most of these assets are in reasonable condition but a significant length of lines will need replacement in the planning period. 0.3 Proposed Service Levels Customers are generally satisfied with the present level of service and no major changes in service levels are proposed. This was the outcome of customer consultation undertaken by a telephone survey. The surveyed customers indicated that they value foremost good supply reliability and expeditious restoration in the event of unplanned supply interruptions. This requirement of customers for a continuous supply of electricity and a speedy restoration of supply in the event of an interruption translates into OtagoNet’s primary measurable service levels, supply continuity and restoration times. To measure the performance of a network three internationally accepted indices have been adopted: The continuity of supply can be measured by the number of interruptions experienced by customers. The network measure used by networks to compare this performance is SAIFI.
• SAIFI stands for “system average interruption frequency index”. This is a measure of how many system interruptions occur per year per customer connected to the network. • Customers connected to the OtagoNet network can expect to have their supply interrupted about twice a year. Restoration times can be measured by the average time the power is interrupted to a customer when an interruption occurs. The network measure used by networks to compare this performance is CAIDI.
• CAIDI stands for “customer average interruption duration index”. This is a measure of the average duration of an interruption experienced by customers who actually suffer a supply interruption. • Customers connected to the OtagoNet network who experience an unplanned supply interruption can expect to have their supply restored after a duration of 80 minutes. The remaining network performance index is SAIDI.
• SAIDI stands for “system average interruption duration index”. This is a measure of how many system minutes of supply are interrupted per year per customer connected to the network. • Customers connected to the OtagoNet network can expect to have their supply interrupted for a total duration of 160 minutes per year. Projections of these measures for the next five years ending 31 March 2016 are set out below. Asset Management Plan Page 7 of 151
SUMMARY
Table 1 – Primary service levels
Measure Limit1 YE 31/3/12 YE 31/3/13 YE 31/3/14 YE 31/3/15 YE 31/3/16 SAIDI Class B Planned 167.90 167.06 166.23 165.40 164.57 SAIDI Class C Unplanned 159.95 159.15 158.35 157.56 156.78 SAIDI Total 379.77 327.85 326.21 324.58 322.96 321.35 SAIFI Class B Planned 0.622 0.620 0.618 0.615 0.613 SAIFI Class C Unplanned 2.078 2.070 2.062 2.055 2.047 SAIFI Total 3.136 2.700 2.690 2.680 2.670 2.660
Note this target is based on normalising extreme events to the following daily boundary values: SAIDI 25.39, SAIFI 0.166 i.e. cannot get more than 25.39 customer-minutes of SAIDI occurring on a single day or event. Due to the radial nature of the network line strength and standards need to be higher to achieve the above service levels. Other network operational statistics are:
Measure Load factor 79% Loss ratio 7.0% Capacity utilisation 31% These are not expected to change significantly over the next ten years. 0.4 Development Plans Annual growth of the network energy and demand has been 3% to 4% over the last 20 years but has increased slightly over the last two years to between 4% and 6%. The future increase is predicted to be between 2 and 2.5% per annum. OJV Historic Energy and Maximum Demand 90 450 Maximum Demand 80 400 Energy
70 350
60 300
50 250
40 200 Energy - (GWh)
Maximum Demand - (MW) - Demand Maximum 30 150
20 100
10 50
0 0 000 003 006 009
1949 1952 1955 1958 1961 1964 1967 1970 1973 1976 1979 1982 1985 1988 1991 1994 1997 2 2 2 2
1 Limit calculated by the Commerce Commission Default Price-Quality Path methodology, with reference data from 1 April 2004 to 31 March 2009. Limit must not be exceeded two out of three years.
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SUMMARY
Focus for the next ten years is to increase the network performance by rebuilding the older poorly performing lines and to reduce the average age of the network assets so that the average remaining life of the assets is closer to 50% of the total life. Vegetation control and minor maintenance will also be targeted to help reduce outages. Major projects planned over the next ten years:
• New Milburn Substation • Milton 33kV Line rebuild • Milton Elderlee Street Substation upgrade • Merton Substation replacement • Zone transformer replacements Planned capital expenditure of about $10 million per annum. 0.5 Managing the asset’s lifecycle The asset lifecycle used by OtagoNet once assets are built, is: Operation, Maintenance, Renewal, Up-sizing, Extensions and Retirement. Analysis is done to review network operation to check if any trigger is exceeded and actions planned to maintain planned service levels. Inspection, monitoring and routine maintenance of assets is expected to cost $0.4 million pa. Fault restoration and repairs is expected to cost $1.5 million pa. Tree trimming to comply with the Trees regulations is expected to cost $0.85 million per annum. Asset refurbishment and renewal maintenance is planned to spend $1.1 million pa. 0.6 Risk Management The business is exposed to a wide range of risks. This section examines OtagoNet’s risk exposures, describes what it has done and will do about these exposures and what it will do when disaster strikes. Risk management is used to bring risk within acceptable levels. 0.7 Funding the business OtagoNet’s revenue is primarily from retailers who pay for conveying energy over OtagoNet’s lines and from customer contributions for the uneconomic portion of new connections or upgrades. Customer surveys found that only 12% would like to pay more for an improvement in service, so is insufficient to warrant a change in the rate of maintaining and renewing the network. 0.8 Processes and systems OtagoNet’s management company PowerNet uses a system based on ISO9000 quality system but has not maintained certification. Asset information resides in three key locations: Geographical Information System (GIS), Asset Management System (AMS), and Supervisory Control And Data Acquisition (SCADA). Most of this information is good. Data on low voltage lines is missing from GIS. Condition information is planned to be better collected by use of a scanned form to collect the 20% of the network inspected each year. Planners can then use this data to plan work more efficiently.
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SUMMARY
0.9 Resourcing the business OtagoNet sees obtaining staff to undertake required works will become difficult and has strategies in place to train and attract new staff. 0.10 Performance and improvement The outcome for the 2009-10 annual business plan was 8.3% under the budgeted $7.01M for capital and 8.3% over the budgeted $2.99M for maintenance. Reliability targets were not achieved for duration of faults (SAIDI) and frequency of faults (SAIFI). Secondary service level targets were achieved and customers expect that PowerNet be the first choice to contact for faults. Efficiency targets were achieved but the change in definition for Capacity Utilisation requires the setting of a new target that considers customer owned transformers. Some strategies are planned to improve performance and achieve targets. 0.11 Feedback and comments Comment on this plan is welcome and should be addressed to the Chief Engineer, PowerNet Ltd, PO Box 1642, Invercargill or email [email protected]. The next review of this AMP is planned for publishing in March 2012.
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BACKGROUND AND OBJECTIVES
1. Background and objectives
OtagoNet Joint Venture (OtagoNet) is the electricity lines business that conveys electricity throughout the North, South, East and some of central Otago (except for the majority of Dunedin) to approximately 14,768 customer connections on behalf of six energy retailers. The wider OtagoNet entity also includes the following associations:
• Owned by three entities: o 51% by Marlborough Lines Limited (MLL). o 24.5% by Electricity Invercargill Limited (EIL). o 24.5% by The Power Company Limited (TPCL). • Managed by PowerNet, an electricity lines management company jointly owned by TPCL and EIL. • Owns Otago Power Services Ltd, an electrical contracting company based in Balclutha, which is managed by MLL. This AMP deals solely with the OtagoNet electricity network assets. 1.1 Purpose of the Asset Management Plan [Addresses the Handbook requirement 4.5.2(a)] The OtagoNet Joint Venture (OtagoNet) owned electricity network supplies 14,768 customers in Otago. It is the least dense network in New Zealand with less than 3 customers per kilometre of line. The lines traverse diverse geographical and climatic areas and are subject to severe snow storms that can make access impossible to repair damaged equipment. Although significant renewal of lines and equipment has occurred over the past few years the network had suffered from inadequate maintenance for many years previously and a higher rate of renewal must be maintained over the next few years to avoid the impact of the wall of wire or an unacceptable deterioration in quality. In recent years considerable effort has been placed on obtaining and recording better information about the network but there are still some gaps which continue to be addressed. The purpose of the AMP is to provide a management framework that ensures that OtagoNet:
• Sets service levels for its electricity network that will meet customer, community and regulatory requirements.
• Understands the network capacity, reliability and security of supply that will be required both now and in the future and the issues that drive these requirements.
• Have robust and transparent processes in place for managing all phases of the network life cycle from commissioning to disposal.
• Has adequately considered the classes of risk OtagoNet’s network business faces and that there are systematic processes in place to mitigate identified risks.
• Has made adequate provision for funding all phases of the network lifecycle.
• Makes decisions within systematic and structured frameworks at each level within the business.
• Has an ever-increasing knowledge of OtagoNet’s asset locations, ages, condition and the assets’ likely future behaviour as they age and may be required to perform at different levels.
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BACKGROUND AND OBJECTIVES
Disclosure of OtagoNet’s AMP in this format will also assist in meeting the requirements of Section 7 and 18 and Schedules 12, 13 and 14 of the Electricity Distribution (Information Disclosure) Requirements 2008. This AMP is not intended to be a detailed description of OtagoNet’s assets (these lie in other parts of the business), but rather a description of the thinking, the policies, the strategies, the plans and the resources that OtagoNet uses and will use to manage the assets. 1.2 Interaction with other goals and drivers All of the assets exist within a strategic context that is shaped by a wide range of issues including OtagoNet’s vision statement, the prevailing regulatory environment, government policy objectives, commercial and competitive pressures and technology trends. OtagoNet’s assets are also influenced by technical regulations, asset deterioration, the laws of physics, and risk exposures independent of the strategic context.
1.2.1 Strategic context The strategic context includes many issues that range from the state of the local economy to developing technologies. Issues that OtagoNet considers include:
• The prevailing regulatory environment which regulates prices, requires no material decline in reliability and requires OtagoNet compile and disclose performance and planning information. • Government policy objectives, such as the promotion of distributed generation (particularly renewables). • OtagoNet’s commercial goal is primarily to deliver a sustainable earnings stream to OtagoNet’s owners that is the best use of their funds. • Competitive pressures from other lines companies which might try to supply OtagoNet’s customers. • Pressure from substitute fuels both at end-user level (such as substituting electricity with coal or oil at a facility level) and at bulk generation level (wind farms). • Advancing technologies such as gas-fired fuel cells that could strand conventional pipes and wires utilities. • Local, national and global economic cycles, in particular the trends in global pastoral commodity prices which can influence the use of land from very passive to very electro-intensive. • Changes in climate that include more storms and hotter, drier summers. • Interest rates which can influence the rate at which new customers connect to the network. • Availability of sufficient resources long term to satisfy OtagoNet’s service requirements. • Assets are relatively old and many require renewal or refurbishment.
1.2.2 Independence from strategic context It is also important to recognise that although OtagoNet’s assets must be shaped by the strategic issues identified in Section 1.2.1 they will also be influenced (and even constrained) by issues that are independent of the strategic context. These issues include:
• Safety requirements such as the earthing of exposed metal, line clearances and suboptimal fences or barriers to prevent accidental contact with live equipment. • Technical regulations including such matters as limiting harmonics to specified levels.
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BACKGROUND AND OBJECTIVES
• Asset configuration, condition and deterioration. These parameters will significantly limit the rate at which OtagoNet can re-align 4,400km of lines and 4,000 transformers to fit ever-changing strategic goals. • The laws of physics which govern such fundamental issues as power flows, insulation failure and faults. • Physical risk exposures. Exposure to events such as wind, snow, earthquakes and vehicle impacts are generally independent of the strategic context. Issues in which risk exposure might depend on the strategic context could be in regard to natural issues such as climate change (increasing severity and frequency of storms) or regulatory issues (say if LTNZ required all poles to be moved back from the carriage way).
1.2.3 Annual Business Plan and works plan Each year the first year of the AMP is consolidated with any recent strategic, commercial, asset or operational issues into OtagoNet’s annual business plan. This defines the priorities and actions for the year ahead which will contribute to OtagoNet’s long-term alignment with the strategic context, fully understanding that this alignment process is very much one of “moving goal posts”. An important component of the annual business plan is the annual works plan which scopes and costs each individual activity or project that the company expects to undertake in the year ahead. A critical activity is to firstly ensure that this annual works plan accurately reflects the current year’s projects in the AMP and secondly ensure that each project is implemented according to the scope prescribed in the works plan. 1.3 Key planning documents [Addresses the Handbook requirement 4.5.2(b)] Interactions of the key planning issues, processes and documents are shown in Figure 2
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BACKGROUND AND OBJECTIVES
Figure 2 - Interaction of key plans
1.3.1 Vision statement To operate as a successful business under the Energy Companies Act, in the distribution of electricity in the Otago region, providing excellent customer service and economic returns to the shareholder. 1.3.2 Strategic plan Key asset management drivers from OtagoNet’s Strategic Plan are: 1. Delivery to the customers of an economic, safe, efficient and quality electricity supply. 2. Maintaining and enhancing the long term value of assets, business units, products and investments. Asset Management Plan Page 14 of 151
BACKGROUND AND OBJECTIVES
3. Delivering a reasonable commercial return to shareholders. 4. Working with the Commerce Commission to achieve: o A regulated price level which enables customers to have increased expectations of a long term reliable electricity supply; and o An appropriate price path to enable the shareholder to reinvest in the business and achieve a reasonable commercial return on equity.
1.3.3 Asset strategy OtagoNet‘s asset strategy follows these guiding principles: • Improve reliability by sectionalising poorly performing feeders. • Consider differing drivers, particularly the importance of supply to dairy farms and commercial premises or residences. • Extend remote controllability of the distribution network. • Replace critical assets near to their technical end-of-life. • Undertake safety, seismic and environmental improvements. • Achieve 100% regulatory compliance.
1.3.4 Prevailing regulatory environment OtagoNet’s assets are subject to price and quality regulation under Part 4 of the Commerce Act 1986. OtagoNet is subject to information disclosure requirements (including the requirement to publish an AMP) along with other structural regulations such as restrictions on generating and retailing energy, and the requirement to connect embedded generation.
1.3.5 Government policy objectives Electricity lines businesses are being increasingly required to give effect to many aspects of government policy, namely: • Facilitating the connection of distributed generation on a regulated basis. • Improving the already high levels of public safety around power lines and transformers. • Offering increasingly variable tariffs to promote demand reduction despite the most economically efficient tariff structure for a lines business being a fixed cost.
1.3.6 Annual business plan An Annual Business Plan (ABP) is produced by PowerNet and contains the following: • Vision Statement and Critical Success Factors. • Customer service and Commercial Objectives, and Action plan. • Annual Capital Works Programme and the Annual Works Plan (AWP) for the following four years. • Business Plan Financials.
1.3.7 Annual works plan The Annual Works Plan (AWP) is produced by PowerNet and details the works to be undertaken for each financial year, and is incorporated into the ABP. All of next year’s works, listed in the AMP, are included in the AWP.
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BACKGROUND AND OBJECTIVES
1.4 Interaction of goals / strategies The table below shows the linkage between the Corporate and Asset Management Strategies: Corporate Strategies Delivery to the customers of an economic, safe, efficient and quality electricity supply. Maintaining and enhancing the long term value of assets, business units, products and investments. Delivering a reasonable commercial return to shareholders. Achieve a long term reliable electricity supply.
Asset Management Strategies Improve reliability by sectionising poorly performing feeders. 9 9 9 Consider differing drivers, particularly the importance of supply to dairy 9 9 farms and commercial premises or residences. Expand remote controllability of the distribution network. 9 9 9 Replace critical assets near to their technical end-of-life. 9 9 9 Undertake safety seismic and environmental improvements. 9 9 9 Achieve 100% regulatory compliance. 9
1.5 Period covered by the Asset Management Plan [Addresses the Handbook requirement 4.5.2(c)] This edition of OtagoNet’s AMP covers the period 1 April 2011 to 31 March 2021. This AMP was prepared during March 2011, approved by OtagoNet’s Governing Committee 17 March 2011 and publicly disclosed at the end of March 2011. 1.6 Stakeholder interests [Addresses the Handbook requirement 4.5.2(d)]
1.6.1 Stakeholders A stakeholder is defined as any person or class of persons who does or may do one or more of the following:
• Has a financial interest in OtagoNet (be it equity or debt).
• Is physically connected to OtagoNet’s network.
• Uses OtagoNet’s network for conveying electricity.
• Supplies OtagoNet with goods or services.
• Is affected by the existence, nature or condition of the network (especially if it is in an unsafe condition).
• Has a statutory obligation to perform an activity in relation to the OtagoNet network’s existence (such as request disclosure data or regulate prices).
1.6.2 Stakeholder interests The interests of the stakeholders are defined in Table 2:
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BACKGROUND AND OBJECTIVES
Table 2 – Key stakeholder interests
Interests
Viability Price Quality Safety Compliance Shareholder 9 9 9 9 9 Bankers 9 9 9 Connected customers 9 9 9 9 Contracted manager (PowerNet) 9 9 9 9 9 Energy retailers 9 9 9 Mass-market representative groups 9 9 9 Industry representative groups 9 9 9 Staff and contractors 9 9 9 Suppliers of goods and services 9 Public 9 9 Land owners 9 9 Councils (excluding as a customer) 9 9 Transport Agency 9 9 Ministry of economic development 9 9 9 9 Energy Safety Service 9 9 Commerce Commission 9 9 9 9 Electricity Authority 9 Electricity & Gas Complaints Commission 9 9 Ministry of Consumer Affairs 9 9
Table 3 below demonstrates how stakeholder’s expectations and requirements are identified. Table 3- How stakeholder’s expectations are identified
Stakeholder How expectations are identified Owners By their approval or required amendment of the Business Plan. Regular meetings between the directors and executive. Bankers Regular meetings between the bankers and PowerNet’s Chief Executive and Chief Financial Officer. By adhering to OtagoNet’s treasury/borrowing policy. By adhering to banking covenants. Connected Customers Regular discussions with large industrial customers as part of their on-going development needs. Annual customer surveys. Contracted Manager (PowerNet) Board representative weekly meeting with the Chief Executive. Energy Retailers Annual consultation with retailers. Mass-market Representative Groups Informal contact with group representatives. Industry Representative Groups Informal contact with group representatives. Staff & Contractors Regular staff briefings. Regular contractor meetings. Suppliers of Goods & Services Regular supply meetings. Newsletters. Public (as distinct from customers) Feedback from the OJV Governing Committee’s
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BACKGROUND AND OBJECTIVES
Stakeholder How expectations are identified public meetings. Land Owners Individual discussions as required. Councils (as regulators) Formally as necessary to discuss issues such as assets on Council land. Formally as District Plans are reviewed. Transport Agency Formally as required. Ministry of Economic Development Regular bulletins on various matters. Release of legislation, regulations and discussion papers. Analysis of submissions on discussion papers. Energy Safety Service Promulgated regulations and codes of practice. Audits of OtagoNet’s activities. Audit reports from other lines businesses. Commerce Commission Regular bulletins on various matters. Release of discussion papers. Analysis of submissions on discussion papers. Conferences following submission process. Electricity Authority Weekly update. Release of discussion papers. Briefing sessions. Analysis of submissions on discussion papers. Conferences following submission process. General information on their website. Electricity & Gas Complaints Reviewing their decisions in regard to other lines Commission companies. Ministry of Consumer Affairs Release of legislation, regulations and discussion papers. General information on their website.
1.6.3 Meeting stakeholder interests Table 4 provides a broad indication of how stakeholder interests are met: Table 4 – Accommodating stakeholder interests
Interest Description How OtagoNet meets interests Safety Staff, contractors and the public The public at large are kept safe by at large must be able to move ensuring that all above-ground assets are around and work on the structurally sound, live conductors are well network in total safety. out of reach, all enclosures are kept locked and all exposed metal is earthed. The safety of our staff and contractors is ensured by providing all necessary equipment, improving safe work practices and ensuring that they are stood down in unsafe conditions. Contractors will use all necessary safety equipment, improve their safe work practices and ensure that they stand down in unsafe conditions. Motorists will be kept safe by ensuring that above-ground structures are kept as far as possible from the carriage way within the constraints faced in regard to private land and road reserve.
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BACKGROUND AND OBJECTIVES
Interest Description How OtagoNet meets interests Viability Viability is necessary to ensure Stakeholders’ needs for long-term viability that the shareholder and other are accommodated by delivering earnings providers of finance such as that are sustainable and reflect an bankers have sufficient reason appropriate risk-adjusted return on to keep investing in OtagoNet. employed capital. In general terms this will need to be at least as good as the stakeholders could obtain from a term deposit at the bank plus a margin to reflect the ever-increasing risks to the capital in the business. Earnings are set by estimating the level of expenditure that will maintain Service Levels within targets and the revenue set to provide the required returns. Price Price is a key means of both OtagoNet’s total revenue is constrained by gathering revenue and Commerce Commission regulation. Prices signalling underlying costs. will be restrained to within the limits Getting prices wrong could prescribed.. result in levels of supply Failure to gather sufficient revenue to fund reliability that are less than or reliable assets will interfere with customer’s greater than OtagoNet’s business activities, and conversely customers want. gathering too much revenue will result in an unjustified transfer of wealth from customers to shareholders. OtagoNet’s pricing methodology is expected to be cost-reflective, but issues such as the Low Fixed Charges requirements can distort this. Supply Emphasis on continuity, Stakeholders’ needs for supply quality will quality restoration of supply and be accommodated by focusing resources reducing flicker is essential to on continuity and restoration of supply. The minimising interruptions to most recent mass-market survey indicated a customers’ businesses. general satisfaction with the present supply quality but also with many customers indicating a willingness to accept a reduction in supply quality in return for lower line charges. Compliance Compliance is necessary with All safety issues will be adequately many statutory requirements documented and available for inspection by ranging from safety to authorised agencies. disclosing information. Performance information will be disclosed in a timely and compliant fashion.
1.6.4 Management of conflicting interests Priorities for managing conflicting interests are:
• Conflict identified. • Analysis of issues and options using the following priority hierarchy: o Safety. Top priority is given to safety. The safety of staff, contractors and the public will not be compromised even if budgets are exceeded. o Viability. Second priority is viability (as defined above), because without it OtagoNet will cease to exist which makes supply quality and compliance pointless. o Pricing. OtagoNet will give third priority to pricing as a follow on from viability (noting that pricing is only one aspect of viability). OtagoNet
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recognises the need to adequately fund its business to ensure that customers’ businesses can operate successfully, whilst ensuring that there is not an unjustified transfer of wealth from its customers to its shareholders. o Supply quality is the fourth priority. Good supply quality makes customers, and therefore OtagoNet, successful. o Compliance. A lower priority is given to compliance that is not safety and supply quality related. • Report with recommendation made to management. • Decision made by Management Team, or escalated to OtagoNet board.
1.6.5 Customer consultation Consultation was undertaken by three methods, firstly there was a phone survey of 200 customers undertaken by external consultants. A copy of the questionnaire used is attached in appendix A. The survey questions response is that 12% (11% 2009) are willing to pay a $10 per month increase in their electricity bill to improve reliability. This plan therefore will attempt to increase reliability at minimal cost possible. The second method was a face to face survey by the survey company with four key clients. The outcome was that all the interviewees didn’t want to pay more for improved reliability and were happy with OtagoNet’s performance. Lastly, individual customers are consulted as they undertake connection to the network or consider upgrades. For example a gold mine is considering expanding its processing operations and this has required numerous options and negotiations before the final solution is agreed. 1.7 Accountabilities for asset management [Addresses the Handbook requirement 4.5.2(e)] OtagoNet’s ownership, governance and management structure is depicted below in Figure 3
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Figure 3 - Governance and Management Accountabilities
1.7.1 Accountability at governance level As OtagoNet uses a Governing Committee to represent the multiple owners and a contracted management company (PowerNet Limited) to manage the assets:
• The governance accountability is between the Governing Committee and the Boards of the respective owners with the principal mechanism being the Statement of Intent (SOI). Inclusion of reliability targets in the SOI makes the Governing Committee accountable to the shareholders for these important asset management outcomes whilst the inclusion of financial targets in the SOI makes the Governing Committee additionally accountable for overseeing the price-quality trade-off inherent in projecting expenditure and reliability. Members of the Governing committee are: o Alan Harper (Chairman). o Ken Forrest. o Neil Boniface. o Terry Shagin. Asset Management Plan Page 21 of 151
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1.7.2 Accountability at executive level Overall accountability for the performance of the electricity network rests with the Chief Executive of PowerNet. The principal accountability mechanism is the Chief Executive’s employment contract with the PowerNet Board which reflects the outcomes specified in the management contract between the OtagoNet Governing Committee and PowerNet.
1.7.3 Accountability at operational level There are seven level two managers reporting directly to PowerNet’s Chief Executive with the principal accountability mechanisms being their respective employment contracts. The individual managers who have the most influence over the long-term asset management outcomes will be the Chief Engineer and Network Manager (Otago) through their preparation of the AMP which will guide the nature and direction of the other managers’ work.
1.7.4 Accountability at work-face level Otago Power Services Limited is used almost exclusively for all construction, replacement and maintenance services, as a contractor, except for specialist work. The principal accountability mechanism is through negotiated project-by-project contracts that reflect the outcomes PowerNet must create for OtagoNet.
1.7.5 Key reporting lines The OtagoNet board receives a monthly report that covers the following items:
• Network reliability – this lists all outages over the last month, and trends regarding the SOI reliability targets. • Network Quality – detail of outstanding voltage complaints and annual statistics on them. • Network Connections – monthly and yearly details of connections to the network. • Use of Network – trend of the energy conveyed through the network. • Revenue – detail on the wheeling fees received. • Retailer activity – detail on volumes and numbers per energy retailer operating on the network. 2 • Works Programme – monthly and YTD expenditure on each works programme item and percentage complete, with notes on major variations. Each level of management has defined financial limits in the PowerNet Financial Authorities Policy. This requires any new project over $100,000 or variation to the approved Annual Works Plan by more than +10% or -30%, to have Board approval. Generally most projects are approved by the board in the Annual Business Plan process. 1.8 Systems and processes [Addresses the Handbook requirement 4.5.2(f)] OtagoNet’s systems and processes are described in detail in Section 8.
2 YTD = Year to date
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2. Details of the assets 2.1 Distribution area
2.1.1 Geographical coverage [Addresses the Handbook requirement 4.5.3(a)(i)] The distribution area covers three geographically distinct areas:
• The south and west Otago area that stretches from Lake Waihola to Owaka and inland to Clinton. • The north Otago coast from Waitati to Shag Point. • The inland north Otago area from Falls Dam south to Hindon.
Figure 4 - Distribution Area Topography varies as follows:
• Flat fertile plains and rolling hills in the south and west Otago area that includes Milton, Balclutha, Owaka and Clinton. • Rolling countryside along the north Otago coast that includes Waitati, Waikouaiti and Palmerston. • Dry flat plains, rolling hills and mountainous areas in the inland north Otago area that includes Naseby, Ranfurly, the Macraes Mine and stretches as far south as Middlemarch, Clarks Junction and Hindon. As the network is interconnect electrically at 11kV or above, there are no separated or segmented parts of the network requiring separate disclosure.
2.1.2 Demographics The population of OtagoNet’s distribution area at the 2006 census was approximately 23,885. Classification of areas within OtagoNet’s distribution area is as follows:
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2006 Census 2021 Projection3
Description Includes Count ≥65 Medium High ≥65 Large town Balclutha 4,140 19% 3,780 4,040 28% Milton 1,930 19% 1,760 1,870 27% Waikouaiti 1,120 24% 1,090 1,170 31% Palmerston 820 28% 720 780 35% Ranfurly 720 33% 640 740 31% Waitati 520 8% 570 610 19% Small town Clinton 300 13% 260 280 23% Middlemarch 170 12% 160 180 19% Naseby 120 25% 110 130 45% Rural All other areas 14,045 10% 14,298 15,343 18% Total 23,885 14% 23,388 25,143 22% Table 5 - Populations It is interesting to note the number of people 65 years and older is projected to increase from 14% in 2006 to 22% in 2021.
2.1.3 Key industries Key industries within the network area include sheep, beef and dairy farming, extensive meat and dairy processing, forestry and timber processing. Most of the large and small towns listed in Section 2.1.2 are rural service towns. The areas economic fortunes will therefore be strongly influenced by:
• Markets for basic and specialised meats such as beef, mutton and lamb. • Markets for dairy products. • Markets for processed timber. • Markets for black and brown coal. • Government policies on mining of coal. • Government policies on forestry and nitrogen-based pastoral farming. • Access to water for crop and stock irrigation, especially in north and central Otago. • Tourism. The impact of these issues is broadly as follows:
Issue Visible impact Impact on OtagoNet’s value drivers Shifts in market May lead to a contraction of Reduces asset utilisation. tastes for beef, demand by these industries. Possible capacity stranding mutton, lamb Shifting markets for May lead to a contraction of Reduces asset utilisation. dairy products demand by these industries. Possible capacity stranding Shifting markets for May lead to a contraction in Reduces asset utilisation. timber demand by these industries Possible capacity stranding Shifting markets for May lead to a contraction in Reduces asset utilisation. coal demand by these industries Possible capacity stranding
Government CO2 May lead to a contraction in Reduces asset utilisation. Policy demand by industries Possible capacity stranding May create new process New capacity required requirement for industries
3 2006 Statistics NZ Population Projection, December 2007.
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Issue Visible impact Impact on OtagoNet’s value drivers Government policy on May lead to contraction of Reduces asset utilisation. nitrogen-based dairy shed demand. Possible capacity stranding farming May lead to contraction of dairy processing demand. Access to water. May lead to increased Increases asset utilisation but without irrigation demand. corresponding increase in load factor
The recent global economic slowdown may well dampen demand growth as the rural sector hesitates to increase dairy shed and irrigation capacity. Major customers that have significant impact on network operations or asset management priorities are [Addresses handbook requirement 4.5.3(a)(ii)]:
• Oceana Gold’s 20MVA of load on the Ranfurly substation requires a 66kV line, large dual rated 33/66kV step-up transformers and two heavy 33kV lines from the Naseby GXP. • TrustPower’s 12.25MW generation station also requires the 66kV supply at Ranfurly and connection to the major Oceana Gold customer. • Pioneer Generation’s Falls Dam power station requires extra 33kV line regulation and arrangements at the Oturehua substation. • PPCS Finegand’s 7MVA of load required a dual 33kV line to provide the required security to it and customers from three downstream zone substations. • Fonterra’s Stirling cheese plant has 33kV switching between two supplies to provide fast recovery of power supply in the event of a fault on one line. • The Otago Regional Corrections Facility at Milburn has been provided with two 11kV supplies and automatic change over switchgear to provide its required security. 2.1.4 Load Characteristics [Addresses handbook requirement 4.5.3(a)(iii)] Domestic: Standard household usage with demand peaks in morning (8am) and evening (7:00pm). The use of heat pumps is increasing electricity usage, with no noticeable impact over summer hot period yet. Peaks normally occur in winter.
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Figure 5 Typical Domestic Daily Load Profile (1 July 2009, Waitati feeders)
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Figure 6 Typical Domestic Feeder Yearly Load Profile (Waitati T1) Farming: In South Otago the predominant load is dairy farming with the milking season between August and May with morning and late afternoon peaks. The remaining farms normally only very low usage with some pumps and electric fences, with peak usage during the few days of shearing or crop harvesting. In North Otago and the Maniototo the predominant load is irrigation with the peak loads over the summer and hot dry periods. Sawmills: Usage at sawmills due to processing and kiln drying of product. Some wood- chipping of logs for export, and these have some very large motors with poor starting characteristics. Dairy Processing: Load characteristic is dependent on milk production and the movement of milk between processing plants to maximise plant efficiency.
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Freezing Works: The load characteristics are similar to the dairy processing but with the off season 1-2 months later depending on the markets and production. Mining: The mining load experienced in Otago has a very flat load profile maintained 24 hours per day all year round supplied from the two northern GXPs.
2.1.5 Other drivers of electricity use Other drivers of electricity use include:
• Low temperatures during winter (-5°C frosts are not uncommon in the area). • The use of these heat pumps as air conditioners in the 26°C summer heat. • Increased energy efficiency due to Government campaigns. (Compact Fluorescent light bulbs, Warm Homes.)
2.1.6 Energy and demand characteristics [Addresses the Handbook requirement 4.5.3(a)(iv)] Key energy and demand figures for the YE 31 March 2010 are as follows:
Parameter Value Long-term trend Energy conveyed 414 GWh Steady increase. Max demand 60.7 MW Steady with growth in summer load. Load factor 78 % Steady. Transformer utilisation 31.6 %4 Expect a slight reduction with minimum 15kVA transformer replacements. Losses -7.1% Steady Table 6 - Key Energy and Demand Figures 2.2 Network configuration To supply OtagoNet’s 14,768 customers the company owns and operates a single electrical network across three geographically distinct areas described in Section 2.1.1. The two northern areas are connected by a 33kV line over the Pig Root that can supply about half of the inland north Otago’s maximum demand. The southern and northern MV networks are connected near Lake Mahinerangi.
2.2.1 Bulk supply assets and embedded generation [Addresses handbook requirement 4.5.3(b)(i)]
2.2.1.1 Balclutha Grid Exit Point (GXP) Balclutha GXP is supplied by a double circuit tower 110kV diversion (not a tee) from the Gore – Berwick single circuit 110kV pole line. Supply is taken through eight 33kV feeders from the GXP.
2.2.1.2 Naseby Grid Exit Point (GXP) Naseby GXP is supplied by a single circuit 220kV tower line from Roxburgh to Livingstone and supplies the Ranfurly zone substation via two 33kV circuits.
4 Change if definition, where an estimate of customer owned transformers are now included. In 2007 when only OtagoNet distribution transformers were included the value was 37.3%.
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2.2.1.3 Palmerston Grid Exit Point (GXP) Palmerston GXP is supplied from Halfway Bush by a double circuit 110kV tower line that splits into two single circuit pole lines just north of Dunedin. The substation has a single 110/33kV transformer and three 33kV feeders. The Palmerston zone substation is supplied by 2.5km of 33kV line from the GXP. There are also 33kV lines heading south to Waikouaiti (Merton zone substation) and west across the Pig Root5 to Deepdell.
2.2.1.4 Paerau generation The 12.25MW Paerau hydro scheme was built by Otago Power Limited in 1984 and then sold to TrustPower as a result of the enactment of Electricity Industry Reform Act 1998. Paerau’s generation is injected into the Ranfurly zone substation at 66kV.
2.2.1.5 Falls Dam generation The Pioneer Generation Limited’s (PGL) 1.25MW Falls Dam hydro scheme is connected to the 33kV network at Oturehua. PGL owns the equipment to enable connection to the OtagoNet 33kV Line. 2.2.1.6 Bulk Supply Characteristics
Supply Point Voltage Rating Firm Rating Balclutha GXP 110/33kV 60MVA 28.1MVA Naseby GXP 220/33kV 80MVA 34.2MVA Palmerston GXP 110/33kV 10MVA 12.3MVA Paerau 66kV 24MVA 12.25MVA Falls Dam 33kV 1.25MVA 1.25MVA
2.2.2 Subtransmission network [Addresses handbook requirement 4.5.3(b)(ii)] While OtagoNet’s network is connected at 11kV, the subtransmission comprises two electrically separate networks as depicted in Figure 8. The subtransmission network comprises 74km of 66kV line and 538km of 33kV line and has the following characteristics:
• It is almost totally overhead except for short cable runs at GXP’s and zone substations.
• It is almost totally radial except for a few instances on the south Otago network where closed rings have been formed. The subtransmission can never be completely meshed economically.
• It includes a large number of lightly loaded zone substations because the long distances are beyond the reach of 11kV.
5 Yes it is spelt this way… named by John Turnbull Thomson.
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FALLS DAM NASEBY OTUREHUA
WEDDERBURN
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WAIPIATA HYDE MACRAES MINE DEEPDELL GOLDEN POINT PATEAROA PAERAU HYDRO PALMERSTON
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CLYDEVALE GLENORE ELDERLEE STREET PUKEAWA LEGEND: CLINTON NORTH BALCLUTHA
CHARLOTTE ST STIRLING OJV SUBSTATIONS
FINEGAND KAITANGATA TPNZ SUBSTATIONS
PORT MOLYNEUX 33kV LINES OWAKA 66kV LINES
Figure 8 – Subtransmission network
2.2.3 Zone substations OtagoNet owns and operates the following 31 zone substations with a 66/33kV interconnecting station (at Ranfurly). There are fifteen distribution transformers supplied direct off the 33kV subtransmission network at Balmoral Water Scheme, Becks, Big Sky Dairy, Brothers Peak, Cormack, Craiglynn, Hills Creek, Hore’s Pump, O’Malley’s House, O’Malley’s Pump, Red Bank, Rough Ridge, Stoneburn and Tisdall. Asset management plan Page 29 of 151
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Table 7 - Zone Substations
Substation Nature of load Description of substation Charlotte Street Urban domestic and commercial with Dual 33kV supply to a 33kV indoor (Balclutha) some rural loads including farms and switchboard, with three 33kV feeders. timber mills Dual 5MVA transformers, 11kV indoor switchboard Clarks Remote isolated rural farms Teed off the 33kV radial line beyond Middlemarch. 0.5 MVA 22kV SWER substation. Clinton Small urban township and rural farms Radial 33kV from Clifton switches. 2.5MVA transformer and outdoor 11kV substation. Clydevale Small urban township and rural farms Alternate 33kV lines supplying 2.5MVA transformer and outdoor 11kV substation. Deepdell Remote isolated rural farms Alternate 33kV lines supplying 0.75MVA transformer and basic 11kV outdoor substation. Elderlee Street Urban domestic and commercial with Supplied off a 33kV ring. Dual 5MVA (Milton) some rural loads including farms and transformers and 11kV indoor timber mills switchboard. Finegand Rural farming Three supply routes at 33kV. 2.5MVA Meat processing plant transformer and outdoor 11kV substation. A 33kV feed to Processing plant. Glenore Rural farming Supplied off a 33kV ring. 1.5MVA transformer and outdoor 11kV substation. Golden Point Mining Teed off the Deepdell to Palmerston 33kV line. 5MVA transformer with indoor 11kV switchgear. Hindon Remote isolated rural farms Radial 33kV line to 0.5 MVA 22kV SWER and 0.1MVA 11kV substation. Hyde Rural farming with irrigation load Alternate 33kV line to a 2.5MVA transformer and outdoor 11kV substation. Kaitangata Small urban township and rural farms Radial 33kV to a 2.5MVA transformer and outdoor 11kV substation. Lawrence Small urban township and rural farms Alternate 33kV lines to a 2.5MVA transformer and indoor 11kV substation. Macraes Mining Gold mine and processing Radial 66kV line to dual 7.5/15MVA 66/11kV transformers with 66kV switchyard and indoor 11kV switchboard. Merton Urban domestic and commercial with Teed off the radial 33kV Palmerston to some rural farms and one large chicken Waitati. Dual 2.5MVA transformers and farm outdoor 11kV substation. Middlemarch Small urban township and rural farms Radial 33kV from Deepdell to 2.5MVA transformer and outdoor 11kV substation. North Balclutha Urban domestic and commercial with 33kV line from Balclutha GXP. 5MVA some rural transformer and outdoor 11kV substation. Oturehua Rural farming Teed off the radial 33kV from Ranfurly to Fall Dam. 0.75MVA transformer, outdoor 11kV substation and 33kV regulator for generator connection.
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Substation Nature of load Description of substation Owaka Small urban township and rural farms Radial 33kV line from Finegand. 2.5MVA transformer and outdoor 11kV substation. Paerau Remote isolated rural farms and Radial 33kV from Ranfurly. 0.75MVA irrigation transformer and basic 11kV substation. Paerau Hydro 12.25 MW hydro generation station Radial 66kV line from Ranfurly. Dual 7.5M/15VA 66/11kV transformers with 66kV switchyard and indoor 11kV board. Palmerston Urban domestic and commercial with Radial 33kV to dual 2.5MVA some rural farms and timber mills transformers and outdoor 11kV substation. Patearoa Rural farming with irrigation Teed off radial 33kV line to Paerau 2.5MVA transformer and outdoor 11kV substation with 33kV regulator for the Paerau line. Port Molyneux Small seaside township and rural farms Teed off radial 33kV line to Owaka. 2.5MVA transformer and outdoor 11kV substation. Pukeawa Rural farming Alternate 33kV lines to a 0.75MVA transformer and basic 11kV substation. Ranfurly Urban domestic and commercial with Dual heavy 33kV lines from Naseby some rural farms and irrigation GXP to a dual 2.5MVA transformers 33/66kV step-up and switching station and outdoor 11kV substation. Dual 12.5/25MVA 33/66kV transformers, 33 and 66kV outdoor substations. Stirling Fonterra Stirling Cheese Factory 33kV line and cable switch-able between two 33kV lines from Balclutha GXP. 5MVA transformer and 11kV indoor switchboard. Waihola Small urban township and rural farms Radial 33kV line off the 33kV Ring that supplies Elderlee St and Glenore. 1.5MVA transformer and outdoor 11kV substation. Waipiata Rural farming with irrigation 33kV tee off the 33kV line from Ranfurly to Deepdell. 1.5MVA transformer and outdoor 11kV substation. Waitati Small urban townships and rural farms Radial 33kV line from Palmerston to a 2.5MVA transformer and outdoor 11kV substation. Wedderburn Rural farming Teed off the 33kV line from Ranfurly to Falls Dam. 0.75MVA transformer and outdoor 11kV substation.
2.2.4 Distribution network [Addresses handbook requirement 4.5.3(b)(iii)]
2.2.4.1 Configuration In rural areas the configuration is almost totally radial with little interconnection. In particular the mountainous topography and the distances in the inland north Otago area preclude 11kV interconnection which excludes the ability to provide an 11kV alternative to the 33kV supply to zone substations. In urban areas there is a higher degree of meshing or interconnection between 11kV feeders where possible, (although transformer loadings rather than distance tends to limit the ability to back-feed on the 11kV). Asset management plan Page 31 of 151
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2.2.4.2 Construction The network construction is very similar in rural and urban areas, with the only differences being closer pole spacing, under-built LV and larger transformers that are often ground-mounted in towns.
2.2.4.3 Per substation basis The split of the distribution network on a per substation basis is presented in Table 8. Safety and reliability are the strongest drivers of allocation of resources, with customer density providing an indication of priority for other works. Table 8 – Distribution network per substation
Line Cable Customer Length Length density Substation / Feeder (km) (km) Customers (per km) Balmoral - - 1 Becks 27.66 - 33 1.19 Big Sky Dairy - - 1 Brothers Peak 1.49 - 2 1.34 Charlotte Street 68.53 1.02 1648 23.70 Clarks 134.57 - 198 1.47 Clinton 285.62 1.64 779 2.71 Clydevale 265.75 0.09 589 2.22 Cormack - - 1 Craiglynn 3.40 - 5 1.47 Deepdell 55.41 0.40 90 1.61 Elderlee Street 187.36 1.63 1640 8.68 Finegand 106.64 0.34 337 3.15 Glenore 91.96 0.03 211 2.29 Golden Point - - 1 0.10 Hindon 117.85 - 135 1.15 Hills Creek 11.80 - 18 1.52 Hore's Pump - - 1 Hyde 38.28 0.01 68 1.78 Kaitangata 92.77 0.01 604 6.51 Lawrence 185.03 0.35 61 0.33 Merton 123.48 0.75 1354 10.90 Middlemarch 103.36 0.49 338 3.25 North Balclutha 118.32 0.30 1259 10.61 O'Mally's House - - 1 O'Mally's Pump - - 1 Oturehua 27.97 - 81 2.90 Owaka 278.17 1.22 924 3.31 Paerau 26.88 - 40 1.49 Paerau Hydro 9.78 - 1 Palmerston 166.58 0.68 1031 6.16 Patearoa 79.24 0.17 178 2.24 Port Molyneux 28.04 0.14 371 13.17 Pukeawa 41.83 - 74 1.77 Ranfurly 199.40 1.42 1140 5.68 Redbank 2.91 - 5 1.72 Rough Ridge - - 1 Asset management plan Page 32 of 151
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Line Cable Customer Length Length density Substation / Feeder (km) (km) Customers (per km) Stirling - - 1 Stoneburn 24.59 - 29 1.18 Tisdall - - 1 Waihola 93.47 0.43 610 6.50 Waipiata 81.99 - 189 2.31 Waitati 67.76 4.38 792 10.98 Wedderburn 35.47 1.07 49 1.34 Unallocated 0.51 0.07 0 3,183.88 16.67 4.65 Note some lines are unallocated to a substation or feeder. ICP numbers were extracted in March 2010.
2.2.5 Distribution substations [Addresses handbook requirement 4.5.3(b)(iv)] Just as zone substation transformers form the interface between OtagoNet’s subtransmission and the OtagoNet’s distribution networks, distribution transformers form the interface between OtagoNet’s 11kV distribution and LV (400/230V) networks. OtagoNet’s distribution substations range from 1-phase 3kVA pole-mounted transformers with only minimal fuse protection to 3-phase 1,000kVA ground-mounted transformers that are dedicated to single customers as shown in Table 9. Table 9 – Number of distribution substations
Rating Pole Ground 1-phase up to 15kVA 2656 4 1-phase 30kVA 398 6 1-phase 50kVA 137 4 1-phase 75kVA 4 1-phase 100kVA 33 1-phase 200kVA 10 3-phase up to 15kVA 171 8 3-phase 30kVA 183 1 3-phase 50kVA 220 3 3-phase 75kVA 27 3-phase 100kVA 83 5 3-phase 200kVA 75 13 3-phase 300kVA 34 38 3-phase 500kVA 1 47 3-phase 750kVA 1 11 3-phase 1,000kVA 4 Total 4033 144
The voltage regulators are managed and recorded separately from distribution transformers and details are as follows: Table 10 - Voltage Regulators
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Location Purpose Craiglynn Regulation of a single wire 11kV circuit from a small 33/11kV isolating transformer feeding a small remote community. Dunback 11kV regulation at a point 14km from Palmerston zone substation for a further 20km of line to Morrisons. Mahinerangi Regulation of a single wire 11kV circuit from a small isolating transformer feeding a small remote community. Naseby 11kV regulation for a large holiday destination 11km from Ranfurly zone substation. Redbank Regulation of a single wire 11kV circuit from a small 33/11kV isolating transformer feeding a small remote community. Stoneburn Regulation of a single wire 11kV circuit from a small 33/11kV isolating transformer feeding a small remote community. Tahakopa 11kV regulation at a point 18km from Owaka zone substation for a popular holiday destination and a further 25km of line into the Chalsands.
2.2.6 LV network [Addresses handbook requirement 4.5.3(b)(v)]
2.2.6.1 Coverage OtagoNet’s LV networks are predominantly clustered around each distribution transformer. The coverage of each individual LV network tends to be limited by volt- drop to about a 200m radius from each transformer hence LV coverage is not as extensive as 11kV.
2.2.6.2 Configuration OtagoNet’s LV networks are almost solely radial with minimal meshing, even in urban areas, because of excessive volt-drop in long conductors.
2.2.6.3 Construction Construction of OtagoNet’s LV network varies considerably and can include the following configurations:
• Overhead LV only. • LV under-built on 11kV. • XLPE or PVC cable (only 19km in total).
2.2.6.4 Per substation basis On a per substation basis OtagoNet’s split of LV network is shown in Table 11. Similar to the distribution network, safety and reliability is OtagoNet’s strongest driver of allocation of resources, with customer density providing an indication of priority for other works. Table 11 – LV network per substation
Line Length Cable Customer Substation / Feeder (km) Length (km) Customers density (per km) Balmoral - - 1 Becks - - 33 Big Sky Dairy - - 1 Brothers Peak - - 2 Charlotte Street 18.55 2.02 1648 80.13
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Line Length Cable Customer Substation / Feeder (km) Length (km) Customers density (per km) Clarks - 0.22 198 919.43 Clinton 6.10 0.03 779 127.27 Clydevale 3.75 0.01 589 156.89 Cormack - - 1 Craiglynn - - 5 Deepdell 1.90 - 90 47.25 Elderlee Street 23.32 0.42 1640 69.11 Finegand 2.18 - 337 154.39 Glenore 0.02 - 211 10,865.09 Golden Point - - 1 Hindon 0.42 - 135 319.77 Hills Creek - - 18 Hore's Pump - - 1 Hyde 1.22 - 68 55.60 Kaitangata 11.35 0.01 604 53.19 Lawrence 16.18 0.31 61 3.70 Merton 22.88 2.36 1354 53.66 Middlemarch 4.70 0.00 338 71.79 North Balclutha 14.44 3.36 1259 70.73 O'Mally's House - - 1 O'Mally's Pump - - 1 Oturehua 0.59 - 81 137.22 Owaka 10.86 0.75 924 79.63 Paerau - - 40 Paerau Hydro - - 1 Palmerston 16.85 0.15 1031 60.65 Patearoa 2.01 - 178 88.47 Port Molyneux 3.67 0.15 371 97.19 Pukeawa 0.07 - 74 1,098.41 Ranfurly 15.68 1.28 1140 67.21 Redbank - - 5 Rough Ridge - - 1 Stirling 0.04 - 1 28.32 Stoneburn - - 29 Tisdall - - 1 Waihola 8.35 1.35 610 62.90 Waipiata 1.79 - 189 105.50 Waitati 14.71 2.59 792 45.77 Wedderburn 0.82 - 49 60.11 Unallocated 12.96 4.44 - 215.38 19.44 63.42 Note that LV line and cable data is not complete.
2.2.7 Customer connection assets OtagoNet has 14,768 customer connections. These customer connections generally involve assets ranging in size from a simple fuse on a pole or in a suburban distribution pillar to dedicated lines and transformer installations supplying single large customers. The connection type and number are shown below.
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Table 12 - Connections
Connection type Total Percent 10kVA Domestic 9363 63.4% 10% fixed option 1797 12.2% 1kVA Unmetered 99 0.7% 15kVA Commercial 2843 19.3% 20kVA Commercial 82 0.6% 30kVA Commercial 178 1.2% 50kVA Commercial 246 1.7% 75kVA Commercial 47 0.3% 100kVA Commercial 37 0.3% 150kVA Commercial 13 0.1% 250kVA Commercial 4 0.0% MD Contract 59 0.4% Total 14768 100.0%
In most cases the fuse forms the demarcation point between OtagoNet’s network and the customer’s assets (the “service main”) and this is usually located at or near the physical boundary of the customer’s property.
2.2.8 Secondary assets and systems [Addresses handbook requirement 4.5.3(b)(vi)]
2.2.8.1 Load control assets OtagoNet currently owns and operates the following load control transmitter facilities for control of ripple relays:
• Three 33kV 492Hz.100kVA injection plants at Naseby, Palmerston and Balclutha points of supply. • One new 33kV 317Hz 100kVA injection plant at Balclutha point of supply which will gradually take over from the 492Hz plant as relays are replaced. The ripple receivers are owned by the Retailers.
2.2.8.2 Protection and control
(a) Key protection systems OtagoNet’s network protection includes the following broad classifications of systems: Circuit Breakers
• Circuit breakers provide powered switching (usually charged springs or DC coil) enabling operational control of isolation and fault interruption of all faults. • Circuit breakers protection relays which have always included over-current, earth- fault and auto-reclose functions. More recent equipment also includes voltage, frequency, directional overcurrent, distance and circuit breakers fail functionality in addition to the basic functions. • Circuit breakers operation may also be triggered by the following to protect downstream devices: o Transformer and tap changer temperature sensors. o Surge sensors. o Explosion vents. o Oil level sensors.
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Reclosers
• Reclosers are compact, self-contained pole mounted circuit breakers complete with integral protection relay functions. Reclosers are used to provide additional protection and the ability to sectionalise longer rural lines or isolate urban customers from rural faults. Many simple substations use reclosers in the place of circuit breakers as more modern reclosers have all the attributes of circuit breakers and protection relays in one simple and cheaper package. • Simple single phase reclosers are used as the protection device on single wire earth return isolating transformers. Fuses
• Fuses provide fault interruption of some faults and may be utilised to provide manual isolation. • As fuses are simple over current devices they do not provide reliable earth fault operation, or any other protection function. • Generally all 11kV fuses are ‘Drop-Out’ type where the operation of the fuse element causes the fuse tube to swing out of the connection position and hang down, enabling clear indication of operation. Switches
• Switches provide no protection function but allow simple manual operation to provide control/isolation. Links
• Links provide no protection function but allow manual operation to provide control/isolation.
(b) DC power supplies Batteries, battery chargers and battery monitors provide the direct current (DC) supply systems for circuit breakers control and protection functions. This allows continued operation of plant throughout any power outage.
(c) Tap changer controls Voltage Regulating Relays (VRR) provides automatic control of the ‘On Load Tap Changers’ (OLTC) on power transformers to regulate the outgoing voltage to within controlled limits.
2.2.8.3 SCADA and Communications SCADA is used for control and monitoring of zone substations and remote switching devices and for activating load control plant.
(a) Master station OtagoNet’s SCADA master station (that provides the human interface to and from the SCADA remote sites) is located in the PowerNet Balclutha office with a link to the PowerNet System Control in Invercargill. The system is an Abbey Systems “PowerLink” SCADA system designed, manufactured and supported in New Zealand. The master system communicates to 35 remote terminal units at all of the OtagoNet zone substations and Transpower points of supply.
(b) Communications links OtagoNet currently owns and operates the following communications links for SCADA and VHF voice communications:
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Figure 9 - OtagoNet SCADA Radio Network
Figure 10 - OtagoNet Mobile Radio Network
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2.2.8.4 Other assets
(a) Mobile generation None, but PowerNet provides a 275kW and a 350kW diesel generators for planned work and power restoration.
(b) Stand-by generators None.
(c) Power factor correction None.
(d) Mobile substations None.
(e) Metering Time of use (TOU) meters have not been installed at any of the zone substations, instead OtagoNet relies on the metering information derived from SCADA measurements and the Retailers’ TOU meters installed for the largest 50 customers and the Grid Exit Point metering, the information from which is available to OtagoNet. 2.3 Age and condition of the assets by category [Addresses handbook requirement 4.5.3(c)]
2.3.1 Bulk supply assets and embedded generation Apart from minor SCADA and metering assets there are no other OtagoNet assets at the Transpower points of supply. While there are a number of smaller embedded generation plants and one hydro plant of 12.25 MW at Paerau, these are all owned by others and do not form part of the network.
2.3.2 Subtransmission network The chart below summarises the length and age of the subtransmission network lines.
Figure 11 - Subtransmission Lines
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There are a large number of poles past their standard life, and these will be replaced when condition monitoring finds that they are in poor condition. OtagoNet has very few subtransmission cables and these are generally very new, with the earliest installed in 1977.
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2.3.3 Zone substations The chart below summarises the number and age of the high voltage circuit breakers in the zone substations.
Figure 12 - Circuit Breakers The chart below summarises the number and age of the power transformers and regulators.
Figure 13 - Power Transformers
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Figure 14 Regulator Transformers
2.3.4 Distribution network The chart below shows the age and length of distribution lines on the network.
Figure 15 - Distribution Lines
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The following chart shows the number and age of poles supporting the distribution lines on the network. The wooden poles used for the past 15 years are predominantly CCA treated softwoods which had replaced the early concrete poles for OtagoNet’s standard construction until 2008. A small number of these recent wooden poles will be traditional hardwood where additional strength is required. The majority of poles since late 2008 will now be the 11m standard Busck concrete pole.
Figure 16 - Distribution Poles
The MV cable age profile is shown below:
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2.3.5 Distribution transformers The two following charts show the age and size of the distribution transformers on the network. The first chart shows every size for each year while the second chart shows the transformers grouped by size and years.
Figure 17 - Distribution Transformers
Figure 18 - Distribution Transformers
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2.3.6 MV Switchgear Outdoor MV circuit age profile is shown below, with the oldest units installed in 1968.
2.3.7 LV network The LV network is partially built under the 11kV lines and any LV extensions would have been built at the same time as the 11kV lines, therefore the age profile and pole types are similar to the distribution lines shown above.
2.3.8 Customer connection assets The network connection assets are limited to the ICP fuse on a pole as most of the connections are overhead (14,400) while the few underground connections (340) would have the ICP fuse mounted in a pillar box on the customer’s boundary.
2.3.9 Load control assets The load control relay mounted in most houses and some commercial installations is the property of the Retailer.
2.3.10 Protection and control
2.3.10.1 Protection and control Most of the protection is integrated with the circuit breakers described in Section 2.3.3, age profiles and condition would be similar except for the protection relays at Ranfurly and Deepdell which were replaced in 2005.
2.3.10.2 DC power supplies As DC batteries are essential to the safe operation of protection devices, regular checks are carried out and each battery is replaced prior to the manufacturer’s recommended life.
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2.3.11 SCADA and Communications
2.3.11.1 Master station OtagoNet’s SCADA system was installed in 2000 with computer and software updates every one or two years to keep the system fully up to date with the manufacturer’s latest product.
2.3.11.2 Communications links When the new OtagoNet SCADA system was installed in 2000 most communications links were also updated. This equipment is checked and maintained annually by the agents.
2.3.11.3 Remote stations All SCADA RTU’s will be no older than 13 years with the majority installed in 2000.
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2.3.12 Other assets None.
2.3.13 Summary OtagoNet’s assets are summarised in Table 13 and described more fully in Appendix B. Table 13 – Summary of assets by category
Average Replacement Percent remaining Condition Asset description Quantity Unit Cost (RC) of total life summary $000 RC (% of ODV) 66kV Lines 74 km 57% Good 7,794 2.20% 33kV Lines 536 km 32% Average to 38,855 10.95% Poor 33kV Cable 1 km 86% Good 363 0.10% Other Zone Substation 1,016 No. 42% Average 8,499 2.40% Assets 66/33kV Switchgear 343 No. 44% Average 4,671 1.32% 22/11kV Switchgear 647 No. 46% Good to 4,940 1.39% Average Power transformers 92 No. 44% Average 14,838 4.18% Strategic Spares 180 Lot 31% Average 1,248 0.35% 22kV Lines 253 km 43% Average 9,082 2.56% 11kV Lines 2,970 km 46% Average 146,040 41.17% 11kV Cables 16 km 67% Good 1,686 0.48% Distribution Voltage 8 No. 88% Good 387 0.11% Regulator Distribution Switchgear 1,775 No. 33% Poor 7,260 2.05% Distribution Transformers 4,170 No. 42% Average 24,372 6.87% Distribution Substation 4,153 No. 50% Average 26,937 7.59% Low Voltage Lines 485 km 33% Poor 38,836 10.95% Low Voltage Cables 23 km 71% Good to 1,827 0.52% Average SCADA and 53 No. 55% Good 442 0.12% Communications Land and Buildings 17,454 No. 74% Good 8,838 2.49% Connection Assets 15,354 No. 42% Average 7,852 2.21% Total 44% 354,767 100% Based on valuation as at 1 April 2010.
2.4 Justifying the assets [Addresses handbook requirement 4.5.3(d)] OtagoNet creates stakeholder service levels by carrying out a number of activities (described in Section 5) on the assets, including the initial step of actually building assets such as lines and substations. Some of these assets need to deliver greater service levels than others e.g. the Balclutha substation in south Otago has a higher capacity and security level than the Hyde substation in rural Otago. Hence a greater
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level of investment will be required that will generally reflect the magnitude and nature of the demand. Matching the level of investment in assets to the expected service levels requires the following issues to be considered:
• It requires an intimate understanding of how asset ratings and configurations create service levels such as capacity, security, reliability and voltage stability. • It requires the asymmetric nature of under-investment and over-investment to be clearly understood i.e. over-investing creates service levels before they are needed but under-investing can lead to service interruptions (which typically cost about 10 to 100 times as much as over-investing). • It requires the discrete “sizes” of many classes of components to be recognised e.g. a 220kVA load will require a 300kVA transformer that is only 73% loaded. In some cases capacity can be staged through use of modular components. • Recognition that the existing network has been built up over 90 years by a series of incremental investment decisions that were probably optimal at the time but when taken in aggregate at the present moment may well be sub-optimal. • The need to accommodate future demand growth (noting that the ODV Handbook now prescribes the number of years ahead that such growth can be accommodated). In theory an asset would be justified if the service level it creates is equal to the service level required. In a practical world of asymmetric risks, discrete component ratings, non-linear behaviour of materials and uncertain future growth rates, OtagoNet considers an asset to be justified if its resulting service level is not significantly greater than that required subject to allowing for demand growth and discrete component ratings. A key practical measure of justification is the ratio of OtagoNet’s optimised depreciated replacement cost (ODRC) to OtagoNet’s depreciated replacement cost (DRC) which is 0.9911, with a ratio close to 1 indicating a high level of justification. Assets that were optimised in the last ODV are listed in Table 14, together with a comment on the configuration. Table 14 - Optimised Assets in the 2004 ODV
Asset Comment Charlotte – Finegand One of three circuits to ‘Finegand, not justified under ODV rules, but 33kV line useful to provide an additional level of security for a major customer and a large portion of the general South Otago customers. Palmerston – Merton This circuit is in the process of being duplicated to provide the 33kV line required security to Merton and Waitati, the unfinished section is optimised out under ODV rules. Mahinerangi 33kV This has been optimised to an 11kV line with regulator. line and substation Paerau Power House There is a spare 66kV bay built to allow further expansion that has 66kV not yet happened, the 66kV switches and this bay are optimised out. Hyde 2.5 MVA The expected planning period load of 1.2 MVA allows this transformer transformer to be optimised down to 1.5 MVA.
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3. Proposed service levels
[Addresses handbook requirement 4.5.4] This section describes how OtagoNet set its various service levels according to the following principles:
• What is most important to stakeholders (Section 1.6) o Safety o Viability o Price o Quality o Compliance • How well is OtagoNet meeting those important objectives? • What trade-off’s exist between differing stakeholders? i.e. o Desire for ROI verses desire for low price with good reliability. o Safety at any cost? o Restoration ahead of compliance? (i.e. South Canterbury snow storm) 3.1 Creating service levels OtagoNet creates a broad range of service levels for all stakeholders, ranging from capacity, continuity and restoration for connected customers (who pay for these service levels) to ground clearances, earthing, absence of interference, compliance with the District Plan and submitting regulatory disclosures (which are subsidised by connected customers), which are shown in Figure 19 below. This section describes those service levels in detail and how OtagoNet justifies the service levels delivered to its’ stakeholders.
Figure 19 Types of service levels
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3.2 Customer-oriented service levels [Addresses handbook requirement 4.5.4(a)] This section firstly describes the service levels expected to be provided for customers which is what they pay for and secondly the service levels expected to be provided for other key stakeholder groups which customers are expected to subsidise. Research indicates that customers value continuity and restoration of supply more highly than other attributes such as answering the phone quickly, fast processing of new connection applications etc. It has also become apparent from OtagoNet’s research that there is an increasing value by customers placed on the absence of flicker, sags, surges and brown-outs. Other research indicates that flicker is probably noticed more often than when it is a problem. The difficulty with these conclusions is that the service levels most valued by customers depend strongly on fixed assets and hence require capital expenditure solutions (as opposed to process solutions). This in itself raises the following three issues:
• Limited substitutability between service levels e.g. customers prefer the power to be kept on rather than the phone to be answered quickly. • Averaging effect i.e. all customers connected to an asset will receive about the same level of service. • Free-rider effect i.e. customers who choose not to pay for improved service levels would still receive improved service due to their common connection.
3.2.1 Primary service levels OtagoNet’s primary service levels are continuity and restoration. To measure the performance of a network three internationally accepted indices have been adopted: The continuity of supply can be measured by the number of interruptions experienced by customers. The network measure used by networks to compare this performance is SAIFI.
• SAIFI stands for “system average interruption frequency index”. This is a measure of how many system interruptions occur per year per customer connected to the network. • Customers connected to the OtagoNet network can expect to have their supply interrupted about twice a year. Restoration times can be measured by the average time the power is interrupted to a customer when an interruption occurs. The network measure used by networks to compare this performance is CAIDI.
• CAIDI stands for “customer average interruption duration index”. This is a measure of the average duration of an interruption experienced by customers who actually suffer a supply interruption. • Customers connected to the OtagoNet network who experience an unplanned supply interruption can expect to have their supply restored after a duration of 77 minutes. The remaining network performance index is SAIDI.
• SAIDI stands for “system average interruption duration index”. This is a measure of how many system minutes of supply are interrupted per year per customer connected to the network. • Customers connected to the OtagoNet network can expect to have their supply interrupted for a total duration of 160 minutes per year.
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Projections of two main measures for the next five years ending 31 March 2016 are set out in Table 15 below. CAIDI is found by dividing SAIDI by SAIFI. Table 15 – Primary service levels
Measure Limit6 YE 31/3/12 YE 31/3/13 YE 31/3/14 YE 31/3/15 YE 31/3/16 SAIDI Class B 167.90 167.06 166.23 165.40 164.57 SAIDI Class C 159.95 159.15 158.35 157.56 156.78 SAIDI Total 379.77 327.85 326.21 324.58 322.96 321.35 SAIFI Class B 0.622 0.620 0.618 0.615 0.613 SAIFI Class C 2.078 2.070 2.062 2.055 2.047 SAIFI Total 3.136 2.700 2.690 2.680 2.670 2.660
Note this target is based on normalising extreme events to the following daily boundary values: SAIDI 25.39, SAIFI 0.166 i.e. cannot get more than 25.39 customer-minutes of SAIDI occurring on a single day or event. In practical terms this means customers can broadly expect the reliability stated in Table 16 below. Table 16 – Expected reliability by location
General location Expected reliability Balclutha, Milton, Ranfurly One outage per year of about 60 minutes duration Towns Two outages per year of about 90 minutes duration Villages Three outages per year of about 120 minutes duration Anywhere else Four outages per year of about 240 minutes duration
3.2.2 Secondary service levels Secondary service levels are the attributes of service that OtagoNet’s customers have ranked below the first and second most important attributes of supply continuity and restoration. The key point to note is that some of these service levels are process driven, which has two implications:
• They tend to be cheaper than fixed asset solutions e.g. someone could work a few hours overtime to process a back log of new connection applications, an over- loaded phone could be diverted or the shut-down notification process could be improved. • They are heterogeneous in nature i.e. they can be provided exclusively to customers who are willing to pay more in contrast to fixed asset solutions which will equally benefit all customers connected to an asset regardless of whether they pay. These attributes include:
• How satisfied customers are after communication regarding: o Tree trimming o Connections o Faults. • Time taken to respond to voltage complaints and time to remedy justified voltage complaints. • Are customers given sufficient notice of planned shutdowns?
6 Limit calculated by the Commerce Commission Default Price-Quality Path methodology, with reference data from 1 April 2004 to 31 March 2009. Limit must not be exceeded two out of three years.
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Table 17 below sets out the targets for these service levels for the next 3 years.
Table 17– Secondary service levels
Attribute Measure YE 31/3/12 YE 31/3/13 YE 31/3/14 Customer Satisfaction: Percentage satisfied with >90% >90% >90% Inquiries OtagoNet staff. {CES: Q9(b)}7 Customer Satisfaction: Phone: Friendliness and >3.59 >3.5 >3.5 New Connections courtesy. {CSS: Q3(c)}8 Phone: Time taken to answer >3.5 >3.5 >3.5 call. {CSS: Q3(a)} Overall level of service. >3.5 >3.5 >3.5 {CSS: Q5} Work done to a standard which >3.5 >3.5 >3.5 meet your expectations. {CSS: Q4(b)} Customer Satisfaction: Power restored in a reasonable >70% >70% >70% Faults amount of time. {CES: Q4(b)} Information supplied was >70% >70% >70% satisfactory. {CES: Q8(b)} PowerNet first choice to contact >25% >35% >35% for faults. {CES: Q6} Voltage Complaints Number of customers who have <30 <30 <30 {Reported in Network made voltage complaints report.} Number of customers who have <15 <15 <15 justified voltage complaints regarding power quality Average days to complete <30 <30 <30 investigation Period taken to remedy justified <60 <60 <60 complaints Planned Outages Provide sufficient information. >75% >75% >75% {CES: Q3(a)} Satisfaction regarding amount of >75% >75% >75% notice. {CES: Q3(c)} Acceptance of maximum of >50% >50% >50% three planned outages per year. {CES: Q1} Acceptance of planned outages >50% >50% >50% lasting four hours on average. {CES: Q1} {Where the information is collected / reported from.}
3.2.3 Other service levels In addition to the service levels that are of primary and secondary importance to customers and for which they pay there are a number of service levels that benefit other stakeholders such as safety, amenity value, absence of electrical interference and performance data. In fact most of these service levels are imposed on OtagoNet by statute and, while they necessary for the proper functioning of a safe and orderly
7 CES = Customer Engagement Survey of 200 customers, undertaken by phone annually. 8 CSS = Customer Satisfaction Survey undertaken by sending questionnaire to customers with invoices. 9 Based on a scoring range of 1 to 5, where 1 is bad and 5 is good.
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community, OtagoNet is expected to absorb the associated costs into its overall cost base, in all probability, with little or no ability to recover those costs through constrained revenue.
3.2.3.1 Public safety Various legal requirements require OtagoNet’s assets (and customers’ plant) to adhere to certain safety standards which include earthing exposed metal and maintaining specified line clearances from trees and from the ground:
• Health and Safety In Employment Act 1992. • Electricity (Safety) Regulations 2010. • Electricity (Hazards From Trees) Regulations 2003. • Maintaining safe clearances from live conductors (NZECP34:2001). • Power system earthing (NZECP35:1993).
3.2.3.2 Amenity value There are a number of Acts and other requirements that limit where OtagoNet can erect overhead lines:
• The Resource Management Act 1991. • The Operative District Plans. • Relevant parts of the Operative Regional Plan. • Land Transport requirements. • Civil Aviation requirements. In general, OtagoNet will need to place some assets underground which is usually significantly more expensive and may provide reliability levels beyond that which customers generally expect and are prepared to pay for.
3.2.3.3 Industry performance Various statutes and regulations require OtagoNet to compile and disclose prescribed information to specified standards. These include:
• Electricity Distribution (Information Disclosure) Requirements 2008 and subsequent amendments. • Commerce Act (Electricity Distribution Thresholds) Notice 2004.
3.2.3.4 Electrical interference Under certain operational conditions assets can interfere with other utilities such as phone wires and railway signalling or with the correct operation of OtagoNet’s own equipment or customers’ plant. The following two codes impose service levels on us:
• Harmonic levels (NZECP36:1993). • SWER load limitation to 8A (NZECP41:1993). 3.3 Regulatory service levels [Addresses handbook requirement 4.5.4(b)] Various Acts and Regulations require OtagoNet to deliver a range of outcomes within specified timeframes, such as the following:
• Ensure a wide degree of customer satisfaction with both pricing and reliability to avoid being placed under a restraining regime. • Publicly disclose an AMP each year. • Publicly disclose prescribed performance measures each year. OtagoNet is also required to disclose a range of internal performance and efficiency measures as required by the Electricity Distribution (Information Disclosure) Asset Management Plan Page 53 of 151
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Requirements 2008. The complete derivation of these measures is included in OtagoNet’s disclosure to 31 March 2010.
3.3.1 Financial efficiency measures OtagoNet’s target financial efficiency measures are shown below. These measures are:
• Percentage of Direct Operational Expenditure = [Routine and Preventative Maintenance + Refurbishment and Renewal Maintenance + Fault and Emergency Maintenance] / [Replacement cost of System Fixed Assets at year end.] • Indirect costs per ICP = [General Management, Administration and Overheads expenditure] / [number of ICP’s at year end]. • Values as defined in the Information Disclosure requirements.
Table 18 - Financial Efficiency
Measure YE 31/3/12 YE 31/3/13 YE 31/3/14 YE 31/3/15 YE 31/3/16 Direct OPEX % 0.98% 1.06% 1.09% 1.11% 1.14% Indirect costs $125.23 $140.02 $139.92 $139.83 $139.73
3.3.2 Energy delivery efficiency measures The target energy efficiency measures are shown below. These measures are:
• Load factor - [kWh entering the network during the year] / [[max demand for the year] x [hours in the year]]. • Loss ratio - [kWh lost in the network during the year] / [kWh entering the network during the year]. • Capacity utilisation - [max demand for the year] / [installed transformer capacity].
Table 19 - Delivery Efficiency
Measure YE 31/3/12 YE 31/3/13 YE 31/3/14 YE 31/3/15 YE 31/3/16 Load factor 79% 79% 79% 79% 79% Loss ratio 7.0% 7.0% 7.0% 7.0% 7.0% Capacity utilisation 31% 31% 31% 31% 32%
3.4 Justifying the service levels [Addresses handbook requirement 4.5.4(c)] OtagoNet’s service levels are justified in four main ways:
• Positive cost benefit within the revenue capability.
• By what is achievable with the available skilled labour and technical resources.
• By the physical characteristics and configuration of assets which are expensive to significantly alter but which can be altered if a customer or group of customers agrees to pay for the alteration.
• By a customer’s specific request and agreement to pay for a particular service level.
• When an external agency imposes a service level on us or in some cases an unrelated condition or restriction that manifests as a service level, such as a
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requirement to place all new lines underground or a requirement to maintain clearances. Customer surveys over the last four years have indicated that customers’ preferences for price and service levels are reasonably static – there is certainly no obvious widespread call for increased supply reliability. However OtagoNet does note the following issues:
• The service level called “Safety’ may need to increase as the requirements of the amended Electricity Act 1992 become operative. • Food and drink processing such as Silver Fern Farms and Fonterra Stirling, storage and handling are subject to increasing scrutiny by overseas markets, and in particular interruptions to cooling and chilling are less acceptable. This requires OtagoNet’s cold storage customers to have higher levels of continuity and restoration. • Economic downturn may increase the instance of theft of copper conductor or other operational assets and energy.
3.4.1 Basis for service level targets Statistics for the last six years are listed below:
Measure YE YE YE YE YE YE 31/3/05 31/3/06 31/3/07 31/3/08* 31/3/09* 31/3/10* SAIDI 194.1 313.2 484.8 502.51 274.25 332.64 SAIFI 2.12 3.97 4.19 3.10 3.02 3.26 Load factor 79% 78% 79% 79% 79% 78% Loss ratio 7.4% 6.8% 6.4% 7.8% 6.8% 7.1% Capacity utilisation 38.7% 37.8% 37.3% 30.6% 32.4% 31.8% Direct OPEX/RC 1.49% 1.18% Indirect/ICP $102.32 (*To new Information Disclosure requirements.) SAIDI & SAIFI: Targets set are based on expected improvement due to additional expenditures. We plan to normalise extreme events using the Commerce Commission DPP methodology. Calculated by averaging the normalised values, over the regulatory period (2004/05 – 2008/09), and decreasing future years by 0.5% pa. Load Factor: The last two years has had late spring Lower South Island (LSI) peak due to New Zealand Aluminium Smelter (NZAS) having one of their transformers fail. This meant that peak load control was not required in winter and results in a higher peak, as load control for peak reduction on each GXP was not needed. Target is set similar to the present. Loss Ratio: As the losses are paid for by retailers, there is no direct financial incentive for the network company to reduce these, apart from other technical issues, such as poor voltage or current rating of equipment. No change in target planned. Capacity Utilisation: Impact of renewals where old 5kVA transformers are replaced with the modern 15kVA transformer, and some downsizing due to analysis of loadings. Note the last two years historical figures include non OtagoNet owned distribution transformers in the calculation with a corresponding drop in utilisation. Customer Survey: Target set due to historic trend and likely impact of targeted improvements. For example: More Public Relations with newsletter and fridge-magnet should increase PowerNet as first point of contact for faults. Financial service levels: Calculations done on future years estimates to give likely future costs and ratios.
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4. Development plans
Development plans are driven primarily by:
• Increasing consumer demand, can be due to growth or generation • Asset renewal requirements • Statutory requirements to improve service levels (Security of supply, safety or environmental compliance.) • Internally generated initiatives to improve service levels At its most fundamental level, demand is created by individual consumers drawing (or injecting) energy across their individual connections. The demand at each connection aggregates “up the network” to the distribution transformer, then to the distribution network, the zone substation, the subtransmission network to the GXP and ultimately through the grid to a power station. 4.1 Planning approach and criteria [Addresses Handbook requirement 4.5.5(a)]
4.1.1 Planning unit OtagoNet has adopted the 22kV or 11kV feeder as OtagoNet’s fundamental planning unit which typically represents one or perhaps two of the following combinations of consumer connections:
• An aggregation of up to 1,000 urban domestic consumer connections. • An aggregation of up to 200 urban commercial consumer connections. • An aggregation of up to 30 urban light industrial consumer connections. • An aggregation of anywhere up to 500 rural domestic or farm consumer connections. • A single large industrial consumer connection. • Injection of generation. Physically this planning unit will usually be based around the individual lines or cables emanating from a zone substation. For single load of more than 1MW (i.e., beyond what is considered incremental) OtagoNet’s planning principles and methods still apply, but likely outcome is new assets at 11kV or higher.
4.1.2 Planning approaches OtagoNet plans its assets in three different ways; strategically, tactically and operationally as shown in Table 20 below:
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Table 20- Planning approaches
Attribute Strategic Tactical Operational Asset description Assets within GXP. Minor zone substation All 400V lines and Subtransmission lines assets. cables. and cables. All individual All 400V consumer Major zone substation distribution lines connections. assets. (11kV). All consumer Load control injection All distribution line metering and load plant. hardware. control assets. Central SCADA and All on-network telemetry. telemetry and SCADA Distribution components. configuration e.g. All distribution decision to upgrade to transformers and 22kV. associated switches. All HV consumer connections. Number of Anywhere from 500 Anywhere from one to Anywhere from one consumers upwards. about 500. to about 50. supplied Impact on Individual impact is low. Individual impact is Individual impact is balance sheet Aggregate impact is moderate. low. and asset moderate. Aggregate impact is Aggregate impact is valuation significant. moderate. Degree of Likely to be included in Likely to be included in Likely to be included specificity in very specific terms, specific terms and in broad terms, with plans probably accompanied accompanied by a maybe a sentence by an extensive paragraph or two. describing each narrative. inclusion. Level of approval Approved in principle in Approved in principle in Approved in principle required annual business plan. annual business plan. in annual business Individual approval by Individual approval by plan. Board and possibly Chief Executive. Individual approval shareholder. by Network Manager (Otago). Characteristics of Tends to use one-off Tend to use established Tends to use analysis models and analyses models with some established models involving a significant depth, a moderate based on a few number of parameters range of parameters significant and extensive and possibly one or two parameters that can sensitivity analysis. sensitivity scenarios. often be embodied in a “rule of thumb”.
OtagoNet has developed the following “investment strategy matrix” shown in Figure 20, which broadly defines the nature and level of investment and the level of investment risk implicit in different circumstances of growth rates and location of growth.
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Figure 20 - Investment strategy matrix Predominant Capital expenditure (CAPEX) modes are:
• Large industrial loads such as a new factory which involves firstly extension and then usually up-sizing sit in Quadrant 4 which has desirable investment characteristics. This mode of investment does however carry the risk that if demand growth doesn’t occur as planned, stranding can occur and the investment slips into Quadrant 3 which has less desirable investment characteristics. • Dairy conversions involve extensions and then sometimes up-sizing but due to the lumpy nature of constructing line assets these may fall into Quadrant 3 which carries some risk of stranding or delayed recovery of investment. • Declining cost of domestic heat pumps primarily requires urban up-sizing which fits mainly in Quadrant 2, which has reasonably desirable investment characteristics. • Residential subdivisions around urban areas tend to have large up-front capital costs but recovery of costs through line charges often lags well behind. The size of the subdivision will dictate whether it falls in Quadrant 1 or 3, neither of which has particularly desirable investment characteristics. Hence some form of developer contribution is almost certain to be expected.
4.1.3 Trigger points for planning new capacity As new capacity has valuation, balance sheet, depreciation and ROI implications for OtagoNet, endeavours will be made to meet demand by other, less investment-
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intensive means. This discussion also links strongly to OtagoNet’s discussion of asset life cycle in section 5.1. The first step in meeting future demand is to determine if the projected demand will exceed any of OtagoNet’s defined trigger points for asset location, capacity, reliability, security or voltage. These points are outlined for each asset class in Table 21. If a trigger point is exceeded OtagoNet will then move to identify a range of options to bring the asset’s operating parameters back to within the acceptable range of trigger points. These options are described in section 4.2 which also embodies an overall preference for avoiding new capital expenditure.
Table 21 - Summary of capacity "trigger points"
Asset class
Type Trigger LV lines and Distribution Distribution lines cables substations and cables
Extension Location Existing LV lines and Load cannot be Load cannot be cables don’t reach the reasonably reasonably supplied required location. supplied by LV by LV configuration configuration therefore requires therefore requires new distribution lines new distribution or cables and lines or cables substation. and substation. Up-sizing Capacity Tends to manifest as Where fitted, MDI Analysis calculates fuse blowing when reading exceeds that the peak current current exceeds circuit 90% of nameplate exceeds the thermal rating. rating. rating of the circuit segment. Reliability Not applicable. Normally a Maintenance or Operational trigger, as no requirement for up-sizing. Security Excursion beyond triggers specified in section 3.2.1
Voltage Voltage at consumers’ Voltage at Voltage at MV boundary consistently consumers’ terminals of drops below 0.94pu. boundary transformer consistently drops consistently drops below 0.94pu that below 10.45kV and cannot be cannot be remedied by LV compensated by local up-sizing. tap setting. Renewal Condition Asset deteriorated to an unsafe condition. Third party requests work. Neighbouring assets being replaced.
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Asset class
Type Trigger Zone substations Subtransmission Network lines and cables equipment within GXP
Extension Location Load cannot be Load cannot be Load cannot be reasonably supplied reasonably supplied reasonably supplied by distribution by distribution by new or extended configuration configuration Subtransmission or therefore requires therefore requires substation therefore new new subtransmission requires new GXP subtransmission lines or cables and equipment. lines or cables and zone substation. zone substation. Up-sizing Capacity Max demand Analysis calculates Max demand consistently that the peak current consistently exceeds exceeds 100% of exceeds the thermal 80% of nameplate nameplate rating. rating of the circuit rating. segment. Reliability Not applicable. Normally a Maintenance or Operational trigger, as no requirement for up-sizing. Security Excursion beyond triggers specified in section 3.2.1.
Voltage Voltage at MV Voltage at HV Not applicable. terminals of terminals of transformer transformer consistently drops consistently drops below 10.45kV and below 0.87pu and cannot be cannot be compensated by compensated by OLTC. OLTC. Renewal Condition Asset deteriorated to an unsafe condition. Third party requests work.
4.1.4 Quantifying new capacity The two major issues surrounding constructing new capacity are:
• How much capacity to build? This comes back to the trade-off between cost and building in extra capacity for security and safety (risk-avoidance). • When to build the new capacity? The obvious theoretical starting point for timing new capacity is to build just enough, just in time, and then add a bit more over time. However OtagoNet recognises the following practical issues:
• The need to avoid risks associated with over-loading and catastrophic failure. • The need to limit investment to what can be recovered under the price-path threshold and the ODV valuation methodology. • The standard size of many components (which makes investment lumpy). The one-off costs of construction, consenting, traffic management, access to land and reinstatement of sealed surfaces which make it preferable to install large lumps of capacity and not go back to the site. Selection of the right capacity to build is based on the following:
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o MV laterals Chlorine conductor o LV allow 20% growth • Cables o Allow 100% growth • Distribution transformers o Individual consumers, size to consumer capacity. o Domestic consumers based on following diversity: Consumers Transformer Size 2 15kVA 6 30kVA 10 50kVA 20 100kVA 50 200kVA 80 300kVA 150 500kVA
• Line equipment o Use standard ratings (e.g. ABS 400A, Recloser 400A) • Power transformers o Allow expected area growth over 20 years • Substation equipment o Use standard ratings • Subtransmission lines o Allow expected area growth over 20 years OtagoNet’s guiding principle is therefore to minimise the level of investment ahead of demand, while minimising the costs associated with doing the work. 4.2 Prioritisation methodology [Addresses handbook requirement 4.5.5(b)]
4.2.1 Options for meeting demand Table 21 defines the trigger points at which the capacity of each class of assets needs to be increased. In a broad order of preference, actions to increase the capacity of individual assets within these classes can take the following forms:
• Do nothing and simply accept that one or more parameters have exceeded a trigger point. In reality, do nothing options would only be adopted if the benefit-cost ratios of all other reasonable options were unacceptably low and if assurance was provided to the Chief Executive that the do nothing option did not represent an unacceptable increase in risk to OtagoNet. An example of where a do nothing option might be adopted is where the voltage at the far end of a remote rural feeder is unacceptably low for a short period at the height of the holiday season – the benefits of correcting such a constraint may be simply too low. • Operational activities, in particular switching on the distribution network to shift load from heavily-loaded to lightly-loaded feeders to avoid new investment or winding up a tap changer to mitigate a voltage problem. The downside to this approach is that it may increase line losses, reduce security of supply or compromise protection settings. • Influence consumers to alter their consumption patterns so that assets perform at levels below the trigger points. Examples might be to shift demand to different time zones, negotiate interruptible tariffs with certain consumers so that overloaded assets can be relieved or assist a consumer to adopt a substitute energy source to avoid new capacity. OtagoNet notes that the effectiveness of line tariffs in Asset Management Plan Page 61 of 151
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influencing consumer behaviour is dampened by the retailers’ practice of repackaging fixed and variable charges. • Construct distributed generation so that an adjacent asset’s performance is restored to a level below its trigger points. Distributed generation would be particularly useful where additional capacity could eventually be stranded or where primary energy is going to waste e.g. waste steam from a process. • Modify an asset so that the asset’s trigger point will move to a level that is not exceeded e.g. by adding forced cooling to transformers. This is essentially a subset of the above approach but will generally involve less expenditure. This approach is more suited to larger classes of assets such as power transformers. • Retrofitting high-technology devices that can exploit the features of existing assets including the generous design margins of old equipment. An example might include using advanced software to thermally re-rate heavily-loaded lines, using remotely switched air break switches to improve reliability or retrofit core temperature sensors on large transformers to allow them to operate closer to temperature limits. • Install new assets with a greater capacity that will increase the assets trigger point to a level at which it is not exceeded. An example would be to replace a 200kVA distribution transformer with a 300kVA so that the capacity criterion is not exceeded. In identifying solutions for meeting future demands for capacity, reliability, security and satisfactory voltage levels, OtagoNet considers options that cover the above range of categories. The benefit-cost ratio of each option is considered including estimates of the benefits of environmental compliance and public safety and the option yielding the greatest benefit is adopted. OtagoNet uses the model in figure 21 to broadly guide adoption of various approaches:
Figure 21 - Options for meeting demand
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4.2.2 Meeting security requirements A key component of security is the level of redundancy that enables supply to be restored independently of repairing or replacing a faulty component. Typical approaches to providing security to a zone substation include:
• Provision of an alternative substation-transmission circuit into the substation, preferably separated from the principal supply by a 66kV or 33kV bus-tie. • Provision to back-feed on the 22kV or 11kV from adjacent substations with sufficient 22kV or 11kV capacity and interconnection. This obviously requires those adjacent substations to be operated within this less than nominal rating. • Use of local generation. • Use of interruptible load (water heating, irrigation). The most pressing issue with security is that it involves a level of investment beyond what is obviously required to meet demand and it can be easy to let demand growth erode this surplus capacity. This was one of the key conclusions of the Electricity Distribution and Service Delivery Report into the blackouts following the storms in Queensland in 2004.
4.2.2.1 Prevailing security standards The commonly adopted security standard in New Zealand is the EEA Guidelines which reflect the UK standard P2/5 that was developed by the Chief Engineers’ Council in the late 1970’s. P2/5 is a strictly deterministic standard i.e. it states that “this amount and nature of load will have this level of security” with no consideration of individual circumstances. Deterministic standards are now beginning to give way to probabilistic standards in which the value of lost load and the failure rate of supply components is estimated to determine an upper limit of investment to avoid interruption.
4.2.2.2 Issues with deterministic standards A key characteristic of deterministic standards such as P2/5 and the EEA Guidelines is that rigid adherence generally results in at least some degree of over investment. Accordingly the EEA Guidelines recommend that individual circumstances be considered.
4.2.2.3 Contribution of local generation to security To be of any use from a security perspective, local generation would need to have 100% availability which is unlikely from a reliability perspective and even less likely from a primary energy perspective such as run-of-the-river hydro, wind or solar. For this reason, the emerging UK standard P2/6 provides for minimal contribution of such generation to security.
4.2.2.4 OtagoNet security standards Table 22 below describes the security standards adopted by OtagoNet, whilst Table 23, lists the level of security at each zone substation and justifies any shortfall. In setting target security levels the following guiding principles are used:
• Where a substation is for the predominant benefit of a single consumer, their wish for security will over-ride prevailing industry guidelines. • The preferred means of providing security to rural zone substations would be back- feeding on the 22kV or 11kV subject to interconnection, line ratings and surplus capacity at adjacent substations. This is difficult due to the terrain with most of OtagoNet’s assets in the valleys and no crossings over the hills.
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• The preferred means of providing security to urban zone substations will be by secondary subtransmission assets with any available back-feeding on the 22kV or 11kV providing a third tier of security. Table 22 - Target security levels
Description Load type Security level AAA Greater than 12MW or 6,000 No loss of supply after the first consumers. contingent event. AA Between 5 and 12MW or 2,000 All load restored within 25 minutes of to 6,000 consumers. the first contingent event. A(i) Between 1 and 5MW All load restored in time to isolate and back-feed following the first contingent event. A(ii) Less than 1MW All load restored in time to repair after the first contingent event.
Table 23 - Substation security levels
Substation Target 2021 Actual Now Remarks Balmoral A(ii) A(ii) One pump Becks A(ii) A(ii) Big Sky Dairy A(ii) A(ii) One pump Brothers Peak A(ii) A(ii) One radio repeater Charlotte Street AA AAA Clarks A(ii) A(ii) Clinton A(i) A(ii) One 33 kV line and limited 11kV back feed, spare transformer to be purchased and stored here. Clydevale A(i) A(ii) Dual 33 kV lines available but single transformer and limited 11kV back feed. Cormack A(ii) A(ii) One house Craiglynn A(ii) A(ii) Deepdell A(ii) A(ii) Elderlee Street AA AAA Finegand A(i) A(ii) Multiple 33 kV feeds, single transformer and limited 11 kV back feed. Glenore A(ii) A(ii) Multiple 33 kV feeds, single transformer and limited 11 kV back feed. Golden Point A(i) A(ii) No backup available with single consumers agreement. Hindon A(ii) A(ii) Hills Creek A(ii) A(ii) Hore’s Pump A(ii) A(ii) One pump Hyde A(i) A(ii) Most customers can be back fed through 11 kV lines, except Macraes pumps. Kaitangata A(i) A(i) Lawrence A(i) A(ii) Multiple 33 kV feeds, single transformer and limited 11 kV back feed. Macraes Mine AA A(ii) No backup available with single consumers agreement. Merton A(i) A(ii) Single 33 kV line with dual transformers and limited 11kV backup. Middlemarch A(ii) A(ii)
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Substation Target 2021 Actual Now Remarks North Balclutha A(i) A(i) O'Mally's House A(ii) A(ii) One house O'Mally's Pump A(ii) A(ii) One pump Oturehua A(ii) A(ii) Owaka A(i) A(ii) Limited 11kV back feed. Paerau A(ii) A(ii) Paerau Hydro AA A(ii) No backup available with single consumers agreement. Palmerston A(i) A(ii) Single short (2km) 33 kV line dual transformers and limited 11kV back feed. Patearoa A(i) A(ii) Increasing load requires 11kV reinforcement Port Molyneux A(ii) A(ii) Pukeawa A(ii) A(ii) Ranfurly A(i) AA Ranfurly 66/33 AA AAA Redbank A(ii) A(ii) Rough Ridge A(ii) A(ii) One telecom repeater. Stirling A(i) A(ii) Limited 11kV back feed with single consumers agreement. Stoneburn A(ii) A(ii) Tisdall A(ii) A(ii) One pump Waihola A(i) A(ii) Limited 11kV back feed, to be reinforced by future substation. Waipiata A(ii) A(ii) Waitati A(i) A(ii) Limited 11kV back feed from one distant substation. Wedderburn A(ii) A(ii)
4.2.3 Choosing the best option to meet demand Each of the possible approaches to meeting demand that are outlined in section 4.2.1 will contribute to strategic objectives in different ways. OtagoNet uses a number of decision tools to evaluate options depending on their cost:
Cost & nature of option Decision tools Organisational level of evaluation Up to $50,000, commonly OtagoNet standard rules. Network Manager recurring, individual projects Industry rules of thumb. not tactically significant but Manufacturer’s tables and collectively they do add up. recommendations. Simple spreadsheet model based on a few parameters. Up to $250,000, individual Spreadsheet model to calculate NPV Network Manager projects of tactical that might consider 1 or 2 variation significance. scenarios.
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Cost & nature of option Decision tools Organisational level of evaluation Up to $1,000,000 occurs Extensive spreadsheet model to Chief Executive maybe once every few years, calculate NPV, Payback that will likely to be strategically probably consider several variation significant. scenarios. Use of UMS Optimisation tool. Over $1,000,000 occurs Extensive spreadsheet model to Board approval maybe once in a decade, calculate NPV, Payback that will likely to be strategically probably consider several variation significant. scenarios. Use of UMS Optimisation tool.
4.3 OtagoNet’s demand forecast [Addresses handbook requirement 4.5.5(c)]
4.3.1 OtagoNet’s current demand OtagoNet’s maximum demand (MD) of 60.419 MW did not occur at the same time as the Lower South Island (LSI) peak at 7:30 pm on the 15 April 2010 when the demand was only 52.679 MW. The individual maximum demands and the LSI coincident demands are shown in Table 24. Table 24 – OtagoNet’s GXP and Generation Maximum Demands
Anytime Maximum Demand Coincident Demand Between 1/09/09 and 31/08/10 On 15 April 2009 at (MW) 1930hrs (MW) Naseby GXP 26.462 25.536 Palmerston GXP 8.598 6.422 Balclutha GXP 27.024 20.462 Total Transpower 60.419 52.679 Paerau Generator 12.363 0.0 Falls Dam Generator 1.296 0.259 (OtagoNet maximum demand including generation occurred at 0830hrs 1 April 2010)
Each zone substation recorded the maximum demands as listed in table 25. Table 25 substation demand
Installed 2010 Maximum Zone substation Capacity (MVA) Demand (MVA) Charlotte Street 10.0 7.0 Clarks Junction 0.5 0.3 Clinton 2.5 2.0 Clydevale 2.5 2.1 Deepdell 0.8 0.2 Elderlee Street 10.0 6.2 Finegand 2.5 1.6 Glenore 1.5 0.8 Golden Point 5.0 2.9
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Installed 2010 Maximum Zone substation Capacity (MVA) Demand (MVA) Hindon 0.5 0.3 Hyde 2.5 1.3 Kaitangata 2.5 1.4 Lawrence 2.5 1.5 Macraes Mine 30 20.4 Mahinerangi 0.1 0.0 Merton 5.0 2.6 Middlemarch 1.5 0.7 North Balclutha 5.0 2.9 Oturehua 0.8 0.2 Owaka 2.5 1.6 Paerau 0.8 0.2 Paerau Hydro 30 12.1 Palmerston 5.0 2.2 Patearoa 2.5 1.6 Port Molyneux 2.5 0.6 Pukeawa 0.8 0.2 Ranfurly 5.0 2.4 Ranfurly 66/33kV 50.0 23.7 Stirling 5.0 3.8 Waihola 1.5 1.1 Waipiata 1.5 1.1 Waitati 2.5 1.6 Wedderburn 0.8 0.2
4.3.2 Drivers of future demand Key drivers of demand growth (and contraction) are likely to include the issues depicted in Figure 22.
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Climatic effects Economic activity Demographics & lifestyle Industry & Economic Local growth technology Convenience of Increasing Increasing initiatives rural ambient up-turns trends electricity compared Increasing to other fuels irrigation temp. energy use Distributed per customer Ascending Low NZ$ generation commodity Climate cycles Migration into change New industrial urban areas initiatives plants
All these factors increase demand
Localised Aggregate demand demand growth growth
All these factors decrease demand
Conservation Economic decline
Demographics & lifestyle Increasing End of useful conservation Declining life of major Economic Declining affordability industrial plant down-turn overall local High NZ$ population Increasing energy Plant closure Descending efficiency for other commodity reasons cycle
Figure 22 - Drivers of demand
At residential and light commercial feeder level, three or four of these issues may predominate and be predictable and manageable on a statistical basis however experience is that large consumers give little if any warning of increases or decreases in demand. The residential and light commercial demand projections can be aggregated into a reasonably reliable zone substation demand forecast but heavy industrial demand will always remain more unpredictable. OtagoNet’s estimates of future demand are described in section 4.3.4 below. Historically, OtagoNet has experienced an average annual demand growth of about 2.4% for the last 10 years. This growth has been distorted with Transpower’s introduction of TPM10 where individual ELB peaks have been replaced by a regional grouping. This has allowed OtagoNet to relax load control during the year due to the increased summer loading of Dairying and Irrigation. Whilst the company expects this average rate not to continue and to influence the revenue aspects of OtagoNet’s business, such as pricing, it must be acknowledged that actual demand growth at
10 Transmission Pricing Methodology: Allocation of Transpower costs are based on the share of the average of the top 100 peaks for all loads in the Lower South Island (LSI) region. See http://www.ea.govt.nz/industry/transmission/transmission-pricing/transmission-pricing-methodology/ for details.
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localised levels (which will influence costs) can vary anywhere from negative to highly positive. The following sections examine in detail the predicted significant drivers of OtagoNet’s network configuration over the next 10 to 15 years. 4.3.2.1 Connection of Distributed Generation OtagoNet has had inquiries from numerous developers and generation companies which highlight the present interest in wind generation. Wind generation up to 2MW can be connected to some 11kV feeders. Above this level or, if a number are installed in an area, will require connection to the subtransmission network. One company has applied for resource consent for a 7.65MW wind farm at Mt Stuart which would require connection to the 33kV network. There have been enquiries about other hydro and coal seam gas generation in the OtagoNet area, but to date there have been no formal applications received. Distributed Generation (DG) of under 10kW is occurring at a slow rate on the network, and these are normally connected on existing installations, so no additional capacity is required. Any larger wind farms will need to connect to the Transpower Transmission network at 110kV or 220kV. 4.3.2.2 Milling of local forests This could involve expansion of existing mills (Figure 20 Quadrant 2), or could involve new mills (Figure 20 Quadrant 2 or 4 depending on location). Key drivers of investment will include global timber prices, the eventual outcome of the Kyoto Protocol, the strength of the NZ dollar and any decisions to process locally as opposed to export. A new mill is expected at Milburn in the next year. 4.3.2.3 Irrigation Dry areas in north Otago and the Maniototo have an on-going and increasing demand for irrigation. Other areas in South Otago have a more constant rainfall with little or no irrigation required. An allowance for up to 4% annual demand increase has been made on some substations in the Maniototo. 4.3.2.4 Dairy conversions While there was an early uptake in dairy conversions in South Otago, there is still a larger land area that could be converted. This suggests there will be an on-going flow of dairy conversions and new 50kVA loads appearing throughout OtagoNet’s network. An allowance of up to 2% demand increase has been made for some substations in the South Otago areas, due to Dairy conversions. 4.3.2.5 Mining The gold mine at Macraes underwent a step change in load in 2007, with their underground mining operations. Investigations are on-going to allow load increases and may create new projects in the planning period. There are other gold prospects in the Otago area, but to date there have been no serious enquiries for new loads. Coal mining continues in Kaitangata and although there are other coal fields no load increases are expected in the planning period.
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4.3.3 Load forecast trend Analysis of historic demand and energy usage over the last 10 years to 31 March 2010 shows a 10 year average demand growth of 2.4% and energy growth of 2.9% while the last year’s demand growth was 1.2% with an energy growth of 0.4%. The chart below shows the data since 1949 and the drop in demand in the mid 1990’s when computerised load control was introduced. OJV Historic Energy and Maximum Demand 90 450 Maximum Demand 80 400 Energy
70 350
60 300
50 250
40 200 Energy - (GWh)
Maximum Demand - (MW) 30 150
20 100
10 50
0 0 000 003 006 009
1949 1952 1955 1958 1961 1964 1967 1970 1973 1976 1979 1982 1985 1988 1991 1994 1997 2 2 2 2
4.3.4 Estimated zone substation demands As outlined in detail in the remainder of section 4, OtagoNet’s demand is expected to increase from that described in section 4.3.1 as follows:
• Standard natural growth of 1.0%, with some decline of small rural communities. • Irrigation growth in North Otago of 2%. • Continued Dairy conversions in South Otago. Experience strongly indicates that it would be rare to ever get more than a few months confirmation, sufficient to justify significant investment, of definite changes in an existing or a new major consumer’s demand. This is because most of these consumers operate in fast-moving consumer markets and often make capital investment decisions quickly themselves and they generally keep such decisions confidential until the latest possible moment. Probably the best that OtagoNet can do is to identify in advance where OtagoNet’s network has sufficient surplus capacity to supply a large chunk of load but, as experience shows, industrial siting decisions rarely, if ever, consider the location of energy supply – they tend to be driven more by land-use restrictions, raw material supply and transport infrastructure. Table 26 below identifies the rate of growth projected to zone substation level for a 10 year horizon, along with the provision expected to be made for future growth.
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Table 26 Substation demand growth rates
Maximum Annual Projected Design Demand Growth Demand Zone Capacity 2010 Rate 2021 Substation MVA MVA % MVA Provision planned Charlotte Street 10.0 7.0 0.5% 7.3 Clarks Junction 0.5 0.3 0.0% 0.3 Clinton 2.5 2.02.0% 2.4 Load transfer, spare TX Clydevale 2.5 2.13.0% 2.7 Increase capacity Deepdell 0.8 0.20.0% 0.2 Elderlee Street 10.0 6.2 6.0% 9.9 Transfer load to new Sub Finegand 2.5 1.60.5% 1.7 Glenore 1.5 0.85.0% 1.2 Golden Point 5.0 2.9 0.0% 2.9 Hindon 0.5 0.30.0% 0.3 Hyde 2.5 1.35.0% 1.9 Kaitangata 2.5 1.4 3.0% 1.8 Lawrence 3.0 1.50.5% 1.7 Macraes Mine 30.0 20.4 0.0% 20.4 Merton 5.0 2.61.0% 2.8 Middlemarch 1.5 0.7 3.0% 1.0 North Balclutha 5.0 2.9 0.5% 3.0 Oturehua 0.8 0.20.0% 0.2 Owaka 2.5 1.60.5% 1.7 Paerau 0.8 0.21.0% 0.3 Paerau Hydro 30.0 12.1 0.0% 12.1 Palmerston 5.0 2.2 1.0% 2.4 Patearoa 2.5 1.68.0% 2.8 Load transfer, increase Port Molyneux 2.5 0.6 1.0% 0.6 Pukeawa 0.8 0.22.0% 0.3 Ranfurly 5.0 2.43.0% 3.1 Ranfurly 66/33kV 50.0 23.7 0.0% 23.7 Stirling 5.0 3.83.5% 5.1 Customer driven Waihola 1.5 1.13.0% 1.4 Transfer load Waipiata 1.5 1.17.5% 2.0 Increase capacity Waitati 2.5 1.61.0% 1.8 Wedderburn 0.8 0.2 3.0% 0.3 The red highlighted values indicate when the initial trigger point for capacity is exceeded based on the present equipment and configuration. 4.3.4.1 Demand model assumptions The impact of Distributed Generation (DG) has been ignored due to the estimated low connection rate of DG and the probability that only a small percentage of the capacity will be available during peaks. Load Management is used when substation equipment is nearing overload, and during load transfers for maintenance, and hasn’t been considered in the projected demands above. Load shifting can also be done at the Retailer’s request or during Dry-year rationing. Increased monitoring of heavily load sites if data indicates capacity will be extended.
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Annual preparation of this data will highlight sites that vary from the above model and the planned works adapted for each situation, with some upgrades delayed or brought forward.
4.3.5 Estimated demand aggregated to GXP level Table 27 shows the aggregated effect of substation demand growth for a 10 year horizon at the three GXP’s, Paerau and Falls Dam. Table 27 GXP demand growth
2010 MD 2020 MD GXP (MW) Growth (MW) Provision for growth Balclutha 27.024 0.5% 28.406 No further work required Palmerston 8.598 2.0% 10.480 No further work required Naseby 26.462 2.5% 33.874 No further work required Paerau 12.363 0.0% 12.250 No generation increase expected Falls Dam 1.296 0.0% 1.296 No generation increase expected OtagoNet 75.743 2.0% 86.306 Total
4.3.6 Issues arising from estimated demand The significant issues arising from the estimated demand in section 4.3.4 and 4.3.5 are:
• Medium term trigger is reached at Patearoa and Waipiata due to irrigation loads. • Long term trigger is reached at Clinton and Clydevale due to dairy farm conversions. • Elderlee Street capacity would be reached due to industry, timber mills and additional housing but load will be transferred to the new Milburn substation. 4.4 Where are OtagoNet network constraints OtagoNet’s network includes the following constraints:
Constraint Description Intended remedy Milton 33kV The loads of Lawrence, Glenore, Rebuild of the western 33kV line to Elderlee Street and Waihola Milton is in progress with larger exceed one 33kV line’s capability conductor Patearoa. 2.5 MVA capacity will be reached Load transfer to adjacent substations by 2018 Ranfurly and Waipiata or increase transformer capacity Waipiata 1.5 MVA capacity will be Transformer replacement with a exceeded before 2018 standard 2.5 MVA unit is in progress. Clinton 2.5 MVA capacity may be reached Consider transformer upgrade and by 2018 or load transfer dependant on 11kV line reinforcements Clydevale 2.5 MVA capacity will be reached Consider transformer upgrade and by 2018 or load transfer dependant on 11kV line reinforcements 11kV Back feed Clinton, Clydevale, Hyde, Owaka, 11kV line reinforcements are Patearoa, Waihola, Waipiata and required to provide additional back Waitati should have A(i)11 security feed capabilities levels, but only have A(ii)12
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Constraint Description Intended remedy Environmental – Expectation of no significant oil Install oil bunding and separation Oil spills from any substation systems at remaining substations Quality of Supply In some growth areas the LV lines Upgrade LV lines in towns as - Voltage are inadequate to supply the new required and consider the size and loads location of transformers Quality of Supply Frequent auto reclose operations Continue with vegetation control, line - Interruptions. on remote lines maintenance and renewals
4.5 Policies for distributed generation [Addresses handbook requirement 4.5.5(d)] The value of distributed generation is clearly recognised in the following ways:
• Reduction of peak demand at Transpower GXP’s. • Reducing the effect of existing network constraints. • Avoiding investment in additional network capacity. • Making a very minor contribution to supply security where the consumers are prepared to accept that local generation is not as secure as network investment. • Making better use of local primary energy resources thereby avoiding line losses. • Avoiding the environmental impact associated with large scale power generation. It is also recognised that distributed generation can have the following undesirable effects:
• Increased fault levels, requiring protection and switchgear upgrades. • Increased line losses if surplus energy is exported through a network constraint. • Stranding of assets or, at least, of part of an asset’s capacity. Despite the potential undesirable effects, the development of distributed generation that will benefit both the generator and OtagoNet is actively encouraged. The key requirements for those wishing to connect distributed generation to the network broadly fall under the following headings, with a guideline and application forms available on the web at: http://www.powernet.co.nz/dg-guide.
4.5.1 Connection terms and conditions (commercial)
• Connection of up to 10kW of distributed generation to an existing connection to the network will not incur any additional line charges. Connection of distributed generation greater than 10kW to an existing connection may incur additional costs to reflect network up-sizing. • Distributed generation that requires a new connection to the network will be charged a standard connection fee as if it was a standard off-take consumer. • An application fee will be payable by the connecting party. • Installation of suitable metering (refer to technical standards below) shall be at the expense of the distributed generator and its associated energy retailer. • Any benefits of distributed generation that arise from reducing OtagoNet’s costs, such as transmission costs or deferred investment in the network, and, provided the distributed generation is of sufficient size to provide real benefits, will be recognised and shared.
12 A(ii) = Load restored in time to isolate and back-feed.
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• Those wishing to connect distributed generation must have a contractual arrangement with a suitable party in place to consume all injected energy – generators will not be allowed to “lose” the energy in the network.
4.5.2 Safety standards
• A party connecting distributed generation must comply with any and all safety requirements promulgated by OtagoNet. • OtagoNet reserves the right to physically disconnect any distributed generation that does not comply with such requirements.
4.5.3 Technical standards
• Metering capable of recording both imported and exported energy must be installed if the owner of the distributed generation wishes to share in any benefits accruing to OtagoNet. Such metering may need to be half-hourly. • OtagoNet may require a distributed generator of greater than 10kW to demonstrate that operation of the distributed generation will not interfere with operational aspects of the network, particularly such aspects as protection and control. • All connection assets must be designed and constructed to technical standards not dissimilar to OtagoNet’s own prevailing standards. 4.6 Use of non-asset solutions [Addresses handbook requirement 4.5.5(e)] As discussed in section 4.2.1 the company routinely considers a range of non-asset solutions and indeed OtagoNet’s preference is for solutions that avoid or defer new investment. Effectiveness of tariff incentives is lessened with Retailers repackaging line charges that sometimes removes the desired incentive. ‘Use of System’ agreements include lower tariffs for controlled, night-rate and other special channels. Load control is utilised to control:
• The amount of Transpower charges by controlling the network load during the LSI peaks. • The load on individual GXP’s when they exceed the capacity of that GXP. • The load on feeders during outage situations. 4.7 Network development options [Addresses handbook requirement 4.5.5(f)]
4.7.1 Identifying options When faced with increased demand, reliability, security or safety requirements, OtagoNet considers the broad range of options described in Section 4.2.1. The range of options for each issue varies due to:
• Stakeholder interests Section 1.6 lists stakeholder interests and the engineer considers these areas in planning and ranking an option.
• Size of the project Different issues have differing resource requirements the level of analysis and the breadth of options varies. A simple issue like connecting a new customer next to an
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existing low voltage pillar box would only have a single option analysed, whereas a new industrial plant would have multiple options considered.
• Creativity and knowledge of the Engineer Breadth of options is also dependent on the Engineer undertaking the planning. Options are developed by the Engineer and critiqued by the Chief Engineer and/or Network Manager (Otago). Use of standard construction and existing designs mainly, but support for innovation.
• Resource The other higher priority projects may limit the resources available for each option. This could be a limitation of finances (uneconomic), workforce (to plan, design, manage, build or operate), materials (unavailability or long lead-time of equipment.) or legal (need Resource Consent or Easements.)
4.7.2 Identifying the best option Once the best broad option has been identified using the principles embodied in figure 21. OtagoNet will use a range of analytical approaches to determine which option best meets OtagoNet’s investment criteria. As set out in Section 4.2.3, OtagoNet uses increasingly detailed and comprehensive analytical methods for evaluating more expensive options.
• Simple Spreadsheet: Cost calculation with standardised economic benefit values. • Risk analysis: More comprehensive and complexity for larger projects. • Net Present Value (NPV) model: Time series model of future costs and benefits. • Payback calculation: Financial calculation of the time estimated to recover cost of undertaking that option.
4.7.3 Implementing the best option Having determined that a fixed asset (CAPEX) solution best meets OtagoNet’s requirements and that OtagoNet’s investment criteria will be met (and if they won’t be met, ensuring that a consumer contribution or some other form of subsidy will be forthcoming), a project will proceed through the following broad steps:
• Perform detail costing and re-run cost-benefit analysis if detail costs exceed those used for investment analysis. • Address resource consent, land owner and any Transpower issues. • Perform detail design and prepare drawings, construction specifications and if necessary tender documents. • Tender out or Assign construction. • Close out and de-brief project after construction. • Ensure that contractors pass all necessary information back to OtagoNet including as-builts and commissioning records. • Ensure that learning experiences are examined, captured and embedded into PowerNet’s culture. 4.8 Development programme
4.8.1 Current projects [Addresses handbook requirement 4.5.5(g)(i)] Expected projects for year one (YE 31 March 2012) are as follows. These projects have a high certainty.
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4.8.1.1 Milton 33kV line o Description Continue rebuilding the North Balclutha – Glenore – Kiness – Elderlee Street (Western) 33kV line to the same capacity as the North Balclutha – Elderlee Street (Eastern) 33kV line to provide N-1 33kV supply to those substations. Design the final stages of the line and obtain easements and agreements where necessary from local land owners, Transit and the Clutha District Council. Increase the construction rate to complete the line by 31 March 2014. o Issues Obtain land owner approval for crossing private land and Transit approval for section from North Balclutha adjacent to state highway 1. Cost of the project and priority compared to other renewal projects. o Options
• Consider alternative routes where there may be significant land owner issues, but final route must be the most cost effective. o Cost and type $2.5M to $5M, System Growth. o Goal / Strategy Achieve 100% regulatory compliance. Minimise the security risk for the Milton area and complete the project within three years.
4.8.1.1 Milburn Substation for increased loads o Description Provide a new zone substation adjacent to the new Southern Cross Forest Products timber mill in Milburn. This new substation will off load the Elderlee Street substation and provide significant load transfer capabilities for both Elderlee Street and Waihola substations to extend their fives and improve fault restoration times. o Issues Obtain new designs and equipment in an appropriate time for the new customer. Consider the ultimate configuration of the Milton 33kV ring supply and requirements at the Elderlee Street substation. Consider the initial configuration for Milburn with a single transformer and half 11kV board until load grows further. Routing of new or replacement feeders that could be used to supply the Waihola load and eliminate that zone substation. o Options
• Consider extent and size of the new Milburn substation, 1 or 2 transformer options with more feeder circuit breakers and 33kV feeder arrangements. o Cost and type $2.5M to $5M, System Growth. o Goal / Strategy Achieve 100% regulatory compliance and Minimise the security risk for the Milton area. Have supply available in time to meet customer’s requirements.
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4.8.1.2 Paerau and Wedderburn Transformers o Description Replace these two ageing 1MVA off load tap transformers and associated separate voltage regulators o Issues Paerau has voltage regulation from a 33kV regulator at Patearoa, which also is ageing and requires future replacement, regulation at Paerau should be considered now for greater efficiency. Wedderburn has two single phase 33kV regulators to maintain the voltage; a transformer with regulation could free these units to replace other ageing regulators. o Options There are no alternative 11kV feeds and little option other than deferment of the project and risk premature failure and resulting extended outages. o Cost and type Under $0.5M for each project, Asset Replacement and Renewal o Goal / Strategy Achieve 100% regulatory compliance and Minimise the security risk for the areas supplied. Complete the project during 2011.
4.8.1.3 Waipiata Transformer and Switchgear o Description Replace these ageing 1.5 MVA transformer with 2.5 MVA to allow ongoing load growth and transfer of load from Patearoa. Provide separate circuit breakers for the three 11kV feeders that presently have only one circuit breaker and three sets of fuses. Use 11kV indoor switchgear and remove the old 11kV structure, utilise existing building if suitable switchgear is available. o Issues Ageing transformer and 11kV switching structure. Capacity of the existing transformer and increasing irrigation loads in the area. Increasing loads in the adjacent Patearoa Substation that can be shared by Waipiata. Large customer numbers interrupted by the single circuit breaker for any line fault. o Options Replace the transformer only to address the future loading and old transformer. Upgrade Patearoa substation from 2.5 to 5MVA and transfer load away from Waipiata Install 11kV switchgear only to address one aspect of reliability. o Cost and type $0.5M to $2.5M for each project, System Growth o Goal / Strategy Achieve 100% regulatory compliance. Allow for load growth and load transfer. Minimise the effect of single faults to improve the security. Complete the project during 2011. Asset Management Plan Page 77 of 151
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4.8.1.4 Glenore Transformer and Oil Containment o Description Replace the ageing 1.5 MVA transformer with a standard 2.5 MVA to allow ongoing load growth in the area and load transfers to Milton, Kaitangata and Lawrence. Review the seismic restraint of all equipment and provide oil bunding as this substation is beside a small river and the consequences of an oil spill are severe. o Issues Ageing transformer and associated 11 kV switching structure. Capacity of the existing transformer and increasing irrigation loads in the area. Increasing loads in the adjacent Substations that can be shared by Glenore. o Options Replace the transformer with 1.5 MVA only and replace it early in the transformer’s life and during the 10 year planning period. Upgrade the interconnecting 11 kV lines from Lawrence, Milton and Kaitangata and provide additional voltage regulation. o Cost and type $0.5M to $2.5M, Asset Replacement and Renewal o Goal / Strategy Achieve 100% regulatory compliance. Allow for load growth and load transfer. Minimise the risk of oil contamination of the environment. Complete the project by 31 March 2012.
4.8.1.5 Spare 2.5 MVA Transformer o Description Purchase a system spare 2.5 MVA transformer that can be transported to and used in an emergency at any of the 22 zone substations in OtagoNet that have single 33/11 kV transformer arrangements at present. A modern transformer will be lighter and more compact making relocation simpler and quicker than for the older tall and heavy units presently being replaced. The transformer will be set up to be self contained and quick to install at its required location. The transformer should be stored at the substation most likely to require increased transformer capacity within the planning period, Clinton or Clydevale, it should be properly installed with full seismic restraint and oil bunding to reduce risk of contamination or loss. o Issues Ageing transformer and associated risk of single transformer installations. Ease of access and movement of older transformers where they might be available. o Options Keep and refurbish one of the old and deteriorating transformers removed from one of the previous projects. o Cost and type Under $0.5M, Reliability, Safety and Environment
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o Goal / Strategy Achieve 100% regulatory compliance. Allow for load growth and load transfer. Minimise the risk of oil contamination of the environment. Complete the project by 31 March 2012. 4.8.1.6 Quality Remedies o Description Projects to remedy poor power quality. o Issues Voltage is measured (or calculated to verify) outside of regulatory limits. o Options Each of the below options / situations are considered and an appropriate solution implemented.
• Installation of 11kV regulators. • Up-sizing of components (Conductor, Transformer). • Demand side management. (Planning an Irrigation channel.) • Power factor improvements. (Ensuring consumer loads are operating effectively.) • Harmonic filtering / blocking. (Ensuring consumers are not injecting harmonics.) • Motor starter faults / settings remedied. (Ensuring consumer equipment is working and configured appropriately.) o Cost and type Under $0.5M pa on-going, System Growth. o Goal / Strategy Achieve 100% regulatory compliance and eliminate voltage complaints where the network can be modelled. 4.8.1.7 New connections o Description Allowance for new connections to the network. Each specific solution will depend on location and consumer requirements. Some subdivision developments are occurring but we receive little or no prior notification of these. Request to Developers and Regional Authorities provided only minimal information on subdivisions occurring. An estimated allowance based on past experience and projected development has been included in the plan. An allowance has been made to connect Distributed Generation to the network as the proposed regulations have this as an OtagoNet’s cost. o Issues New consumers wanting connection to the network. o Options Vary due to consumer type and location. o Cost and type $0.5M to $2.5M pa, Customer Connection. o Goal / Strategy Undertake new investments, which are ‘core business’, acceptable return for risk involved.
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4.8.1.8 Reliability and Safety Projects o Description Works to improve the reliability and safety of the network. o Issues Safety issues are identified from the on-going pole and line condition survey Poorly performing feeders and consumer groups with high SAIDI and SAIFI. o Options
• Replacement of poles and wires. • Additional isolation devices to segregate feeders into shorter sections. • Installation of Surge Divertors to diminish impact of lightning and surges. • Use of temporary generators to restore supply. o Cost and type Under $0.5M pa. Reliability. o Goal / Strategy Eliminate any known safety concerns. Minimise outages caused by premature failure of line components. Continue to expand the meshed area of the network, by closing gaps between radial feeders. Provide its customers with above average levels of service.
4.8.2 Planned projects [Addresses handbook requirement 4.5.5(g)(ii)] Expected projects for year two to five (YE 31 March 2013 to 2016) are as follows. These projects have some certainty. Note some projects are planned to start in year one and continue over following years, these are not repeated in following sections. 4.8.2.1 Palmerston to Merton 33 kV Line o Description Consider the second 33 kV line from Palmerston to Merton. This project was started a number of years ago but put on hold while the possibility of purchasing the Transpower 110 kV lines and use at 33 kV from Halfway Bush was investigated. The 110 kV line purchase did not progress as the load at Palmerston was temporarily increased to feed Oceana Gold’s underground mine at Golden Point. The mine now is investigating upgrading their 66 kV supply which would release the 33 kV Golden Point supply, making the 33 kV supply from Halfway Bush viable once again. This project will lead into the future replacement of the Merton Substation for improved capacity and reliability with dual 33 kV feeds. o Issues Supply reliability and efficiency and cost of the Transpower Palmerston supply and OtagoNet’s 33 kV lines back to Merton and Waitati substations. Obtaining Transpower agreement to permanently transfer the existing 110 kV lines as a shorter term will not be acceptable to OtagoNet. o Options Continue with original plans to provide the second 33 kV line from Palmerston.
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o Cost and type $2.5M to $10M depending on the timing and solution, System Growth o Goal / Strategy Achieve 100% regulatory compliance. Continue negotiation with Transpower to arrive at some certainty of project direction by 31 March 2013. 4.8.2.2 Regulator Replacements o Description Replace old regulators at Pukeawa, Deepdell, Oturehua and Waihola. o Issues Service life is reached and quality and reliability are compromised. o Options
• Consider replacing the associated transformers with new transformers incorporating on load tap changers. o Cost and type Under $0.5M, Asset replacement and renewal. o Goal / Strategy Replace critical assets near to the end of their technical life and maintain reliability. 4.8.2.3 11kV Circuit Breaker Replacements o Description Replace outdoor switchgear and structures with indoor switchgear. o Issues Old outdoor structures using wooden poles are at the end of their lives. Some substations have a basic single circuit breaker arrangement and with increasing load and customer numbers a fault affecting all customers is no longer acceptable. o Options
• Rebuild outdoor structures. • Add appropriate circuit breakers to divide customer and load base. o Cost and type Under $0.5M, Reliability. o Goal / Strategy Replace critical assets near to the end of their technical life and enhance reliability.
4.8.3 Considered projects [Addresses handbook requirement 4.5.5(g)(iii)] Expected projects for year six to ten (YE 31 March 2017 to 2021) are as follows. These projects have little if any certainty. Note some projects that are on-going through-out this period are detailed above. 4.8.3.1 33kV Transformer Circuit Breakers o Description Install 33kV circuit breakers to protect larger transformers, 5 MVA initially then 2.5 MVA.
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o Issues Only four out of six 5 MVA transformers have 33kV circuit breakers for transformer protection, the others rely on 33kV fuses only. None of the 15 smaller 2.5 MVA transformers have circuit breakers. Single transformers may be damaged by slow fuse clearing times with little protection for earth faults. Dual transformer sites may be vulnerable to additional damage from back feeding into a transformer fault. o Options
• Install protection relays with inter-trip arrangements to the 33kV source. • Install individual outdoor circuit breakers and protection systems. • Do nothing. o Cost and type Under $2.5M depending on individual solution, Reliability. o Goal / Strategy Protect critical assets and minimise impact of potential faults. 4.8.3.2 Transformer Replacements o Description Before the end of the planning period five 2.5 MVA will have reached then end of their economic life at Patearoa, Clinton, Finegand, Waitati, and Owaka plus a 1 MVA transformer at Oturehua. o Issues Replace aging transformers and consider optimum voltage regulating configurations. o Options
• Refurbish transformers. • Defer replacement based on condition assessment. o Cost and type Under $0.5M Asset replacement and renewal. o Goal / Strategy Replace critical assets near to but before the end of their technical life and enhance reliability.
4.8.4 Contingent projects The following projects are contingent on uncertain events. These have been excluded from OtagoNet’s spend plans until they become certain. 4.8.4.1 Mount Stewart Wind Farm Connection Consent has been approved for a 7 MW wind farm on Mount Stewart, and the project has been transferred to Pioneer Generation. They are indicating the project will proceed in 2011/12 but OtagoNet is only just pricing the work and commissioning additional system studies. If the project goes ahead there will be little impact on the network (there is sufficient capacity), or financial cost as connection will be paid by the generator and the connection will be simple requiring minimal OPSL contractor resources.
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4.8.4.2 Ranfurly – Deepdell 66kV upgrade Oceana Gold, through OtagoNet, has commissioned a study to reconductor the 66 kV line to provide additional capacity to the mine and reduce electrical losses. At this stage only outside consultants are involved in the feasibility and line design considerations and any likely outcome would likely involve a large and experienced contractor to manage the complete project. 4.8.4.3 Balclutha Main Street Undergrounding for the Clutha District Council OtagoNet has had enquiries from the local Council on the cost to underground the main low voltage lines along Clyde Street from the Bridge to Gordon Street. Options and suggestions will be developed for the Council to consider. As a largely customer initiated project this work should have little financial impact on OtagoNet and much of the installation work will be by outside civil contractors, again with little impact on OtagoNet or OPSL.
4.8.5 Capital Budget The estimated capital budget for OtagoNet is given below in Table 28 - Capital Budget (Years 2011 to 2016) and Table 29 - Capital Budget (Years 2016 to 2021). Table 28 - Capital Budget (Years 2011 to 2016)
Project 2011/12 2012/13 2013/14 2014/15 2015/16 Asset Replacement and Renewal Akatore Bull Creek spur lines 115,000 Anderson Rd Bobbys Head Palm 50,000 Arran St Tokoiti Spur Line 41,000 Ashley Downs ER, Waiwera South Athenaeum Rd Craigellachie Balclutha area upgrade SCADA radio system 20,000 Balclutha Urban 11kV Lines 734,000 Barrata Creek Rd Port Molyneux Barrs Falls Rd - Chaslands Hwy Refurbishment 30,000 Benhar 11kV Spans 31,000 Berwick 11kV 176,000 Blackburn & Gordon Rds Hillend 230,400 Bloy Rd Lawrence Braeside - McKnight 44,000 Brooklands Rd Goodwood Sett Rd 143,000 Brooklands Rd, Goodwood 125,000 Bush Gully Road, Tokoiti 100,000 Bush Rd Tuapeka West - 2 stages 519,000 519,000 Camp Hill Rd Rongahere Chrystalls Beach E/R Lines 470,000 Circuit Breaker replacements and upgrades 300,000 300,000 Clarke Rd Wairuna 60,000 Clarkesville Spurs 33,000 Clifton/Totara E/R 99,000 Clinton 2.5 MVA transformer replacement 350,000 Cockshell Rd Evans Flat Coe Rd SH-1 Lovells Flat 175,000 Cowan Rd Round Hill Croydon Rd - 2w 11kV 145,000 Danseys Pass - E/R Circuit 250,000 Devon Sharkey Rds Gimmerburn 140,000 Distribution Minor Capital Work 120,000 120,000 120,000 120,000 120,000 Doctors Point Rd 18,000 Dodd's Rd Slopedown 131,000 Dumfrise Rd Taumata 380,000 Estate Rd, Clinton 42,000 Farm Rd, Mmarch (Sutton Fdr) 128,000 Farquhar Rd SWER Owaka Valley 335,000 Finegand 2.5 MVA transformer replacement Freezing Works Rd Spur: Kakapu 41,000 Glenelg Rd, Lochindorb 452,000 Glenledi E/R Lines Glenomaru Valley Rd Spur Lines Asset Management Plan Page 83 of 151
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Project 2011/12 2012/13 2013/14 2014/15 2015/16 Glenore 2.5 MVA transformer 500,000 Greenfield Rd 11kV 161,000 Greenfield Rd Greenfield 196,000 Greenfield Spur Lines Ground Sub Refurbishments 25,000 25,000 25,000 25,000 25,000 Hadfield -Puketi Rd Greenfield 227,000 Heywards Point E/R 256,000 Hills Creek 52,000 Hindon 22kV: Mt Allen Line 91,000 Hindon 22kV: Mt Stoker Part 2 400,000 Hindon 22kV: Wehenga Rd Hindon 450,000 Horse Range E/R - End of Lines 174,000 Horse Range E/R - Part 1 188,000 Horseburn Rd E/R Tiroiti 154,000 Hughes Rd Palmerston 54,000 Hummock 3phase, Waikouaiti 255,000 Hunt Rd Katea Second Section Hunt Rd, Katea 11kV 77,000 Hyde - Macraes Rd spur line 194,000 Hyde - Rock & Pillar 11kV 62,000 John OGroats Rd Rongahere SWER 422,000 Kilmog Fdr - Stage 1a & 1b 329,000 Kilmog Feeder Stage 2011-12 410,000 Lambourne Rd Clydevale 90,000 Lawrence Rd Crescent 43,000 Laws Rd Gimmerburn 72,000 Lime Springs Rd, Clarendon Limeworks & Dunback footbridge, Dunback 87,500 Lochindorb 11kV E/R 486,000 Lochindorb Runs Rd Owaka Valle 458,000 Lower Kyeburn river crossing - Stage 1 first half 362,500 MacLennan - Papatowai Lines Matanaka Rd Waikouaiti 47,000 McHardy Rd, Sutton 353,000 McKinnon Rd Mmarch 2w 11kV 90,000 McLachlan Rd Karitane 58,000 Merton Substation rebuild and relocation 600,000 1,000,000 600,000 Mill View Rd Tuapeka West 187,000 Milton/Tokoiti Urban 11kV Line 256,000 Morrisons E/R Stage 3 245,000 Mount Mistake Rd Wairuna 245,000 Mowat Rd Clydevale 209,000 Mt Cargill Rd 11kV 41,000 Mt Cooe - Stirling straight Murray Rd Tuapeka Flat Narrowdale Rd Milton 10,000 Network Chargeable Capital 60,000 60,000 60,000 60,000 60,000 Newhaven Rd Owaka 131,000 Ngapuna - SH87 spurs 176,000 North Balclutha replace ripple plant 180,000 Nugget Pt Lighthouse 215,000 Nugget Stream Rd E/R Round Hil 157,500 Old Balclutha Hospital 11kV 33,750 Old Coach Rd Clinton 250,000 Ongoing Line Replacement and Renewall - part year 480,000 Ongoing Line Replacement and Renewall Balclutha - part year Ongoing Line Replacement and Renewall Balclutha - per year Ongoing Line Replacement and Renewall Palmerston - per year Ongoing Line Replacement and Renewall Ranfurly - per year 780,000 780,000 Orokonui & Mt Cargill Waitati 121,000 Oturehua 1.0 MVA transformer replacement Oturehua 33kV regulator replacement 150,000 Owaka 2.5 MVA transformer replacement Paerau 1MVA transformer - carry over 180,000 Palmerston Spurs (Pal) 120,000 Pannets Rd Wharetoa Pateraoa 2.5 MVA transformer replacement 350,000 Polsons Rd Waitahuna 396,000
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Project 2011/12 2012/13 2013/14 2014/15 2015/16 Port Molyneux - near Sub 31,000 Protection Upgrades 50,000 50,000 50,000 50,000 Pryde Rd Kilmog Feeder 94,000 Puerua SWER: Part A 448,000 Puerua SWER: Part B 413,000 Pukeawa & Deepdell 11 kV Regulator replacements 200,000 Puketapu Rd Bushey Palmerston 85,000 Puketi E/R - Stage 2 690,000 Puketi E/R Lines Stage 1 Puketi E/R Pt 3: Breakneck Rd 499,000 Purakanui LT ABC Stage 3 330,000 Purakanui SWER: Part A 320,000 Purakauiti SWER: Part B 579,000 Radio repeater site SCADA RTUs 15,000 Ranfurly - spur to Tx3277 86,000 Ranfurly Spur Lines 257,000 Ranfurly Urban 11kV Line 187,000 Rankleburn SWER line 337,500 Ritchie Rd, Dunback 150,000 Roberts Rd Waipiata 265,000 Runbrake St Palmerston 47,000 SH 87 Kyeburn 242,000 SH1 Balclutha Spur 19,000 SH1 Clinton 155,000 SH-1 North Clinton - Spur Line 29,000 SH-8 Beaumont - Raes Junction Shag Point - Divert 11kV - carry over 50,000 Shag Valley - Spur line 42,000 Soaper Rd Te Houka 201,600 Spur - Bruce Rd Milton Spur lines Finegand/Romahapa - 2 stages 340,000 340,000 Spur Lines Ranfurly North (Ran) 60,000 Spur to Tx 21310, Hislop Rd 29,000 Spur to TX 315 (Ran) 50,000 Spur to TX 3767 (Ran) 45,000 Spurs - Clinton (Clydevale Rd) Stoneburn 11kV E/R Stage 2 - carry over 50,000 Storer Rd Stirling Substation outdoor bus upgrade / replacement 300,000 300,000 Substations minor capital work 20,000 20,000 20,000 20,000 20,000 Summerhill Rd Wangaloa 611,000 Sweetwater Creek Rd Shag Vlly 55,000 Table Hill - SWER Lines Tahakopa Valley Titri Rd, Waihola 223,000 Toiro Rd Shaws Track Warepa 61,000 Toko Mouth - Coastal SWER Line Transformer or Regulator Replacements Tx 2589 - Clutha Leader Tx 116,000 Waihola 11 kV regulator replacement 100,000 Waihola Sub TaieriMouth Feeder 187,000 Waikouiti Township 11kV 376,000 Waitati 2.5 MVA transformer replacement Waitati Valley Main Line 208,000 Waiwera Station Rd Rebuild 2 wire line 155,000 Ward Rd Otekura Warrington Spur Lines 274,000 Wedderburn 1MVA transformer - carry over 180,000 Wharetoa Rd Clydevale White Sow Valley 80,000 Whiteside Rd Wairuna 99,000 Asset Replacement and Renewal Total 6,358,350 5,695,400 7,536,000 6,760,000 6,405,000
Customer Connections External customer chargeable 6,000 6,000 6,000 6,000 6,000 New Connections 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 Customer Connections Total 1,006,000 1,006,000 1,006,000 1,006,000 1,006,000
Reliability, Safety and Environment Frasers - James Street Tx 2592 136,600 Ground Sub 11kV Cable replacements 10,000 10,000 10,000 10,000 10,000
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Project 2011/12 2012/13 2013/14 2014/15 2015/16 Palmerston Transpower 33 kV feeder alteration + 500,000 300,000 Palmerston line Patearoa oil containment and seismic restraint - carry over 50,000 Recloser upgrades for SCADA control and new reclosers 70,000 100,000 100,000 100,000 100,000 Replacement of O/H structures with Ground Subs 120,000 120,000 120,000 120,000 120,000 Spare transportable 2.5 MVA transformer (install at Clinton) 300,000 Stirling 11 kV protection relays 30,000 Stirling 11kV switchgear convert secondary contacts 15,000 Upgrade outdoor CB stands for seismic strength 20,000 20,000 Reliability, Safety and Environment Total 751,600 250,000 730,000 530,000 230,000
System Growth Awamunga: E/R to 2ph Upgrade 592,000 Burning Plains Rd Popotunoa 253,000 Catlins Valley Rd Houipapa Tie line 126,000 Clutha River Rd Rongahere 182,000 Easements 9,000 9,000 9,000 9,000 9,000 Hillfoot Rd Clinton 253,000 Jacks Bay - Upgrade to 3ph Karoro Creek - New Tie line Milburn Substation, transformer and switchgear 1,920,000 Milton 33/66kV Line Stage 2 600,000 600,000 600,000 Misc. Quality of Supply Upgrades 120,000 120,000 120,000 120,000 120,000 Morven Rd, Slopedown 2W conversion 385,000 Ongoing Load Growth Balclutha - part year Ongoing Load Growth Balclutha - per year Ongoing Load Growth Palmerston - part year 300,000 300,000 Ongoing Load growth Palmerston - per year Ongoing Load Growth work Ranfurly - per year 300,000 300,000 Owaka township 11kV 180,000 Palmerston - Merton 2nd 33kV 200,000 Pukeawa - Clydevale 11kV 254,000 Substation & feeder half hour metering 25,000 35,000 45,000 Tahakopa 11kV Feeder - Part 2 487,500 488,000 Tahakopa Feeder - Part 3 360,000 Waipiata 11kV switchgear & 2.5 MVA Tx - carry over 650,000 Waiwera Station Rebuild SWER lines 345,000 System Growth Total 3,811,500 2,308,000 1,209,000 1,416,000 1,681,000 Grand Total 11,927,450 9,259,400 10,481,000 9,712,000 9,322,000
Table 29 - Capital Budget (Years 2016 to 2021)
Project 2016/17 2017/18 2018/19 2019/20 2020/21 Asset Replacement and Renewal Akatore Bull Creek spur lines Anderson Rd Bobbys Head Palm Arran St Tokoiti Spur Line Ashley Downs ER, Waiwera South 436,000 Athenaeum Rd Craigellachie 61,000 Balclutha area upgrade SCADA radio system Balclutha Urban 11kV Lines Barrata Creek Rd Port Molyneux 274,000 Barrs Falls Rd - Chaslands Hwy Refurbishment Benhar 11kV Spans Berwick 11kV Blackburn & Gordon Rds Hillend Bloy Rd Lawrence 40,000 Braeside - McKnight Brooklands Rd Goodwood Sett Rd Brooklands Rd, Goodwood Bush Gully Road, Tokoiti Bush Rd Tuapeka West - 2 stages Camp Hill Rd Rongahere 331,000 Chrystalls Beach E/R Lines Circuit Breaker replacements and upgrades 300,000 300,000 300,000 300,000 300,000 Clarke Rd Wairuna Clarkesville Spurs Clifton/Totara E/R Clinton 2.5 MVA transformer replacement Cockshell Rd Evans Flat 37,000 Asset Management Plan Page 86 of 151
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Project 2016/17 2017/18 2018/19 2019/20 2020/21 Coe Rd SH-1 Lovells Flat Cowan Rd Round Hill 52,000 Croydon Rd - 2w 11kV Danseys Pass - E/R Circuit Devon Sharkey Rds Gimmerburn Distribution Minor Capital Work 120,000 120,000 120,000 120,000 120,000 Doctors Point Rd Dodd's Rd Slopedown Dumfrise Rd Taumata Estate Rd, Clinton Farm Rd, Mmarch (Sutton Fdr) Farquhar Rd SWER Owaka Valley Finegand 2.5 MVA transformer replacement 350,000 Freezing Works Rd Spur: Kakapu Glenelg Rd, Lochindorb Glenledi E/R Lines 531,000 Glenomaru Valley Rd Spur Lines 241,000 Glenore 2.5 MVA transformer Greenfield Rd 11kV Greenfield Rd Greenfield Greenfield Spur Lines 197,000 Ground Sub Refurbishments 25,000 25,000 25,000 25,000 25,000 Hadfield -Puketi Rd Greenfield Heywards Point E/R Hills Creek Hindon 22kV: Mt Allen Line Hindon 22kV: Mt Stoker Part 2 Hindon 22kV: Wehenga Rd Hindon Horse Range E/R - End of Lines Horse Range E/R - Part 1 Horseburn Rd E/R Tiroiti Hughes Rd Palmerston Hummock 3phase, Waikouaiti Hunt Rd Katea Second Section 517,000 Hunt Rd, Katea 11kV Hyde - Macraes Rd spur line Hyde - Rock & Pillar 11kV John OGroats Rd Rongahere SWER Kilmog Fdr - Stage 1a & 1b Kilmog Feeder Stage 2011-12 Lambourne Rd Clydevale Lawrence Rd Crescent Laws Rd Gimmerburn Lime Springs Rd, Clarendon 38,000 Limeworks & Dunback footbridge, Dunback Lochindorb 11kV E/R Lochindorb Runs Rd Owaka Valle Lower Kyeburn river crossing - Stage 1 first half MacLennan - Papatowai Lines 305,000 Matanaka Rd Waikouaiti McHardy Rd, Sutton McKinnon Rd Mmarch 2w 11kV McLachlan Rd Karitane Merton Substation rebuild and relocation Mill View Rd Tuapeka West Milton/Tokoiti Urban 11kV Line Morrisons E/R Stage 3 Mount Mistake Rd Wairuna Mowat Rd Clydevale Mt Cargill Rd 11kV Mt Cooe - Stirling straight 98,000 Murray Rd Tuapeka Flat 41,000 Narrowdale Rd Milton Network Chargeable Capital 60,000 60,000 60,000 60,000 60,000 Newhaven Rd Owaka Ngapuna - SH87 spurs North Balclutha replace ripple plant Nugget Pt Lighthouse Nugget Stream Rd E/R Round Hil Old Balclutha Hospital 11kV Old Coach Rd Clinton
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Project 2016/17 2017/18 2018/19 2019/20 2020/21 Ongoing Line Replacement and Renewall - part year Ongoing Line Replacement and Renewall Balclutha - part 300,000 year Ongoing Line Replacement and Renewall Balclutha - per 2,820,000 2,820,000 2,820,000 year Ongoing Line Replacement and Renewall Palmerston - per 840,000 840,000 840,000 840,000 840,000 year Ongoing Line Replacement and Renewall Ranfurly - per year 780,000 780,000 780,000 780,000 780,000 Orokonui & Mt Cargill Waitati Oturehua 1.0 MVA transformer replacement 250,000 Oturehua 33kV regulator replacement Owaka 2.5 MVA transformer replacement 350,000 Paerau 1MVA transformer - carry over Palmerston Spurs (Pal) Pannets Rd Wharetoa 366,000 Pateraoa 2.5 MVA transformer replacement Polsons Rd Waitahuna Port Molyneux - near Sub Protection Upgrades 50,000 50,000 50,000 50,000 50,000 Pryde Rd Kilmog Feeder Puerua SWER: Part A Puerua SWER: Part B Pukeawa & Deepdell 11 kV Regulator replacements Puketapu Rd Bushey Palmerston Puketi E/R - Stage 2 Puketi E/R Lines Stage 1 584,000 Puketi E/R Pt 3: Breakneck Rd Purakanui LT ABC Stage 3 Purakanui SWER: Part A Purakauiti SWER: Part B Radio repeater site SCADA RTUs Ranfurly - spur to Tx3277 Ranfurly Spur Lines Ranfurly Urban 11kV Line Rankleburn SWER line Ritchie Rd, Dunback Roberts Rd Waipiata Runbrake St Palmerston SH 87 Kyeburn SH1 Balclutha Spur SH1 Clinton SH-1 North Clinton - Spur Line SH-8 Beaumont - Raes Junction 144,000 Shag Point - Divert 11kV - carry over Shag Valley - Spur line Soaper Rd Te Houka Spur - Bruce Rd Milton 33,000 Spur lines Finegand/Romahapa - 2 stages Spur Lines Ranfurly North (Ran) Spur to Tx 21310, Hislop Rd Spur to TX 315 (Ran) Spur to TX 3767 (Ran) Spurs - Clinton (Clydevale Rd) 159,000 Stoneburn 11kV E/R Stage 2 - carry over Storer Rd Stirling 90,000 Substation outdoor bus upgrade / replacement 300,000 300,000 300,000 300,000 300,000 Substations minor capital work 20,000 20,000 20,000 20,000 20,000 Summerhill Rd Wangaloa Sweetwater Creek Rd Shag Vlly Table Hill - SWER Lines 414,000 Tahakopa Valley 729,000 Titri Rd, Waihola Toiro Rd Shaws Track Warepa Toko Mouth - Coastal SWER Line 420,000 Transformer or Regulator Replacements 600,000 600,000 600,000 Tx 2589 - Clutha Leader Tx Waihola 11 kV regulator replacement Waihola Sub TaieriMouth Feeder Waikouiti Township 11kV Waitati 2.5 MVA transformer replacement 350,000 Waitati Valley Main Line
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Project 2016/17 2017/18 2018/19 2019/20 2020/21 Waiwera Station Rd Rebuild 2 wire line Ward Rd Otekura 65,000 Warrington Spur Lines Wedderburn 1MVA transformer - carry over Wharetoa Rd Clydevale 175,000 White Sow Valley Whiteside Rd Wairuna Asset Replacement and Renewal Total 6,721,000 6,247,000 5,915,000 5,915,000 5,915,000
Customer Connections External customer chargeable 6,000 6,000 6,000 6,000 6,000 New Connections 1,000,000 1,000,000 1,000,000 1,000,000 1,000,000 Customer Connections Total 1,006,000 1,006,000 1,006,000 1,006,000 1,006,000
Reliability, Safety and Environment Frasers - James Street Tx 2592 Ground Sub 11kV Cable replacements 10,000 10,000 10,000 10,000 10,000 Palmerston Transpower 33 kV feeder alteration + Palmerston line Patearoa oil containment and seismic restraint - carry over Recloser upgrades for SCADA control and new reclosers 100,000 100,000 100,000 100,000 100,000 Replacement of O/H structures with Ground Subs 120,000 120,000 120,000 120,000 120,000 Spare transportable 2.5 MVA transformer (install at Clinton) Stirling 11 kV protection relays Stirling 11kV switchgear convert secondary contacts Upgrade outdoor CB stands for seismic strength Reliability, Safety and Environment Total 230,000 230,000 230,000 230,000 230,000
System Growth Awamunga: E/R to 2ph Upgrade Burning Plains Rd Popotunoa Catlins Valley Rd Houipapa Tie line Clutha River Rd Rongahere Easements 9,000 9,000 9,000 9,000 9,000 Hillfoot Rd Clinton Jacks Bay - Upgrade to 3ph 339,000 Karoro Creek - New Tie line 420,000 Milburn Substation, transformer and switchgear Milton 33/66kV Line Stage 2 Misc. Quality of Supply Upgrades 120,000 120,000 120,000 120,000 120,000 Morven Rd, Slopedown 2W conversion Ongoing Load Growth Balclutha - part year 300,000 Ongoing Load Growth Balclutha - per year 900,000 900,000 900,000 Ongoing Load Growth Palmerston - part year Ongoing Load growth Palmerston - per year 240,000 240,000 240,000 240,000 240,000 Ongoing Load Growth work Ranfurly - per year 300,000 300,000 300,000 300,000 300,000 Owaka township 11kV Palmerston - Merton 2nd 33kV Pukeawa - Clydevale 11kV Substation & feeder half hour metering Tahakopa 11kV Feeder - Part 2 Tahakopa Feeder - Part 3 Waipiata 11kV switchgear & 2.5 MVA Tx - carry over Waiwera Station Rebuild SWER lines System Growth Total 1,008,000 1,389,000 1,569,000 1,569,000 1,569,000 Grand Total 8,965,000 8,872,000 8,720,000 8,720,000 8,720,000
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5. Managing the assets’ lifecycle
All physical assets have a lifecycle. This section describes how OtagoNet manages assets over their entire lifecycle from “commissioning” to “retirement”. 5.1 Lifecycle of the assets The lifecycle of OtagoNet’s existing assets is outlined in Figure 23 below:
Start here with existing asset base
Yes
Make Are any operational operational triggers adjustments exceeded ??
No
Yes Are any Perform maintenance triggers maintenance exceeded ??
No
Yes
Are any Undertake renewal triggers renewals exceeded ??
No
Yes Are any Add new extension or augmentation capacity triggers exceeded ??
No
Yes
Are any Retire retirement triggers assets exceeded ??
No
Figure 23 - Asset lifecycle
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Table 30 below provides some definitions for key lifecycle activities: Table 30 – Definition of key lifecycle activities
Activity Detailed definition Operations Involves altering the operating parameters of an asset such as closing a switch or altering a voltage setting. Doesn’t involve any physical change to the asset, simply a change to the assets configuration that it was designed for. In the case of electrical assets it will often involve doing nothing and just letting the electricity flow. Maintenance Involves replacing consumable components like the seals in a pump, the oil in a transformer or the contacts in a circuit breaker. Generally these components will be designed to wear out many times over the assets design lifecycle and continued operation of the asset will require such replacement. There may be a significant asymmetry associated with consumables such as lubricants in that replacing a lubricant may not significantly extend the life of an asset but not replacing a lubricant could significantly shorten the assets life. Renewal Generally involves replacing a non-consumable item like the housing of a pump with a replacement item of identical functionality (usually capacity). Such replacement is generally regarded as a significant mile-stone in the life of the asset and may significantly extend the life of the asset (a bit like “Grandpa’s axe”). Renewal tends to dominate the Capital expenditure in low growth areas (Quadrant 1 of Figure 20) because assets will generally wear out before they become too small. The most typical criteria for renewal will be when the capitalised costs of ops and maintenance exceed the cost of renewal. A key issue with renewal is technological advances that generally make it impossible to replace assets such as SCADA with equivalent functionality. Up-sizing Generally involves replacing a non-consumable item like a conductor, busbar or transformer with a similar item of greater capacity but which does not increase the network footprint i.e. restricted to Quadrants 1 and 2 in Figure 20. Extensions Involves building a new asset where none previously existed because a location trigger in Table 21 has been exceeded e.g. building several spans of line to connect a new factory to an existing line. This activity falls within Quadrants 3 and 4 of Figure 20. Notwithstanding any surplus capacity in upstream assets, extensions will ultimately require up-sizing of upstream assets. Retirement Generally involves removing an asset from service and disposing of it. Typical guidelines for retirement will be when an asset is no longer required, creates an unacceptable risk exposure or when its costs exceed its revenue.
5.2 Operating OtagoNet’s assets As outlined in Table 30 operations predominantly involves changing equipment configuration and maintaining good electricity flow from the GXP’s to customers’ premises year after year with occasional intervention when a trigger point is exceeded. As outlined in Figure 23 the first efforts to relieve excursions beyond trigger points are operational activities with typical activities listed in Table 31.
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Table 31 Typical responses to operational triggers
Asset class Trigger event Response to event Approach GXP Voltage is too high or Automatic operation of tap Reactive low on 33kV or 11kV. changer. Demand exceeds Activate ripple injection plant to Reactive allocated Transpower switch off load control relays. limit. Move Zone Substations Reactive between GXP’s to relieve load from highly loaded GXP. Transition from day to Activate ripple injection plant to Proactive night. switch street lights on or off. On-set of off-peak tariff Activate ripple injection plant to Proactive periods. switch controlled loads on or off. Zone substation Voltage is too high or Automatic operation of tap Reactive transformers low on 11kV. changer. Demand exceeds Move tie points to relieve load Reactive rating. from zone sub. Distribution reclosers Fault current exceeds Automatic operation of recloser. Reactive threshold. Distribution ABS’s Component current Open & close ABS’s to shift Proactive rating exceeded. load. or reactive Fault has occurred. Open & close ABS’s to restore Reactive supply. Distribution Voltage is too high or Manually raise or lower tap Reactive transformers low on LV. where fitted. Fuses keep blowing. Shift load to other transformers Reactive by cutting and reconnecting LV jumpers. LV distribution Voltage is too low at Supply from closer transformer Reactive customers’ board. if possibly by cutting and reconnecting LV jumpers.
Table 32 outlines the key operational triggers for each class of OtagoNet’s assets. Note that whilst temperature triggers will usually follow demand triggers, they may not always e.g. an overhead conductor joint might get hot because it is loose or rusty rather than overloaded. Table 32 - Operational triggers
Asset category Voltage trigger Demand trigger Temperature trigger LV lines and cables Voltage routinely drops Customers’ pole or Infra-red survey too low to maintain at pillar fuse blows reveals hot joint. least 0.94pu at repeatedly. customers switchboards. Voltage routinely rises too high to maintain no more than 1.06pu at customers switchboards.
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Asset category Voltage trigger Demand trigger Temperature trigger Distribution Voltage routinely drops Load routinely Infra-red survey substations too low to maintain at exceeds rating where reveals hot least 0.94pu at MDI’s are fitted. connections. customers LV fuse blows switchboards. repeatedly. Voltage routinely rises Short term loading too high to maintain no exceeds guidelines in more than 1.06pu at IEC 354. customers switchboards. Distribution lines and Alarm from SCADA Infra-red survey cables that current has reveals hot joint. exceeded a setpoint. Zone substations Voltage drops below Load exceeds Top oil temperature level at which OLTC guidelines in IEC exceeds can automatically raise 354. manufacturers’ or lower taps. recommendations. Core hot-spot temperature exceeds manufacturers’ recommendations. Subtransmission Alarm from SCADA that Alarm from SCADA Infra-red survey lines and cables voltage is outside of that current is over reveals hot joint. allowable setpoints. allowable setpoint. OtagoNet equipment Alarm from SCADA that Alarm from SCADA Infra-red survey within GXP voltage is outside of that current is over reveals hot joint. allowable setpoints. allowable setpoint.
5.3 Maintaining OtagoNet’s assets [Addresses handbook requirement 4.5.6(a)] As described in Table 30 maintenance is primarily about replacing consumable components. Examples of the way in which consumable components “wear out” include the oxidation or acidifying of insulating oil, pitting or erosion of electrical contacts and wearing of pump seals. Continued operation of such components will eventually lead to failure as indicated in Figure 24 below. Failure of such components is usually based on physical characteristics and exactly what leads to failure may be a complex interaction of parameters such as quality of manufacture, quality of installation, age, operating hours, number of operations, loading cycle, ambient temperature, previous maintenance history and presence of contaminants – note that the horizontal axis in Figure 24 is not simply labelled “time”.
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Figure 24 - Component failure Exactly when maintenance is performed will be determined by the need to avoid failure. For instance the need to avoid failure of a 10kVA transformer supplying a single customer is low; hence it might be operated out to point C in Figure 24 whilst a 66/11kV substation transformer may only be operated to point B due to a higher need to avoid failure. In the extreme case of, say, a transformer supplying a critical facility it would be desirable to avoid even the slightest probability of failure hence the transformer may only be operated to point A. The obvious trade-off with avoiding failure is the increased cost of labour and consumables over the assets lifecycle along with the cost of discarding unused component life. Like all OtagoNet’s other business decisions, maintenance decisions are made on cost-benefit criteria with the principal benefit being avoiding supply interruption. The practical effect of this is that assets supplying large customers or numbers of customers will be extensively condition monitored to avoid supply interruption whilst assets supplying only a few customers such as a 10kVA transformer will more than likely be run to breakdown. The maintenance strategy map in Figure 25 broadly identifies the maintenance strategy adopted for various ratios of costs and benefits.
Figure 25 - Maintenance strategy map
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This map indicates that where the benefits are low (principally there is little need to avoid loss of supply) and the costs of maintenance are relatively high, an asset should be run to breakdown. As the value of an asset and the need to avoid loss of supply both increase, the company relies less and less on easily observable proxies for actual condition (such as calendar age, running hours or number of trips) and more and more on actual component condition (through such means as DGA for transformer oil). Component condition is the key trigger for maintenance; however the precise conditions that trigger maintenance are very broad, ranging from oil acidity to dry rot. Table 33 describes the maintenance triggers adopted: Table 33 - Maintenance triggers
Asset category Components Maintenance trigger LV lines and cables Poles, arms, stays and Evidence of dry-rot. Five yearly inspection bolts Loose bolts, moving stays. Displaced arms. Pins, insulators and Obviously loose pins. binders Visibly chipped or broken insulators. Visibly loose binder. Conductor Visibly splaying or broken conductor. Distribution Poles, arms and bolts Evidence of dry-rot. substations Loose bolts, moving stays. Five yearly inspection Displaced arms. Six monthly for sites Enclosures Visible rust. >150kVA Cracked or broken masonry. Transformer Excessive oil acidity (500kVA or greater). Visible signs of oil leaks. Excessive moisture in breather. Visibly chipped or broken bushings. Switches and fuses Visible rust. Oil colour. Visible signs of oil leak. Distribution lines and Poles, arms, stays and Evidence of dry-rot. cables bolts Loose bolts, moving stays. Five yearly inspection Displaced arms. Pins, insulators and Loose tie wire. binders Chipped or cracked insulator. Conductor Loose or pitted strands. Visible rust. Ground-mounted Visible rust. switches Oil colour. Visible signs of oil leak. Regulators Visible rust. Oil colour. Visible signs of oil leak. Excessive moisture in breather. High Dissolved Gas Analysis results. Zone substations Fences and enclosures Weeds. Monthly checks Visible rust. Gaps in fence. Buildings Flaking paint. Timber rot. Cracked or broken masonry. Bus work and conductors Hot spot detected by Infrared detector. Corrosion of metal or fittings. 33kV switchgear Visible rust. Operational count exceeded. Low oil breakdown.
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Asset category Components Maintenance trigger Transformer Visible rust. High Dissolved Gas Analysis results (Annual test). Low oil breakdown. High oil acidity. 11kV switchgear Visible rust. Operational count exceeded. Low oil breakdown. Instrumentation/protection Maintenance period exceeded. • Electromechanical Possible mal-operation of device. three yearly • Electronic five yearly Batteries Discharge test or Impedance test. Six monthly test Substation- Poles, arms, stays and Evidence of dry-rot. transmission lines bolts Loose bolts, moving stays. and cables Displaced arms. Five yearly inspection Pins, insulators and Loose tie wire. binders Chipped or cracked insulator. Conductor Loose or pitted strands. Visible rust. Cable High Partial discharge detected. Annual check Sheath insulation short. Oil pressure declining. Our equipment within Injection plant Alarm from failure ripple generation. GXP Period exceed for checks. Monthly check Typical maintenance policy responses to these trigger points are described in Table 34. Table 34 Typical responses to maintenance triggers
Asset class Trigger point Response to trigger Approach Subtransmission Loose or displaced Tighten or replace Condition as revealed lines components by annual inspection Rotten or spalled Brace or bandage pole Condition as revealed poles unless renewal is by annual inspection required Cracked or broken Replace as required Breakdown insulator Splaying or broken Repair conductor unless Condition as revealed conductor renewal is required by annual inspection GXP and zone Oil acidity Filter oil Condition as revealed substation by annual test transformers Excessive moisture Filter oil Condition as revealed in breather by monthly inspection Weighted number of Filter oil, possibly de- Event driven through faults tank and refurbish General condition of Repair or replace as Condition as revealed external components required by monthly inspection Distribution lines Loose or displaced Tighten or replace Condition as revealed components by three yearly inspection Rotten or spalled Brace or bandage pole Condition as revealed poles unless renewal is by three yearly required inspection
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Asset class Trigger point Response to trigger Approach Cracked or broken Replace as required Breakdown insulator Splaying or broken Repair conductor unless Condition as revealed conductor renewal is required by three yearly inspection Distribution Weighted number of Repair or replace Event driven reclosers light and heavy faults contacts, filter oil if applicable Distribution Loose or displaced Tighten or replace Condition as revealed ABS’s supporting unless renewal is by three yearly components required inspection Seized or tight Lubricate or replace Breakdown components as required Distribution Loose or displaced Tighten or replace Condition as revealed transformers supporting unless renewal is by three yearly components required inspection Rusty, broken or Make minor repairs Condition as revealed cracked enclosure unless renewal is by three yearly where fitted required inspection Oil acidity Filter oil Remove from service for full overhaul every 15 years Excessive moisture Filter oil Condition as revealed in breather where by three yearly fitted inspection Visible oil leaks Remove to workshop for Condition as revealed repair or renewal if by three yearly serious inspection Chipped or broken Replace Breakdown or condition bushings as revealed by three yearly inspection LV lines Loose or displaced Tighten or replace Breakdown unless components revealed by five yearly inspection Rotten or spalled Brace or bandage pole Five yearly inspection poles unless renewal is required Cracked or broken Replace as required Breakdown unless insulator revealed by five yearly inspection Splaying or broken Repair conductor unless Breakdown unless conductor renewal is required revealed by five yearly inspection
The frequency and nature of the response to each of the above triggers are embodied in OtagoNet’s policies and work plans. 5.3.1.1 Systemic faults There are no present projects investigating systemic failures. Examples of past investigations and outcomes:
• Kidney strain insulators: Replaced with new polymer strains. • DIN LV fuses: Sourced units that can be used outdoor. • Parallel-groove clamps: Replaced with compression joints.
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• Non-UV stabilised insulation: Exposed LV now has sleeve cover, with new cables UV stabilised. • Opossum faults: Extended opossum guard length. 5.3.2 Inspection, monitoring and routine maintenance [Addresses handbook requirement 4.5.6(b)] Each maintenance trigger has a related inspection period listed in Table 33. i.e. Zone substations are checked each month. Monitoring of assets includes the following areas:
• Statistic data collection of loading data on substations and large transformers. • Protection relay testing / checks. • Network condition surveys. • Communication network checks. • Earthing checks. • Dissolved Gas Analysis (DGA) of transformer oil. • Partial discharge and Infrared survey of substations and major distribution equipment. • Injection plant tuning checks. • Supply quality checks. The on-going maintenance of assets is also covered by this budget. Items covered include:
• Lubrication of ABS’s. • Cleaning of air insulated switchgear. • Battery replacements. • Rust repairs and painting. • TCOL and CB service. • Minor customer connections. Two extra tasks are planned for the coming year:
• Spares checks: What do we have and what is its condition? • Seismic checks: Will our substations continue to operate after likely earthquakes? Inspection, monitoring and routine maintenance is budgeted at $0.4 million per annum. 5.3.3 Fault restoration and repairs Fault and emergency maintenance provides for the provision of staff, plant and resources to be ready for faults and/or emergencies. This resource attends and makes the area safe, then may isolate the faulty section so other customers are restored or undertake quick repairs to restore supply to all customers. Note all repairs after three hours are then covered in the routine maintenance budget. Fault restoration and repairs is budgeted at $1.5 million per annum. 5.3.4 Tree trimming Electricity (Hazards from Trees) Regulations 2003, put the requirement on OtagoNet to undertake the first trim of trees free, and this budget is the on-going actioning of this. While some customers have received their first free trim, some are disputing the process and additional costs are occurring to resolve the situation. Tree trimming is budgeted at $0.85 million per annum.
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5.4 OtagoNet’s maintenance policies [Addresses handbook requirement 4.5.6(c)] OtagoNet’s maintenance policies are embodied in the PowerNet standards PNM-99, PNM-97 and PNM-105 which broadly follow manufacturers’ recommendations but tend to be modified by industry experience. 5.5 Renewing OtagoNet’s assets [Addresses handbook requirement 4.5.6(d) and (e)] Work is classified as renewal if there is no change (and such change would usually be an increase) in functionality i.e. the output of any asset doesn’t change. OtagoNet’s key criterion for renewing an asset is when the capitalised operations and maintenance costs exceed the renewal cost and this can occur in a number of ways:
• Operating costs become excessive e.g. addition of inputs to a SCADA system requires an increasing level of manning. • Maintenance costs begin to accelerate away e.g. a transformer needs more frequent oil changes as the seals and gaskets perish. • Supply interruptions due to component failure become excessive; what constitutes “excessive” will be a matter of judgment which will include the number and nature of customers affected. • Renewal costs decline, particular where costs of new technologies for assets like SCADA decrease by several fold. Table 35 below lists OtagoNet’s renewal triggers for key asset classes. Table 35 – Renewal triggers
Asset category Components Renewal trigger LV lines and cables Poles Fails pole test. Failure due to external force. Pins, insulators and binders Done with pole renewal. Conductor Excessive failures. Multiple joints in a segment Distribution substations Poles Failure due to pole test. Failure due to external force. Enclosures Uneconomic to maintain. Transformer Excessive rust. Old technology, pre-1970 core. Not economical to maintain. Switches and fuses Not economical to maintain. Distribution lines and Poles Fails pole test. cables Failure due to external force. Pins, insulators and binders Done with pole renewal. Conductor Excessive failures. Multiple joints in a segment. Ground-mounted switches Not economical to maintain. No source of spare parts. If not able to be remote controlled. Regulators Not economical to maintain. No spare parts. Greater than Standard Life and maintenance required. Zone substations Fences and enclosures Not economical to maintain. Buildings Not economical to maintain. Bus work and conductors Not economical to maintain.
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Asset category Components Renewal trigger 33kV switchgear Not economical to maintain. No spare parts. Greater than Standard Life and maintenance required. Transformer Not economical to maintain. No spare parts. Greater than 1.2 Standard Life and maintenance required. 11kV switchgear Not economical to maintain. No spare parts. Greater than Standard Life and maintenance required. Bus work and conductors Not economical to maintain. Instrumentation/Protection Not economical to maintain. No spare parts. Greater than Standard Life and maintenance required. Batteries Prior to manufacturers’ stated life. On failure of testing. Subtransmission lines Poles Not economical to maintain. and cables Fails pole test. Failure due to external force. Pins, insulators and binders Not economical to maintain. Conductor Not economical to maintain. Excessive joints in a segment Cables Not economical to maintain. Our equipment within Not economical to maintain. GXP
Broad polices for renewing all classes of assets are:
• When an asset is likely to create an operational or public safety hazard. • When the capitalised operations and maintenance costs exceed the likely renewal costs. • When continued maintenance is unlikely to result in the required service levels.
5.5.1 Current Renewal projects [Addresses handbook requirement 4.5.6(d)(i)] Renewal projects planned to year end 31 March 2012. 5.5.1.1 General renewals This covers the on-going operation of the network and covers the following items / areas:
• Red tagged pole replacement. • Increasing road crossing height. • Minor distribution renewals and upgrades. Cost under $0.5M per annum, CAPEX Renewals. 5.5.1.2 Line refurbishments Work discovered during previous years inspections are combined by feeders into projects. As work is planned based on feeders, this renewal and refurbishment covers distribution lines, cables, dropouts and ABS’s and distribution transformers. Cost $2.5M to $5M per annum, CAPEX Renewals. Asset Management Plan Page 100 of 151
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5.5.1.3 Subtransmission Line renewals/upgrades Work discovered during previous years inspections are combined by circuits into projects. Allows for renewal of equipment and minor upgrades. Cost under $0.5M per annum, CAPEX Renewals. 5.5.1.4 Relays replacements On-going testing and fault investigation sometimes highlight protection and control relays that are not performing as desired; this programme allows renewal of these with modern protection and control relays, (includes Voltage Regulating Relays). Cost under $0.5M per annum, CAPEX Renewals. 5.5.1.5 Distribution refurbishments A budget to allow refurbishment works that doesn’t impact on the valuation of the distribution asset. Covers items like crossarms, insulators, strains, re-sagging lines, stay guards, straightening poles, pole caps, ABS handle replacements etc. Cost under $0.5M per annum, OPEX Renewals. 5.5.1.6 Subtransmission refurbishments A budget to allow refurbishment works that doesn’t impact on the valuation of the subtransmission assets. Covers items like crossarms, insulators, strains, re-sagging lines, stay guards, straightening poles, pole caps, ABS handle replacements etc. Cost under $0.5M per annum, OPEX Renewals. 5.5.1.7 Zone Substation refurbishments A budget to allow refurbishment works that doesn’t impact on the valuation of the substation assets. Covers items like minor works on power transformers, earth sticks, safety equipment, buildings, battery systems etc. Cost under $0.5M per annum, OPEX Faults Maintenance. 5.5.2 Planned renewal projects [Addresses handbook requirement 4.5.6(d)(ii)] Project planned for year two to five, YE 2013 to YE 2016. The majority of the renewal projects for OtagoNet are 11kV line renewals as the poles, cross arms and or conductors have reached the end of their economic life. Because of the small loads and minimal load growth most of these projects are all renewals with the few growth projects being reported in section 4. Similarly parts of the OtagoNet LV and sub transmission lines are planned to be renewed as they reach their end of economic life. These line renewal projects will renew some 120 km of distribution line each year including single phase and three phase 11kV lines and single wire earth return lines where it is uneconomical to consider upgrading to two or three wires. The individual project and budgeted costs are found in the detailed capital budgets in section 4. $2.5M to $5M per annum, CAPEX renewal 5.5.3 Future renewal projects [Addresses handbook requirement 4.5.6(d)(iii)] Projects planned for year five to ten, YE 2017 to YE 2021. Future renewal projects will continue to focus on 11kV line renewals at a similar rate for the remainder of the planning period. This rate of 120km plus any growth and Asset Management Plan Page 101 of 151
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extension work (with a total line length of 4,400km) should be sufficient to reduce the average age of the network lines to 50% by the end of the planning period. 5.5.4 Renewal budget CAPEX renewals are budgeted in the capital budget, see section 4.8.5. 5.6 Up-sizing or extending OtagoNet’s assets If any of the capacity triggers in Table 21 are exceeded consideration is given to either up-sizing or extending OtagoNet’s network. These two modes of investment are however, quite different as described in Table 36 below. Table 36 - Distinguishing between up-sizing and extension
Characteristic Up-sizing Extension Location Within or close to existing network Outside of existing network footprint (within a span or so). footprint (more than a couple of spans). Load Can involve supply to a new Almost always involves connection within the network supply to a new connection. footprint or increasing the capacity to an existing connection. Upstream Generally forms the focus of up- May not be required unless reinforcement sizing. upstream capacity is constrained. Visible presence Generally invisible. Obviously visible. Quadrant in Figure 20 Either 1 or 2 depending on rate of Either 3 or 4 depending on growth. rate of growth. Necessity Possible to avoid if sufficient Generally can’t be avoided – surplus capacity exists. Possible to a physical connection is avoid or defer using tactical required. approaches described in section 4.2.1. Impact on revenue Difficult to attribute revenue from Generally results in direct increased connection number or contribution to revenue from capacity to augmented the new connection at the components. end of the extension. Impact on costs Cost and timing can vary and be Likely to be significant and staged. over a short time. Impact on ODV Could be anywhere from minimal to Could be significant high. depending on length of extension and any consequent up-sizing required. Impact on profit Could be anywhere from minimal to Could be minimal depending high. on level of customer contribution. Means of cost recovery Most likely to be spread across all Could be recovered from customers as part of on-going line customers connected to that charges. extension by way of capital contribution. Nature of work carried Replacement of components with Construction of new assets. out greater capacity items.
Despite the different nature of up-sizing and extension work, similar design and build principles are used as described in sections 5.6.1 and 5.6.2.
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5.6.1 Designing new assets OtagoNet uses a range of technical and engineering standards to achieve an optimal mix of the following outcomes:
• Meet likely demand growth for a reasonable time horizon including such issues as modularity and scalability. • Minimise over-investment. • Minimise risk of long-term stranding. • Minimise corporate risk exposure commensurate with other goals. • Maximise operational flexibility. • Maximise the fit with soft organisational capabilities such as engineering and operational expertise and vendor support. • Comply with sensible environmental and public safety requirements. Given the fairly simple nature of OtagoNet’s network standardised designs are adopted for all asset classes with minor site-specific alterations. These designs, however, will embody the wisdom and experience of current standards, industry guidelines and manufacturers recommendations. 5.6.2 Building new assets OtagoNet uses external contractors to augment or extend assets. As part of the building and commissioning process OtagoNet’s information records will be “as-built” and all testing documented. 5.7 Enhancing reliability Although enhancing reliability does not neatly fit into the life-cycle model, OtagoNet believes that enhancing reliability is strategically significant enough in reshaping the business platform to merit inclusion in the AMP. As described in Section 3.2.1 customers’ prefer to receive the same reliability in return for paying the same line charges. It is acknowledged that there is no mandate to improve reliability just because it can be improved. However there are many factors that will lead to a decline in reliability over time and it is just important to avoid a decline in supply reliability to our customers. To prevent this occurring the following must be monitored and controlled:
• Tree re-growth. • Declining asset condition (especially in coastal marine areas). • Extensions to the network that increase its exposure to trees and weather. • Increased customer numbers that increase the lost customer-minutes for a given fault. • Installation of customer requested asset alterations that can reduce reliability (e.g. needing to lock out reclosers on feeders that have embedded generation). OtagoNet believes it is necessary to offset these impacts in order to maintain reliability; hence a reliability enhancement program using an approach that embodies the following steps has been developed:
• Identifying the customer-minutes lost for each asset by cause. • Identifying the scope and likely cost of reducing those lost customer-minutes. • Estimating the likely reduction in lost customer-minutes if the work scope was to be implemented. • Calculating the cost per customer-minute of each enhancement opportunity. • Prioritising the enhancement opportunities from lowest cost to highest. OtagoNet expects the incremental cost of regaining lost customer-minutes will accelerate away at some point which will set an obvious limit to implementing opportunities.
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5.8 Converting overhead to underground Conversion of overhead lines to underground cable is also an activity that doesn’t fit neatly within the asset life-cycle because it tends to be driven more by the need to beautify areas or remove overhead obstructions rather than for asset-related reasons (which doesn’t really fit the renewal or up-sizing triggers). As such, conversion tends to rely on other utilities cost sharing or local communities funding the work. 5.9 Retiring of OtagoNet’s assets Retiring assets generally involves doing most or all of the following activities:
• De-energising the asset. • Physically disconnecting it from other live assets. • Curtailing the assets revenue stream. • Removing it from the ODV. • Either physical removal of the asset from location or abandoning in-situ (typically for underground cables). • Disposal of the asset in an acceptable manner particularly if it contains SF6, oil, lead or asbestos. Key criteria for retiring an asset include:
• Its physical presence is no longer required (usually because a customer has reduced or ceased demand). • It creates an unacceptable risk exposure, either because its inherent risks have increased over time or because emerging trends of safe exposure levels are declining. Assets retired for safety reasons will not be re-deployed or sold for re- use. • Where better options exist to create similar outcomes (e.g. replacing lubricated bearings with high-impact nylon bushes) and there are no suitable opportunities for re-deployment. • Where an asset has been augmented and no suitable opportunities exist for re- deployment.
5.10 OtagoNet’s Maintenance Budget [Addresses handbook requirement 4.5.9(a)] Estimated expenditure on maintaining the assets are given below. Target is maintaining the ratio of maintenance under 2% of the total network replacement cost. This budget covers both Operation and Maintenance areas. Table 37 Maintenance Budget (2011 to 2016)
Project 2011/12 2012/13 2013/14 2014/15 2015/16
Refurbishment and Renewal Maintenance Clinton 33 kV pole maintenance 100,000 100,000 Hillend 11kV feeder maintenance 182,000 Morven Road, Slopedown maintain old / weak poles 80,000 Network chargeable Maintenance 60,000 45,000 45,000 45,000 45,000 New Connection Maintenance 6,000 6,000 6,000 6,000 6,000 Ongoing Special Line Maintenance Projects - per 500,000 500,000 500,000 500,000 year Pole and Line maintenance identified in line survey 200,000 200,000 200,000 200,000 200,000 Pole or conductor maintenance on minor spur lines 200,000 200,000 200,000 200,000 200,000 Transformer Refurbishment (workshop) 30,000 30,000 30,000 30,000 30,000 Refurbishment and Renewal Maintenance Total 858,000 1,081,000 981,000 981,000 981,000
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Project 2011/12 2012/13 2013/14 2014/15 2015/16 Routine and Preventative Maintenance Earth Maintenance from earth test results 100,000 100,000 100,000 100,000 100,000 Earth Testing and review for Safety and Risk 100,000 100,000 100,000 100,000 100,000 Line Condition Survey Work (Subtrans and Town LV) 150,000 80,000 80,000 80,000 80,000 Load Control Equipment 1,000 1,000 1,000 1,000 1,000 Radio Equipment 24,000 24,000 24,000 24,000 24,000 SCADA Equipment 1,000 1,000 1,000 1,000 1,000 Transmission Line Minor Maintenance 50,000 50,000 50,000 50,000 50,000 Vegetation Control 850,000 850,000 850,000 850,000 850,000 Voltage Complaint Investigation 15,000 15,000 15,000 15,000 15,000 Routine and Preventative Maintenance Total 1,291,000 1,221,000 1,221,000 1,221,000 1,221,000
Fault and Emergency Maintenance Distribution Faults 500,000 500,000 500,000 500,000 500,000 Distribution Minor Maintenance 400,000 400,000 400,000 400,000 400,000 Sub Transmission Line Faults 65,000 65,000 65,000 65,000 65,000 System Control Services 194,400 194,000 194,000 194,000 194,000 Zone Sub Faults 48,000 48,000 48,000 48,000 48,000 Zone Sub Minor Maintenance 250,000 250,000 250,000 250,000 250,000 Fault and Emergency Maintenance Total 1,457,400 1,457,000 1,457,000 1,457,000 1,457,000 Grand Total 3,606,400 3,759,000 3,659,000 3,659,000 3,659,000
Table 38 Maintenance Budget (2016 to 2021)
Project 2016/17 2017/18 2018/19 2019/20 2020/21
Refurbishment and Renewal Maintenance Clinton 33 kV pole maintenance Hillend 11kV feeder maintenance Morven Road, Slopedown maintain old / weak poles Network chargeable Maintenance 45,000 45,000 45,000 45,000 45,000 New Connection Maintenance 6,000 6,000 6,000 6,000 6,000 Ongoing Special Line Maintenance Projects - per year 500,000 500,000 500,000 500,000 500,000 Pole and Line maintenance identified in line survey 200,000 200,000 200,000 200,000 200,000 Pole or conductor maintenance on minor spur lines 200,000 200,000 200,000 200,000 200,000 Transformer Refurbishment (workshop) 30,000 30,000 30,000 30,000 30,000 Refurbishment and Renewal Maintenance Total 981,000 981,000 981,000 981,000 981,000
Routine and Preventative Maintenance Earth Maintenance from earth test results 100,000 100,000 100,000 100,000 100,000 Earth Testing and review for Safety and Risk 100,000 100,000 100,000 100,000 100,000 Line Condition Survey Work (Subtrans and Town LV) 80,000 80,000 80,000 80,000 80,000 Load Control Equipment 1,000 1,000 1,000 1,000 1,000 Radio Equipment 24,000 24,000 24,000 24,000 24,000 SCADA Equipment 1,000 1,000 1,000 1,000 1,000 Transmission Line Minor Maintenance 50,000 50,000 50,000 50,000 50,000 Vegetation Control 850,000 850,000 850,000 850,000 850,000 Voltage Complaint Investigation 15,000 15,000 15,000 15,000 15,000 Routine and Preventative Maintenance Total 1,221,000 1,221,000 1,221,000 1,221,000 1,221,000
Fault and Emergency Maintenance Distribution Faults 500,000 500,000 500,000 500,000 500,000 Distribution Minor Maintenance 400,000 400,000 400,000 400,000 400,000 Sub Transmission Line Faults 65,000 65,000 65,000 65,000 65,000 System Control Services 194,000 194,000 194,000 194,000 194,000 Zone Sub Faults 48,000 48,000 48,000 48,000 48,000 Zone Sub Minor Maintenance 250,000 250,000 250,000 250,000 250,000 Fault and Emergency Maintenance Total 1,457,000 1,457,000 1,457,000 1,457,000 1,457,000 Grand Total 3,659,000 3,659,000 3,659,000 3,659,000 3,659,000
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6. Risk Management
[Addresses handbook requirement 4.5.7(a)] The business is exposed to a wide range of risks. This section examines OtagoNet’s risk exposures, describes what it has done and will do about these exposures and what it will do when disaster strikes. Risk management is used to bring risk within acceptable levels. 6.1 Risk methods The risk management process as it applies to the electricity network business is intended to assess exposure and prioritise mitigating actions. The risk on the network is analysed at the high level, reviewing major network components and systems to see if possible events could lead to undesirable situations.
6.1.1 Guiding principles OtagoNet’s behaviour and decision making is guided by the following principles:
• Safety of the public and staff is paramount. • Essential services are the second priority. • Works that have the larger benefit are done before those with less of a benefit. • Switching to restore supplies prior to repair work. • Plans will generally only handle one major event at a time. • Risks will be removed, mitigated, or lessened, depending on the economics.
6.1.2 Risk Categories Risks are classified against the following categories:
• Weather o Wind – strong winds that cause either pole failures or blow debris into lines. o Snow – impact can be by causing failure of lines or limiting access around the network. o Flood – while the Regional Council has installed flood protection works, there is still a risk in the lower Clutha area and still needs to be considered. • Physical o Earthquake – no recent history of major damage. Large events may occur and impact the network. The 15 July 2009 7.8 Richter scale quake 100 km south-west of Te Anau, caused no damage to the network. (Ref. number 3124785/G) o Liquefaction – post Christchurch 22 February 2011 6.3 quake, the hazard of liquefaction has become a risk to be considered.
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o Fire – transformers are insulated with mineral oil that is flammable and buildings have flammable materials so fire will affect the supply of electricity. Source of fire could be internal or from external sources. o Terrorism – malicious damage to equipment can interrupt supply. o Asset Failures – equipment failures can interrupt supply or negate systems from operating correctly. i.e. failure of a padlock could allow public access to restricted areas. • Human o Pandemic – impact depends on the virility of the disease. Could impact on staff work as they try to avoid infection or become unable to work. o Car versus pole – damage to the driver/passengers and the network could be significant. o Vandalism – range varies from malicious damage to ‘tagging’ of buildings or equipment. • Corporate o Investment – providing business processes that ensure appropriate contracts and guarantees are agreed prior to undertaking large investments. o Loss of revenue – loss of customers through by-pass or economic downturn could reduce revenue. o Management contract – failure of PowerNet as OtagoNet’s asset manager. o Regulatory – failure to meet regulatory requirements. o Resource – field staff to undertake operation, maintenance, renewal, augmentation, extension and retirement of network assets.
6.1.3 Risk Tactics The following tactics are used to manage risk under the following broad categories:
• Operate a 24hr Control centre. • Provide redundancy of supply to large customer groups. • Remove assets from risk zone. • Involvement with the local Civil Defence.
6.2 Risk Details [Addresses handbook requirement 4.5.7(b)]
6.2.1 Weather Table 39 - Weather Risk
Event Likelihood Consequence Responses Wind Low Low If damage occurs on lines this is remedied by repairing the failed equipment. Snow Very Low Low If damage occurs on lines this is remedied by repairing the failed equipment. If access is limited then external plant is hired to clear access or substitute. Flood Very Low Low Transformers and switchgear in high risk areas to be mounted above the flood level. Zone substations to be sited in areas of very low flood risk.
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6.2.2 Physical Table 40 - Physical Risk
Event Likelihood Consequence Responses Earthquake Extremely Major Disaster recovery event. (>8) Low Need to determine actual likely level of survivability of existing assets. Earthquake Very Low Low to High Specify buildings and equipment to (6 to 7) survive. Review existing buildings and equipment and reinforce if necessary. Liquefaction Very Low Low to Medium Specify buildings and equipment foundations to minimise impact. Review existing sites and reinforce if economic. Fire Very Low High Supply customers from neighbouring LV cables and transformers. Continue to operate or install fire sprinklers or suppression systems in basement housed sites. Continue to maintain fire detection and alarm systems. Terrorism Very Low High Ensure security of restricted sites. Use alternative routes and equipment to restore supply, similar to equipment failures below.
6.2.3 Equipment Failures As the impact of this is variable, a central control room is provided, which is manned 24 hours a day by PowerNet staff. Engineering staff are on standby at any time to provide backup assistance for network issues. Table 41 - Equipment Failure Risk
Event Likelihood Consequence Responses 33kV cable Low Low Each section of cable has an alternative 33kV route. Power Very Low Low Larger substations have dual transformers Transformer to allow one to be removed from service due to fault or maintenance. Continue to undertaken annual DGA to allow early detection of failures. If prolonged outage or loss of a single unit then a spare power transformer can be installed. 11kV Low Medium Annual testing including PD13 and IR14. Switchgear Replacement before end of life with modern equipment. The network configuration allows switchgear to be bypassed at most times.
13 PD = Partial Discharge, indication of discharges occurring within insulation. 14 IR = Infrared, detection of heat of equipment that highlights hot spots.
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Event Likelihood Consequence Responses Oil Spill Very Low Medium Oil spill kits located at the three contractor’s depots to be used in event of an oil leak or spill. Zone substation transformers have oil bunding and regular checks to discharge only clean rain water. Security Very Low Medium Monthly checks of each restricted site. measures Remote monitoring of access doors by SCADA is being implemented. Batteries Low Medium Continue monthly check and six monthly testing. Circuit Very low Medium Continue regular operational checks. Breakers Mal-operations investigated. Protection Circuit Very low Low Backup provided by incomer circuit Breakers breakers. Continue regular maintenance and testing. SCADA RTU Low Low Monitor response of each RTU at the Master Station and alarm if no response after five minutes. If failure then send faults contractor to restore, if critical events then roster a contractor onsite. SCADA Very low Low Continue to independently monitor and Masterstation alarm the master station and communications links to the Invercargill control centre. Continue to have a support agreement with the software supplier and technical faults contractor to maintain the equipment. Load Control Low Medium Manually operate plant with test set if SCADA controller fails.
6.2.4 Human Table 42 - Human Risk
Event Likelihood Consequence Responses Pandemic Low Low to High Work to the PowerNet Pandemic plan. Includes details such as working from home, only critical faults work and provide emergency kits for offices etc. Car versus Very Low Low Have resource to bypass and or repair. pole Vandalism Medium Low to High Six monthly checks of all ground-mounted equipment. Faults contractor to report all vandalism and repair depending on safety then economics. i.e. tagging/graffiti would depend on the location and content. Any safety problems will be made safe as soon as they are discovered.
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6.2.5 Corporate Table 43 - Corporate Risk
Event Likelihood Consequence Responses Investment Low Low Very little new investment occurring, new larger contracts require Shareholder Guarantee before supply is provided. Loss of Very Low High Continue to have Use of System Revenue Agreements with retailers. New large investments for individual customers to have a guarantee. Management Extremely High Maintain a contract with PowerNet. Contract low Ensure PowerNet has and operates to a Business Continuity Plan. Regulatory Extremely High Continue to contract PowerNet to meet low regulatory requirements. Ensure PowerNet has and operates to a Business Continuity Plan. Resource Low High Continue to enhance contractor relationship with present contractor. Provide a long term commitment and support, for the contractor to be sufficiently resourced to achieve the contract service levels on the network.
6.2.6 Projects Major projects are evaluated by the UMS Optimisation Tool. Part of the analysis is a risk assessment of the project. An example is shown below.
Risk Matrix-Overall
18
5 1 9 21
20
16 4
3 5 19 3 22
15 6
Probability 8
13 14 2
4 7 10 2
1 17 11 12
0
0 1 2 3 4 5 Consequence Figure 26 - Risk Matrix
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The two axes relate to the probability of failure, the higher up the “Y” axis the more certainty that this may occur and the “X” axis representing the consequence or impact of failure from minimal to catastrophic. The coloured regions group the common risk levels with the blue representing very minor risks through to the red zone representing an unacceptable extreme risk. This shows the risk analysis of the selected projects. The unselected projects are shown as unfilled points with these generally relating to the other options for major projects. 6.3 Contingency Plans OtagoNet has the following contingency plans: 6.3.1 Business Continuity Plan OtagoNet must be able to continue in the event of any serious business interruption. Events causing interruption can range from malicious acts through damaging events, to a major natural disaster such as an earthquake. The principle objectives of the Business Continuity Plan are to:
• Eliminate or reduce damage to facilities, and loss of assets and records. • Minimise financial loss. • Provide for a timely resumption of operations in the event of a disaster. • Reduce or limit exposure to potential liability claims filed against the Company, its Directors and Staff. 6.3.2 Pandemic Action Plan OtagoNet must be able to continue in the event of a breakout of any highly infectious illness which could cause staff to be unable to function in their job. The plan aims to manage the impact of an influenza pandemic on OtagoNet’s staff, the business and services through two main strategies: 1. Containment of the disease by reducing spread within OtagoNet. This is achieved by such measures as; reducing risk of infected persons entering OtagoNet’s premises, social distancing, cleaning of the work environment, managing fear, management of cases at work and travel advice. 2. Maintenance of essential services if containment is not possible. This is achieved through identification of the essential activities and functions of the business, the staff required to carry out these tasks and special measures required to continue these tasks under a pandemic scenario. 6.3.3 Network Operating Plans As contingency for major outages on the OtagoNet network there are network operating plans for safe and efficient restoration of services where possible. For example, an operating order detailing operational steps required to restore supply after loss of a zone substation. 6.4 Insurance OtagoNet holds the following insurances:
• Material damage and business interruption over Substations, Buildings and the Macraes 66 kV line. • Contracts works. • Directors and officers liability.
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• Utilities Industry Liability Programme (UILP) that covers Public, Forest & Rural Fires and Products liability. • Statutory liability. • Marine Cargo. Contractors working on the network are asked to hold Liability Insurance.
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7. Funding the business
Everything discussed in the AMP so far has been (indirectly) about costs. This section discusses how OtagoNet funds its business. 7.1 Business model OtagoNet’s business model is based around the right-hand side of Figure 27.
Customer relationship
Figure 27 – Customer interface model This model clearly shows that OtagoNet receives cash from its customers (via the retailers who operate on the network) and then, through a wide range of internal processes, policies and plans, OtagoNet converts that cash into fixed assets. These fixed assets in turn create the service levels such as capacity, reliability, security and voltage stability that customers want. 7.2 Revenue source OtagoNet’s money comes primarily from the retailers who pay OtagoNet for conveying energy over OtagoNet’s lines or by customer contributions for the uneconomic part of works. In regard to funding new assets (i.e. beyond the immediate financial year) OtagoNet has considered the following approaches:
• Funding from revenue within the year concerned. • Funding from after-tax earnings retained from previous years. • Raising new equity (very unlikely given the current shareholding arrangement). • Raising debt (which has a cost, and is also subject to interest cover ratios).
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• Allowing Transpower to build and own assets which allows OtagoNet to avoid new capital on its ODV and its balance sheet. 7.3 Expenditure Work is done to maintain the asset value of the network and to expand or augment to meet customer demands. 7.4 Changes in the value of assets Given the preferences expressed by OtagoNet’s customers for the following price- quality trade-offs in the ‘Customer engagement telephone survey’ undertaken by Gary Nicol Associates in January - February 2010 {previous survey}:
• 11% {13%} of rural customers are willing to pay $10 per month more for improved reliability. • 4% {6%} or rural customers don’t know or are unsure of price-quality trade-offs. • 12% {8%} of urban customers are willing to pay $10 per month more for improved reliability. • 4% {6%} of urban customers don’t know or are unsure of price-quality trade-offs. OtagoNet’s asset value should either remain about the same or be allowed to decline in a controlled manner (and knowing how to do this is obviously a complex issue). However this presents OtagoNet with the dilemma of responding to customers wishes for lower supply quality in the face of a “no material decline in charges requirement”. Factors that will influence OtagoNet’s asset value are shown in Table 44: Table 44 – Factors influencing asset value
Factors that increase Factors that decrease OtagoNet’s asset value OtagoNet’s asset value Addition of new assets to the network. Removal of assets from the network. Need to Need to confirm exactly when asset value confirm when asset value can be removed from can be added to valuation base under valuation base under ODV rules. ODV rules. Renewal of existing assets. Note On-going depreciation of assets. definition of renewal as being restoration of original functionality – no increase in service potential beyond original functionality. Increase of standard component values Reduction of standard component values implicit in the ODV methodology. implicit in the ODV methodology.
At a practical level the asset valuation will vary even in the absence of component revaluations. This is principally because the accounting treatment of depreciation models the decline in service potential as a straight line (when in most cases it is more closely reflected by an inverted bath-tub curve) whilst the restoration of service potential is very “lumpy”. However the aggregation of many depreciating assets and many restoration projects tends to smooth short-term variations in asset value. 7.5 Depreciating the assets As outlined in Section 7.4 above, the accounting treatment of depreciation doesn’t strictly model the decline in service potential of an asset - sure it probably does quite accurately model the underlying physical processes of rust, rot, acidification, erosion etc – but an asset often tends to remain serviceable until it has rusted, rotted, acidified, or eroded substantially and then fails quickly.
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Straight-line depreciation does, however, provide a smooth and reasonably painless means of gathering funds to renew worn out assets but recognize that replacement costs are increasing and additional funds may be needed. This will be particularly important as OtagoNet approaches the large increase of asset renewals due to large network expansion in the 1950’s, see Figure 15.
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OUR PROCESSES AND SYSTEMS
8. Processes and systems
[Addresses handbook requirement 4.5.2(f)] The core of OtagoNet’s asset management activities lie with the detailed processes and systems that reflect its thinking, manifest in its policies, strategies and processes and ultimately shape the nature and configuration of the fixed assets. The hierarchy of data model shown in Figure 28 describes the typical sorts of information residing within the business (including in employees heads).
Wisdom Hard to codify
Understanding
Knowledge
Information Easier to codify
Data
Figure 28 - Hierarchy of Data The bottom two layers of the hierarchy tend to relate strongly to the asset and operational data which reside in the GIS and SCADA respectively and the summaries of this data that form one part of the decision making process. The third layer - knowledge - tends to be more broad and general in nature and may include such things as technical standards that codify accumulated knowledge into a single useful document. The top two layers tend to be very broad and often quite fuzzy. It is at this level that key organisational strategies and processes reside at. As indicated in Figure 28 it is generally hard to codify these things, hence correct application is heavily dependent on skilled people. 8.1 Asset knowledge [Addresses handbook requirement 4.4.6] OtagoNet knows a great deal about almost all of the assets – their location, what they are made of, generally how old they are and how well they can perform. OtagoNet’s asset data resides in three key locations:
• Asset description, location, age and condition information of line, cables and field devices resides in the Geographical Information System (GIS). • Asset descriptions, details, age and condition information of serial numbered components resides in Asset Management System (AMS).
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• Asset operational data such as loadings, voltages, temperatures and switch positions reside in the Supervisory Control and Data Acquisition (SCADA). An additional class of data (essentially commercial in nature) includes such data as customer details, consumption and billing history. Table 45 Knowledge Accuracy
System Parameter Completeness Notes GIS Description Excellent Some delays between job completion and updating into the GIS. GIS Location Excellent Few low voltage lines/cables captured. All Pole ages available, some minor GIS Age Good errors. GIS Condition Good MV & HV survey complete. WASP Description Good Some delays between job completion WASP Details Good and updating into WASP. WASP Age Good Missing age on old components. Some condition monitoring data like WASP Condition Poor DGA are held in external databases. SCADA Zone Substations Excellent All monitored. SCADA Field Devices Okay A few site monitored.
8.2 Improving the quality of the data [Addresses handbook requirement 4.4.6(c)] 8.2.1 GIS data improvement The original data capture emphasised asset location and configuration and was used to populate the GIS, but did not include a high level of asset condition. OtagoNet now condition assesses about 20% of the network (by length) each year to update asset condition data (noting that asset condition is continually varying). Key process improvements will include more timely as-builts from contractors and use of hand-held data capture devices. Key process improvements will include more timely as-builts with PowerNet staff GPS- ing15 poles and use of scan-able forms for data input (Teleform system). 8.2.2 AMS data improvement Data for the AMS is collected by the Network Movement Notice that records every movement of serial numbered assets. Some updating of data is obtained when sites are checked, maintained or upgraded and during other processes like collecting and verifying data for valuations. 8.3 Use of the data All data will be used for either making decisions within the own business or assisting external entities to make decisions. This data is almost always aggregated into information (the second level of the pyramid) in order to make decisions e.g. a decision to replace a zone substation transformer will be based on an aggregation of loading data.
15 GPS = Global Positioning System, a device that uses satellites and accurate clocks, to measure the location of a point.
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8.4 Decision making The decision making process also involves the top two levels of the hierarchy - understanding and wisdom - which tend to be broad and enduring in nature. Although true understanding and wisdom are difficult to codify, it is possible to capture discrete pieces of understanding and wisdom and then codify them into such documents as technical standards, policies, processes, operating instructions, spreadsheet models etc. This is called knowledge and probably represents the upper limit of what can be reasonably codified. Accurate decision making therefore requires the convergence of both information and (a lot of) knowledge to yield a correct answer - deficiencies in either area (incorrect data, or a failure to correctly understand issues) will lead to wrong outcomes. The source, roles and interaction of each component of the hierarchy are shown below in Figure 29.
Commercial info – customer number, consumption etc
Customer initiated change - load Operational Repositories – Parallel info – switch paper, PCs, “information status, faults, servers, brains asset” load, voltage etc etc Externally initiated Network change – assets weather, faults, Asset info – generators description, age, location, condition, history etc Internally initiated change – operational, maintenance, capital
Internal decision processes
Info to Guides to decision making external – policies, procedures, parties manuals, standards, regulations, legislation, codes, plans etc
Figure 29 - Key information systems and processes 8.5 Key processes and systems OtagoNet’s key processes and systems are based around the key lifecycle activities defined in Figure 23 and are described in the following sections. Asset Management Plan Page 118 of 151
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8.5.1 Operating processes and systems Commissioning Network Equipment PNM-61 Network Equipment Movements PNM-63 Planned Outages PNM-65 Network Faults, Defects and Supply Complaints PNM-67 Major Network Disruptions PNM-69 Use of Operating Orders (O/O) PNM-71 Control of Tags PNM-73 Access to Substations and Switchyards PNM-75 Operational Requirements for Confined Space Entry PNM-76 Operating Authorisations PNM-77 Radio Telephone Communications PNM-79 Operational Requirements for Live Line Work PNM-81 Control of SCADA Computers PNM-83 Machinery Near Electrical Works PNM-85 Customer Fault Calls/Retail Matters PNM-87 Site Safety Management Audits PNM-88 Meter/Ripple Receiver Control PNM-121
8.5.2 Maintenance processes and systems Control of Network Spares PNM-97 Transformer Maintenance PNM-99 Maintenance Planning PNM-105 Other maintenance is to manufacturers’ recommendations or updated industry practise.
8.5.3 Renewal processes and systems Network Development PNM-113 Design and Development PNM-114
8.5.4 Up-sizing or extension processes and systems Network Development PNM-113 Design and Development PNM-114 Processing Installation Connection Applications PNM-123 Easements PNM-131
8.5.5 Retirement processes and systems
Disconnected And/Or Discontinued Supplies PNM-125
8.5.6 Performance measuring processes and systems [Addresses handbook requirement 4.5.2(f)(iii)] 8.5.6.1 Faults All faults are entered into the ‘Faults’ database and reported monthly to the board, together with details of all the planned outages. 8.5.6.2 Financial Monthly reports out of the Finance One (F1) financial system provide measurement of revenues and expenses for the OtagoNet line business unit. Project costs are managed in PowerNet with project managers managing costs through the WASP system. Interfaces between F1 and WASP track estimates and costs against assets.
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8.5.6.3 Customer Customer statistics are monitored by a Customer Database system developed by ACE computers, this interfaces with the National Registry to provide and obtain updates on customer connections and movements. Customer consumption is monitored by another ACE Computers system ‘BILL’. BILL receives monthly details from retailers and links this to the customer database. 8.5.6.4 Service levels Customers that have had work done are sent a survey form at the end of the job. Results are monitored and any comments given are reviewed and responded to.
8.5.7 Other business processes In addition to the above processes that are specific to life cycle activities, OtagoNet has a range of general business processes that guide activities such as evaluating tenders and closing out contracts: Setting Up the Contract PNM-10 Tender Evaluation PNM-15 Contract Formation PNM-20 Construction Approval PNM-25 Materials Management PNM-30 Contract Control PNM-35 Contract Close Out PNM-40 Customer Satisfaction PNM-50 External Contracting PNM-60 Drawing Control PNM-89 Network Operational Diagram/GIS Control PNM-91 Control of Operating and Maintenance Manuals PNM-93 Control of External Standards PNM-95 Control of Power Quality Recorders PNM-103 Quality Plans PNM-107 Health and Safety PNM-109 Accidents and Incidents PNM-111 Design and Development PNM-114 Network Purchasing PNM-115 Network Pricing PNM-117 Customer Service Performance PNM-119 Incoming and Outgoing Mail Correspondence PNM-129 8.6 Asset Management tools [Addresses handbook requirement 4.5.2(f)(i) and (ii)] A variety of tools and procedures are utilised by PowerNet to best manage the assets of the various networks. GIS and WASP software packages are used to store and evaluate assets data. Quality system procedures are in place to highlight and focus on various management techniques. The outputs of these systems produce one year and 10 year AMP’s, together with data for on-going day to day planning and control.
8.6.1 GIS An Intergraph based Geographic Information System is utilised to store and map data on individual components of distributed networks. This focuses primarily on cables, conductors, poles, transformers, switches, fuses and similar items. Large composite
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items such as substations are managed by more traditional techniques such as drawings and individual test reports. Equipment capacity, age and condition are listed by segment. The data is used to provide base maps of existing equipment, for extensions to the network, for maintenance scheduling and similar functions.
8.6.2 WASP WASP (Works, Assets, Scheduling, Purchasing) is a work scheduling and asset management tool. It is intricately linked to the financial management system. This package tracks major assets and is the focus for work packaging and scheduling. Most day to day operations are managed using WASP. Maintenance regimes, field inspections and customers produce tasks and/or estimates that are sometimes grouped and a ‘work packs’ issued from WASP.
8.6.3 Faults Database All outages are logged into a database, with is used to provide regulatory information and statistics on networks performance. Reports from this system are used to highlight poorly performing feeders, these are then analysed to determine if it is a maintenance issue or if reliability may be enhanced by other methods.
8.6.4 PNM-105 maintenance planning The quality system procedure PNM-105 drives maintenance planning. It is the procedure used to drive this document to completion. Relevant inputs into the plan include:
• WASP Records. • Surveys (field, CDM). • Analysis of faults database. • GIS database. • System network loading data. • Major customers. • Growth (domestic, commercial, industrial) in geographic areas. • Legislation. • Cyclic maintenance on major plant items. • Current AMP.
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9. Performance and improvement
This section firstly evaluates OtagoNet’s performance over the 2009/10 year and secondly identifies areas where OtagoNet believes it could improve its business. 9.1 Outcomes against plans [Addresses handbook requirement 4.5.8(a)] The outcome for the 2009/10 annual business plan was 8.3% under the budgeted $7.01M for capital and 8.3% over the budgeted $2.99M for maintenance. 9.1.1 Capital The spending on Capital works was below budget due to three projects being deferred due to land owner access issues and one project was not completed during the year due to lack of contractor resources. New connections were also well under the expected and budgeted level. Some of the resources were diverted to the urgent maintenance work, see below. Comment on development projects are listed below:
9.1.1.1 Line Rebuilding Projects 14 projects in excess of $100,000 each were completed before 31 March 2008 with the following projects being delayed as follows:
• Milton second 33kV line, this project continued with 87% of the budgeted work completed. This is expected to be a four year project with the work rate ‘ramped up’ as design and land owner issues are resolved. • The Shag Point 11 kV line diversion was delayed due to Transit Landowner and adjacent lines company negotiations to determine the best possible solution for all. • Two smaller ground mounted transformer renewals in Balclutha township were also delayed due to negotiation for the new transformer sites being stalled by the land owners and Council. The net effect was to spend 8.3% less than budgeted.
9.1.1.2 Lawrence Substation 2.6MVA Transformer and 11kV Indoor Switchboard The two 1.5MVA transformers and the outdoor 11kV structure were replaced at Lawrence during the year with a single standard sized 2.5MVA transformer and a four way compact indoor switchboard that was installed into the existing control room.
9.1.1.3 New connections Work on new connections was only $879,240, 27% less than budgeted, mainly due to a reduction in the number of Dairy conversions requiring expensive line extensions and connections. 9.1.2 Maintenance Maintenance costs were 8.3% over the budgeted $2.99M. All projects and planned work was completed except the Owaka 33kV pole replacement work, which was deferred to allow completion of the work during the next summer utilising generation to eliminate the otherwise lengthy outages required. The main increase over budget was as a result of the pole condition survey and the urgent maintenance of individual poles. Urgent safety work was also uncovered as the pole survey progresses and more work than budgeted was required to rectify ground
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clearance of some wires. The total budget was $300,000 which was over spent by 42%. The vegetation control budget of $775,000 was also overspent by $94,000 due to increasing costs and more difficult work now being identified. 9.2 Performance against targets [Addresses handbook requirement 4.5.8(b)] 9.2.1 Primary service levels The chart below displays the target versus actual reliability performance on the network.
Class B and C 2009/10 AMP Target 12 Month Actual SAIFI 2.65 3.26 SAIDI 326 332.64
For the 2009/10 year the network fault rate has not improved with a higher frequency and duration than targeted. These reflect on-going faults on the network relating to equipment condition and its ability to withstand the higher winds and snow seen during the year. The poorly performing areas of the network are targeted in the long term planning process. The Class B planned SAFI figures were marginally higher than previous year or planed and reflect the extra pole maintenance work completed. 9.2.2 Secondary service levels Results for 2009/10 are shown below, with all targets achieved.
Attribute Measure YE 31/3/10 Actual Customer Satisfaction: Percentage satisfied with >80% No result17 Inquiries OtagoNet staff. {CES: Q9(b)}16 Customer Satisfaction: Phone: Friendliness and >3.5 5 New Connections courtesy. {CSS: Q3(c)}18 Phone: Time taken to answer >3.5 5 call. {CSS: Q3(a)} Overall level of service. >3.5 5 {CSS: Q5} Work done to a standard which >3.5 4.8 meet your expectations. {CSS: Q4(b)} Customer Satisfaction: Power restored in a reasonable >60% 83% Faults amount of time. {CES: Q4(b)} Information supplied was >60% 75% satisfactory. {CES: Q8(b)} PowerNet first choice to contact >35% 8% for faults. {CES: Q6} Voltage Complaints Number of customers who have <30 14 {Reported in Network made voltage complaints
16 CES = Customer Engagement Survey of 100 customers, undertaken by phone in January – February 2010 by Gary Nicol Associates. 17 None of those surveyed had contacted PowerNet Otago office. 18 CSS = Customer Satisfaction Survey undertaken by sending questionnaire to customers with invoices.
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Attribute Measure YE 31/3/10 Actual report.} Number of customers who have <15 13 justified voltage complaints regarding power quality Average days to complete <30 9 investigation Period taken to remedy justified <90 34 complaints Planned Outages Provide sufficient information. >75% 93% {CES: Q3(a)} Satisfaction regarding amount of >75% 96% notice. {CES: Q3(c)} Acceptance of maximum of >50% 97% three planned outages per year. {CES: Q1} Acceptance of planned outages >50% 85% lasting fours hours on average. {CES: Q1} {Where the information is collected / reported from.}
9.2.3 Other service levels 9.2.3.1 Efficiency Good results with only Load factor just over the target, mostly due to the introduction of Transmission Pricing Methodology (TPM) changing how OtagoNet controls the network-wide peak. Note that the new Information Disclosure requirements have changed the capacity utilisation factor, by adding an estimate of customer owned distribution transformers.
Measure 2009/10 AMP Target Actual Comment Load factor 79% 78% Loss ratio 7.0% 7.1% Dependant on Retailer accruals Capacity utilisation 38% 31.8% Includes Non-OtagoNet transformers not targeted in 2008-18 AMP
9.2.3.2 Financial
Measure 2009/10 AMP Target Actual Comment Direct costs $1039.24 Not done in Information Disclosure now, new factor proposed is OPEX %. Indirect costs $38.36 $102.32 New definition in Information Disclosure Total financial costs are close to target. 9.3 Improvement areas and Strategies [Addresses handbook requirement 4.5.8(c)] The following areas are highlighted as gaps in performance that could be improved, and the strategies proposed to achieve improvements. OtagoNet plans to improve its AMP in the future by improving the asset management processes, systems and activities that it uses / undertakes.
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9.3.1 Maintenance and Capital Works Gaps: Overspend and delays with projects. Discussion: Increased investment in maintenance and renewal work is required to improve network performance as there has been no discernable improvement in SAIDI and SAIFI figures. The average age of the network assets is also only being maintained by present investment levels and an increase is required to address the average age of the network and the increasing contractor and material costs. Strategies: We plan to create a long term relationship with contractors so they can build their resources and personnel. This will allow more work to be completed and ensure a resource for future years. We will continue to forward plan projects so that resource requirements are better defined and works can be effectively scheduled. We will bring design and planning back ‘in-house’ to improve timing on projects and provide better control on implementation. 9.3.2 Reliability Gaps: Decline in reliability level. Discussion: The achieved reliability level of SAIDI and SAIFI is poor even considering the geographical size and diversity of the network. Increased maintenance and renewal together with greater vegetation control and further adoption of live line working will improve the network performance over time. Strategies: We will create a long term relationship with contractors so they can build their resources and personnel, so that the restoration of supply is done effectively. We will continue to regularly inspect the network and action critical items as they are identified. We will increase number of remotely controlled devices to speed isolation of faulty sections and restoration of supply to healthy sections. 9.3.3 Efficiency Gaps: Low transformer capacity utilisation. Reduce losses to improve efficiency. Discussion: Capacity utilisation is low, but not unexpected for a largely rural network using lightly loaded 15kVA transformers. As more of the older 3, 5 and 10kVA transformers are replaced with the minimum standard 15kVA unit, the capacity utilisation will decline further.
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Strategies: We will check utilisation and efficiency19 of transformers during network upgrades or replacements, with a rationalisation of their capacities. Underutilised units will be relocated to match loads. Overloaded transformers will also be rationalised to improve their efficiency but this has a negative impact on the utilisation. We will review the demand of customers that own their own transformers and contact them if we believe that there is a concern. Analysis of highly loaded lines and cables has highlighted sections that have high losses, up-sizing of these to larger conductor or a higher voltage will improve the loss ratio of the network. The level of losses normally doesn’t initiate the change but is used when selecting sizes when work is done on the equipment.
19 The poor efficiency of old transformers may warrant scrapping rather than refurbishment.
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APPENDIX - CONSUMER ENGAGEMENT SURVEY
A. Appendix - Customer Engagement Survey
PowerNet Consumer Engagement Telephone Survey: OtagoNet © Gary Nicol Associates 2009
Phone Date Interviewer
Good afternoon/evening my name is _____. I am conducting a brief customer survey on behalf of PowerNet. May I please speak to a person in your home who is responsible for paying the electricity account? (Reintroduce if necessary) May I trouble you for a few minutes of your time?
A1: Do you know who Yes 1 Go to A2 PowerNet is? No 2 Go to A3
A2: Using a 1 to 5 rating Caring for customers 1 2 3 4 5 X scale where 1 is Poor and Sensitive to the environment 1 2 3 4 5 X 5 is Excellent can you rate the performance of Supporting the community 1 2 3 4 5 X PowerNet over the last 12 months for: Safety conscious 1 2 3 4 5 X
Go to D1 Efficiency 1 2 3 4 5 X
A3: PowerNet maintains the local electricity lines and substations that supply power to your premises.
D1: Do you live in a mainly rural or Urban 5 urban area? Rural 6
D2: Are you a commercial or residential Commercial 1 customer? Residential 2
Question 1: PowerNet is proposing a Yes 1 Go to Q 2 maximum of one planned interruption to your power supply, on average, every No 2 Go to Q 1(a) year in order to carry out maintenance or upgrade work on its electricity network. Don’t know/unsure 3 Go to Q 2 Do you consider this number of planned interruptions to be reasonable?
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2 years 1 Question 1(a): How many years between planned interruptions do you 3 years 2 consider to be more reasonable? 4 years 3
Question 2: PowerNet expects such Yes 1 Go to Q 3 planned interruptions will on average last up to four hours each. No 2 Go to Q 2(a) Do you consider this amount of time to Don’t know/unsure 3 Go to Q 3 be reasonable?
1 hour 1 Question 2(a): What length of time would you consider to be more 2 hours 2 reasonable? (Specify hours) 3 hours 3
Yes 1 Go to Q 3(a) Question 3: Have you received advice of a planned electricity interruption No 2 Go to Q 3(e) during the last 6 months? Don’t know/unsure 3 Go to Q 3(e)
Yes 1 Go to Q 3(c) Question 3(a): Were you satisfied with the amount of information given to you No 2 Go to Q 3(b) about this planned interruption? Unable to recall 3 Go to Q 3(c)
Question 3 (b): What additional information would you have liked?
Yes 1 Go to Q 3(e) Question 3(c): Do you feel that you were given enough notice of this No 2 Go to Q 3(d) planned interruption? Don’t know/unsure 3 Go to Q 3(e)
Question 3(d): How much notice of 1 day 1 1 week 4 planned interruptions would you prefer to be given? (Specify days/weeks) 3 days 2 2 weeks 5 (Do not prompt) 5 days 3 Other 6
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Question 3(e): Do you have a preferred Yes 1 Go to Q 3(f) day and time(s) for a planned interruptions? No 2 Go to Q 4
Question 3 (f): What is your preferred day and time(s)?
Yes 1 Go to Q 4(a) Question 4: Have you had an unexpected interruption to your power No 2 Go to Q 5 supply during the last 6 months? Unable to recall 3 Go to Q 5
Within 45 min 1 3 hours 5 Question 4(a): Thinking about the most recent unexpected interruption to your 1 hour 2 4 hours 6 electricity supply, how long did it take 1 for your supply to be restored? 1 /2 hours 3 12 hours 7 (Specify hours/days) 2 hours 4 Don’t know 8 (Do not prompt) Other 9
Yes 1 Go to Q 5 Question 4(b): Do you consider your electricity supply was restored within a No 2 Go to Q 4(c) reasonable amount of time? Unable to recall 3 Go to Q 5
1 Question 4(c): What do you consider 30 minutes 1 1/2 hours 4 would have been a more reasonable amount of time? (Specify hours/days) 45 minutes 2 2 hours 5 (Do not prompt) 1 hour 3 Other 6 Go to Q5(a)
5 minutes 1 2 hours 10
10 minutes 2 3 hours 11 Question 5: In the event of an 15 minutes 3 4 hours 12 unexpected interruption to your electricity supply, what do you consider 20 minutes 4 5 hours 13 would be a reasonable amount of time before electricity supply is restored to 30 minutes 5 6 hours 14 your home? 40 minutes 6 12 hours 15 (Specify hours/days) 45 minutes 7 1 day 16 (Do not prompt) 1 hour 8 Unsure 17
1 1 /2 hours 9 Other 18
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Question 5(a): PowerNet is reviewing the level of service provided to its Yes 1 customers and options include increasing spending. Presently there is No 2 an average of four interruptions each year. If this was reduced to three interruptions per year would you be happy to pay an additional $10 per Don’t know/unsure 3 month on your electricity bill?
Meridian Energy 1
Question 6: Who would you contact in Contact Energy 2 the event of the power supply to your home being unexpectedly interrupted? Mighty River Power 3 TrustPower 4 (Do not prompt) PowerNet 5
Other 6
Yes 1 Go to Q 8 Question 7: Have you made such a call No 2 Go to Q 8(d) within the last 6 months? Unable to recall 3 Go to Q 8(d)
Question 8: Were you satisfied that the Yes 1 Go to Q 8(b) system worked in getting you enough No 2 Go to Q 8(a) information about the supply interruption? Don’t know/unsure 3 Go to Q 8(b)
Question 8 (a): What, if anything, do you feel could be done to improve this system?
Yes 1 Go to Q 8(d) Question 8 (b): Were you satisfied with No 2 Go to Q 8(c) the information that you received? Don’t know/unsure 3 Go to Q 8(d)
Question 8 (c): What, if anything, do you feel could be done to improve this information or the way in which it is delivered?
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Question 8 (d): What is the most Accurate time when 1 important information you wish to power will be restored receive when you experience an unplanned supply interruption? Reason for fault 2 (Do not prompt) Other 3
Question 8(e): Are you aware of Yes 1 No 2 PowerNet’s 0800 faults number?
Question 9: Have you contacted Yes 1 Go to Q 9(a) PowerNet regarding any other issues No 2 Go to Q 9(e) relating to your electricity supply during the last 6 months? Unable to recall 3 Go to Q 9(e)
Voltage complaints 1
Question 9(a): What did your enquiry Safety disconnections 2 relate to? New or altered supply 3
(Do not prompt) Trees near lines 4 Other 5
Yes 1 Go to Q 9(d) Question 9 (b): Were you satisfied with the performance of the PowerNet staff No 2 Go to Q 9(c) member(s) who handled your enquiry? Don’t know/unsure 3 Go to Q 9(e)
Question 9 (c): Specifically what were you dissatisfied with?
Question 9 (d): Was there anything that PowerNet did well?
Question 9 (e): What if anything do you feel could be done to improve the service provided by PowerNet staff?
This concludes our survey - Thank you for your time
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APPENDIX - DESCRIPTION OF OUR ASSETS
B. Appendix - Description of the assets This appendix extends the descriptions of the assets in detail. B.1 Subtransmission The natural split of this group is into overhead tower circuits, overhead pole line circuits and cable circuits. Any particular circuit from A to B may be a mixture of these forms. Overhead lines may be multi circuit or be common with lower voltage circuits. Maintenance planning differences are more a function of circuit form than circuit voltage. Subtransmission includes all circuits “upstream” of a zone substation. Effectively these circuits bring electricity to whole communities of interest and are therefore more critical than distribution circuits. The arrangement of these circuits is very much dependent on geography and history. The required reliability varies according to the security available with the associated network configuration. Supply security and reliability are defined in the Network Design Standard. Subtransmission design varies considerably between the networks. The OtagoNet subtransmission consists mainly of overhead pole lines with some short lengths of cable to enter or exit the confined areas around substations. Only Charlotte Street, Finegand, Elderlee Street and Ranfurly have full duplication of subtransmission circuits. The tie between Palmerston and Ranfurly offers multiple paths to Deepdell, Hyde and Waipiata between them. B.1.1 Pole line circuits B.1.1.1 Description and capacity Pole overhead lines form the majority of subtransmission circuits within rural Otago. These consist of unregulated 33kV or 66kV circuits of a capacity specifically chosen for the anticipated load. The dominant design parameters are voltage drop and losses. Almost exclusively the current loading is well below capacity. Voltage drop is a problem due to small conductor and long circuit lengths. EHV regulators are needed on the OtagoNet system partly because the subtransmission system is also used as distribution. On a voltage and loss basis most circuits operate between 80% and 150% of optimum level. Most subtransmission line circuits are routed cross-country to minimise cost and length. More recent circuits tend to be constructed along roads due to the stifling nature of recent legislation. Poles are a mixture of concrete, hardwood and softwood, chosen by the relative economics at the time of construction. Rural lines are typically sagged to a maximum operating temperature of 75°C to maximize capacity and minimise cost. Some of the circuits have substantial design drawings and route plans, a reflection of their importance. The majority of circuits shown in Figure 8 are overhead lines in this category. The poles and conductors are listed within the GIS system in the same fashion as lower voltage circuits. B.1.1.2 Condition, age and performance Only part of the original subtransmission network remains. Upgrading, rebuilding and piecewise maintenance has replaced many of the circuits originally installed before 1950. The age profile of transmission circuits is shown in Figure 11. Since most transmission circuits are of overhead line construction this graph gives a good indication of overall circuit age. Note however that many circuits have poles and other hardware replaced when and were needed. Consequently the age of circuits is difficult to precisely state.
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The subtransmission fault rate is averaging 1.8 faults/100km/per annum. This rate is 59% and 33% of the MV SWER lines and Non-SWER MV line respectively. B.1.1.3 Monitoring and procedures Dominant failure modes are pole and crossarm deterioration, tree contact, conductor corrosion, ties/clamps, joints and insulator cracking. Visual inspection is conducted annually to locate obvious problems. These are rectified dependent on the urgency. Defect inspection and pole testing are conducted at 5 yearly intervals on a rolling basis. This includes checks of foundation, pole integrity, crossarm condition, faulty hardware and insulator condition. Part of the inspection includes the diagnostic techniques of ultrasonic survey and thermal imaging. This inspection is the prime driver for maintenance planning. Fault data is used for abnormal problems. Protection relay data (distance to fault) is used where available to help locate faults and subsequently identify fault cause. Detailed analysis of outages and their cause using Root Cause Analysis (RCA) identifies target areas for maintenance programs. B.1.1.4 Maintenance plan A program to replace cross arms and insulators on certain lines is in place as appropriate on those lines that do not require capital replacement. B.1.1.5 Replacement plan See the capital works plan for details of subtransmission circuit replacement. B.1.1.6 Disposal plan There are no plans for any disposal of tower circuit assets. B.2 Cable circuits B.2.1.1 Description and capacity The Otago network has only 1.4km of 33kV cable, these are around the Transpower Balclutha Charlotte Street substations where the overhead line congestion requires it. The cables at Transpower are 240mm² AL XLPE and 33 years old and at Charlotte Street they are 95mm2 AL XLPE and 13 years old. Additional cables were installed in 2007 with the installation of the 33kV switchboard. There is also a six year old section of 95mm2 AL XLPE cable installed on the Patearoa 33kV line to bypass an irrigation system B.2.1.2 Condition, age and performance See the four discrete installation date above. There are no known problems associated with the cables. The cable sizes match the associated lines and substations to which they connect, so are well utilised. B.2.1.3 Monitoring and procedures Dominant failure modes for cables are joint or termination faults, sheath damage, overheating and external mechanical damage. Generally cables are very stable and require little attention, particularly these short lengths without any in line joints. B.2.1.4 Maintenance plan There are no plans for any significant cable maintenance. B.2.1.5 Replacement plan There are no plans for any replacement of subtransmission cables.
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B.2.1.6 Disposal plan There are no plans for any disposal of cables. B.3 Zone substations B.3.1 Substations general B.3.1.1 Description and capacity There are 32 zone substations in the OtagoNet network and these are listed in Table 7. These stations vary considerably from installations with indoor switchgear and dual transformers to single outdoor circuit breaker and transformer rural substations. The prime general functions of the stations are to house the transformers, switchgear and associated controls. B.3.1.2 Monitoring and procedures The stations consist of buildings, fences, yards and similar exposed items similar to other industrial sites. Monitoring consists of monthly checks to identify obvious problems such as broken windows, weeds, damaged security fencing. Routine maintenance such as spraying is conducted in conjunction with monitoring. Yearly inspections are undertaken for forward planning, at which time such activities as painting, spouting, rusting problems are identified. The standard required is as would be expected for domestic or industrial building. Station batteries have resistance checked yearly and are replaced as per the manufacturers recommendation. They are also replaced at 10 years age on assumption that failure rates increase significant at this age. Electromechanical protection relays are tested on a 5 yearly basis due to general drift and wear of the mechanical bearings etc. They are also being replaced with electronic relays in conjunction with circuit breaker replacement. The preferred relays are the Schweitzer Engineering Laboratories range chosen on a reliability, flexibility and functional basis. SCADA is generally maintained on a repair basis due to the random basis of failure. Outdoor structures are checked as part of the monthly inspections. Yearly visual inspections are undertaken to assess overall condition and list any action required. Yearly ultrasonic and thermal imaging tests are done to identify failed insulation or high contact resistance. B.3.1.3 Maintenance and replacement plans Maintenance is of a routine nature with no significant activity expected. There are no plans to replace any existing buildings or sites.
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B.3.2 Transformers B.3.2.1 Description and capacity These vary significantly in both size and detail. They range from 12.5/25MVA 33/66kV three phase units complete with On Load Tap Changers (OLTC) at Ranfurly to simple 750kVA fixed tap transformers at rural substations. The zone substation transformers have two main purposes. Firstly they are required to “transform” the higher subtransmission voltages to more usable distribution voltage and secondly they are required to regulate the highly variable higher voltages to a more stable voltage at distribution levels. At simple substations with fixed tap transformers there is an associated voltage regulator, usually on the 11kV output of the transformer. Several issues should be noted. The rating is obviously important. The transformers must be suitable to withstand the load imposed upon them. This is generally stated as the ONAN (Oil Natural, Air Natural) level at which losses are optimised and no special cooling is required. To allow for maintenance or faults transformers are often installed in pairs. Typically they share the load and operate within their economic ONAN level. Should one transformer not be in service then the remaining transformer can carry the total load. Fans and pumps are needed to dissipate heat and the life may be reduced. The rating at this level is called OFAF and may be twice the ONAN rating. Transformers are often relocated to optimise use as load varies at the various sites. Consequently the transformers are well utilised. Phasing of the transformers is important to allow paralleling of the network. All of the transformers therefore have Dyn11 vector for 33/11kV and Yyn0 for 33/66kV. For larger transformers On Load Tap Changers provide a less expensive regulation method than separate Regulators except for the smallest substations using a simple 33/11kV transformer up to 1.5 MVA. The high cost of the larger transformers has driven the installation of comprehensive protection systems for the transformers. The OtagoNet transformers are also well utilised at around 85% based on 11kV load transformers only. B.3.2.2 Monitoring and procedures Most transformer deterioration is assumed to be time based, with the exception that tap changing equipment wears proportionately to the number of operations. Monthly visual inspection is undertaken to check for obvious problems such as oil leaks. Yearly inspections are done to check fan control operation, paint condition and obtain oil samples for Dissolved Gas Analysis testing. Routine transformer maintenance is done on a 5 yearly basis. This covers protection relay operation, insulation levels and instrumentation checks.
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Tap Changer maintenance is done on a time and/or operation basis as per manufacturer’s recommendations. Dissolved Gas Analysis results are checked for trend changes and against industry standard absolute levels. Action is taken as recommended by the testing agency. Insulation trend is used to trigger further more specific action. Transformers are sometimes moved as part of utilisation planning. B.3.2.3 Maintenance plan There are no plans for any significant transformer maintenance. All work consists of routine inspection and maintenance. B.3.2.4 Replacement plan Six 2.5MVA transformers have been replaced last two years with a seventh unit being replace at Lawrence in 2010. This AMP shows further replacements at other substations as unit’s age. It is also possible that future load growth may require upgrading of existing transformer capacity. B.3.2.5 Disposal plan Of the six transformers displaced above, four were scrapped. The ex Kaitangata (2.5 MVA OLTC Dyn11) has been retained for use as a spare and the ex Ranfurly transformer was refurbished and transferred to Middlemarch. B.3.3 Switchgear B.3.3.1 Description and capacity Four general group types of switchgear are in use in the networks covered by PowerNet:
• The majority of 33kV and 66kV circuit breakers are outdoor units mounted on stands in conjunction with associated current transformers. Many types and ratings are in use. This equipment is purchased on a case-by-case basis, generally on a lowest price tender basis. Minimum oil, vacuum and SF6 units are in use. Ratings vary from 200A to 2000A, although load is typically in the range of 20A to 630A. Most operating mechanisms are dc motor wound spring to allow operation de- energised. There are a number of “recloser” type units in service although these are limited in number because of the directional limits of solenoid closing. • Charlotte Street has an indoor 33kV Schneider switchboard with seven circuit breakers and a bus section switch. • Three 11kV indoor switchboards are Reyrolle of various vintages and two smaller substations, Patearoa and Lawrence have Holec Xiria and SVS units for their 2.5 MVA single transformers and two and three feeders respectively. • Most of 11kV outdoor circuit breakers consist of pole mounted outdoor units with integral current transformers. Many of these are solenoid operated reclosers. Note that current transformers are generally assumed to form part of the switchgear, but outdoor isolators etc are lumped in with the general structure.
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The dominant circuit breaker rating is 630A continuous and 12kA or 13kA fault break capacity. Few circuit breakers are loaded over 200A due to the nature of the network. The main purpose of a circuit breaker is to allow switching of high energy circuits and more specifically to switch open (i.e. break) faulted circuits automatically by the use of associated protection devices. A few circuit breakers at the source ends of lines would be adequate to protect the lines from a safety point of view. Unfortunately faults are bound to occur on lines no matter how well maintained the lines are. If a large length of line were protected by a very limited number of circuit breakers then the reliability at any particular installation would be completely unacceptable. To achieve reasonable reliability on the network PowerNet have adopted a guideline such that no more than 40km of line is connected between circuit breakers for circuits near the coast. This figure increases to 100km inland where fault density is less. The large length of lowly loaded line circuits in the Otago hinterland has resulted in a large number of lightly loaded field circuit breakers being installed. These are included together with substation circuit breakers as a single logical grouping. Based on load capacity the circuit breakers are very much underutilized. Based on the more important safety and reliability parameters there is no doubt that more circuit breakers should be installed in specific areas. B.3.3.2 Monitoring and procedures Circuit breakers are assumed to deteriorate in a time based fashion with regard to general corrosion and mechanical faults. Experienced has indicated that circuit breakers with oil based arc quenching require significant maintenance following relatively few fault clearing operations. Literature and manufacturer recommendations suggest that vacuum and SF6 devices are not impacted as greatly based on fault breaking current. PowerNet does not have significant data on current breaking levels for individual switching operations. Consequently routine maintenance is carried out at two yearly intervals for oil base circuit breakers and five years for vacuum and SF6. Some circuit breakers are maintained following a specific number of operations. Routine substation inspections are used to check for corrosion, external damage and the like. Maintenance is specific to the requirements. Outdoor units may require sand blasting and painting as determined from inspections. Time based maintenance generally covers correct operation, timing tests, insulation levels and determination of contact life, Contacts or vacuum bottles are replaced as per the manufacturer’s recommendations. B.3.3.3 Maintenance plan There are no plans for any significant switchgear maintenance. All work consists of routine inspection and maintenance. B.3.3.4 Replacement plan No individual units are planned for early replacement, but a new indoor switchboard is planned for Waipiata as part of upgrading the substation for load growth in the coming year. Merton and Elderlee Street substations are also planned for replacement during
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the planning period, requiring new indoor switchgear. Circuit breakers and associated protection systems are planned to be installed to protect the most expensive transformers. B.3.3.5 Disposal plan
Oil and SF6 gas are reclaimed. Useful spare parts are retained. The contractor scraps the remainder. B.4 Distribution circuits B.4.1 Overhead lines B.4.1.1 Description and capacity Overhead lines form the backbone of the rural networks. These form the basis of getting the centralised bulk generation to the multitude of individual customers. The lines account for the largest proportion of rural network costs and interference to customer supply. Most lines are rated at 11kV phase to phase. This is the most common voltage utilised for distribution within New Zealand and has been the standard used in most of Otago since the inception of reticulated electrical supply. A few circuits have been built at 22kV. This voltage has four times the capacity of 11kV and greatly reduces voltage drop and losses. There is generally a 7% cost penalty in using this voltage over 11kV, so implementation is limited. There are a few other voltages used specifically in conjunction with SWER. The majority of feeder lines are three wire three phase with all connections phase to phase. A significant part of the OtagoNet lines reduce to two wire single phase circuits. Single Wire Earth Return (SWER) is used on the more remote parts of the OtagoNet system. SWER accounts for a large proportion of the Otago rural line length. Our new standard concrete pole is 11m long with a transverse top load capacity of 22kN. A typical softwood pole is 11m 9kN symmetric top load capacity. 12m, 6kN and 12kN poles are also relatively common. Common conductors previously used are relative small such as: Squirrel, Dog, Mink, Dog and Cockroach. The present AAAC standard allows for five conductors for most situations:
Conductor Name Current Rating Resistance Chlorine 150A 0.86Ω/km Helium 250A 0.38Ω/km Iodine 350A 0.24Ω/km Neon 500A 0.12Ω/km Oxygen 700A 0.09Ω/km B.4.1.2 Condition, age and performance Bulk electrical distribution within Otago generally commenced around 1930. Lines are up to 70 years old. Most construction was undertaken in the 1930’s, 1950’s and 1960’s. The 1970’s and 1980’s extensions were generally to transmit larger levels of energy into the existing reticulated areas. Present new construction levels are very low. Consequently there is quite a range of material and construction types. Hardwood poles gave way firstly to concrete and then largely softwood until early 2008 when the standard was changed to the Busck concrete pole manufactured in a dedicated facility
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in Invercargill. Copper conductor was very common. This was generally replaced by AAC and ACSR conductor (All Aluminium Conductor and Aluminium Conductor Steel Reinforced) based on a lesser cost. The present standard is AAAC1120 (All Aluminium Alloy Conductor) based on price and resistance to corrosion. Maintenance requirements vary by material. Poles are the critical and most expensive component of line support. Most construction in the 1930’s utilised hardwood poles because of availability and strength. Hardwood poles cannot be effectively treated and are therefore prone to rot. Rot is worst in the biologically active ground area. Rot is often not visible, such that many poles that appeared healthy were in fact very prone to failure. Typical life expectance of hardwood poles varies from 30 years to 70 years. Around 20% of poles are hardwood. Structurally the poles are very good, but cost and life expectancy limit hardwood pole usefulness. Concrete poles became prevalent in the 1950’s. The strength of these poles was very limited and failure from abnormal overload such as snow loading can be a problem. They do not suffer from significant deterioration so maintenance requirements tend to be limited. From 1991 to 2008 softwood poles were introduced based on cost and strength. These are treated timber with a minimum life expectancy of 50 years. Long term durability has yet to be confirmed. New concrete poles became the standard from 2008. The new design provides improved strength and expected long life. Cross arms are generally hardwood and suffer from significant deterioration. Life expectancy varies, but since they are not in contact with the ground a minimum life of 40 years is expected. A few lines have been constructed in armless format, but generally this form does not have acceptable mid span clearance. For most distribution lines hardwood cross arms remain the preferred form. Conductor life is limited by vibration (excessive tension) and corrosion. Copper conductor is robust, but very expensive. ACSR conductor is prone to corrosion especially in coastal areas. All Aluminium Alloy Conductor has been chosen as a standard conductor that is expected to limit maintenance requirements of line conductor. The age profile of poles is shown in Figure 16. B.4.1.3 Monitoring and procedures Overhead distribution lines are the dominant feature of rural networks. With poles numbering over 40,000 and conductor length over 3,000km the largest proportion of capital is tied up in these assets. Consequently cost effective procedures have been introduced to optimise the balance between cost, safety and reliability. The PowerNet inspection and maintenance regime is aimed at the identification and rectification of defects which have the potential to cause outages or which threaten safety. The following specific procedures are extracted from the Lines Services Contracts Scope of Works. Strategies Focus should be on:
• Higher priority will be given to those 33/66kV and 11kV circuits that have a greater potential to adversely affect SAIDI figures. • Factors adversely affecting SAIFI and the number of faults per kilometre of line to allow subsequent appropriate targeting of maintenance using RCM strategies on areas that significantly impact reliability indices.
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• Issues affecting public safety and the safety of employees working on the network using CDM strategies. • Meeting legislative requirements for test and inspection criteria. Inspection Regime General The Scope of Work generally describes the requirements for inspections of the subtransmission and distribution networks using visual and diagnostic techniques (i.e. ultrasonic surveys, thermal imaging) and includes: Inspections of all the equipment listed, including 5 yearly circuit inspections, 6 monthly transformer inspections/MDI recording and earth testing. Upgrading of earths is not included in the scope but may be added at a later date. Annual inspections of certain circuits selected due to their low reliability and/or high importance. The bidder will include in its response its proposed methodology in implementing the required strategies and any enhancements that may be beneficial. PowerNet and the Contractor(s) will jointly review the inspection regime and the annual program to ensure best practice is being employed. Methodology The PowerNet inspection and maintenance regime is aimed at the identification and rectification of defects which have the potential to cause outages or which threaten safety. The SAIFI and SAIDI performance of each 11kV feeder and 33/66kV circuit will be analysed quarterly and classified as being either Level 1, 2 or 3. Those in Level 1 will be passed to a team consisting of PowerNet and Contractor’s staff for a detailed root cause analysis and to establish an inspection and maintenance strategy. Those in Level 2 will be discussed by the team to reach an agreed maintenance strategy and will then be closely monitored by PowerNet System Control. Level 1 represents the worst performance. The table below provides an indication of the inspection and maintenance regime.
• Defect Inspection This detailed route and equipment inspection, generally conducted from ground level and includes an ultra-sound inspection. For the five yearly inspection cycle 20% of the feeders/circuits in the Contract Area are inspected every year, as part of the cycle and included as part of the lump sum cost.
• Targeted Inspections Selected feeders/circuits, including those in Level 1 and those supplying important CBD and industrial areas, may require more frequent inspections. The frequency of these inspections will be decided on a reliability basis and completed as a reimbursable cost. Use of a helicopter may be approved in some rural situations.
• Annual Inspections These are rapid patrol generally achieved by a drive-by, although CBD cable routes may require a walk-by to identify any recent works that may affect cable performance. The object is to identify any obvious defects that may impact network reliability in the short term (two years). For example: leaning/damaged poles; unbalanced/excessive sags; leaning insulators; loose ties and/or hardware; excavations near poles; clearances from ground, buildings, trees; damaged crossarms, lightning arrestors, insulators; ground mounted equipment: cable protection and terminations; and similar items. Included as part of the lump sum cost.
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• Thermal Inspections Generally carried out at times of peak load on the network in order to identify hot connections. A thermal inspection of connections on CBD, industrial and urban feeders may be required within three days of a heavy fault near a substation. Unit rates per kilometre of overhead line and per site for ground mounted equipment are to be provided. Inspections are to be grouped for efficiency and an estimate of costs prepared prior to commencement.
• Ultra-Sound Inspections To be carried out in conjunction with Defect Inspections and Thermal Inspections.
• Wood Pole Tests PowerNet owns a Foley AIME WoodScan equipment that will be made available to the Contractor(s) for the purpose of testing wood (hardwood and softwood) poles. The use of this equipment will be subject to a lease agreement between the Contractor(s) and PowerNet. The Contractor(s) must have at least two staff trained in the use of the equipment. The criteria for selecting poles to be tested are wood poles over 10 years old that have not been tested in the previous five years, or any pole the Contractor(s) believe to be in danger of imminent failure. A unit rate per test is to be provided on the basis of a specific agreed number of poles.
• Pole Top Inspections This inspection is to identify any defects in the pole head, crossarm, insulators, tie wire and associated hardware, connections and terminations, as required. A unit rate per kilometre of overhead line is to be provided. Inspections are to be grouped for efficiency and a cost estimate prepared prior to commencement.”
Level 1 Level 2 Level 3 CBD and Thermal inspection on fault All incidents Level 1 Annual thermal inspection at Major route peak loads, including link Industrial < 7 day response and boxes correction of urgent defects Annual cable route inspection < 3 month correction of 5 yearly defect inspection non-urgent defects < 6 month correction of non- No loss of 11kV supply urgent defects No loss of 11kV supply Industrial Thermal, ultra sound and All incidents Level 1 Annual thermal inspection at defect inspection peak loads < 1 month response and 5 yearly defect inspection, LL correction of urgent defects pole top inspection and pole live line (LL) test < 3 month correction of < 6 month correction of non- non-urgent defects urgent defects No loss of 11kV supply Urban Thermal, ultra sound and Thermal inspection Annual Inspection defect inspection following heavy fault 5 yearly thermal and defect < 1 month response and Defect inspection inspection and pole test correction of urgent defects Defect correction LL 10 year LL pole top LL < 6month correction of inspection < 3month correction of non- non-urgent defects 12 month correction of non- urgent defects urgent defects Rural Defect inspection Defect inspection Annual Inspection < 2 month response and < 2 month response 5 yearly defect correction of urgent defects and correction of urgent inspection/pole test LL defects LL 12month correction of non- < 6month correction of non- < 6month correction of urgent defects Asset Management Plan Page 141 of 151
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urgent defects non-urgent defects
B.4.1.4 Maintenance plan A significant volume of maintenance is planned, too numerous to detail within this document. B.4.1.5 Replacement plan Few lines are replaced in entirety solely based on maintenance requirements. Most lines are like the proverbial axe that was two hundred years old. It had its head replaced twice and the handle replaced ten times. In theory it was 200 years old. In practice it was much less. Lines, in common with most network equipment, consist of many components of varying age. Complete replacement is usually triggered by capacity upgrade requirements or similar. Significant capital works are listed elsewhere. B.4.1.6 Disposal plan Since no lines are being replaced under maintenance, there are no lines that require disposal. However a significant amount of material does become redundant. This typically has little value and is not suitable for reuse, since it is component level material that has deteriorated beyond use. B.4.2 Distribution cables B.4.2.1 Description and capacity Most cables in OtagoNet network tend to be one or three core aluminium conductor, XLPE insulated, medium duty copper screen and HDPE sheath. This is the present cable standard used in all of the PowerNet networks. Because of the very short circuit lengths generally associated with cable supply, voltage drop is seldom a problem. So design limits tend to be that of the cable current rating. XLPE cables operate acceptably at significantly higher temperatures to paper insulated cables. Therefore the current rating is higher with XLPE giving a more economic cable form. The standard sizes and typical ratings of cables are listed below.
Cable type Current Rating Resistance 1 x 3C 35mm2 Al XLPE 135A 0.868Ω/km 1 x 3C 95mm2 Al XLPE 240A 0.320Ω/km 1 x 3C 185mm2 Al XLPE 320A 0.164Ω/km 3 x 1C 300mm2 Al XLPE 420A 0.100Ω/km Rating is very much affected by the thermal parameters of the surrounding media. Most distribution cables are direct buried to limit temperature rise associated with ducts. Backfill material is almost always the removed material, so no control is available over thermal resistively. Most backfill tested appears to have similar characteristics to the standard quoted figures. Lightning protection (surge diverters) is fitted where cables terminate to overhead lines. Lightning is a dominant cause of cable failure. B.4.2.2 Condition, age and performance The OtagoNet network is predominately overhead distribution with limited short lengths of 11kV cable being installed in recent years. Failure of cable is very rare. The most common failure modes are joints, terminations, lightning and external mechanical damage. Consequently little proactive maintenance is deemed necessary on the cables themselves.
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B.4.2.3 Monitoring and procedures Little monitoring is conducted on cables. Most processed involving cable is involved with loading and circuit arrangement. Failure analysis is the prime tool utilised to identify possible maintenance or remedial action. B.4.2.4 Maintenance plan Several types of cable termination have been identified as a common cause of failure. The breakout arrangements on these terminations are being replaced. B.4.2.5 Replacement plan There are no plans to replace existing cables. B.4.2.6 Disposal plan No cables have been identified for disposal. B.4.3 Distribution switchgear B.4.3.1 Description and capacity Distribution switchgear used in the Southern region can be classified into four forms. The most common switch is in fact a fuse that can be used to switch, isolate and protect equipment. Around 10,000 MV fuses are in service in sets of 1, 2 or 3. The most common fuse is the Drop Out fuse rated up to 100A. These are the preferred type because of fault rating and clearly visible break point. A number of glass fuses and sand filled porcelain are still in use, but are generally replaced during significant maintenance work. Fuses are fitted at transformers, on MV service mains and quite a number of lateral circuits. The majority of true switches, generally in rural areas, are pole mounted Air Break Switches (ABS). There are approximately 300 switches in service. They are generally rated 200A continuous capacity or 400A. Most are in fact more correctly called isolators because their load breaking capacity is in the range of 10A to 20A. 10% of these switches have load break heads that allow the switch to break rated load. A few enclosed units are being trailed. 10 outdoor Ring Main Unit switches are in service manufactured by ABB (SDAF series) and Merlin Gerin (Ringmaster series). These are associated with transformers and located with them. At present there is only one example of an indoor ring main unit, the Xiria ring main unit manufactured by Holec. This is mounted within a customer’s substation building. B.4.3.2 Monitoring and procedures Experience has shown that indoor Ring Main Units require little maintenance. Routine visual inspections are conducted in conjunction with line surveys. The dominant maintenance requirement is protective painting of outdoor equipment. Outdoor Air Break Switches are also visually assessed. Major switchgear is periodically inspected with Infrared thermal cameras, which are the main method of identifying joint or contact heating problems. Unfortunately, for the majority of switchgear, failure during operation is the first indication of a maintenance requirement. Asset Management Plan Page 143 of 151
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B.4.3.3 Maintenance plan There are no plans for any specific switchgear maintenance. All work consists of routine inspection and maintenance. B.4.3.4 Replacement plan No switchgear has been specifically targeted for replacement, but a small budget is allowed for the replacement of the old glass fuses with modern 11kV drop out fuses. B.4.3.5 Disposal plan Very little switchgear is removed from service which the contractor scraps. B.4.4 Distribution transformers B.4.4.1 Description and capacity The concept of electrical transformers was central to the development of the present integrated electricity systems found throughout the world. Previous centralised generation systems were extremely inhibited due to the limits imposed by low voltage direct current utilisation. Transformers provide a relatively economic means to convert voltage and allow distribution of electricity over large areas. Distribution transformers are the present devices used to convert distribution level voltages to reticulation level voltages directly usable by customers. The majority of rural transformers supply one or two customers in close proximity. Since many rural properties are spaced kilometres apart there are a great number of customers with their own individual transformer. The most common rural transformer size is 10kVA to 30kVA. Urban customers tend to have section frontages of 20m, meaning they are in close proximity. The most economic electrical supply arrangement tends to have around 50 domestic customers connected to a single transformer. Consequently the most common urban transformer ratings are 200kVA to 300kVA. The primary side voltage ratings must match the distribution voltages. Consequently most distribution transformers have a primary rating of 11kV phase to phase. A few connect directly to 33kV subtransmission and are therefore rated at 33kV. There are a significant number of Single Wire Earth Return (SWER) transformers in the systems in the OtagoNet region. These are generally rated at 11kV or 22kV phase to ground. The secondary side voltage must be suitable for typical reticulation voltages. The secondary rating is almost always 240V phase to neutral which is equivalent to 415V phase to phase. An important point to note is that the standard New Zealand nominal LV voltage is 230V, yet 240V transformers are used. 230V is the nominal voltage with an allowable deviation of ±6%. As load is applied to a transformer the voltage always drops. Transformers are rated at the upper limit of the allowable voltage range. As load increases the voltage falls through the nominal system voltage towards the minimum allowable limit. This fine distinction has created problems, even with experts. Another item of significance that is best explained in terms of transformers is that of polyphase systems. Polyphase systems generally utilise three phases, usually being the most economic form. Two important differences exist between single phase (or direct current) and three phase systems. The three phase system has two voltage Asset Management Plan Page 144 of 151
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levels available. 230V is the voltage between any one of the three phases and the common neutral point. But 400V is the voltage between any pair of the three phases. The standard vector arrangement of distribution transformers is Dyn11. It is difficult to connect some transformers in a standard fashion. Consequently the actual 400V system vector varies. The other significant advantage of three phase supply is that the system has a sense of rotation. Motors will rotate in a direction defined by their electrical connection. Originally many rural properties utilised motors, so three phase supply was prevalent. Typical domestic requirements are met by single phase supply. Groups of urban customers are most economically supplied by connecting single phase customers to three phase transformers. Consequently there are a great variety of transformer configurations and ratings. This has significant implications for stocking levels and replacement availability. Most transformers are purchased with Off Load Tap Change (FLTC20) systems to allow some adjustment of voltage. There are four general forms of transformers. Most rural transformers in the range of 5kVA to 50kVA are pole hanger mounted. These have brackets that allow easy installation of the transformer near the pole top, giving a very economic installation. Some large outdoor transformers are still in service, mounted on specially made two pole structures. This arrangement is rather messy. These units are being replaced with ground mounted transformers over time. A third form of transformer is the kiosk unit. These are freestanding ground mount transformers that have cubicles included to enclose associated switches and terminations. These are the most common form of urban transformer. A similar form is a cable entry transformer that has no cubicles for switchgear. Cables are terminated in small termination boxes. Transformers are one of the few network assets that can be readily and uniquely tracked as individual items. Most other named items are formed of combinations of minor parts that are replaced as needed. Consequently the age of lines, for example, is in reality not really definable. With transformers, however, at least the nameplate has a manufacture date. The tank and cores may have been replaced, but a date can still be associated with each transformer. Transformers are fairly robust devices. It is economic to overhaul many units for reuse on the system. Consequently there are quite a number of old units still in use as shown in the age profile graph. Transformers have for many years been purchased on a total cost economic basis. This includes capitalization of losses. Losses now form part of the MIPS legislation that specifies maximum allowable equipment losses. Generally there is little difference between old and new transformers. B.4.4.2 Monitoring and procedures As equipment failure is not a major cause of outages most maintenance is based on inspections. Age of assets is deemed to have greater impact on maintenance requirements and inspection strategies are adjusted to allow for this. Small rural transformers are inspected together with line circuits on a five year basis. Urban transformers and large rural transformers are inspected on a six monthly basis and Maximum Demand Indicators are read where fitted. The typical maintenance requirement is for tank and bushing repair or refurbishment. This can usually be determined from the visually inspection. A five year cycle of inspection is well within typical deterioration rates. Catastrophic failure is very random in nature and no economic means are available to determine risk of failure. The six
20 On Load Tap Changer is OLTC, so use FLTC for Off Load.
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monthly inspections are largely to check for overload and problems with miscellaneous equipment such as fuse heating. Transformers are replaced on site with new or refurbished transformers. Removed transformers are individually assessed for repair, refurbishment or retirement. B.4.4.3 Maintenance plan There are no plans for any large scale maintenance of transformers. All work consists of routine inspection and maintenance. B.4.4.4 Replacement plan There are no specific plans to replace transformers, however older small units (<10kVA) are replaced in association with line replacements or maintenance. B.4.4.5 Disposal plan Oil is removed from scrapped transformers and the remainder of the transform sold as scrap metal. Bushings are sometimes kept where these may prove useful to replace damaged insulation. High loss, old, small and non standard transformers removed from service are invariably scrapped. B.5 Reticulation B.5.1 Overhead lines B.5.1.1 Description and capacity The majority of original reticulation circuits were of overhead construction, similar to 11kV distribution circuits. Most were of a flat top construction with 2 to 5 wires. Copper was the dominant conductor. The conductor size was relatively small due to the typical loading of the time. Underground reticulation became dominant for urban extensions from the 1960’s, but overhead reticulation has remained in most areas until this day. The main change in overhead construction has been the use of Aerial Bundled Conductor (ABC) since around 1990. This eliminated the need for cross arms, uses covered conductor and is generally a more reliable overhead format. The dominant bare wire conductor sizes range from 14mm2 (7/16 Cu) to 40mm2 (19/16Cu). ABC uses aluminium conductor of 35mm2, 50mm2 and 95mm2 cross- sectional-areas. Some bare aluminium conductor was used prior to the introduction of ABC. Many LV reticulation circuits are attached to 11kV poles. B.5.1.2 Condition, age and performance Most overhead reticulation is relatively old, because little of this construction is used now days. Age profiles are therefore slightly older than for 11kV lines. LV systems are more tolerant of ambient conditions than MV systems due to the much lower voltage stress imposed. B.5.1.3 Maintenance plan There are no plans for any large scale maintenance. All work consists of routine inspection and maintenance. LV overhead reticulation is managed on a similar basis to the MV distribution, although with a lesser priority.
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B.5.1.4 Replacement plan There are no plans for large scale overhead line replacements or undergrounding. B.5.1.5 Disposal plan See overhead distribution. B.5.2 Reticulation cables B.5.2.1 Description and capacity New reticulation in urban areas is now undertaken using cable circuits. Cable is generally aluminium conductor with a copper neutral screen. Standard sizes are 95mm2, 185mm2 with a small amount of 300mm2 as the maximum size. The dominant selection criterion is to limit voltage drop. Typically cables are loaded to 30% of their current capacity. The combination of aluminium cable and copper based switchgear requires rigid adherence to proper termination procedures, generally utilising bimetal compression joints. B.5.2.2 Condition, age and performance Few problems are experienced with underground cable. Most faults are due to joints and external mechanical damage. The cable network is relatively young. B.5.2.3 Monitoring and procedures Little monitoring is conducted on cables. Most processed involving cable is involved with loading and circuit arrangement. Failure analysis is the prime tool utilised to identify possible maintenance or remedial action. B.5.2.4 Maintenance plan Minor works only. B.5.2.5 Replacement plan No replacement is planned for. B.5.2.6 Disposal plan No cables have been identified for disposal. B.5.3 Service mains B.5.3.1 Description and capacity Service mains are generally the responsibility of individual customers with the demarcation point at the local pillar box. But a large proportion of rural service mains are MV. MV circuits are generally not a specialty of customers or their electricians. Consequently ownership of most MV service mains now resides with the associated network. Typical MV service mains will be of 2 or 3 wire squirrel conductor, possibly 2 to 5 spans long. In many cases there will be drop out fuses protecting both the line and the transformer. B.5.3.2 Condition, age and performance Not a lot of information is available on service mains due to past ownership changes.
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B.5.3.3 Monitoring and procedures A five yearly inspection regime is in place, as required for safety and forward planning. Similar methods are used as with the distribution circuits. This inspection is limited to circuits identified as owned by the various networks. B.5.3.4 Maintenance, replacement and disposal Little maintenance is planned. Disposal is at the whim of the individual customers. B.6 Earthing B.6.1.1 Description and capacity Earthing is a very important safety system that is often overlooked. Earthing costs are significant. Earthing comes in two general forms. In urban areas with close proximity between transformers the prime format is to ensure interconnection of earth systems to create a large equipotential grid. In rural areas the main purpose is to create a connection to earth that has a reasonable resistance and will ensure that protection will operate to clear any fault. Urban design targets limiting earth potential rise (EPR) to 650V and ensuring Touch Voltages are acceptable. 70mm2 earth conductor is used to allow for the relatively large fault currents. Rural design attempts to achieve a 10Ω earth resistance. 25mm2 conductor is used, suitable for the lower fault currents. B.6.1.2 Condition, age and performance The age profile of earth system is similar to that of transformers. Unfortunately earth systems, by definition, are in close proximity to the ground. Corrosion is an on-going problem. B.6.1.3 Monitoring and procedures A five yearly inspection regime is in place. The results are stored in the GIS system and maintenance is planned around the sites with the worst results. B.7 Ripple control B.7.1.1 Description and capacity “Ripple Control” controls a large proportion of demand side load directly or indirectly. This is a form of communications that has the highest probability of being usable at all electrical sites. Ripple control is a very slow speed communication signal superimposed on the network. Where 50Hz power flows, so does the ripple signal. Modern systems utilise 217Hz or 317Hz as the carrier signal. Older systems used 500Hz to 1000Hz, which had problems due to electrical resonance. The signals propagate similar to telephone signals. Communications theory is required to understand and analyse the operation of ripple control. Ripple systems consist of three basic sections. Firstly the load must be monitored such that appropriate control actions can be undertaken. This is done with separate SCADA equipment. Secondly a signal must be injected onto the 50Hz network. This is done with Injection Plants. And finally the signal must be detected by a Receiver that undertakes control at the individual installations. A common receiver is shown here.
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APPENDIX - DESCRIPTION OF OUR ASSETS
It is similar to a radio receiver that receives its signal not from an antenna, but from the mains wiring. One, two or three relays control equipment such as hot water heating, night store heaters and meters. The maintenance and control of receivers is intricately tied to meters. The central part of ripple control that is discussed here is injection plant. They all consist of a generator and a coupling cell. The generator was traditionally a motor/generator set. Modern generators use electronic components to convert 50Hz firstly to direct current and secondly to the required frequency. A typical rating is 100kVA at around 200V. The coupling cells vary. Those in use in the PowerNet networks consist of: (a) LV side inductor/capacitor tuning, (b) coupling transformer and (c) HV capacitors. These operate well under a large range of network configurations. Many traditional systems injected onto the 11kV busbar of each zone substation. This required a lot of injection plants. The systems within PowerNet all inject at 33kV on or near to Transpower Grid Exit Points. The signal propagates quite satisfactorily down to the zone substations on to individual LV installations. Injection plants are located at Ranfurly, Palmerston and Balclutha. They are all 33kV 100kVA. The typical signal level is 2%. The system works adequately at injection levels down to 1.4%. Ripple control has been instrumental in increasing load factor and reducing demands on the network and Transpower Grids Exit Points. B.7.1.2 Monitoring and procedures The electronics of the plants are located indoors and here is little that can deteriorate. Inspection is limited to locating obvious signs of failure. Spare parts or duplicate systems are available as backup in the case of faults. Most work involves tuning and signal level investigation that is largely influence by the network, not the injection plant. B.7.1.3 Maintenance, replacement and disposal No maintenance is planned other than routine inspection. B.8 Trees B.8.1.1 Description and capacity The network does not own trees; however they are the single most common cause of faults on the network. Consequently a lot of effort is spent on tree control and maintenance. B.8.1.2 Monitoring and procedures Trees and similar vegetation are listed within the GIS system. Procedures are in place for proper monitoring within the bounds of recent legislation. A significant amount of tree trimming is being undertaken at the expense of the networks. Once trees have been confirmed as being within specified clearances from the lines, the responsibility is placed on the tree owner for future maintenance. At that stage procedures will change to a monitoring and policing role.
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APPENDIX - ASSUMPTIONS
C. Appendix - Assumptions When developing this plan we have made the following assumptions:
• No major developments in the region, unless specifically listed. • Growth trends will be similar to historic trends. • No change in present regulation. • Distributed generation will develop slowly with little impact until after ten years. • The standard life of assets is based on the ODV asset life. • Population for sizing of equipment is based on the high projection. • No decline in meat and wool markets. • Increase in dairy markets. • Recovery in the timber market. • No major development in coal extraction and/or processing. • No major development in mineral extraction and/or processing. • Material and Labour costs only increasing by CPI.
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DIRECTOR CERTIFICATION
10. Approval by Board of Directors
We, Alan Bertram Harper and Neil Douglas Boniface, being Directors of companies which are parties to the OtagoNet Joint Venture certify that the Governing Committee has approved the disclosed AMP for the years 2011 - 2021.
31 March 2011
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