Otagonet Asset Management Plan (2014-2024)
Asset Management Plan 2014 – 2024 Clarks Substation in winter Publicly disclosed in March 2014 CONTENTS Contents 0. SUMMARY OF THE PLAN ....................................................................................................................5 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 0.10 0.11 0.12 BACKGROUND AND OBJECTIVES ......................................................................................................5 DETAILS OF THE NETWORK ..............................................................................................................6 COMPARATIVE BENCHMARKING .......................................................................................................8 RISK MANAGEMENT ........................................................................................................................8 PERFORMANCE AND IMPROVEMENT .................................................................................................9 PROPOSED SERVICE LEVELS ...........................................................................................................9 DEVELOPMENT PLANS ................................................................................................................. 10 MANAGING THE ASSET‘S LIFECYCLE .............................................................................................. 11 PROCESSES AND SYSTEMS .......................................................................................................... 12 RESOURCING THE BUSINESS ........................................................................................................ 12 REGULATORY COMPLIANCE OF THIS PLAN ..................................................................................... 12 FEEDBACK AND COMMENTS .......................................................................................................... 12 1. BACKGROUND AND OBJECTIVES .................................................................................................. 13 1.1 1.2 1.3 1.4 1.5 1.6 1.7 1.8 1.9 HISTORY OF THE NETWORK ......................................................................................................... 13 PURPOSE OF THE ASSET MANAGEMENT PLAN .............................................................................. 14 INTERACTION WITH OTHER GOALS AND DRIVERS ............................................................................ 15 KEY PLANNING DOCUMENTS AND PROCESSES ............................................................................... 16 INTERACTION OF GOALS AND STRATEGIES ..................................................................................... 19 PERIOD COVERED BY ASSET MANAGEMENT PLAN ......................................................................... 19 STAKEHOLDER INTERESTS ........................................................................................................... 20 ACCOUNTABILITIES FOR ASSET MANAGEMENT ............................................................................... 26 SYSTEMS AND PROCESSES .......................................................................................................... 27 2. DESCRIPTION OF NETWORK ........................................................................................................... 28 2.1 2.2 SERVICE AREA............................................................................................................................. 28 SUMMARY OF NETWORK CONFIGURATION...................................................................................... 35 3. PERFORMANCE BENCHMARKING .................................................................................................. 49 3.1 3.2 3.3 3.4 COSTS ........................................................................................................................................ 49 RELIABILITY ................................................................................................................................. 54 TECHNICAL EFFICIENCY ............................................................................................................... 58 ASSET BASE ................................................................................................................................ 60 4. RISK MANAGEMENT ......................................................................................................................... 63 4.1 4.2 4.3 4.4 RISK METHODS ............................................................................................................................ 63 RISK DETAILS .............................................................................................................................. 64 CONTINGENCY PLANS .................................................................................................................. 69 INSURANCE ................................................................................................................................. 69 5. PERFORMANCE AND IMPROVEMENT ............................................................................................ 70 5.1 5.2 5.3 OUTCOMES AGAINST PLANS ......................................................................................................... 70 PERFORMANCE AGAINST TARGETS ............................................................................................... 71 IMPROVEMENT AREAS AND STRATEGIES ........................................................................................ 79 6. PROPOSED SERVICE LEVELS ......................................................................................................... 81 6.1 6.2 6.3 6.4 CUSTOMER-ORIENTED SERVICE LEVELS ........................................................................................ 82 SAFETY ....................................................................................................................................... 85 OTHER SERVICE LEVELS .............................................................................................................. 85 REGULATORY SERVICE LEVELS..................................................................................................... 86 7. DEVELOPMENT PLANS .................................................................................................................... 88 7.1 7.2 7.3 7.4 7.5 7.6 7.7 PLANNING APPROACH AND CRITERIA ............................................................................................. 88 PRIORITISATION METHODOLOGY ................................................................................................... 93 OTAGONET‘S DEMAND FORECAST ................................................................................................ 98 OTAGONET NETWORK CONSTRAINTS .......................................................................................... 104 POLICIES FOR DISTRIBUTED GENERATION.................................................................................... 105 USE OF NON-ASSET SOLUTIONS .................................................................................................. 106 NETWORK DEVELOPMENT OPTIONS............................................................................................. 107 Asset Management Plan 2014 Page 2 of 193 CONTENTS 7.8 7.9 7.10 DEVELOPMENT PROGRAMME ...................................................................................................... 109 NON-NETWORK DEVELOPMENT ................................................................................................... 119 DEVELOPMENT STRATEGIES THAT PROMOTE ENERGY EFFICIENCY ................................................ 120 8. MANAGING THE ASSETS’ LIFECYCLE ......................................................................................... 121 8.1 8.2 8.3 8.4 8.5 8.6 8.7 8.8 8.9 8.10 8.11 8.12 LIFECYCLE OF THE ASSETS......................................................................................................... 121 OPERATING OTAGONET‘S ASSETS.............................................................................................. 122 MAINTAINING OTAGONET‘S ASSETS............................................................................................ 124 RENEWING OTAGONET‘S ASSETS ............................................................................................... 130 UP-SIZING OR EXTENDING OTAGONET‘S ASSETS ......................................................................... 136 ENHANCING RELIABILITY............................................................................................................. 137 CONVERTING OVERHEAD TO UNDERGROUND ............................................................................... 137 RETIRING OF OTAGONET‘S ASSETS ............................................................................................ 138 NON-NETWORK, MAINTENANCE AND RENEWAL ............................................................................ 138 LIFECYCLE STRATEGIES THAT PROMOTE ENERGY EFFICIENCY ...................................................... 138 LIFE CYCLE MAINTENANCE AND RENEWAL BUDGET .................................................................... 139 LIFE CYCLE BY ASSET CATEGORY .............................................................................................. 139 9. PROCESSES AND SYSTEMS.......................................................................................................... 166 9.1 9.2 9.3 9.4 9.5 9.6 ASSET KNOWLEDGE ................................................................................................................... 166 ASSET MANAGEMENT TOOLS ...................................................................................................... 167 IMPROVING THE QUALITY OF THE DATA AND PROCESSES .............................................................. 168 USE OF THE DATA ...................................................................................................................... 168 DECISION MAKING...................................................................................................................... 169 KEY PROCESSES AND SYSTEMS .................................................................................................. 170 10. RESOURCING THE BUSINESS ....................................................................................................... 172 10.1 FUTURE RESOURCING REQUIREMENTS........................................................................................ 172 A. APPENDIX – AMP DISCLOSURE REQUIREMENTS ...................................................................... 173 B. APPENDIX - CUSTOMER ENGAGEMENT SURVEY ...................................................................... 180 C. APPENDIX – ASSUMPTIONS .......................................................................................................... 185 D. APPENDIX – EDIDD SCHEDULE 11A ............................................................................................ 186 E. APPENDIX – EDIDD SCHEDULE 11B ............................................................................................. 187 F. APPENDIX – EDIDD SCHEDULE 12A ............................................................................................. 188 G. APPENDIX – EDIDD SCHEDULE 12B ............................................................................................ 189 H. APPENDIX – EDIDD SCHEDULE 12C ............................................................................................ 190 I. APPENDIX – EDIDD SCHEDULE 12D ............................................................................................ 191 J. APPENDIX – EDIDD SCHEDULE 13................................................................................................ 192 K. APPENDIX - APPROVAL BY GOVERNING COMMITTEE.............................................................. 193 Asset Management Plan 2014 Page 3 of 193 CONTENTS Enquiries Enquiries, submissions or comments about this Asset Management Plan (AMP) can be directed to: OtagoNet Limited PO Box 1586 Invercargill, 9840 Phone (03) 418 4950 Email [email protected] Declaration OtagoNet Joint Venture (OtagoNet) confirms that they have produced this AMP in accordance with the requirements of the Commerce Commission and any other legislative requirements. Liability disclaimer The information and statements made in this AMP are prepared on assumptions, projections and forecasts made by OtagoNet JV (OtagoNet) and represent the company‘s intentions and opinions at the date of issue (31 March 2014). Circumstances may change, assumptions and forecasts may prove to be wrong, events may occur that were not predicted, and OtagoNet may, at a later date, decide to take different actions to those that it currently intends to take. OtagoNet may also change any information in this document at any time. OtagoNet accepts no liability for any action, inaction or failure to act taken on the basis of this AMP. Asset Management Plan 2014 Page 4 of 193 SUMMARY 0. Summary of the plan This section summarises the key points from this Asset Management Plan which signals a step increase in network expenditure driven off the need to recover the network condition and meet the network safety, security and reliability objectives. As discussed in this plan, the indicated increase in expenditure continues a trend of rising expenditure on the network following the transfer of ownership in 2003 and comes on the back of historically low and unsustainable levels of expenditure, all as depicted in Figure 1 below. Historic and forecast expenditure (CPI adjusted) $18,000k $16,000k $14,000k Expenditure ($k) $12,000k Total $10,000k Capital Maint. $8,000k Total Capital $6,000k Maint. $4,000k $2,000k $0k Figure 1 Historic and forecast expenditure In the last financial year (FY2014), a number of assets found to be in poor condition prompted the commencement of a one-off full network inspection that will continue into FY2015. As the results of this accelerated surveillance are not complete and may point to further work not identified in this plan, the costs set out herein may change and a revision of this plan will be published. 0.1 Background and Objectives The purpose of the AMP is to provide a governance and management framework that ensures that OtagoNet: Meets all safety requirements consistent with regulatory requirements and recognised industry practice Sets service levels for its electricity network that will meet customer, community and regulatory requirements. Meets the network capacity, reliability and security of supply requirements both now and in the future. Have robust and transparent processes in place for managing all phases of the network life cycle from commissioning to disposal. Properly considers the classes of risk OtagoNet‘s network business faces and that there are systematic processes in place to mitigate identified risks. Makes adequate provision for funding all phases of the network lifecycle. Makes decisions within systematic and structured frameworks at each level within the business. Asset Management Plan 2014 Page 5 of 193 SUMMARY Obtains increased levels of information relative to the location, age and condition of the constituent components of the network. Implements systems to ensure that the information pertaining to the network assets is able to be readily utilised to facilitate network planning and efficiently determine prudent levels of capital and maintenance expenditure and maximise reliability of customer supply. OtagoNet works to the below strategies at the corporate and asset level: Corporate Strategies Delivery to the customers of an economic, safe, efficient and quality electricity supply and meets all legislative requirements. Maintaining and enhancing the long term value of assets, business units, products and investments. Deliver a reasonable commercial return on equity. Achieve a long term reliable electricity supply. Asset Management Strategies Sectionalising poorly performing feeders Continue to expand the meshed area of the network Manage deteriorating assets through condition inspection and replacement Reduce planned SAIDI by employing mobile generation where feasible and economic Employ strong capital governance processes Identifying and managing network health, safety and other risks Direct investment towards reliability and the more economic sections of the network Achieve 100% regulatory compliance Ensure compliance with internal network standards This plan covers the period 1 April 2014 to 31 March 2024, and was approved by the OtagoNet Governing Committee on 31 March 2014. However, it has to be stated that the provisions of this plan are based on information currently available and may well change as further information is obtained. The extensive surveillance of the network provided for in this plan for the year ending 31 March 2015, will enable the current provisions of this plan to be more accurately determined. Accordingly, it is intended that this plan be reviewed during the year. Management of the assets is undertaken OtagoNet with support from PowerNet Limited and Marlborough Lines Limited. OtagoNet uses one main external contractor to operate, maintain, renew, upsize and expand the network. The processes and systems used by OtagoNet are described in section 9. 0.2 Details of the network OtagoNet supplies14,8121 customers in Otago, with a population of 34,791.2 Key industries within OtagoNet‘s network area include sheep, beef and dairy farming, extensive meat processing, gold mining, black and brown coal mining, forestry, and timber processing. 1 As per the FY 2013 information disclosure. 2 From combined Clutha and Central Otago Territorial Authority normal resident population data from the 2013 census. The 2013 census result by town was not available at time of publishing. Asset Management Plan 2014 Page 6 of 193 SUMMARY Figure 2 Overview of OtagoNet Subtransmission Network 2012 As at 31 March 2013 there were a total of 4,394 km of lines and cables comprising: 74 km of 66kV lines and 539 km of 33 kV lines and cables. 35 zone substations to transform High Voltage (HV) to Medium Voltage (MV). 956 km of SWER lines and cables 2,275 km of 11 kV lines (other than SWER) and 21 km of 11 kV cables. 4,197 distribution transformers supplying 14,812 customers. 24 Voltage regulators, controlling local voltage. 499 km of low voltage (230V) lines and 28 km of cable. The age of the network is relatively old; with the 2013 disclosure (schedule 4(vii)) showing only 46% of expected life remaining for distribution and LV lines and 39% for subtransmission lines. Comparative benchmarking, analysis of faults and the Asset Management Plan 2014 Page 7 of 193 SUMMARY management of risk, all points to the continued need for replacement programs particularly for the line assets. 0.3 Comparative benchmarking This section considers OtagoNet‘s performance in comparison to all other electricity distribution businesses (EDBs) in New Zealand using data disclosed in the FY2013 information disclosure. Key findings are: A comparatively high proportion of faults expenditure indicative of the deteriorating condition of the network Direct opex expenditure comparative with other EDBs Indirect opex also comparative with other EDBs The lowest customer density of any New Zealand network at three customers per kilometre. An average rate of return being achieved on network investment but the second highest investment value per ICP owing to the low connection density of the network Reasonable SAIFI performance but noting a high prevalence of faults attributable to the quality of the network. A high proportion of planned SAIDI and high CAIDI although the latter is highly variable due to the radial nature of the network with long feeders and terrain which in winter is often inaccessible because of snow. Transformer utilisation and network losses consistent with the network characteristics noting OtagoNet‘s single largest customer utilises approximately 50% of the energy delivered over the network and this distorts overall statistics relative to losses and energy demand. Has one of the most ‗aged‘ networks in New Zealand, a factor which needs to be addressed relative to safety and the sustainability of the supply reliability. Although historical statistics may be utilised for comparison with other networks, going forward the statistics for OtagoNet can be expected to change. The possible closure of its largest customer, publicly reported for circa 2017, taking approximately 50% of the energy, and the need to renew the network whilst minimising the capital burden on customers results in challenges not faced by other networks of greater customer density. It is salient that a significant proportion of OtagoNet‘s lines were built under the previous government requirements to construct uneconomic lines with the provision of Rural Electrical Reticulation Council subsidies. A number of these lines remain uneconomic yet need replacement. Because OtagoNet does not have a dense urban network to offset the number of customers it services in the rural areas, it is inevitable the capital investment per customer will further increase relative to other networks. The reality is the previous owners of the network deferred maintenance and capital expenditure and unfortunately the savings of the past now have to be funded to ensure the safety of the network and to maintain reliability of supply. 0.4 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 its disaster preparedness Risk management is used to identify and control risk to within acceptable levels. Highlighted risks are the potential public safety hazards arising from the deteriorated network condition, which are being addressed through an accelerated condition Asset Management Plan 2014 Page 8 of 193 SUMMARY inspection programme and addressing some issues identified over the last year around historic earthing practices on SWER transformers. 0.5 Performance and improvement The outcome for the 2012-13 annual business plan was a 3% underspend on the $9.66M capital budget, and a 2% underspend on the $3.5M budgeted for maintenance. Forecast out-turn for the current 2013-14 year is running at -16% on the capital budget of $13.3m and +18% on the $3.7m maintenance budget, giving an overall underexpenditure of -9%. Although this expenditure approximated to budget, it is expected the underspend will be spent prior to 2015 (2014/15 year). Performance for duration of faults (SAIDI) and frequency of faults (SAIFI) exceeded target levels and SAIDI is close to the regulatory threshold for the 2013/14 year. The network was adversely affected by the winter storms in 2013. However, given the radial nature of the network and the propensity of the network to be affected by snow, it is salient to note that the reliability of the network will always be subject to the vagaries of weather. Further, that when outages occur, snow and inaccessibility can impede restoration of supply as occurred during the winter of 2013. The majority of secondary service level target were achieved3. Utilisation was on target. Network losses were below target due to a change in the metering location of the network‘s largest load and new targets have been set to recognise this in the future. Strategies are planned and described to improve performance particularly in areas of strengthened capital governance and management, improved processes for recording and using line condition information and reducing planned outages through the application of more mobile generation. 0.6 Proposed service levels The outcome of customer consultation undertaken by a telephone survey, public meetings and one-on-one meetings showed the majority of customers are content with the present level of service but the expectations of customers vary depending upon their individual requirements such as milking, irrigation and their dependency upon electricity as an essential service in a harsh winter climate. Irrespective, customers do not want a lesser level of service and have an expectation going forward that reliability of supply will be at least maintained or improved. Positive feedback has been received relative to the increased levels of maintenance and capital expenditure undertaken on the network in recent years. The surveyed customers have indicated that they value continuity and then restoration most highly and therefore OtagoNet‘s primary service levels are continuity and restoration. To measure performance in this area two internationally accepted indices have been adopted: SAIDI – 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. SAIFI – system average interruption frequency index. This is a measure of how many system interruptions occur per year per customer connected to the network. Projections of these measures for the next ten years are set out below and are based on meeting or exceeding the supply quality requirements set out by the Commerce Commission and enacting the strategies set out in this plan. 3 Unachieved target was percentage of customers recognising OtagoNet as the first call for an outage. Asset Management Plan 2014 Page 9 of 193 SUMMARY Target levels for unplanned outages have been calculated by averaging the values over the regulatory period (2004/05 – 2008/09) (allowing for normalisation to remove extreme events as per the Commerce Commission guidelines), and decreasing future years by 0.5% p.a. However this proposed reduction is an interim target only and will be reviewed as part of the reassessment of the network to be undertaken this year. Indeed, recent failures have indicated that unless expenditure is maintained or increased reliability will diminish. Target levels for planned outages have been maintained constant acknowledging that OtagoNet remains uncertain of the planned reliability impacts of its work programme mainly due to the unknown extent of the condition driven work. Table 1 – Primary service levels SAIDI Year End Class B Limit 31/03/15 31/03/16 31/03/17 31/03/18 31/03/19 31/03/20 31/03/21 31/03/22 31/03/23 31/03/24 Class C 148 148 148 148 148 148 148 148 148 148 175 174 173 173 172 171 170 169 168 168 SAIFI Total 361.08 323 322 321 320 319 318 318 317 316 315 Class B 0.63 0.63 0.63 0.63 0.63 0.63 0.63 0.63 0.63 0.63 Class C 2.07 2.06 2.05 2.04 2.03 2.02 2.01 2.00 1.99 1.98 Total 3.120 2.70 2.69 2.68 2.67 2.66 2.65 2.64 2.63 2.62 2.61 Class B are planned interruptions on the network and Class C are unplanned interruptions on the network, commonly known as faults. 0.7 Development Plans Annual growth of the network energy and demand has been 1.4% to 1.5% over the last 10 years with demand growth relatively flat over the last 5 years. Most growth in energy delivered has been with the HV (industrial or large commercial) customers. Based on long run historic trends, the future increase in demand is predicted at a rate of 1.5% per annum over the larger network. This, however, excludes OtagoNet‘s largest single customer, for which closure has been announced circa 2017 and which would incur a one-off drop in demand of 42% and reduce delivered energy by 53% should this occur. As this customer is essentially supplied via a dedicated 66kV line paid for by the customer there will be minimal effect to the network in terms of stranded assets should it close. Typically domestic customers are reducing demand through the more efficient utilisation of electricity and consolidation of connections points and growth in total customer numbers has been generally static in recent years. Against this background, growth in demand has occurred in specific areas with increased demand for timber and milk processing and the conversion of sheep farms to dairying. The latter also has requirements for increased levels of irrigation particularly in the Maniatoto area where already approximately 1MW of additional capacity has been requested for later in the year. Asset Management Plan 2014 Page 10 of 193 SUMMARY OJV Historic Energy and Maximum Demand (showing with and without Macraes Gold Mine Load) 90 450 Base MW (excl. Macraes) Total MW 80 400 Base GWh (excl. Macraes) Energy - (GWh) 2012 2010 2008 2006 2004 2002 2000 1998 1996 1994 1992 1990 1988 1986 1984 1982 1980 0 1978 0 1976 50 1974 10 1972 100 1970 20 1968 150 1966 30 1964 200 1962 40 1960 250 1958 50 1956 300 1954 60 1952 350 1950 Maximum Demand - (MW) Total GWh 70 Figure 3 Historic energy and maximum demand Network development focuses on completion of the Transpower Palmerston GXP and 110 kV line purchase, projects associated with this to take full advantage of this network re-configuration to yield improved reliability and projects to meet customer demand in specific areas. Major projects planned over the next ten years are: Transpower Palmerston & 110kV line purchase completion Merton Substation replacement to increase capacity and replace old assets. North Otago East supply reconfiguration to increase capacity and replace old assets. New substation at Puketoi to take up new irrigation load. Milton Elderlee Street Substation replacement to increase capacity and replace old assets. Planned development capital expenditure averages about $4.3 million per annum. 0.8 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 will be undertaken to review network condition and performance to check if any trigger is exceeded and actions planned to maintain target service levels. A number of pole failures at loads less than design load, including some unassisted pole failures, have highlighted gaps in both the identification of condition and the recording and application of the line inspection data. In response to the potential hazards posed from unknown lines condition, OtagoNet has revised its line inspection template, streamlined its data capture processes and has commenced a one-off 1-year accelerated inspection cycle of its full network at a total cost of $1.5m with $967k allocated for FY2015. This is justified on public safety considerations and to maximise efficiency of expenditure. An additional $500k is set provisionally in the FY2015 maintenance budget to cover priority maintenance works that are likely to be discovered during the detailed condition inspections but should the asset assessments Asset Management Plan 2014 Page 11 of 193 SUMMARY determine additional work is necessary to improve the safety of the network or eliminate potential outages, such work will be undertaken. Condition driven renewal is budgeted at approximately $6.1m p.a. as detailed further in this plan. Focus for the longer term is to increase the network performance by progressively rebuilding the older lines with impaired performance and to reduce the average age of the network closer to 50% average remaining life. Vegetation control and minor maintenance will also be targeted to help reduce outages. Improved network information will result from increased network surveillance and will enable expenditure to be better targeted to maximise benefit. 0.9 Processes and systems Asset information resides in three key locations: Geographical Information System (GIS), Asset Management System (AMS), and Supervisory Control And Data Acquisition (SCADA). A review of the information available from these systems has been undertaken and it has been determined improvements can be made relative to the capture, recording and accessibility of data. Because of the importance of the availability of accurate information for maximising customer reliability, targeting and managing expenditure and ensuring regulatory compliance, it is intended to invest in the order of $1m in the 2014/15 financial year into the development of these systems. This plan highlights needed improvements in the collection and analysis of asset condition data through the GIS, improvements in the collection and analysis of fault data and in on-going improvement in the accuracy of the asset locations. 0.10 Resourcing the business Resourcing an operation such as OtagoNet in rural New Zealand imposes its unique challenges. Further, because of the relatively small customer base and revenue, it is imperative all resources are utilised efficiently. 0.11 Regulatory compliance of this plan This plan is required to comply with the Electricity Distribution Information Disclosure Determination 2012 (EDIDD) appendix A (Asset Management Plans) which sets out the required content of the AMPs. Compliance with the EDIDD is tabulated in Appendix A which maps clause requirements of the EDIDD to the section headings in this AMP. Forecast budgets provided in this plan are expressed in FY2014 dollars (real). 0.12 Feedback and comments Comment on this plan is welcome and should be addressed to the Network Manager (OtagoNet), OtagoNet Ltd, PO Box 1586, Invercargill or email [email protected]. The next review of this AMP is planned for publishing in March 2015. Asset Management Plan 2014 Page 12 of 193 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 City) to approximately 14,812 customer connections on behalf of six energy retailers. The wider OtagoNet entity also includes the following associations: Owned by three entities: - 51% by Marlborough Lines Limited (MLL). - 24.5% by Electricity Invercargill Limited (EIL). - 24.5% by The Power Company Limited (TPCL). Supported by PowerNet, an electricity lines management company jointly owned by TPCL and EIL, for corporate services, financial and commercial management, enterprise business systems, system control and administrative services. Supported by Marlborough Lines Ltd for engineering support. Otago Power Services Ltd, an electrical contracting company based in Balclutha, which has the same owners as OtagoNet and which is managed by MLL. It undertakes the majority of OtagoNet capital and maintenance expenditure. This AMP deals solely with the OtagoNet electricity network assets and non-network assets as defined by the Electricity Distribution Information Disclosure Determination 2012 (EDIDD). The OtagoNet‘s Asset Management and Planning Processes are based on previous AMPs, company standards & processes (e.g. PNM-105). The objective for OtagoNet‘s Asset Management and Planning Processes is to maintain and develop the OtagoNet assets to achieve all stakeholders target service levels. 1.1 History of the Network The network was largely constructed under the auspices of the former Otago Electric Power Board, a special purpose entity formed in 1923 under the provisions of the Electric Power Board Act. As a requirement of the Electricity Companies Act 1992, the Otago Electric Power Board was obliged to corporatise. This was achieved following public consultation and transformed into the customer cooperative Otago Power Limited ("OPL") with shares allocated to customers. In 1998 OPL was obliged by government regulation to divest either its line business or its generation and electricity retail business and it elected to sell the latter. In 2003 the Board of the cooperative opted to sell the assets of the company by tender and return the proceeds to the customers connected to the network relative to the number of shares each were given. A domestic customer typically received a sum in the order of $5,000 and commercial customers received greater amounts relative to their electricity payments. The Otago network is unusual in that it provides supply to a predominantly rural network and much of its reticulation was constructed with the support of RERC subsidy because the lines were uneconomic. It is the least dense network in New Zealand. The construction of such uneconomic lines was required by the legislation of the day. Because of the low customer density and in an endeavour to minimise costs, the lines were frequently constructed to a standard below that required today. The Otago Electric Power Board operated on a minimal cost basis with low levels of reinvestment and its successor, the cooperative company Otago Power Limited, acted similarly. Asset Management Plan 2014 Page 13 of 193 BACKGROUND AND OBJECTIVES As a consequence when the current owners of OtagoNet acquired the assets in 2003 they were in a less than ideal condition. A condition of sale was that line charges be held for three years from 2003 which meant that maintenance and capital expenditure was constrained and costs were minimised. In recognition of historic low expenditure on replacement capital and the consequent poor condition of the lines and substation assets, OtagoNet commenced and continues a programme of capital investment to reduce the network average age, improve the network reliability and resilience and meet safety requirements. This programme of needed capital investment has necessitated increases in line charges noting that rebuilding lines is considerably more expensive than green fields construction and is being undertaken without the regime of central government subsidy that most of these rural lines were initially built under. Hence from 2006 the capital and maintenance expenditure has been increased as depicted in the chart below. Historic and forecast expenditure (CPI adjusted) $18,000k $16,000k $14,000k Expenditure ($k) $12,000k Total $10,000k $8,000k $6,000k Capital Maint. Total Capital Maint. $4,000k $2,000k $0k The marked increment in expenditure in the above graph is indicative at the time of preparation of this report. Substantive surveillance work on the network is planned over the next few months to verify the need for the renewal expenditure together with finalisation of a potential customer‘s significant requirements requiring network augmentation. Accordingly it is intended to issue a further revision of this plan when additional information is available. Revenue levels have already been set for the coming year based on information previously provided to the Commerce Commission and from a financial perspective it is preferable to maintain the expenditure at previously determined levels. Irrespective, OtagoNet is conscious of its obligations in relation to the delivery of electricity and will increase expenditure as required to meet its priorities and statutory obligations. The increase in expenditure described in this plan is reflective of the situation known at the time of publishing this AMP. 1.2 Purpose of the Asset Management Plan The purpose of the AMP is to provide a governance and management framework that ensures that OtagoNet: Assets, systems and procedures meet all regulatory requirements including safety requirements. 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. Asset Management Plan 2014 Page 14 of 193 BACKGROUND AND OBJECTIVES 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. Status of this AMP is ‗Applying‘ with some processes in use in OtagoNet and Otago Power Services. Disclosure of OtagoNet‘s AMP in this format will also assist in meeting the requirements of Section 2.6 and Schedules 11, 12, and 13 of the Electricity Distribution Information Disclosure Determination 2012. 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. 1.3 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 mission statement and business plan, the prevailing regulatory environment, government policy objectives, commercial and competitive pressures and technology trends. OtagoNet‘s assets are also influenced by technical regulations, codes of practice, asset deterioration, network performance, natural processes, and risk exposures all independent of the strategic context. 1.3.1 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 determines prices, requires no material decline in reliability and requires that OtagoNet compile and disclose performance and planning information. Government policy objectives, such as the promotion of distributed generation (particularly renewables). OtagoNet‘s commercial goal to deliver a sustainable earnings stream to its owners that represent an acceptable rate of return. Pressure from substitute fuels both at the end-user level (such as substituting electricity with coal or oil at a facility level) and at bulk generation level (wind farms) including the utilisation of diesel engines to provide motive power for pumps. Advancing technologies such as fuel cells, improved batteries and current technologies of micro-wind and photovoltaic, which could potentially strand some reticulation. 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 and the consequent change in the customers need for capacity and reliability. Changes in climate that may include more storms and hotter, drier summers (prompting greater irrigation loads). The economic climate and interest rates which can influence the rate at which new customers connect to the network and the shareholders required rate of return. Aggregation of connection points (ie customer‘s sub-mains replacing individual connection points on barns and workshops) Asset Management Plan 2014 Page 15 of 193 BACKGROUND AND OBJECTIVES Availability of sufficient resources long term to satisfy OtagoNet‘s service requirements. 1.3.2 Independence from strategic context Further factors apply independent of the strategic context including: Safety requirements such as; the earthing of exposed metal, line clearances, ensuring the network assets are physically sound and generally ensuring the network does not impose unacceptable risk to customers, the public, contractors and staff. Technical regulations including such matters as limiting harmonics to specified levels. Asset configuration, condition and deterioration. Natural processes and laws 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 may depend on the strategic context could be in regard to natural issues such as climate change increasing the severity and frequency of storms or regulatory issues -for example if LTNZ were to require all poles to be moved back from the carriage way. Landowner agreement for property access. 1.3.3 Annual Business Plan and works plan In 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 and which contribute to OtagoNet‘s long-term alignment with its strategic goals. 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. Fundamental is a need to utilise information relative to the performance of the network and information gained from surveillance in setting and targeting the expenditure. 1.4 Key planning documents and processes Interactions of the key planning issues, processes and documents are shown in Figure 4. Asset Management Plan 2014 Page 16 of 193 BACKGROUND AND OBJECTIVES Issues Dependent on Strategic Context Issues Independent from Strategic Context Regulatory Environment Government Policy Objectives Commercial Goals Competitive Pressures Substitute Fuels Technology Trends Economic Cycles Interest Rates Safety Requirements Technical Regulations Asset Configuration Asset Deterioration Asset Condition Natural Processes Physical Risk Exposures Asset Management Plan Annual Business Plan incl. Works Programme Performance Review Varying Condition Influences & Constraints Assets Service Levels Figure 4 - Interaction of key plans 1.4.1 Vision statement To operate as a successful business in the distribution of electricity in the Otago region. 1.4.2 Strategic plan Key asset management drivers from OtagoNet‘s Strategic Plan are: 1. Ensure public, customers, contractors and staff are safe relative to all aspects of the network operations. This includes adherence to all regulatory requirements and recognised industry practice. 2. Delivery to the customers of an economic, safe, efficient and quality electricity supply. 3. Maintaining and enhancing the long term value of assets, business units, products and investments. Asset Management Plan 2014 Page 17 of 193 BACKGROUND AND OBJECTIVES 4. Working with the Commerce Commission to achieve: - Regulated prices which enable customers to enjoy a long term reliable and sustainable network connection and Result in a reasonable commercial return on equity to the owners to enable continued support and investment in the business. 1.4.3 Asset strategy OtagoNet continues to develop its detailed asset strategy to meet its corporate goals and in response to the performance levels it achieves. The following are our key asset strategies that are further supported and developed in this plan: Improve reliability by: - managing deteriorating assets through condition inspection and replacement; - sectionalising poorly performing feeders; - reduce planned SAIDI by greater use of mobile generation where feasible and economic; and - expand the meshed area of the network where practical by closing gaps between radial feeders but noting that options in this regard are extremely limited. Control costs and manage economic and regulatory risk by: - employing strong capital governance and management processes; - using condition-based assessments in the replacement and maintenance of assets; - identifying and managing network risks; - directing investment towards reliability improvement and the more economic sections of the network. Meet safety and environmental standards by: - identifying and managing network health, safety and other risks including external review; - achieving full regulatory compliance; - ensuring compliance with internal network standards; and - utilising applicable codes of practice. 1.4.4 Prevailing regulatory environment OtagoNet‘s assets are subject to a price path threshold established 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. 1.4.5 Government objectives Electricity lines businesses are 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 variable tariff components to promote demand reduction despite the most cost reflective tariff structure for a lines business being that of fixed cost. Continuance of supply regulations that require the provision and maintenance of existing lines that may be uneconomic. Price increases in rural areas to be no greater than those prevailing in urban areas. 1.4.6 Annual business plan An Annual Business Plan (ABP) which is produced by OtagoNet and which contains the following: Asset Management Plan 2014 Page 18 of 193 BACKGROUND AND OBJECTIVES 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. 1.4.7 Annual works plan The Annual Works Plan (AWP) 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. 1.5 Interaction of goals and strategies The below table 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 and meets all legislative requirements. Maintaining and enhancing the long term value of assets, business units, products and investments. Deliver a reasonable commercial return on equity. Achieve a long term reliable electricity supply. Asset Management Strategies Sectionalising poorly performing feeders Continue to expand the meshed area of the network Manage deteriorating assets through condition inspection and replacement Reduce planned SAIDI by employing mobile generation where feasible and economic Employ strong capital governance processes Identifying and managing network health, safety and other risks Direct investment towards reliability and the more economic sections of the network Achieve 100% regulatory compliance Ensure compliance with internal network standards 1.6 Period covered by Asset Management Plan This edition of OtagoNet‘s AMP covers the period 1 April 2014 to 31 March 2024. This AMP was prepared during January to March 2014, approved by OtagoNet‘s Governing Committee in March 2014 and publicly disclosed at the end of March 2014. Uncertainty is a factor in any planning process and accordingly the plans set out in this AMP include a degree of uncertainty. Customer demand driven by turbulent commodity markets, public policy trends and possible generation opportunities within OtagoNet‘s demand profile means the future is perhaps less certain than many other infrastructure businesses of greater scale. Accordingly, OtagoNet has attached the following certainties to the timeframes of the AMP: Timeframe Residential and Commercial Large Industrial Year 1 to 2 Years 3 to 5 Reasonably certain Less certain Reasonably certain Reasonable certainty Little if any certainty Little if any certainty Asset Management Plan 2014 Intending Generators Page 19 of 193 BACKGROUND AND OBJECTIVES Years 6 to 10 Little if any certainty 1.7 Little if any certainty Little if any certainty Stakeholder interests 1.7.1 Stakeholders A stakeholder is defined as any person or class of persons who: 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). 1.7.2 Stakeholder interests The interests of OtagoNet‘s stakeholders are classified in Table 2: Table 2 – Key stakeholder interests Interests Viability Shareholder Bankers Connected customers Contracted managers (PowerNet and Marlborough Lines) Energy retailers Mass-market representative groups Industry representative groups Staff and contractors Suppliers of goods and services Public Land owners Councils (excluding as a customer) Transport Agency Ministry of Economic Development Energy Safety Service Commerce Commission Electricity Authority Electricity & Gas Complaints Commission Ministry of Consumer Affairs Asset Management Plan 2014 Price Quality Safety Compliance Page 20 of 193 BACKGROUND AND OBJECTIVES Table 3 below demonstrates how stakeholder‘s expectations and requirements are identified. Table 3- How stakeholder’s expectations are identified Stakeholder Owners Bankers Connected Customers Contracted Managers (PowerNet and Marlborough Lines) Energy Retailers Mass-market Representative Groups Industry Representative Groups Staff & Contractors Suppliers of Goods & Services Public (as distinct from customers) Land Owners Councils (as regulators) Transport Agency Ministry of Economic Development Energy Safety Service Commerce Commission Electricity Authority Electricity & Gas Complaints Commission Ministry of Consumer Affairs Asset Management Plan 2014 How expectations are identified By their approval or required amendment of the Business Plan. Regular meetings between the directors and executive. Regular meetings between the bankers and PowerNet‘s Chief Executive and GM Finance. By adhering to OtagoNet‘s treasury/borrowing policy By adhering to banking covenants. Regular discussions with large industrial customers as part of their on-going development needs. Annual customer surveys and feedback from OtagoNet Newsletters Chairman and Management Committee meeting with the Chief Executive as required. Annual consultation with retailers. Informal contact with group representatives. Informal contact with group representatives. Regular staff briefings. Regular contractor meetings. Regular supply meetings. Informal discussions. Feedback from public meetings. Individual discussions as required. Formally as necessary to discuss issues such as assets on Council land. Formally as District Plans are reviewed. Formally as required. Regular bulletins on various matters. Release of legislation, regulations and discussion papers. Analysis of submissions on discussion papers. Promulgated regulations and codes of practice. Audits of OtagoNet‘s activities. Audit reports from other lines businesses. Regular bulletins on various matters. Release of discussion papers. Analysis of submissions on discussion papers. Conferences following submission process. Weekly update. Release of discussion papers. Briefing sessions. Analysis of submissions on discussion papers. Conferences following submission process. General information on their website. Reviewing their decisions in regard to other lines companies. Release of legislation, regulations and discussion papers. General information on their website. Page 21 of 193 BACKGROUND AND OBJECTIVES 1.7.3 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 at large must be able to move around and work on the network in total safety. Viability Viability is necessary to ensure that the shareholder and other providers of finance such as bankers have sufficient reason to keep investing in OtagoNet. Price Price is a key means of both gathering revenue to sustain the business and signalling the true underlying costs. The public at large are kept safe by ensuring that all above-ground assets are structurally sound, live conductors are well 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 aboveground structures are kept as far as possible from the carriage way within the constraints faced in regard to private land and road reserve. An improved surveillance program has been initiated to ensure the network is compliant in these regards. Stakeholders‘ needs for long-term viability are accommodated by delivering earnings that are sustainable and reflect an appropriate risk-adjusted return on 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. OtagoNet‘s total revenue is constrained by the default price quality path regime. Prices are controlled with the CPI-X price path with X set at 0% in the current Price Reset which runs to 1 April 2015. The opportunity exists to apply to the Commerce Commission for a Customised Price Path in circumstance where prices are insufficient to fund the business. The regulatory regime also applies a building-block approach for setting allowed revenue based on the business‘s forecast operating and capital requirements and where revenue claw-backs in the next period may be applied if the business fails to expend those budgets. OtagoNet‘s pricing methodology is expected to be cost-reflective, but issues such as the Low Fixed Charges requirements can distort this. Supply quality Emphasis on continuity then restoration of supply and reducing flicker is essential to minimising interruptions to customers‘ businesses. Asset Management Plan 2014 Stakeholders‘ needs for supply quality will be accommodated by focusing resources on continuity and then rapid restoration of supply. The most recent mass-market survey indicated a general satisfaction with the present supply quality. Page 22 of 193 BACKGROUND AND OBJECTIVES Interest Description How OtagoNet meets interests Compliance Compliance is necessary with many statutory requirements ranging from safety to disclosing information. All safety issues will be adequately documented and available for inspection by authorised agencies. Performance and other regulatory disclosure information will be provided in a timely and compliant fashion. 1.7.4 Management of conflicting interests Conflicts exist in simultaneously meeting all stakeholders interests ie between price, commercial return and reliability. Priorities for managing conflicting interests are: Safety. Top priority is given to safety. The safety of staff, contractors and the public will not be compromised even if budgets are exceeded. Compliance. Legislative compliance is paramount to proper governance and operation of any business. Viability. Third priority is viability of the business (as defined in 1.7.3 above), as the business needs to sustain itself in order to provide a network service to its customers. Pricing. OtagoNet will give forth priority to pricing noting that pricing is also an aspect of viability. OtagoNet recognises the need to adequately fund its business whilst ensuring that its customers‘ businesses can operate successfully and there is not an unjustified transfer of wealth from its customers to its shareholders. Supply quality is the fifth priority. Good supply quality minimises economic loss to OtagoNet‘s customers. 1.7.5 Customer consultation Consultation was undertaken by four methods, firstly a phone survey of 200 customers was undertaken by external consultants. A copy of the questionnaire used is attached in appendix B. The second method was a face to face survey by the survey company with major customers. Overall customers did not wish to pay more but expected reliability of supply to improve or at least be maintained. Thirdly OtagoNet held community consultation meetings at various locations throughout the network, where direct feedback was obtained. Lastly, individual customers are consulted as they undertake connection to the network or consider upgrades. An example was the Greenfields Dairy processing plant near Clydevale and this has required numerous options and negotiations before the final solution was agreed. Asset Management Plan 2014 Page 23 of 193 BACKGROUND AND OBJECTIVES Figure 5 Greenfields Substation 1.7.6 Uneconomic connections Within OtagoNet‘s network there is an inherent level of cross-subsidy between consumers as the proportion of asset value needed for each connection on the network is not uniform. A consumer adjacent to Charlotte St zone substation in Balclutha is supported by the short subtransmission lines between the Balclutha grid exit point and this zone substation, the Charlotte St zone substation transformation and switching capacity, and the small length of distribution line to the consumers installation. Additionally, all of the network assets upstream of this consumer are shared over a large number of other consumers in Balclutha. In contrast, a consumer on a farm out of Hindon is supported by much longer subtransmission lines, proportionately more transformation capacity (due to lower diversity) and long 11 kV or SWER distribution lines which are shared over a relatively few consumers. Maintenance costs are also proportionately higher for the rural consumer as these costs scale with network length. However, both consumers pay uniform capacity charges. Cross-subsidy exists in all electricity network businesses employing uniform charging to a greater or lesser extent largely dependent on the connection density of the network. In OtagoNet‘s case, it has the lowest connection density of all EDBs in New Zealand.4 Consequently, dealing with uneconomic connections is a substantial issue for the company. The extent of the issue is illustrated in the following chart of Figure 6 below. This plots the cumulative percentage of network connections (x-axis) against the cumulative percentage of network asset value needed to support those connections. This shows that approximately 50% of the network value is utilised by the last 22% of the network connections and highlights the extent of the cross-subsidy inherent in the network configuration.5 4 FY2013 disclosure has OtagoNet at 3 connections per km of line and this compares to Wellington Electricity at 36 connections per km. 5 This should be considered a conservative estimate as operational costs are not included and these approximately scale in proportion to network length. Asset Management Plan 2014 Page 24 of 193 BACKGROUND AND OBJECTIVES Figure 6 Network cross subsidy Whilst differential charging is not being considered at this time, the issue is highlighted with generally static growth in urban areas and lower consumer demand from the impact of energy efficiency and photovoltaic uptake, which will potentially result in a greater subsidy if network charges continue to be recorded on a variable basis. In regard to asset management, consideration of the uneconomic nature of some connections, lines, and even zone substations, requires the prioritisation of capital works towards the more economic parts of the network. For the avoidance of doubt we note that any works addressing safety issues do not consider the economic return from the affected connections. As measures of reliability such as SAIDI react most to outages on the parts of the network that affect large customer numbers, there is a natural favouring of the more economic parts of the network when works are directed based on their impact on reliability and OtagoNet directs its capital and maintenance expenditure in part through this mechanism. Asset Management Plan 2014 Page 25 of 193 BACKGROUND AND OBJECTIVES 1.8 Accountabilities for asset management OtagoNet‘s ownership, governance and management structure is depicted below in Figure 7. Marlborough Electric Power Trust (100%) Invercargill City Council (100%) SEPS Consumer Trust (100%) Ownership Invercargill City Holdings (100%) Marlborough Lines Board of Directors (100%) Electricity Invercargill Board of Directors (100%) The Power Company Board of Directors (100%) Southern Lines (51%) Pylon (24.5%) Last Tango (24.5%) Governance Otago Joint Venture Governing Committee PowerNet Corporate services; financial and commercial management; enterprise business systems; system control; admin services Marlborough Lines Engineering Management Figure 7 - Governance and Management Accountabilities 1.8.1 Accountability at governance level As OtagoNet uses a Governing Committee to represent the multiple owners and contracts to PowerNet for corporate services, financial and commercial management, regulatory management, enterprise business systems, system control and administrative services and Marlborough Lines for engineering support and so it effectively has a two-tier governance structure as follows: The first tier of 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 ultimately 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: - Terry Shagin (Chairman) Alan Harper Ken Forrest Neil Boniface The second tier of governance accountability is between the Governing Committee and the PowerNet and Marlborough Lines Boards with the principal mechanism being the management contracts. Asset Management Plan 2014 Page 26 of 193 BACKGROUND AND OBJECTIVES 1.8.2 Accountability at executive level Accountability for corporate services, financial and commercial management, regulatory management, enterprise business systems, system control and administrative services rests with the chief executive of PowerNet Limited and accountability for engineering matters rests with the chief executive of Marlborough Lines Limited. The mechanism of accountability is through the management contracts to the OtagoNet Management Committee. 1.8.3 Accountability at operational level The individual managers who have the most influence over the long-term asset management outcomes will be the Engineering Manager and Network Manager (Otago) through their preparation and execution of the AMP which will guide the activities and direction of others. 1.8.4 Accountability at construction/maintenance level Otago Power Services Limited is used almost exclusively for all construction, replacement and maintenance services, as a contractor, except for some specialist work. The principal accountability mechanism is through a contract between Otago Power Services and OtagoNet. 1.8.5 Key reporting lines The OtagoNet Governing Committee receives a monthly report that covers the following items: Network Safety – safety performance reported and issues highlighted, with progress to eliminate, mitigate or manage reported Network reliability – this lists all outages over the last month, and trends regarding the 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 line charges and other miscellaneous revenue received Retailer activity – detail on volumes and numbers per energy retailer operating on the network Works Programme – monthly and YTD6 expenditure on each works programme item and percentage complete, with notes on major variations Key Performance Indicator measures Each level of management has defined financial limits in the OtagoNet 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 Governing Committee approval. Generally most projects are approved by the Governing Committee in the Annual Business Plan process. 1.9 Systems and processes OtagoNet‘s systems and processes are described in detail in section 9. Specific asset inspection and network maintenance strategies are described in section 8.3. 6 YTD = Year to date Asset Management Plan 2014 Page 27 of 193 OUR NETWORK 2. Description of network 2.1 Service area 2.1.1 Regions covered 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 8 - Distribution Area Topography varies as follows: Flat fertile plains and rolling hills in the south and west Otago area that includes townships of Milton, Balclutha, Owaka and Clinton. Rolling countryside along the north Otago coast that includes townships of Waitati, Waikouaiti and Palmerston. Dry flat plains, rolling hills and mountainous areas in the inland north Otago area that includes townships of Naseby and Ranfurly, the Macraes Mine and stretches as far south as Middlemarch, Clarks Junction and Hindon. Under the regulatory requirements, OtagoNet treats all areas similarly with no separated or segmented disclosure as all areas are connected electrically with the northern and southern MV networks connecting at Lake Mahinerangi. Asset Management Plan Page 28 of 193 OUR NETWORK 2.1.2 Demographics The normal resident population in the main territorial authorities of Clutha district and Central Otago district comprise 34,785 residents with a largely static population in Clutha and a slowly rising population in Central Otago as illustrated in Figure 9 below.7 Figure 9 Territorial population trend Of note is the distinctly aging nature of the populations in both districts but particularly in the Central Otago district as evident in the shift in the population mode between the 2006 and 2013 census, which is illustrated in the chart of Figure 10 below. Figure 10 Population age profile by region OtagoNet‘s total connections are relatively static as described in Table 5 and Figure 11 following.8 [Note that the increase in ―crop growing‖ connections relates mainly to new irrigation pump connections often associated with grass growing for dairy farming]. 7 Source 2013 Census data. Note this differs to the FY2012 AMP that used the 2006 census for which populations by towns solely within the OtagoNet area were available. 8 Categorisation based on ANZSIC codes in retailer data; not all classifications included. Asset Management Plan Page 29 of 193 OUR NETWORK Table 5 - ICP counts by year Disclosure Year 2008 2009 2010 2011 2012 2013 2014 (estimated) Total Network Connections 14,747 14,761 14,768 14,801 14,824 14,812 14,740 Figure 11 Trends in ICPs by type (not all categories included) Whilst the population in the areas served by OtagoNet is aging, the drop in domestic connections does not necessarily relate to a fall-off in domestic consumers but mostly Asset Management Plan Page 30 of 193 OUR NETWORK relates to rural consumers aggregating connection points i.e. avoiding connection charges on multiple connections by sub-maining barns or workshops into a single nondomestic connection. This reduces the total domestic connections while maintaining (or sometimes reducing) the number of non-domestic connections. This highlights that electricity charges are at a level where consumers in particular circumstances are investing to limit or avoid these charges, which in turn reduces OtagoNet‘s line charge revenue. The rise in dairy farm operations, particularly in the Central Otago region, is a notable feature with an expectation of continued growth in the near term as noted in the dairy herd and land use statistics published by the dairy industry and as illustrated in Figure 12 following:9 Figure 12 Dairy farming trends by region The challenge for OtagoNet from these demographics will be in managing its capital replacement program in the face of a potentially diminishing connection base to support the network service costs and the increase in the number of dairy farm connections, which are more sensitive to service outages.10 These challenges are 9 FY2008 to FY2013 annual reports; Dairynz; www.dairynz.co.nz/publications 10 Inability to milk the herd and/or the loss of milk chillers that can result in rejected product. Asset Management Plan Page 31 of 193 OUR NETWORK addressed through asset management strategies reinforcing capital expenditure governance processes to maintain or reduce planned and fault outages. 2.1.3 Large Consumers The largest consumer in the area is a gold mine but other large consumers include extensive meat and dairy processing and forestry and timber processing and increasingly dairy farming. Most of the towns in the service area are rural service towns. The area‘s economic fortunes will therefore be strongly influenced by: Market for gold 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. The impact of these issues is broadly as described in Table 6. The recent increase in new connections for irrigation indicate the farming sector is willing to invest and create new load points and OtagoNet responds to this through its network development and reliability planning. Major consumers have significant impact on network operations and asset management priorities. Significant single loads are:: Oceana Gold‘s 23 MVA of load on the Oceana Gold’s 66kV line upgrade Ranfurly substation requires a 66kV line, large dual rated 33/66kV step-up transformers and two heavy 33kV lines from the Naseby GXP. [Public announcements have been made that this mine is due Mount Stuart Wind Farm for closure circa 2017 but confirmation is yet to be received by OtagoNet]. TrustPower‘s 12.25MW generation station also requires the 66kV supply at Ranfurly for an embedded connection to Oceana Gold. Pioneer Generation‘s Falls Dam power station requires enhanced 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 on 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. Asset Management Plan Page 32 of 193 OUR NETWORK The Otago Regional Corrections Facility at Milburn has been provided with two 11kV supplies from different zone substations and automatic change over switchgear to deliver its required security. Pioneer Generation‘s Mount Stuart wind farm that connects into the Glenore to Lawrence 33kV line. Greenfield‘s Dairy Processing plant at Clydevale. Table 6 – Impact of regional economic issues Issue Visible impact Impact on OtagoNet’s value drivers Shifts in market tastes for beef, mutton, lamb Reduced gold price May lead to a contraction of demand by these industries. Reduces asset utilisation. Possible capacity stranding Shifting markets for dairy products May lead to reduction or closure of mine May lead to a contraction of demand by these industries. Shifting markets for timber May lead to a contraction in demand by these industries Shifting markets for coal May lead to a contraction in demand by these industries Government CO2 Policy May lead to a contraction in demand by industries May create new process requirement for industries May lead to contraction of dairy shed demand. May lead to contraction of dairy processing demand. May lead to increased irrigation demand. Little impact because supply assets largely paid for by mine Reduces asset utilisation. Possible capacity stranding Reduces asset utilisation. Possible capacity stranding Reduces asset utilisation. Possible capacity stranding Reduces asset utilisation. Possible capacity stranding New capacity required Government policy on nitrogen-based farming Access to water. Reduces asset utilisation. Possible capacity stranding Increases asset utilisation but without corresponding increase in load factor 2.1.4 Load characteristics 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 the summer hot period yet. Peaks normally occur in winter. Farming: In South Otago the predominant farming load is dairy farming with the milking season between August and May with morning and late afternoon peaks. The remaining farms normally have 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 hot dry periods. A notable feature of farm irrigation load is its effect on measures of transformer utilisation as irrigation connections employ distribution transformer capacity but contribute almost no demand at the time of the network winter peak. Sawmills: Usage at sawmills due to processing and kiln drying of the product. There is also 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. 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. Asset Management Plan Page 33 of 193 OUR NETWORK The makeup of load in the 2013 year and the percentage changes from 2009 to 2013 are illustrated in the charts of Figure 13 below [which excludes the Macraes gold mine load which is the dominant load on the network]. This shows a general reduction in non HV connection loads with the greatest change in domestic loads.11 Figure 13 Load make-up (kWhs) by type (excludes Macraes mine) 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 heat pumps as air conditioners in the 26°C summer heat. Increased energy efficiency due to Government campaigns. (Compact fluorescent and LED lights, Warm Homes initiatives.) Fuel switching ie installation of wood pellet fires in response to rising electricity prices. 2.1.6 Energy and demand characteristics Key energy and demand figures for the YE 31 March 2013 are as follows: Table 7 - Key Energy and Demand Figures Parameter Value Long-term trend Energy conveyed 422 GWh Max demand Load factor Transformer utilisation 60.7 MW 79 % 29.2 % Losses -5.1% Steady increase but mainly from HV (industrial) loads; domestic loads reducing. Steady. Steady. Slight reduction with minimum 15kVA transformer size. Step drop from -6.9% arising from change in metering point for Macraes Gold Mine load Closure or reduction of the gold mine would have a major impact on the above statistics for energy conveyed, maximum demand and load factor. 11 Seasonal differences between 2009 and 2013 will also influence this finding. The decrease in domestic load will also be affected by the consolidation of connections through sub-maining as the single connection then becomes classified as commercial. Asset Management Plan Page 34 of 193 OUR NETWORK 2.2 Summary of network configuration To supply OtagoNet‘s 14,812 customers12 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 33 kV line over the Pig Root13 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 2.2.1.1 Balclutha Grid Exit Point (GXP) Balclutha GXP is supplied by a double circuit tower 110 kV diversion (not a tee) from the Gore – Berwick single circuit 110 kV pole line. Supply is taken through eight 33kV feeders from the Balclutha GXP. 2.2.1.2 Naseby Grid Exit Point (GXP) Naseby GXP is supplied off a single circuit 220 kV tower line from Roxburgh to Livingstone and supplies the Ranfurly zone substation via two 33 kV circuits. 2.2.1.3 Halfway Bush Grid Exit Point (GXP) The Halfway Bush GXP supplies the coastal area north of Dunedin and Palmerston by a double circuit 110 kV tower line that splits into two single circuit pole lines just north of Dunedin. The supply is transformed to 33 kV at Palmerston at the site previously owned by Transpower. The Palmerston zone substation is supplied by 2km of 33kV line from this previous GXP site. There are also 33kV lines heading south to Waikouaiti (Merton zone substation) and west across the Pig Root to Deepdell. Prior to 1 April 2014 Palmerston was supplied at 110 kV from a Transpower GXP at Palmerston but OtagoNet gained ownership of the Transpower lines from Halfway Bush and the Transpower Palmerston substation on 31 March 2013 with completion of the transaction on 1 April 2014. The acquisition of the Transpower assets and subsequent improvements to the OtagoNet network will result in increased reliability of supply for the Waitaki coastal area and reduce operational costs. 2.2.1.4 Paerau generation The 12.25 MW Paerau hydro scheme was built by Otago Power Limited in 1984 and then sold to TrustPower as a result of the enactment of the Electricity Industry Reform Act 1998. Paerau‘s generation is injected into the Ranfurly zone substation at 66 kV and is embedded with the Macraes Gold Mine load. 2.2.1.5 Falls Dam generation The Pioneer Generation Limited (PGL) 1.25 MW Falls Dam hydro scheme is connected to the 33 kV network at Oturehua. PGL owns the equipment to enable connection onto the OtagoNet 33 kV Line. 2.2.1.6 Mt Stuart Generation The Pioneer Generation Limited (PGL) 7.65MW Mt Stuart wind scheme is connected to the 33 kV network on the Glenore-Lawrence line. PGL owns the equipment to enable connection onto the OtagoNet 33 kV line. 12 FY2013 disclosure connections total. 13 Between Palmerston and Ranfurly and yes it is spelt this way… named by John Turnbull Thomson. Asset Management Plan Page 35 of 193 OUR NETWORK 2.2.1.7 Bulk Supply Characteristics Table 8 – Bulk supply characteristics (highest half-hour) Supply Point Balclutha GXP Naseby GXP 14 Palmerston GXP Paerau Falls Dam Mt Stuart Voltage 110/33kV 220/33kV 110/33 kV 66 kV 33 kV 33 kV Rating 60MVA 80MVA 10 MVA 24 MVA 1.25 MVA 8 MVA Firm Rating 28.1MVA 34.2MVA 10.0 MVA 15 15 MVA 1.25 MVA 15 7 MVA Peak Load FY2013 27,182kW (Feb) 24,948kW (April) 9,030 kW (Jun) 12,409 kW 1,281 kW 7,500 kW 2.2.2 Subtransmission network OtagoNet‘s subtransmission network comprises two electrically separate networks as depicted in Figure 14. The subtransmission network comprises 74 km of 66 kV line and 539 km of 33 kV 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. It includes a large number of lightly loaded zone substations because the long distances are beyond the reach of 11 kV. OtagoNet‘s subtransmission network is different to most other electricity distribution businesses in that it has very little redundancy because of the low load density; it may be essentially characterised as 33 kV feeders. This impacts on reliability as 33 kV line faults result in larger customer outages and this focuses the asset management towards the condition and integrity of these lines. As poor condition lines are rebuilt they are generally rebuilt with concrete poles, galvanised steel crossarms and clamp-top insulators to maximise reliability and life. 2.2.3 Zone substations OtagoNet owns and operates 34 zone substations with a 66/33 kV interconnecting station (at Ranfurly). A description of each zone and its security level is given in Table 9. Additionally there are eight 33/0.415 kV distribution transformers supplied direct off the 33kV subtransmission network at Balmoral Water Scheme, Big Sky Dairy, Cormack, Hore‘s Pump, O‘Malley‘s House, O‘Malley‘s Pump, Rough Ridge and Tisdall. 14 The transfer to halfway Bush GXP is effective from 1 April 2014. The peak load provided here relates to the configuration existing prior to that. 15 This firm rating is based on the number and capacity of the transformers on site, however, it should be noted that these sites are connected to the network via a single supply route. Asset Management Plan Page 36 of 193 OUR NETWORK Figure 14 – Subtransmission network Table 9 - Zone Substations Substation Nature of load Description of substation Supply security Charlotte Street (Balclutha) Urban domestic and commercial with some rural loads including farms and timber mills Dual 33kV supply to a 33kV indoor switchboard, with three 33kV feeders. Dual 5MVA transformers, 11kV indoor switchboard No loss of supply after first contingent event (N-1) Clarks Remote farms rural Tee off the 33kV radial line beyond Middlemarch. 0.5MVA 22kV SWER substation. Load restored in time taken for repair of first contingent event (N) Clinton Small urban township and rural farms Radial 33kV from Clifton switches. 2.5MVA transformer and outdoor 11kV substation. Load restored in time taken for repair of first contingent event (N) isolated Asset Management Plan Page 37 of 193 OUR NETWORK Substation Nature of load Description of substation Supply security Clydevale Small urban township and rural farms Alternate 33kV lines supplying 2.5MVA transformer and outdoor 11kV substation. Load restored in time taken for repair of first contingent event (N) Deepdell Remote farms rural Alternate 33kV lines supplying 0.75MVA transformer and basic 11kV outdoor substation. Load restored in time taken for repair of first contingent event (N) Elderlee Street (Milton) Urban domestic and commercial with some rural loads including farms and timber mills Supplied off a 33kV ring. Dual 5MVA transformers and 11kV indoor switchboard. No loss of supply after first contingent event (N-1) Finegand Rural farming Meat processing plant Three supply routes at 33kV. 2.5MVA transformer and outdoor 11kV substation. A 33kV feed to Processing plant. Load restored in time taken for repair of first contingent event (N) Glenore Rural farming Supplied off a 33kV ring. 1.5MVA transformer and outdoor 11kV substation. Load restored in time taken for repair of first contingent event (N) Greenfield Dairy processing plant Single 33kV line with 33kV circuit breaker and 33kV regulator with three 33kV feeds to the plant. Load restored in time taken for repair of first contingent event (N) Golden Point Mining Teed off the Deepdell to Palmerston 33kV line. 5MVA transformer with indoor 11kV switchgear. Load restored in time taken for repair of first contingent event (N) Hindon Remote farms rural Radial 33kV line to 0.5MVA 22kV SWER and 0.1MVA 11kV substation. Load restored in time taken for repair of first contingent event (N) Hyde Rural farming irrigation load with Alternate 33kV line to a 2.5MVA transformer and outdoor 11kV substation. Load restored in time taken for repair of first contingent event (N) Kaitangata Small urban township and rural farms Radial 33kV to a 2.5MVA transformer and outdoor 11kV substation. Load restored in time taken to isolate and back-feed after first contingent event (N) Lawrence Small urban township and rural farms Alternate 33kV lines to a 2.5MVA transformer and indoor 11kV substation. Load restored in time taken for repair of first contingent event (N) Macraes Mining Gold mine processing and Radial 66kV line to dual 7.5/15MVA 66/11kV transformers with 66kV switchyard and indoor 11kV switchboard. Load restored in time taken for repair of first contingent event (N) Merton Urban domestic and commercial with some rural farms and one large chicken farm Teed off the radial 33kV Palmerston to Waitati. Dual 2.5MVA transformers and outdoor 11kV substation. Load restored in time taken for repair of first contingent event (N) Middlemarch Small urban township and rural farms Radial 33kV from 2.5MVA transformer 11kV substation. Deepdell to and outdoor Load restored in time taken for repair of first contingent event (N) Milburn Sawmills and some rural load transferred off Milton and Waihola Teed off the Elderlee to Waihola 33kV line. One 3/5MVA transformer and one 2.5MVA transformer with indoor 11kV switchgear. Load restored within 25 minutes after first contingent event (N) North Balclutha Urban domestic and commercial with some rural 33kV line from Balclutha GXP. 5MVA transformer and outdoor 11kV substation. Load restored in time taken to isolate and back-feed after first contingent event (N) 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. Load restored in time taken for repair of first contingent event (N) isolated isolated Asset Management Plan Page 38 of 193 OUR NETWORK Substation Nature of load Description of substation Supply security Owaka Small urban township and rural farms Radial 33kV line from Finegand. 2.5MVA transformer and outdoor 11kV substation. Load restored in time taken for repair of first contingent event (N) Paerau Remote isolated rural farms and irrigation Radial 33kV from Ranfurly. 0.75MVA transformer and basic 11kV substation. Load restored in time taken for repair of first contingent event (N) Palmerston Urban domestic and commercial with some rural farms and timber mills Radial 33kV to transformers and substation. dual 2.5MVA outdoor 11kV Load restored in time taken for repair of first contingent event (N) Patearoa Rural farming irrigation with Teed off radial 33kV line to Paerau 2.5MVA transformer and outdoor 11kV substation with 33kV regulator for the Paerau line. Load restored in time taken for repair of first contingent event (N) Port Molyneux Small seaside township and rural farms Teed off radial 33kV line to Owaka. 2.5MVA transformer and outdoor 11kV substation. Load restored in time taken for repair of first contingent event (N) Pukeawa Rural farming Alternate 33kV lines to a 0.75MVA transformer and basic 11kV substation. Load restored in time taken for repair of first contingent event (N) Ranfurly Urban domestic and commercial with some rural farms and irrigation 33/66kV step-up and switching station Dual heavy 33kV lines from Naseby GXP to a dual 2.5MVA transformers and outdoor 11kV substation. Dual 12.5/25MVA 33/66kV transformers, 33 and 66kV outdoor substations. No loss of supply after first contingent event (N-1) for 66/33 loads. Other load restored within 25 minutes after first contingent event (N) Stirling Fonterra Stirling Cheese Factory 33kV line and cable switch-able between two 33kV lines from Balclutha GXP. 5MVA transformer and 11kV indoor switchboard. Load restored in time taken for repair of first contingent event (N) 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. Load restored in time taken for repair of first contingent event (N) Waipiata Rural farming irrigation with 33kV tee off the 33kV line from Ranfurly to Deepdell. 1.5MVA transformer and outdoor 11kV substation. Load restored in time taken for repair of first contingent event (N) Waitati Small urban townships and rural farms Radial 33kV line from Palmerston to a 2.5MVA transformer and outdoor 11kV substation. Load restored in time taken for repair of first contingent event (N) Wedderburn Rural farming Teed off the 33kV line from Ranfurly to Falls Dam. 0.75MVA transformer and outdoor 11kV substation. Load restored in time taken for repair of first contingent event (N) Table 10 Generation connection points Generation Nature of load Description Supply security Mount Stuart Pioneer Generation Wind farm 33kV circuit breaker with remote monitoring and control. Load restored in time taken for repair of first contingent event (N) Falls Dam Pioneer Generation hydro generation station No OtagoNet switchgear on site. Load restored in time taken for repair of first contingent event (N) Paerau Hydro 12.25MW hydro generation station Radial 66kV line from Ranfurly. Dual 7.5/15MVA 66/11kV transformers with 66kV switchyard and indoor 11kV board. Load restored in time taken for repair of first contingent event (N) Asset Management Plan Page 39 of 193 OUR NETWORK 2.2.4 Distribution network 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 prevents the provision of an 11kV alternative for load transfer to the 33kV supply from the 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. OtagoNet has a small amount of underground distribution cable mainly in newer housing areas and in special circumstances to avoid clearance issues. 2.2.4.2 Construction The network construction is largely similar in rural and urban areas, with the main differences being closer pole spacing in towns, under-built LV and larger transformers that are often ground-mounted in the towns. OtagoNet also has remote and rugged areas that are serviced, sometimes at considerable extra cost, even for similar line types, due to increased travel times and specialised vehicles required to install poles in rugged terrain. Some of the worst areas require extensive use of helicopter and tracked vehicles. Line rebuild standards use concrete poles and hardwood crossarms to ensure long lives. 2.2.4.3 SWER lines The network includes 949 km of Single Wire Earth Return (SWER) lines. This is a cheaper form of line construction applicable for feeding small loads at the fringes of the network. Regulatory requirements limit the impact on affected telecommunications circuits which generally requires the high voltage current on this line construction to be 8 amps or less. OtagoNet has identified a number of SWER transformer installations below current industry guidelines in terms of earthing practice and these are planned for upgrade as discussed further in the life cycle and risk sections of this plan. As load requirements build, SWER lines are progressively replaced with the more normal 2-phase and 3-phase line construction. 2.2.4.4 Per substation basis The split of the distribution network on a per substation basis is presented in Table 11. Safety and reliability are the strongest drivers of allocation of resources, with customer density providing an indication of priority for other works. Table 11 – Distribution network per substation Substation / Feeder Balmoral Becks Line Length (km) Cable Length (km) Customers Customer Density (per km) 0.00 0.00 1 27.50 0.00 32 Big Sky Dairy 0.00 0.00 1 Brothers Peak 2.15 0.00 2 0.93 70.97 1.09 1532 21.26 134.73 0.00 169 1.25 Charlotte Street Clarks Asset Management Plan 1.16 Page 40 of 193 OUR NETWORK Substation / Feeder Clinton 292.28 1.72 718 Customer Density (per km) 2.44 Clydevale 282.44 1.21 561 1.98 Cormack 0.00 0.00 1 Craiglynn 3.41 0.00 5 1.47 Deepdell 57.35 0.40 80 1.39 150.26 1.10 1428 9.43 Finegand 95.09 0.72 281 2.93 Glenore 94.26 188 1.99 Elderlee Street Line Length (km) Cable Length (km) Customers Golden Point 0.00 0.00 1 Greenfield 0.00 0.00 1 117.34 0.00 128 1.09 11.81 0.00 16 1.35 0.00 0.00 1 Hyde 38.08 0.01 63 1.65 Kaitangata 99.22 0.01 586 5.91 Lawrence 182.18 0.36 667 3.65 0.00 0.00 1 Merton 124.34 1.62 1319 10.47 Middlemarch 119.14 0.70 314 2.62 40.59 0.69 101 2.45 121.28 0.34 1191 9.79 O'Mally's House 0.00 0.00 1 O'Mally's Pump 0.00 0.00 1 28.19 0.00 79 2.80 Owaka 287.27 1.23 849 2.94 Paerau 26.88 0.00 37 1.38 0.00 0.00 1 168.71 1.12 969 5.71 Patearoa 85.94 0.82 173 1.99 Port Molyneux 36.51 0.14 365 9.96 Pukeawa 42.35 0.51 71 1.66 Ranfurly 202.99 1.42 1089 5.33 Redbank 3.53 0.00 4 1.13 Rough Ridge 0.00 0.00 1 Stirling 0.00 1.08 1 0.93 30.27 0.00 28 0.92 0.00 0.00 1 Waihola 92.77 0.97 551 Waipiata 82.24 0.79 180 2.17 Waitati 67.68 4.38 959 13.31 Wedderburn 35.56 1.02 46 1.26 Unallocated 0.21 0.91 18 16.01 3255.53 24.39 14812 4.52 Hindon Hills Creek Hore's Pump Macraes Mining Milburn North Balclutha Oturehua Paerau Hydro Palmerston Stoneburn Tisdall Asset Management Plan 5.88 Page 41 of 193 OUR NETWORK Note some lines are unallocated to a substation or feeder, and some SWER is cable. 2.2.5 Distribution substations Just as zone substation transformers form the interface between OtagoNet‘s subtransmission and distribution networks, distribution transformers form the interface between OtagoNet‘s 11kV distribution and LV (400/230 V) networks. OtagoNet‘s distribution substations range from 1-phase 3 kVA pole-mounted transformers with only minimal fuse protection to 3-phase 1,500 kVA ground-mounted transformers that are dedicated to single customers as shown in Table 12. Table 12 – Number of distribution substations Rating Pole Ground 1-phase up to 15 kVA 2668 6 1-phase 30 kVA 401 7 1-phase 50 kVA 144 4 1-phase 75 kVA 3 1-phase 100 kVA 11 1-phase 200 kVA 5 1 3-phase up to 15 kVA 150 3 3-phase 30 kVA 178 1 3-phase 50 kVA 239 6 3-phase 75 kVA 33 1 3-phase 100 kVA 83 10 3-phase 200 kVA 75 21 3-phase 300 kVA 38 41 3-phase 500 kVA 3-phase 750kVA 49 1 10 3-phase 1000 kVA 7 3-phase 1500 kVA 1 Total 4029 168 The voltage regulators are managed and recorded separately from distribution transformers and details are as follows: Table 13 - Voltage Regulators Location Balmoral Craiglynn Dunback Mahinerangi Naseby Redbank Stoneburn Tahakopa Purpose 33/0.4 kV regulation of a low voltage for the local water scheme Regulation of a single wire 11 kV circuit from a small 33/11 kV isolating transformer feeding a small remote community. 11 kV regulation at a point 14 km from Palmerston zone substation for a further 20 km of line to Morrisons. Regulation of a single wire 11 kV circuit from a small isolating transformer feeding a small remote community. 11 kV regulation for a large holiday destination 11 km from Ranfurly zone substation. Regulation of a single wire 11 kV circuit from a small 33/11 kV isolating transformer feeding a small remote community. Regulation of a single wire 11 kV circuit from a small 33/11 kV isolating transformer feeding a small remote community. 11 kV regulation at a point 18 km from Owaka zone substation for a popular holiday destination and a further 25 km of line into the Chaslands. Asset Management Plan Page 42 of 193 OUR NETWORK 2.2.6 LV network 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 voltdrop to about a 200 m radius from each transformer. 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 which would otherwise occur in the 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 11 kV. XLPE or PVC cable (only 19 km in total). 2.2.6.4 Per substation basis On a per substation basis OtagoNet‘s split of LV network is shown in Table 14. 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 14 – LV network per substation Substation / Feeder Line Length (km) Cable Length (km) Customers Customer Density (per km) Balmoral 0.00 0.00 1 Becks 0.00 0.00 32 Big Sky Dairy 0.00 0.00 1 Brothers Peak 0.00 0.00 2 27.32 3.31 1532 50.01 Clarks 0.34 0.30 169 267.03 Clinton 8.68 0.19 718 80.97 Clydevale 6.53 0.03 561 85.49 Cormack 0.00 0.00 1 Craiglynn 0.00 0.00 5 Deepdell 2.58 0.00 80 30.99 31.18 0.78 1428 44.68 Finegand 2.94 0.04 281 94.23 Glenore 1.28 0.49 188 105.84 Golden Point 0.00 0.00 1 Greenfield 0.00 0.00 1 Hindon 0.62 0.00 128 Hills Creek 0.00 0.00 16 Charlotte Street Elderlee Street Asset Management Plan 206.03 Page 43 of 193 OUR NETWORK Substation / Feeder Line Length (km) Cable Length (km) Customers Customer Density (per km) Hore's Pump 0.00 0.00 1 Hyde 1.34 0.00 63 46.90 Kaitangata 14.97 0.10 586 38.88 Lawrence 20.70 1.65 667 29.84 0.00 0.00 1 33.85 3.83 1319 35.00 Middlemarch 7.97 0.06 314 39.11 Milburn 2.02 0.16 101 46.27 North Balclutha 21.53 4.21 1191 46.26 O'Mally's House 0.00 0.00 1 O'Mally's Pump 0.00 0.00 1 Macraes Mining Merton Oturehua 0.97 0.08 79 75.20 Owaka 17.28 1.71 849 44.71 Paerau 0.00 0.00 37 Paerau Hydro 0.00 0.00 1 29.82 1.28 969 31.16 Patearoa 3.21 0.55 173 45.97 Port Molyneux 6.30 0.34 365 54.95 Pukeawa 0.13 0.02 71 484.24 Ranfurly 24.82 2.12 1089 40.42 Redbank 0.00 0.00 4 Rough Ridge 0.00 0.00 1 Stirling 0.00 0.00 1 Stoneburn 0.00 0.00 28 Tisdall 0.00 0.00 1 Waihola 11.42 2.99 551 38.24 Waipiata 3.32 0.29 180 49.91 24.08 4.68 959 33.34 Wedderburn 1.15 0.00 46 40.15 Unallocated 199.83 0.31 18 0.09 506.20 29.52 14812 27.65 Palmerston Waitati Note that LV line and cable data is not complete. 2.2.7 Secondary assets and systems 2.2.7.1 Load control assets OtagoNet currently owns and operates the following load control transmitter facilities for control of ripple relays: Three 33 kV 492 Hz 100 kVA injection plants at Naseby, Palmerston and Balclutha points of supply. One new 33 kV 317 Hz 100 kVA injection plant at Balclutha point of supply which will gradually take over from the 492 Hz plant as relays are replaced. Asset Management Plan Page 44 of 193 OUR NETWORK 2.2.7.2 Protection and control 2.2.7.2.1 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, earthfault 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: - Transformer and tap changer temperature sensors. - Surge sensors. - Explosion vents. - Oil level sensors. 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 the 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. Switches Switches provide no protection function but allow simple manual operation to provide control/isolation. 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 protection for high impedance faults. Links Links provide no protection function but allow manual operation to provide sectionalising/isolation. 2.2.7.2.2 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. 2.2.7.2.3 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. 2.2.7.3 SCADA and Communications SCADA is used for control and monitoring of zone substations and remote switching devices and for activating load control plant. SCADA has the potential to improve network reliability through the management of network automation including automatic sectionalising and re-configuration of the network under faults. Installation of more Asset Management Plan Page 45 of 193 OUR NETWORK automatic reclosers/sectionalisers monitored through the SCADA system is promoted in this plan to be undertaken as resources allow. 2.2.7.3.1 Master station OtagoNet‘s SCADA master station 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 44 remote terminal units at all of the OtagoNet zone substations and Transpower points of supply. 2.2.7.3.2 Communications links OtagoNet currently owns and operates the following communications links for SCADA and VHF voice communications: Figure 15 - OtagoNet SCADA Radio Network Asset Management Plan Page 46 of 193 OUR NETWORK Figure 16 - OtagoNet Mobile Radio Network 2.2.7.4 Other assets 2.2.7.4.1 Mobile generation PowerNet makes a 275 kW and a 350 kW diesel generator available for planned work and power restoration although these are not owned by the network. However, it is also planned to purchase additional generators that will be owned by OtagoNet including a 1 MVA step-up transformer to be used with hired generators to provide for zone substation support, all as part of a strategy to minimise customer service disruption given the increase in renewal works planned on the network. 2.2.7.4.2 Customer connection assets OtagoNet has 14,81216 customer connections; the network connection assets are usually an ICP fuse on a pole as most of the connections are overhead (97%) while the few underground connections would have the ICP fuse mounted in a pillar box on the customer‘s boundary. The load control relay mounted in most houses and some commercial installations is the property of the Retailer. 16 FY2013 disclosure numbers Asset Management Plan Page 47 of 193 OUR NETWORK 2.2.7.4.3 Stand-by generators None. It is intended to purchase a standby generator to supply the office of OtagoNet and its primary depot within the next few months. 2.2.7.4.4 Power factor correction None. 2.2.7.4.5 Mobile substations None. 2.2.7.4.6 Metering Time of use (TOU) meters have not been installed at any of the zone substations and instead OtagoNet relies on the metering information derived from SCADA measurements and the Retailers‘ TOU meters for the largest 50 customers and the Grid Exit Point metering, the information from which is available to OtagoNet. All domestic meters are owned by the retailers (including any smart meters). Given the incumbent retailer has not installed large numbers of new smart meters, OtagoNet does not have access to potentially useful information, such as LV voltage levels, and is considering installing its own smart meters to some of its larger distribution transformer sites so it can gather more information on its service quality. Asset Management Plan Page 48 of 193 PERFORMANCE BENCHMARKING 3. Performance Benchmarking This section examines the current OtagoNet performance in relation to other Electricity Distribution Businesses (EDBs) using the FY2013 disclosure data.17 The purpose of the benchmark comparison is to identify any poor or outlier performance in relation to OtagoNet‘s peers and to direct asset management strategy where performance improvement is indicated. 3.1 Costs 3.1.1 Opex (operational expenditure) The following chart summarises OtagoNet‘s FY2013 total opex (direct and indirect) in relation to other EDBs in New Zealand. Figure 17 Comparison of opex by category 17 This benchmarking is taken from or developed from the Hyland McQueen Ltd EDB Comparative Performance Report; November 2013. Asset Management Plan Page 49 of 193 PERFORMANCE BENCHMARKING Notable features are: A large proportionate spend on fault maintenance in relation to other opex compared to the average EDB; The ratio of fault to preventive opex is one of the highest in the peer grouping; A total opex per connection (ICP) that is in the upper quartile. Higher business support expenditure relative to other networks.18 Whilst these findings will vary from year-to-year depending on the extent of the faults experienced and there are always factors that confound comparisons such as accounting differences and opex/capex trade-offs, there is an indicative case that OtagoNet needs to move towards more preventive maintenance work rather than reactive fault repair. This is addressed in the developed strategy of improving the condition inspection methods and processes and then driving more maintenance and replacement off the condition inspection data as discussed further in this plan. 3.1.1.1 Direct Opex Direct opex is that proportion of opex spent directly on the network assets (eg on asset maintenance) as opposed to the indirect components of business management and operations. The comparative review found that direct opex for each EDB was best related to the network length of the EDB after allowing different scale multiplication factors for the different types of network (urban overhead + rural overhead + rugger/remote overhead + underground). The regression chart of direct opex with composite length is presented following and where OtagoNet is marked as the red dot point.19 18 The information disclosure requirements split indirect opex into ―business support‖ and ―system operations and network support‖. OtagoNet out-source much of its business support to PowerNet with the control room function is included in the direct costs and this arrangement may affect any comparison with other businesses in the relationship between operations and business costs. In total, indirect opex benchmarks below expectation based on the number of ICPs. 19 The blue dotted lines represent the 95% confidence limits of the regression line itself and the orange dotted lines represent the 95% confidence bounds of the prediction (interpolation) limits of the regression relationship. Asset Management Plan Page 50 of 193 PERFORMANCE BENCHMARKING Figure 18 Regression of direct opex Whilst OtagoNet plots just above the regression line, it plots well within the error bounds for the relationship between direct opex cost and the scale of its network and gives no evidence that OtagoNet‘s direct opex costs are excessive in relation to its peers. Accounting differences also play a part in the variability seen between EDBs noting that OtagoNet expenses renewal works on a single pole whereas others may capitalise this work and this will have the effect of accentuating OtagoNet‘s direct opex costs. Vegetation management (tree cutting) costs per km of line are also disclosed by some EDBs and, as the following chart shows, OtagoNet‘s costs benchmark well in this respect although we would expect this to be the case as vegetation density will be lower in parts of Otago than other places in New Zealand. Asset Management Plan Page 51 of 193 PERFORMANCE BENCHMARKING Figure 19 Regression of vegetation control costs 3.1.1.2 Indirect Opex Indirect opex is that proportion of opex spent on the business itself and on day operation of the network. It is typically benchmarked on a cost per basis. The following charts plot indirect opex in relation to both the connections and to the distribution transformer capacity of the different where OtagoNet is marked as the red dot point. the day-toconnection number of EDBs and In both of these measures, OtagoNet benchmarks well, indicating its indirect opex costs are in line with those of its peers. Asset Management Plan Page 52 of 193 PERFORMANCE BENCHMARKING Figure 20 Regression of indirect opex 3.1.2 Return on investment (ROI) As already discussed in this plan, OtagoNet has competing priorities of providing a cost efficient electricity supply service whilst funding its business and meeting its shareholder expectations. The following charts identifies OtagoNet in relation to its percentage rate of return on investment (pre-tax) and the components of its capital costs where the blue vertical lines represent the industry average. Asset Management Plan Page 53 of 193 PERFORMANCE BENCHMARKING Figure 21 Comparisons relating to return on investment This shows OtagoNet to have an average rate of return on investment but has the second largest ratio of investment value per connection, which arises from the low number of connections per km of line. Consequently OtagoNet also has a large value of retained revenue and depreciation per connection to support that capital investment. This highlights a key characteristic of the OtagoNet service cost make-up; that being the dominant component of the return of and return on capital that has to be supported on a low customer base and this arises from OtagoNet having to provide a large network to service a relatively small number of connections. This situation motivates the asset management policies of ensuring strong governance and management processes for justifying capital expenditure; developing comprehensive asset and risk management processes to lessen the asset holding risk premium for shareholders; and for seeking long asset lives through condition-based replacement, asset life extension and appropriate design. 3.2 Reliability SAIDI is the System Average Interruption Duration Index and represents the average customers experience of outages in minutes per annum. SAIDI is calculated by the multiplication of two components; SAIFI being the average number (frequency) of interruptions and CAIDI being the average duration of any single interruption. Interruptions may be planned where parts of the network need to be taken out for maintenance or repair, and unplanned outages due to faults, storm conditions or third party damage. Asset Management Plan Page 54 of 193 PERFORMANCE BENCHMARKING 3.2.1 SAIDI Comparative SAIDI for the FY2013 year is described in the following charts, which shows OtagoNet to have an upper quartile SAIDI performance and for an above average proportion of planned SAIDI in relation to its peers. Figure 22 Comparisons of SAIDI As discussed in section 6 (service levels), the high SAIDI figure derives from a high CAIDI value and where the SAIFI (or frequency of events) is actually below average in relation to other EDBs given the scale exposure of the network. The high ratio of planned SAIDI is also discussed and arises from our increased lines replacement program combined with inability to back-feed when parts of the network are taken out for replacement work. This motivates asset strategy initiatives to reduce planned SAIDI through greater use of mobile generation. 3.2.2 SAIFI SAIFI is the system averaged interruption frequency index and measures the average number of interruptions per annum. It is usually only considered within the context of unplanned interruptions. The following chart compares the make-up of OtagoNet‘s SAIFI to its peers. Whilst there will be annual variability in this measure, the general conclusion is that OtagoNet‘s unplanned SAIFI make-up is not markedly different from other EDBs. The lower than average vegetation SAIFI is a pleasing result as trimming trees away from lines has been a focus of network maintenance over recent years. The SAIFI margin represents the margin between the reported SAIFI and the service quality threshold mandated by the Commerce Commission and shows OtagoNet is well within the regulated service quality on this measure. Asset Management Plan Page 55 of 193 PERFORMANCE BENCHMARKING Figure 23 Comparisons of SAIFI The following chart identifies the reported SAIFI in relation to the expected SAIFI (blue line) calculated based on the extent of the network exposed to faults. As shown, OtagoNet has lower SAIFI than expected but also that this measure carries a wide range of variability. Asset Management Plan Page 56 of 193 PERFORMANCE BENCHMARKING Figure 24 Regression of SAIFI 3.2.3 CAIDI CAIDI measures the duration of the average interruption and is again usually discussed in relation to unplanned outages. CAIDI = SAIDI/SAIFI and the following chart illustrates this ratio by plotting SAIDI against SAIFI in comparison to other EDBs and where OtagoNet is marked as the red dot point. This shows OtagoNet with an outlier performance arising from a high CAIDI value (as we have already noted that SAIFI is lower than the regression line expectation in the FY2013 year). Figure 25 Comparison of CAIDI Asset Management Plan Page 57 of 193 PERFORMANCE BENCHMARKING The high value of CAIDI in FY2013 largely arises out of the high variability seen in unplanned CAIDI on OtagoNet‘s and other networks as illustrated in the following chart that shows the variability in both CAIDI and SAIFI from FY2008 to FY2012 (OtagoNet marked in red). Figure 26 CAIDI and SAIFI variation between years OtagoNet experiences high variability in CAIDI largely because it is a small network with a wide variety in the types of faults that can affect it. A predominance of faults on the more remote sections on its network in a particular year will greatly affect the average fault restoration time in that year. For these reasons OtagoNet does not focus on CAIDI as a meaningful measure. OtagoNet‘s response to the reliability benchmarking for unplanned outages, discussed further in section 5 (performance and improvement) of this plan, is to continue to address the root causes of faults on the network with a focus on those assets with a high impact (ie 33 kV sub-transmission faults). 3.3 Technical Efficiency This section examines OtagoNet‘s comparative performance in the utilisation of its network assets and in particular the utilisation of its distribution transformer capacity and the technical load losses on its network. High utilisation is desirable as it indicates efficient use of capital. High losses are undesirable as it indicates inefficiency for the load transfers across the network but also unusually low losses may indicate overdesign and capital inefficiency. Asset Management Plan Page 58 of 193 PERFORMANCE BENCHMARKING 3.3.1 Distribution transformer utilisation The following chart compares OtagoNet distribution transformer utilisation to other EDBs in the FY2013 year.20 The utilisation is compared on two measures; the nominal utilisation which just compares the maximum demand to the total distribution transformer capacity and; the utilisation measured by using just the standard connection demand (ie removing large commercial and industrial load). The most useful measure of transformer utilisation is expected to lie between these two measures.21 These measures have also been corrected for the different energy densities on the different networks as networks with high energy density (which OtagoNet is not) have more opportunity to achieve higher utilisation through increased load diversity. OtagoNet has above average utilisation on the nominal measure and below average utilisation on the standard connections measure giving an overall average performance. We would note that a low performance on the standard connection basis is unsurprising given 67% of OtagoNet‘s distribution transformers are 15 kVA or less and where 15 kVA is now a minimum standard size for single service connections. This measure is therefore limited in its applicability to this largely rural network. No change in OtagoNet‘s distribution transformer loading practice is required based on these comparisons. Figure 27 Comparison of transformer utilisation 20 The charts on the left give the regression and the charts on the right give the corresponding comparison normalised against that regression trend (ie as if all networks had the same average energy density). 21 The points marked with orange squares (of which OtagoNet is one) have high ratios of non-standard to total connections and makes proper assessment of transformer utilisation less reliable for these entities. Asset Management Plan Page 59 of 193 PERFORMANCE BENCHMARKING 3.3.2 Technical losses The following chart plots the annualised load losses on the different EDB networks and where the load loss is regressed against the network circuit length in a log-log relationship. As shown, OtagoNet plots below the expectation line indicating it has a lower load loss than would be expected based on the size of the network. While this is a good result from the point of energy efficiency, unduly low losses may also indicate over-capitalisation of the lines - that is conductor sizes are too large for cost efficiency. However, conductor sizing for the OtagoNet network is largely based on keeping voltage drop under 10% and, due to the relatively long lines, load losses become secondary to this. After consideration, no change in the network design policy is indicated by this comparative performance. Figure 28 Regression of network losses 3.4 Asset base This section examines the aging of OtagoNet‘s asset base in relation to its peers. Figure 29 below contrasts the range of expected lives in years (top chart) for the different network asset classes between the different EDBs and highlights the different expectations in how long assets will last. This figure also contrasts the consumption of the expected life in percent for each EDB under each asset class (bottom chart). Again, OtagoNet is marked with the red dot points. Variability in the expected life of an asset class arises from both the make-up of that asset class – for example distribution lines may have different proportions of wood and concrete poles with different life expectancies – and in each EDBs experience or expectation of the life of its assets. Variance in the consumption of the expected life largely arises from the degree to which a network is aged, its growth rate and the degree of replacement capital that has been undertaken on it. Asset Management Plan Page 60 of 193 PERFORMANCE BENCHMARKING Figure 29 Comparison of expected lives and consumption of lives From these benchmark comparisons we conclude: • • • By-and-large, OtagoNet shows with life expectations for its assets that fall within the 50 percentile bounds. OtagoNet has a relatively low expectation of the life of its distribution cables. Although OtagoNet has only a small quantity of distribution underground cable (and sub-transmission cables) compared to other more urban networks, a point of the lifecycle plan for this asset class will be a re-examination of our life expectations. OtagoNet has a high expectation on the life of its distribution transformers. This arises from the long lives seen for these assets particularly in the dry Central Otago area where corrosion rates are markedly reduced. Nevertheless, continued aging of OtagoNet‘s distribution switchgear, transformers and cables is inevitable Asset Management Plan Page 61 of 193 PERFORMANCE BENCHMARKING • • and understanding and measuring true life expectancy and achieving means for life extension will be a focus of the lifecycle management of these assets. Distribution and sub-transmission lines form the major part of OtagoNet‘s asset base and the comparisons show these assets are far more aged in average than most other EDBs. OtagoNet has commenced and will continue to expend capital to pull back the average age of its network lines assets which will be achieved through condition based inspection and replacement. Network other and non-network asset classes are included in the charts for completeness but comprise a wide variety of asset types from buildings to vehicles to computers and no meaningful conclusions should be drawn from comparisons of such wide asset groupings. Asset Management Plan Page 62 of 193 RISK MANAGEMENT 4. 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 how it prepares for extreme events. Risk management is used to bring risk within acceptable levels. 4.1 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. 4.1.1 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. Large impact work takes priority over smaller impact work. 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. 4.1.2 Risk Categories Risks are classified against the following categories: Weather - Wind – extreme winds that cause either pole failures or blow debris into lines. - Snow – impact can be by causing failure of lines or severely limiting access around the network. - Flood – while the Regional Council has installed flood protection works, there is still a risk in the lower Clutha area and so this still needs to be considered. Physical - 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) - Liquefaction – post Christchurch 22 February 2011 6.3 quake, the hazard of liquefaction has become a risk to be considered. - 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. - Tsunami – The OtagoNet network services coastal areas that are potentially vulnerable to tsunami. - Terrorism – malicious damage to equipment can interrupt supply. Asset Management Plan Page 63 of 193 RISK MANAGEMENT Asset Failures – equipment failures can interrupt supply or negate systems from operating correctly. Failure of security could allow public access to restricted areas. Asset failures may also harm the public, staff, property and the environment. Human - Health & Safety – harm to public and staff (includes safety clearances). - 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. - Third Party Accident – most typically car vs. pole; injury to the driver/passengers and damage and loss of service to the network could be significant. - Vandalism – range varies from malicious damage to ‗tagging‘ of buildings or equipment. - Theft – gives rise to safety issues both for the thief and potentially for staff and customers when earthing copper is stolen. Corporate - Stranded assets/Bad debt – providing business processes that insure appropriate contracts and guarantees are agreed prior to undertaking large investments. - Loss of revenue – loss of customers through by-pass or economic downturn could reduce revenue. - Management contract – failure of Marlborough Lines as OtagoNet‘s asset manager and PowerNet as OtagoNet‘s administration manager. - Regulatory – failure to meet regulatory requirements. - Resource – field staff to undertake operation, maintenance, renewal, augmentation, extension and retirement of network assets. - Environmental – release of pollutants into the air, water or soil. - 4.1.3 Risk Tactics The following tactics are used to manage risk under the following broad categories: 4.2 Operate a 24hr Control centre. Provide redundancy of supply to large customer groups. Spares management Asset inspections Design standards Corporate governance Locate assets away from risk zone. Involvement with the local Civil Defence. Review present sites risk to earthquake and liquefaction. Risk Details 4.2.1 Weather Table 15 - Weather Risk Event Extreme Wind Asset Management Plan Likelihood High Consequence Can be considerable and widespread Responses If damage occurs on lines this is remedied by repairing the failed equipment. Asset condition inspections and renewal to manage network resilience. Page 64 of 193 RISK MANAGEMENT Event Snow Likelihood High Consequence High but usually localised Flood Very Low Low Responses 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 generation. Helicopters may be used. Asset condition inspections and renewal to maintain and improve network resilience. 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. Waitati and Waikouaiti zone substations are planned to be rebuilt away from their present flood-prone sites. 4.2.2 Physical Table 16 - Physical Risk Event Earthquake Likelihood Very Low Consequence Low to major Tsunami Very Low Low to extreme Liquefaction Very Low Low to Medium Fire Very Low High Terrorism Very Low High Responses Disaster recovery event. Review of existing buildings and equipment for seismic strength is ongoing; transformer assessment and mitigation all but complete (only Glenore site remaining) Most of the network is sited in areas not vulnerable to tsunami however this is dependent on the size of the event. Specify buildings and equipment foundations to minimise impact. Review of existing buildings and equipment foundations for seismic strength is ongoing. Continue to maintain fire detection and alarm systems. Identify and replace deteriorating transformers and switchgear noting that generally fault levels are low and most indoor bulk oil switchgear has now been removed from the network. Ensure security of restricted sites. Use alternative routes and equipment to restore supply where feasible A total of $750k has been budgeted for seismic upgrades of substation outdoor structures over the next 5 years. 4.2.3 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. Asset Management Plan Page 65 of 193 RISK MANAGEMENT Table 17 - Equipment Failure Risk Event 33 kV cable Likelihood Low Consequence Low Power Transformer Very Low Low – depends on supply security arrangements 11 kV Switchgear Low Medium Pole failure or conductor breaks Some failures historically Medium to High Oil Spill Very Low Low to medium depending on containment Security measures Very Low Medium Batteries Low Protection Very low Low to medium (backup zone protection) Medium 11 kV cable Very low Low to medium SCADA RTU Low Low SCADA Masterstation Very low Low Load Control Low Low to medium Asset Management Plan Responses Each section of cable has an alternative 33 kV route. Larger substations have dual transformers to allow one to be removed from service due to fault or maintenance. Continue to undertake 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. Annual inspection. Replacement before end of life with modern equipment. The network configuration allows switchgear to be bypassed at most times. Most indoor bulk oil switchgear has now been removed from the network and switchboards are generally air insulated (not pitch-filled). Routine condition inspection with data capture into GIS. Pole condition inspections may include X-ray examination as well as sounding and dig inspections. On-going process of inspection and renewal. 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 any clean rain water. Monthly checks of each restricted site. Remote monitoring of access doors by SCADA is being implemented. Continue monthly check and annual testing. Continue regular operational checks. Mal-operations investigated. Temporary supply restorations can be undertaken. 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. Continue to independently monitor and 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. Manually operate plant with test set if SCADA controller fails. LSI (Transpower) peak now different to OtagoNet demand peak. Page 66 of 193 RISK MANAGEMENT 4.2.4 Human Table 18 - Human Risk Event Health & Safety Likelihood Low Consequence Low to High Pandemic Low Low to High Third party accident Low to medium Low to Medium Vandalism Medium Low to High Theft Medium Medium to High Responses Normal business processes followed and legislative and code requirements complied with. Regular checks and inspections to find risks and then control. Work to the PowerNet Pandemic plan. Includes details such as working from home, only critical faults work and provide emergency kits for offices etc. Depends on what asset is impacted. Have resource to bypass and or repair for car vs. pole. 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. Theft of copper earthing conductor has been reported on the network. Police are informed when discovered. Theft is discovered during routine inspection and earth testing. Safety inspection of ground mount equipment and earthing located in public locations is undertaken annually. 4.2.5 Corporate Table 19 - Corporate Risk Event Bad debt / stranded assets Likelihood Low Consequence Low - high Loss of Revenue Very Low High Management Contract Extremely low High Regulatory Low High Resource Low High Asset Management Plan Responses Prudence in network investment. Keep abreast of new developments in distributed generation technologies and costs. New larger contracts require customer guarantee before supply is provided. Continue to have Use of System Agreements with retailers. New large investments for individual customers to have a guarantee. Strengthen governance on capital expenditure. Engage in active risk management. Continue with management contracts with PowerNet and Marlborough Lines noting both organisations operate a Business Continuity Plan. Meet regulatory obligations. Engage with regulator as required. Continue to enhance relationships with present contractors. Continue to recruit appropriate staff and utilise appropriate resources. Page 67 of 193 RISK MANAGEMENT Event Environment al Likelihood Low Consequence Medium to high Public Liability Low High Responses Monitor likely pollutant sources (noise, oil, SF6, treated wood, concrete, etc) Comply with RMA and District Plan requirements. Act in a prudent manner and comply with all legislative and industry code requirements. 4.2.6 Projects Projects undertaken by the network are prioritised in accordance with the strategies expressed in this plan, where safety is the highest priority. Option selection includes evaluation of over-run costs, achievement of the project goals and other business risks. 4.2.7 Highlighted Risks The following highlighted risks have been targeted for action in this plan: Equipment Failure Recent pole failures at loads less than design have spurred increased condition inspections with the employment of temporary staff to cover the whole asset over a shortened inspection cycle. Condition inspection templates have been enhanced as well as streamlining the capture of the condition data into the GIS/AMS system. This plan continues and further develops these initiatives including the development of risk prioritisation leveraged off the condition data. Whilst this programme is directed at improving safety and reliability on the network, it has the potential to identify more assets that need immediate replacement than have been provided within estimated costs. Earthing Safety Until they were revoked under the 2011 amendments,22 Single Wire Earth Return (SWER) systems were covered under code of practice ECP41 cited in the Electricity (Safety) Regulations 2010. SWER systems are no longer specifically cited in the safety regulations and any test of competency would fall to the electricity industry best practice being the EEA Guide for HV SWER Systems – October 2010. A number of OtagoNet‘s SWER installations include bar joints in the earth continuity conductors (as is practiced in other HV 3-phase grounded neutral systems) and have common HV and LV earths both of which are not recommended practice in the guide and having joints in the HV earth conductor would not have complied with the previous regulations set out in ECP41. Opening the HV earth joint with the SWER supply in service would be a safety hazard and is non-compliant with both the previous regulations and the current guidelines. OtagoNet has therefore commenced a program to upgrade all its SWER installations to full code compliance as soon as practicable with priority to ugrading the installations with joints in the HV conductors. An estimated cost of $1m has been allocated for the FY2015 year with a total cost of $2.5m and this will be subject to further review as further information becomes known. Network Resilience Electricity supply is not only an essential service, it may represent community safety in such events as prolonged snow storms. OtagoNet has and will continue with its programme of refurbishing its deteriorated lines with the new replacement standard of concrete poles, AAAC conductor and clamp-top insulators for subtransmission lines where that is appropriate. 22 Electricity (Safety) Amendment Regulations 2011, regulation 9 (which revoked clause 21); 33A (which inserted requirements for limitation of effects on telecommunications circuits) and 46 (which substituted new schedule 2 removing code of practice ECP41) Asset Management Plan Page 68 of 193 RISK MANAGEMENT A known risk, particularly with concrete poles with steel crossarms and clamp-top insulators, is that excessive line loads (for example in extreme snow or ice storms) may break the poles in cascade failure. Placement of in-line strains or the selected placement of a number of more load bearing hardwood poles to restore the intended resilience is considered under a programme of design assessment for which OtagoNet has already purchased new line design software. The priority is to complete line design reviews on its 33 kV subtransmission lines as they are refurbished. 4.3 Contingency Plans OtagoNet has the following contingency plans: 4.3.1 OtagoNet 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: Maintain or promptly restore supply to its customers 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. 4.3.2 OtagoNet 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 work. The plan aims to manage the impact of an influenza pandemic on OtagoNet‘s staff and contractors 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 and other appropriate measures. 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. 4.3.3 Network Operating Plans As contingency for major outages on the OtagoNet network PowerNet holds 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. 4.4 Insurance OtagoNet holds the following insurances: Material damage and business interruption over Substations, Buildings and the Macraes 66kV line. Contracts works Utilities Industry Liability Programme (UILP) that covers Public, Forest & Rural Fires and Products liability. Statutory liability Marine Cargo. Employee and Fidelity/Crime Contractors working on the network are asked to hold Liability Insurance. Asset Management Plan Page 69 of 193 PERFORMANCE AND IMPROVEMENT 5. Performance and improvement This section firstly evaluates OtagoNet‘s performance over the 2012/13 year and secondly identifies areas where OtagoNet believes it could improve its business through asset management practices. 5.1 Outcomes against plans The following tables provide the cost out-turns for financial years FY2010 to FY2013 and cost variance to budget for years FY2012 and FY2013 plus expected out-turn for the FY2014 year based on accounts to 31 January 2014. Out-turn costs in FY2013 dollars (000) FY2010 FY2011 FY2012 FY2013 Capital Expenditure: Customer Connection Capital Expenditure: System Growth Capital Expenditure: Reliability, Safety and Environment Capital Expenditure: Asset Replacement and Renewal Capital Expenditure: Asset Relocations $874 $622 $278 $1,172 $1,704 $940 $1,523 $2,488 $299 $2,054 $1,927 $610 FY2014 (est) $ $ $ $4,687 $5,375 $4,535 $5,066 $ $19 $0 $0 $0 $ Capital Expenditure on assets $6,481 $9,190 $8,844 $9,657 $11,200 Operational Expenditure: Routine and Preventative Maintenance Operational Expenditure: Refurbishment and Renewal Maintenance Operational Expenditure: Fault and Emergency Maintenance Operational Expenditure on assets $1,184 $1,204 $1,087 $1,329 $ $637 $706 $877 $428 $ $1,446 $1,354 $1,615 $1,742 $ $3,268 $3,264 $3,580 $3,499 $4,300 Total direct expenditure on assets $9,749 $12,454 $12,424 $13,156 $15,500 Variation to Budget Capital Expenditure - Customer Connection System Growth Asset Replacement and Renewal Reliability, Safety and Environment Asset Relocations Subtotal - Capital Expenditure on asset management Operational Expenditure: Routine and Preventative Maintenance Operational Expenditure: Refurbishment and Renewal Maintenance Operational Expenditure: Fault and Emergency Maintenance Subtotal - Operational Expenditure on asset management Total direct expenditure on distribution network FY2012 FY2013 50% -35% -61% -29% Not defined -26% FY2014 (to 31 Jan 14) 35% 69% -90% 534% -100% -3% -16% -16% -12% 1% -30% 10% 20% -2% -2% +18% -21% -3% -9% The tables show OtagoNet has been consistent in expending approximately $8m to $10m p.a. capital and $4m opex in average on its network assets over the last 3 financial years. Variances exist within expenditure categories but total capital and total Asset Management Plan Page 70 of 193 PERFORMANCE AND IMPROVEMENT opex remain only marginally under budget in the last two financial years and the forecast under-expenditure in the current year is anticipated to be made-up early in the next financial year. 5.2 Performance against targets 5.2.1 Primary service levels The charts below displays the actual and target SAIDI and SAIFI reliability performance on the network for the 2012/13 year. Note that class B are planned outages while class C are fault outages. The out-turn for the current financial year (FY2014) is SAIFI of 2.9 and SAIDI of 360 both of which are above target. This is an increase on the last 3 years and arises from 3 incidents: • a snow storm on 20th June 2013 causing approximately 1m customer minutes; • a pole fire in September 2013 disrupting power to the township of Waikouaiti that could not be quickly repaired due to crew safety issues from a prolonged lightning storm with the incident causing approximately 1.2m customer minutes; and • high winds in January that broke an old wooden pole near Clinton causing 300k customer minutes (noting that this pole was part of a line that had been 90% renewed in the previous year but this pole was part of a section not replaced due to land owner consent issues for access at that time). SAIDI Performance 600 500 Total number of interruption minutes SAIDI minutes 400 Reliability planned - Class B 300 Reliability unplanned - Class C Targets for Forecast Year - Class B 200 Targets for Forecast Year- Class C 100 Regulatory threshold FY2018 FY2017 FY2016 FY2015 FY2014 FY2013 FY2012 FY2011 FY2010 FY2009 FY2008 0 Figure 30 OtagoNet SAIDI trend and forecast target Asset Management Plan Page 71 of 193 PERFORMANCE AND IMPROVEMENT SAIFI Performance 4 3.5 SAIFI (frequency) 3 2.5 Total interruption frequency Reliability planned - Class B 2 1.5 Reliability unplanned - Class C Targets for Forecast Year - Class B Targets for Forecast Year - Class C 1 Regulatory threshold 0.5 0 Figure 31 OtagoNet SAIFI trend and forecast target The charts show target SAIDI and SAIFI for unplanned (class C) outages have risen and fallen in recognition of the inherent variability of these statistics when applied on a small network (including faults due to and access under extreme weather), with current targets set about the average of past experience with a modest future decline to recognise improvement strategies. OtagoNet has greater control over planned outages reflected by the closer matching of target and out-turn values. Setting reliability performance levels is discussed further in section 6.1 of this plan. 5.2.2 Outage composition, trends and targeting This section examines the composition and trends of the outages occurring on the network and considers this in relation to the asset strategies and targets. The following charts of Figure 32 show the average total customer minutes per year for the years 2009 to 2013 categorised by network voltage and class of outage (plan or fault). The left hand chart shows the total customer minutes while the right hand chart shows the customer minutes per km of line. This chart reveals that, while the 11 kV distribution lines produce the majority of outage minutes, on a per kilometre basis targeting work on the 33 kV lines is more beneficial for reliability improvement and this represents one of the key strategies for our reliability improvement expenditure. Note that while the 33 kV lines only show a small amount of planned outage minutes, this does not necessarily relate to OtagoNet undertaking less work on these lines but rather is reflective of OtagoNet‘s recognising the importance of these lines and seeking portable generation or back–feeding options when taking out these lines to limit the customer impact. Asset Management Plan Page 72 of 193 PERFORMANCE AND IMPROVEMENT Figure 32 Composition of customer outage minutes The following chart of Figure 33 examines the performance of planned outages in the period 2009 to 2013 and consists of 4 charts. The top left chart shows the spread of planned customer minutes per ICP (effectively per zone planned SAIDI) in each year and by location. This shows that planned work is occurring reasonably uniformly across all parts of the network and reveals the effect of meshed parts of the network, such as exist in Milton (Elderlee St sub) and Balclutha (Charlotte St sub) having significantly reduced outage minutes due to the ability to back-feed customers. The top right chart plots the distribution of planned outage times by location and where the blue vertical line is the 4-hour average target and the brown line the 6-hour target. The bottom left chart highlights the planned outage performance in the 2013 calendar year and shows the performance was short of meeting 95% of planned outages being 6 hours or less. The revised service level discussed in section 6.1 set 95% of planned outages to be 6 hours or less, this being a more meaningful measure of the customers experience of planned outages than the previous average time measurement, and these charts show this will be a stretch target for OtagoNet to accomplish. The bottom right chart plots the distribution of the number of affected connections in each outage. This shows that some 90% of planned outage affect 40 connections or less and points to the use of mobile generation as a potential means to reduce planned SAIDI levels and deliver reliability improvement to OtagoNet‘s customers. Whilst this cannot be applied in all cases and must be economic when it is applied, the increased use of mobile generation to limit the impacts of planned outages is promoted as an appropriate reliability improvement strategy in this plan. Asset Management Plan Page 73 of 193 PERFORMANCE AND IMPROVEMENT Figure 33 Examination of planned outages The charts of Figure 34 and Figure 35 following show the make-up of the unplanned outages for 33 kV lines and for distribution (11 kV) lines with the left-hand charts showing the composition by fault type, where the predominance of ―defective equipment‖ faults is clear, and the right-hand charts that further detail the next level make-up of the defective equipment faults. Both of these charts highlight the reliability impact of the deteriorated nature of the lines and reinforce the asset strategy of continuing with condition-based replacement. Asset Management Plan Page 74 of 193 PERFORMANCE AND IMPROVEMENT Figure 34 Composition of 33 kV faults Figure 35 Composition of 11 kV (distribution) faults The following chart of Figure 36 looks at the fault count per km of line for distribution lines with the left-hand chart showing the average fault rate by composition and location and the right-hand chart showing the variation in fault rate by location and year. This highlights the elevated fault rate of lines in the Waitati area, which arises from the known poor nature of the lines in this area and the incursion of trees, and the elevated fault rate of the lines about Port Molyneux - largely caused by the salt corrosion in this area. Both these regions are targeted in this plan for reliability improvement works. Asset Management Plan Page 75 of 193 PERFORMANCE AND IMPROVEMENT Figure 36 Unplanned outages by density, location, type and variance OtagoNet has been engaged in increased levels of line refurbishment over the past few years and the chart of Figure 37 following shows a pleasing trend in decreasing defective equipment faults per annum from circa 2010. The strategies set out in this plan are designed to continue to drive down the defective equipment fault rate on the network. Figure 37 Distribution defective equipment fault count trend Asset Management Plan Page 76 of 193 PERFORMANCE AND IMPROVEMENT 5.2.3 Secondary service levels Results for 2012/13 are shown below. 23 Attribute Customer Satisfaction: New Connections Customer Satisfaction: Faults Voltage Complaints {Reported in Network report.} Planned Outages Measure YE 31/3/13 Actual Phone: Friendliness and 24 courtesy. {CSS: Q3(c)} Phone: Time taken to answer call. {CSS: Q3(a)} Overall level of service. {CSS: Q5} Work done to a standard which meet your expectations. {CSS: Q4(b)} Power restored in a reasonable amount of time. {CES: Q4(b)} Information supplied was satisfactory. {CES: Q8(b)} OtagoNet first choice to contact for faults. {CES: Q6} Number of customers who have justified voltage complaints regarding power quality Average days to complete investigation Period taken to remedy justified complaints Provide sufficient information. {CES: Q3(a)} Satisfaction regarding amount of notice. {CES: Q3(c)} Acceptance of maximum of one planned outage per year. {CES: Q1} Acceptance of planned outages lasting four hours on average. {CES: Q1} >3.5 4.25 23 >3.5 4.09 23 >3.5 4.55 23 >3.5 4.21 23 >60% 88% 23 >60% 88% 23 >20% 13% <15 6 <30 5 <60 29 >75% 92% >75% 94% >50% 97% >50% 94% (Reference in parentheses {} indicates where the information is collected/reported from.) 5.2.4 Other service levels 5.2.4.1 Technical efficiency The following charts show the target and actual values for the network loss ratio and the transformer utilisation. As shown, the loss ratio has decreased from 7% to 5% largely owing to the shift in the metering point to Ranfurly for the 66 kV lines that supply the Macraes Gold mine load. This change occurred as the mine owner now bears the cost of losses on what was a heavily loaded line until its upgrade in the FY2012 year which was funded by the mine owner. 23 Results for the CSS survey are for FY2012 as the next iteration of the survey was not complete at the time of compiling this AMP 24 CSS = Customer Satisfaction Survey undertaken by sending questionnaire to customers with invoices. Asset Management Plan Page 77 of 193 PERFORMANCE AND IMPROVEMENT The transformer utilisation is substantially on target in the FY2013 year. As shown in the benchmarking section, the current level of utilisation benchmark satisfactorily in relation to OtagoNet‘s peers given the load density of the network. Network loss ratio (%) 9.0% 8.0% 7.0% 6.0% 5.0% Losses 4.0% 3.0% 2.0% 1.0% 0.0% Target Network transformer utilisation (%) 40.0% 38.0% 36.0% 34.0% 32.0% 30.0% 28.0% 26.0% 24.0% 22.0% 20.0% Transformer Utilisation FY2018 FY2017 FY2016 FY2015 FY2014 FY2013 FY2012 FY2011 FY2010 FY2009 FY2008 Target 5.2.4.2 Financial Measure 2012/13 AMP Target Actual Comment Direct costs/km No target $796.3 Indirect costs/ICP $174.94 $210.2 Benchmarking shows direct costs per km is appropriate compared to other electricity distribution businesses Benchmarking shows indirect costs per ICP in FY2013 benchmark appropriately (and lower than the regression expectation) in comparison to other electricity distribution businesses. Asset Management Plan Page 78 of 193 PERFORMANCE AND IMPROVEMENT The following chart shows the financial performance from FY2010 for the measures of direct cost per line kilometre and indirect cost per ICP. Direct costs include routine and preventive maintenance, refurbishment and renewal maintenance, and fault and emergency maintenance. Indirect costs include business administration and operations expenditure (Transpower and pass-through costs are excluded). The chart shows a relatively consistent performance for direct cost per km up to FY2013. Note that no previous target has been set for this parameter as direct cost per network replacement cost was used in the FY2013 AMP. However, as replacement cost is no longer disclosed, this target has been replaced with direct cost per km of circuit for supply. We note also that in the comparative benchmarking assessments, OtagoNet showed with a satisfactory performance in the comparison of direct costs on this basis. The increase in direct opex cost per kilometre for forecast out-turn FY2014 and budget FY2015 arises from undertaking the accelerated network surveillance program discussed later in this plan plus an allowance for renewal maintenance expenditure expected to arise from that surveillance. Direct cost per kilometre is expected to return to FY2013 levels by FY2017. Indirect costs have shown a rising trend above CPI and the FY2013 performance was marginally above target. The rise in indirect costs relates to a 37% increase in the PowerNet management fee. Despite the indirect costs becoming fully allocated, the indirect costs per ICP continue to benchmark well in comparison with other distribution businesses as shown in section 3.1.1.2. Note also that from and including FY2015 the system control room costs are shifted from direct to indirect opex to better reflect the contractual arrangements with PowerNet. Direct/km and Indirect/ICP Direct/km Target direct/km Indirect/ICP Target indirect/ICP 1200.0 400.0 Direct cost/km ($ FY2014) 300.0 800.0 250.0 600.0 200.0 150.0 400.0 100.0 200.0 Indirect cost/ICP ($ FY2014) 350.0 1000.0 50.0 0.0 0.0 FY2010 FY2011 FY2012 FY2013 FY2014 FY2015 FY2016 FY2017 FY2018 FY2019 5.3 Improvement areas and strategies 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 not simply by writing a better document but by improving the asset management processes, systems and activities that it uses. Asset Management Plan Page 79 of 193 PERFORMANCE AND IMPROVEMENT 5.3.1 Maintenance and Capital Works Gaps: Strengthen capital governance and management. Discussion: Benchmarking and other analysis shows OtagoNet with the highest capital burden per connection arising from the low connection density of the network. The nature of the network also leads to inherent cross subsidy between customers as customers pay uniform capacity charges. Additionally, prices appear to be at a level that is causing some customers to avoid multiple connection charges through installing a single point supply feeding multiple installations. In addition, government policy and the potential of distributed generation technologies combined with an aging population in the coverage area, all threaten the revenue base of the network. This reinforces that prudent capital spending must be a key focus for OtagoNet. Strategies: OtagoNet will continue to make safety its first priority combined with enhancing its capital governance processes through development of standard project assessment templates and development of project evaluation tools including improved surveillance and increased utilisation of information. 5.3.2 Condition assessment Gaps: Formalised condition assessment process and data capture. Assessment of condition risks Discussion: Pole failures have highlighted improvements can be made, particularly in the capture and use of condition inspection data. Additionally, condition data exists in isolation and is not formally linked to the network risks that deteriorated assets pose. This will also assist with capital governance as it will strengthen the capital expenditure justifications. Strategies: We have commenced upgrading the asset inspection templates and the means of capturing that data into the GIS/AMS system. Other processes are under development to automate the risk assessment impact of observed condition to better measure total network risk and help prioritise maintenance and replacement works. 5.3.3 Planned outages Gaps: High level of planned outage SAIDI. Discussion: Benchmarking and performance analysis shows high levels of planned outage SAIDI largely driven by the current lines refurbishment programme and the lack of network meshing to back-feed customers. However, the cost of establishing cross-feeder links typically outweighs the benefits. Strategies: We plan to increase the use of mobile generation to support load during planned outages where this is feasible and cost effective. This plan includes allocated capital for the purchase of appropriate step-up transformers to be used with hired or purchased mobile generation plant. Asset Management Plan Page 80 of 193 SERVICE LEVELS 6. Proposed service levels This section describes how OtagoNet sets the various service levels to its stakeholders as set out in section 1.6 of this plan. 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 mandatory requirements in the provision of a network service. These service levels are categorise and described in Figure 38 below. This section describes those service levels in detail and how OtagoNet justifies the service levels delivered to its‘ stakeholders. Primary Customer service levels Customer service levels Paid for by customers for the benefit of customers Secondary Customer service levels Tertiarary Customer service levels Compliance with price path threshold Overall bundle of delivered services Regulatory service levels Compliance with reliability threshold Disclosure of financial and energy delivery efficiency measures Paid for by customers for the benefit of other stakeholders Public safety Other service levels Amenity value Electrical interference Figure 38 Types of service levels OtagoNet‘s service levels are justified in six main ways: Positive cost benefit within the revenue capability. The consequence of meeting regulatory and/or industry best practice for security levels. By what is achievable for the business to resource. 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 or regulation imposes a new service level. Asset Management Plan Page 81 of 193 SERVICE LEVELS 6.1 Customer-oriented service levels This section describes the service levels expected to be provided to customers which affect them directly and exclusively. Customer surveys 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 evident from OtagoNet‘s research that there is an increasing value placed by customers on the absence of flicker, sags, surges and brown-outs. Other research indicates that flicker is probably noticed more when it is usually absent. 6.1.1 Primary service levels OtagoNet‘s primary service levels are continuity and restoration which recognise its customer‘s requirements. To measure performance in this area two internationally accepted indices have been adopted: SAIDI – system average interruption duration index. This is a measure of how many minutes of supply are interrupted per year. SAIFI – system average interruption frequency index. This is a measure of how many system interruptions occur per year. The benchmarking results presented in section 2, showed OtagoNet as: having a lower than expected SAIFI given its network exposure but; having a high cost of fault relative to preventive maintenance expenditure; having a modestly high ratio of planned SAIDI (attributed to the current line refurbishment program and lack of network inter-connection for back-feeding), and; having a high proportion of its faults arising from failing components (currently being addressed through condition-based inspection and replacement). Additionally, the area demographics discussed in section 1 showed increasing connections of load more sensitive to load outages but that the high capital burden per ICP for OtagoNet‘s customers requires a high degree of prudence in further capital expenditure. The outcome of customer consultation undertaken by a telephone survey, public meetings and one-on-one meetings showed the majority of customers are content with the present level of service but the expectations of customers vary depending upon their individual requirements such as milking, irrigation and their dependency upon electricity as an essential service in a harsh winter climate. Irrespective, customers do not want a lesser level of service and have an expectation going forward that reliability of supply will be at least maintained or improved. Positive feedback has been received relative to the increased levels of maintenance and capital expenditure undertaken on the network in recent years. After consideration of these factors, OtagoNet has set reliability targets to recognise: an expected slowly decreasing fault outage rate as the network reliability continues to respond to the lines refurbishment programme; modest improvement in fault SAIDI as the few economically justified opportunities for network interconnection are constructed; modest improvement in fault SAIFI as the economically justified opportunities for installing additional 11 kV distribution reclosers are enacted; a greater emphasis on reducing planned SAIDI through the increased use of mobile generation but; an increase in planned work requiring outages due to both the planned programme of work and the unknown work that may be required as data is returned from the condition inspection surveys. Asset Management Plan Page 82 of 193 SERVICE LEVELS Target levels for unplanned outages have therefore been calculated by averaging the values over the regulatory period (2004/05 – 2008/09) (allowing for normalisation to remove extreme events as per the Commerce Commission guidelines), and decreasing future years by 0.5% p.a. Target levels for planned outages have been maintained constant acknowledging that OtagoNet remains uncertain on the planned reliability impacts of its work programme mainly due to the unknown condition driven work. OtagoNet also acknowledges that it needs to improve its ability to forecast planned outages impacts and this also motivates the improvement of our capital governance and management processes discussed in this plan. Projections of our reliability targets for the next ten years ending 31 March 2024 are set out in Table 20 below. Table 20 – Primary service levels SAIDI Year End Class B 25 Limit1.1 31/03/15 31/03/16 31/03/17 31/03/18 31/03/19 31/03/20 31/03/21 31/03/22 31/03/23 31/03/24 1.2 148 148 148 148 148 148 148 148 148 148 Class C 175 174 173 173 172 171 170 169 168 168 SAIFI Total Class B 361.08 1.3 323 322 321 320 319 318 318 317 316 315 Class C 1.4 0.63 0.63 0.63 0.63 0.63 0.63 0.63 0.63 0.63 0.63 Total 2.07 2.06 2.05 2.04 2.03 2.02 2.01 2.00 1.99 1.98 3.120 2.70 2.69 2.68 2.67 2.66 2.65 2.64 2.63 2.62 2.61 In practical terms this means customers can broadly expect the reliability stated in Table 21 below where the reliability deteriorates towards the outer extents of the network where there is no ability to provide backup and there are long single lines exposed to faults. Table 21 – Expected unplanned outages by location General location Balclutha, Milton, Ranfurly Towns (dual transformers; some meshed distribution) Villages (single subtransmission lines; no meshed distribution) Anywhere else (long rural feeders) Expected reliability One outage per year of about 60 minutes duration Two outages per year of about 90 minutes duration in total Three outages per year of about 120 minutes duration in total Four outages per year of about 240 minutes duration in total For planned outages OtagoNet has set a new target of undertaking 95% of planned outages in 6 hours or less, as this is a more meaningful measurement of the customers experience of planned outages. As shown in the performance and improvement section, this is a stretch target for OtagoNet and will be used as a driver for closer management of planned outages and the increased use of mobile generation. 25 Limit calculated by the Commerce Commission Default Price-Quality Path methodology, with reference data from 1 April 2004 to 31 March 2009. Normalised data must not exceed the limit two out of three years. Normalisation calculates a boundary value which is used to reduce the daily value when an extreme event occurs. Asset Management Plan Page 83 of 193 SERVICE LEVELS 6.1.2 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 capital asset solutions. 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 measures could include: How satisfied customers are after communication regarding: - Tree trimming - Connections - Faults Time taken to respond to voltage complaints and time to remedy justified voltage complaints. Sufficient notice of planned shutdowns Targets for our secondary services are set at levels reflective of a good corporate citizen, that maintain or improve the historic trend and recognise the likely impact of targeted improvements. For example: More Public Relations with newsletter and fridge-magnet should increase OtagoNet as first point of contact for faults. The newsletter will also inform customers relative to safety issues and energy efficiency. Table 22 below sets out the targets for these service levels for the next ten years.26 Table 22– Secondary service levels Year ending Measure 31/3/15 31/3/16 31/3/17 … 31/3/24 Phone: Friendliness and 27 courtesy. {CSS: Q3(c)} Phone: Time taken to answer call. {CSS: Q3(a)} Overall level of service. {CSS: Q5} Work done to a standard which meets customer expectations. {CSS: Q4(b)} Customer satisfied power restored in a reasonable amount of time. {CES: Q4(b)} >3.5 >3.5 >3.5 … >3.5 >3.5 >3.5 >3.5 … >3.5 >3.5 >3.5 >3.5 … >3.5 >3.5 >3.5 >3.5 … >3.5 >60% >62% >63% … >70% Attribute Customer Satisfaction: New Connections Customer Satisfaction: Faults 26 From this plan forward targets of customer satisfaction enquiries and number of customers making a voltage complaint have been dropped. The first is because the measure was unreliable in that in a random sample of 200, the number who had made an enquiry of the network was small and resulted in large variation between years. Additionally; it is often customers who have issues of service who do make contact so the measure is not unbiased. Voltage complaint has also been dropped noting that it is only upheld voltage complaints that have an asset management solution and this is the measure that has been retained. 27 CSS = Customer Satisfaction Survey undertaken by sending questionnaire to customers with invoices. Asset Management Plan Page 84 of 193 SERVICE LEVELS Year ending Measure 31/3/15 31/3/16 31/3/17 … 31/3/24 Information supplied was satisfactory. {CES: Q8(b)} OtagoNet first choice to contact for faults. {CES: Q6} Number of customers who have justified voltage complaints regarding power quality Provide sufficient information. {CES: Q3(a)} Satisfaction regarding amount of notice. {CES: Q3(c)} Acceptance of maximum of three planned outages per year. {CES: Q1} Acceptance of planned outages lasting four hours on average. {CES: Q1} >60% >62% >63% … >70% >35% >35% >35% … >50% <15 <15 <15 … <15 >75% >75% >75% … >75% >75% >75% >75% … >75% >50% >50% >50% … >50% >50% >50% >50% … >50% Attribute Voltage Complaints {Reported in network report.} Planned Outages {Where the information is collected / reported from.} 6.2 Safety Various legislation requires 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). OtagoNet seeks 100% compliance with all its legislated requirements and industry codes of practice. 6.3 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, as such, are service levels for which OtagoNet seeks 100% compliance. 6.3.1.1 Amenity value There are a number of Acts and other requirements that limit where OtagoNet can erect or maintain overhead lines: The Resource Management Act 1991. The Operative District Plans. Relevant parts of the Operative Regional Plan. Land Transport requirements. Civil Aviation requirements. Land owner consent Asset Management Plan Page 85 of 193 SERVICE LEVELS In general, OtagoNet will need to respond to these circumstances as they arise. 6.3.1.2 Supply quality 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 codes impose service levels on us: Voltage levels Harmonic levels (NZECP36:1993). Voltages induced into telecommunications circuits from SWER lines (regulation 33A of the Electricity (Safety) Regulations 2010) OtagoNet recognises that many of its LV lines are in poor condition and often include small conductor sizes owing to the age of the lines and the low load requirements at the time the line was built. This may result in poor voltage delivery to customers and reacting just to voltage complaints is not the best method to manage this service delivery. As discussed in this plan, OtagoNet intends to progressively upgrade its LV network not only to restore the condition of the lines but to also ensure that voltage quality is appropriate. Variable speed drives often used in conjunction with irrigation pumps emit harmonic currents. OtagoNet‘s policy is to require customers to limit such harmonics at source as required under the legislation. 6.4 Regulatory service levels 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 including the Electricity Distribution Information Disclosure Determinations 2012 and subsequent amendments. OtagoNet seeks 100% compliance in meeting its regulatory obligations. 6.4.1 Financial efficiency measures OtagoNet set two financial efficiency measures which are: Direct costs / km = [Routine and Preventative Maintenance] + [Refurbishment and Renewal Maintenance] + [Fault and Emergency Maintenance]) / [Total circuit km for supply] 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. OtagoNet‘s target financial efficiency measures are shown below. Note that previously OtagoNet set a target on the total opex cost per year per replacement cost of the network. As replacement cost is no longer disclosed it cannot be benchmarked so OtagoNet has moved to the metric of direct cost per circuit km. Justification for these service levels arises from the comparative benchmark findings discussed in section 2, that showed OtagoNet‘s direct and indirect opex costs in line with those of its peers, together with a short term step increase in direct costs arising from the accelerated program of condition inspections discussed further in the life cycle section of this plan. Asset Management Plan Page 86 of 193 SERVICE LEVELS Table 23 - Financial Efficiency Year ending Direct costs/km Indirect costs/ICP 31/3/15 31/3/16 31/3/17 31/3/18 31/3/19 31/3/20 31/3/21 31/3/22 31/3/23 31/3/24 $960 $820 $774 $774 $774 $774 $774 $774 $774 $774 $240 $240 $241 $241 $241 $241 $241 $241 $241 $241 Note that from FY2015, system control room costs have been shifted from direct to indirect opex. 6.4.2 Energy delivery efficiency measures The target energy efficiency measures are shown below. These measures are: 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 distribution transformer capacity]. The benchmarking of section 3 showed both the FY2013 loss ratio (5.1%) and the current capacity utilisation (29.8%) to benchmark satisfactorily given the size and circumstances of OtagoNet‘s network and justifies the continuation of these service targets at these levels. Note that previous AMPs set a service level target for network load factor. However, as OtagoNet cannot undertake retailing over its network and there are no effective asset management strategies that OtagoNet could reasonably undertake that would impact load factor, it has been dropped as a service level target. Table 24 - Delivery Efficiency Year ending Loss ratio Capacity utilisation 31/3/15 31/3/16 31/3/17 31/3/18 31/3/19 31/3/20 31/3/21 31/3/22 31/3/23 31/3/24 5.00% 5.00% 5.00% 5.00% 5.00% 5.00% 5.00% 5.00% 5.00% 5.00% 30% 30% 30% 30% 30% 30% 30% 30% 30% 30% Asset Management Plan Page 87 of 193 OUR DEVELOPMENT PLANS 7. Development plans Development plans are driven primarily by: 7.1 Increasing consumer demand due to growth or new connections or to generation power transfers over the network. Asset renewal requirements prompting network re-configuration (ie shifting the location of a zone substation when it must be rebuilt). Statutory or code requirements to improve service levels (Security of supply, safety or environmental compliance.). Internally generated initiatives to improve service levels. Planning approach and criteria 7.1.1 Planning detail OtagoNet has adopted the 22kV or 11kV feeder as OtagoNet‘s fundamental planning unit which includes either a single large consumer load, a point of generation injection, a distribution feeder, or other specific customer requirement. 7.1.2 Planning approaches OtagoNet plans its assets in three different ways; strategically, tactically and operationally as shown in Table 25 below: Table 25- Planning approaches Attribute Strategic Asset description Assets within GXP. Subtransmission lines and cables. Major zone substation assets. Load control injection plant. Central SCADA and telemetry. Distribution configuration e.g. decision to upgrade to 22kV. Number of consumers supplied Impact on balance sheet Asset valuation Anywhere from 500 upwards. Degree of specificity in plans Level of approval required Asset Management Plan Individual impact is high. Aggregate impact is moderate. Likely to be included in very specific terms, probably accompanied by an extensive narrative. Approved in principle in annual business plan. Individual approval by Governing Committee Tactical Operational Minor zone substation assets. All individual distribution lines (11kV). All distribution line hardware. All on-network telemetry and SCADA components. All distribution transformers and associated switches. All HV consumer connections. Anywhere from one to about 500. All 400V lines and cables. All 400V consumer connections. All consumer metering and load control assets. Individual impact is moderate. Aggregate impact is significant. Likely to be included in specific terms and accompanied by a paragraph or two. Individual impact is low. Aggregate impact is moderate. Likely to be included in broad terms on a program basis Approved in principle in annual business plan. Individual approval by the Engineering Approved in principle in annual business plan. Individual approval Anywhere from one to about 50. Page 88 of 193 OUR DEVELOPMENT PLANS Attribute Characteristics of analysis Strategic and possibly shareholders. Tends to use one-off models and analyses involving a significant number of parameters and extensive sensitivity analysis. Tactical Operational Manager. by Network Manager. Tend to use established models with some depth, a moderate range of parameters and possibly one or two sensitivity scenarios. Tends to use established models based on a few significant parameters that can often be embodied in procedural rules. OtagoNet has developed the following ―investment strategy matrix‖ shown in Figure 39, 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. 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, asset 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. 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 required. Asset Management Plan Page 89 of 193 OUR DEVELOPMENT PLANS Quadrant 4 Quadrant 3 Outside of existing network footprint Location of demand growth Capital Expenditure will be dominated by new assets that require both connection to existing assets and possibly upstream reinforcement. Likely to absorb lots of cash – may need capital funding. Easily diverts attention away from legacy assets. Likely to result in low capacity utilisation unless modular construction can be adopted. May have high stranding risk. Capital Expenditure will be dominated by new assets that require both connection to existing assets and possibly upstream reinforcement. Likely to absorb lots of cash – may need capital funding. Easily diverts attention away from legacy assets. Need to confirm regulatory treatment of growth. May have a high commercial risk profile if a single consumer is involved. Quadrant 2 Quadrant 1 Within existing network footprint Capital Expenditure will be dominated by enhancement rather than renewal (assets become too small rather than worn out). Regulatory treatment of additional revenue arising from volume thru’ put as well as additional connections may be difficult. Likely to involve tactical upgrades of many assets Capital Expenditure will be dominated by renewals (driven by condition). Easy to manage by advancing or deferring straightforward Capital Expenditure projects. Possibility of stranding if demand contracts. Lo Prevailing load growth Hi Figure 39 - Investment strategy matrix 7.1.3 Trigger points for planning new capacity As new capacity has valuation, balance sheet, depreciation and ROI implications for OtagoNet, endeavours are made to meet demand by other, less investment-intensive means, first. 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 26. 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 operation. These options are described in section 7.2 which also embodies an overall preference for avoiding new capital expenditure particularly given OtagoNet‘s the high capital burden per ICP identified in the benchmarking section. Table 26 - Summary of capacity "trigger points" Asset class Type Trigger Extension Location Asset Management Plan LV lines and cables Existing LV lines and cables don‘t reach the required location. Distribution substations Distribution lines and cables Load cannot be reasonably supplied by LV configuration therefore requires new distribution lines or cables and distribution Load cannot be reasonably supplied by LV configuration therefore requires new distribution lines or cables and substation. Page 90 of 193 OUR DEVELOPMENT PLANS Asset class Type Up-sizing Trigger LV lines and cables Distribution substations Capacity Tends to manifest as fuse blowing when current exceeds circuit rating. substation. Where fitted, MDI reading exceeds 90% of nameplate rating. Reliability Not applicable. Normally a Maintenance or Operational trigger, as reliability is not an indicator for up-sizing. Excursion beyond triggers specified in the EEA security guidelines and discussed further in section 7.2.2 Voltage at consumers‘ Voltage at Voltage at MV boundary consistently consumers‘ terminals of boundary transformer drops below 0.94pu. 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. Asset deteriorated to an unsafe condition or poses an undue risk as discussed further in the life cycle section of this plan. Third party requests work. Neighbouring assets being replaced. Security Voltage Renewal Condition Distribution lines and cables Analysis calculates that the peak current exceeds the thermal rating of the circuit segment. Asset class Type Trigger Zone substations Extension Location Up-sizing Capacity Load cannot be reasonably supplied by distribution configuration therefore requires new subtransmission lines or cables and new zone substation. Max demand consistently exceeds 100% of nameplate rating. Reliability Security Voltage Renewal Condition Asset Management Plan Subtransmission lines and cables Network equipment within GXP Load cannot be Load cannot be reasonably supplied reasonably supplied by distribution by new or extended configuration Subtransmission or therefore requires substation therefore new subtransmission requires new GXP lines or cables and equipment. new zone substation. Analysis calculates Max demand that the peak current consistently exceeds exceeds the thermal 80% of nameplate rating of the circuit rating. segment. Not applicable. Normally a Maintenance or Operational trigger, as reliability is not a trigger for up-sizing. Excursion beyond triggers specified in the EEA security guidelines and discussed further in section 7.2.2 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. Asset deteriorated to an unsafe condition. Third party requests work. Page 91 of 193 OUR DEVELOPMENT PLANS 7.1.4 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 incrementally add more over time but this is not economical for feasible. OtagoNet therefore 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 sizing steps 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: Overhead lines: - MV routes between zone substations, a minimum of Helium conductor. - Usually set by voltage drop limits and strength requirements - MV laterals Chlorine conductor - LV allow 20% growth Cables - Allow 100% growth Distribution transformers - Individual consumers, size to consumer capacity. - Domestic consumers based on following diversity: Maximum consumers Transformer Size 2 15 kVA 6 30 kVA 10 50 kVA 20 100 kVA 50 200 kVA 80 300 kVA 150 500 kVA [Note that this clearly depends on the individual load and network configuration circumstances. In most rural supply situations it is typically infeasible to connect other than a single property to a standard 15 kVA transformer because of voltage considerations]. Line equipment - Use standard ratings (e.g. ABS 400A, Recloser 400A) Power transformers - Allow expected area growth over 20 years Substation equipment - Use standard ratings Subtransmission lines - Allow expected area growth over 20 years OtagoNet‘s guiding principle is therefore to minimise the level of investment ahead of demand, then minimising the costs associated with doing the work. Asset Management Plan Page 92 of 193 OUR DEVELOPMENT PLANS 7.2 Prioritisation methodology 7.2.1 Options for meeting demand Table 26 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 Governing Committee 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 in relation to the cost. 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 or installing voltage regulators 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 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. 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 40 to broadly guide adoption of various approaches: Asset Management Plan Page 93 of 193 OUR DEVELOPMENT PLANS Install new assets Hi Modify existing asset Rate of payback Retrofit hitech Construct DG Lo Influence consumer demand Operational changes Do nothing Lo Hi Prevailing load growth Figure 40 - Options for meeting demand 7.2.2 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 at less than nominal rating. Use of local generation. Use of interruptible load (water heating, irrigation). Generally security of supply is greater in the urban areas or for larger customers where there are a lesser number of components in the supply chain and/or the revenue justifies a greater level of investment. 7.2.2.1 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. OtagoNet applies this standard for its network security. Asset Management Plan Page 94 of 193 OUR DEVELOPMENT PLANS 7.2.2.2 Issues with deterministic standards 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. OtagoNet will have the opportunity to consider such an approach as further information is gained relative to the network. 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 which is the approach adopted by OtagoNet. 7.2.2.3 Contribution of local generation to security From a security perspective, ideally local generation would need to have 100% availability which is unlikely from small undiversified plant and even less likely where the primary energy is 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 requirements. In practical terms OtagoNet will always seek to ensure the network has the ability to receive all available generation capacity. 7.2.2.4 OtagoNet security standards Table 27 below describes the security standards adopted by OtagoNet, whilst Table 28, lists the level of security at each zone substation (noting the security level using the codes listed in Table 28 and justifies any shortfall. In setting target security levels the following guiding principles are used: Where a substation is for the sole benefit of a single consumer, their preference for security will be considered in that individual line services agreement. The preferred means of providing security to rural zone substations will be backfeeding on the 11kV subject to interconnection, line ratings and surplus capacity at adjacent substations but noting that the low connection density of the network means such opportunities are not common. 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 27 - Minimum security levels required Description Load type Security level AAA Greater than 12MW or 6,000 consumers. No loss of supply after the first contingent event. AA Between 5 and 12MW or 2,000 to 6,000 consumers. All load restored within 25 minutes of the first contingent event. A(i) Between 1 and 5MW All load restored in the time necessary to isolate and back-feed following the first contingent event. A(ii) Less than 1MW All load restored in the time necessary to repair after the first contingent event. Table 28 - Substation security levels Substation Balmoral Becks Big Sky Dairy Asset Management Plan Min. Reqt A(ii) A(ii) A(ii) Actual Now A(ii) A(ii) A(ii) Remarks One pump One pump Page 95 of 193 OUR DEVELOPMENT PLANS Substation Brothers Peak Charlotte Street Clarks Min. Reqt A(ii) AA A(ii) Actual Now A(ii) AAA A(ii) Clinton A(i) A(ii) Clydevale A(i) A(ii) Cormack Craiglynn Deepdell A(ii) A(ii) A(ii) A(ii) A(ii) A(ii) Elderlee Street AA AAA Finegand A(i) A(ii) Glenore A(ii) A(ii) Golden Point A(i) A(ii) Greenfields A(ii) A(ii) Hindon A(ii) A(ii) Hyde A(i) A(ii) Kaitangata A(i) A(i) Lawrence A(i) A(ii) Macraes Mine AA A(ii) Merton A(i) A(ii) Middlemarch Milburn A(ii) AA A(ii) AA Mount Stuart A(i) A(i) North Balclutha O'Mally's House O'Mally's Pump Oturehua A(i) A(ii) A(ii) A(ii) A(i) A(ii) A(ii) A(ii) Owaka A(i) A(ii) Paerau A(ii) A(ii) Paerau Hydro AA A(ii) Palmerston A(i) A(ii) Asset Management Plan Remarks One radio repeater One 33 kV line and limited 11kV back feed, spare transformer to be purchased and stored here Dual 33 kV lines available but single transformer and limited 11kV back feed Load increasing. Long term plan to make closed 33 kV ring + dual transformers. One house Long term plan to establish higher capacity installation on new site. Multiple 33 kV feeds, single transformer and limited 11 kV back feed Multiple 33 kV feeds, single transformer and limited 11 kV back feed Now a single consumers back-up supply only Single 33 kV customer with limited back up on 11 kV Most customers can be back fed through 11 kV lines, except Macraes pumps where loss of supply is only an issue if the pond storage is low Single 33 kV supply; Restoration via 11 kV backfeeds Multiple 33 kV feeds, single transformer (new incl. 11 kV swgr) and limited 11 kV back feed No backup available with single consumers agreement off single 66 kV line. Single 33 kV line with dual transformers and limited 11kV backup. Plan to provide dual 33 kV supplies. Single Customer only required N reliability Security via 11 kV backfeed. One house One pump Single 33 kV line and single transformer. Limited 11kV back feed No backup available with single consumers agreement Single short (2km) 33 kV line dual transformers and limited 11kV back feed. Long term plan to relocate to Transpower GXP site after land purchase Page 96 of 193 OUR DEVELOPMENT PLANS Substation Min. Reqt Actual Now Patearoa A(i) A(ii) Port Molyneux Pukeawa Ranfurly Ranfurly 66/33 Redbank Rough Ridge A(ii) A(ii) A(i) AA A(ii) A(ii) A(ii) A(ii) AA AAA A(ii) A(ii) Stirling A(i) A(ii) Stoneburn Tisdall A(ii) A(ii) A(ii) A(ii) Waihola A(i) A(ii) Waipiata A(i) A(ii) Waitati A(i) A(ii) Wedderburn A(ii) A(ii) Remarks Increasing load requires 11kV reinforcement. One telecom repeater Limited 11kV back feed with single consumers agreement One pump Some 11kV back feed from adjacent substations Single (new) transformer; limited 11 kV back feed. Limited 11kV back feed from one distant substation. Plan to provide dual 33 kV after Palmerston GXP re-configuration 7.2.3 Choosing the best option to meet demand Each of the possible approaches to meeting demand that are outlined in section 7.2.1 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 Up to $50,000, commonly recurring, individual projects not tactically significant but collectively add up. Up to $250,000, individual projects of tactical significance. Up to $1,000,000 occurs maybe once every few years, likely to be strategically significant. Over $1,000,000 occurs maybe once in a decade, likely to be strategically significant. Decision tools OtagoNet standard rules. Industry common practice. Manufacturer‘s tables and recommendations. Simple spreadsheet model based on a few parameters. Spreadsheet model to calculate NPV that might consider 1 or 2 variation scenarios. Extensive spreadsheet model to calculate NPV, Payback that will probably consider several variation scenarios. Extensive spreadsheet model to calculate NPV, Payback that will probably consider several variation scenarios. Organisational level of evaluation Network Manager Network Manager Engineering Manager (Marlborough Lines) Governing Committee approval 7.2.4 Project prioritisation Designers and planners use the ‗decision tools‘ on projects to enable prioritisation and rationing of our resources. OtagoNet prioritises the work based on its needs to meet service standards and network condition assessment. It is the intent to be proactive and eliminate potential Asset Management Plan Page 97 of 193 OUR DEVELOPMENT PLANS faults before they occur. Some abnormal situations28 do distort results and these are considered in meeting both targets and budgets. Note all known expenditure for any year is included in the business plan which is approved by the Governing Committee. 7.3 OtagoNet’s demand forecast 7.3.1 OtagoNet’s current demand Maximum demand (MD) is considered in 3 ways: the individual any-time half-hour maximum demands at each site (which will not necessarily occur at the same time) and which define the engineering considerations of load at the sites; the maximum demands co-incident with the Transpower regional peak (with OtagoNet being in the Lower South Island (LSI) region); and the average of the 100 half-hourly maximum demands at each site occurring coincident with the 100 top LSI demands – this determines the Transpower demand charges at the GXPs.29 The individual maximum demands and the LSI coincident demands and average 100 demands (in { }) are shown in Table 29. Table 29 – OtagoNet’s GXP and Generation Maximum Demands GXP Balclutha GXP 30 Palmerston GXP Naseby GXP Total Transpower Paerau Generation Falls Dam Generation Mt Stuart Wind Farm Total System Anytime Maximum Demand Between 1/4/12 and 31/3/13 (MW) LSI Coincident Demand On 11 Sept 2012 at 0830 (MW) {+ 100 avg} 27.182 (February) 9.030 (June) 31 24.948 (April) 26.518 {22.426} 7.644 {7.180} 12.704 {13.973} 46.866 11.688 1.270 0.000 59.824 12.409 1.281 7.500 60.719 Because the Lower South Island regional peaks are dominated by the Tiwai smelter load, there is very little correlation between the LSI peaks and the OtagoNet load peaks. Compounding this is the unpredictability of the LSI peaks that makes the use of load control for demand minimisation through operation of the ripple plant almost ineffectual. However, this has also allowed OtagoNet to relax load control during the year providing customers with less restricted supply on an off-peak rate. 28 Abnormal situations: Major storms, snow, significant planned outages, dry year rationing, external party major equipment failures. 29 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/transmissionpricing/transmission-pricing-methodology/ for details. 30 Configuration prior to completion of the transfer to Halfway Bush. 31 This is net of Paerau generation; the regional load peak occurred in December driven by holiday residences and irrigation. Asset Management Plan Page 98 of 193 OUR DEVELOPMENT PLANS Each zone substation recorded the maximum demands as listed in Table 30. Table 30 substation demand Zone Substation Charlotte Street Clarks Junction Clinton Clydevale Deepdell Elderlee Street Finegand Glenore Golden Point Greenfield Hindon Hyde Kaitangata Lawrence Macraes Mine Merton Middlemarch Milburn North Balclutha Oturehua Owaka Paerau Paerau Hydro Palmerston Patearoa Port Molyneux Pukeawa Ranfurly Ranfurly 66/33 kV Stirling Waihola Waipiata Waitati Wedderburn Installed Capacity MVA 2013 Maximum Demand MVA 2013 Capacity Utilisation 10.0 0.5 2.5 2.5 0.8 10.0 2.5 1.5 5.0 2.3 0.5 2.5 2.5 2.5 30.0 5.0 2.5 7.5 5.0 0.8 2.5 0.8 30.0 5.0 2.5 2.5 0.8 5.0 50.0 5.0 1.5 2.5 2.5 0.8 6.1 0.4 2.0 2.7 0.1 6.4 1.1 0.7 4.2 1.7 0.2 1.2 1.4 1.5 22.4 2.4 0.7 2.4 2.8 0.2 1.5 0.3 12.8 2.2 1.7 0.7 0.4 2.2 25.3 3.9 1.2 1.3 1.5 0.2 61% 80% 78% 110% 17% 64% 43% 44% 83% 72% 48% 49% 56% 62% 75% 49% 30% 31% 56% 19% 60% 36% 43% 44% 67% 27% 48% 43% 51% 78% 80% 53% 62% 26% In practical terms the utilisation of substations is a function of customer demand, standard transformer size and provision for future load over the long life of the substation. 7.3.2 Drivers of future demand Key drivers of demand growth (and contraction) are likely to include the issues depicted in Figure 41. Asset Management Plan Page 99 of 193 OUR DEVELOPMENT PLANS Demographics & lifestyle Convenience of electricity compared to other fuels Increasing energy use per customer Migration into urban areas Climatic effects Increasing rural irrigation Increasing ambient temp. Climate change initiatives Economic activity Economic up-turns Ascending commodity cycles Industry & technology trends Local growth initiatives Distributed generation Low NZ$ New industrial plants All these factors increase demand Localised demand growth Aggregate demand growth All these factors decrease demand Conservation Demographics & lifestyle Declining overall local population Declining affordability Increasing conservation Economic decline End of useful life of major industrial plant Economic down-turn High NZ$ Increasing energy efficiency Descending commodity cycle Plant closure for other reasons Figure 41 - Drivers of demand At the residential and light commercial feeder level, three or four of these issues may predominate, 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 potentially more predictable zone substation demand forecast but previous growth is not always indicative of the future. Industrial demand will always remain more unpredictable. OtagoNet‘s estimates of future demand are described in section 7.3.4 below. Historically, OtagoNet has experienced an average annual demand growth of about 1.6% for the last 10 years. Whilst the company expects this long-run average rate of growth to decline and to influence the revenue aspects of OtagoNet‘s business (as discussed in the background section of this plan), it must be acknowledged that actual demand growth at 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 5 to 10 years. 7.3.2.1 Connection of Distributed Generation In December 2010 OtagoNet connected Pioneer Generation‘s 7.65MW wind farm at Mount Stuart with a 33kV connection into the Glenore to Lawrence line. Asset Management Plan Page 100 of 193 OUR DEVELOPMENT PLANS Wind generation up to 2MW can be connected to some 11kV feeders. Generation greater than 2MW, or if a number of small generators are installed in an area, will require the generation to be connected to the subtransmission network. There have previously been enquiries about other hydro 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 is normally connected on existing LV installations. The connection of distributed generation has the potential to increase voltage above regulatory levels.32 Any larger wind farms will need to connect to the Transpower Transmission network at 110kV or 220kV. No changes are included in the OtagoNet network peak demand forecasts based on currently known generation schemes. 7.3.2.2 Milling of local forests This could involve expansion of existing mills (Figure 39 Quadrant 2), or could involve new mills (Figure 39 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 was connected at Milburn in FY2012, with negligible impact on peak demand. 7.3.2.3 Irrigation Dry areas in north Otago and the Maniototo have an increasing demand for irrigation driven from an increasing trend in dairying land conversion in these areas as discussed in the background section of this plan. Generally other areas in South Otago have a more constant rainfall with little or no irrigation required although dairying has necessitated some irrigation in the Clydevale area. An allowance for up to 4% annual demand increase has been made on the relevant substations in the Maniototo. 7.3.2.4 Dairy conversions While there was an early uptake in dairy conversions in South Otago this appears to be levelling off. However, there is still a larger land area that could be converted or used with irrigation for feed supply, particularly in Central Otago. We are now seeing more irrigation on existing dairy farms in south Otago (particularly around Clydevale) and new loads in the Maniototo. 7.3.2.5 Mining closure The gold mine at Macraes underwent a step change in load in 2007, with their underground mining operations. However, recent announcements have suggested the mine is due for closure in circa 2017 but this is yet to be confirmed to OtagoNet. There are other gold prospects in the Otago area, but to date there have been no serious enquiries for new loads. 32 It is important that distributed generation is connected the network via equipment which meets network standards. The situation is compounded if several generators are in close proximity. It is salient electricity networks are designed with voltage regulation on the high voltage side of transformers to compensate for increased load. Distributed generation has the potential to elevate voltage to unacceptable levels at times of low load. Asset Management Plan Page 101 of 193 OUR DEVELOPMENT PLANS Coal mining continues in Kaitangata and although there are other coal fields no load increases are expected in the planning period. 7.3.3 Load forecast trend Analysis of historic demand and energy usage over the last 10 years to 31 March 2013 shows a 10 year average demand growth of 1.6%. Figure 42 shows the data since 1949 and the drop in demand in circa 1996 when computerised load control was introduced. The chart also shows the significant effect of the Macraes Flat gold mine load which is the single largest load on the network and which may close circa 2017 according to recent statements but such has not been confirmed to OtagoNet. OJV Historic Energy and Maximum Demand (showing with and without Macraes Gold Mine Load) 90 450 Base MW (excl. Macraes) Total MW 80 400 Base GWh (excl. Macraes) Energy - (GWh) 2012 2010 2008 2006 2004 2002 2000 1998 1996 1994 1992 1990 1988 1986 1984 1982 1980 0 1978 0 1976 50 1974 10 1972 100 1970 20 1968 150 1966 30 1964 200 1962 40 1960 250 1958 50 1956 300 1954 60 1952 350 1950 Maximum Demand - (MW) Total GWh 70 Figure 42 – Historic energy and maximum demand 7.3.4 Estimated zone substation demands As outlined in detail in the remainder of section 7, OtagoNet‘s demand is expected to increase from that described in section 7.3.1 as follows: Standard natural growth of 1.0%, with some decline of small rural communities. On-going dairy conversions and associated new irrigation load growth particularly in central Otago with an estimated growth rate of 2%. Long term growth rates are uncertain so budgets beyond 5 years carry a high margin of error Experience strongly indicates that it would be rare to ever see 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 options, raw material supply and transport infrastructure. Asset Management Plan Page 102 of 193 OUR DEVELOPMENT PLANS Table 31 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. Table 31 Substation demand growth rates Design Capacity 2013 Maximum Demand 2013 MVA Annual Growth Rate % Projected Demand 2023 MVA Charlotte Street Clarks Junction Clinton Clydevale Deepdell 10.0 0.5 2.5 2.5 0.8 6.1 0.4 2.0 2.7 0.1 0.0% 0.0% 1.5% 5.0% 0.0% 6.1 0.4 2.3 4.1 0.1 Elderlee Street 10.0 6.4 0.0% 6.4 Finegand Glenore 2.5 1.5 1.1 0.7 0.0% 1.0% 1.1 0.7 Golden Point 5.0 4.2 0.0% 4.2 Greenfield Hindon Hyde Kaitangata Lawrence Macraes Mine 2.3 0.5 2.5 2.5 2.5 30.0 1.7 0.2 1.2 1.4 1.5 22.4 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 1.7 0.2 1.2 1.4 1.5 22.4 Merton 5.0 2.4 0.0% 2.4 Middlemarch Milburn North Balclutha Oturehua Owaka Paerau Paerau Hydro Palmerston Patearoa Port Molyneux Pukeawa Ranfurly Ranfurly 66/33 kV Stirling Waihola Waipiata Waitati Wedderburn 2.5 7.5 5.0 0.8 2.5 0.8 30.0 5.0 2.5 2.5 0.8 5.0 50.0 5.0 1.5 2.5 2.5 0.8 0.7 2.4 2.8 0.2 1.5 0.3 12.8 2.2 1.7 0.7 0.4 2.2 25.3 3.9 1.2 1.3 1.5 0.2 0.0% 0.0% 0.0% 0.0% 0.5% 0.0% 0.0% 1.0% 5.0% 0.0% 5.0% 1.0% 0.0% 0.0% 1.0% 5.0% 1.0% 0.0% 0.7 2.4 2.8 0.2 1.6 0.3 12.8 2.4 2.5 0.7 0.6 2.4 25.3 3.9 1.3 2.0 1.7 0.2 Zone Substation Provision for Growth Over N-1 but load transfer available Approaching capacity, need to monitor Increase capacity for 2014 Load transfered to Milburn, replacement planned Load transferred to Macraes end of 2013 Near N-1 capacity, replacement planned Near N-1 capacity, replocation planned Monitor and plan to ncrease capacity Monitor growth Discussions with Fonterra re security Monitor and plan to ncrease capacity The red highlighted values indicate when the initial trigger point for capacity is exceeded based on the present equipment, configuration and security requirement. 7.3.4.1 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. Increased monitoring of heavily load sites if data indicates capacity will be exceeded. Annual revision 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, due to uncertainty of load changes within the network. This occurs when customers add additional plant and equipment without applying to OtagoNet. Depending upon the circumstances OtagoNet can use various methods to maintain supply until equipment is upgraded, should unexpected growth occur: Asset Management Plan Page 103 of 193 OUR DEVELOPMENT PLANS Load Management. Mobile generator(s). Load transfers to neighbouring substations. Utilisation of voltage boosters. Temporary substations. Overall significant new loads will be dependent on new equipment being installed or built. 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 control can also be undertaken at a Retailer‘s request or during Dry-year rationing. 7.3.5 Estimated demand aggregated to GXP level Table 32 shows the aggregated effect of substation demand growth for a 10 year horizon at the three GXP‘s, Paerau scheme and Falls Dam. Table 32 GXP demand growth 2013 MD (MW) 27.2 Growth (%) 0.75% 2024 MD (MW) 29.8 Provision for Growth No further work required 9.0 0.00% 8.5 None after GPT shutdown 24.9 1.50% 31.7 Paerau 12.4 0.00% 12.4 Falls Dam 1.3 0.00% 1.3 Mt Stuart 7.5 0.00% 7.5 No further work required No generation increase expected No generation increase expected No generation increase expected GXP Balclutha GXP Palmerston GXP Naseby GXP 7.3.6 Issues arising from estimated demand The significant issues arising from the estimated demand in section 7.3.4 and 7.3.5 are: 7.4 The short term capacity of Clydevale is already exceeded and a number of dairy conversions and irrigators are expected for the 2014/2015 season. At Patearoa, the known dairying and irrigation load increases for the 2014/2015 season will necessitate increases in substation capacity. Elderlee Street and Charlotte Street‘s capacity is above their required N-1 capacity, but some load transfer to other substations is possible. OtagoNet network constraints OtagoNet‘s network includes the following constraints: Constraint Description Intended remedy Milton 33kV The loads of Lawrence, Glenore, Elderlee Street and Waihola exceed single 33kV line capability Rebuild of the western 33kV line to Milton is in progress with larger conductor and automatic switching to be improved Patearoa 2.5MVA capacity will be reached by 2015-16. Establish a new zone substation in the west of Patearoa with temporary 11 kV reinforcement in 2014 Asset Management Plan Page 104 of 193 OUR DEVELOPMENT PLANS Constraint Description Intended remedy Patearoa 11 kV line capacity and low voltage to the west of Patearoa Establish a new zone substation in the west of Patearoa, 11 kV line upgrades and regulators Clydevale 2.5MVA capacity has been reached Add a second larger transformer into spare transformer bay Clydevale 11 kV line voltage low at Popotunoa and Wharetoa Upgrade line sections and install regulators Clinton 2.5MVA capacity may be reached by 2018 with increased dairying or irrigation. Consider further tie line upgrades and load transfers towards the increased capacity at Clydevale Owaka Unreliable 11 kV switchgear and safety clearance issues Outdoor to Indoor conversion with modular switch room Port Molyneux Unreliable 11 kV switchgear in harsh seaside environment Outdoor to Indoor conversion with modular switch room Waitati & Waikouaiti Single long 33 kV line with maintenance and reliability issues Take 33 kV supply from Halfway Bush and provide alternate 33 kV feed at Waitati Environmental – Oil Expectation of no significant oil spills from any substation Install oil bunding and separation systems at remaining substations Quality of Supply - Voltage In some growth areas the LV lines are inadequate to supply the new loads Upgrade LV lines in towns as required and consider the size and location of transformers Options including non-asset, considered and found to be uneconomic or unsupported: 7.5 Distributed generation into the 33kV from Mount Stuart wind farm is not constant enough to remove the need of the upgrade of the western Milton 33kV line. Load control of irrigation at Patearoa is unlikely to receive support. Change to ‗green‘ oil is higher cost than oil interception systems. Upgrade to covered ‗spacer cable‘ for vegetation problem locations found to be expensive in a trial at Shag Point. Policies for distributed generation 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 impacts 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. Increase in voltage variation on lightly loaded lines from LV connected generation. The development of distributed generation is actively encouraged subject to compatibility with the network and ensuring the generation does not impact adversely on those receiving supply. Asset Management Plan Page 105 of 193 OUR DEVELOPMENT PLANS 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 OtagoNet web site under Customer Information – Distributed Generation; see http://www.otagonet.co.nz/index.php?pageLoad=116&par=251 7.5.1 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. 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. 7.5.2 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. 7.5.3 Technical standards 7.6 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. Use of non-asset solutions As discussed in section 7.2.1 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 load on individual GXP‘s when they exceed the capacity of that GXP. The load on feeders during outage situations. As noted in section 7.3.1, it has become infeasible to manage Transpower demand charges as the LSI peak is determined by the Tiwai load and has consequently become uncoupled from the OtagoNet peak demand times. Asset Management Plan Page 106 of 193 OUR DEVELOPMENT PLANS If an Engineer considers that adoption of non-asset options may be sufficient to overcome a constraint, a business case would be prepared to get approval from the Network Manager (OtagoNet) or Governing Committee, to proceed. The approval would be given if the likelihood of success is acceptable and the cost / benefit ratio is positive. Suggestions of non-asset options can come from other staff and external parties with these allocated to an Engineer to investigate. 7.7 Network development options 7.7.1 Identifying options When faced with increased demand, reliability, security or safety requirements, OtagoNet considers the broad range of options described in Section 7.2.1. The range of options for each issue varies due to: Stakeholder interests Section 1.7 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, and so the level of analysis and the breadth of options vary. A simple issue like connecting a new customer next to an 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). Network standards are utilised but innovation is supported where alternative optimum solutions result. 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.) Standardisation Standards that apply to the network are given in the PowerNet Network Design standard. Some of the standardisation is listed below: Component Standard Justification Conductor All Aluminium Alloy Conductor (AAAC): Chlorine, Helium, Iodine, Neon, Oxygen. Low corrosion and improved impedance Conductor Aluminium Conductor Steel Reinforced (ACSR): Magpie, Squirrel, Flounder, Snipe. Higher strength for long spans or snow loading Low Voltage Aerial Bundled Cable (ABC): 35, 50 & 95mm² Al / two & four core. Safety, visual impact, lower cost. Cable Cross-linked Polyethylene (XLPE) Rating, ease of use. Asset Management Plan Page 107 of 193 OUR DEVELOPMENT PLANS Component Standard Justification Suppliers Normally one or two suppliers for each component Reduce spare requirements. Improved contractor familiarity. Poles Concrete Long life, good strength Crossarms Solid hardwood or steel Long life, good strength Distribution Transformers Standardised sizes, e.g. minimum size 15kVA except for specific applications Reduce spare requirements. Improved contractor familiarity. Note: Where particular conditions apply such as access or strength, hardwood poles and steel crossarms are used. Standardised design is used for line construction using Network Standards. 7.7.2 Identifying the best option Once the best broad option has been identified using the principles embodied in Figure 40, OtagoNet will use a range of analytical approaches to determine which option best meets OtagoNet‘s investment criteria. As set out in Section 7.2.3, OtagoNet uses increasingly detailed and comprehensive analytical methods for evaluating the more expensive projects. 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. Customer consultation: If solution impacts on a customer and changes the service level provided, the customer must be consulted to obtain their support. i.e. disconnecting remote customers by replacing connection with a RAPS33. 7.7.3 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. 33 RAPS = Remote Area Power System: A stand-alone energy network of alternative energy sources (Solar, Photovoltaic, Wind turbine, Micro-hydro, LPG, Diesel, etc…) so that a connection to the electricity network is not required. Asset Management Plan Page 108 of 193 OUR DEVELOPMENT PLANS 7.8 Development programme The following table sets out the network development programme for the next 5 years. Individual projects are then discussed separately. Network Development Capex Projects Year 1 2014-15 Milton - Elderlee Street Substation Replacement Milton 33 kV ring protection upgrade Waitati substation relocation Waikouaiti (Merton) substation relocation Glenore substation relocation Clydevale transformer upgrade and indoor switchgear Clydevale 33 kV Ring protection Palmerston GXP purchase & conversion to 33 kV Palmerston 33 kV sub and feeder to ex TPNZ substation Palmerston area ripple injection plant replacement 11 KV Reclosers and SCADA for automation New Puketoi substation, prob. off 66 kV line in Wilson Road Patearoa - Paerau - Puketoi 11 kV line upgrade; regulators first Substation Land Purchase and Safety Improvement Subtotal projects New Connections (on-going) Ongoing & new substation work 33 kV Line Upgrades 11 kV Line Upgrades Clydevale - Popotunoa line upgrade + regulator Clydevale - Hall Road line upgrade Clydevale - Hall Road to Camp Hill Road Tie line Yr 1 Subtotal 11 kV line upgrades LV Voltage Quality (on-going) Easements (on-going) Total Network Development Capex Year 3 2016-17 Year 4 2017-18 $100k $50k $100k $0k $360k $750k Year 2 201516 $1,900k $200k $700k $50k $40k $250k $0k $0k $0k $1,000k $0k $0k Year 5 201819 $0k $0k $0k $800k $0k $0k $600k $0k $500k $100k $0k $0k $50k $300k $0k $200k $150k $50k $0k $200k $0k $2,600k $250k $1,300k $1,950k $400k $1,000k $0k $140k $550k $0k $350k $300k $0k $50k $0k $250k $990k $900k $0k $200k $0k $100k $200k $50k $400k $200k $300k $0k $200k $1,000k $500k $1,000k $1,350k $100k $0k $0k $0k $0k $100k $300k $0k $0k $0k $0k $300k $3,740k $1,000k $0k $2,240k $1,000k $0k $2,550k $1,000k $600k $2,050k $1,000k $1,200k $800k $120k $9k $0k $120k $9k $0k $120k $9k $0k $120k $9k $0k $120k $9k $4,239k $4,869k $3,369k $4,279k $4,379k $2,310k $1,000k $0k Life Cost $500k $200k $100k 7.8.1.1 Milton (Elderlee Street) Substation 7.8.1.1.1 Description This substation feeding Milton is approaching its N-1 capacity and is not in an ideal situation being in a residential area with potential noise issues and limited room for expansion or renewal. The future growth in Milburn will also require additional switchgear and lines from this substation. Rather than trying to develop the existing substation in the domestic area of town and crossing the railway corridor with multiple 33kV lines a new site on the industrial land on the other side of the railway has been proposed. The project is to secure that land and then develop final plans for 33kV switchgear, 11kV indoor switchgear and dual transformers. Consideration will be given to refurbishing and reusing the existing 5MVA transformers while there is sufficient transfer capacity to Millburn and Glenore substations. Asset Management Plan Page 109 of 193 $12,890k OUR DEVELOPMENT PLANS 7.8.1.1.2 Issues The present substation is reaching the N-1 capacity of the 5MVA transformers and the 400 Amp limit of the 11kV switchboard. The substation is bounded by residential houses and the transformers on the boundary have potential noise issues. The existing substation building is too small for new switchgear and has been identified as below current building seismic strength requirements. The existing 33kV lines cross industrial land and the railway and future 33kV line easements for the Milburn ring extension will be difficult to obtain. 7.8.1.1.3 Options Redevelop on a new site away from the residential area. Redevelop on the existing site with a new substation and indoor sound proofed transformers Partially offload Elderlee Street substation to Milburn and Glenore to defer overloading. Replace the transformers only with 7.5MVA units and add bus protection. No non-asset solutions are available. 7.8.1.1.4 Option selection Replacement on a new site is the best strategic solution with the lowest risk. 7.8.1.1.5 Cost and type $2.6m for the whole project; Asset Replacement and Growth 7.8.1.1.6 Goal / Strategy Allow for load growth and load transfer. Minimise the environmental impact. Complete the project by 2017. 7.8.1.2 Milton 33 kV Ring Protection Upgrade 7.8.1.2.1 Description The 33kV ring feed switching design from Balclutha through Glenore and Kiness only provides N-1 reliability to Elderlee Street but not to other substations t‘ed off it and is an early basic system that can be improved to provide N-1 reliability to the Glenore substation on the ring and the downstream substations of Lawrence, Milburn, Waihola and the Mt Stuart wind farm. The project will involve additional 33kV circuit breakers at Glenore and communication and signalling between the replacement protection systems around the ring. 7.8.1.2.2 Issues The present ring protection only provides an N-1 protection for Elderlee Street substation and that is compromised by a remote circuit breaker at Kiness. The present protection only uses directional protection relays and there have been some spurious openings of the ring in association with other faults. A replacement system will have greater selectivity using end to end communications. The load and importance in the adjacent substations has grown and now includes the 7.65MW wind farm connection and the new Milburn substation which will benefit from an enhanced protection scheme. 7.8.1.2.3 Options Wait and install distance relays only at the new Elderlee Street replacement substation. Do nothing and accept nuisance tripping‘s that reduce reliability and result in voltage disturbances if not actual loss of supply. Asset Management Plan Page 110 of 193 OUR DEVELOPMENT PLANS No non-asset solutions available. 7.8.1.2.4 Option selection The enhanced protection system will yield the full reliability potential from the line assets employed which alternative options will not. 7.8.1.2.5 Cost and type $250k for the whole project; Asset Replacement and Renewal, Reliability Improvement 7.8.1.2.6 Goal / Strategy Improve reliability to 33 kV line faults. Complete the project by 2016. 7.8.1.3 Waitati Zone Sub Relocation 7.8.1.3.1 Description The Waitati substation is in a flood prone location within a residential area. The condition of the transformer and switchgear is poor and both have reached end of life 7.8.1.3.2 Issues Reliability for customers off the Waitati substation is the poorest on the network. The existing substation is flood prone and is located within a residential area. The supply security is below the EEA guidelines as there is insufficient 11kV backfeeds available for loss of the single 33kV supply. Reconfiguration of the Palmerston GXP supply allows for redundant 33kV line circuits to be provided into Waitati. 7.8.1.3.3 Options Do nothing and continue with poor reliability due to 33kV line faults Redevelop on the existing site to allow for the dual 33kV circuits. Redevelop on a new site. 7.8.1.3.4 Option selection Redeveloping on a new site is the best strategic solution with the lowest future risk. 7.8.1.3.5 Cost and type $1.3m; Asset Renewal; Reliability Improvement 7.8.1.3.6 Goal / Strategy Improve reliability to 33kV line faults in the Waitati area. Complete the project by 2016. 7.8.1.4 Merton Substation (Waikouaiti) 7.8.1.4.1 Description This substation feeding the Waikouaiti area is approaching its N-1 capacity and the outdoor structure and transformers are both in poor condition. A better location than beside a flood prone river and the State Highway 1 is also desirable. A further opportunity exists with purchase of the Transpower 110kV lines that run past this substation, allowing for improved security and reduced losses with more direct supply than the existing configuration. 7.8.1.4.2 Issues The present substation is reaching the N-1 capacity of the 5MVA transformers and the 11kV and 33kV structures have deteriorating wooden poles and components. The supply security is below the EEA guidelines as there is insufficient 11kV backfeeds available for loss of the single 33kV supply. Asset Management Plan Page 111 of 193 OUR DEVELOPMENT PLANS The substation is low lying alongside the Waikouaiti River and is prone to flooding and is at risk from tsunami or liquefaction following a seismic event. The substation is beside SH1 to the north of Waikouaiti, its major load centre, meaning there is only one line route to the main loads. Inefficiency and lower reliability of the existing single circuit 33kV arrangement. 7.8.1.4.3 Options Redevelop on the existing site with a new transformers and indoor switchgear, raised above possible flood levels. Build a second substation on the south side of Waikouaiti to provide greater reliability and less dependence on this substation. Redevelop the substation on a more secure site closer to the load No non-asset solutions available. 7.8.1.4.4 Option selection Redeveloping on a new site is the best strategic solution with the lowest future risk. 7.8.1.4.5 Cost and type $1.95m; Asset Replacement and Renewal; Reliability Improvement. 7.8.1.4.6 Goal / Strategy Allow for load growth and greater security. Maximise the opportunity from the Transpower purchase of the 110kV lines. Minimise the environmental impact. Complete the project by 2017. 7.8.1.5 Glenore Transformer, Oil Containment and Overhead Structure 7.8.1.5.1 Description Install the new replacement 2.5MVA transformer into a new site to allow on-going load growth in the area, load transfers to Milton, Kaitangata and Lawrence and to remove the risk of oil spills into the nearby waterway. Replace the overhead 11kV structure with indoor circuit breaker and cable to the lines. Make provision for additional circuit breakers on the 33kV ring around Balclutha and Milton [this integrates with the Milton ring protection project]. 7.8.1.5.2 Issues Ageing transformer and associated overhead switching structure. Capacity of the existing transformer and increasing loads in the area as well as increasing loads in the adjacent substations that can be shared by Glenore. Performance of the 33 kV Milton ring with the introduction of the wind farm. Proximity of the substation transformer to a waterway with consequent risk of an oil spill. 7.8.1.5.3 Options Replace the transformer with 1.5MVA only and replace it early in the transformer‘s life and during the 10 planning period. Cost differential between units small, so not supported. Upgrade the interconnecting 11kV lines from Lawrence, Milton and Kaitangata and provide additional voltage regulation. Implementation costs similar but lower benefits with higher losses and worst reliability. Rebuild the overhead structure and replace the outdoor circuit breakers on the same site. Cost likely to be higher than standardised indoor solution, with no increased safety or environmental benefits. Rebuild on a new site (which has been identified) away from the river. Asset Management Plan Page 112 of 193 OUR DEVELOPMENT PLANS No non-asset solutions. 7.8.1.5.4 Option selection Rebuild on new site. 7.8.1.5.5 Cost and type $400k (Transformer already purchased), Asset Replacement and Renewal; Growth. 7.8.1.5.6 Goal / Strategy Allow for load growth and load transfer. Minimise the risk of oil contamination of the environment. Complete the project by year end 2014. 7.8.1.6 Clydevale transformer upgrade 7.8.1.6.1 Description Increasing loads from new irrigation are now pushing the load capacity of the existing single transformer. In addition there are concerns with the condition and reliability of the old KF outdoor circuit breakers. The project is to install a new 5 MVA transformer and place new indoor 11 kV switchgear. The existing 2.5 MVA transformer will be left on site as a warm spare. 7.8.1.6.2 Issues The supply security is below the EEA guidelines as there is insufficient 11 kV backfeeds available for loss of the single 33 kV supply. The load is approaching the capacity of the existing transformer and there is limited load transfer ability away from the substation. The existing KF outdoor 11 kV circuit breakers are old and in poor condition. 7.8.1.6.3 Options Replace the transformer but keep the existing switchgear. Place dual transformers to meet the security criteria. No non-asset solutions. 7.8.1.6.4 Option selection A replacement transformer is required for load growth. Replacing the old 11 kV CBs at the same time as the transformer replacement is the lowest cost option in the long term. 7.8.1.6.5 Cost and type $1.0 m; Growth and Asset Renewal. 7.8.1.6.6 Goal / Strategy Cater for future load growth in the region. Complete the project by 2016. 7.8.1.7 Clydevale Ring 7.8.1.7.1 Description Upgrade the switching configuration and ring protection around the Clydevale and Greenfield dairy factory to make the network more robust to single 33 kV line faults. 7.8.1.7.2 Issues The load and customer numbers in this area are increasing with highlighted importance on a reliable supply to the individual dairy farms and the Gardians diary factory. There two 33 kV lines to Clydevale from Balclutha passing through Greers and Clifton with tee offs to supply the Greenfield and Pukeawa substations. The second line is in poor condition, is not reliable as a backup and only has basic manual switching involving hours of driving to achieve restoration after a fault on one line. Asset Management Plan Page 113 of 193 OUR DEVELOPMENT PLANS 7.8.1.7.3 Options • Replace manual switches at Clifton, Greers, Clydevale and Greenfield with SCADA operated circuit breakers for timely restoration, one line at a time. • Extend the circuit breaks with additional directional protection and run the ring closed for resilience to the first fault. • Do nothing and accept worsening SAIDI and SAIFI figures and increasingly unhappy customers • No non-asset solutions available. 7.8.1.7.4 Option selection Upgrading the ring protection yields the most reliability from the existing 33 kV network in the area. Network performance will be increased with better SAIDI and SAIFI results. The closed ring will reduce losses and improve quality of supply to all customers in the area. 7.8.1.7.5 Cost and type $250 k; Asset replacement; Reliability Improvement. 7.8.1.7.6 Goal / Strategy Complete by 2016. 7.8.1.8 Transpower Palmerston – 33 kV conversion 7.8.1.8.1 Description The Transpower Palmerston Point of Supply has only N capacity due to the single transformer although there are two 110 kV lines from Halfway Bush. The current Transpower charging makes this substation the most expensive per ICP and the least reliable on the Otago network. An opportunity arose to purchase the Transpower assets at a fair price to enable OtagoNet to further develop or modify the supply to increase reliability and efficiency, both of this point of supply and the downstream 33 kV network and zone substations by shifting the point of supply to Halfway Bush and converting the 110kV lines to 33 kV then providing second 33 kV circuits into the zone substations along the line route at Waitati and Waikouaiti. The first stage is to convert one of the 110 kV lines to 33 kV and this work has already commenced. The second stage is to convert the second line to 33 kV. 7.8.1.8.2 Issues The present single transformer arrangement is below the standard of security required and peak load is at 90% of the firm capacity. In 2012 there were two planned outages of this point of supply that have required the establishment of major generation to keep the power on to 3,000 customers during these 9-12 hour outages. The high cost of the Palmerston GXP connection from Transpower reflected the asset value of the 110 kV lines as this is a 110 kV spur substation. The configuration of the existing 33 kV network back towards Dunedin that is less than optimal with the lowest reliability being effectively at the end of the OtagoNet network, yet is the closest point to the Halfway Bush point of supply. The conversion to 33 kV must be undertaken in two stages as until Transpower upgrade the Halfway Bush 33 kV bus capacity, scheduled for 2017, there is insufficient firm capacity at 33 kV to supply both the Aurora and OtagoNet loads. 7.8.1.8.3 Options The options post purchase of the Transpower assets that were considered included: continue with the present set up, keep the 110 kV voltage and install a Asset Management Plan Page 114 of 193 OUR DEVELOPMENT PLANS second 110/33 kV transformer, move the 110/33 kV substation to Waikouaiti, run the lines at 33 kV from Halfway Bush. Continue with the expensive and lower reliability from the present arrangement. No non-asset solutions available. 7.8.1.8.4 Option selected Convert the 110 kV lines to 33 kV in two stages. 7.8.1.8.5 Cost and type $1.0m spread over 5 years; Reliability, Safety and Environmental. 7.8.1.8.6 Goal / Strategy Allow greater reliability and security. Maximise the opportunity from the purchase of the 110kV lines and substation. Reduce the cost of supply and maximise the efficiency and reliability. 7.8.1.9 Palmerston Substation Feeder Alteration 7.8.1.9.1 Description The Palmerston substation has dual transformers but only a single 33 kV circuit form the GXP and will benefit from dual 33 kV lines to give it full N-1 reliability which can be achieved in association with changes to the 110/33 kV Palmerston substation. The 11 kV feeders arrangements are also sub optimal and on an old and difficult to maintain outdoor structure. This project is to shift the Palmerston zone substation to the recently purchased GXP site with new 33 and 11 kV switchgear but utilising the existing 33/11 kV transformers. 7.8.1.9.2 Issues Old outdoor structure using wooden cross arms and concrete poles is at the end of its life and has minimal clearances to maintain and operate without adjacent feeder shutdowns. Structure and transformers are close to the existing contractor‘s depot building with clearance safety issues. The supply security is below the EEA guideline due to the single 33 kV incomer (although it is a short length) Substation controls and ripple injection plant are within the contractor‘s depot building. 7.8.1.9.3 Options • • Relocate Palmerston zone substation to newly acquired Palmerston 110 kV substation. Keep the existing substation and route a second 33 kV incomer. 7.8.1.9.4 Option selected Relocating the substation allows for increasing the supply security to meet the guidelines as well as dealing with the condition and safety issues of the existing substation. 7.8.1.9.5 Cost and type $900k; Asset replacement and renewal; Security and Reliability. 7.8.1.9.6 Goal / Strategy Complete the project by 2017 in conjunction with the Palmerston 33 kV supply reconfiguration. Asset Management Plan Page 115 of 193 OUR DEVELOPMENT PLANS 7.8.1.10 Palmerston Area ripple Injection Plant 7.8.1.10.1 Description Replace the aging 33 kV ripple injection plant, both transmitter and coupling cells at a new location. 7.8.1.10.2 Issues The plant is at the end of its service life with spares are no longer being supported and reliability is compromised. The value of load control to OtagoNet is doubtful given the change to the lower South Island regional demand grouping as discussed earlier, however, the ripple receivers are owned by the retailer and are required for day/night rate switching, limiting other options. Palmerston zone substation, structure and buildings are old and in poor condition. The 33 kV reconfiguration means the ripple signal will be too attenuated towards the Halfway Bush 33 kV bus and so the ripple plant injection point must be re-located. 7.8.1.10.3 7.8.1.10.4 Options Consider if replacement is justified as the main benefactor is the Retailer with their receivers being used more to control tariff options rather than the Network controlling load. Consider alternatives to ripple injection for load control in association with Smart Meters. Consider daylight switches for the main network use to control street lights. Consider replacement in the newly acquired Palmerston 110 kV substation, along with the Palmerston zone substation. No non-asset solutions. Option selected The preferred option has not been identified. Provision of expenditure in 2017 is to coincide with the substation relocation works. 7.8.1.10.5 Cost and type $500k; Asset replacement and renewal; Consequential works with 33kV reconfiguration projects. 7.8.1.10.6 Goal / Strategy Complete the investigations and recommendation for the project by 31 March 2015 with installation and commissioning completed by 2017. 7.8.1.11 Puketoi + interim voltage regulators 7.8.1.11.1 Description Load growth in the Maniototo from irrigation/dairy conversion places load that it is inefficient to supply from Patearoa, Ranfurly or Waipiata zone substations. Confirmed new load is to be supported off Patearoa using additional 11 kV voltage regulators but if load continues to develop in this region a new zone substations at Puketoi supplied off the 66 kV or 33 kV line between Ranfurly and Paerau Hydro appears the best option. 7.8.1.11.2 Issues Continuing load growth in the region from dairy conversion and new spray irrigation. The location of the new load makes it inefficient to support at 11 kV from existing substations. Head-works costs may need to be supported by irrigation/farm owners. Asset Management Plan Page 116 of 193 OUR DEVELOPMENT PLANS 7.8.1.11.3 Options • Support the load from the existing substations (but the ability for this is limited) • Develop a new zone substations at or near Puketoi off the 66 of 33 kV lines. • No non-asset solutions. 7.8.1.11.4 Option selection Place new voltage regulators to support the confirmed new load as an interim measure. Make provision of a new substation at Puketoi. 7.8.1.11.5 Cost and type $1.75 m; Growth. 7.8.1.11.6 Goal / Strategy Install voltage regulators in 2014 and 2015 as interim measure. Provisional expenditure set for FY2018 an FY2019 for new zone substations. 7.8.1.12 11 kV Reclosers and SCADA automation 7.8.1.12.1 Description Reliability improvement may be economically provided by the installation of line reclosers that automatically sectionalise lines under fault conditions thereby restoring service to unaffected parts with only momentary interruption. 7.8.1.12.2 Issues The 11 kV network is radial with few feeder interconnections and any faults on the feeder interrupt all customers on the feeder until the fault is found and repaired. The costs of reclosers is approximately $50k ea. which provides relatively cheap reliability improvement. OtagoNet needs to establish a dollar value range for its customers value of lost load to properly establish the financial benefits of recloser installations. 7.8.1.12.3 Options • Do nothing and continue with the current reliability performance. • Install reclosers where they are economically viable. • No non-asset solutions available. 7.8.1.12.4 Option selection Install reclosers where they are economically viable including SCADA modifications. 7.8.1.12.5 Cost and type $2.5m over 5 years but dependent on business cases. Reliability Improvement. 7.8.1.12.6 Goal / Strategy Identify economic locations during FY2015. 7.8.1.13 Land Purchases Expenditure of $300k for purchase of land ahead of zone substation relocations or new developments. 7.8.1.14 Subtransmission Line Upgrades No subtransmission line upgrades are currently planned in the next 5 years. Asset Management Plan Page 117 of 193 OUR DEVELOPMENT PLANS 7.8.1.15 Distribution Line Upgrades The following 11 kV line upgrades are planned: • Clydevale – Popotunoa line upgrade and voltage regulator due to load growth. Cost $500k in FY2015. • Clydevale – Hall Rd. line upgrade due to load growth. Cost $200k in FY2015. • Clydevale – Hall Rd to Camp Hill Rd tie line to improve load transfer and reliability. Cost $360k spread over FY2015 and FY2016. 7.8.1.16 Quality Remedies Various works to remedy poor power quality usually identified from voltage complaint investigations and where an appropriate solution is identified including. Installation of 11kV regulators. Up-sizing of components (conductor, transformer). Demand side management. 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.) Cost of $120k p.a. on-going, System Growth. 7.8.1.17 New connections and easements 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. The budgeted cost of $1.0 m p.a. is based on past experience and known development has been included in the plan. A modest allowance has been made to connect Distributed Generation to the network. A budgeted cost of $9k p.a. is made for new easements and is based on past experience. 7.8.2 Considered projects Expected projects for year six to ten (YE 31 March 2019 to 2025) are as follows. These projects have little if any certainty. Note that some projects that are on-going through-out this period are detailed above. 7.8.2.1 33kV Transformer Circuit Breakers Three out of seven 5MVA transformers do not have 33kV circuit breakers for transformer protection at present, and rely on 33kV fuses only. None of the 15 smaller 2.5MVA transformers have circuit breakers. Single transformers may be damaged by slow fuse clearing times with little protection for earth faults and dual transformer sites may be vulnerable to additional damage from back feeding into a transformer fault. This project looks to install 33kV circuit breakers to protect the larger transformers, (5MVA) initially then the 2.5 MVA transformers. $300k per year depending on individual solutions, Reliability. Asset Management Plan Page 118 of 193 OUR DEVELOPMENT PLANS 7.8.2.2 Network automation Continue to install reclosers and sectionalisers, controlled through the SCADA system to enhance the network reliability. 7.8.3 Contingent projects There are no known contingent projects, however some customer related work may be expected from our largest current customers, for example requests for increased transformer or subtransmission line capacity. These have been excluded from OtagoNet‘s spend plans until they been requested by the customer and have become certain. 7.8.4 Network Development Capital Forecast The estimated 10-year network development capital budget for OtagoNet is given below in Table 33 – Network development (capex) budget (Years FY2015 to FY2024). 7.8.4.1 Assumptions The budgeted amounts are based on our best estimates and may vary by ±20% due to wage settlements, material costs movements or unforeseen site conditions. Projects may be delayed or accelerated if new information is discovered or priorities change. Most developers do not always give more than one year‘s notice of significant load changes and resource may be diverted onto these projects to meet customer expectations. 2015 to 2024 Network Development CAPEX Budget Table 33 – Network development (capex) budget (Years FY2015 to FY2024) Development expenditure Customer connections System growth Reliability, safety, environment Asset replacement & renewal Network development capex total 7.9 2014-15 2015-16 2016-17 2017-18 2018-19 2019-20 2020-21 2021-22 2022-23 2023-24 $1,000k $1,779k $1,260k $1,000k $679k $790k $1,000k $179k $340k $1,000k $429k $550k $1,000k $1,129k $250k $1,000k $129k $0k $1,000k $129k $0k $1,000k $129k $0k $1,000k $129k $0k $1,000k $129k $0k $200k $2,700k $1,850k $2,300k $2,000k $3,000k $3,000k $3,000k $3,000k $3,000k $4,239k $5,169k $3,369k $4,279k $4,379k $4,129k $4,129k $4,129k $4,129k $4,129k Non-network development OtagoNet receives IT and management services support through its management services contract with PowerNet. Whilst it does not directly develop the GIS (Intergraph) or AMS (Maximo) systems, it does in conjunction with PowerNet develop interfaces and processes around these systems. In particular, it is currently developing both inspection templates for condition assessment, the IT tools to efficiently implement inspections in the field and automatically upload that data, and the processes for using and updating that data. These systems and processes are considered critical to progressing its asset management strategies and strengthening its risk management and capital governance systems. 7.9.1.1 Mobile Generation To manage the planned reliability impacts of the increase programme of line renewals and to rectify the below average benchmarking of the company on its proportion of planned SAIDI, expenditure on a trailer or truck mounted generator in the size range of 300kVA is planned. In addition, the purchase of a mobile 1000 kVA 0.4/11 stepAsset Management Plan Page 119 of 193 OUR DEVELOPMENT PLANS up/earthing transformer is planned to be used in conjunction with leased generators for large zone substation outages. Cost $350k in FY2015; Reliability Improvement. 7.10 Development strategies that promote energy efficiency Line losses are considered in the decisions to undertake load transfers within the network and in the location of new assets and the sizing of the conductors that connect them. Asset Management Plan Page 120 of 193 ASSET LIFECYCLE 8. 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‖. 8.1 Lifecycle of the assets The lifecycle of OtagoNet‘s existing assets is outlined in Figure 43 below: Start here with existing asset base Yes Make operational adjustments Are any operational triggers exceeded ?? No Yes Are any maintenance triggers exceeded ?? Perform maintenance No Yes Are any renewal triggers exceeded ?? Undertake renewals No Yes Are any extension or augmentation triggers exceeded ?? Add new capacity No Yes Retire assets Are any retirement triggers exceeded ?? No Figure 43 - Asset lifecycle Asset Management Plan Page 121 of 193 ASSET LIFECYCLE Table 34 below provides some definitions for key lifecycle activities: Table 34 – Definition of key lifecycle activities Activity Operations Maintenance Renewal Up-sizing Extensions Retirement 8.2 Detailed definition Involves altering the operating parameters of an asset such as closing a switch or altering a voltage setting without any physical change to the asset. Involves replacing consumable components like the seals in a pump, the oil in a transformer or the contacts in a circuit breaker. There may be a significant asymmetry associated with maintenance such as lubrication 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. 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. Renewal tends to dominate the Capital expenditure in low growth networks like OtagoNet because assets will generally wear out before the load exceeds their capacity. Typical criteria for renewal occur when the capitalised costs of ongoing maintenance exceed the cost of renewal or the condition deteriorates to where the risk of failure becomes significant and the consequence of that failure is material. A key issue with renewal is technological advances that generally make it impossible to replace assets such as SCADA with equivalent functionality. Generally involves replacing a non-consumable and existing item like a conductor, busbar or transformer with a similar item of greater capacity. Involves building a new asset where none previously existed because a location or growth trigger e.g. building several spans of line to connect a new factory to an existing line. Notwithstanding any surplus capacity in upstream assets, extensions will ultimately require the up-sizing of upstream assets. Generally involves removing an asset from service and disposing of it. Typical guidelines for retirement will be when an asset is no longer required and cannot be re-located, creates an unacceptable risk exposure or when its costs exceed its revenue. Operating OtagoNet’s assets Operations mainly involve switching by remote command or in the field to configure the network to distribute line loadings, undertake maintenance on sections of the network or configure back-feeds during the repair of a fault. As outlined in Figure 43 the first efforts to relieve excursions beyond trigger points are operational activities with typical activities listed in Table 35. Table 35 Typical responses to operational triggers Asset class GXP Asset Management Plan Trigger event Voltage is too high or low on 33kV or 11kV. Demand exceeds allocated Transpower limit. Response to event Approach Automatic operation of tap changer. Activate ripple injection plant to switch off load control relays. Transfer loads between GXP‘s to relieve load from highly Proactive Reactive No facility in network Page 122 of 193 ASSET LIFECYCLE Asset class Trigger event Response to event Approach loaded GXP. Transition from day to night. On-set of off-peak tariff periods. Zone substation transformers Distribution reclosers Distribution ABS‘s Distribution transformers LV distribution Voltage is too high or low on 11kV. Demand exceeds rating. Fault current exceeds threshold of set level. Component current rating exceeded. Fault has occurred. Voltage is too high or low on LV. Fuses keep blowing. Voltage is too low at customers‘ board. Activate ripple injection plant to switch street lights on or off. Activate ripple injection plant to switch controlled loads on or off. Automatic operation of tap changer. Move tie points to relieve load from zone sub. Automatic operation of recloser. Open & close ABS‘s to shift load. Open & close ABS‘s to restore supply. Manually raise or lower tap where fitted. Shift load to other transformers by cutting and reconnecting LV jumpers Supply from closer transformer if possibly by cutting and reconnecting LV jumpers. for this response Proactive Proactive Proactive Reactive. Limited ability within network Reactive Proactive or reactive Reactive Reactive Reactive Reactive Table 36 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 36 - Operational triggers Asset category LV lines and cables Distribution substations Asset Management Plan Voltage trigger Voltage routinely drops too low to maintain at least 0.94pu at customers switchboards. Voltage routinely rises too high to maintain no more than 1.06pu at customers switchboards. Voltage routinely drops too low to maintain at least 0.94pu at customers switchboards. Voltage routinely rises too high to maintain no more than 1.06pu at customers switchboards. Demand trigger Temperature trigger Customers‘ pole or pillar fuse blows repeatedly. Infra-red survey reveals hot joint. Load routinely exceeds rating where MDI‘s are fitted. LV fuse blows repeatedly. Short term loading exceeds guidelines in IEC 354. Infra-red survey reveals hot connections. Page 123 of 193 ASSET LIFECYCLE Asset category Voltage trigger Distribution lines and cables Zone substations Voltage drops below level at which OLTC can automatically raise or lower taps. Subtransmission lines and cables Alarm from SCADA that voltage is outside of allowable setpoints. Alarm from SCADA that voltage is outside of allowable setpoints. OtagoNet equipment within GXP 8.3 Demand trigger Alarm from SCADA that current has exceeded a setpoint. Load exceeds guidelines in IEC 354. Alarm from SCADA that current is over allowable setpoint. Alarm from SCADA that current is over allowable setpoint. Temperature trigger Infra-red survey reveals hot joint. Top oil temperature exceeds manufacturers‘ recommendations. Core hot-spot temperature exceeds manufacturers‘ recommendations. Infra-red survey reveals hot joint. Infra-red survey reveals hot joint. Maintaining OtagoNet’s assets 8.3.1 Overview As described in Table 34 maintenance is primarily about replacing consumable components. Examples of the way in which consumable components ―wear out‖ include the oxidation or acidification of insulating oil, pitting or erosion of electrical contacts and wearing of pump seals. Continued operation of such components will eventually lead to failure. Durability 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. Exactly when maintenance is performed will be determined by the need to avoid failure or unwarranted loss of life and is based on manufacturer‘s recommendations, operational experience, condition assessments, operational history and risk assessment. 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 supplying a single residence will more than likely be run to breakdown. The maintenance strategy map in Figure 44 broadly identifies the maintenance strategy adopted for various ratios of costs and benefits. Asset Management Plan Page 124 of 193 ASSET LIFECYCLE Design out Condition based Event based Benefits (avoiding loss of supply) Time based Breakdown Cost of mtce activities relative to asset value Figure 44 - Maintenance strategy map 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 (or other failure consequences) both increase, the company relies less on easily observable proxies for actual condition (such as calendar age, running hours or number of trips) and more on actual component condition (through such means as dissolved gas analysis (DGA) for transformer oil). Component condition driven off periodic inspection is the key trigger for maintenance; however the precise conditions that trigger maintenance are very broad, ranging from oil acidity to dry rot. Table 37 describes the inspection cycles and maintenance triggers adopted: Table 37 - Maintenance triggers Asset category LV lines and cables Five yearly inspection Ten yearly scan of wooden poles Components Poles, arms, stays and bolts Pins, insulators and binders Conductor (repairable) Distribution substations yearly rolling inspection Six monthly for sites >150kVA Poles, arms and bolts Five Enclosures Transformer Switches and fuses Distribution lines and cables Asset Management Plan Poles, arms, stays and bolts Maintenance trigger Evidence of dry-rot. Loose bolts, moving stays. Displaced arms. Obviously loose pins. Visibly chipped or broken insulators. Visibly loose binder. Visibly splaying or corrosion or broken conductor strands. Evidence of dry-rot. Loose bolts, moving stays. Displaced arms. Visible rust. Cracked or broken masonry. Excessive oil acidity (500kVA or greater). Visible signs of oil leaks. Excessive moisture in breather. Visibly chipped or broken bushings. Visible rust. Oil colour. Visible signs of oil leak. Evidence of dry-rot. Loose bolts, moving stays. Displaced arms. Page 125 of 193 ASSET LIFECYCLE Asset category Components Five yearly rolling inspection Ten yearly scan of wooden poles Pins, insulators and binders Conductor Ground-mounted switches Regulators Zone substations Fences and enclosures Monthly checks Buildings Bus work and conductors 33kV switchgear Transformer 11kV switchgear Instrumentation/protection Electromechanical three yearly Electronic five yearly Maintenance trigger Loose tie wire. Chipped or cracked insulator. Loose or pitted strands. Visible rust. Visible rust. Oil colour. Visible signs of oil leak. Visible rust. Oil colour. Visible signs of oil leak. Excessive moisture in breather. High Dissolved Gas Analysis results. Weeds. Visible rust. Gaps in fence. Flaking paint. Timber rot. Cracked or broken masonry. Hot spot detected by Infrared detector. Corrosion of metal or fittings. Visible rust. Operational count exceeded. Low oil breakdown. Visible rust. High Dissolved Gas Analysis results (Annual test). Low oil breakdown. High oil acidity. Visible rust. Operational count exceeded. Low oil breakdown. Maintenance period exceeded. Possible mal-operation of device. Discharge test or Impedance test. Batteries Six monthly test Substationtransmission lines and cables Poles, arms, stays and bolts Annual fly-over inspection Five yearly inspection Ten yearly scan of wooden poles Pins, insulators and binders Conductor Cable Annual check Our equipment within GXP Injection plant Evidence of dry-rot. Loose bolts, moving stays. Displaced arms. Loose tie wire. Chipped or cracked insulator. Loose or pitted strands. Visible rust. High Partial discharge detected. Sheath insulation short. Oil pressure declining. Alarm from failure ripple generation. Period exceed for checks. Monthly check Typical maintenance policy responses to these trigger points are described in Table 38. Table 38 Typical responses to maintenance triggers Asset class Subtransmission lines Asset Management Plan Trigger point Loose or displaced components Response to trigger Tighten or replace Approach Condition as revealed by ongoing surveillance Page 126 of 193 ASSET LIFECYCLE Asset class Trigger point Rotten or spalled poles Cracked or broken insulator GXP and zone substation transformers Distribution lines Distribution ABS‘s Distribution transformers Repair conductor unless renewal is required Filter oil Excessive moisture in breather Weighted number of through faults General condition of external components Loose or displaced components Rotten or spalled poles Filter oil Splaying or broken conductor Weighted number of light and heavy faults Loose or displaced supporting components Seized or tight Asset Management Plan Filter oil, possibly detank and refurbish Repair or replace as required Tighten or replace Brace or bandage pole unless renewal is required Replace as required Repair conductor unless renewal is required Repair or replace contacts, filter oil if applicable Tighten or replace unless renewal is required Lubricate or replace components as required Loose or displaced supporting components Rusty, broken or cracked enclosure where fitted Oil acidity Tighten or replace unless renewal is required Make minor repairs unless renewal is required Filter oil Excessive moisture in breather where fitted Visible oil leaks Filter oil Chipped or broken bushings LV lines Brace or bandage pole unless renewal is required Replace as required Splaying or broken conductor Oil acidity Cracked or broken insulator Distribution reclosers Response to trigger Loose or displaced components Remove to workshop for repair or renewal if serious Replace Tighten or replace Approach Condition as revealed by five yearly inspection or ten yearly scan Breakdown unless revealed by five yearly inspection Condition as revealed by five yearly inspection Condition as revealed by annual test Condition as revealed by monthly inspection Event driven Condition as revealed by monthly inspection Condition as revealed by five yearly inspection Condition as revealed by five yearly inspection or ten yearly scan Breakdown unless revealed by five yearly inspection Condition as revealed by five yearly inspection Event driven Condition as revealed by five yearly inspection Breakdown unless revealed by five yearly inspection Condition as revealed by five yearly inspection Condition as revealed by five yearly inspection Remove from service for full overhaul every 15 years Condition as revealed by five yearly inspection Condition as revealed by five yearly inspection Breakdown or condition as revealed by five yearly inspection Breakdown unless revealed by five yearly inspection Page 127 of 193 ASSET LIFECYCLE Asset class Trigger point Rotten or spalled poles Cracked or broken insulator Splaying or broken conductor Response to trigger Brace or bandage pole unless renewal is required Replace as required Repair conductor unless renewal is required Approach Five yearly inspection Ten yearly scan Breakdown unless revealed by five yearly inspection Breakdown unless revealed by five yearly inspection The inspection cycles detailed in the above table have been taken from last year‘s Asset Management Plan. However as part of the asset management program for the year ending 2015 it is intended to undertake surveillance of all parts of the network: • To ensure the network meets safety requirements. • To enable population of the GIS database with accurate information. • To establish an accurate database of the condition of all parts of the network. This information will then be utilised to maximise the benefit of expenditure and improve reliability of supply. Following an assessment of the information gained from the 2015 asset survey the inspection cycles and trigger points for all assets will be reassessed. The frequency and nature of the response to each of the above triggers are embodied in OtagoNet‘s policies and work plans. 8.3.2 Maintenance budget The life cycle maintenance budget for the next 5 years is set out in the following table. Life Cycle Maintenance (opex) Connection Maintenance Substations Maintenance Load Control Equipment Radio Equipment SCADA Equipment Zone Sub Faults Zone Sub Minor Maintenance System Control Services Subtotal substations maintenance Lines Maintenance Vegetation Control Voltage Complaint Investigation Transmission Line Minor Maintenance Line Condition Survey and GIS update Maintenance identified in line condition survey Network chargeable Maintenance Transformer Refurbishment (workshop) Distribution Faults Distribution Minor Maintenance Sub Transmission Line Faults Earth Testing Subtotal lines maintenance Total Life Cycle Maintenance Year 1 2014-15 $6k Year 2 2015-16 $6k Year 3 2016-17 $6k Year 4 2017-18 $6k Year 5 2018-19 $6k $6k $24k $1k $48k $400k $479k $6k $24k $1k $48k $400k $479k $6k $24k $1k $48k $400k $479k $6k $24k $1k $48k $400k $479k $6k $24k $1k $48k $400k $479k $850k $12k $24k $967k $500k $60k $50k $500k $650k $60k $60k $3,733k $850k $12k $24k $500k $350k $60k $50k $500k $650k $60k $60k $3,116k $850k $12k $24k $300k $350k $60k $50k $500k $650k $60k $60k $2,916k $850k $12k $24k $300k $350k $60k $50k $500k $650k $60k $60k $2,916k $850k $12k $24k $300k $350k $60k $50k $500k $650k $60k $60k $2,916k $4,218k $3,601k $3,401k $3,401k $3,401k As noted in section 5.1 (Outcomes against plans), the total life cycle maintenance in FY2013 was $3,499k and expected outcome in FY2014 is $4,288k, with the forecast Asset Management Plan Page 128 of 193 ASSET LIFECYCLE levels in total expected to return towards historic levels after a step increase for FY2014 and FY2015 due to the accelerated network surveillance programme plus provision for renewal maintenance work expected to arise out of that surveillance. 8.3.2.1 Connection maintenance This is a provisional annual sum for non-capitalised work associated with new connections and includes minor costs in responding to faults with ICP fuses and customer connections. Cost $6k p.a. 8.3.2.2 Substations maintenance This comprises recurring maintenance on the substation assets including battery changes, oil changes, grounds maintenance etc. It is budgeted based on the average out-turn from previous years. Cost $768k p.a. 8.3.2.3 Lines maintenance This comprises recurring inspection and maintenance on the distributed network. Main components are managing trees, finding and repairing faults, condition inspections and undertaking preventive repairs driven off the condition inspections. Cost $3.733m for FY2015 reducing to $2.916m p.a. from FY2017. 8.3.2.3.1 Vegetation 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 undertaking of this requirement. While some customers have received their first free trim, some are disputing the process and additional costs are occurring to resolve those situations. The forecast costs are $850k p.a. 8.3.2.3.2 Line condition survey and GIS update Monitoring of the distribution network includes the following areas: Network condition surveys. Wooden pole x-ray scanning. Earthing checks. Infrared survey of major distribution equipment. Supply quality checks. Inspections are carried out on a planned basis in accordance with the frequencies listed in Table 37. However, a number of pole failures at loads less than design load, including several unassisted pole failures over the last few years, have highlighted gaps in both the identification of line condition and the recording and application of that data. In response to the potential hazards posed from unknown lines condition, OtagoNet has revised its line inspection template and streamlined its data capture processes and has commenced an accelerated one-off inspection cycle of its full network at a total cost of $1.5m with $967k allocated for FY2015. This is justified on public safety considerations. 8.3.2.3.3 Maintenance identified from line condition surveys An additional $500k is set provisionally in the FY2015 maintenance budget followed by $350k p.a. to cover priority maintenance works that are likely to be discovered during the detailed condition inspections. Asset Management Plan Page 129 of 193 ASSET LIFECYCLE 8.3.2.3.4 Distribution minor maintenance This covers on-going maintenance of assets and includes: Lubrication of ABS‘s. Cleaning of air insulated switchgear. Battery replacements. Rust repairs and painting. TCOL and CB service. Minor customer connections. 8.3.2.3.5 Faults (distribution and subtransmission) 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. The forecast budget for faults restoration and repair is $710 k p.a. Expending this sum clearly depends on the number and nature of the faults impacting the network in the forecast year so this budget has a high degree of variability and is set based on the average costs from previous years. 8.3.2.4 Systemic faults Systemic faults are where a class of component or installation practice is identified as causing failures or hazards. Examples of past investigations and outcomes are: 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. Non-UV stabilised insulation: Exposed LV now has sleeve cover, with new cables UV stabilised. Opossum faults: Extended opossum guard length Currently OtagoNet has identified the earthing arrangements on 750 SWER transformers as being below current recommended practice and has planned for their upgrade at a cost of approximately $1.1m p.a. over two years. This is covered under renewal. 8.3.3 OtagoNet maintenance policies OtagoNet‘s maintenance policies are embodied in the PowerNet standards PNM-99, PNM-97 and PNM-105 which broadly follow manufacturers‘ recommendations but modified by industry experience. 8.4 Renewing OtagoNet’s assets 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 the asset doesn‘t change. OtagoNet‘s key criterion for renewing an asset is when the capitalised operations and maintenance costs exceed the renewal cost or the assessed hazard of failure must be mitigated. Examples include: Operating costs become excessive e.g. addition of inputs to a SCADA system requires an increasing level of manning. Spares for the current asset are no longer available. Maintenance costs begin to accelerate. Asset Management Plan Page 130 of 193 ASSET LIFECYCLE Supply interruptions due to component failure become excessive; what constitutes ―excessive‖ is a matter of judgment which will include the number and nature of customers affected. Renewal costs decline, particularly where costs of new technologies for assets like SCADA or protection devices decrease with capitalised benefits of lower on-going operation and maintenance costs. Failure hazard has become unacceptable (ie deteriorated pole near a school). Asset Management Plan Page 131 of 193 ASSET LIFECYCLE Table 39 below lists OtagoNet‘s renewal triggers for key asset classes. Table 39 – Renewal triggers Asset category LV lines and cables Components Poles Pins, insulators and binders Conductor Distribution substations Poles Enclosures Transformer Distribution lines and cables Switches and fuses Poles Pins, insulators and binders Conductor Ground-mounted switches Regulators Zone substations Fences and enclosures Buildings Bus work and conductors 33kV switchgear Transformer 11kV switchgear Bus work and conductors Instrumentation/Protection Batteries Subtransmission lines and cables Poles Pins, insulators and binders Conductor Cables Asset Management Plan Renewal trigger Fails pole scan. Failure due to external force. Done with pole renewal. Excessive failures. Multiple joints in a segment Multiple corrosion sites Fails pole scan. Failure due to external force. Installation below seismic strength Uneconomic to maintain. Excessive rust. High standing losses, ie pre-1970 core. Not economical to maintain. Not economical to maintain. Fails pole scan. Failure due to external force. Done with pole renewal. Excessive failures. Multiple joints in a segment. Not economical to maintain. No source of spare parts. If not able to be remote controlled. Not economical to maintain. No spare parts. Greater than Standard Life and maintenance required. Not economical to maintain. Not economical to maintain. Not economical to maintain. Not economical to maintain. No spare parts. Greater than Standard Life and maintenance required. Not economical to maintain. No spare parts. Greater than 1.2 Standard Life and maintenance required. Not economical to maintain. No spare parts. Greater than Standard Life and maintenance required. Not economical to maintain. Not economical to maintain. No spare parts. Greater than Standard Life and maintenance required. Prior to manufacturers‘ stated life. On failure of testing. Not economical to maintain. Fails pole scan. Failure due to external force. Not economical to maintain. Not economical to maintain. Excessive joints in a segment Not economical to maintain. Page 132 of 193 ASSET LIFECYCLE Asset category Components Renewal trigger Not economical to maintain. Our equipment within 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. 8.4.1 Current Renewal projects Capital renewal programs and projects planned over the next 5 years are set out in the following table: Life Cycle Renewal Capex Projects Owaka indoor switchgear Port Molyneux indoor switchgear Substation outdoor structure seismic upgrades if not indoor switchgear Replacement reclosers for SWER lines (with automation) SWER Earth upgrades to current best practice Clifton - Clydevale 33 kV line rebuild Ranfurly - Deepdell 33 kV line refurbishment Subtotal projects Identified line renewal works Ongoing 33 kV line rebuild Ongoing 11 kV line rebuild Ongoing LV line rebuild Ongoing transformer refurbishment Year 1 2014-15 $250k $0k $100k Year 2 2015-16 $150k $150k $50k Year 3 2016-17 $0k $100k $300k Year 4 2017-18 $0k $0k $200k Year 5 2018-19 $0k $0k $100k Life Cost $400k $250k $750k $150k $150k $150k $50k $0k $500k $1,000k $200k $250k $1,950k $5,205k $0k $0k $0k $0k $1,000k $500k $0k $2,000k $6,160k $0k $0k $0k $0k $250k $0k $0k $800k $760k $750k $3,300k $1,560k $600k $0k $0k $0k $250k $1,010k $750k $3,300k $1,560k $600k $0k $0k $0k $100k $1,010k $750k $3,300k $1,560k $600k $2,250k $700k $250k $5,100k Total Life Cycle Renewal Capex $7,155k $8,160k $7,770k $7,470k $7,320k Recent expenditure in this category has been approximately $5m per annum so this represents a step increase. 8.4.1.1.1 Owaka switchgear This project replaces the existing old outdoor 11 kV circuit breakers with an indoor switchboard. The outdoor switchgear and bus arrangement has seismic strength and clearance issues and may require additional land for the substation to give adequate clearance to the fences if it was retained. Redevelopment on a different site is not warranted. Cost $400 k. 8.4.1.1.2 Port Molyneux switchgear This project replaces the existing old outdoor 11 kV circuit breakers with an indoor switchboard. The proximity of the substation to the coast means the outdoor equipment suffers accelerated corrosion and salt pollution on the equipment bushings. Redevelopment on a different site is not warranted. Cost $250 k 8.4.1.1.3 Seismic strength A structural report has identified a number of substation buildings and outdoor structures that do not meet current building structural requirements under earthquake. There will be a range of work required at many substations, with the work prioritised and planed for completion over the next five years. More detailed engineering work is required to prioritise and plan the remedial work noting that: Asset Management Plan Page 133 of 193 ASSET LIFECYCLE There will be options for improving the building and structure integrity and each substation will require investigation and recommendations for consideration. As well as improving the strength of existing structures, consideration must be given to the age of the structures and their possible future replacements with indoor equipment. No non-asset solutions are available. Cost $750k over 5 years. 8.4.1.1.4 Replacement reclosers for SWER lines The existing hydraulic reclosers on SWER lines are old and unsupported. This renewal projects will replace, remove or replace in a different location reclosers on SWER lines to achieve improved reliability. Cost $500k over 4 years. 8.4.1.1.5 SWER earthing Until they were revoked under the 2011 amendments, Single Wire Earth Return (SWER) systems were covered under code of practice ECP41 cited in the Electricity (Safety) Regulations 2010. SWER systems are no longer specifically cited in the safety regulations and any test of competency would fall to the electricity industry best practice being the EEA Guide for HV SWER Systems – October 2010. A number of OtagoNet‘s SWER installations include bar joints in the earth continuity conductors (as is practiced in other HV 3-phase grounded neutral systems) and have common HV and LV earths both of which are not recommended practice in the guide (and having joints in the HV earth conductor would not have complied with the previous regulations set out in ECP41). Opening the earth joint with the SWER supply in service would be a safety hazard and is non-compliant under the previous regulations and the current guidelines. OtagoNet has therefore commenced a program to upgrade all its SWER installations to full code compliance as soon as practicable with priority to upgrading the installations with joints in the HV earth conductors. An estimated cost of $1m has been allocated for the FY2015 year with a total cost of $2.5m and this will be subject to further review. Cost $2.25m over 3 years. 8.4.1.1.6 Clifton – Clydevale 33 kV line rebuild This section of line has been identified from condition inspection to warrant line rebuilding as opposed to individual pole replacements. Cost $700k over 2 years 8.4.1.1.7 Ranfurly - Deepdell 33 kV line rebuild This section of line has been identified from condition inspection to warrant line rebuilding as opposed to individual pole replacements. Cost $250k in FY2015 8.4.1.2 Identified line works The following projects have been previously identified through condition assessment and are either on-going or planned over the next 5 years. Completion of this work is dependent on customer requirements, land access permission and priority reassignment as further network condition information becomes available. General Distribution Minor Capital Work Network Chargeable Capital Replacement of O/H structures with Ground Subs Pole or conductor replacements on minor spur lines Asset Management Plan 180,000 60,000 80,000 200,000 Page 134 of 193 ASSET LIFECYCLE Balclutha: Clifton-Old Lake 33kV pole replacement Milton 33 kV line completion Finegand - Owaka 33 kV conductor replacement Hunt Road 11 kV line rebuild on road side Summerhill Rd Wangaloa Clutha leader - TX 2586 replacement on ground Tuapeka Mouth 11 kV Line rebuild on road Chrystalls Beach E/R Lines Mill View Rd Tuapeka West Farquhar Rd SWER Owaka Valley. Puketi E/R - Stage 2 Glenomaru Valley Rd Spur Lines Estate Rd, Clinton Silverpeaks 22 kV Titri Rd, Waihola Fella Burn Road 11kV Project Puerua SWER: Part A North Foreland Street, Waihola. Replace overloaded 200kVA at TX Site 22108 SH-8 Beaumont - Raes Junction Shannon - Matarae 22kV ER (Clarks 22kV) 400,000 800,000 600,000 600,000 270,000 116,000 120,000 321,600 41,200 213,500 451,500 188,000 40,000 135,000 266,000 39,500 306,000 58,000 67,500 216,000 Palmerston Palmerston - Deepdell 33kV pole replacements Deepdell - Middlemarch 33kV Refurbishment Kilmog 11 kV feeder stage 2 Horse Range E/R - Part 1 Bushey Park Road Dunback Footbridge Sweetwater Creek Puketapu Road Hughes Rd Palmerston 250,000 300,000 300,000 80,500 53,000 16,000 32,000 64,000 54,000 Ranfurly McHardy Rd, Sutton Ngapuna - SH87 spurs Three O'Clock - Mt Stoker Ranfurly Spur Lines Ida Valley Station 265,000 171,000 208,000 45,500 157,500 8.4.2 Planned renewal projects Planned renewal projects for years 5 to 10. 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 for lines being reported in section 7. Similarly, parts of the OtagoNet LV and sub transmission lines are planned to be renewed as they reach the end of their economic life noting that renewal of LV lines is generally more expensive than 11 kV feeder lines. Longer term renewal budgeting is based on Poles have a life expectancy of 65 years noting that deterioration of headgear (crossarms, insulators, binders etc.) may be the driver that replaces a deteriorated but serviceable pole given the costs of establishing a work crew at the pole and the economics of doing extended works so that the pole is good for a number of years. By way of the example, the following charts shows the age profile for the hardwood poles together with a hazard curve that give a 10% Asset Management Plan Page 135 of 193 ASSET LIFECYCLE replacement probability at 70 years age. This indicates approximately 240 pole replacements per annum when applied against the age profile. Hardwood Poles Age profile Replacement hazard 600 0.4 0.3 Pole count 400 0.25 300 0.2 200 0.15 0.1 100 0.05 0 0 10 20 30 -100 40 50 60 70 80 90 Age (years) 100 Replacement hazard (per year) 0.35 500 0 -0.05 After including for other asset category renewals (ie transformers, regulators etc.) this gives a long-run renewal budget of approximately $6.7 m p.a. Future projections of long-run renewal levels will improve as better information becomes available from both the condition surveillance data and process improvements in the recording of failure causes. 8.5 Up-sizing or extending OtagoNet’s assets If any of the capacity triggers in Table 26 are exceeded consideration is given to either up-sizing or extending OtagoNet‘s network. This is discussed fully under the network development section of this plan. 8.5.1 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. 8.5.2 Building new assets OtagoNet uses external contractors to augment or extend assets. As part of the building and commissioning process OtagoNet‘s information records are ―as-built‖ and all testing documented. Asset Management Plan Page 136 of 193 ASSET LIFECYCLE 8.6 Enhancing reliability Reliability is a service product of the network that is managed through appropriate network configuration, managing the condition of the network, minimising the environmental exposures (ie tree trimming and fitting possum guards), and responding to the faults that do occur. As noted in the performance and benchmarking sections of this plan, a high proportion of faults relate to the deteriorated lines condition and where the inability to inter-mesh the networks leads to long restoration times and inability to back-feed during planned outages. Also, as described in the background and objectives, whilst customers prefer improved reliability they are also price sensitive, so OtagoNet must balance the cost of any reliability improvement initiatives with the expected benefit through the value that customers place on continuous supply. There are many factors that will lead to a decline in reliability over time including: Tree re-growth. Declining asset condition. Extensions to the network that increase its exposure to trees and weather. Changes in the frequency of extreme weather events 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). Declining asset condition is being addressed through the lines and assets renewal programme, which is driven firstly by safety and maintaining reliability. However, reliability improvement is also considered through targeted maintenance or treetrimming programmes, installation of automatic sectionalisers that limit the impact of line faults and in employing more mobile generation to support load during planned outages. OtagoNet evaluates these initiatives on a case-by-case basis using the following steps: Identifying the customer-minutes lost for each outage by cause. Identifying the scope and likely cost of reducing those lost customer-minutes against the customer value of doing so. Calculating the cost per customer-minute of each enhancement opportunity. Prioritising the enhancement opportunities from lowest cost to highest. Budgeted plans in FY2015 (discussed in the development section of this plan) include purchase of another trailer or truck mounted generator and purchase of a larger generator step-up and earthing transformer to support load during planned outages and a budget of $200 k in FY2015 for the installation of 11 kV reclosers with a total provisional budget of $1 m over 5 years for automatic network sectionalising. 8.7 Converting overhead to underground Conversion of overhead lines to underground cable is an activity that doesn‘t fit within the asset life-cycle as described because it tends to be driven more by amenity value or to remove overhead obstructions rather than for asset-related reasons. As such, conversion tends to rely on other utilities cost sharing or local communities funding the work. Asset relocations planned in the near term are: Network Chargeable Capital Balclutha Main Street LV underground Milton Main Street LV undergrounding John Street - TX 2590 OH lines to underground Asset Management Plan 60,000 400,000 300,000 40,000 Page 137 of 193 ASSET LIFECYCLE Telecom - TX 2591 OH lines to Underground 8.8 80,000 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: 8.9 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 practice reveal unknown hazards. Assets retired for safety reasons will not be re-deployed or sold for reuse. 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 redeployment. Non-network, maintenance and renewal OtagoNet owns offices in the township of Balclutha, which provide workspaces for the OtagoNet employees whose time is predominantly devoted to the OtagoNet area. The maintenance and renewal policies applicable to these buildings are much the same as those applied to zone substation buildings. 8.10 Lifecycle strategies that promote energy efficiency Energy efficiency through reducing network losses is mainly considered during the design of new or up-rated assets or in the component standards for renewal works. Although the cost of losses fall to the network retailers, OtagoNet include costs of losses in its business cases at the retail energy rate. Many of the older SWER lines are constructed with steel conductor. Where SWER conductor is being replaced, modern aluminium, or aluminium/steel-based conductors are used, which for the same diameter offer reduced transmission losses per unit length. In certain situations the replacement of SWER with a single phase circuit generates a further reduction in transmission losses. Energy efficiency is a factor considered when new transformers are purchased to ensure maximum efficiency is gained over the transformer‘s life. Asset Management Plan Page 138 of 193 ASSET LIFECYCLE 8.11 Life Cycle Maintenance and Renewal Budget Table 40 Life cycle budget (FY2015 to 2024) Lifecycle expenditure 2014-15 Fault & emergencies Vegetation management Routine & corrective maintenance Renewal & replacement opex Lifecycle opex total Asset replacement & renewal Asset relocations Reliability, safety, environment Lifecycle capex total $1,658k $850k $1,094k Total lifecycle 20152016201716 17 18 $1,658k $1,658k $1,658k $850k $850k $850k $627k $427k $427k 201819 $1,658k $850k $427k 201920 $1,658k $850k $427k 202021 $1,658k $850k $427k 202122 $1,658k $850k $427k 202223 $1,658k $850k $427k 202324 $1,658k $850k $427k $616k $466k $466k $466k $466k $466k $466k $466k $466k $466k $4,218k $4,320k $3,601k $6,150k $3,401k $6,760k $3,401k $6,660k $3,401k $6,610k $3,401k $6,610k $3,401k $6,610k $3,401k $6,610k $3,401k $6,610k $3,401k $6,610k $1,405k $1,430k $60k $1,650k $60k $950k $60k $750k $60k $650k $60k $550k $60k $550k $60k $550k $60k $550k $60k $550k $7,155k $7,860k $7,770k $7,470k $7,320k $7,220k $7,220k $7,220k $7,220k $7,220k $11,373 k $11,461 k $11,171 k $10,871 k $10,721 k $10,621 k $10,621 k $10,621 k $10,621 k $10,621 k 8.12 Life Cycle by Asset Category This section includes a detailed description of the network assets including age profiles. 8.12.1 Assets installed at non-OtagoNet bulk electricity supply points OtagoNet owns assets at the three Transpower-owned GXPs, and on easements near the Mt Stuart and Paerau Hydro sites. There are no OtagoNet assets installed at Falls Dam. The assets involved are: • • • Balclutha, Naseby, Palmerston GXPs: Each site has an OtagoNet-owned check meter and a SCADA terminal connected to Transpower-owned circuit breakers. Paerau Hydro: All substation assets at this site are owned by OtagoNet. Mt Stuart: OtagoNet owns an outdoor bus with metering unit, relays, and a 33kV CB protecting customer-owned cable. This equipment is physically located on private land approx. 1km from the wind farm. 8.12.2 Subtransmission network The natural split of this group is into 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 under-built 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 carry greater load and are therefore more critical than distribution circuits particularly when they are in a radial configuration where loss of the circuit means loss of the supply. The arrangement of these circuits is very much dependent on load density, 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. 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 zone substations between them. Asset Management Plan Page 139 of 193 ASSET LIFECYCLE 8.12.2.1 Pole line circuits 8.12.2.1.1 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 the thermal capacity of the conductor. Voltage drop is a problem due to the small conductor size 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 road reserves due to the 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 50C to minimise the installation (capital) cost. Whilst some of the circuits have substantial design drawings and route plans, many do not. In particular, the GIS pole positions have been taken from original plans using, for example, road centre-line off-sets. As such, the terrestrial position in the GIS may be incorrect by a few or several meters. More importantly the ground profile under the line is not precisely known in a number of cases so the line design in terms of loads, sags and clearances cannot be fully checked. OtagoNet is undertaking a progressive programme of updating its line data in GIS and undertaking line design checks using its new CTAN software to close this gap. This is also prompted by the line renewal programme that replaces with concrete poles, clamp-top insulators, steel cross-arms and AAAC conductor with incumbent issues of potential resilience under extreme loads. 8.12.2.1.2 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. Figure 45 and Figure 46 summarises the length and age of the subtransmission network poles and conductor respectively. Since most transmission circuits are of overhead line construction these graphs gives a good indication of overall circuit ages. Note however that many circuits have poles and other hardware replaced as and when needed; so the age of a circuit is not necessarily the age of individual components within that circuit. Asset Management Plan Page 140 of 193 ASSET LIFECYCLE Figure 45 - Subtransmission poles Figure 46 - Subtransmission conductor There are a large number of poles past their standard life although environmental conditions in the OtagoNet area are generally very good, with excellent wood pole life in the Maniototo. However, total line refurbishment is indicated where work must be done on the pole tops due to deteriorated crossarms or broken insulator binders and where the pole condition is markedly deteriorated as it is uneconomic not to replace a deteriorated pole given the high work site set-up costs quite apart from the pole climbing risks. The subtransmission fault rate averaged 1.6 faults/100km/annum in 2013 with a variable trend in total faults as shown in the chart of Figure 47 below. Asset Management Plan Page 141 of 193 ASSET LIFECYCLE Figure 47 Trend in subtransmission equipment defect faults 8.12.2.1.3 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. rectified dependent on the urgency. These are Defect inspection is carried out five yearly, and pole scanning at ten yearly intervals, on a rolling basis. This inspection includes checks of foundation, pole integrity, crossarm condition, faulty hardware and insulator condition. The scanning uses x-rays to inspect the internal condition of wooden poles and thermal imaging to highlight hot spots. A more detailed description of the inspection processes is given at section 8.12.5.1.3. These inspections are 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. 8.12.2.1.4 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. 8.12.2.1.5 Replacement plan Refer to the life cycle renewal plan for details of subtransmission circuit replacement. 8.12.2.1.6 Disposal plan There are no plans for any disposal of pole circuit assets. 8.12.2.2 Cable circuits 8.12.2.2.1 Description and capacity The Otago network has only 1.6km of 33kV cable, these are around the Transpower Balclutha and Charlotte Street substations where the overhead line congestion requires it. These cables are 240mm² AL XLPE installed in 1977 near the Balclutha sub, and Asset Management Plan Page 142 of 193 ASSET LIFECYCLE 95mm² AL XLPE installed in 1997 at Charlotte Street. Additional cables were installed in 2007 with the installation of the 33kV switchboard. There is also a section of 95mm2 AL XLPE cable installed 2003/4 on the Patearoa 33kV line to bypass an irrigation system. 8.12.2.2.2 Condition, age, and performance There are no known problems associated with the cables. The cable sizes match the associated lines and substations to which they connect, and so are well utilised. The age profile of the cables is displayed graphically in Figure 48. 8.12.2.2.3 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 protected short lengths without any in line joints. 8.12.2.2.4 Maintenance plan There are no plans for any significant cable maintenance. 8.12.2.2.5 Replacement plan There are no plans for any replacement of subtransmission cables. 8.12.2.2.6 Disposal plan There are no plans for any disposal of cables. Figure 48 - Subtransmission Cables 8.12.3 Zone substations 8.12.3.1 Substations General 8.12.3.1.1 Description and capacity There are 34 zone substations in the OtagoNet network and these are listed in Table 9. These stations vary considerably from installations with indoor switchgear and dual transformers to single outdoor circuit breaker and transformer rural substations. Asset Management Plan Page 143 of 193 ASSET LIFECYCLE The prime general functions of the stations are to house the transformers, switchgear and associated controls. 8.12.3.1.2 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, rust repairs etc. are identified. The standard required is as would be expected for domestic or industrial building. Station batteries are checked yearly and are replaced as per the manufacturers recommendation or at 10 years of age, based on the assumption that failure rates start to climb significantly after this age. Protection relays are tested at intervals of no greater than three years, to detect 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 (SEL) range, which were chosen on a reliability, flexibility and functional basis. Electronic relays are tested at least every six years. SCADA is generally maintained on a repair basis due to the random pattern 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. 8.12.3.1.3 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. 8.12.3.2 Transformers 8.12.3.2.1 Description and capacity OtagoNet power transformers vary significantly in both size and detail. They range from the 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 as 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 but only at sites with high load as set out in the supply security requirements Asset Management Plan Page 144 of 193 ASSET LIFECYCLE discussed in section 7.2.2. Typically they share the load and operate within their economic ONAN rating. Should one transformer not be in service then the remaining transformer can carry the total load which may require the operation of fans and pumps to dissipate heat and the life of the transformer 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 a 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. Therefore regulators are only used on the smallest substations that use 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 them. The OtagoNet zone transformers are also well utilised at around 85%. 8.12.3.2.2 Condition, age, and performance Figure 49 summarises the number and age of the power transformers and Figure 50 the regulator transformers. Figure 49 - Power Transformers Asset Management Plan Page 145 of 193 ASSET LIFECYCLE Figure 50 Regulator Transformers 8.12.3.2.3 Monitoring and procedures Most transformer deterioration is considered 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. Tap Changer maintenance is done on a time and/or count of operations 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. 8.12.3.2.4 Maintenance plan There are no plans for any significant transformer maintenance. All work consists of routine inspection and maintenance. 8.12.3.2.5 Replacement plan The regulators at Oturehua and Waihola are to be replaced in the coming planning period, with power transformer replacements at Pateraoa, Clinton, Finegand, Waitati, Oturehua, and Owaka planned over the next five years. 8.12.3.2.6 Disposal plan Transformers displaced by replacement will have their oil drained and recycled, and the tank and windings will be competitively tendered to scrap metal dealers. Asset Management Plan Page 146 of 193 ASSET LIFECYCLE 8.12.3.3 Circuit Breakers 8.12.3.3.1 Description and capacity Four general group types of switchgear are in use in the networks covered by OtagoNet: 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 to a lowest price tender offer. 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 in circumstances where lower fault interruption ratings may be used. 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 2.5MVA single transformers. Most 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. 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. The OtagoNet network therefore contains a number of circuit breakers outside zone substations, as described in section 8.12.4.1. 8.12.3.3.2 Condition, age, and performance Figure 51 summarises the number and age of the high voltage circuit breakers in the zone substations. Asset Management Plan Page 147 of 193 ASSET LIFECYCLE Figure 51 - Circuit Breakers 8.12.3.3.3 Monitoring and procedures Circuit breakers are considered 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 affected so severely by fault breaking current. OtagoNet does not have significant data on the current breaking levels for individual switching operations. Consequently routine maintenance is carried out at two yearly intervals for oil-based circuit breakers and five yearly intervals 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 checking for correct operation, timing tests, insulation levels and determination of contact life. Contacts or vacuum bottles are replaced as per the manufacturer‘s recommendations. 8.12.3.3.4 Maintenance plan There are no plans for any significant switchgear maintenance. All work consists of routine inspection and maintenance. 8.12.3.3.5 Replacement plan No individual units are planned for early replacement. 8.12.3.3.6 Disposal plan Oil and SF6 gas are reclaimed. Useful spare parts are retained. The contractor scraps the remainder. Asset Management Plan Page 148 of 193 ASSET LIFECYCLE 8.12.3.4 Protection and control Most of the protection is integrated with the circuit breakers described in Section 0, age profiles and condition would be similar except for the protection relays at Ranfurly and Deepdell which were replaced in 2005. 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. 8.12.3.5 SCADA and Communications 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. When the new OtagoNet SCADA system was installed, most communications links were also updated. This equipment is checked and maintained annually by the agents. Figure 52 - Communication radios age profile All SCADA RTU‘s are no older than 15 years with the majority installed in 2000. 8.12.3.6 Ripple control injection plants 8.12.3.6.1 Description and capacity ―Ripple Control‖ controls a large proportion of demand side load directly or indirectly. Ripple control is a communication signal superimposed on the network which is picked up by ripple receiver relays installed in consumers premises which then switch day/night load tariffs or hot water load. The ripple receivers are owned by the retailers. OtagoNet also utilise the ripple system to switch street lights. Modern systems utilise 217Hz or 317Hz as the carrier signal. 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. One, two or three relays control equipment such as hot Asset Management Plan Page 149 of 193 ASSET LIFECYCLE water heating, night store heaters and meters. receivers is intricately tied to meters. The maintenance and control of 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 then to the required frequency. A typical rating is 100kVA at around 200V. The coupling cells vary. Those in use in the OtagoNet 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. The systems within OtagoNet 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 approximately 1.4%. Ripple control has been instrumental in increasing load factor and reducing demands on the network and Transpower Grids Exit Points although changes in the manner in which OtagoNet is charged for GXP capacity and a shift in the time of maximum demand has meant that use of the ripple system for load control is no longer as important. Its main function now is as a service to the retailers for tariff switching. 8.12.3.6.2 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 configuration, not the injection plant. 8.12.3.6.3 Maintenance, replacement and disposal No maintenance is planned other than routine inspection. Figure 53 - Remote Terminal Units (RTU) age profile Asset Management Plan Page 150 of 193 ASSET LIFECYCLE 8.12.4 Distribution Switchgear 8.12.4.1 Description and capacity Distribution switchgear can be classified into five forms. There are the distribution network circuit breakers, which generally consist of pole mounted 11kV outdoor units with integral current transformers. Many of these are solenoid operated reclosers. To achieve reasonable reliability on the network OtagoNet 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. Based on load capacity the circuit breakers are very much underutilised. However, in terms of the more important safety and reliability parameters, there are areas where more circuit breakers should be installed and this is currently being planned. The most common form of switch is in fact a fuse that can be used to switch, isolate and protect equipment. Around 10,000 individual 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 at 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. 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. 8.12.4.2 Condition, age, and performance The outdoor MV circuit breaker age profile is shown in Figure 54, with the oldest units installed in 1968. Asset Management Plan Page 151 of 193 ASSET LIFECYCLE Figure 54 - MV Circuit Breakers 8.12.4.3 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. 8.12.4.4 Maintenance, replacement, and disposal plans Maintenance and disposal of distribution network circuit breakers is the same as for the circuit breakers in the substations (refer sections 8.12.3.3.4 and 8.12.3.3.6). A small budget is set aside for the replacement of the old glass fuses with modern 11kV dropout fuses. There are no other specific plans for replacement of distribution switchgear – they are replaced as and when required, and the displaced items are scrapped. 8.12.5 Distribution network 8.12.5.1 Pole line circuits 8.12.5.1.1 Description and capacity Overhead lines form the backbone of the rural networks and 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. Increasingly it can be expected that this voltage will be used in the future. There are a few other voltages used specifically in conjunction with SWER. Asset Management Plan Page 152 of 193 ASSET LIFECYCLE 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 standard pole is now 11m concrete 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. 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: Table 41 – Standard conductor sizes Conductor Name Chlorine Helium Iodine Neon Oxygen 8.12.5.1.2 Current Rating Resistance 150A 250A 350A 500A 700A 0.86/km 0.38/km 0.24/km 0.12/km 0.09/km Condition, age, and performance Electrical distribution within Otago generally commenced around 1923. Lines are up to 70 years old. Most construction was undertaken in the 1930‘s and then in the 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. New construction levels are presently very low. As a consequence of the wide time frame over which the network was constructed there is a wide 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 a commercially manufactured pre-stressed concrete pole. Copper conductor was very common but this has generally been 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 their 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 are in fact 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. improved strength and expected long life. The new design provides Cross arms are generally hardwood and can suffer from deterioration. Life expectancy varies, but since they are not in contact with the ground a minimum life of 40 years is Asset Management Plan Page 153 of 193 ASSET LIFECYCLE 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 as it enables longer spans. Conductor life is limited by vibration (usually as the result of excessive tension) and corrosion. Copper conductor is robust, but very expensive relative to aluminium. ACSR conductor is prone to corrosion especially in coastal areas. All Aluminium Alloy Conductor has been chosen as a standard conductor and is expected to limit the future maintenance requirements of line conductor. Figure 55 shows the age and length of distribution conductor on the network, while Figure 56 shows the number and age of poles supporting the distribution lines on the network. The wooden poles used for the 15 years to end 2008 are predominantly CCA treated softwoods, while a small number of recent wooden poles will be traditional hardwood where the additional strength is required. The majority of poles since late 2008 are the 11m standard Busck concrete pole. Figure 55 - Distribution conductor Asset Management Plan Page 154 of 193 ASSET LIFECYCLE Distribution Poles 1200 Concrete Wood 1000 Steel Unknown Number of Poles 800 600 400 200 2012 Unknown 2010 2008 2006 2004 2002 2000 1998 1996 1994 1992 1990 1988 1986 1984 1982 1980 1978 1976 1974 1972 1970 1968 1966 1964 1962 1960 1958 1956 1954 1952 1950 1948 1946 1944 1942 1940 1938 1936 1934 1932 1930 1928 1926 1924 0 Commissioning Year Figure 56 - Distribution Poles 8.12.5.1.3 Monitoring and procedures The following specific procedures were included in the previous Asset Management Plan and provided for information. As detailed earlier it is planned to undertake an accelerated program of surveillance of all aspects of the network in the current year. Following completion of this surveillance program the ongoing inspection and surveillance program will be determined relative to safety requirements and driven by information specific to the various components of the network. General 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. Methodology The SAIFI and SAIDI performance of each 11kV feeder and 33/66kV circuit is analysed quarterly and classified as being either Level 1, 2 or 3, with Level 1 representing the worst performance. Those circuits in Level 1 are passed to a team consisting of OtagoNet and Contractor 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. The bullet points and table below provide an indication of the inspection and maintenance regime. Network Safety Inspection Routine inspection to ensure public safety and earthing system integrity. Defect Inspection Detailed route and equipment inspection, generally conducted from ground level and including an ultra-sound inspection. 20% of the feeders/circuits in the Contract Area are inspected every year, so as to provide a five-yearly inspection cycle. Asset Management Plan Page 155 of 193 ASSET LIFECYCLE Targeted Inspections Selected feeders/circuits, including those in Level 1 and those supplying important single customer loads and industrial areas, may require more frequent inspections. The frequency of these inspections is decided on a reliability basis. Annual Inspections These inspections are rapid patrol generally achieved by a drive-by. The object is to identify any obvious defects that may impact network reliability in the short term (two years). 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 industrial and urban feeders may be required within three days of a heavy fault near a substation. Ultra-Sound Inspections To be carried out in conjunction with Defect Inspections and Thermal Inspections. Wood Pole Tests Wood poles are assessed using industry standard methods. 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. Table 42 – Inspection and maintenance regime Level 1 Level 2 CBD and Major Industrial Thermal inspection on fault route < 7 day response and correction of urgent defects < 3 month correction of non-urgent defects No loss of 11kV supply All incidents Level 1 Industrial Thermal, ultra sound and defect inspection < 1 month response and correction of urgent defects live line (LL) < 3 month correction of non-urgent defects No loss of 11kV supply Thermal, ultra sound and defect inspection < 1 month response and correction of urgent defects LL < 3month correction of nonurgent defects Defect inspection < 2 month response and correction of urgent defects LL < 6month correction of nonurgent defects All incidents Level 1 Urban Rural Asset Management Plan Thermal inspection following heavy fault Defect inspection Defect correction LL < 6month correction of non-urgent defects Defect inspection < 2 month response and correction of urgent defects LL < 6month correction of non-urgent defects Level 3 Annual thermal inspection at peak loads, including link boxes Annual cable route inspection 5 yearly defect inspection < 6 month correction of nonurgent defects No loss of 11kV supply Annual thermal inspection at peak loads 5 yearly defect inspection, LL pole top inspection and pole test < 6 month correction of nonurgent defects Annual Inspection 5 yearly thermal and defect inspection and pole test 10 year LL pole top inspection 12 month correction of nonurgent defects Annual Inspection 5 yearly defect inspection/pole test 12month correction of nonurgent defects Page 156 of 193 ASSET LIFECYCLE 8.12.5.1.4 Maintenance plan Maintenance of distribution lines makes up a large proportion of the annual maintenance spend. Defects found in the pole head, crossarm, insulators, tie wire and associated hardware, connections, or terminations are to be repaired as required. 8.12.5.1.5 Replacement plan The high set-up costs for lines replacement works means that it is more economical to renew sections of line at a time where specific poles or hardware require replacement and the general state of the remaining poles is poor. After the initial renewal programmes are completed, it is anticipated that renewal will shift towards individual pole replacement or pole top refurbishment. 8.12.5.1.6 Disposal plan There are no plans for disposal of any circuits under maintenance. 8.12.5.2 Distribution cables 8.12.5.2.1 Description and capacity Most cables in the OtagoNet network tend to be one or three core aluminium conductor, XLPE insulated, medium duty copper screen and HDPE sheath. 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 giving a more economic cable form. The standard sizes and typical ratings of cables are listed below. Table 43 – Standard cable sizes Cable type 2 1 x 3C 35mm Al XLPE 2 1 x 3C 95mm Al XLPE 2 1 x 3C 185mm Al XLPE 2 3 x 1C 300mm Al XLPE Current Rating Resistance 135A 240A 320A 420A 0.868/km 0.320/km 0.164/km 0.100/km Cable rating is very much affected by the thermal parameters of the surrounding media. Most distribution cables are direct buried to limit the temperature rise associated with installation in 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 upon which the nominal cable ratings are determined. Lightning protection (surge diverters) is fitted where cables terminate to overhead lines. Lightning is a dominant cause of cable failure. 8.12.5.2.2 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. The MV cable age profile is shown in Figure 57. Asset Management Plan Page 157 of 193 ASSET LIFECYCLE Figure 57 - MV Cables 8.12.5.2.3 Monitoring and procedures Condition monitoring is not considered to be cost-effective for solid insulated cables. Cables will generally be left undisturbed unless maintenance or upgrade is required. Upgrades may be required due to increased loading or rearrangement of circuits. Failure analysis is the prime tool utilised to identify possible maintenance or remedial action. 8.12.5.2.4 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. 8.12.5.2.5 Replacement plan There are no plans to replace existing cables. 8.12.5.2.6 Disposal plan No cables have been identified for disposal. 8.12.6 Distribution transformers 8.12.6.1 Description and capacity The concept of electrical transformers was central to the development of the present integrated electricity systems found throughout the world. Transformers provide a relatively economic means to convert voltage and so limit electrical losses and volt drop and thereby 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 supplied from an individual transformer. The most common rural transformer sizes are 10kVA to 30kVA. The most economic electrical supply arrangement typically tends to have around 50 domestic customers connected via LV circuits to a single common 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 Asset Management Plan Page 158 of 193 ASSET LIFECYCLE 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. As a result of the different optimum ratings and number of phases to the suit the connected loads OtagoNet employs a 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 (FLTC34) 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 but these carry the risks from seismic strength requirements and oil spills under car vs pole accidents and so 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 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. Earthing at the transformer supply is an important safety system and 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 low resistance grid. In rural areas the main purpose is to create a connection to earth that has a sufficiently low resistance to 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 10 earth resistance. 25mm2 conductor is used, suitable for the lower fault currents. 8.12.6.2 Condition, age, and performance The following chart shows the age and size of the distribution transformers on the network grouped by both size and age. The age profile of earth system is similar to that of transformers but earths are tested on an ongoing basis. 34 On Load Tap Changer is OLTC, so use FLTC for Off Load. Asset Management Plan Page 159 of 193 ASSET LIFECYCLE Figure 58 - Distribution Transformers 8.12.6.3 Monitoring and procedures As transformer failure (other than through lightning damage) 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 limited tank and bushing repair or full refurbishment. This can usually be determined from visual 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 proactively determine risk of failure. The six monthly inspections are largely to check for overload and problems with miscellaneous equipment such as fuse or cable connection heating. Transformers are replaced on site with new or refurbished transformers. Removed transformers are individually assessed for repair, refurbishment or retirement. A five yearly earthing inspection regime is in place. The results are stored in the GIS system and maintenance is planned around the sites with the worst results. Rewirable HV fuses are replaced with standard drop-out cartridge types to improve future reliability as circumstances allow (ie the linesman is at the transformer for other work). 8.12.6.4 Maintenance Plan There are no plans for any large scale maintenance of transformers. All work consists of routine inspection and maintenance. Asset Management Plan Page 160 of 193 ASSET LIFECYCLE 8.12.6.5 Replacement Plan There are no specific plans to replace transformers although we expect to replace on average 100 transformers per annum giving an average transformer life of 45 years. Older small units (<10kVA) are replaced in association with line replacements or maintenance. 8.12.6.6 Disposal Plan Oil is removed from scrapped transformers and the remainder of the transformer is sold as scrap metal. Bushings are sometimes kept where these may prove useful as spares. High loss, old, small and non-standard transformers removed from service are invariably scrapped. 8.12.7 LV network 8.12.7.1 Pole line circuits 8.12.7.1.1 Description and capacity Construction is a mix of underbuilt (on 11 kV lines) and flat top construction with 2 to 5 wires. Copper was the dominant conductor but LV lines are now constructed in Aluminium. The conductor size is relatively small in the older lines due to the typically low loading of the time and this often results in poor voltage delivery at times of higher network loading. Underground reticulation became dominant for new urban extensions from the 1960‘s, but overhead reticulation has remained in most urban areas noting there has been little new subdivision development across the network. A change in overhead construction has been the limited use of Aerial Bundled Conductor (ABC) since around 1990 which is sometimes applied in circumstances of light load and generally with a view to avoid tree contact problems. 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 crosssectional-areas. Some bare aluminium conductor was used prior to the introduction of ABC. 8.12.7.1.2 Condition, age, and performance Most overhead reticulation is relatively old, undersized and in poor condition. Information on the age profile of the LV lines is incomplete; however the data that does exist within the information system is shown in Figure 59 and Figure 60 for the LV conductor and LV poles respectively. Asset Management Plan Page 161 of 193 ASSET LIFECYCLE Figure 59 – Low voltage conductor Figure 60 - Low voltage poles Significant renewal and upgrading is planned to maintain or remedy customer supplies to meet regulatory voltage levels. 8.12.7.1.3 Monitoring and procedures LV line inspections are carried out in the same manner as for distribution lines – refer section 8.12.5.1.3. 8.12.7.1.4 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. Asset Management Plan Page 162 of 193 ASSET LIFECYCLE 8.12.7.1.5 Replacement plan There are no plans for large scale overhead line replacements or undergrounding. 8.12.7.1.6 Disposal plan See overhead distribution. 8.12.7.2 Cable circuits 8.12.7.2.1 Description and capacity New reticulation in urban areas is now undertaken using underground 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. 8.12.7.2.2 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. The LV cable age profile is shown in Figure 61. It should be noted that age profile information on LV cables is incomplete. Figure 61 – Low Voltage cables 8.12.7.2.3 Monitoring and procedures Little monitoring is conducted on cables. Failure analysis is the prime tool utilised to identify possible maintenance or remedial action. 8.12.7.2.4 Maintenance plan Minor works only. 8.12.7.2.5 Replacement plan No planned replacements. Asset Management Plan Page 163 of 193 ASSET LIFECYCLE 8.12.7.2.6 Disposal plan No cables have been identified for disposal. 8.12.8 Other system fixed assets 8.12.8.1 Customer connection assets OtagoNet has 14,812 customer connections; all of OtagoNet‘s ―other assets‖ convey energy to these customer connections and essentially are a cost to OtagoNet that has to be matched by the revenue derived from the customer connections. These customer connections generally involve assets ranging in size from a simple fuse, mounted on a pole or in a distribution pillar, to dedicated lines and transformer installations supplying single large customers. The connection type and number are shown in Table 4435. 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. Table 44 - Connections Connection type 1 (residential) 2 (commercial) 3 (commercial – max. demand) 4 (commercial – major customers) 5 (unmetered) 6 (street lights) 7&8 (low user) Total Total Percent 8394 3384 56.7% 22.8% 46 0.3% 23 0.2% 88 9 2868 14,812 0.6% 0.1% 19.4% 100.0% 8.12.8.2 Service Mains 8.12.8.2.1 Description and capacity Service mains are generally the responsibility of individual customers with the demarcation point at the local pillar box. However a large proportion of rural service mains are MV. MV circuits are generally not a specialty of customers or their electricians and consequently ownership of most MV service mains now resides with OtagoNet. 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. 8.12.8.2.2 Condition, age, and performance There is not enough information available to comment on the age of service mains; this information was lost amidst past ownership changes. 8.12.8.2.3 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 being owned by OtagoNet. 35 Connection type codes as per FY2013 Information Disclosure Asset Management Plan Page 164 of 193 ASSET LIFECYCLE 8.12.8.2.4 Maintenance, replacement and disposal Little maintenance is planned. OtagoNet have a policy of replacing rewirable service fuses with standard cartridge types as circumstances allow. 8.12.9 Mobile generation and mobile substations None – but PowerNet makes a 275kW and/or a 350kW diesel generator available for rent when necessary for planned work. OtagoNet has plans to purchase its own additional mobile generator and larger generator step-up transformer in the FY2015 year as discussed in the development section of this plan. 8.12.10 Other assets None that are known. Asset Management Plan Page 165 of 193 OUR PROCESSES AND SYSTEMS 9. Processes and systems The engine of OtagoNet‘s asset management activities lie with the detailed processes and systems that reflect its thinking, manifest in its policies and strategies, plan and manage the execution of its works and record the cost and performance of the services, all of which ultimately shape the nature and configuration of the fixed assets. OtagoNet‘s processes and systems exist within a hierarchy of value illustrated in Figure 62 which describes the typical sorts of information residing within the business including the intellectual capital of its employees. Wisdom Hard to codify Understanding Knowledge Information Easier to codify Data Figure 62 - 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, SCADA, outage database, and works management systems and where the summaries of this data 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 planning processes reside. As indicated in Figure 62, these are generally hard to codify, and thus correct application is heavily dependent on employing skilled people within the organisation. 9.1 Asset knowledge OtagoNet has considerable knowledge on its assets location (although not to sufficient accuracy), what they are made of, the asset capacity and generally how old they are (but mostly installation ages rather than both manufactured date and last installation date which is preferable). However, it lacks sufficient detail on the current condition and fitness for purpose, particularly for the distributed network assets, and this is a current focus for both system and process development (as well as the physical process of populating this data through field inspection) OtagoNet‘s asset data resides in three key locations: Asset Management Plan Page 166 of 193 OUR PROCESSES AND SYSTEMS Some asset description, location, age and condition information of lines, cables and field devices resides in the Geographical Information System (GIS). This also includes links/layers for land ownership and use data derived from Land Information NZ. Asset descriptions, details, age, cost and works history of identifiable components resides in the Asset Management System (AMS). Asset operational data such as loadings, voltages, temperatures and switch positions reside in the Supervisory Control and Data Acquisition (SCADA). Reliability performance is collected in the outages database An additional class of data (essentially commercial in nature) includes such data as customer details, consumption and billing history. All data systems are connected through key fields. 9.2 Asset management tools A variety of tools and procedures are utilised by OtagoNet to best manage the assets. GIS and AMS software packages are used to store, map and evaluate asset data and manage the work undertaken on them. Technical, operational and business procedures are managed under a document quality system. The outputs of these systems combine to produce both long and medium term plans and the on-going day to day planning and control of the business. 9.2.1 GIS An Intergraph based Geographic Information System is utilised to store and map data on individual components of the network. This focuses primarily on cables, conductors, poles, transformers, switches, fuses and similar geographically dispersed items. Large composite items such as substations are managed by more traditional techniques such as drawings and individual item test reports. Equipment capacity, age and condition are listed by point or segment. The data is used to provide base maps of existing equipment, for extensions to the network, for maintenance scheduling and similar functions. The system allows overlays of terrestrial maps and land information. 9.2.2 AMS WASP (Works, Assets, Scheduling, Purchasing) has been replaced by Maximo in FY2013 as the asset management system (AMS). Maximo has links to the financial management system and is also linked to the GIS system. Maximo consolidated asset management information from WASP and a range of smaller databases, to offer improved data validation functionality. Maximo tracks major assets and is the focus for work packaging and scheduling. 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. Most day to day operations are managed using Maximo. Maintenance regimes (including time-based maintenance and testing work), field inspections and customer‘s orders produce tasks and/or estimates, that are sometimes grouped, and a ‗work package‘ issued from Maximo. 9.2.3 Faults Database All outages are logged into a database which is used to provide regulatory information and statistics on networks performance. Reports from this system are used to highlight Asset Management Plan Page 167 of 193 OUR PROCESSES AND SYSTEMS poorly performing feeders, which are then analysed to determine if it is a maintenance issue or if reliability may be enhanced by other means. 9.3 Improving the quality of the data and processes Because of the importance of the availability of accurate information for maximising customer reliability and efficiency of expenditure and ensuring regulatory compliance it is intended to invest in the order of $1m in the 2014/15 financial year into the development of these systems. 9.3.1 Asset condition Condition information on the distributed assets is not presently reliable or fully useful and a revision of both the inspection templates, the means of automatically up-loading the captured data, and the processes for recovering and applying that data are being re-developed by OtagoNet. Condition information is crucial to both network safety and capital governance and past systems have been found wanting with assets discovered in very poor condition or expressed through unassisted pole failures. OtagoNet has therefore commenced a re-development of the condition inspection regime including revision of it inspection templates, the means of automatic uploading of the collected data, and the processes for data analysis that will support both the measurement of risk and the prioritisation of work. 9.3.2 Attribute location The initial population of the GIS data was through uplifting asset locations off existing drawings and maps and where asset locations may have been noted as being off-set from road centre lines etc. This results in assets being generally placed but the location accuracy is poor with assets showing on the wrong side of roads or off roads in private land when this is not the case. Asset location is being progressively improved as the new condition inspections use field GPS locating devices to verify location. 9.3.3 Attribute description Some delays occur between job completion (eg a new connection) and updating into the GIS/AMS. Not all low voltage lines and cables have been captured and improvement of this data is on-going. 9.3.4 Attribute age Some old components are missing age information altogether. Additionally, a number of assets only list the last installation date rather than both an installation date and a manufactured date making determination of the true age unreliable. 9.3.5 Faults data Presently there is no link between the GIS and the recording of faults so fault locations cannot be plotted and hence fault density/clustering cannot be illustrated. 9.4 Use of the data Data is used for either making decisions within the business or providing data to external entities – for example regulatory disclosure. This data is almost always aggregated and processed in order to make decisions e.g. a decision to replace a zone substation transformer will be based on an aggregation of loading data for the formation of trends, age and condition of the transformer, maintenance cost history etc. Asset Management Plan Page 168 of 193 OUR PROCESSES AND SYSTEMS 9.5 Decision making For efficiency, compliance and consistency, many lower level processes are codified into such documents as technical standards, policies, processes, operating instructions, templates, spreadsheet models etc., much as listed in section 0 following. Higher level strategy and business and asset management planning is undertaken less systematically as it requires assessment of conflicting interests, in-depth analysis of comparative performance and the setting of targets and budgets that drive the business towards the corporate objectives. The source, roles and interaction of each component of the overall information processes are illustrated below in Figure 63. Commercial info – customer number, consumption etc Customer initiated change load Parallel “information asset” Externally initiated change – weather, faults, generators Operational info – switch status, faults, load, voltage etc Repositories – paper, PCs, servers, brains etc Network assets Asset info – description, age, location, condition, history etc Internally initiated change – operational, maintenance, capital Internal decision processes Guides to decision making – policies, procedures, manuals, standards, regulations, legislation, codes, plans etc Info to external parties Figure 63 - Key information systems and processes Asset Management Plan Page 169 of 193 OUR PROCESSES AND SYSTEMS 9.6 Key processes and systems Procedures and process documentation available to OtagoNet are listed following. 9.6.1 Operating processes and systems Commissioning Network Equipment Network Equipment Movements Planned Outages Network Faults, Defects and Supply Complaints Major Network Disruptions Use of Operating Orders (O/O) Control of Tags Access to Substations and Switchyards Operational Requirements for Confined Space Entry Operating Authorisations Radio Telephone Communications Operational Requirements for Live Line Work Control of SCADA Computers Machinery Near Electrical Works Customer Fault Calls/Retail Matters Site Safety Management Audits Meter/Ripple Receiver Control PNM-61 PNM-63 PNM-65 PNM-67 PNM-69 PNM-71 PNM-73 PNM-75 PNM-76 PNM-77 PNM-79 PNM-81 PNM-83 PNM-85 PNM-87 PNM-88 PNM-121 9.6.2 Maintenance processes and systems Control of Network Spares Transformer Maintenance Maintenance Planning Network Lines Equipment Replacement PNM-97 PNM-99 PNM-105 PNM-106 Other maintenance is to manufacturers‘ recommendations or updated industry practice. 9.6.3 Renewal processes and systems Network Development Design and Development PNM-113 PNM-114 9.6.4 Up-sizing or extension processes and systems Network Development Design and Development Processing Installation Connection Applications Easements PNM-113 PNM-114 PNM-123 PNM-131 9.6.5 Retirement processes and systems Disconnected and/or Discontinued Supplies PNM-125 9.6.6 Performance measuring processes and systems 9.6.6.1 Faults All faults are entered into the faults database and reported monthly to the Governing Committee, together with details of all the planned outages. Asset Management Plan Page 170 of 193 OUR PROCESSES AND SYSTEMS 9.6.6.2 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 through the accounting systems with project managers managing costs through the AMS. Interfaces between F1 and AMS track estimates and costs against assets. 9.6.6.3 Customer Customer statistics are monitored by a Customer Database system, developed by ACE computers, which 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. 9.6.6.4 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. 9.6.7 Other business processes In addition to the above processes that are specific to life cycle activities, OtagoNet has a range of general business processes available to it that guide activities such as evaluating tenders and closing out contracts: Setting Up the Contract Tender Evaluation Contract Formation Construction Approval Materials Management Contract Control Contract Close Out Customer Satisfaction External Contracting Drawing Control Network Operational Diagram/GIS Control Control of Operating and Maintenance Manuals Control of External Standards Control of Power Quality Recorders Quality Plans Health and Safety Accidents and Incidents Design and Development Network Purchasing Network Pricing Customer Service Performance Incoming and Outgoing Mail Correspondence Asset Management Plan PNM-10 PNM-15 PNM-20 PNM-25 PNM-30 PNM-35 PNM-40 PNM-50 PNM-60 PNM-89 PNM-91 PNM-93 PNM-95 PNM-103 PNM-107 PNM-109 PNM-111 PNM-114 PNM-115 PNM-117 PNM-119 PNM-129 Page 171 of 193 RESOURCING OUR BUSINESS 10. Resourcing the business Resourcing an operation such as OtagoNet in rural New Zealand imposes its unique challenges.Because of the relatively small customer base and revenue, it is imperative all resources are utilised efficiently. It is intended to increase the level of OtagoNet staff in Balclutha in the 2015 year to better serve the interests of OtagoNet and its customers. OtagoNet has agreements with PowerNet and Marlborough Lines to provide administration, accounting and IT services (including control room services) and engineering support respectively and OPSL to provide Network Contractor services. Should workload be beyond what OPSL can provide then other contractors will be contracted for specific projects. Provision of these services is secured through the management services contracts which is monitored and managed by the OtagoNet governing committee. 10.1 Future resourcing requirements OtagoNet‘s main contractor, OPSL has adequate resources for the present work program requirements The forecast budget for FY2015 is approximately $16m capital and $4.5m maintenance and is forecast to continue at these levels for a number of years. This expenditure represents a step increase on previous capital expenditure as described within this plan. However, OtagoNet have no reason to believe the works set out in this plan for the next forecast year cannot be achieved and sets plans for both the execution and management of that work including the contracting of resources as required. Asset Management Plan Page 172 of 193 RESOURCING OUR BUSINESS A. Appendix – AMP Disclosure Requirements The following table sets out the Commerce Commission requirements for disclosed asset management plans and identifies where these requirements are met within this plan. Clause 1.1 1.2 1.3 1.4 1.5 1.6 1.7 1.8 1.9 3 3.1 3.2 3.3 3.3.1 3.3.2 3.3.3 3.3.4 3.3.5 3.4 3.5 3.6 3.6.1 3.6.2 3.6.3 3.6.4 3.7 Requirement The core elements of asset management— A focus on measuring network performance, and managing the assets to achieve service targets; Monitoring and continuously improving asset management practices; Close alignment with corporate vision and strategy; That asset management is driven by clearly defined strategies, business objectives and service level targets; That responsibilities and accountabilities for asset management are clearly assigned; An emphasis on knowledge of what assets are owned and why, the location of the assets and the condition of the assets; An emphasis on optimising asset utilisation and performance; That a total life cycle approach should be taken to asset management; That the use of ‗non-network‘ solutions and demand management techniques as alternatives to asset acquisition is considered. Contents of the AMP 3. The AMP must include the followingA summary that provides a brief overview of the contents and highlights information that the EDB considers significant Details of the background and objectives of the EDB‘s asset management and planning processes A purpose statement whichmakes clear the purpose and status of the AMP in the EDB‘s asset management practices. The purpose statement must also include a statement of the objectives of the asset management and planning processes states the corporate mission or vision as it relates to asset management identifies the documented plans produced as outputs of the annual business planning process adopted by the EDB states how the different documented plans relate to one another, with particular reference to any plans specifically dealing with asset management includes a description of the interaction between the objectives of the AMP and other corporate goals, business planning processes, and plans Details of the AMP planning period, which must cover at least a projected period of 10 years commencing with the disclosure year following the date on which the AMP is disclosed The date that it was approved by the directors A description of stakeholder interests (owners, consumers etc) which identifies important stakeholders and indicateshow the interests of stakeholders are identified what these interests are how these interests are accommodated in asset management practices how conflicting interests are managed A description of the accountabilities and responsibilities for asset management on at least 3 levels, including- Asset Management Plan AMP Response Section(s) 3, 5, 6 3, 5, 6, 9 1 5, 6 1.8, 2, 8 3, 5 8, 7.7 0. 1. 1.1 1.2, 1.3, 1.4 1.3.3, 1.4.7 1.4, 1.5, 1.6, 1.6, 1.7, 1.7.1, 1.7.2, 1.7.3, 1.7.4, 1.8, Page 173 of 193 RESOURCING OUR BUSINESS 3.7.1 3.7.2 3.7.3 3.8 3.8.1 3.8.2 3.8.3 3.8.4 3.8.5 3.9 3.10 3.11 3.12 3.13 3.13.1 3.13.2 3.13.3 3.14 governance—a description of the extent of director approval required for key asset management decisions and the extent to which asset management outcomes are regularly reported to directors 1.8.1, 1.8.5 executive—an indication of how the in-house asset management and planning organisation is structured 1.8.2, field operations—an overview of how field operations are managed, including a description of the extent to which field work is undertaken in-house and the areas where outsourced contractors are used 1.8.3, 1.8.4 All significant assumptions 1.6, Apx C quantified where possible 7.8.4.1, Apx C clearly identified in a manner that makes their significance understandable to interested persons, including a description of changes proposed where the information is not based on the EDB‘s existing business the sources of uncertainty and the potential effect of the uncertainty on the prospective information Apx C the price inflator assumptions used to prepare the financial information disclosed in nominal New Zealand dollars in the Report on Forecast Capital Expenditure set out in Schedule 11a and the Report on Forecast Operational Expenditure set out in Schedule 11b. A description of the factors that may lead to a material difference between the prospective information disclosed and the corresponding actual information recorded in future disclosures 1.6, Apx C An overview of asset management strategy and delivery 1.4, 1.5 An overview of systems and information management data 9, 9.5, 9.6 To support the AMMAT disclosure and assist interested persons to assess the maturity of systems and information management, the AMP should describe- the processes used to identify asset management data requirements that cover the whole of life cycle of the assets; the systems used to manage asset data and where the data is used, including an overview of the systems to record asset conditions and operation capacity and to monitor the performance of assets; the systems and controls to ensure the quality and accuracy of asset management information; and the extent to which these systems, processes and controls are integrated. A statement covering any limitations in the availability or completeness of asset management data and disclose any initiatives intended to improve the quality of this data 9, A description of the processes used within the EDB for1.8, managing routine asset inspections and network maintenance 9.5.7, 8.3 planning and implementing network development projects 9.5.7, 7, measuring network performance. 9.5.6, 3 An overview of asset management documentation, controls and review processes 9,1.4 To support the AMMAT disclosure and assist interested persons to assess the maturity of asset management documentation, controls and review processes, the AMP should- (i) identify the documentation that describes the key components of the asset management system and the links between the key components; (ii) describe the processes developed around documentation, control and review of key components of the asset management system; (iii) where the EDB outsources components of the asset management system, the processes and controls that the EDB uses to ensure efficient and cost effective delivery of its asset management strategy; (iv) where the EDB outsources components of the asset management system, the systems it uses to retain core asset knowledge in-house; and (v) audit or review procedures undertaken in respect of the asset Asset Management Plan Page 174 of 193 RESOURCING OUR BUSINESS management system. 3.15 3.16 3.17 4 4.1 4.1.1 4.1.2 4.1.3 4.1.4 4.2 4.2.1 4.2.2 4.2.3 4.2.4 4.2.5 4.2.6 4.3 An overview of communication and participation processes To support the AMMAT disclosure and assist interested persons to assess the maturity of asset management documentation, controls and review processes, the AMP should- (i) communicate asset management strategies, objectives, policies and plans to stakeholders involved in the delivery of the asset management requirements, including contractors and consultants; (ii) demonstrate staff engagement in the efficient and cost effective delivery of the asset management requirements. The AMP must present all financial values in constant price New Zealand dollars except where specified otherwise; The AMP must be structured and presented in a way that the EDB considers will support the purposes of AMP disclosure set out in clause 2.6.2 of the determination. Assets covered The AMP must provide details of the assets covered, includinga high-level description of the service areas covered by the EDB and the degree to which these are interlinked, includingthe region(s) covered identification of large consumers that have a significant impact on network operations or asset management priorities description of the load characteristics for different parts of the network peak demand and total energy delivered in the previous year, broken down by sub-network, if any. a description of the network configuration, includingidentifying bulk electricity supply points and any distributed generation with a capacity greater than 1 MW. State the existing firm supply capacity and current peak load of each bulk electricity supply point; a description of the subtransmission system fed from the bulk electricity supply points, including the capacity of zone substations and the voltage(s) of the subtransmission network(s). The AMP must identify the supply security provided at individual zone substations, by describing the extent to which each has n-x subtransmission security or by providing alternative security class ratings; a description of the distribution system, including the extent to which it is underground; a brief description of the network‘s distribution substation arrangements; a description of the low voltage network including the extent to which it is underground; and an overview of secondary assets such as protection relays, ripple injection systems, SCADA and telecommunications systems. To help clarify the network descriptions, network maps and a single line diagram of the subtransmission network should be made available to interested persons. These may be provided in the AMP or, alternatively, made available upon request with a statement to this effect made in the AMP. If sub-networks exist, the network configuration information referred to in subclause 4.2 above must be disclosed for each sub-network. Asset Management Plan 1.7.5, 0.11 Complies 2, 2.1, 2.1.1, 2.1.3, 2.1.4, 2.1.5, 2.1.6, 2.2, 2.2.1, 2.2.2, 2.2.3, 2.2.4, 2.2.5, 2.2.6, 2.2.7, 2.2.3, Not applicable Page 175 of 193 RESOURCING OUR BUSINESS 4.4 4.4.1 4.4.2 4.4.3 4.4.4 4.5 4.5.1 4.5.2 4.5.3 4.5.4 4.5.5 4.5.6 4.5.7 4.5.8 4.5.9 4.5.10 4.5.11 5 6 7 7.1 7.2 8 9 10 11 11.1 The AMP must describe the network assets by providing the following information for each asset categoryvoltage levels; description and quantity of assets; age profiles; and a discussion of the condition of the assets, further broken down into more detailed categories as considered appropriate. Systemic issues leading to the premature replacement of assets or parts of assets should be discussed. The asset categories discussed in subclause 4.4 above should include at least the followingSub transmission Zone substations Distribution and LV lines Distribution and LV cables Distribution substations and transformers Distribution switchgear Other system fixed assets Other assets; assets owned by the EDB but installed at bulk electricity supply points owned by others; EDB owned mobile substations and generators whose function is to increase supply reliability or reduce peak demand; and other generation plant owned by the EDB. Service Levels The AMP must clearly identify or define a set of performance indicators for which annual performance targets have been defined. The annual performance targets must be consistent with business strategies and asset management objectives and be provided for each year of the AMP planning period. The targets should reflect what is practically achievable given the current network configuration, condition and planned expenditure levels. The targets should be disclosed for each year of the AMP planning period. Performance indicators for which targets have been defined in clause 5 above must include SAIDI and SAIFI values for the next 5 disclosure years. Performance indicators for which targets have been defined in clause 5 above should also includeConsumer oriented indicators that preferably differentiate between different consumer types; Indicators of asset performance, asset efficiency and effectiveness, and service efficiency, such as technical and financial performance indicators related to the efficiency of asset utilisation and operation. The AMP must describe the basis on which the target level for each performance indicator was determined. Justification for target levels of service includes consumer expectations or demands, legislative, regulatory, and other stakeholders‘ requirements or considerations. The AMP should demonstrate how stakeholder needs were ascertained and translated into service level targets. Targets should be compared to historic values where available to provide context and scale to the reader. Where forecast expenditure is expected to materially affect performance against a target defined in clause 5 above, the target should be consistent with the expected change in the level of performance. Network Development Planning AMPs must provide a detailed description of network development plans, including— A description of the planning criteria and assumptions for network development; Asset Management Plan 8.12, 8.12, 8.12, 8.12 8.12 8.12.2, 8.12.3, 8.12.5, 8.12.7, 8.12.5, 8.12.6, 8.12.4, 8.12.8, 8.12.10, 8.12.1, 8.12.9, 8.12.10, 6, 6.5.1, 6.1.2, 6.3, 3, 4, 6.1.1, 6.1.2, 6.3.2 5.1, 5.2.1, 5.2.3 6.1.1 7 7.1, Page 176 of 193 RESOURCING OUR BUSINESS Planning criteria for network developments should be described logically and succinctly. Where probabilistic or scenario-based planning techniques are used, this should be indicated and the methodology 11.2 briefly described; A description of strategies or processes (if any) used by the EDB that promote cost efficiency including through the use of standardised assets 11.3 and designs; The use of standardised designs may lead to improved cost efficiencies. 11.4 This section should discuss11.4.1 the categories of assets and designs that are standardised; 11.4.2 the approach used to identify standard designs. A description of strategies or processes (if any) used by the EDB that 11.5 promote the energy efficient operation of the network. A description of the criteria used to determine the capacity of equipment 11.6 for different types of assets or different parts of the network. A description of the process and criteria used to prioritise network development projects and how these processes and criteria align with 11.7 the overall corporate goals and vision. Details of demand forecasts, the basis on which they are derived, and the specific network locations where constraints are expected due to 11.8 forecast increases in demand; explain the load forecasting methodology and indicate all the 11.8.1 factors used in preparing the load estimates; provide separate forecasts to at least the zone substation level covering at least a minimum five year forecast period. Discuss how uncertain but substantial individual projects/developments that affect load are taken into account in the forecasts, making clear the extent to which these uncertain increases in demand 11.8.2 are reflected in the forecasts; identify any network or equipment constraints that may arise due to the anticipated growth in demand during the AMP planning 11.8.3 period; and discuss the impact on the load forecasts of any anticipated levels of distributed generation in a network, and the projected impact 11.8.4 of any demand management initiatives. Analysis of the significant network level development options identified and details of the decisions made to satisfy and meet target levels of 11.9 service, includingthe reasons for choosing a selected option for projects where 11.9.1 decisions have been made; the alternative options considered for projects that are planned to start in the next five years and the potential for non-network 11.9.2 solutions described; consideration of planned innovations that improve efficiencies within the network, such as improved utilisation, extended asset 11.9.3 lives, and deferred investment. A description and identification of the network development programme including distributed generation and non-network solutions and actions to be taken, including associated expenditure projections. The network 11.10 development plan must includea detailed description of the material projects and a summary description of the non-material projects currently underway or 11.10.1 planned to start within the next 12 months; a summary description of the programmes and projects planned 11.10.2 for the following four years (where known); and an overview of the material projects being considered for the 11.10.3 remainder of the AMP planning period. For projects included in the AMP where decisions have been made, the reasons for choosing the selected option should be stated which should include how target levels of service will be impacted. For other projects planned to start in the next five years, alternative options should be discussed, including the potential for non-network approaches to be Asset Management Plan 7.7, 7.1.3, 7.7.1, 7.7.1, 7.7.1, 7.7.1, 7.10, 7.1.4, 7.2, 7.3, 7.3.2, 7.3.3 7.3.4 7.4 7.5, 7.6 7.8, 7.7.1, 7.8.1 7.8.1 7.8.1, 7.10 7.8, 7.8, 7.8.1 7.8.1 7.8.2 Page 177 of 193 RESOURCING OUR BUSINESS more cost effective than network augmentations. A description of the EDB‘s policies on distributed generation, including the policies for connecting distributed generation. The impact of such 11.11 generation on network development plans must also be stated. 11.12 A description of the EDB‘s policies on non-network solutions, includingeconomically feasible and practical alternatives to conventional network augmentation. These are typically approaches that would reduce network demand and/or improve asset utilisation; 11.12.1 and the potential for non-network solutions to address network 11.12.2 problems or constraints. Lifecycle Asset Management Planning (Maintenance and Renewal) The AMP must provide a detailed description of the lifecycle asset 12 management processes, including— 12.1 The key drivers for maintenance planning and assumptions; Identification of routine and corrective maintenance and inspection policies and programmes and actions to be taken for each asset category, including associated expenditure projections. This must 12.2 includethe approach to inspecting and maintaining each category of assets, including a description of the types of inspections, tests and condition monitoring carried out and the intervals at which 12.2.1 this is done; any systemic problems identified with any particular asset types 12.2.2 and the proposed actions to address these problems; and budgets for maintenance activities broken down by asset 12.2.3 category for the AMP planning period. Identification of asset replacement and renewal policies and programmes and actions to be taken for each asset category, including associated 12.3 expenditure projections. This must includethe processes used to decide when and whether an asset is replaced or refurbished, including a description of the factors on which decisions are based, and consideration of future demands 12.3.1 on the network and the optimum use of existing network assets; a description of innovations made that have deferred asset 12.3.2 replacement; a description of the projects currently underway or planned for 12.3.3 the next 12 months; a summary of the projects planned for the following four years 12.3.4 (where known); and an overview of other work being considered for the remainder of 12.3.5 the AMP planning period. The asset categories discussed in subclauses 12.2 and 12.3 above 12.4 should include at least the categories in subclause 4.5 above. Non-Network Development, Maintenance and Renewal AMPs must provide a summary description of material non-network 13 development, maintenance and renewal plans, including— 13.1 a description of non-network assets; 13.2 development, maintenance and renewal policies that cover them; a description of material capital expenditure projects (where known) 13.3 planned for the next five years; a description of material maintenance and renewal projects (where 13.4 known) planned for the next five years. Risk Management AMPs must provide details of risk policies, assessment, and mitigation, 14 including— 14.1 Methods, details and conclusions of risk analysis; Asset Management Plan 7.5, 7.6, 7.5 8 8.3, 8.1, 8.3 8.3.1, 8.3.3 8.3.2.4, 8.11, 8.4, 8.4 8.4 8.4.1 8.4.2 8.4.3 8.12 7.9, 8.9, 8.12.9, 8.12.10 7, 8 7, 8 7, 8 4, 4.1, 4.2, Page 178 of 193 RESOURCING OUR BUSINESS 14.2 14.3 14.4 15 15.1 15.2 15.3 15.4 16 16.1 16.2 Strategies used to identify areas of the network that are vulnerable to high impact low probability events and a description of the resilience of the network and asset management systems to such events; A description of the policies to mitigate or manage the risks of events identified in subclause 16.2; Details of emergency response and contingency plans. Asset risk management forms a component of an EDB’s overall risk management plan or policy, focusing on the risks to assets and maintaining service levels. AMPs should demonstrate how the EDB identifies and assesses asset related risks and describe the main risks within the network. The focus should be on credible low-probability, highimpact risks. Risk evaluation may highlight the need for specific development projects or maintenance programmes. Where this is the case, the resulting projects or actions should be discussed, linking back to the development plan or maintenance programme. Evaluation of performance AMPs must provide details of performance measurement, evaluation, and improvement, including— A review of progress against plan, both physical and financial; referring to the most recent disclosures made under Section 2.6 of this determination, discussing any significant differences and highlighting reasons for substantial variances; commenting on the progress of development projects against that planned in the previous AMP and provide reasons for substantial variances along with any significant construction or other problems experienced; commenting on progress against maintenance initiatives and programmes and discuss the effectiveness of these programmes noted. An evaluation and comparison of actual service level performance against targeted performance; in particular, comparing the actual and target service level performance for all the targets discussed under the Service Levels section of the AMP in the previous AMP and explain any significant variances; An evaluation and comparison of the results of the asset management maturity assessment disclosed in the Report on Asset Management Maturity set out in Schedule 13 against relevant objectives of the EDB‘s asset management and planning processes. An analysis of gaps identified in subclauses 15.2 and 15.3 above. Where significant gaps exist (not caused by one-off factors), the AMP must describe any planned initiatives to address the situation. Capability to deliver AMPs must describe the processes used by the EDB to ensure thatThe AMP is realistic and the objectives set out in the plan can be achieved; The organisation structure and the processes for authorisation and business capabilities will support the implementation of the AMP plans. Asset Management Plan 4.2, 4.2, 4.3, 5 5.1, 5.2, 5.3 5.3, 10 10, 10.1 10, 10.1 Page 179 of 193 APPENDIX - CONSUMER ENGAGEMENT SURVEY B. Appendix - Customer Engagement Survey PowerNet Consumer Engagement Telephone Survey: OtagoNet © Gary Nicol Associates Phone Date Interviewer Good afternoon/evening my name is _____. I am conducting a brief customer survey on behalf of OtagoNet. 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 OtagoNet is? No 1 Go to A2 2 Go to A3 A2: Using a 1 to 5 rating scale where 1 is Poor and 5 is Excellent can you rate the performance of OtagoNet over the last 12 months for: Caring for customers 1 2 3 4 5 X Sensitive to the environment 1 2 3 4 5 X Supporting the community 1 2 3 4 5 X Safety conscious 1 2 3 4 5 X Go to D1 Efficiency 1 2 3 4 5 X A3: OtagoNet maintains the local electricity lines and substations that supply power to your premises. D1: Do you live in a mainly rural or Urban urban area? Rural 5 D2: Are you a commercial or residential Commercial customer? Residential 1 Question 1: OtagoNet is proposing a Yes maximum of one planned interruption to your power supply, on average, every No year in order to carry out maintenance or upgrade work on its electricity network. Don‘t know/unsure Do you consider this number of planned interruptions to be reasonable? 2 years Question 1(a): How many years between planned interruptions do you 3 years Asset Management Plan 6 2 1 Go to Q 2 2 Go to Q 1(a) 3 Go to Q 2 1 2 Page 180 of 193 APPENDIX - CONSUMER ENGAGEMENT SURVEY consider to be more reasonable? 3 4 years Question 2: OtagoNet expects such Yes planned interruptions will on average No last up to four hours each. Do you consider this amount of time to Don‘t know/unsure be reasonable? 1 Go to Q 3 2 Go to Q 2(a) 3 Go to Q 3 1 hour Question 2(a): What length of time would you consider to be more 2 hours reasonable? (Specify hours) 3 hours 1 Yes Question 3: Have you received advice of a planned electricity interruption No during the last 6 months? Don‘t know/unsure 1 Go to Q 3(a) 2 Go to Q 3(e) 3 Go to Q 3(e) Yes Question 3(a): Were you satisfied with the amount of information given to you No about this planned interruption? Unable to recall 1 Go to Q 3(c) 2 Go to Q 3(b) 3 Go to Q 3(c) 2 3 Question 3 (b): What additional information would you have liked? Yes Question 3(c): Do you feel that you were given enough notice of this No planned interruption? Don‘t know/unsure 1 Go to Q 3(e) 2 Go to Q 3(d) 3 Go to Q 3(e) Question 3(d): How much notice of 1 day planned interruptions would you prefer 3 days to be given? (Specify days/weeks) 1 1 week 4 2 2 weeks 5 (Do not prompt) 3 Other 6 5 days Question 3(e): Do you have a preferred Yes day and time(s) for a planned interruptions? No Asset Management Plan 1 Go to Q 3(f) 2 Go to Q 4 Page 181 of 193 APPENDIX - CONSUMER ENGAGEMENT SURVEY Question 3 (f): What is your preferred day and time(s)? 1 Go to Q 4(a) Yes Question 4: Have you had an unexpected interruption to your power No supply during the last 6 months? Unable to recall Question 4(a): Thinking about the most recent unexpected interruption to your electricity supply, how long did it take for your supply to be restored? (Specify hours/days) 2 Go to Q 5 3 Go to Q 5 Within 45 min 1 3 hours 5 1 hour 2 4 hours 6 11/2 hours 3 12 hours 7 2 hours 4 Don‘t know 8 Other 9 (Do not prompt) Yes Question 4(b): Do you consider your electricity supply was restored within a No reasonable amount of time? Unable to recall Question 4(c): What do you consider 30 minutes would have been a more reasonable amount of time? (Specify hours/days) 45 minutes 1 Go to Q 5 2 Go to Q 4(c) 3 Go to Q 5 1 11/2 hours 4 2 2 hours 5 3 Other (Do not prompt) Go to Q5(a) Question 5: In the event of an unexpected interruption to your electricity supply, what do you consider would be a reasonable amount of time before electricity supply is restored to your home? (Specify hours/days) (Do not prompt) 1 hour 5 minutes 1 2 hours 10 10 minutes 2 3 hours 11 15 minutes 3 4 hours 12 20 minutes 4 5 hours 13 30 minutes 5 6 hours 14 40 minutes 6 12 hours 15 45 minutes 7 1 day 16 1 hour 8 Unsure 17 11/2 hours 9 Other 18 Question 5(a): OtagoNet is reviewing Yes the level of service provided to its customers and options include increasing spending. Presently there is No an average of four interruptions each Asset Management Plan 6 1 2 Page 182 of 193 APPENDIX - CONSUMER ENGAGEMENT SURVEY year. If this was reduced to three interruptions per year would you be happy to pay an additional $10 per Don‘t know/unsure month on your electricity bill? 3 Meridian Energy 1 Contact Energy 2 3 Question 6: Who would you contact in Mighty River Power the event of the power supply to your TrustPower home being unexpectedly interrupted? (Do not prompt) 4 PowerNet 5 OtagoNet 6 Genesis Energy 7 Other 8 Yes Question 7: Have you made such a call No within the last 6 months? Unable to recall Question 8: Were you satisfied that the Yes system worked in getting you enough No information about the supply interruption? Don‘t know/unsure 1 Go to Q 8 2 Go to Q 8(d) 3 Go to Q 8(d) 1 Go to Q 8(b) 2 Go to Q 8(a) 3 Go to Q 8(b) Question 8 (a): What, if anything, do you feel could be done to improve this system? Yes Question 8 (b): Were you satisfied with No the information that you received? Don‘t know/unsure 1 Go to Q 8(d) 2 Go to Q 8(c) 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? time when Question 8 (d): What is the most Accurate 1 important information you wish to power will be restored receive when you experience an 2 Reason for fault unplanned supply interruption? (Do not prompt) Asset Management Plan Other 3 Page 183 of 193 APPENDIX - CONSUMER ENGAGEMENT SURVEY Question 8(e): Are you aware of Yes 1 OtagoNet‘s 0800 faults number? Question 9: Have you contacted Yes OtagoNet regarding any other issues No relating to your electricity supply during the last 6 months? Unable to recall No 2 1 Go to Q 9(a) 2 Go to Q 9(e) 3 Go to Q 9(e) 1 Voltage complaints Question 9(a): What did your enquiry Safety disconnections relate to? New or altered supply (Do not prompt) 2 3 Trees near lines 4 Other 5 Yes Question 9 (b): Were you satisfied with the performance of the OtagoNet staff No member(s) who handled your enquiry? Don‘t know/unsure 1 Go to Q 9(d) 2 Go to Q 9(c) 3 Go to Q 9(e) Question 9 (c): Specifically what were you dissatisfied with? Question 9 (d): Was there anything that OtagoNet did well? Question 9 (e): What if anything do you feel could be done to improve the service provided by OtagoNet staff? This concludes our survey - Thank you for your time Asset Management Plan Page 184 of 193 APPENDIX - ASSUMPTIONS C. Appendix – Assumptions When developing this plan we have made the following key assumptions: No major developments in the region, unless specifically identified. - Developers don‘t always let OtagoNet know of their plans with large projects kept confidential until the last minute. Growth trends will be similar to historic trends. - No step changes considered as none are certain but noting the announced possible closure of the Macraes gold mine circa 2017 is considered within this plan. No change in present regulations that would impact planned expenditures. Distributed generation will develop slowly with little impact within the planning period. The standard life of assets is based on the ODV asset life, with actual replacement done on a condition basis. - Some areas exceed standard lives (Inland North Otago) and others fail to reach standard lives (Coastal regions). No decline in meat and wool markets. - Closure of any large customer would have a significant a small rural network. Continuation of trend for increased use of spray irrigation. No major development in coal extraction and/or processing. The Plan will be reviewed following the completion of the accelerated network surveillance program to be undertaken. Asset management plan Page 185 of 193 APPENDIX – EDIDD SCHEDULES D. Appendix – EDIDD Schedule 11a Company Name AMP Planning Period OtagoNet Joint Venture 1 April 2014 – 31 March 2024 SCHEDULE 11a: REPORT ON FORECAST CAPITAL EXPENDITURE This schedule requires a breakdown of forecast expenditure on assets for the current disclosure year and a 10 year planning period. The forecasts should be consistent with the supporting information set out in the AMP. The forecast is to be expressed in both constant price and nominal dollar terms. Also required is a forecast of the value of commissioned assets (i.e., the value of RAB additions) EDBs must provide explanatory comment on the difference between constant price and nominal dollar forecasts of expenditure on assets in Schedule 14a (Mandatory Explanatory Notes). This information is not part of audited disclosure information. sch ref 1 7 8 9 for year ended 11a(i): Expenditure on Assets Forecast 10 Consumer connection 11 System growth 12 Asset replacement and renewal 13 Asset relocations 14 Reliability, safety and environment: 15 Quality of supply 16 17 Legislative and regulatory Other reliability, safety and environment 18 19 Expenditure on network assets 21 1.084 1.151 1.201 1.239 1.269 1.301 1.348 1.397 1.447 CY+1 CY+2 CY+3 CY+4 CY+5 CY+6 CY+7 CY+8 CY+9 CY+10 31 Mar 14 31 Mar 15 31 Mar 16 31 Mar 17 31 Mar 18 31 Mar 19 31 Mar 20 31 Mar 21 31 Mar 22 31 Mar 23 31 Mar 24 $000 (in nominal dollars) Total reliability, safety and environment 20 1 Current Year CY 822 1,000 109 1,779 736 206 515 1,399 164 168 174 180 187 4,685 4,520 9,593 9,910 10,761 10,668 12,195 12,503 12,954 13,425 13,906 1,405 65 69 72 74 76 78 81 84 3,441 600 813 391 661 310 - - - - - 695 2,090 1,832 1,093 901 805 698 716 741 768 796 4,136 2,690 2,645 1,485 1,561 1,115 698 716 741 768 796 9,796 11,394 14,123 12,821 14,111 14,495 14,402 14,765 15,298 15,855 16,422 44 1,084 1,151 1,201 1,239 1,269 1,301 1,348 1,397 1,447 87 Non-network assets - - - - - - - - - - - Expenditure on assets 9,796 11,394 14,123 12,821 14,111 14,495 14,402 14,765 15,298 15,855 16,422 22 23 plus 24 less 25 26 plus 27 Cost of financing Value of capital contributions 573 1,352 750 796 831 857 878 900 933 967 1,001 9,223 10,042 13,373 12,024 13,279 13,638 13,524 13,865 14,366 14,888 15,421 Value of vested assets Capital expenditure forecast 28 29 Value of commissioned assets 9,223 30 for year ended 32 Consumer connection 34 System growth 35 Asset replacement and renewal 36 Asset relocations 37 Reliability, safety and environment: 38 Quality of supply 39 40 Legislative and regulatory Other reliability, safety and environment 41 Total reliability, safety and environment 42 Expenditure on network assets 43 44 12,024 13,279 13,638 13,524 13,865 14,366 14,888 15,421 CY+2 CY+3 CY+4 CY+5 CY+6 CY+7 CY+8 CY+9 CY+10 31 Mar 15 31 Mar 16 31 Mar 17 31 Mar 18 31 Mar 19 31 Mar 20 31 Mar 21 31 Mar 22 31 Mar 23 31 Mar 24 822 1,000 1,000 1,000 109 1,779 679 179 429 1,129 129 129 129 129 129 4,685 4,520 8,850 8,610 8,960 8,610 9,610 9,610 9,610 9,610 9,610 1,405 60 60 60 60 60 60 60 60 3,441 600 750 340 550 250 - - - - - 695 2,090 1,690 950 750 650 550 550 550 550 550 4,136 2,690 2,440 1,290 1,300 900 550 550 550 550 550 9,796 11,394 13,029 11,139 11,749 11,699 11,349 11,349 11,349 11,349 11,349 11,349 11,349 11,349 11,349 11,349 44 1,000 1,000 Non-network assets - - - - - - Expenditure on assets 9,796 11,394 13,029 11,139 11,749 11,699 1,000 1,000 1,000 1,000 1,000 60 Subcomponents of expenditure on assets (where known) 47 Energy efficiency and demand side management, reduction of energy losses 48 Overhead to underground conversion 49 Research and development 57 58 59 13,373 CY+1 31 Mar 14 $000 (in constant prices) 33 45 46 10,042 Current Year CY Current Year CY for year ended Difference between nominal and constant price forecasts CY+1 31 Mar 14 $000 CY+2 31 Mar 15 CY+3 31 Mar 16 CY+4 31 Mar 17 CY+5 31 Mar 18 CY+6 31 Mar 19 CY+7 31 Mar 20 CY+8 31 Mar 21 CY+9 31 Mar 22 CY+10 31 Mar 23 31 Mar 24 60 Consumer connection - - 84 151 201 239 269 301 348 397 61 System growth - - 57 27 86 270 35 39 45 51 58 62 Asset replacement and renewal - - 743 1,300 1,801 2,058 2,585 2,893 3,344 3,815 4,296 63 Asset relocations - - 5 9 12 14 16 18 21 24 447 64 Reliability, safety and environment: 27 65 Quality of supply - - 63 51 111 60 - - - - - 66 67 Legislative and regulatory Other reliability, safety and environment - - 142 143 151 155 148 166 191 218 246 - - 205 195 261 215 148 166 191 218 246 - - 1,094 1,682 2,362 2,796 3,053 3,416 3,949 4,506 5,073 68 Total reliability, safety and environment 69 Expenditure on network assets 70 Non-network assets 71 72 Expenditure on assets - for year ended 74 - - 73 Current Year CY 31 Mar 14 - - CY+1 31 Mar 15 - 1,094 CY+2 31 Mar 16 - 1,682 CY+3 31 Mar 17 2,362 CY+4 31 Mar 18 - - - - - - 2,796 3,053 3,416 3,949 4,506 5,073 CY+5 31 Mar 19 11a(ii): Consumer Connection 75 Consumer types defined by EDB* 76 New Connections $000 (in constant prices) 822 1,000 1,000 1,000 1,000 1,000 822 1,000 1,000 1,000 1,000 1,000 563 650 650 650 650 650 259 350 350 350 350 350 77 78 79 80 81 *include additional rows if needed 82 83 Consumer connection expenditure less 84 85 Capital contributions funding consumer connection Consumer connection less capital contributions 11a(iii): System Growth 86 Subtransmission 65 87 Zone substations 1 750 250 50 300 1,000 88 Distribution and LV lines 43 1,029 429 129 129 129 89 Distribution and LV cables 90 Distribution substations and transformers 91 92 Distribution switchgear Other network assets 109 1,779 679 179 429 1,129 109 1,779 679 179 429 93 94 System growth expenditure less 95 Capital contributions funding system growth System growth less capital contributions 103 104 105 for year ended 11a(iv): Asset Replacement and Renewal 106 Subtransmission 107 Zone substations 108 Distribution and LV lines 109 Distribution and LV cables 110 Distribution substations and transformers 111 112 114 CY+2 CY+3 CY+4 CY+5 31 Mar 15 31 Mar 16 31 Mar 17 31 Mar 18 31 Mar 19 $000 (in constant prices) 779 2,000 1,650 750 750 750 218 220 2,720 1,870 2,320 2,020 3,688 2,150 4,330 5,240 5,240 5,240 - - 600 600 less 600 150 150 150 50 - 4,520 8,850 8,610 8,960 8,610 4,675 4,520 8,850 8,610 8,960 8,610 36 60 60 60 60 60 8 1,345 - - - - Asset relocations expenditure 44 1,405 60 60 60 60 Capital contributions funding asset relocations Asset relocations less capital contributions 44 702 703 42 18 42 18 42 18 42 18 200 200 200 200 200 50 200 Asset replacement and renewal expenditure 115 116 117 CY+1 31 Mar 14 Distribution switchgear Other network assets 113 1,129 Current Year CY 4,685 Capital contributions funding asset replacement and renewal 10 Asset replacement and renewal less capital contributions 11a(v):Asset Relocations Project or programme* 118 Chargeable capital 119 Overhead to underground projects 120 121 122 123 124 *include additional rows if needed All other asset relocations projects or programmes 125 126 127 less 128 129 11a(vi):Quality of Supply 130 Project or programme* 131 Reclosers and SCADA automation 132 Clydevale 33 kV ring protection 133 Milton 33 kV ring protection 134 Palmerston GXP purchase and conversion to 33 kV 135 Distribution ties 136 137 *include additional rows if needed All other quality of supply projects or programmes 138 139 - - 200 - - - 150 140 350 50 3,441 600 750 340 550 250 3,441 600 750 340 550 250 - - - - - - - - - - - 572 Quality of supply expenditure less 140 - 50 300 2,869 Capital contributions funding quality of supply Quality of supply less capital contributions 141 142 11a(vii): Legislative and Regulatory 143 Project or programme* 144 145 146 147 148 149 150 *include additional rows if needed All other legislative and regulatory projects or programmes 151 152 Legislative and regulatory expenditure less 153 Capital contributions funding legislative and regulatory Legislative and regulatory less capital contributions - 161 162 for year ended 163 Current Year CY 31 Mar 14 CY+1 31 Mar 15 CY+2 31 Mar 16 CY+3 31 Mar 17 CY+4 31 Mar 18 CY+5 31 Mar 19 11a(viii): Other Reliability, Safety and Environment 164 Project or programme* 165 Zone substation safety and environmental protection 166 Overhead distribution subs to groundmount 167 SWER earth upgrades to best practice $000 (in constant prices) 656 390 400 200 100 80 300 300 300 300 1,000 1,000 250 250 250 695 2,090 1,690 950 750 650 695 2,090 1,690 950 750 650 - - - - - - Atypical expenditure - - - - - - Non-network assets expenditure - - - - - - 39 1,010 168 169 170 171 *include additional rows if needed All other reliability, safety and environment projects or programmes 172 173 174 175 176 177 178 179 180 Other reliability, safety and environment expenditure less Capital contributions funding other reliability, safety and environment Other reliability, safety and environment less capital contributions 11a(ix): Non-Network Assets Routine expenditure Project or programme* 181 182 183 184 185 186 187 188 189 190 *include additional rows if needed All other routine expenditure projects or programmes Routine expenditure Atypical expenditure Project or programme* 191 192 193 194 195 196 197 198 *include additional rows if needed All other atypical projects or programmes 199 200 Asset management plan Page 186 of 193 Asset management plan Operational Expenditure Forecast Routine and corrective maintenance and inspection Asset replacement and renewal 12 13 Routine and corrective maintenance and inspection Asset replacement and renewal 24 25 Direct billing* Research and Development Insurance 34 35 36 Vegetation management Routine and corrective maintenance and inspection Asset replacement and renewal 43 44 45 Non-network opex Operational expenditure 50 System operations and network support Business support 49 47 48 Network Opex Service interruptions and emergencies 46 Difference between nominal and real forecasts 42 $000 31 Mar 14 41 Current Year CY for year ended 40 - - - - - - - 7,386 3,098 188 2,910 4,288 625 1,758 775 1,130 39 38 37 * Direct billing expenditure by suppliers that direct bill the majority of their consumers Energy efficiency and demand side management, reduction of energy losses 33 32 Subcomponents of operational expenditure (where known) Operational expenditure 30 31 Non-network opex System operations and network support Business support 29 27 28 Network Opex Vegetation management 23 26 Service interruptions and emergencies 22 $000 (in constant prices) 31 Mar 14 21 Current Year CY for year ended 7,386 20 Operational expenditure 18 3,098 188 2,910 4,288 625 1,758 775 1,130 19 Non-network opex System operations and network support Business support 17 15 16 Network Opex Vegetation management 11 14 Service interruptions and emergencies 10 1 $000 (in nominal dollars) 31 Mar 14 9 Current Year CY 8 for year ended 7 sch ref CY+1 7,750 3,532 2,025 1,507 4,218 - - - - - - - 7,750 3,532 2,025 1,507 4,218 1,094 616 850 1,658 31 Mar 15 CY+1 850 1,094 616 31 Mar 15 CY+1 1 1,658 31 Mar 15 CY+2 1.035 CY+2 CY+2 31 Mar 16 204 78 45 33 126 22 16 30 58 7,133 3,532 2,025 1,507 3,601 627 466 850 1,658 31 Mar 16 7,337 3,610 2,070 1,540 3,727 649 482 880 1,716 31 Mar 16 CY+3 1.072 CY+3 CY+3 31 Mar 17 409 164 94 70 245 31 34 61 119 6,933 3,532 2,025 1,507 3,401 427 466 850 1,658 31 Mar 17 7,342 3,696 2,119 1,577 3,646 458 500 911 1,777 31 Mar 17 CY+4 1.113 CY+4 CY+4 31 Mar 18 637 253 145 108 384 48 53 96 187 6,933 3,532 2,025 1,507 3,401 427 466 850 1,658 31 Mar 18 7,570 3,785 2,170 1,615 3,785 475 519 946 1,845 31 Mar 18 CY+5 1.155 CY+5 CY+5 31 Mar 19 871 344 197 147 527 66 72 132 257 6,933 3,532 2,025 1,507 3,401 427 466 850 1,658 31 Mar 19 7,804 3,876 2,222 1,654 3,928 493 538 982 1,915 31 Mar 19 CY+6 1.199 CY+6 CY+6 437 250 187 677 85 93 169 330 1,114 31 Mar 20 6,933 3,532 2,025 1,507 3,401 427 466 850 1,658 31 Mar 20 8,047 3,969 2,275 1,694 4,078 512 559 1,019 1,988 31 Mar 20 CY+7 1.245 CY+7 CY+7 532 305 227 833 105 114 208 406 1,366 31 Mar 21 6,933 3,532 2,025 1,507 3,401 427 466 850 1,658 31 Mar 21 8,299 4,064 2,330 1,734 4,234 532 580 1,058 2,064 31 Mar 21 CY+8 8,549 4,162 2,386 1,776 4,387 1,616 630 361 269 986 124 135 247 481 6,933 3,532 2,025 1,507 3,401 427 466 850 1,658 31 Mar 22 CY+8 551 601 1,097 31 Mar 22 CY+8 1.29 2,139 31 Mar 22 CY+9 CY+9 CY+9 143 157 286 557 1,872 730 418 312 1,143 31 Mar 23 6,933 3,532 2,025 1,507 3,401 427 466 850 1,658 31 Mar 23 8,805 4,262 2,443 1,819 4,544 570 623 1,136 2,215 31 Mar 23 1.336 1.385 CY+10 CY+10 164 179 327 638 2,141 832 477 355 1,309 31 Mar 24 6,933 3,532 2,025 1,507 3,401 427 466 850 1,658 31 Mar 24 9,074 4,364 2,502 1,862 4,710 591 645 1,177 2,296 31 Mar 24 CY+10 OtagoNet Joint Venture 1 April 2014 – 31 March 2024 This schedule requires a breakdown of forecast operational expenditure for the disclosure year and a 10 year planning period. The forecasts should be consistent with the supporting information set out in the AMP. The forecast is to be expressed in both constant price and nominal dollar terms. EDBs must provide explanatory comment on the difference between constant price and nominal dollar operational expenditure forecasts in Schedule 14a (Mandatory Explanatory Notes). This information is not part of audited disclosure information. SCHEDULE 11b: REPORT ON FORECAST OPERATIONAL EXPENDITURE Company Name E. AMP Planning Period APPENDIX – EDIDD SCHEDULES Appendix – EDIDD Schedule 11b Page 187 of 193 APPENDIX – EDIDD SCHEDULES F. Appendix – EDIDD Schedule 12a Company Name AMP Planning Period OtagoNet Joint Venture 1 April 2014 – 31 March 2024 SCHEDULE 12a: REPORT ON ASSET CONDITION This schedule requires a breakdown of asset condition by asset class as at the start of the forecast year. The data accuracy assessment relates to the percentage values disclosed in the asset condition columns. Also required is a forecast of the percentage of units to be replaced in the next 5 years. All information should be consistent with the information provided in the AMP and the expenditure on assets forecast in Schedule 11a. All units relating to cable and line assets, that are expressed in km, refer to circuit lengths. sch ref 7 Asset condition at start of planning period (percentage of units by grade) 8 Units Grade 1 Grade 2 Grade 3 Grade 4 Grade unknown % of asset forecast to be replaced in next 5 years Data accuracy (1–4) Voltage Asset category Asset class 9 10 All Overhead Line Concrete poles / steel structure No. 1.86% 0.69% 19.22% 5.84% 72.39% 3 5.14% 11 All Overhead Line Wood poles No. 1.04% 1.00% 11.81% 2.88% 83.27% 3 34.52% 12 All Overhead Line Other pole types No. 13 HV Subtransmission Line Subtransmission OH up to 66kV conductor km 0.04% 0.02% 0.86% 0.51% 98.57% 3 28.69% 14 HV Subtransmission Line Subtransmission OH 110kV+ conductor km N/A 15 HV Subtransmission Cable Subtransmission UG up to 66kV (XLPE) km 100.00% N/A 16 HV Subtransmission Cable Subtransmission UG up to 66kV (Oil pressurised) km N/A 17 HV Subtransmission Cable Subtransmission UG up to 66kV (Gas pressurised) km N/A 18 HV Subtransmission Cable Subtransmission UG up to 66kV (PILC) km N/A 19 HV Subtransmission Cable Subtransmission UG 110kV+ (XLPE) km N/A 20 HV Subtransmission Cable Subtransmission UG 110kV+ (Oil pressurised) km N/A 21 HV Subtransmission Cable Subtransmission UG 110kV+ (Gas Pressurised) km N/A 22 HV Subtransmission Cable Subtransmission UG 110kV+ (PILC) km 23 HV Subtransmission Cable Subtransmission submarine cable km 24 HV Zone substation Buildings Zone substations up to 66kV No. 25 HV Zone substation Buildings Zone substations 110kV+ No. 26 HV Zone substation switchgear 22/33kV CB (Indoor) No. 27 HV Zone substation switchgear 22/33kV CB (Outdoor) No. 28 HV Zone substation switchgear 33kV Switch (Ground Mounted) No. 29 HV Zone substation switchgear 33kV Switch (Pole Mounted) No. 30 HV Zone substation switchgear 33kV RMU No. N/A 31 HV Zone substation switchgear 50/66/110kV CB (Indoor) No. N/A 32 HV Zone substation switchgear 50/66/110kV CB (Outdoor) No. 33 HV Zone substation switchgear 3.3/6.6/11/22kV CB (ground mounted) No. 16.67% 27.78% 55.55% 3 13.89% 34 HV Zone substation switchgear 3.3/6.6/11/22kV CB (pole mounted) No. 22.86% 72.86% 4.28% 3 17.14% N/A N/A N/A 2.94% 58.82% 23.53% 14.71% 3 N/A 100.00% 24.14% 65.52% 4 10.34% 3 13.79% 3 7.00% N/A 12.80% 78.40% 8.80% 100.00% 42 43 3 Asset condition at start of planning period (percentage of units by grade) Units Grade 1 Grade 2 Grade 3 Grade 4 Grade unknown % of asset forecast to be replaced in next 5 years Data accuracy (1–4) Voltage Asset category Asset class 45 HV Zone Substation Transformer Zone Substation Transformers No. 46 HV Distribution Line Distribution OH Open Wire Conductor km 47 HV Distribution Line Distribution OH Aerial Cable Conductor km 48 HV Distribution Line SWER conductor km 49 HV Distribution Cable Distribution UG XLPE or PVC km 100.00% N/A 50 HV Distribution Cable Distribution UG PILC km 100.00% N/A 51 HV HV Distribution Cable Distribution switchgear Distribution Submarine Cable km 52 3.3/6.6/11/22kV CB (pole mounted) - reclosers and sectionalisers No. 53 HV Distribution switchgear No. 54 HV Distribution switchgear 3.3/6.6/11/22kV CB (Indoor) 3.3/6.6/11/22kV Switches and fuses (pole mounted) 55 HV Distribution switchgear 3.3/6.6/11/22kV Switch (ground mounted) - except RMU No. 56 HV Distribution switchgear 3.3/6.6/11/22kV RMU No. 57 HV Distribution Transformer Pole Mounted Transformer No. 58 HV Distribution Transformer Ground Mounted Transformer No. 59 HV Distribution Transformer Voltage regulators No. 60 HV Distribution Substations Ground Mounted Substation Housing No. 61 LV LV Line LV OH Conductor km 62 LV LV Cable LV UG Cable km 63 LV LV Streetlighting LV OH/UG Streetlight circuit km 64 Connections Protection OH/UG consumer service connections No. 65 LV All Protection relays (electromechanical, solid state and numeric) No. 12.64% 52.45% 34.91% 66 All SCADA and communications SCADA and communications equipment operating as a single system Lot 3.77% 62.27% 33.96% 67 All Capacitor Banks Capacitors including controls No. 68 All Load Control Centralised plant Lot 69 All Load Control Relays No. N/A 70 All Civils Cable Tunnels km N/A 44 Asset management plan 9.52% 76.19% 14.29% 3.60% 1.96% 24.99% 2.68% 2.07% 0.30% 3.09% 1.50% 66.77% 3 7.14% 3 17.93% 3 14.47% N/A 93.04% 5.88% N/A 7.70% 46.15% 46.15% 3 53.85% N/A No. 25.19% 72.55% 2.26% 3 N/A 100.00% 1.56% 10.00% 3 0.79% 20.55% 2.00% 11.76% 64.71% 23.53% 75.10% 3 10.00% 3 17.65% 2 2.96% 3 5.00% 100.00% N/A N/A 1.06% 0.75% 6.51% 0.35% 1.06% 0.75% 6.51% 0.35% 91.33% 100.00% N/A 91.33% 100.00% N/A 3 2.26% 3 18.86% 3 50.00% N/A 50.00% 25.00% 25.00% Page 188 of 193 Asset management plan 2.0 2.7 0.1 6.4 1.1 0.7 4.2 1.7 0.2 1.2 1.4 1.5 2.4 0.7 2.4 2.8 0.2 1.5 0.3 Clinton Clydevale Deepdell Elderlee St Finegand Glenore Golden Point Greenfield Hindon Hyde Kaitangata Lawrence Macraes Mine Merton Middlemarch Milburn North Balclutha Oturehua Owaka Paerau 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 36 35 34 32 33 31 30 29 1.7 0.7 0.4 2.2 Patearoa Port Molyneux Pukeawa Ranfurly 1.2 1.3 1.5 0.2 Waihola Waipiata Waitati Wedderburn Zone substation transformer capacity Total distribution transformer capacity Distribution transformer capacity (EDB owned) Distribution transformer capacity (Non-EDB owned) 12b(ii): Transformer Capacity (MVA) 158 205 163 42 ¹ Extend forecast capacity table as necessary to disclose all capacity by each zone substation 3.9 Stirling 25.3 2.2 Palmerston Ranfurly 66/33 kV 12.8 Paerau Hydro 22.4 0.4 Clarks Junction 11 9 10 Current Peak Load (MVA) 6.1 12b(i): System Growth - Zone Substations Existing Zone Substations Charlotte St 8 7 sch ref Security of Supply Classification (type) 0.8 N 2.5 N 2.5 N 1.5 N 5.0 N 50.0 N-1 5.0 N-1 switched 0.8 N 2.5 N 2.5 N 5.0 N 30.0 N 0.8 N 2.5 N 0.8 N 5.0 N 7.5 N 2.5 N 5.0 N 30.0 N 2.5 N 2.5 N 2.5 N 0.5 N 2.3 N 5.0 N 1.5 N 2.5 N 10.0 N-1 0.8 N 2.5 N 2.5 N 0.5 N 10.0 N-1 Installed Firm Capacity (MVA) Transfer Capacity (MVA) 25% 60% 52% 80% 78% 51% 44% 50% 28% 68% 44% 43% 38% 60% 25% 56% 32% 28% 48% 75% 60% 56% 48% 40% 74% 84% 47% 44% 64% 13% 108% 80% 80% 61% Utilisation of Installed Firm Capacity % 0.8 2.5 2.5 1.5 5.0 50.0 5.0 0.8 2.5 2.5 5.0 30.0 0.8 2.5 0.8 5.0 7.5 2.5 5.0 30.0 2.5 2.5 2.5 0.5 2.3 5.0 2.5 2.5 10.0 0.8 5.0 2.5 0.5 10.0 Installed Firm Capacity +5 years (MVA) Installed Firm Capacity Constraint +5 years (cause) 84% Transformer 78% Transformer 46% Transformer 48% Transformer 75% 14% 69% Transformer 86% Transformer 61% Transformer Utilisation of Installed Firm Capacity + 5yrs % This schedule requires a breakdown of current and forecast capacity and utilisation for each zone substation and current distribution transformer capacity. The data provided should be consistent with the information provided in the AMP. Information provided in this table should relate to the operation of the network in its normal steady state configuration. SCHEDULE 12b: REPORT ON FORECAST CAPACITY Company Name Monitor - 1% growth rate Discuss reliability requirement with single customer Near N-1 capacity (on transformers). Site to be relocated Near N-1 capacity (on transformers) Low growth rate Possible closure New 2.5 MVA transformer with new site New 5.0 MVA transformer and existing 2.5 for on-site spare Monitor Explanation Over N-1 capacity but load transfer available OtagoNet Joint Venture 1 April 2014 – 31 March 2024 G. AMP Planning Period APPENDIX – EDIDD SCHEDULES Appendix – EDIDD Schedule 12b Page 189 of 193 OtagoNet Joint Venture 1 April 2014 – 31 March 2024 Asset management plan Commercial Maximum Demand Contract 14 Installed connection capacity of distributed generation (MVA) 21 Demand on system for supply to consumers' connection points Net transfers to (from) other EDBs at HV and above Maximum coincident system demand GXP demand Distributed generation output at HV and above Losses Load factor Loss ratio 39 40 Total energy delivered to ICPs Electricity entering system for supply to ICPs 37 38 36 less plus less 33 34 35 Electricity exports to GXPs 32 Electricity supplied from distributed generation Net electricity supplied to (from) other EDBs Electricity supplied from GXPs less 31 Electricity volumes carried (GWh) less plus Maximum coincident system demand (MW) 30 29 28 27 25 26 24 12c(ii) System Demand Number of connections 20 22 23 Distributed generation 19 17 18 Connections total *include additional rows if needed Domestic 13 15 16 Consumer types defined by EDB* 12 Number of ICPs connected in year by consumer type 12c(i): Consumer Connections 11 8 9 10 7 sch ref for year ended for year ended 5.0% 79% 21 402 423 83 340 61 61 48 13 Current Year CY 31 Mar 14 59 1 26 32 Current Year CY 31 Mar 14 79% 21 402 423 83 340 61 61 48 13 104 4 20 80 5.0% CY+1 31 Mar 15 CY+1 31 Mar 15 80% 21 404 425 83 342 61 61 48 13 5.0% CY+2 31 Mar 16 104 4 20 80 79% 21 406 427 83 344 62 62 49 13 104 4 20 80 5.0% CY+3 31 Mar 17 Number of connections CY+2 CY+3 31 Mar 16 31 Mar 17 79% 21 408 429 83 346 62 62 49 13 104 4 20 80 5.0% CY+4 31 Mar 18 CY+4 31 Mar 18 78% 22 409 431 83 348 63 63 50 13 104 4 20 80 5.0% CY+5 31 Mar 19 CY+5 31 Mar 19 This schedule requires a forecast of new connections (by consumer type), peak demand and energy volumes for the disclosure year and a 5 year planning period. The forecasts should be consistent with the supporting information set out in the AMP as well as the assumptions used in developing the expenditure forecasts in Schedule 11a and Schedule 11b and the capacity and utilisation forecasts in Schedule 12b. SCHEDULE 12C: REPORT ON FORECAST NETWORK DEMAND Company Name H. AMP Planning Period APPENDIX – EDIDD SCHEDULES Appendix – EDIDD Schedule 12c Page 190 of 193 Asset management plan OtagoNet Joint Venture 1 April 2014 – 31 March 2024 0.63 2.03 0.63 2.04 0.63 2.05 0.63 2.06 0.63 2.07 0.57 2.35 Class B (planned interruptions on the network) Class C (unplanned interruptions on the network) 14 15 SAIFI 172.0 173.0 173.0 174.0 13 148.0 148.0 148.0 148.0 175.0 CY+5 31 Mar 19 148.0 CY+4 31 Mar 18 199.0 CY+3 31 Mar 17 151.0 CY+2 31 Mar 16 Class C (unplanned interruptions on the network) CY+1 31 Mar 15 Class B (planned interruptions on the network) Current Year CY 31 Mar 14 12 SAIDI for year ended 11 sch ref 8 9 10 This schedule requires a forecast of SAIFI and SAIDI for disclosure and a 5 year planning period. The forecasts should be consistent with the supporting information set out in the AMP as well as the assumed impact of planned and unplanned SAIFI and SAIDI on the expenditures forecast provided in Schedule 11a and Schedule 11b. SCHEDULE 12d: REPORT FORECAST INTERRUPTIONS AND DURATION Company Name I. AMP Planning Period Network / Sub-network Name APPENDIX – EDIDD SCHEDULES Appendix – EDIDD Schedule 12d Page 191 of 193 APPENDIX – EDIDD SCHEDULES J. Appendix – EDIDD Schedule 13 Summary of Asset Management Maturity Assessment Tool. Question No. Function 3 Asset management policy 10 Asset management strategy 11 Asset management strategy 26 Question To what extent has an asset management policy been documented, authorised and communicated? Score Evidence—Summary 3 The asset management policy is authorised by top management, is widely and effectively communicated to all relevant employees and stakeholders, and used to make these persons aware of their asset related obligations. 3 Asset management plan(s) What has the organisation done to ensure that its asset management strategy is consistent with other appropriate organisational policies and strategies, and the needs of stakeholders? In what way does the organisation's asset management strategy take account of the lifecycle of the assets, asset types and asset systems over which the organisation has stewardship? How does the organisation establish and document its asset management plan(s) across the life cycle activities of its assets and asset systems? 27 Asset management plan(s) How has the organisation communicated its plan(s) to all relevant parties to a level of detail appropriate to the receiver's role in their delivery? 3 29 Asset management plan(s) How are designated responsibilities for delivery of asset plan actions documented? 3 31 Asset management plan(s) What has the organisation done to ensure that appropriate arrangements are made available for the efficient and cost effective implementation of the plan(s)? 2 33 Contingency planning 37 Structure, authority and responsibilities 40 Structure, authority and responsibilities 42 Structure, authority To what degree does the organisation's top management communicate the importance of and responsibilities meeting its asset management requirements? 3 Top management communicates the importance of meeting its asset management requirements to all relevant parts of the organisation. 45 Outsourcing of asset management activities Training, awareness and competence Where the organisation has outsourced some of its asset management activities, how has it ensured that appropriate controls are in place to ensure the compliant delivery of its organisational strategic plan, and its asset management policy and strategy? How does the organisation develop plan(s) for the human resources required to undertake asset management activities - including the development and delivery of asset management strategy, process(es), objectives and plan(s)? Training, awareness How does the organisation identify competency requirements and then plan, provide and and competence record the training necessary to achieve the competencies? 3 Training, awareness How does the organization ensure that persons under its direct control undertaking and competence asset management related activities have an appropriate level of competence in terms of education, training or experience? Communication, How does the organisation ensure that pertinent asset management information is participation and effectively communicated to and from employees and other stakeholders, including consultation contracted service providers? Asset Management What documentation has the organisation established to describe the main elements of System its asset management system and interactions between them? documentation Information What has the organisation done to determine what its asset management information management system(s) should contain in order to support its asset management system? 3 Evidence exists to demonstrate that outsourced activities are appropriately controlled to provide for the compliant delivery of the organisational strategic plan, asset management policy and strategy, and that these controls are integrated into the asset management system The organisation can demonstrate that plan(s) are in place and effective in matching competencies and capabilities to the asset management system including the plan for both internal and contracted activities. Plans are reviewed integral to asset management system process(es). Competency requirements are in place and aligned with asset management plan(s). Plans are in place and effective in providing the training necessary to achieve the competencies. A structured means of recording the competencies achieved is in place. Competency requirements are identified and assessed for all persons carrying out asset management related activities - internal and contracted. Requirements are reviewed and staff reassessed at appropriate intervals aligned to asset management requirements. Two way communication is in place between all relevant parties, ensuring that information is effectively communicated to match the requirements of asset management strategy, plan(s) and process(es). Pertinent asset information requirements are regularly reviewed. The organisation has established documentation that comprehensively describes all the main elements of its asset management system and the interactions between them. The documentation is kept up to date. 63 Information management 3 64 Information management How does the organisation maintain its asset management information system(s) and ensure that the data held within it (them) is of the requisite quality and accuracy and is consistent? How has the organisation's ensured its asset management information system is relevant to its needs? 69 Risk management process(es) 3 79 Use and maintenance of asset risk information Legal and other requirements How has the organisation documented process(es) and/or procedure(s) for the identification and assessment of asset and asset management related risks throughout the asset life cycle? How does the organisation ensure that the results of risk assessments provide input into the identification of adequate resources and training and competency needs? What procedure does the organisation have to identify and provide access to its legal, regulatory, statutory and other asset management requirements, and how is requirements incorporated into the asset management system? How does the organisation establish implement and maintain process(es) for the implementation of its asset management plan(s) and control of activities across the creation, acquisition or enhancement of assets. This includes design, modification, procurement, construction and commissioning activities? How does the organisation ensure that process(es) and/or procedure(s) for the implementation of asset management plan(s) and control of activities during maintenance (and inspection) of assets are sufficient to ensure activities are carried out under specified conditions, are consistent with asset management strategy and control cost, risk and performance? How does the organisation measure the performance and condition of its assets? 3 How does the organisation ensure responsibility and the authority for the handling, investigation and mitigation of asset-related failures, incidents and emergency situations and non conformances is clear, unambiguous, understood and communicated? 3 What has the organisation done to establish procedure(s) for the audit of its asset management system (process(es))? 3 48 49 50 53 59 62 82 88 Life Cycle Activities 91 Life Cycle Activities 95 Performance and condition monitoring Investigation of asset-related failures, incidents and nonconformities Audit 99 105 (Note this is about resources and enabling support) What plan(s) and procedure(s) does the organisation have for identifying and responding to incidents and emergency situations and ensuring continuity of critical asset management activities? What has the organisation done to appoint member(s) of its management team to be responsible for ensuring that the organisation's assets deliver the requirements of the asset management strategy, objectives and plan(s)? What evidence can the organisation's top management provide to demonstrate that sufficient resources are available for asset management? 3 3 3 3 3 3 3 3 3 3 2 3 3 Appropriate emergency plan(s) and procedure(s) are in place to respond to credible incidents and manage continuity of critical asset management activities consistent with policies and asset management objectives. Training and external agency alignment is in place. The appointed person or persons have full responsibility for ensuring that the organisation's assets deliver the requirements of the asset management strategy, objectives and plan(s). They have been given the necessary authority to achieve this. An effective process exists for determining the resources needed for asset management and sufficient resources are available. It can be demonstrated that resources are matched to asset management requirements. The organisation has determined what its asset information system should contain in order to support its asset management system. The requirements relate to the whole life cycle and cover information originating from both internal and external sources. The organisation has effective controls in place that ensure the data held is of the requisite quality and accuracy and is consistent. The controls are regularly reviewed and improved where necessary. The organisation has developed and is implementing a process to ensure its asset management information system is relevant to its needs. Gaps between what the information system provides and the organisations needs have been identified and action is being taken to close them. Identification and assessment of asset related risk across the asset lifecycle is fully documented. The organisation can demonstrate that appropriate documented mechanisms are integrated across life cycle phases and are being consistently applied. Outputs from risk assessments are consistently and systematically used as inputs to develop resources, training and competency requirements. Examples and evidence is available. Evidence exists to demonstrate that the organisation's legal, regulatory, statutory and other asset management requirements are identified and kept up to date. Systematic mechanisms for identifying relevant legal and statutory requirements. Effective process(es) and procedure(s) are in place to manage and control the implementation of asset management plan(s) during activities related to asset creation including design, modification, procurement, construction and commissioning. The organisation is in the process of putting in place process(es) and procedure(s) to manage and control the implementation of asset management plan(s) during this life cycle phase. They include a process for confirming the process(es)/procedure(s) are effective and if necessary carrying out modifications. 2 The organisation is developing coherent asset performance monitoring linked to asset management objectives. Reactive and proactive measures are in place. Use is being made of leading indicators and analysis. Gaps and inconsistencies remain. The organisation have defined the appropriate responsibilities and authorities and evidence is available to show that these are applied across the business and kept up to date. Corrective & How does the organisation instigate appropriate corrective and/or preventive actions to Preventative action eliminate or prevent the causes of identified poor performance and non conformance? 3 113 Continual Improvement 2 115 Continual Improvement Asset management plan Asset management plan(s) are established, documented, implemented and maintained for asset systems and critical assets to achieve the asset management strategy and asset management objectives across all life cycle phases. The plan(s) are communicated to all relevant employees, stakeholders and contracted service providers to a level of detail appropriate to their participation or business interests in the delivery of the plan(s) and there is confirmation that they are being used effectively. Asset management plan(s) consistently document responsibilities for the delivery actions and there is adequate detail to enable delivery of actions. Designated responsibility and authority for achievement of asset plan actions is appropriate. The organisation has arrangements in place for the implementation of asset management plan(s) but the arrangements are not yet adequately efficient and/or effective. The organisation is working to resolve existing weaknesses. 2 109 How does the organisation achieve continual improvement in the optimal combination of costs, asset related risks and the performance and condition of assets and asset systems across the whole life cycle? How does the organisation seek and acquire knowledge about new asset management related technology and practices, and evaluate their potential benefit to the organisation? All linkages are in place and evidence is available to demonstrate that, where appropriate, the organisation's asset management strategy is consistent with its other organisational policies and strategies. The organisation has also identified and considered the requirements of relevant stakeholders. The asset management strategy takes account of the lifecycle of all of its assets, asset types and asset systems. 3 The organisation can demonstrate that its audit procedure(s) cover all the appropriate asset-related activities and the associated reporting of audit results. Audits are to an appropriate level of detail and consistently managed. Mechanisms are consistently in place and effective for the systematic instigation of preventive and corrective actions to address root causes of non compliance or incidents identified by investigations, compliance evaluation or audit. Continuous improvement process(es) are set out and include consideration of cost risk, performance and condition for assets managed across the whole life cycle but it is not yet being systematically applied. The organisation actively engages internally and externally with other asset management practitioners, professional bodies and relevant conferences. Actively investigates and evaluates new practices and evolves its asset management activities using appropriate developments. Page 192 of 193 APPENDIX - APPROVAL BY GOVERNING COMMITTEE K. Appendix - Approval by Governing Committee Certification for Year-beginning Disclosures We, Terry Michael Shagin and, Kenneth John Forrest being Directors of companies which are parties to the OtagoNet Joint Venture certify that, having made all reasonable enquiry, to the best of our knowledgea) The following attached information of OtagoNet Joint Venture prepared for the purposes of clause 2.6.1 and subclauses 2.6.3(4) and 2.6.5(3) of the Electricity Distribution Information Disclosure Determination 2012 in all material respects complies with that determination. b) The prospective financial or non-financial information included in the attached information has been measured on a basis consistent with regulatory requirements or recognised industry standards. ____________________ T M Shagin ____________________ K J Forrest Date: 31 March 2014 Asset management plan Page 193 of 193
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