asset management plan update 2015 - 2025 · now manages all three electricity networks. effective...

Asset Management Plan

Update

2015 - 2025

Publicly disclosed on 31st March 2015

SUMMARY & CONTENTS

Update Overview

The Asset Management Plan update 2015-25 for OtagoNet Joint Venture (OJV) is presented as the sections shown overleaf under “Contents”, which have been updated from OJV’s Asset Management Plan 2014-24. The headings shown in the contents retain the same numbering as the previous AMP for convenient referencing. The superscripts to the headings are references to the corresponding paragraph in the Electricity Distribution Information Disclosure Determination 2012, Attachment A.

Updates are highlighted by a blue shaded background to indicate where project implementation timeframes have varied from those indicated in the previous AMP, where new projects have been added to the capital or maintenance programmes or where projects have been completed and therefore do not form part of the updated work plan for future years.

The two Southland joint venture parties to OJV, The Power Company Limited (TPCL) and Electricity Invercargill Limited (EIL), increased their combined ownership in OJV on 30 September 2014 to 100% following the purchase of Marlborough Lines Limited’s 51% interest. TPCL and EIL own PowerNet Limited, an electricity network and field services management company which now manages all three electricity networks.

Effective from 1 April 2015 PowerNet’s management of the OJV network is being carried out in a manner consistent with the agency arrangements in place for EIL and TPCL. As a result OJV capital expenditure will increase slightly with project management and other associated costs now being capitalised or expensed to maintenance projects. Operating expenditure previously in the form of a management fee will reduce by a corresponding amount.

EIL and TPCL are also the owners of Electricity Southland Limited (ESL), which owns a small exempt electricity network, located at Frankton (Lakeland network). This network is located within the Aurora Energy Limited supply area and takes direct supply from Transpower’s Frankton grid exit point. ESL has not historically been a supplier of electricity lines services, as it has not met the size criteria under Section 54C(2) of the Commerce Act.

The identical ownership interest of OJV and ESL creates a requirement for the Lakeland network assets to be incorporated into OJV for regulatory reporting. Consequently the Section 54C(2) exemption no longer applies and Part 4 of the Commerce Act will apply. The Lakeland network is non-contiguous and due to its size falls under the threshold that triggers additional subnetwork disclosures.

Over the five years to 31 March 2015, OJV has had difficulty achieving its capital expenditure targets – due largely to difficulties in resourcing at the Project Manager level, together with disruptions caused by changes of engineering management provider and network ownership. These three issues are now resolved; but their effect on recent capital spending has nevertheless caused the Commerce Commission to reduce the level of planned capital expenditure used to calculate OJV’s prices for the 1 April 2015 price reset. This produces financial constraints which have led to OJV’s decision to delay significant parts of its reliability and renewal investment beyond what OJV would normally consider appropriate for its network.

SUMMARY & CONTENTS

Contents 7.8 DEVELOPMENT PROGRAMME

[A11.9, 11.10] ............................................................................................... 3

7.8.1 CURRENT PROJECTS[A11.10.1&2]

........................................................................................................... 3 7.8.2 CONSIDERED PROJECTS

[A11.10.3] ....................................................................................................... 17

7.8.3 CONTINGENT PROJECTS .................................................................................................................. 18 7.8.4 NETWORK DEVELOPMENT CAPITAL FORECAST ................................................................................. 18 7.9 NON-NETWORK DEVELOPMENT

[A13.1-4] .............................................................................................. 20

7.9.1 MOBILE GENERATION ...................................................................................................................... 20 8.3.2 MAINTENANCE BUDGET

[A12.2.3] .......................................................................................................... 21

8.4.1 CURRENT RENEWAL PROJECTS[A12.3.3&4]

........................................................................................... 24 8.4.2 PLANNED RENEWAL PROJECTS

[A12.3.5] .............................................................................................. 28

8.7 CONVERTING OVERHEAD TO UNDERGROUND .................................................................................... 29 D. APPENDIX – SCHEDULE 11A ............................................................................................................. 30 E. APPENDIX – SCHEDULE 11B ............................................................................................................. 34 F. APPENDIX – SCHEDULE 12A ............................................................................................................. 35 G. APPENDIX – SCHEDULE 12B ............................................................................................................. 37 H. APPENDIX – SCHEDULE 12C ............................................................................................................ 38 I. APPENDIX – SCHEDULE 12D ............................................................................................................ 39 J. APPENDIX – SCHEDULE 13 ............................................................................................................... 40 K. APPROVAL BY BOARD OF DIRECTORS ............................................................................................... 42

Enquiries Enquiries, submissions or comments about this Asset Management Plan (AMP) can be directed to:

Chief Engineer

PowerNet Limited

PO Box 1642

Invercargill 9840

Phone (03) 211 1899

Fax (03) 211 1880

Email [email protected]

Liability disclaimer The information and statements made in this AMP are prepared on assumptions, projections and forecasts made by OtagoNet Joint Venture (OtagoNet) and represent the company’s intentions and opinions at the date of issue (31 March 2015). 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.

mailto:[email protected]

DEVELOPMENT PLANS

ASSET MANAGEMENT PLAN PAGE 3

7.8 Development Programme[A11.9, 11.10]

7.8.1 Current Projects[A11.10.1&2]

7.8.1.1 Milton (Elderlee St) 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 Milburn and Glenore substations.

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.

DEVELOPMENT PLANS


7.8.1.2 Milton 33 kV Ring Protection Upgrade


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 teed 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.

No non-asset solutions available.


The enhanced protection system will yield the full reliability potential from the line assets employed which alternative options will not.


$250k for the whole project; Asset Replacement and Renewal, Reliability Improvement


Improve reliability to 33 kV line faults. Complete the project by 2016.

The intent at time of writing the 2014-24 AMP was for the owners of the industrial land referred to in Section 7.8.1.1.1 to subdivide off an appropriate area of land and sell it to OJV. The owners of the land at that time have since gone into liquidation, which delayed the purchase of the land. The land has however now been procured.

This project has been delayed in order to work within Commerce-Commission-imposed financial constraints – construction is now planned to take place over 2018/19/20.


DEVELOPMENT PLANS


7.8.1.3 Waitati Zone Sub Relocation


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 back-feeds 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.


Redeveloping on a new site is the best strategic solution with the lowest future risk.


$1.3m; Asset Renewal; Reliability Improvement


Improve reliability to 33kV line faults in the Waitati area. Complete the project by 2016.

7.8.1.4 Merton Substation (Waikouaiti)


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.

This project requires the purchase of a new substation site outside Waitati, and the landowners of the shortlisted sites showed only cautious interest in selling. As a result, construction-related expenditure was delayed while an alternative site was procured.

Detailed design for the first stage of the project is underway, resulting in a revised whole-of-life project cost forecast of $1.7M. This increase reflects the use of consultants rather than in-house resource to manage the first phase of the project, and the incorporation of aesthetic measures to disguise the substation frontage.

The project is being carried out in two stages:

(1) Construction of 33 kV bus and switchgear to allow redundant 33 kV supply into Waitaiti area; forecast completion 2015/16.

(2) Construction of remainder of substation; forecast completion 2020/21.

DEVELOPMENT PLANS


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 back-feeds available for loss of the single 33kV supply.

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 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



Redeveloping on a new site is the best strategic solution with the lowest future risk.


$1.95m; Asset Replacement and Renewal; Reliability Improvement.


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


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.


DEVELOPMENT PLANS


7.8.1.5.3 Options

Redevelop 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.

No non-asset solutions.


Rebuild on new site.


$400k (Transformer already purchased), Asset Replacement and Renewal; Growth.


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


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 KFE 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 back-feeds 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.



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.

No material change.

DEVELOPMENT PLANS



$1.0 m; Growth and Asset Renewal.


Cater for future load growth in the region. Complete the project by 2016.

7.8.1.7 Clydevale Ring


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.

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.



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.


$250k; Asset replacement; Reliability Improvement.


Complete by 2016.

Installation is proceeding according to plan. The 2014-24 AMP forecast that the new transformer would be paid for in the 2014/15 financial year. While the deposit on this transformer has been paid, the balance will come due in the 2015/16 financial year.

DEVELOPMENT PLANS


7.8.1.8 Transpower Palmerston – 33 kV Conversion


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 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.

Do nothing and accept worsening SAIDI and SAIFI figures and increasingly unhappy customers.



Convert the 110 kV lines to 33 kV in two stages.

This project has been delayed in order to work within Commerce-Commission-imposed financial constraints – construction is now planned to take place over 2021/22.

Project budget revised to take account of the requirement for a more sophisticated tee for the dairy factory than originally anticipated.

DEVELOPMENT PLANS



$1.0m spread over 5 years; Reliability, Safety and Environmental.


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


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.


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.

OtagoNet has prepared the Palmerston end of the first 110 kV line for conversion to 33 kV. Transpower have scheduled to complete the corresponding work at the Halfway Bush end before 31 Mar 2015.

The bulk of the work for the second 33 kV conversion will be carried out by Transpower, during and after Transpower’s Halfway Bush Indoor Conversion project. The timing of the second 33 kV conversion is therefore heavily dependent upon Transpower; it will be included in the budget once timing is more clearly known. Approximate CAPEX impact will be $300k.

DEVELOPMENT PLANS



$900k; Asset replacement and renewal; Security and Reliability.


Complete the project by 2017 in conjunction with the Palmerston 33 kV supply reconfiguration.

7.8.1.10 Palmerston Area Ripple Injection Plant


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 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.



The preferred option has not been identified. Provision of expenditure in 2017 is to coincide with the substation relocation works.


$500k; Asset replacement and renewal; Consequential works with 33kV reconfiguration projects.


Complete the investigations and recommendation for the project by 31 March 2015 with installation and commissioning completed by 2017.


DEVELOPMENT PLANS


7.8.1.11 Puketoi + Interim Voltage Regulators


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.

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.



Place new voltage regulators to support the confirmed new load as an interim measure. Make provision of a new substation at Puketoi.


$1.75 m; Growth.


Install voltage regulators in 2014 and 2015 as interim measure. Provisional expenditure set for FY2018 and FY2019 for new zone substations.

The future Waikouaiti substation (Section 7.8.1.4) has been identified as the optimal location for a new ripple injection plant. The budget for this project has therefore been incorporated into the Waikouaiti budget.

Alternatives to ripple injection continue to be investigated.

Demand is increasing quickly in the area, to the extent that it is considered prudent to bring forward the construction of the replacement substation. Land for the substation is currently being finalised and work will now commence in the 2015/16 year. A 1 MVA temporary substation has been installed in order to maintain voltage quality in the meantime.

DEVELOPMENT PLANS


7.8.1.12 11 kV Reclosers and SCADA Automation


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.



Install reclosers where they are economically viable including SCADA modifications.


$2.5m over 5 years but dependent on business cases. Reliability Improvement.


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.

This project has been merged with the Network Automation project (Section 7.8.2.2), expanding the scope to include opportunities for SCADA-controlled isolation and backfeed of sections of line “downstream” of a fault.

Also merged into this project is the replacement of SWER reclosers described in Section 8.4.1.1.4.

At time of writing the review of economic locations is not yet complete. Commerce-Commission-imposed financial constraints limit planned expenditure to $1.5M over the next five years. In later years additional expenditure may be allocated from the “Unspecified Quality of Supply Projects” budget, according to the results of the review.

DEVELOPMENT PLANS


7.8.1.14 Subtransmission Line Upgrades

No subtransmission line upgrades are currently planned in the next 5 years.

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.

Land purchases continue to be carried out for safety, clearance augmentation, and new or relocated substations. Fencing of existing sites for improved safety has now also been included in this budget line.

An additional $1.25M over the next three years has been added to the budget to reflect the extra land purchases and additional safety work.

The Milton 33/66 kV line (Balclutha end and Glenore to Kiness) is undergoing upgrade due to load growth. Cost $750k spread over two years. The majority of the work is being completed in the 2014/15 financial year.

The Clydevale – Popotunoa upgrade has proceeded according to plan. The Hall Rd upgrades have progressed more slowly and will be carried over into the 2015/16 financial year; a more detailed assessment of the requirements for the Hall Rd – Camp Hill Rd section has resulted in a budget revision to $520k. An upgrade of Kyeburn feeder from Waitati to Kokonga due to load growth is also planned. The first 4km of this work is planned for FY 2015/16 at a cost of $230k.

Budget has been increased to $173k p.a. to more accurately reflect recent levels of expenditure on this work.

DEVELOPMENT PLANS


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. Requests 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.

No material change.

New current project: NER Installation at Substations

Description

As part of compliance with the new EEA Guide to Power System Earthing Practice 2009, Neutral Earthing Resistors (NERs) are being installed at each zone substation to limit earth fault currents on the 11kV network. While NERs alone will not ensure network safety they significantly reduce the earth potential rise appearing on and around network equipment when an earth fault occurs.

Issues

The new EEA Guide sets a higher standard for distribution earthing than was previously applicable. OJV considers that the cost of building/upgrading individual earth sites in compliance with the Guide, can be significantly reduced by the relatively low-cost installation of an NER at the upstream substation.

Options

Do nothing and accept the higher overall cost of building distribution earths compliant with the EEA Guide.

Install Petersen Coils and carry out the necessary network upgrades to allow sustained operation with p-g voltage at p-p levels.

Install NERs.


Option Selection

The NER installation is considered to provide the best cost-benefit ratio.

Cost and Type

$800k; Safety.

Goal/Strategy

Staged implementation in all zone substations over four years 2015/19.

DEVELOPMENT PLANS


New current project: Gimmerburn Substation and Lines

Description

Construction of a new Gimmerburn substation midway between the existing Ranfurly and the planned Puketoi substations.

Issues

Load continues to develop in the Maniototo region due to irrigation and dairy conversion, to the extent that the Ranfurly and planned Puketoi substations will not be sufficient to supply the regional load over the long term. The location and size of the new load makes it inefficient to support at 11kV from these substations.

The Gimmerburn area is centred further west of the existing subtransmission lines than the Puketoi area, with no existing easement or line route to the nearby subtransmission line, and much of the existing distribution network in the area is light and/or SWER conductor that will need redesign/reinforcement. The Gimmerburn substation will therefore require substantially more expenditure than Puketoi.

Options

Support the load from the existing substations (but the networks’ capacity to achieve this is limited).

Develop a new zone substation at or near Gimmerburn off the 66 or 33 kV lines.


Option Selection

Construct a new substation at or near Gimmerburn.

Cost and Type

$2.84M; System Growth

Goal/Strategy

Provisional expenditure set for 2018/19/20 for a new zone substation.

New current project: Surge Arrestor Replacement due Transpower NER

Description

Replace surge arrestors at subtransmission voltage where the presence of a Neutral Earth Resistor (NER) at the upstream Grid Exit Point (GXP) could cause inappropriate surge arrestor operation.

Issues

Many existing subtransmission-voltage surge arrestors are chosen to operate at less than the line-to-line voltage of the circuit. This selection of rating maximises the extent to which lightning surges are “clipped”, thus minimising voltage stress on the protected equipment.

However Transpower are installing 33 kV NERs at the Balclutha GXP. The presence of an NER means that downstream surge arrestors can be legitimately held at line-to-line voltage for the maximum fault clearing time of the GXP feeder protection system.

Each surge arrestor at risk of inappropriate operation must therefore be replaced with a new unit with a higher rating.

DEVELOPMENT PLANS


7.8.2 Considered Projects[A11.10.3]

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 33 kV 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.

Options

Accept occasional inappropriate surge arrestor operation

Replace surge arrestors


Option Selection

Replace at-risk subtransmission surge arrestors with models having a rating appropriate for an upstream NER.

Cost and Type

$460k; Reliability.

Goal/Strategy

Staged implementation over two years 2015/16/17.

New current project: Frankton Network Development

Description

Expansion of the Frankton area network to supply new residential subdivisions, commercial developments, apartment complexes, and hotels.

Issues

Rapid expansion in the Frankton area requires a corresponding expansion of the area’s distribution network. Particular developments underway at present include the Shotover Country residential subdivision, continued commercial development in Remarkables Park Ltd, and light industrial development in Shotover Park.

Options

Expand distribution network in Frankton


Option Selection

Expand distribution network in Frankton

Cost, Type, and Strategy

$1.7M in 2015/16, with investment gradually easing to a long term average of $1.225M per annum. System Growth.

DEVELOPMENT PLANS


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.

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 in the Capital Budget in Figure 1.

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.

No material change.

This project has been merged with the “11 kV Reclosers and SCADA Automation” project described in Section 7.8.1.12.

DEVELOPMENT PLANS


CAPEX: Consumer Connection 2015/16 2016/17 2017/18 2018/19 2019/20 2020/21 2021/22 2022/23 2023/24 2024/25

Customer Connections (≤ 20kVA) 257 249 236 257 249 267 267 257 267 267

Customer Connections (21 to 99kVA) 467 472 472 472 472 472 472 472 472 472

Customer Connections (≥ 100kVA ) 564 564 564 564 564 564 564 564 564 564

1,288 1,286 1,273 1,293 1,286 1,304 1,304 1,293 1,304 1,304

CAPEX: System Growth 2015/16 2016/17 2017/18 2018/19 2019/20 2020/21 2021/22 2022/23 2023/24 2024/25

Clydevale - Hall Road Line Upgrade 173

Clydevale transformer upgrade and new switchgear 1,020 57

New Puketoi Substation and lines 228 1,476

New Gimmerburn Substation and lines

568 2,273

Clydevale - Hall Rd to Camp Hill Rd 520

Chrystalls Beach SWER line upgrade to 3 phase

231 231

Waipiata - Kyeburn 11 kV Feeder Upgrade 231

Balclutha - Milton 33/66 kV line rebuild 289

RPL Village Network 255 255 408 664 919 919 511 919 919 919

Shotover Park 391

408

408

Shotover Country 919 919 511

General ESL MV Network Growth 128 128 332 306 306 306 306 306 306 306

Easements 12 12 12 12 12 12 12 12 12 12

Unspecified System Growth Projects

1,271 1,271 1,271 1,271 1,271

4,165 3,077 1,493 1,958 3,510 2,508 2,508 2,508 2,508 2,508

CAPEX: Asset Replacement and Renewal 2015/16 2016/17 2017/18 2018/19 2019/20 2020/21 2021/22 2022/23 2023/24 2024/25

LV Line Replacement and Renewal 202 506 758 758 758 758 758 758 758 758

SWER Line Replacement and Renewal 404 506 506 506 506 506 506 506 506 506

11 kV Line Replacement and Renewal 2,123 2,528 3,033 3,033 3,033 3,033 3,033 3,033 3,033 3,033

33 kV Line Replacement and Renewal 1,502 1,517 2,022 2,022 2,022 2,022 2,022 2,022 2,022 2,022

Merton Substation replacement 58 35 35 1,135 1,135 114

Milton Substation replacement 58 35 35 1,554 908 137

Waitati Tee and future substation 172

907 568

Palmerston Substation Rebuild Taieri Peak Rd

342 794

Substation minor capital work 29 29

Substation structure seismic upgrades 58 58 347 347 347

MV Cable Renewals 18

Unspecified Replacement and Renewal Projects

795 1,592 1,592 1,592

4,625 5,212 6,736 9,355 9,616 7,480 7,909 7,912 7,912 7,912

CAPEX: Asset Relocations 2015/16 2016/17 2017/18 2018/19 2019/20 2020/21 2021/22 2022/23 2023/24 2024/25

Balclutha Main Street Undergrounding 636

Milton Main Street Undergrounding 173 173 173

Network Chargeable 116 116 116 116 116 116 116 116 116 116

TX 2589 Clutha Leader relocation and Underground 58

TX 2590 John Street Lines to Underground 58

TX 2591 Telecom transformer lines to move 58

Unspecified Asset Relocation Projects

231 231 231 231 231

1,098 289 289 116 116 347 347 347 347 347

CAPEX: Quality of Supply 2015/16 2016/17 2017/18 2018/19 2019/20 2020/21 2021/22 2022/23 2023/24 2024/25

Reclosers with SCADA integration 231 231 347 347 347

Misc Quality of Supply Upgrades 173 173 173 173 173 173 173 173 173 173

Unspecified Quality of Supply Projects

231 231 231 231 231

404 404 520 520 520 404 404 404 404 404

CAPEX: Legislative and Regulatory 2015/16 2016/17 2017/18 2018/19 2019/20 2020/21 2021/22 2022/23 2023/24 2024/25

CAPEX: Other Reliability, Safety and Environment 2015/16 2016/17 2017/18 2018/19 2019/20 2020/21 2021/22 2022/23 2023/24 2024/25

Palmerston 110 kV conversion to 33 kV 172

Substation NER installation x 32 substations 171 285 171 171

Milton 33kV ring protection upgrade

227 114

Glenore substation rebuild 400

Clydevale 33 kV ring rebuild and protection

114 341

Owaka 11 kV switchgear replacement

340 340

Port Molyneux 11 kV switchgear replacement

397 284

Replacement of OH structures with Ground Mounted 58 173 173 173 173 173 173 173 173 173

Earth refurbishment from earth testing, incl. SWER 173 173 173 173 173 173 173 173 173 173

Substation clearances and fence improvements 231 404 636

Surge Arrestor replacement due Transpower NER 231 231

Unspecified Reliability/Safety/Environment Projects

693 693 693

1,436 1,267 1,153 518 347 1,028 1,538 1,324 1,040 1,040

Total Capital Projects 13,016 11,536 11,464 13,760 15,395 13,071 14,010 13,788 13,515 13,515

Figure 1 – Network Capital Budget ($000)

DEVELOPMENT PLANS


7.9 Non-Network Development[A13.1-4]

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 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 step-up/earthing transformer is planned to be used in conjunction with leased generators for large zone substation outages.

Cost $350k in FY2015; Reliability Improvement.

The mobile generation project has been placed on hold. At current usage levels, rental generators are a more cost-effective means of managing 33 kV outages. Planned outages at 11 kV are managed with a combination of load switching and generator sets on a project by project basis.

ASSET LIFECYCLE


8.3.2 Maintenance Budget[A12.2.3]

The life cycle maintenance budget for the next 10 years is set out in the Operational budget in Figure 2.

OPEX: Asset Replacement and Renewal 2015/16 2016/17 2017/18 2018/19 2019/20 2020/21 2021/22 2022/23 2023/24 2024/25

Customer Connections Maintenance 6 6 6 6 6 6 6 6 6 6

33 kV Pole Maintenance 54 54 54 54 54 54 54 54 54 54

Network Chargeable Maintenance 32 32 32 32 32 32 32 32 32 32

Maintenance Identified on Distribution Line Survey 540 324 324 324 324 324 324 324 324 324

Transformer Refurbishment 27 65 65 65 65 65 65 65 65 65

660 482 482 482 482 482 482 482 482 482

OPEX: Vegetation Management 2015/16 2016/17 2017/18 2018/19 2019/20 2020/21 2021/22 2022/23 2023/24 2024/25

Vegetation Management 972 972 972 972 972 972 972 972 972 972

972 972 972 972 972 972 972 972 972 972

OPEX: Routine and Corrective Maintenance and Inspection 2015/16 2016/17 2017/18 2018/19 2019/20 2020/21 2021/22 2022/23 2023/24 2024/25

Voltage Complaint Investigation 16 16 16 16 16 16 16 16 16 16

Transmission Line Minor Maintenance 13 13 13 13 13 13 13 13 13 13

Line Condition Survey 432 540 540 540 540 540 540 540 540 540

Earth Testing and Review 108 216 216 216 216 216 216 216 216 216

Load Control Equipment 6 6 6 6 6 6 6 6 6 6

Radio Equipment 32 32 32 32 32 32 32 32 32 32

SCADA Equipment 1 1 1 1 1 1 1 1 1 1

Routine ESL Dist Insp Check & Mtce 2 2 2 2 2 5 5 5 5 5

MV Equipment Checks & Maint. 21 25 25 34 38 49 60 70 81 91

632 853 853 861 866 879 890 901 911 922

OPEX: Service Interruptions and Emergencies 2015/16 2016/17 2017/18 2018/19 2019/20 2020/21 2021/22 2022/23 2023/24 2024/25

Distribution Faults 772 775 776 782 786 794 803 811 819 827

Distribution Minor Maintenance 329 329 334 334 345 345 345 345 345 345

Sub Transmission Line Faults 65 65 65 65 65 65 65 65 65 65

Zone Sub Faults 91 96 101 106 111 116 122 127 132 137

Zone Sub Minor Maintenance 355 355 406 355 355 355 355 406 355 355

1,612 1,620 1,682 1,642 1,661 1,675 1,688 1,753 1,715 1,728

Operational Expenditure Total 3,876 3,926 3,988 3,957 3,980 4,008 4,032 4,108 4,080 4,104

System Operations and Network Support 608 621 696 765 834 834 834 834 834 834

Business Support 1,573 1,607 1,786 1,786 1,786 1,786 1,786 1,786 1,786 1,786

AMP Total Operational Expenditure 6,057 6,154 6,470 6,508 6,601 6,629 6,652 6,728 6,700 6,724

Grand Total Capital and Operational Expenditure 19,073 17,690 17,935 20,268 21,996 19,699 20,662 20,516 20,215 20,239

Figure 2 – Operational Budget ($000)

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.

No material change.

ASSET LIFECYCLE


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.

This line item formerly included an annual charge for System Control Services. This charge has now been moved into non-network OPEX, for consistency in reporting with the other PowerNet-managed networks. The line item therefore reverts to $485k p.a. for 2015/16, increasing gradually in successive years as the Frankton network expands.

Annual budget revised to $972k p.a. reflecting recent costs.

The line structure inspection program is undergoing revision and co-alignment with the corresponding PowerNet inspection program. OtagoNet will adopt a more thorough inspection process, carried out on all line structures over a five-year cycle, but will continue an accelerated one-off visual inspection program on core 33 kV and critical 11 kV lines.

The earth testing program continues to be carried out.

Inspection budget revised to $700k p.a. long term.

ASSET LIFECYCLE


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.

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[A12.2.2]

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.

No material change.

Budget revised downward in accordance with recent costs.

Budget revised upward in accordance with recent costs.

ASSET LIFECYCLE


8.4.1 Current Renewal Projects[A12.3.3&4]

Capital renewal programs and projects planned over the next 5 years are set out in the Capital budget in Figure 1 (Section 7.8.4).

8.4.1.1 Life Cycle Renewal Projects

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.

The budget line for this work has been merged with the SWER earth bar joints project described in Section 8.4.1.1.5 and upgrade work arising from the Earth Testing program described in Section 8.3.2.3.2.

New System Operations & Network Support charge: SCADA Integration

A joint project between OJV, EIL and TPCL is underway to bring System Control equipment, systems and procedures in line with current best practice. OJV will bear a share of the implementation costs in the System Control area. Some upgrades to OJV communications equipment and information systems will also be required for compatibility with the new system.

This first stage of this work will be completed in 2016/17 and the entire project is scheduled for completion in 2018/19. The project will be lease charged to OJV.

Cost: $62k 2017/18 rising gradually to $200k p.a. from 2019/20 onward

New Business Support charge: Balclutha Office Structural Strengthening

The Balclutha office and supplier depot have been assessed as being in need of structural strengthening to align with Building Code requirements. This work will be undertaken in 2016/17 and lease charged to OJV.

Cost: $100k p.a. from 2017/18 onward

New Business Support charge: Balclutha Truck Sheds

The current truck sheds at the Balclutha depot are in deteriorating condition and have space for only four large vehicles. The current OPSL vehicle fleet is twelve large vehicles plus six light vehicles and 29 trailers. A new expanded shed building would provide protection for the vehicles as well as sufficient space for an improved workshop and indoor storage of live line gear. This work will be undertaken in 2016/17 and lease charged to OJV.

Cost: $50k p.a. from 2017/18 onward

ASSET LIFECYCLE


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 planned for completion over the next five years. More detailed engineering work is required to prioritise and plan the remedial work noting that:

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.



The project budget has been revised to $600k based on a recent similar project, reflecting latest market rates for equipment, design, and installation.


The project budget has been revised to $600k based on a recent similar project, reflecting latest market rates for equipment, design, and installation.

This project has been delayed in order to work within Commerce-Commission-imposed financial constraints – construction is now planned to take place over 2017-2020.

PowerNet experience with seismic upgrades on other networks has led to a revised budget estimation of approx. $1 million.

ASSET LIFECYCLE


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 re-building as opposed to individual pole replacements.


8.4.1.1.7 Ranfurly-Deepdell 33 kV Line Rebuild

This section of line has been identified from condition inspection to warrant line re-building 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

No material change.

The budget line for this work has been merged with the “11 kV Reclosers and SCADA Automation” project described in Section 7.8.1.12.

The budget line for this work has been merged with the SWER Transformer Earth Upgrade project described in Section 8.3.2.4 and upgrade work arising from the Earth Testing program described in Section 8.3.2.3.2.

This project has been spread out over a more extended timeframe in order to work within Commerce-Commission-imposed financial constraints. The complexity of the work involved has also been reduced after reassessment against the appropriate standards. Budget adjusted to $230k in FY2015/16 and $344k p.a. thereafter.

ASSET LIFECYCLE


dependent on customer requirements, land access permission and priority re-assignment as further network condition information becomes available.

General:

Distribution Minor Capital Work 180,000

Network Chargeable Capital 60,000

Replacement of O/H structures with Ground Subs 80,000

Pole or conductor replacements on minor spur lines 200,000

Balclutha:

Clifton-Old Lake 33kV pole replacement 400,000

Milton 33 kV line completion 800,000

Finegand - Owaka 33 kV conductor replacement 600,000

Hunt Road 11 kV line rebuild on road side 600,000

Summerhill Rd Wangaloa 270,000

Clutha leader - TX 2586 replacement on ground 116,000

Tuapeka Mouth 11 kV Line rebuild on road 120,000

Chrystalls Beach E/R Lines 321,600

Mill View Rd Tuapeka West 41,200

Farquhar Rd SWER Owaka Valley. 213,500

Puketi E/R - Stage 2 451,500

Glenomaru Valley Rd Spur Lines 188,000

Estate Rd, Clinton 40,000

Silverpeaks 22 kV 135,000

Titri Rd, Waihola 266,000

Fella Burn Road 11kV Project 39,500

Puerua SWER: Part A 306,000

North Foreland Street, Waihola. Replace overloaded 200kVA at TX Site 22108

58,000

SH-8 Beaumont - Raes Junction 67,500

Shannon - Matarae 22kV ER (Clarks 22kV) 216,000

Palmerston:

Palmerston - Deepdell 33kV pole replacements 250,000

Deepdell - Middlemarch 33kV Refurbishment 300,000

Kilmog 11 kV feeder stage 2 300,000

Horse Range E/R - Part 1 80,500

Bushey Park Road 53,000

Dunback Footbridge 16,000

Sweetwater Creek 32,000

Puketapu Road 64,000

Hughes Rd Palmerston 54,000

Ranfurly:

McHardy Rd, Sutton 265,000

Ngapuna - SH87 spurs 171,000

Three O'Clock - Mt Stoker 208,000

Ranfurly Spur Lines 45,500

Ida Valley Station 157,500

ASSET LIFECYCLE


8.4.2 Planned Renewal Projects[A12.3.5]

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% replacement probability at 70 years age. This indicates approximately 240 pole replacements per annum when applied against the age profile.

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.

OtagoNet has reprioritised its line rebuild planning to factor in ICP count and risk as well as condition. The Clifton-Clydevale and Ranfurly-Deepdell line rebuilds specified in the 2014 AMP have therefore been deferred.

OJV has curtailed its short-term line rebuild program in order to work within Commerce-Commission-imposed financial constraints – budgeted expenditure is $4.2M for the coming year, rising gradually to the desired target of $6.25M by the 2018 financial year.

Line replacements will continue at approximately $5M p.a. rising to $6M p.a. by 2018/19.

ASSET LIFECYCLE


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 60,000

Balclutha Main Street LV underground 400,000

Milton Main Street LV undergrounding 300,000

John Street - TX 2590 OH lines to underground 40,000

Telecom - TX 2591 OH lines to Underground 80,000

No material change.

Milton Main Street LV Undergrounding program has been delayed slightly while land ownership issues are resolved. The Balclutha Main Street LV undergrounding program has also been delayed and will now start in the 2015/16 year. John St and Telecom undergrounding projects are nearly complete and forecast for completion in FY2015/16. Market rates for underground conversions have led to a significant increase in the budget for these projects.

Over the long term, a budget of $229k p.a. has been allocated for similar works.

EDDID SCHEDULES


D. Appendix – Schedule 11a

EDDID SCHEDULES


EDDID SCHEDULES


E. Appendix – Schedule 11b

EDDID SCHEDULES


F. Appendix – Schedule 12a

EDDID SCHEDULES


EDDID SCHEDULES


G. Appendix – Schedule 12b

EDDID SCHEDULES


H. Appendix – Schedule 12c

Note: A recent metering point shift brought the metering point for OJV’s largest industrial customer (responsible for approximately one third of OJV’s electricity volume) close to the GXP, thus removing most of the losses involved in providing their power. This artificially reduces the loss ratio calculated below, by spreading the losses incurred in the rest of the network over 1.5x the electricity volume consumed by the rest of the network.

EDDID SCHEDULES


I. Appendix – Schedule 12d

Note: Forecasts from Current Year (CY) +1 onward incorporate the new 50% weighting on Class B SAIDI & SAIFI. Class C SAIDI and SAIFI for the current year is currently trending uncharacteristically high compared with recent years. These two factors lead to a marked step-change between the CY forecast and future year forecasts in schedule 12d below.

EDDID SCHEDULES


J. Appendix – Schedule 13 Summary of Asset Management Maturity Assessment Tool:

Q No. Function Question Score Maturity Description

3 Asset management policy

To what extent has an asset management policy been documented, authorised and communicated? 2 The organisation has an asset management policy, which has been authorised by top management, but it has had limited circulation. It may be in use to influence development of strategy and planning but its effect is limited.

10 Asset management strategy

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?

2 Some of the linkages between the long-term asset management strategy and other organisational policies, strategies and stakeholder requirements are defined but the work is fairly well advanced but still incomplete.

11 Asset management strategy

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?

2 The long-term asset management strategy takes account of the lifecycle of some, but not all, of its assets, asset types and asset systems.

26 Asset management plan(s)

How does the organisation establish and document its asset management plan(s) across the life cycle activities of its assets and asset systems?

2 The organisation is in the process of putting in place comprehensive, documented asset management plan(s) that cover all life cycle activities, clearly aligned to asset management objectives and the asset management strategy.


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?

2 The plan(s) are communicated to most of those responsible for delivery but there are weaknesses in identifying relevant parties resulting in incomplete or inappropriate communication. The organisation recognises improvement is needed as is working towards resolution.


How are designated responsibilities for delivery of asset plan actions documented? 3 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.


What has the organisation done to ensure that appropriate arrangements are made available for the efficient and cost effective implementation of the plan(s)? (Note this is about resources and enabling support)

2 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.

33 Contingency planning 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?

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.

37 Structure, authority and responsibilities

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)?

3 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.


What evidence can the organisation's top management provide to demonstrate that sufficient resources are available for asset management?

2 A process exists for determining what resources are required for its asset management activities and in most cases these are available but in some instances resources remain insufficient.


To what degree does the organisation's top management communicate the importance of 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

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?

2 Controls systematically considered but currently only provide for the compliant delivery of some, but not all, aspects of the organisational strategic plan and/or its asset management policy and strategy. Gaps exist.

48 Training, awareness and competence

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)?

2 The organisation has developed a strategic approach to aligning competencies and human resources to the asset management system including the asset management plan but the work is incomplete or has not been consistently implemented.


How does the organisation identify competency requirements and then plan, provide and record the training necessary to achieve the competencies?

2 The organisation is the process of identifying competency requirements aligned to the asset management plan(s) and then plan, provide and record appropriate training. It is incomplete or inconsistently applied.


How does the organization ensure that persons under its direct control undertaking asset management related activities have an appropriate level of competence in terms of education, training or experience?

2 The organization is in the process of putting in place a means for assessing the competence of person(s) involved in asset management activities including contractors. There are gaps and inconsistencies.

53 Communication, participation and consultation

How does the organisation ensure that pertinent asset management information is effectively communicated to and from employees and other stakeholders, including contracted service providers?

3 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.

59 Asset Management System documentation

What documentation has the organisation established to describe the main elements of its asset management system and interactions between them?

2 The organisation in the process of documenting its asset management system and has documentation in place that describes some, but not all, of the main elements of its asset management system and their interaction.

62 Information management

What has the organisation done to determine what its asset management information system(s) should contain in order to support its asset management system?

1 The organisation is aware of the need to determine in a structured manner what its asset information system should contain in order to support its asset management system and is in the process of deciding how to do this.


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?

2 The organisation has developed a controls that will ensure the data held is of the requisite quality and accuracy and is consistent and is in the process of implementing them.


How has the organisation's ensured its asset management information system is relevant to its needs? 2 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.

69 Risk management process(es)

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?

2 The organisation is in the process of documenting the identification and assessment of asset related risk across the asset lifecycle but it is incomplete or there are inconsistencies between approaches and a lack of integration.

79 Use and maintenance of asset risk information

How does the organisation ensure that the results of risk assessments provide input into the identification of adequate resources and training and competency needs?

2 The organisation is in the process ensuring that outputs of risk assessment are included in developing requirements for resources and training. The implementation is incomplete and there are gaps and inconsistencies.

82 Legal and other requirements

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?

2 The organisation has procedure(s) to identify its legal, regulatory, statutory and other asset management requirements, but the information is not kept up to date, inadequate or inconsistently managed.

88 Life Cycle Activities 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?

3 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.

91 Life Cycle 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?

2 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.

95 Performance and condition monitoring

How does the organisation measure the performance and condition of its assets? 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.

99 Investigation of asset-related failures, incidents and nonconformities

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?

2 The organisation is in the process of defining the responsibilities and authorities with evidence. Alternatively there are some gaps or inconsistencies in the identified responsibilities/authorities.

105 Audit What has the organisation done to establish procedure(s) for the audit of its asset management system (process(es))?

2 The organisation is establishing its audit procedure(s) but they do not yet cover all the appropriate asset-related activities.

109 Corrective & Preventative action

How does the organisation instigate appropriate corrective and/or preventive actions to eliminate or prevent the causes of identified poor performance and non conformance?

2 The need is recognized for systematic instigation of preventive and corrective actions to address root causes of non compliance or incidents identified by investigations, compliance evaluation or audit. It is only partially or inconsistently in place.

113 Continual Improvement

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?

1 A Continual Improvement ethos is recognised as beneficial, however it has just been started, and or covers partially the asset drivers.

115 Continual Improvement

How does the organisation seek and acquire knowledge about new asset management related technology and practices, and evaluate their potential benefit to the organisation?

3 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.

EDDID SCHEDULES


AtugoNet DIREcToR CERTI FIcATIoN

K. Approval bv Board of D¡rectors

We, Alan Bertram Harper and Neil Douglas Boniface being directors of companies which areparties to the OtagoNet Joint Venture certify that, having made all reasonable enquiry, to the bestof our knowledge-

a) the following attached information of OtagoNet Joint Venture prepared for the purposes ofclause 2.4.1, clause 2.6.1 and subclauses 2.6.3(4) and 2.6.5(3) of the Electricity Distributionlnformation Disclosure Determination 2012 in all material respects complies with thatdetermination.

b) The prospective financial or non-financial information included in the attached information hasbeen measured on a basis consistent with regulatory requirements or recognised industrystandards.

c) The forecasts in Schedules 1 1a, 11b, 12a, 12b and 12c are based on objective and reasonableassumptions which both align with OtagoNet Joint Venture's corporate vision and strategy andare documented in retained records.

B Harper

rl; ßN D Boniface

Date: 25 March 2015

Asser M¡runcen¡e¡¡r Pm¡¡ Ptce42

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