Annual Planning Report 2013 Complete - Transpower

ANNUAL PLANNING REPORT2013INCORPORATING THE GRID RELIABILITY REPORTAND THE GRID ECONOMIC INVESTMENT REPORTMARCH

ForewordForeword to the Annual Planning Report 2013I am pleased to introduce this eighth Transpower Annual PlanningReport (APR).Transpower is the owner, operator and planner of the National Grid– the high voltage electrical transmission system that stretchesacross both North and South Islands, connecting generationsources to local substations that serve rural and urban customers.The National Grid also facilitates the competitive wholesaleelectricity market.The purpose of the APR is to ensure our transmission planningprocess is open and transparent to all. The APR also includes bothnew build and replacements and how they fit into the work we do to deliver the long-termservice expected from the grid.There are always uncertainties in transmission planning, and forecasting future electricitydemand is a continuing challenge. We’ve recently seen a flattening in demand, aided inpart by new consumer technologies and increasing energy efficiency. This has pushedout the timing of some future upgrades, but we know key regions such as Auckland willcontinue to grow and we will remain reliant on major hydro and geothermal generation formany years. In that context, there is an enduring role for the grid to connect thisrenewable energy to our major load centres.Even with a reduced demand for electricity, where and how electricity is generated willchange. As we’ve seen recently, older uneconomic generation will be retired and newgeneration developed close to where the resource is – be it geothermal, wind, gas orhydro. So the importance of the APR in identifying transmission capacity issues on theinvestment horizon continues.While new build is sometimes unavoidable, we can and must do more to optimise ourinvestment in the existing network. Already, we are applying variable line ratings onselected core transmission lines, and we’re also widely promoting the use of demand-sidemanagement as a means of deferring transmission investment.We continue to look for ways of enhancing the value of the APR to all our stakeholders.We will also make greater use of information from customers to form our views ondemand forecast and generation possibilities to ensure the APR is the primary gridplanning document for the industry.Dr Patrick StrangeChief ExecutiveMarch 20132012 Annual Planning Report © Transpower New Zealand Limited 2012. All rights reserved. i

Executive SummaryExecutive SummaryBackgroundThe 2013 Annual Planning Report (APR) provides information about:the capabilities of the existing National Griddemand and generation forecasts for the next 10 to 15 yearsthe National Grid’s ability to meet future demand and generation needsthe role of the transmission grid in facilitating generationNational Grid investment that may be required to meet future needs for the next10 to 15 years and beyond, by way of:grid backbone transmission plans for the main North and South Islandtransmission corridors, and for the HVDC link, and13 regional plans.The APR also includes all the requirements of the Grid Reliability Report (GRR) andGrid Economic Investment Report (GEIR) as defined under Part 12, of the ElectricityIndustry Participation Code, and 10-year forecast of fault levels at each customerpoint of service under the Benchmark Agreement.This APR represents information available up to 28 February 2013.Purpose of the APRThe role of the APR is to signal proposed and possible transmission investmentswithin a 10 to 15 year horizon, so that market participants have a greater degree ofinformation about Transpower’s plans in order to confirm their own.While the APR is not a regulatory requirement, we appreciate that our operatingenvironment relies on a greater transparency of information about the National Grid,and our plans to operate, maintain and develop it. The APR draws on otherpublications (like the System Security Forecast) to provide a comprehensive 10 to 15year forecast of the issues impacting on the National Grid and our plans and possiblefuture paths for development.The GRR and GEIR are regulatory requirements. We have endeavoured to go wellbeyond the minimum requirements of the GRR to provide greater transparency of ourplanning functions and methods.OverviewThe APR aims to provide our view on future grid development needs andaugmentation options. In order to allow interested parties to fully evaluate the needsand options, the base data and analytical methods are presented for scrutiny andcomment.The APR takes a national and a regional approach to examine, respectively, the gridbackbone and the requirements for each individual region.Energy and peak demand forecastsThis year we have continued to use the approach we developed in 2011 where weuse a top down approach to derive national and regional peak demand forecasts anda bottom up approach to derive individual GXP peak demand forecasts. Ourii2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Executive Summaryapproach builds on the earlier work the Electricity Commission did on demandforecasting.The peak demand forecast represents a prudent forecast that has a probability ofexceedance (POE) of 10% until 2018, and then is assumed to grow at a mean growthrate. 1Continuing the trend from last year, this demand forecast shows significantly lowergrowth. The forecast now shows an average growth rate of 1.5% per annum from2013 to 2028.Generation forecastsWe have developed a new set of generation scenarios for use in this work. They arebroadly consistent with the scenarios published in the Electricity Commission’s 2010Statement of Opportunities.There are five market development scenarios:Sustainable Path – New Zealand embarks on a path of sustainable electricitydevelopment and sectoral emissions reduction.Wind – Renewable development proceeds at a slightly more moderate pace.Considerable increase in wind and hydro particularly in lower South Island.Medium Renewables – Middle of the road scenario; renewables developed inboth islands with North Island Geothermal playing an important role. Tiwaismelter assumed decommissioned in the mid-2020s.Coal – Low carbon charge and greater gas availability after 2030 make new gas,coal and lignite fired plants economic.High Gas Discovery – Major new indigenous gas discoveries keep gas prices lowover the entire time horizon.1Further information about the new model is provided in Chapter 4.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. iii

Executive SummaryState of the gridA reliable “fit for purpose” National Grid that meets present consumer needs, andresponds to changing demands, is an essential component of a modern society. Arobust and capable grid also creates a platform to allow strong competition betweengenerators and retailers, to put downward pressure on prices to the benefit ofconsumers. The National Grid also continues to provide New Zealanders with accessto renewable sources of generation (hydro, wind, geothermal).Based on present knowledge, we can demonstrate that the projects identified in thisreport will enable the grid to meet forecast demand and solve the grid related issuespredicted to occur over the next 10-15 years. 2Key proposed developmentsA number of the major projects signalled in previous years are now either completedor nearing completion in the next 12 months, including well underway including theNorth Island Grid Upgrade project (completed 2012), North Auckland and NorthlandUpgrade project (targeting late 2013), the HVDC Pole 3 project (Stage 1 targetingmid-2013) and Wairakei to Whakamaru C line (targeting late 2013).In other areas and in the regional networks particularly, smaller upgrade projectsproviding incremental changes to existing capacity continue to be needed. In theseregions, where there is less certainty over future transmission capacity, investment innewer technologies is helping to get the most out of what we have now. Recentprojects include deployment of further static synchronous compensators at Penroseand Marsden, and development of a demand side management platform.Completed projects for 2012Summary Table 1 lists the projects completed since the 2012 Annual PlanningReport.Summary Table 1: Projects completed since the 2012 Annual Planning ReportProject nameNorth Island Grid Upgrade project – new 220/400 kV double circuit transmission line (partiallyunderground cables) from Whakamaru to PakurangaBay of Plenty Interconnection Upgrade project including:New 220/110 kV transformers at KaitimakoConverting the Hairini–Tarukenga–A line to 220 kV operationMasterton supply transformer replacementA third 220/66 kV transformer at BromleyKawerau generation enhancement – Stage 1:Split Matahina bus.Reconfigure Edgecumbe–Kawerau–2 and Kawerau–Matahina–2 to form Edgecumbe–Matahina–2,bypassing Kawerau substation.Open the Edgecumbe–Kawerau–2 circuit.Install a Special Protection Scheme (SPS) to protect Kawerau–T12 and T13.New grid exit point at Piako.Install a Bromley 220/66 kV transformer.Replace Roxburgh 220/110 kV interconnecting transformer.2Transpower is unable to comment on supply side issues (e.g. beyond the grid exit point) other thanthrough the impact of the generation scenarios.iv2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Executive SummaryCommitted projects for 2013Summary Figure 1 and Summary Figure 2 provide a summary of all committedprojects in this APR 3 . Detail around any particular project can be found in therelevant regional or grid backbone chapter.Summary Figure 1: Transpower’s committed projects – North IslandAuckland Regional ProjectsNew 220 kV connection betweenPakuranga and Penrose.New cross harbour 220 kVconnection between Penrose andAlbany.New grid exit point at Hobson Street.New STATCOM at Penrose.Northland Regional ProjectsNew STATCOM at Marsden.New grid exit point at Wairau Road.Waikato Regional ProjectsUpgrade Te Kowhai supplytransformer.Replace Cambridge 11 kVswitchgear.Taranaki Regional Projects110 kV Opunake–Stratfordtransmission line conductorreplacement.Replace Stratford supplytransformers.Replace Wanganui supplytransformers.110 kV Hawera–Waverleyconductor replacement.Bay of Plenty Regional ProjectsReplace Tarukengainterconnecting transformers.Replace Rotorua supplytransformers.Replace Kawerau–T12interconnecting transformer.Hawke’s Bay Regional ProjectsReplace Redclyffe supplytransformer.Wellington Regional ProjectsInstall a third Wilton 110 kV bus section.Replace Kaiwharawhara supplytransformer.North Island Grid Backbone ProjectsNew 220 kV Wairakei–Whakamaru–C transmission line220 kV Bunnythorpe–Haywards–A and B line conductorreplacement.3Refer to Chapter 1, Section 1.4 for definitions of “committed” and “proposed”.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. v

Executive SummarySummary Figure 2: Transpower’s committed projects – South IslandNelson-Marlborough projectsReplace Stoke supplytransformers.Canterbury projectsNew supply transformer atAshburtonSouth Canterbury projectsUpgrade Timaru supplytransformer.Convert Timaru 110 kV bus tothree zones.Otago-Southland Regional ProjectsLower South Island Reliability Projectincluding:new 220/110 kV interconnectionat Gore and 220 kV lineconnecting Gore to the NorthMakarewa–Three Mile Hill linereplace interconnectingtransformer at Invercargillnew capacitors at Balcluthaseries compensation at ThreeMile Hill.South Island Grid Backbone ProjectsClutha–Upper Waitaki Lines Project.HVDC Grid Backbone ProjectsHVDC Pole 3 Project.HVDC control system replacement.vi2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Executive SummaryFeedbackWe will be using this document as a basis for discussions with our customers andother stakeholders by way of regional forums and other meetings. Feedbackreceived will be used to improve subsequent releases of the Annual Planning Report.If you are unable to attend a regional forum in your area, but have feedback on howthis document might be improved, please address to:Grid DevelopmentTranspower New Zealand LtdPO Box 1021Wellingtongridinvestmentprojects@transpower.co.nz2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. vii

Table of Contents82013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Table of Contents1 INTRODUCTION ..............................................................................................................102 FACILITATING NEW ZEALAND’S ENERGY FUTURE ..................................................153 EXISTING NATIONAL GRID ...........................................................................................234 DEMAND ASSUMPTIONS ..............................................................................................315 GENERATION ASSUMPTIONS ......................................................................................356 GRID BACKBONE ...........................................................................................................417 NORTHLAND REGIONAL PLAN ....................................................................................878 AUCKLAND REGIONAL PLAN ....................................................................................1079 WAIKATO REGIONAL PLAN ........................................................................................12910 BAY OF PLENTY REGIONAL PLAN ............................................................................15511 CENTRAL NORTH ISLAND REGIONAL PLAN ...........................................................18112 TARANAKI REGIONAL PLAN ......................................................................................20113 HAWKE’S BAY REGIONAL PLAN ...............................................................................21814 WELLINGTON REGIONAL PLAN .................................................................................23415 NELSON-MARLBOROUGH REGIONAL PLAN ...........................................................25616 WEST COAST REGIONAL PLAN .................................................................................27017 CANTERBURY REGIONAL PLAN ................................................................................28518 SOUTH CANTERBURY REGIONAL PLAN ..................................................................30219 OTAGO-SOUTHLAND REGIONAL PLAN ....................................................................322APPENDIX A GRID RELIABILITY REPORT .................................................................343APPENDIX B GRID ECONOMIC INVESTMENT REPORT ...........................................388APPENDIX C FAULT LEVELS.......................................................................................390APPENDIX D PROJECT CALENDAR ...........................................................................405APPENDIX E TRANSPOWER’S INVESTMENT APPROVALS PROCESS (IAP)........418APPENDIX F GRID SUPPORT CONTRACTS ..............................................................420APPENDIX G GENERATION SCENARIOS ...................................................................425APPENDIX H TRANSPOWER PROJECT NAMING .....................................................442APPENDIX I GLOSSARY .............................................................................................444APPENDIX J GRID EXIT AND INJECTION POINTS ....................................................4492013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 9

Chapter 1: Introduction1 Introduction1.1 Purpose of the Annual Planning Report1.2 The regulatory framework and the APR’s context1.3 The planning approach1.4 Project classification1.5 Project references1.6 Cost bandsTranspower owns, maintains, operates and develops New Zealand’s high voltagetransmission network (the National Grid).The Annual Planning Report (APR) provides details of potential transmissioninvestment over the next 15 years. This includes:the forecast of demand and generation at each grid exit point and grid injectionpoint, respectively, over the next 15 yearsinformation about the existing transmission networkanticipated system constraints and issues over the next 15 yearsa summary of potential transmission investment to alleviate the anticipatedsystem constraints and issues, andother issues impacting on transmission investment.The information in this APR is based on the New Zealand transmission network as at28 February 2013.1.1 Purpose of the Annual Planning ReportWe produce the APR to:provide an indication of the National Grid’s ability to meet forecast demand andgeneration development over the next 15 yearscommunicate the potential transmission investment required to alleviateanticipated system constraints and issues to customers, industry, regulators andinterested partiesprovide transparency in terms of the current transmission network developmentoptions, andencourage efficient investment decision making via the timely disclosure of griddevelopment options.This APR represents our view of how the National Grid might be developed over thenext 15 years to provide both reliability of supply and facilitate a competitive electricitymarket. To achieve this, the APR:presents a grid development plan, which includes possible transmissioninvestments based on preliminary assessments 4 - detailed analysis occurs whenpreparing a case for investment (see Appendix E for more information), andaims to provide information to enable interested parties to:understand the transmission network’s ability to supply their needsprovide input into our transmission network development plansidentify and evaluate alternative transmission network investments4This plan does not imply that we have formed a view about a particular transmission investment, orthat a transmission (versus a transmission alternative) investment is the most efficient solution.102013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 1: Introductionidentify potentially preferred locations for connecting significant load (e.g.heavy industry)identify locations that may benefit from demand-side initiatives, andassess generation development opportunities, such as preferred locationsand the ability of the transmission network to accommodate the proposedgeneration.This document is produced for the purposes specified above. Any associated costinformation represents a high level and provisional estimate only and therefore shouldnot form the basis for investment decisions. Interested parties should confirm theadequacy of these cost estimates for themselves, or contact us for more detailedinformation.1.1.1 Document overviewIn this APR:Chapter 2 ‘Facilitating New Zealand’s Energy Future’ provides a high-leveldescription of our long term goal and the challenges in meeting it.Chapter 3 ‘Existing National Grid provides a description of the National Grid’sexisting configuration, including recently completed projects.Chapter 4 ‘Demand Assumptions’ provides a high-level description of ourdemand forecast approach and the various demand forecasts it has developed.Chapter 5 ‘Generation Assumptions’ describes the development and selection ofour generation scenarios.Chapter 6 ‘Grid Backbone’ discusses the grid backbone’s ability to accommodatethe forecast demand.Chapters 7 - 19 ‘Regional Plans’ describe the specific plan for each region’stransmission network.Appendices A to J contain supporting information including the Grid ReliabilityReport (Appendix A ) and Grid Economic Investment Report (Appendix B ).Each regional plan also provides an overview of the existing regional transmissionnetwork and any anticipated security issues.1.2 The regulatory framework and the APR’s contextUnder Part 12 of the Electricity Industry Participation Code, we are required topublish:a Grid Reliability Report (GRR), which sets out 10-year forecasts of demand atgrid exit points and generation at grid injection points, and whether the NationalGrid can be reasonably expected to meet (n-1) security requirements, anda Grid Economic Investment Report (GEIR), which identifies economicinvestments (creates net market benefits) that Transpower considers could bemade in respect of the interconnection assets.The Annual Planning Report (APR) includes both the GRR and GEIR.1.2.1 The context for our APRAs owner, operator and planner of the National Grid, we publish the APR annually toassist all market participants to understand the extent of potential transmissioninvestments requirements.A summary of the GRR information can be found in Appendix A A summary of theGEIR information can be found in Appendix B2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 11

Chapter 1: IntroductionSystem Security Forecast (SSF)As the System Operator, we also publish the System Security Forecast (SSF). TheSSF assesses the National Grid’s capability to meet demand as required under Part 7of the Code, and generally covers a shorter term and operational focus. The latestSSF is available from our System Operator website. 5Transmission CodeOur Transmission Code codifies a set of technical planning requirements that weapply to ensure the National Grid remains resilient, fit for purpose and is consistentwith good industry practice. More information on the Transmission Code can befound on our website. 61.3 The planning approachOur long-term strategic view is outlined in Chapter 2 ‘Facilitating New Zealand’sEnergy Future’. Planning is framed by the long-term view to ensure the appropriateselection of investment for the maintenance of a reliable and secure electricity supply,under a range of system and environmental conditions.1.4 Project classificationThe APR refers to a large number of current and potential transmission andgeneration projects. This section explains how we present projects in the APR in thecontext of their state of completion, regulatory status, identification references andcosts.1.4.1 State of completionWe classify transmission network development projects by their state of completion.Table 1-1 lists the completion states by project type and definition.Table 1-1: State of completion classificationsStatusCompletedCommittedProposedPreferredPossibleInformation onlyDefinitionProjects that have recently been completed and are commissioned and operating.Projects that are currently underway for which either:the investment has obtained regulatory approval, orTranspower has entered into a new investment contract with a specificcustomer or customers.Projects that Transpower has proposed, either:to the Commission via a Major Capex Proposal, oras part of our Base Capex funding, orto specific customer or customers for their agreement.Projects for which Transpower has undertaken detailed analysis and identified apreferred transmission or non-transmission solution.Projects identified as possible options for future grid upgrade, subject to furtheranalysis.Descriptions of issues that are likely to be managed operationally or by customerdriven investment. Specific projects are not formulated either because it is tooearly to do so, or because alternative low-cost options are evident.56http://www.systemoperator.co.nz/publications#cs-85812https://www.transpower.co.nz/about-us/what-we-do/planning-future/planning-inputs122013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 1: Introduction1.4.2 Investment typeOur transmission network development projects can be classified by the fundingsource as shown in Table 1-2.Table 1-2: Regulatory investment typeInvestment typeBase CapexMajor CapexCustomer-specificDefinitionReplacement and Refurbishment projects of any value, orDevelopment projects forecast to cost less than:$5 million in RCP1, or$20 million in RCP2These proposed projects are funded under a CC-approved approved BaseCapex allowance.These are individual investment proposals to enhance the Grid, which aresubmitted to the Commerce Commission for approval on a case by casebasis. The cost threshold for individual enhancement project approval is $5million in the current Regulatory Control Period 1 (RCP1) and increases to$20 million for RCP2 (which begins April 2015). Each proposal must complywith the regulated Investment Test as prescribed in the Transpower CapitalExpenditure Input Methodology Determination 7Enhancement projects on assets specific to a customer or group ofcustomers which are agreed and paid for under a new investment contractbetween Transpower and the customer/group of customers.1.4.3 Generation proposalsTable 1-3 summarises the generation proposal classifications used throughout theAPR.Table 1-3: Generation proposals classificationsStatus Definition Consideration in APRCommittedLikely toproceedPossibleProjects for which:land for the project has beenacquiredresource consents have beenobtained, andbusiness approval has beenobtained.Projects for which the following areunder way or close to beingobtained:procuring land for the projectapplication for resource consent,andbusiness approval.Projects for which the following are intheir initial stages or have yet tocommence:procuring land for the projectapplication for resource consent,andbusiness approval.The project will be:considered explicitly in Transpower’sassessment of transmission issues anddevelopment options, anddescribed in the main body of the text.The project will be considered as:part of the generation scenarios described inChapter 5, ora sensitivity assessment, if it does not fit withinany of the generation scenarios described inChapter 5. In this case, the APR will describethe project in a separate section under theregional plans, including its possible impact onthe transmission network and developmentstatus.Considered as part of the generation scenariosdescribed in Chapter 5.7 http://www.comcom.govt.nz/assets/Pan-Industry/Input-Methodologies/Transpower-Capital-Expenditure-IM/Capex-IM-Final-Determination-and-Reasons-Paper/Transpower-Capital-Expenditure-Input-Methodologies-Determination-2012.pdf2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 13

Chapter 1: Introduction1.5 Project referencesWe apply a unique project reference for each provisional, preferred, proposed orcommitted project. These references, which feed through our planning, design, buildand maintenance operations, should be used when requesting further informationfrom us about any specific project. See Appendix H for more information about howthese codes are determined and interpreted.1.6 Cost bandsWhere investment is required to resolve identified issues, an indicative cost has beendeveloped. The indicative costs represent the expected cost (in 2012 dollars) to fullyimplement the indicated solution, and include a contingency allowance of 25%,(excluding any property costs that may be required - unless specifically stated).Property costs have not generally been included because of the uncertaintiesinvolved, but for some projects the property costs can significantly impact the overallcost.Table 1-4 lists the indicative cost bands for transmission network development,reflecting the fact that these are broad estimates only.Table 1-4: Indicative cost bandsIdentifierABCDEFGIndicative cost bandUp to $5 million$5 - $10 million$10 - $20 million$20 - $50 million$50 - $100 million$100 - $300 million$300 million plus142013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 2: Facilitating New Zealand’s Energy Future2 Facilitating New Zealand’s Energy Future2.1 Introduction2.2 Transmission Tomorrow – a progress report2.3 Long term performance targets2.4 Generation and grid compatibility2.5 When do we invest?2.1 IntroductionThe transmission network is central to the delivery of least cost electricity to NewZealand’s homes and industry. It enables the economic dispatch of least costelectricity through the electricity market from diverse generation sources. It alsoenables a range of ancillary services such as frequency keeping, spinning reserveand interruptible load to provide the support needed to keep the network secure.The requirements placed on the transmission network evolve over time. The assetsand operation of the power system of the 1950s are different to today. Therequirements placed on the transmission grid will continue to evolve in ways that wecannot foresee today:the historic link between load growth and GDP may be changing, creatinguncertainty over how much electricity use will grow (see Chapter 4 for moreinformation)the nature of demand for electricity will change, particularly the shape of thedemand curve on a daily and annual basishow and where electricity is generated will change, both to replace retiringgeneration and to meet load growth, andnew technologies will change how electricity is generated, transmitted and used.Therefore, the future is inherently uncertain. Our planning must reflect this andposition us to be able to meet all possible eventualities. This will allow us to makebest use of our existing assets and provide better options when new assets areneeded. This will reduce the cost and footprint of the grid for future generations whileproviding a grid that is fit for purpose.To manage the inherently uncertain future, we developed long-term strategies,platforms and technologies to guide and inform our transmission planning, with inputfrom a wide range of stakeholders. These are described in Transmission Tomorrow 8 .Where relevant to the Annual Planning Report, their effect is reflected in Chapter 6 forthe grid backbone and Chapters 7-19 for the regional grids.In this chapter:Section 2.2 is a progress report on Transmission TomorrowSection 2.3 describes an initiative to develop long term grid performancemeasures and targets.Section 2.4 describes emerging and potentially significant interactions betweengeneration technology and the grid.Section 2.5 concludes with when we invest.8https://www.transpower.co.nz/resources/transmission-tomorrow2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 15

Chapter 2: Facilitating New Zealand’s Energy Future2.2 Transmission Tomorrow – a progress reportSince releasing Transmission Tomorrow, we have made progress on the strategicinitiatives. Several initiatives are summarised below.2.2.1 Variable line ratings - operating assets to ratingsThe initiativeMost of our transmission lines are operated to pre-calculated, seasonal ratings.Pre-calculated ratings are design ratings which reflect a least favourable combinationof operating conditions (such as ambient temperature and wind) for that season.Transmission lines can carry more power than the design rating when the ambientconditions are more favourable than the design ratings.Variable line ratings (VLR) use ambient conditions from a 500 metre grid along a lineusing historic weather data from NIWA on a time of day and monthly basis. Theratings are then determined from the maximum design operating conditions and lineto ground clearances.VLR also requires a change in transmission line rating methodology. The change inrating methodology, combined with VLR, usually increases the average rating of atransmission circuit, but may also decrease the rating for certain periods during theday and month. In general, the benefit from VLR is greater for larger conductors andhigher maximum operating temperature (and the periods where the rating decreasesare reduced in duration and magnitude).We implemented interim variable line ratings (iVLR) on six transmission circuits inNovember 2011 as a trial. iVLR provides the circuits with ratings for six periodswithin a day for each month in the year. The average increase in rating for eachcircuit was between 8% and 16%. However, the rating of the circuits also decreasedfor certain periods during the day and month.The trial is expected to continue for at least another two–three years. The experiencefrom the trial will help frame the rollout of VLR:Should VLR be applied to all lines, or only selected lines with the highest benefit?Should VLR be based on two-hour intervals per day?For what situations did VLR provide a system or market benefit, for how long andto what extent?A full rollout of VLR to all lines will require major changes in the System Operator’splanning and real time software tools and processes, to fully automate VLR updates,with a high associated cost. It may be more cost effective to apply VLR to onlyselected circuits with the highest benefits, resulting in simpler and lower costupgrades of the existing tools that the System Operator uses.Operating experienceThe following circuits have iVLR applied. The circuits were selected to cover diversegeographical areas and potentially provide benefits for different situations:Clyde–Roxburgh–1 and 2 – part of the 220 kV grid in the Otago-Southland areaWairakei–Ohakuri–Atiamuri circuits – part of the 220 kV “Wairakei Ring”northwest of Taupo, andOtahuhu–Whakamaru–1 and 2 – part of the 220 kV grid into Auckland.Only 17 months of system operation with iVLR is available. Large inter-yearvariations of power flows due to differences in yearly hydro inflows makes it difficult tofind a clear cut quantifiable difference in pre- and post- iVLR power flows on the sixcircuits for the 17 month period. The following is a qualitative description ofexperience to date.162013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 2: Facilitating New Zealand’s Energy FutureVLR on the Clyde–Roxburgh–1 and 2 circuits assists in management of low hydrogeneration in the Otago-Southland area by increasing the average transmissioncapacity from the Waitaki Valley and Clyde to the Otago-Southland area. Increasedcapacity is beneficial for an infrequent combination of hydro inflows, which is beingexperienced at present in early 2013. When the capacity of the Clyde–Roxburgh 1and 2 circuits is increased through the installation of duplex conductors (an approvedproject), it is expected that there will be little system benefit from retaining VLR.The Wairakei Ring area has significant hydro and geothermal generation, with moregeothermal generation under construction or planned. VLR on the Wairakei–Ohakuri–Atiamuri circuits increased the transmission capacity of the Wairakei Ring,so that the next constraint was the rating of the Te Mihi–Whakamaru circuit. At therequest of generators in an industry forum, we also raised the constraint limit on theTe Mihi–Whakamaru circuit by installing a special protection scheme (SPS) andupgrading some substation equipment. This further increased the transmissioncapacity of the Wairakei ring, which is a very strong indication of the benefit of VLR.There is an approved project to increase transmission capacity by building a highcapacity transmission line in the Wairakei ring. Retaining VLR on the Wairakei–Ohakuri–Atiamuri circuits after the new line is commissioned is still effective,providing additional capacity and better utilisation of the existing and new lines.VLR on the Otahuhu–Whakamaru 1 and 2 circuits provided increased transmissioncapacity during maintenance outages of other 220 kV circuits supplying Auckland.There was no observed need for the increased capacity in the last 17 months. Therecent commissioning of the new line from Whakamaru into Auckland means theneed for VLR during maintenance outages is significantly reduced.Planning experienceAdoption of VLR for most circuits forming the grid backbone is not expected to be anissue, as most circuits gain an increase in average capacity and the effects of anyperiods of decreased capacity will be limited to changes in generation dispatch.We carried out a VLR planning study on a double circuit radial line supplying a load.The increase in rating due to VLR was expected to be modest as the conductor wasrelatively small and strung at low temperature 9 . The load has a pronounced winterpeak.The study showed:Applying VLR and assuming all spans of the line have minimum design (i.e.statutory) clearances to ground resulted in a change in rating ranging from a20 MVA decrease to a 30 MVA increase, depending on time of day and month.The increased VLR rating in winter deferred the n-1 overloading by six years.However, the decreased VLR rating in summer daytime caused an n-1 overloadissue now (particularly from 10:00 am to 12:00 noon).Applying VLR and surveying the line to determine the actual clearance to groundfor each span resulted in an increase in rating from about 1 MVA to 35 MVA,depending on time of day and month.The improved VLR rating deferred the summer n-1 overloading by about twoyears, assuming the peak summer load could occur at any time during summer.Refining the load forecast for time of day and month of year, assuming thehistoric load profile, deferred both the summer and winter n-1 overloading byabout seven years.The profile of the refined load forecast approximately matched the daily andmonthly VLR load profile.The general conclusions for the line studied above are:9The conductor was simplex wolf strung at 50°C, which has a rating of 53/77 MVA summer/winter.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 17

Chapter 2: Facilitating New Zealand’s Energy FutureThe VLR rating needed to be calculated for each span using actual survey data.The load forecast needed to be based on the same day/month increments asused for the VLR methodology.The load profile must be forecast and/or managed, not just the peak load.VLR would not deliver any benefits for this line if dairy or irrigation load was beingsupplied, as the load profile would not match the VLR profile.2.2.2 Demand-side response – enabling consumer responseThe initiativeDemand-side response programmes allows a means of reducing load (eitherindividually or as part of an aggregated group) to the extent and times required by thegrid. The magnitude and duration of any load reduction is to pre-agreed contractualterms.Wide adoption of demand-side response will reduce growth in transmission peaks,delaying the need for transmission upgrades. It may also be very useful to manageoutages for maintenance, either maintaining security during outages or avoiding theneed for additional investment to facilitate maintenance outages.Progress to dateWe have made significant progress over the last 12 months having successfullyimplemented a Demand Response Management System (DRMS) which allowscalling and coordination of any size demand-side response. We have just startedtesting the connectivity of the platform with end users and will be looking to launch amarket pilot by mid-year.The pilot will target large electricity users as well as smaller consumers.The pilot will seek to:Test operation of the DRMSDetermine the natural price points for different demand response providersTest distributor coordination and collaborationUnderstand coordination between AUFLS and demand response, andInform the next steps required to embed demand response in the NZ landscape.Transpower aims to have 100 MW of demand response registered for the pilot and10% of peak demand enrolled in a demand response programme within five years.Success of the demand response initiative will depend on constructive collaborationand coordination by a wide range of organisations and interested parties. Therefore,the challenge to establish demand response is not limited to Transpower, but to thebroader electricity industry to build a new capability that will benefit New Zealand forthe long term.2.2.3 Corridor management of transmission routes – secure long term access totransmission routesThe initiativeNational and local policy-makers recognise the need to plan long-term forinfrastructure 10 . Local authorities are now considering utility corridors in theirlong-term plans. This provides a mechanism by which transmission line corridors can10The 2008 introduction of the National Policy Statement on Electricity Transmission (NPSET)provides increased protection against activities incompatible with transmission lines, such asunderbuild.182013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 2: Facilitating New Zealand’s Energy Futurebe managed so that only compatible developments are built under and adjacent toexisting transmission lines. This will preserve our ability to operate, maintain andupgrade our transmission lines 11 , which are irreplaceable assets.Progress to dateWe have focussed our efforts initially on the Auckland region to coincide with ourinvolvement in the development of the Auckland Council’s spatial plan, which is nowpublished.2.2.4 Other initiativesResilience of the gridGrid reliability is inherent in much of what we do; however, maintaining and improvingresilience in a more highly loaded grid requires special attention, especially for HighImpact Low Probability (HILP) events.Initiatives in the last year which increase the resilience of the grid include thefollowing:A HILP study was completed for Bunnythorpe substation, which is a critical nodefor supply to the lower North Island. The study highlighted cost effectiveinvestments which improve the resilience of the transmission network to HILPevents.Work has commenced to mitigate the risk of a loss of supply following a fault onthe Wilton 110 kV bus. This bus is the “hub” for the supply to Wellington city.The work will allow Wellington city load to remain connected following the loss ofa 110 kV bus section at Wilton, and also allows easier and safer maintenance.A HILP study is being completed for the supply for Wellington city (Wilton, CentralPark and Kaiwharawhara substations).Single phase transformer replacementWe have a long term transformer fleet replacement programme to improve assetperformance. We will retire approximately 25 single-phase interconnecting bank andsupply transformers over a three-year period from July 2012 to June 2015.Replacement transformers will be modern three-phase transformersThis renewal programme will result in a more reliable grid, requiring fewer and shorteroutages for maintenance and with fewer faults. The replacement transformers willhave higher ratings where capacity issues are identified as part of the APR process.Integrating generation and transmissionAs part of replacing HVDC Pole 1 with the new Pole 3, the HVDC controls will also bereplaced, which allows greater functionality and flexibility. For example, at presentthere are separate frequency-keeping and reserve markets in the North and SouthIslands. The replacement HVDC controls will allow a single market.The new HVDC controls will also enable automatic controls to be added as requiredin future. For example, this could be to continuously balance North Island windgeneration with South Island hydro, or automatically adjusting HVDC transfer inresponse to outages in the North or South Islands (to the extent that the other islandcan absorb the change). To make full use of the increased HVDC functionality mayalso require development of the System Operator’s tools, or rule changes forprovision of ancillary services.11About 95% of our line corridors are controlled by the Electricity Act 1992 Part 3. About 5% of ournew line corridors are controlled by ownership or easements by Transpower.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 19

Chapter 2: Facilitating New Zealand’s Energy FutureThe HVDC is a clear example of how the rest of the grid may develop. It usesmodern power technology and controls, a market framework, advanced analysis, andsophisticated software tools for the System Operator to maximise the benefit of theelectricity system.2.3 Long term performance targetsWe are developing new long-term grid performance measures and targets to applyfrom 2015. These measures and targets will be part of our submission to ourregulator, the Commerce Commission, for our revenue for Regulatory Control Period2 (2015-2020). We will use the new targets as the basis for aggregated annualtargets that will be linked to our revenue – we will be either rewarded or penalised forour overall performance against the aggregated targets.Our grid performance measures have dual roles – providing information to customers,and encouraging us to focus on efficient asset expenditure, where the benefits tocustomers justify the costs. Over the last few months we have been consulting withcustomers on the form the new performance standards should take.The standards split grid exit points (GXPs) into four categories and establishperformance standards for each category. The standards include interruptionfrequency targets: for example, one per five years. However, recognising that asingle GXP may have more or less than this in any period, we will also define levels(say, two in two years) which will trigger investigation, reporting and remedial action.There will also be restoration duration targets and, for the first time, communicationtargets. The latter are important to customers – the impact of an interruption can bereduced by prompt information as to what has happened, what we are doing, andwhen we think the electricity is likely to come back on.Initially, the targets will be about delivering the service that the customer shouldexpect given the grid assets used to supply them. As our approach matures, we willfocus on matching the performance delivered to what is both desired and economic.2.4 Generation and grid compatibilityTransmission Tomorrow looks forward at how transmission services must developand Transpower’s role in achieving this. Generation development also has animportant role, and this section highlights items that may be significant in future as thegeneration technology and generation mix change.There are good reasons why generation technology and the generation mix arechanging. They may require changes to how the generation is integrated into thepower system and how it is operated. This is ‘business as usual’, as New Zealandhas a long history of integrating and managing new technologies into the powersystem. Examples include the original and hybrid upgrade of the HVDC link, theintroduction of large thermal generating units (Huntly), the first combined cycle gasturbine (in Taranaki), and the wind farm at Taurarua.2.4.1 High voltage fault ride-throughNew Zealand’s transmission grid is “long and thin”, and parts are heavily loaded withhigh levels of reactive compensation for voltage support. An inherent characteristic ofpower systems with increasing levels of reactive compensation is the potential forhigh Transient Over Voltage (TOV) 12 when there is a sudden reduction in load.12 TOV is a phenomenon where the voltage jumps to a very high value in the first half cycle followingthe sudden reduction in load. The natural response from power system dynamics and fast actingcontrols then rapidly decreases the TOV to merely a high value over approximately 25 cycles.202013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 2: Facilitating New Zealand’s Energy FutureHigh TOV can cause generating units to trip to protect themselves from damage. Thetripping of the HVDC link can cause high TOV in the lower North Island (up toBunnythorpe and Stratford substations, and other substations in the area) which cancause regional generation to trip. This has not been a concern in the past as therewas relatively little generation in the Wellington region. The connection of wind farmsnear Wellington and the proposals for more wind farms in Wellington and theWairarapa make TOV considerations more important for the future.The loss of the HVDC link at high north transfer can result in not only the loss ofHVDC transfer but potentially also generation in the Wellington region. Such a risk ismanaged through the procurement of instantaneous reserves to cover the loss of theHVDC link and generation, or by reducing HVDC transfer and generation in theWellington region. These measures can have high market costs. High TOV can alsobe mitigated by investment in transmission assets, which will have considerablecosts. A more cost effective measure for New Zealand may be to require generationplant capable of remaining connected and providing support during and after a TOV.2.4.2 Recovery following a faultFaults are a normal and expected part of operating the power system. Generationplays an important part in assisting the power system in recovering from faults. Onetype of fault is the loss of generation infeed. This could be caused by the loss of agenerating unit, a bus with generating units connected, or transmission circuit(s)carrying power from an area with net generation export to an area of net load. Theimmediate effect following the loss of generation infeed is a fall in frequency.Generation that remains connected to the grid has an important role in arrestingfrequency fall and restoring frequency.The System Operator ensures that there are sufficient instantaneous reserves (IR)(partially loaded generating units and interruptible load) available to halt the fall infrequency caused by loss of certain amounts of generation or transmission infeed.The amount of IR required mainly depends on the size of the largest risk. In theNorth Island, the largest risk is usually the sudden loss of a large thermal generatingunit (up to 400 MW).Other factors such as governor action on generating units and system inertia are alsoimportant. Hydro and fossil fuelled generation will automatically use more ‘fuel’ andincrease output during falls in frequency as a result of free governor action. Systeminertia (the ability of the system to resist or slow down the fall in frequency) affects theamount of reserves required. Falls in frequency following the loss of generation arefaster with lower system inertia. Halting the fall then requires faster acting IR.The changing nature of the generation fleet in the future will affect the amount ofrequired instantaneous reserves:The displacement of large thermal generating units by renewable generation withsmaller unit sizes will tend to reduce the size of the risk of a generating unit trip,and hence reduce the required IR. However, the IR to cover the tripping of a busor transmission circuits will remain largely unchanged, and hence the overall levelof IR required may not reduce significantly.Increased amounts of renewable generation with less ability to provide supportduring falls in frequency will increase the need for instantaneous reserves in thefuture. Geothermal, wind and, in the future, marine energy and photovoltaiccannot increase output as the frequency falls. This is because usually all their‘fuel’ input is being used to generate electricity and there is no additional ‘fuelreserve’ for sustained additional generation to provide instantaneous reserve.Some forms of renewable generation have less inertia than the hydro or thermalplant which they displace. This reduction in system inertia will increase the needfor instantaneous reserves.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 21

Chapter 2: Facilitating New Zealand’s Energy FutureWind and other forms of renewable generation could also provide instantaneousreserves if they ‘spill’ some of their ‘fuel’, so an instantaneous increase in generationoutput is possible (up to the maximum level of ‘fuel’ input) if required. The ‘fuel spill’comes at a cost of decreased efficiency, but this may be more than balanced by theinstantaneous reserve costs. Similarly, wind and other forms of renewablegeneration can provide “pseudo inertia”. This is achieved by allowing the windturbines to slow down or speed up during changes in power system frequency.It is possible that there will be an economic imperative for wind farms and otherrenewable generation sources to provide instantaneous reserves and pseudo inertiain future. This is especially likely if enough new geothermal and wind farm generatingstations are built so that during low load periods most hydro and fossil fuelled powerstations are off.2.4.3 Balancing generationThe power system must be continuously operated to balance supply and demand forelectrical energy. The normal variability of generation and load is exacerbated bywind and other intermittent renewable generation. This places additional demands onthe real-time operation of the power system as the proportion of renewablesincreases. Some overseas utilities have experienced periods when wind generationhas supplied the entire overnight load. New Zealand has had 25% of load suppliedby renewables and scenarios where the total load is supplied from renewables arerealistic.A common strategy to manage the variability of generation and load is to implementautomatic generation control (AGC). A multiple frequency keeper service MFK (a NZvariant of AGC) is being implemented for wide-area control of generation on acontinuous basis, in 2013 for the North Island and 2014 for the South Island.It is also expected that more use will be made of demand-side response to balancegeneration. This will develop as technology advances and markets mature.2.5 When do we invest?The underlying principle for transmission investment in New Zealand is that thetransmission investment should provide the highest net benefit.Transmission Tomorrow identified existing and future drivers, including technology,which may or will shape the grid of the future. These technologies increase theoptions available for enhancing the grid where necessary.Demand-side response may be particularly useful for reducing the cost of newinvestment. Many projects are commissioned ‘early’ to account for the year-to-yearvariability in peak load growth and the risk of project delays. Demand-side responsehas the potential to cover this uncertainty, allowing new investment to be deferred fora few years.Demand-side response may also be very useful to manage outages for maintenance,either maintaining security during the outage or avoiding the need for additionalinvestment to allow maintenance outages.It is important that we maintain options like using demand-side response to deal withthe unexpected. Transmission planning is often said to be about minimising themistakes from being wrong about the future. Developing our options whether by wayof technology, future corridor protection or demand-side initiatives will help ensurethat tomorrow’s consumers will have a fit-for-purpose transmission grid at the leastpossible cost.222013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 3: Existing National Grid3 Existing National Grid3.1 Introduction3.2 Load and generation3.1 IntroductionThis chapter provides an overview of New Zealand’s existing National Grid as at28 February 2013 with respect to load and generation. New Zealand’s National Gridconsists of the:HVAC transmission network, andan inter-island HVDC link.3.1.1 The AC transmission networkNew Zealand’s HVAC transmission network supplies most of the major load centres,and consists of a grid backbone of 220 kV transmission lines stretching nearly the fulllength of each island.There is also a network of 110 kV lines that run roughly parallel to the 220 kV system.The 110 kV system was the original grid backbone, largely superseded by theintroduction of the 220 kV grid from the 1950s onwards. The 110 kV system is nowprimarily used for transmission to some regions that do not have 220 kV, or for subtransmissionto substations within a region.Figure 3-1 and Figure 3-2 show maps of the transmission network for both the Northand South Islands.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 23

Chapter 3: Existing National GridFigure 3-1: New Zealand’s North Island transmission network242013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 3: Existing National GridFigure 3-2: New Zealand’s South Island transmission network2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 25

Chapter 3: Existing National Grid3.1.2 The HVDC LinkThe HVDC link connects the North and South Island transmission networks.This bi-directional link runs from Benmore, in the South Island, where there is anAC/DC converter station. There is a 534 km transmission line between Benmore andFighting Bay (Marlborough), a 40 km submarine cable between Fighting Bay andOteranga Bay across the Cook Strait, and a further 37 km transmission line intoHaywards substation north of Wellington. At Haywards substation, there is anotherAC/DC converter station.HVDC power flow is predominantly from the South Island to the North Island. Powerflow is from north to south when it is necessary to conserve South Island hydroresources as part of an efficient generation process, or to supply South Islanddemand during dry South Island periods.The HVDC link now consists of one permanently operating pole: Pole 2(commissioned in 1991) operating at 350 kV, which uses thyristor conversiontechnology. An older pole (Pole 1), which used mercury arc valve technology, wasfully decommissioned in 2012. The construction of a replacement pole (Pole 3) usesthyristor conversion technology and is being commissioned (as at 18 March 2013).Table 3-1 lists the existing pole capacities for converting power from AC to DC andfrom DC to AC for both poles. Total pole capacity equates to the total capacity of thelink.Table 3-1: Converter ratings and pole capacitiesPole Commissioned Converter type TransmissioncapacityOperationPole 2 1991 Thyristor valves 700 MW FullPole 3 2013 Thyristor valves 700 MW Being commissionedTotal possible HVDC transmission capacity1000 1 MWNotes:1. Stage 1 of the Pole 3 project is limited to a total of 1000 MW due to limitations of the AC network inthe Wellington region. Stage 2 of the Pole 3 project will increase this limit to 1200 MW.3.1.3 Transmission network asset profileTable 3-2 provides a summary of the transmission network’s assets.Table 3-2: Transmission network assetsAsset descriptionLength of HVAC and HVDC transmission lineDetail11,730 route kmNumber of substations (including HVDC) 178HVAC transmission line voltages220, 110, 66, 50 kVHVDC transmission line voltages350, 270 kVHVDC link capacity 700 MW 1Capacitor banks and filters 347Transformers (banks) 65Synchronous condensers 10Static Var Compensators/STATCOMS 4Notes:1. Pole 1 was decommissioned in 2012.262013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 3: Existing National Grid3.1.4 Recently completed transmission upgrade projectsTable 3-3 lists the transmission upgrade projects completed since the last AnnualPlanning Report (31 March 2012).Table 3-3: Projects completed since the 2012 Annual Planning ReportProject nameNorth Island Grid Upgrade project – new 220/400 kV double circuit transmission line (partiallyunderground cables) from Whakamaru to PakurangaBay of Plenty Interconnection Upgrade project including:New 220/110 kV transformers at KaitimakoConverting the Hairini–Tarukenga–A line to 220 kV operationMasterton supply transformer replacementA third 220/66 kV transformer at BromleyKawerau generation enhancement – Stage 1:Split Matahina bus.Reconfigure Edgecumbe–Kawerau–2 and Kawerau–Matahina–2 to form Edgecumbe–Matahina–2,bypassing Kawerau substation.Open the Edgecumbe–Kawerau–2 circuit.Install a Special Protection Scheme (SPS) to protect Kawerau–T12 and T13.New grid exit point at Piako.Install a Bromley 220/66 kV transformer.Replace Roxburgh 220/110 kV interconnecting transformer.Table 3-4 lists the transmission upgrade projects that have commenced but are notyet commissioned.Table 3-4: Projects commenced (not yet commissioned)Project nameNorth Auckland and Northland grid upgrade project including a new 220 kVunderground cable between:Pakuranga and PenrosePenrose and Hobson StreetHobson Street and Wairau Road, andWairau Road and Albany.Expectedcompletion date20132013201320132013Replacement of 220 kV Wairakei–Whakamaru–C line 2013HVDC Pole 3Stage 1Stage 220132014Upper North Island Dynamic Reactive Support Project 2013-14Lower South Island Reliability Project 2012-17Clutha–Upper Waitaki Lines Project2013-TBCTarukenga interconnecting transformer replacement 2013Opunake–Stratford–A reconductoring 2013New grid exit point at Hobson Street 2013New grid exit point at Wairau Road 2013Stoke supply transformer replacement 2014Replace Stratford supply transformer with two 40 MVA units. 2014110 kV Hawera–Waverley reconductoring 2014Replace Rotorua 110/11 kV supply transformers with two 35 MVA units. 2013-142013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 27

Chapter 3: Existing National GridProject nameUpgrade Te Kowhai supply transformers to the n-1 capacity of 132 MVA. 2013Replace Redclyffe supply transformers with two 120 MVA units. 2013Replace Kaiwharawhara supply transformer. 2013A third Wilton 110 kV bus section. 2015-16Install new 220/66 kV, 120 MVA supply transformer at Ashburton 2014Replace the existing three Timaru 110/11 kV supply transformers with three47 MVA units.Expectedcompletion date2014Lower South Island Reliability projects (including 220/110 kV connection at Gore). 2015-163.2 Load and generationNew Zealand’s transmission network is regarded as narrow and longitudinal, withareas of demand (load) commonly some distance from the areas of significantgeneration. Consequently, the transmission network is essential in complementinggeneration to bring the power to where it is needed.A particular feature of the National Grid, and a key benefit for a sustainable NewZealand, is its ability to provide New Zealanders with access to renewablegeneration. Typically, the remote areas of generation connected by the National Gridare renewable (e.g. hydro in the Waitaki Valley, wind in the Tararuas, and hydro andgeothermal in the Central North Island).Figure 3-3 shows a simplified map of load, generation, and the transmissionnetwork’s grid backbone. For more information see Chapter 4 for the demandassumptions, Chapter 5 for the generation assumptions and Chapter 6 for thetransmission backbone.282013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 3: Existing National GridFigure 3-3: Load, Generation and the Grid BackboneMany of New Zealand’s larger population centres are located in the North Island,while a significant amount of hydro generation is located in the South Island.Power flow tends to be from south to north during normal rainfall years, deliveringpower from the hydro generation in the South Island to the North Island through theHVDC link, which also balances demand between the islands. North to southtransfers have been occurring for longer periods in recent years. They occur morefrequently during dry years where hydro generators in the South Island try toconserve water.Figure 3-4 shows New Zealand’s electricity demand as seen at grid exit points (i.e.this includes distribution network losses but not demand supplied by generationembedded within these networks). Demand has been flat over the last seven yearsparticularly when compared with the strong growth seen in earlier decades. In recentyears demand has been affected by the ongoing impacts of the global recession, thewinter savings campaign in 2007, a reduction in demand at Tiwai Aluminium Smelterin 2008 and the impact of the Christchurch earthquakes.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 29

Chapter 3: Existing National GridFigure 3-4: New Zealand energy use for last seven years302013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 4: Demand Assumptions4 Demand assumptions4.1 Introduction4.2 Energy use versus peak demand4.3 Peak demand forecast methodology4.4 Comparison4.5 Review of forecasting methodology4.1 IntroductionThis chapter provides an overview of the grid exit point demand forecasts used in theplanning studies for this report.Consideration of the National Grid’s future adequacy requires a view of futureelectricity demand, which by definition is uncertain. As part of our forecastingapproach we attempt to quantify the range of future uncertainty. Based on this range,we then derive a prudent level of future demand growth to use in our planning. In linewith international Good Electricity Industry Practice (GEIP) we use a prudent level ofdemand growth to help ensure the timely construction of new transmission. Ourprudent peak forecasts represent a 10% probability of exceedance (POE) forecast forthe first 5 years of the forecast period (until 2018). In other words, until 2018 onewould expect actual demand to exceed the forecast in one year out of ten. Post-2018we assume an expected (or mean) rate of growth such that the probability ofexceedance increases over time. We consider this an appropriate basis on which toconduct our planning.For this publication of the Annual Planning Report we have continued to use an“ensemble” approach where several forecasting models are used to derive ourforecasts. As is highlighted later in this chapter, in response to recent trends we arereviewing our methodology to ensure that it is adequately capturing the range ofuncertainty in future electricity demand growth.Both the Annual Planning Report (APR) and Grid Reliability Report (GRR) require agrid adequacy assessment at the grid exit point level.This is in accordance with Rule 12.76, Part 12 of the Electricity Industry ParticipationCode, which states:Part 12 Grid reliability reporting12.76 Transpower to publish grid reliability report12.76(1) Transpower must publish a grid reliability reportsetting out:12.76(1)(a) a forecast of demand at each grid exitpoint over the next 10 years12.76(1)(b) a forecast of supply at each grid injectionpoint over the next 10 years12.76(1)(c) whether the power system is reasonablyexpected to meet the N-1 criterion, including inparticular whether the power system would be in asecure state at each grid exit point, at all times overthe next 10 years, and12.76(1)(d) proposals for addressing any mattersidentified in accordance with rule 12.76(1)(c).2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 31

MW00:0001:0002:0003:0004:0005:0006:0007:0008:0009:0010:0011:0012:0013:0014:0015:0016:0017:0018:0019:0020:0021:0022:0023:00Chapter 4: Demand Assumptions12.76(2) Transpower must publish a grid reliability report nolater than 2 years after the date on which it published theprevious grid reliability report, or such other date as determinedby the Electricity Authority.12.76(3) If there is a material change in the forecast demand ata grid exit point or in the forecast supply at a grid injection pointin the period to which the most recent grid reliability reportrelates, Transpower must publish a revised grid reliabilityreport as soon as reasonably practicable after the materialchange.Appendix A contains the detailed prudent peak load forecasts by region and grid exitpoint.4.2 Energy use versus peak demandThe demand for electrical energy in New Zealand varies from month-to-month, dayto-day,and from hour-to-hour. For example, households demand much more energybetween the hours of 7:00 – 9:00 am and 5:00 – 8:00 pm than at other times of theday, due to heavier domestic appliance use. The demand at peak times of the daycan be up to twice the lowest demand during the day.Figure 4-1 shows a typical graph (load profile) of daily energy use.Figure 4-1: Typical pattern of daily energy useTypical Daily Load ProfileTime of DayBecause electricity cannot be stored practically in the quantities required, meetingelectricity demand means having sufficient capacity in the electricity supply system(generation, transmission and distribution) to meet the highest (peak) demand.Peak demand is expressed in instantaneous MW, whereas energy is described asconsumption over time, in MWh. Transmission planning requires an analysis of thetransmission network’s adequacy in terms of meeting a forecast of peak demand,rather than energy.322013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 4: Demand Assumptions4.3 Peak demand forecast methodologyOur approach to demand forecasting uses both top-down modelling of national andregional peak and energy demand, and bottom-up modelling of grid exit point peakdemand. The top-down models employ a suite of models and use Monte Carlotechniques to randomly vary components of the models to assess the variability thatcan be expected in future peak demand. More details are available athttps://www.transpower.co.nz/about-us/what-we-do/planning-future/planninginputs#demand.Note that for this year’s Annual Planning Report we have removedthe “Ad hoc” model from our ensemble due to concerns over its subjective nature.At grid exit point level we have employed simpler regression techniques on historicalgrid exit point demand data to project expected and prudent peaks. We have alsosought customer views on grid exit point demand and in many cases modified ourforecasts to include specific load information from our customers. See the relevantregion’s chapter for more information about specific amendments (Chapters 7-19).Our forecasting structure also allows us to project each grid exit point’s contribution toregional and island peak demand. These will typically be less than grid exit pointpeak demand and are calibrated to sum to a similar level as the regional and islandpeak demands produced by our top-down models.4.3.1 Customer consultationWe believe customers are best placed to provide information about future demand intheir transmission networks. To this end, we issued prudent forecasts to ourcustomers in August 2012, inviting comments and adjustments where applicable. Wereceived responses from about half of our customers and for others we consideredthe demand forecasts included in the companies’ Asset Management Plans 2012.We have endeavoured, where reasonable and practical, to incorporate thesecustomer views.We are committed to further consultation with customers with regard to our peak loadforecasts and we welcome ongoing dialogue on the nature and timing of changes togrid exit point demand.4.4 Comparison with the 2012 APR demand forecast and 2010 SoO forecastThe following figure compares the updated APR2013 forecast with the APR2012forecast made last year and with the last of the Electricity Commission’s Statement ofOpportunity (SoO) forecasts from 2010. The forecasts have moved lower each yearas historical demand growth has flattened.The updated forecast is seen to start from a lower base but projected growth remainssimilar to that projected last year; averaging 1.5% per annum to 2028. Part of thedrop in demand forecast for 2012 results from the specific adjustment made toaccount for the loss of load in Canterbury following the earthquakes.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 33

Chapter 4: Demand AssumptionsFigure 4-2: Comparison of 2013 APR prudent peak demand forecast with APR 2012 andSoO 2010 forecastsThe peak demand seen in recent years has been affected by a range of factors.Since 2008 the economy has been impacted by the fallout from the global financialcrisis. In addition, the first part of 2008 was affected by dry weather, resulting inhigher market prices and a conservation campaign, which both reduced demand. In2009, demand was low compared with 2006 and 2007 due in part to reduced TiwaiPoint production at the aluminium smelter. In 2011, we saw a new national peakrecord occur during the unusual polar weather event that affected the whole countryin mid-August serving to mask the underlying drop in demand.4.5 Review of forecasting methodologyGiven the sustained period of flat growth in demand, we believe it is timely to reviewour methodology once again to ensure that it adequately identifies the range of futuredemand growth.In our review we intend to consider the appropriate range of uncertainty in our nearerterm(i.e. 1 to 5 year) forecasts. Our models are based on long-term trends, but weare considering if there is a basis on which to consider shorter-term trends in ournearer term forecasts.We also intend to review some of the long-term relationships we use in our forecasts.In particular, we intend to review the relationship between demand and real GDPgrowth that is used in one of our ensemble models. More recently, real GDP appearsto be growing at higher rates than demand. Partly, this appears to be a result ofdifferent sectors of the economy growing at different rates, and in particular, a resultof a decline in demand in the energy-intensive industrial sector. We are currentlyinvestigating whether these sectorial differences in growth are adequately beingaccounted for in our modelling.We intend to complete our review later this year, and amend our methodology asrequired.342013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 5: Generation Assumptions5 Generation assumptions5.1 Introduction5.2 Generation capacity assumptions5.3 Use of the generation capacity assumptions5.1 IntroductionThis chapter sets out the planning assumptions used to forecast future electricitygeneration at each grid injection point.Transpower undertakes grid planning to ensure that:electricity demand is met reliablythe generation investment market is efficient for all market participants, andthe energy market is competitive for all consumers.As a result, consideration of the National Grid’s future adequacy requires a view ofnot only future electricity demand – a requirement of both the Annual Planning Report(APR) and the Grid Reliability Report (GRR) – but also future electricity generation ateach grid injection point.Future generation will comprise a mix of existing generation (adjusted fordecommissioning), new committed generation, and other potential generationdevelopments. The uncertainty surrounding future generation requires theconsideration of several possible generation scenarios.We have considered five scenarios that are essentially an updated version of thescenarios in the Electricity Commission’s 2010 Statement of Opportunities (SoO).5.2 Generation capacity assumptionsGeneration capacity assumptions derive from a combination of:existing grid connected generation, (assumed to be available, at its existingcapacity, for the duration of the planning period)committed new generation, (new generation that is assumed to be committed,which is included from its publicly notified commissioning date, at its publiclynotified capacity, for the duration of the planning period from commissioning andincludes expansions of existing grid-connected generation)committed decommissioned generation, (existing generation that we have beennotified will be decommissioned, which is excluded from its publicly notifieddecommissioning date, for the balance of the planning period), andnew generation forecasts, (forecast new generation, which is included from theassumed commissioning date, at assumed capacities, for the duration of theplanning period from commissioning. Decommissioning may occur as well).5.2.1 Existing grid connected generationTable 5-1 lists the operating capacities of existing grid-connected generation.Installed capacities may differ in some cases.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 35

Chapter 5: Generation AssumptionsTable 5-1: Existing grid-connected generationGeneration plant Region Type Operatingcapacity inMWGrid injectionpointGlenbrook 1 Auckland Cogen 74 GlenbrookOtahuhu B Auckland Gas - CCGT 380 OtahuhuSouthdown Auckland Cogen 170 SouthdownKawerau Bay of Plenty Geothermal 105 KawerauKawerau Norske Skog Bay of Plenty Geothermal 25 KawerauKinleith Bay of Plenty Cogen 28 KinleithMatahina Bay of Plenty Hydro 72 MatahinaWheao/Flaxy Bay of Plenty Hydro 24 RotoruaAratiatia Central North Island Hydro 78 AratiatiaMangahao Central North Island Hydro 37 MangahaoOhaaki Central North Island Geothermal 46 OhaakiPoihipi Central North Island Geothermal 51 PoihipiRangipo Central North Island Hydro 120 RangipoTararua III 2 Central North Island Wind 93 BunnythorpeTe Apiti Central North Island Wind 90 WoodvilleTokaanu Central North Island Hydro 240 TokaanuTe Mihi Central North Island Geothermal 166 Te MihiWairakei Central North Island Geothermal 161 WairakeiNga Awa Purua Central North Island Geothermal 140 Nga Awa PuruaNgatamariki Central North Island Geothermal 82 Nga Awa PuruaKaitawa Hawkes Bay Hydro 36 TuaiPiripaua Hawkes Bay Hydro 42 TuaiTuai Hawkes Bay Hydro 60 TuaiWhirinaki Hawkes Bay Diesel 155 WhirinakiKapuni Taranaki Cogen 25 KapuniKiwi Dairy Taranaki Cogen 70 HaweraMcKee Peaker Taranaki Gas - OCGT 100 Motunui DeviationPatea Taranaki Hydro 31 HaweraTaranaki CC Taranaki Gas - CCGT 385 StratfordStratford Peaker Taranaki Gas - OCGT 200 StratfordArapuni Waikato Hydro 197 ArapuniAtiamuri Waikato Hydro 84 AtiamuriHuntly Waikato Coal 1000 HuntlyHuntly e3P Waikato Gas - CCGT 385 HuntlyHuntly P40 Waikato Gas - OCGT 50 HuntlyKarapiro Waikato Hydro 90 KarapiroMaraetai Waikato Hydro 360 MaraetaiMokai Waikato Geothermal 112 WhakamaruOhakuri Waikato Hydro 112 OhakuriWaipapa Waikato Hydro 51 MaraetaiWhakamaru Waikato Hydro 100 WhakamaruWest Wind Wellington Wind 143 West Wind362013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 5: Generation AssumptionsGeneration plant Region Type Operatingcapacity inMWGrid injectionpointArgyle/Wairau Nelson/Marlborough Hydro 11 ArgyleCobb Nelson/Marlborough Hydro 32 CobbColeridge Canterbury Hydro 45 ColeridgeAviemore South Canterbury Hydro 220 AviemoreBenmore South Canterbury Hydro 540 BenmoreOhau A South Canterbury Hydro 264 Ohau AOhau B South Canterbury Hydro 212 Ohau BOhau C South Canterbury Hydro 212 Ohau CTekapo A South Canterbury Hydro 25 Tekapo ATekapo B South Canterbury Hydro 160 Tekapo BWaitaki South Canterbury Hydro 105 WaitakiClyde Otago/Southland Hydro 432 ClydeManapouri Otago/Southland Hydro 840 ManapouriRoxburgh Otago/Southland Hydro 320 RoxburghWaipori 3 Otago/Southland Hydro 84 Halfway Bush1. This value includes an embedded generating unit with a nominal rating of 38 MW that is operating at acontinuous output of 25 MW.2. Tararua stages I and II are both embedded generation.3. Partly embedded.5.2.2 Committed new generationCommitted projects are those which are reasonably likely to proceed and where thefollowing are satisfied:all necessary resource and construction consents have been obtainedconstruction has commenced, or a firm date setarrangements for securing the required land are in placesupply and construction contracts have been executed, andfinancing arrangements are in place.Table 5-2 lists committed grid-connected generation projects.Table 5-2: Committed new generationGeneration plant Region Type Operatingcapacityin MWGrid injectionpointThere are currently no committed new grid connected generation projects.5.2.3 Decommissioned generationGeneration forecasts must also account for decommissioned generation. There hasbeen no decommissioning of generation in 2012. However, Genesis Energy haveplaced one unit of Huntly (250 MW) into long-term storage, and have signalled theyare likely to store a second unit in 2014. Technically units placed into long-termstorage could be recertified and brought back into operation. However, for modellingpurposes we will treat storage as equivalent to decommissioning. 1313http://www.med.govt.nz/sectors-industries/energy/energy-modelling/modelling/electricity-demandand-generation-scenarios/cross-submissions/submission-by-genesis-energy.pdf2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 37

Chapter 5: Generation AssumptionsNew generation forecastsThis year’s APR uses a new set of scenarios, which are again an updated version ofthe scenarios in the Electricity Commission’s 2010 Statement of Opportunities (SoO).What are generation scenarios?Generation scenarios represent possible future generation outcomes, resulting frommaking specific assumptions about future fuel availability and environmental policy.They enable the assessment of transmission needs.Transpower’s scenarios are based on the five generation scenarios in the 2010 SoO:Scenario 1: Sustainable PathScenario 2: WindScenario 3: Medium RenewablesScenario 4: CoalScenario 5: High Gas DiscoveryScenario 1 – Sustainable PathNew Zealand embarks on a path of sustainable electricity development and sectoralemissions reduction. Major development of renewable generation takes place in boththe North and South Islands – mainly hydro, geothermal, and wind, but tidal and waveenergy, solar power and biomass cogeneration also feature. Renewable energyproduction exceeds 90% of total generation from 2020 onwards. Baseload thermalgeneration is largely phased out, but new thermal peakers are required. The demandside also has an important role to play in balancing intermittent generation andmeeting peak demand.Scenario 2 – WindThere is extensive wind and hydro generation development, with a focus on theSouth Island and lower North Island. Geothermal resources in the central NorthIsland are developed more slowly than in the other scenarios. Renewable energyproduction exceeds 85% of total generation (on average) from 2019 onwards.Baseload thermal generation is considerably reduced, but there is substantialinvestment in thermal peaking generation and demand-side participation.Scenario 3 – Medium RenewablesA ‘middle-of-the-road’ scenario. There is moderate geothermal and winddevelopment, mainly in the North Island, but little new hydro generation. Baseloadthermal generation is considerably reduced, but new thermal peakers are required.The demand side contributes less than in the other scenarios. The NZAS aluminiumsmelter is progressively phased out between 2022 and 2027 – no new generationbuild is required over the phase-out period.Scenario 4 – CoalThis is the scenario with the lowest carbon prices, which makes investment in newcoal-fired power stations economic. An efficient new coal-fired power station iscommissioned in 2022; a second, burning Southland lignite, in 2025. Most existingbaseload thermal generation remains online. There is also some renewabledevelopment – but some existing hydro schemes have to reduce their output, owingto difficulty in securing water rights. Intermittent generation is supported by thermalpeaking generation and demand-side response.382013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 5: Generation AssumptionsScenario 5 – High Gas DiscoveryMajor new gas discoveries keep gas prices low over the entire time horizon. Someexisting thermal power stations are replaced by new, more efficient, gas-fired plants.A 200 MW combined cycle gas turbine (CCGT) is installed in Taranaki in 2015, a240 MW CCGT in Northland in 2017, and 400 MW CCGTs in Auckland in 2020 and2025. New gas-fired peakers and gas cogeneration are also constructed. There issome geothermal and wind development but little new hydro generation.Scenario development approachThe Electricity Commission’s scenarios from the 2010 SOO were produced using theGeneration Expansion Model (GEM), which creates a least-cost schedule of newgeneration capacity required to meet forecast demand. See the Electricity Authority’swebsite for more information about GEM. 14The new scenarios described in this document are based on the 2010 SOO scenariosand have been produced using a similar version of GEM with many of the same inputassumptions (including capital and maintenance costs, fuel costs and carbon prices).Transpower has revised some assumptions to bring the scenarios up to date withcurrent information, and to reflect our views about plausible generation and demandsidedevelopment. Key changes include:updating the lists of existing, committed and potential generationusing the APR 2013 demand forecast (as described in Chapter 4)relaxing the GEM security constraints (the original constraints tended to producescenarios with an implausibly high amount of North Island peaking capacity)setting exchange rates to what we would regard as a plausible long-term averagereviewing the potential contribution of demand-side alternatives to managingsystem peaks, andreviewing the range of possible Huntly decommissioning schedules.GEM data files and code are available on request.The scenarios produced by GEM were manually edited so as to increase the diversityof outcomes in some regions (which is important for assessing the range of possibletransmission flows).We have attempted to incorporate the most up to date information about futuregeneration projects. Throughout 2012 the industry re-appraised future generationrequirements in light of 4 years which have seen little demand growth. Subsequentlynearly all large hydro scheme developments have been placed on hold. Theseincluded Meridian Energy’s Mokihinua and North Bank Tunnel schemes, Mighty RiverPower’s Wairau River, and Contact Energy’s Clutha developments. These largehydro schemes are now only included in the MDS post-2020 and this timing is stillfeasible if less likely given the recent announcements.5.3 Use of the generation capacity assumptions5.3.1 Use of generation scenarios in the APRThe generation scenarios are used to assess the effect of generation on the NationalGrid backbone. The generation output is varied to test the transmission capability.Issues that have already been noted are considered again to determine what effect, ifany, the forecast generation will have.14http://www.ea.govt.nz/industry/modelling/in-house-models/gem/2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 39

Chapter 5: Generation Assumptions5.3.2 Grid Injection Point injection forecast assumptionsGrid Injection Point injection forecasts, (required for the GRR), are based on eachgenerator’s operating capacity. For the purposes of assessing local grid injectionpoint adequacy, we base our assessment on ensuring there is adequate transmissioncapacity to fully dispatch each generator rather than making assumptions about howmuch each generator may actually generate in the future.402013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 6: Grid Backbone6 Grid backbone6.1 Introduction6.2 Changes since the 2012 Annual Planning Report6.3 North Island grid backbone overview6.4 North Island grid backbone issues and project options6.5 South Island grid backbone overview6.6 South Island grid backbone issues and project options6.7 HVDC link overview6.8 HVDC link issues and project options6.1 IntroductionThis chapter describes the adequacy of New Zealand’s grid backbone to meetforecast demand, anticipated generation development. Approved development plans,and further development options for the next 15 years are summarised.The grid backbone (see Chapter 3 for more information) provides the connectionbetween the regions. The regions are described in Chapters 7 to 19.Prudent transmission network planning considers a range of generation scenarios tomeet the forecast growth in demand (see Chapters 4 and 5 for more information) todetermine the development option and timing for grid upgrades.Transmission needs for the grid backbone are identified after the commissioning ofcommitted projects. The identification of transmission needs is indicative only, basedon a limited number of load and generation dispatch scenarios, along with the impactof future new generation scenarios. They indicate the possible need for a fullerinvestigation within the forecast period, with the timing and scope of the investigationdetermined by new generation developments and demand growth.The resolving projects to meet the transmission needs are also indicative only, beingpossible solutions that will be subject to the Investment Test. They will be developedthrough the grid planning process as investments to meet the Grid ReliabilityStandard and/or to provide net market benefit.For the North Island, the existing and possible future grid backbones are described inSection 6.3, with issues and possible grid upgrades described in Section 6.4.For the South Island, the existing and possible future grid backbones are described inSection 6.5, with issues and possible grid upgrades described in Section 6.6.The HVDC link is described in Sections 6.7 and 6.8. The Annual Planning Report(APR) assumed that the High Voltage Direct Current (HVDC) Pole 1 is replaced byPole 3 in 2012/13.6.2 Changes since the 2012 Annual Planning ReportTable 6-1 lists the specific issues and projects that are either new or no longerrelevant within the forecast period when compared to last year's report.Table 6-1: Changes since 2012Issues/projectsTransmission capacity into Auckland and NorthlandChangeNIGU project completed, most issuesaddressed (see Section 6.4.2)2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 41

Chapter 6: Grid Backbone6.3 North Island grid backbone overview6.3.1 Existing North Island transmission configurationThe North Island grid backbone comprises the:220 kV circuits from Wellington to Auckland located along the Central NorthIsland corridor, including the recently commissioned double-circuit transmissionlink from Whakamaru to Auckland220 kV Wairakei Ring circuits (220 kV circuits between Wairakei andWhakamaru) connecting the major hydro and geothermal generation in theCentral North Island to the transmission network, and220 kV circuits from Bunnythorpe to Huntly through Stratford connecting Taranakigeneration to the transmission network.Power flows either north or south on the inter-island HVDC link, depending on thetime of day or year. During daylight periods and normal rainfall patterns in the SouthIsland, power tends to flow north. In non-peak periods (late evenings and earlymornings) and years of low South Island rainfall, power tends to flow south.Figure 6-1 shows a simplified schematic of the existing North Island grid backbone.422013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 6: Grid BackboneFigure 6-1: North Island grid backbone schematicOtahuhuPakurangaGlenbrookTakaniniDruryBrownhillHuntlyOhinewaiHamiltonTe KowhaiWhakamaruAtiamuriOhakuriTaumarunuiPoihipiTe MihiTokaanuWairakeiRangipoStratfordTangiwaiBrunswickBunnythorpeLintonKEY220 kV CIRCUIT220 kV SUBSTATION BUSHaywardsGENERATORCAPACITORTEE POINTWilton2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 43

Chapter 6: Grid Backbone6.3.2 Future North Island grid backboneFigure 6-2 and Figure 6-3 provide an indication of the North Island transmissionbackbone development in the medium-term (the next 15 years), and longer-term(beyond 2028), respectively.We are building a new double-circuit transmission line between Wairakei andWhakamaru to replace a lower capacity, single-circuit line.We will resubmit an Investment Proposal to the Commerce Commission to replaceconductor on the existing 220 kV transmission lines between Bunnythorpe andHaywards in the second quarter of 2013. A consequence of the replacement may bean increase in the capacity on these lines.We will also investigate an increase in transmission capacity north of Bunnythorpe,either through the Central North Island to Whakamaru, and/or through the Taranakiregion and a new line to Whakamaru.In the longer term, we may increase the transmission capacity through the NorthIsland by increasing the operating voltage on the new overhead transmission line intoAuckland to 400 kV. Ultimately we may build a new transmission line connectingBunnythorpe, Whakamaru, and Auckland, but this is highly dependent on future loadand generation growth, and the viability of alternatives.We will also strengthen the resilience of some critical substations to high impact lowprobability events.Voltage stability in the Upper North Island is an ongoing issue. We will provideadditional reactive support to maintain Upper North Island voltage stability as regionalload continues to grow.442013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 6: Grid BackboneFigure 6-2: Indicative North Island grid backbone schematic to 2028OtahuhuPakurangaTakaniniGlenbrookDruryBrownhill** new double circuit transmission line constructed for400 kV operation but initially operated at 220 kV.OhinewaiHuntlyHamiltonTe KowhaiWhakamaruAtiamuriOhakuriTaumarunuiTokaanuTe MihiPoihipiWairakeiRangipoStratfordTangiwaiBrunswickBunnythorpeLintonKEYParaparaumuNEW ASSETSUPGRADED ASSETSHaywardsWilton2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 45

Chapter 6: Grid BackboneFigure 6-3: Longer-term indicative North Island grid backbone schematic beyond 2028OtahuhuPakuranga400 kVTakanini220 kVBrownhill**GlenbrookDrury***400 kVAlthough this diagram shows a fewpossible development paths for thefuture North Island grid backbonetransmission system, it is not intendedto indicate a preference. Any optionwill be finalised closer to the date thattransmission reinforcement is needed.OhinewaiHuntlyHamilton400 kV* Another possible option is a newHVDC link into Auckland.** New grid exit point(s) south ofOtahuhu, possibly:- north of Drury, and/or- at Brownhill Road by extending the220 kV bus.Te KowhaiWhakamaruAtiamuriOhakuriTaumarunuiMokaiTokaanuTe MihiPoihipiWairakeiRangipoStratfordTangiwaiBrunswickBunnythorpeParaparaumuLintonKEYNEW ASSETSUPGRADED ASSETSWiltonHaywards6.4 North Island grid backbone issues and project optionsThe North Island grid backbone comprises five areas indicated in Figure 6-4. Table6-2 summarises issues involving the grid backbone for the next 15 years. For moreinformation about a particular issue, refer to the listed section number in Table 6-2.462013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 6: Grid BackboneFigure 6-4: North Island grid backbone areaUpper NorthIsland areaWairakei Ring areaTaranaki areaCentral NorthIsland areaWellington areaTable 6-2: Grid backbone transmission issuesSectionnumberIssue6.4.1 Upper North Island voltage stability6.4.2 Transmission capacity into Auckland and Northland6.4.3 Wairakei Ring transmission capacity6.4.4 Taranaki transmission capacity6.4.5 Central North Island transmission capacity2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 47

Chapter 6: Grid BackboneSectionnumberIssue6.4.6 Wellington area transmission capacity6.4.1 Upper North Island voltage stabilityOverviewThe Upper North Island covers the geographical area north of Huntly, includingGlenbrook, Takanini, Auckland, and the North Isthmus.The transmission capability to supply the Upper North Island load is limited by voltagestability, which in turn is influenced by:generation in Auckland and at Huntlythe reactive power losses due to the transmission system within the Upper NorthIslandthe reactive power losses due to the transmission system supplying the UpperNorth Island area, andthe reactive power demand due to the composition of the load in the area (inparticular the proportion and type of motor load).There are several generator and circuit contingencies that can cause voltage controlproblems. The worst contingencies include the loss of the:Pakuranga–Whakamaru–1 or 2 circuitsOtahuhu combined-cycle gas turbine generatorHuntly E3P generator (Unit 5)220 kV Huntly–Takanini–Otahuhu–2 circuit, or220 kV Drury–Huntly–1 circuit.The Upper North Island load includes a significant proportion of motor load. Thebehaviour of this load during and following faults influences the regional transmissionvoltage performance. During a severe fault, motors will decelerate and some canstall. The motors will then draw large currents which in turn delay the voltagerecovery after a fault. We have identified that voltage recovery is most at risk in latesummer between mid-January and mid-March, when the greatest amount of motorload is connected.Reactive losses on heavily loaded transmission lines are significant, especiallyfollowing a circuit tripping when the loading of parallel circuits increases.The Upper North Island has an enduring need for voltage support because of itsreliance on long transmission lines from the south for much of its power. Somecomponent of reactive power support in the Auckland region must be dynamic toavoid the need for shunt capacitor switching after a transmission or generatorcontingency. The dynamic reactive support may be provided by generators,synchronous condensers, static var compensators (SVCs) or static synchronouscompensators (STATCOMs).Approved projectsInvestments in previous years included an SVC at Albany, binary switched capacitorsat Kaitaia, ten capacitor banks totalling 600 Mvar at four substations 15 , and ashort-term contract for reactive support from condensers at Otahuhu 16 .15Capacitors installed in previous years are: Albany 1 x 100 Mvar, Hepburn Road 3 x 50 Mvar,Penrose 4 x 50 Mvar, and Otahuhu 2 x 100 Mvar.482013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 6: Grid BackboneWe have installed power system monitoring equipment to improve our understandingof the Upper North Island power system, specifically load composition and responseto transient events.Projects approved in 2010 by the Electricity Commission under Part F of theElectricity Governance Rules include:a STATCOM at Penrose, scheduled for commissioning in 2013two STATCOMs at Marsden, scheduled for commissioning in 2014a Reactive Power Controller (RPC) to co-ordinate the various dynamic and staticdevices in the Upper North Island, scheduled for commissioning in 2015/2016,anddemand-side participation.We issued a Request For Proposals for demand-side participation, but the proposalsreceived were all uneconomic. This was an unexpected result, and the demand-sideparticipation framework is being further developed to unlock its potential (see Section2.2 for more information).Other approved projects also have a beneficial effect on voltage stability in the UpperNorth Island by reducing the reactive power losses in the transmission system.The North Auckland and Northland (NAaN) project that increases thetransmission capacity in the Auckland and Northland regions (see Chapter 7,Section 7.8.4 for more information).The recently commissioned North Island Grid Upgrade (NIGU) project thatincreases the transmission capacity into the Auckland and Northland regions (seeSection 6.4.2 for more information).Even with these approved projects, voltage stability will be an ongoing issue.Resolving projectsWe have completed an investigation to determine the amount of additional reactivesupport required to relieve the Upper North Island voltage stability issue beyond thecompletion of the NAaN and NIGU projects. This project indicated that additionalreactive support will be required within the next fifteen years. This will be a mixtureof:shunt capacitors, in the next five years, some installed in the Northland region toalso address local voltage issues (see Chapter 7 section 7.8.7 for details)dynamic support such as STATCOMs, in approximately ten years.Advancing the series capacitors on the new transmission link between Whakamaruand Pakuranga will also improve voltage stability in the region.6.4.2 Transmission capacity into Auckland and NorthlandOverviewPower transfer to the Upper North Island is dependent on:the generation from Huntly, and the transmission capacity between Huntly andOtahuhu, andgeneration from Whakamaru and south of Whakamaru, and the transmissioncapacity between Whakamaru and Otahuhu.Eight 220 kV circuits from the south primarily supply the Upper North Island, withthree diverse routes, comprising:16The condensers belong to Contact Energy, and were once operated as gas turbine generators. Thecontract for the condensers expires in 2013 and will not be renewed, as it is more economic to installother reactive support such as STATCOMs.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 49

Chapter 6: Grid Backbonetwo circuits from Huntly to Otahuhu (the western path)four circuits from Whakamaru to Otahuhu (the central path), andtwo circuits from Whakamaru to Pakuranga (the eastern path).There are also two circuits between Huntly and Ohinewai connecting the western andcentral paths.The Auckland region is also connected by two smaller 110 kV regional circuits fromArapuni via Hamilton, Bombay, and Wiri to Otahuhu, though their contribution isminor compared to the 220 kV circuits.The recently completed North Island Grid Upgrade (NIGU) project either removed orsignificantly reduced issues with the transmission capacity into Auckland andNorthland. Issues that may still arise during periods of high demand and lowgeneration in the Auckland area include:an outage of the Hamilton–Whakamaru circuit may overload the two 110 kVArapuni–Hamilton regional circuits.an outage of the Hamilton–Ohinewai circuit may cause low voltage at theHamilton 220 kV busan outage of an Otahuhu 220 kV bus section may overload the Bombay–Hamilton circuits (see chapter 9 section 9.9.3)an outage of a Whakamaru 220 kV bus section may result in unmanageablepower flows in the parallel 110 kV network.Approved projectsThe NIGU project has been recently completed. There are no other approvedprojects to increase the transmission capacity into Auckland and Northland.There is a 220 kV connection between Otahuhu and Pakuranga within the Aucklandregion. There is also a North Auckland and Northland (NAaN) project that makes useof the transmission capacity and diversity provided by Pakuranga to increase thecapacity and security within the Auckland and Northland regions (see Chapter 7,Section 7.8.4).Figure 6-5 shows the grid backbone circuits supplying the Upper North Island area.502013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 6: Grid BackboneFigure 6-5: 220 kV Upper North Island grid backbone circuitsOtahuhuPakurangaGlenbrookTakaniniDruryBrownhillOhinewaiHuntlyCircuitDrury–Huntly–1Drury–Glenbrook–1 and 2Drury–Takanini–Otahuhu–1Huntly–Ohinewai–1 and 2Huntly–Takanini–2Hamilton–Ohinewai–1Hamilton–Whakamaru–1Ohinewai–Otahuhu–1 and 2Ohinewai–Whakamaru–1Otahuhu–Whakamaru–1 and 2Otahuhu–Takanini–2Pakuranga–Whakamaru–1 and 2Summer/Winterrating694/764 MVA694/762 MVA1140/1200 MVA694/764 MVA694/764 MVA615/671 MVA615/671 MVA615/671 MVA615/671 MVA293/323 MVA*678/724 MVA633/676 MVA*These circuits have variable line ratings, the ratingprovided is the planning ratingHamiltonWhakamaruThe following sections assess the transmission capability of the circuits into theAuckland and Northland regions. The assessment is based on representative systemconditions, to determine how different generation development scenarios interact withthe circuits into Auckland and Northland.System condition 1 (normal summer’s day demand)This system condition tests a low generation scenario in the Auckland and Northlandregions during a normal demand period, specifically:normal summer’s day load in the North Island (approximately 85% of summerpeak load)no thermal generation in Auckland and Northland in servicelow renewable generation in Auckland and Northland, andmedium to high generation elsewhere.The circuits into the Auckland and Northland regions have sufficient capacity during anormal demand period and low generation in the Auckland and Northland regions forthe duration of the forecast period.However, this system condition will cause the power flows in the 110 kV networkbetween Tarukenga and Hamilton to become unmanageable from around 2019. Theworst contingency is an outage of the Whakamaru 220 kV bus section thatdisconnects the Atiamuri–Whakamaru and Hamilton–Whakamaru circuits.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 51

Chapter 6: Grid BackboneSystem condition 2 (peak demand)This system condition tests high demand in the Auckland and Northland regionsalong with the outage of the biggest generator, specifically:island peak load in the North Islandhigh generation in the North Islandthe biggest generator in Auckland is out of service, i.e. Otahuhu CCGT, andmoderate thermal generation in Northland, Auckland and Huntly. 17The Hamilton bus voltage may fall below 0.9 p.u. for the loss of the Hamilton–Ohinewai circuit towards the end of the forecast period, particularly when power flowthrough the Central North Island 220 kV circuits are high.This system condition also causes the power flows in the 110 kV network betweenTarukenga and Hamilton to become unmanageable from about 2024. The worstcontingency is an outage of the Whakamaru 220 kV bus section that disconnects theAtiamuri–Whakamaru and Hamilton–Whakamaru circuits.Impact of generation scenariosThe five generation scenarios described in Chapter 5 have the following impacts onthe circuits into Auckland and Northland.For system condition 1, all the generation scenarios have minimal impact within theforecast period.For system condition 2, although the voltage at Hamilton is low for all generationscenarios, it will not fall below 0.9 p.u. as all scenarios include some additionalgeneration in the Northland, Auckland and Waikato regions resulting in reducedpower flows through the Central North Island, provided the generation is dispatched.OutagesAn outage of one of the circuits into Auckland and an outage of the biggest generatorin Auckland still maintains n-1 security into Auckland and Northland.Resolving projectsWe will investigate options to resolve the Hamilton bus voltage issue closer to thetime it occurs (see Chapter 9, Section 9.9.3 for more information).We will investigate the 220 kV bus configuration at Whakamaru to confirm the mostoptimal configuration to manage power flows in the grid backbone and the parallel110 kV network. Any changes are likely to be operational.We recently completed an economic analysis to optimise the timing of seriescompensation on the new Pakuranga–Whakamaru circuits. This analysis showedthat it may be economic to install series compensation in 2019 to minimise systemlosses. We anticipate commencing a more detailed investigation of this option in2014.Beyond 15 years, the double-circuit overhead line from Whakamaru to Brownhill willbe converted from 220 kV to its construction voltage of 400 kV. This will also require:220/400 kV transformers and associated works at Whakamaru substation tointerconnect with the existing 220 kV systema switchyard in the vicinity of the transition station at Brownhill with 220/400 kVtransformers and associated works17Generation in the Northland, Auckland and Huntly area assumed for this system condition is690 MW at Huntly and 155 MW at Southdown.522013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 6: Grid Backbone220 kV underground cables to the Otahuhu substation, andextensions to the Otahuhu switchyard(s).6.4.3 Wairakei Ring transmission capacityOverviewThe Wairakei Ring circuits:connect the major hydro and geothermal generation stations in the North Islandto the grid backbone, andsupply the Bay of Plenty region from Atiamuri and Ohakuri.In addition, a new geothermal power station is being commissioned at Te Mihi, and anumber of other generation stations which connect directly or indirectly to theWairakei Ring are in various stages of planning or construction.For the existing system, as this generation develops, an outage of one of theWairakei Ring circuits may begin to constrain north power flows. Specifically, anoutage of the:Whakamaru–Te Mihi–Wairakei circuit may overload the Wairakei–Ohakuri–Atiamuri circuitsWairakei–Ohakuri–Atiamuri circuits may overload the Whakamaru–Poihipi–Wairakei circuit.Approved projectsTo address the above issues, we are building a 220 kV double-circuit line betweenWairakei and Whakamaru, to replace the existing single-circuit Wairakei–Whakamaru–B line. The line is scheduled for commissioning in 2013, and willincrease the power flow capacity through the Wairakei Ring. We recentlycommissioned the new substation at Te Mihi, which will feed into this line.Figure 6-6 shows the grid backbone circuits in the Wairakei Ring area after thecommissioning of the Wairakei Ring project.Figure 6-6: 220 kV Wairakei Ring circuitsWhakamaruAtiamuriOhakuriCircuitOhakuri–Wairakei–1Atiamuri–Ohakuri–1Atiamuri–Whakamaru–1Wairakei–Whakamaru–1Wairakei–Te Mihi–Whakamaru–1Summer/Winterrating333/358 MVA*333/358 MVA*333/358 MVA903/994 MVA903/994 MVATe MihiPoihipiWairakei*These circuits have variable line ratings, the ratingprovided is the planning ratingThe following sections assess the Wairakei Ring transmission capability following thecommitted Wairakei to Whakamaru Replacement Line Project. The assessment isbased on representative system conditions, to determine how different generationdevelopment scenarios interact with the Wairakei Ring.System condition 1A (high north flow)This system condition tests power flowing north through the circuits in the WairakeiRing towards the Upper North Island, with power flow through the Central NorthIsland up to the capacity of its existing transmission capacity (see section 6.4.5),specifically:2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 53

Chapter 6: Grid Backboneisland peak load in the North Islandmoderate thermal generation in Northland, Auckland and Huntly 18high geothermal generation in the Wairakei Ring areaHVDC north transfer 600 MW, andmedium to high generation (including peakers) elsewhere to balance generationwith demand (including maximum generation in Taranaki and Wellington areas).There will be no thermal constraints if:the HVDC transfer and/or Taranaki generation is constrained to preventoverloading of the Central North Island circuits between Bunnythorpe andWhakamarugeneration in the Wairakei ring does not exceed the existing committed level.System condition 1B (very high north flow)This system condition tests power flowing north through the circuits in the WairakeiRing towards the Upper North Island, assuming higher transmission through theCentral North Island (see section 6.4.5) is possible using variable line ratings and/orspecial protection schemes 19 , specifically:island peak load in the North Islandmoderate thermal generation in Northland, Auckland and Huntly 20high geothermal generation in the Wairakei Ring areaHVDC north transfer 900 MW, andmedium to high generation (including peakers) elsewhere to balance generationwith demand (including maximum generation in Taranaki and Wellington areas).The following issues were identified, if Central North Island transmission capacityincreased:The Atiamuri–Ohakuri and Ohakuri–Wairakei circuits may come close tooverloading for an outage of either the new Te Mihi–Whakamaru or Wairakei–Whakamaru circuitsThe Atiamuri–Ohakuri and Ohakuri–Wairakei circuits may overload for an outageof the Whakamaru 220 kV bus that connects a Tokaanu–Whakamaru and TeMihi–Whakamaru circuits.Also, high generation at Kawerau and low demand in the Bay of Plenty may causehigher circuit loading on the Atiamuri–Ohakuri circuit especially during high north flowthrough the Wairakei Ring circuits. In this scenario, the Atiamuri–Ohakuri circuit mayalso overload for an outage of the Edgecumbe–Kawerau circuit.System condition 2 (south flow)This system condition tests power flowing south through the circuits in the WairakeiRing towards the Wellington region and the South Island via the HVDC link,specifically:low North Island load (approximately 45% of peak load)high geothermal generation in the Wairakei Ring area181920Generation in the Northland, Auckland and Huntly area assumed for this system condition is690 MW at Huntly and 155 MW at Southdown.Using variable line rating and/or special protection schemes keeps the system impedanceunchanged. Other upgrade options, such as duplexing existing lines or a new line, changes thesystem impedance. A change in system impedance for the Central North Island will change theoverloads in the Wairakei ring.Generation in the Northland, Auckland and Huntly area assumed for this system condition is690 MW at Huntly and 155 MW at Southdown.542013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 6: Grid Backbonemedium to low generation elsewhere, andHVDC south transfer up to 900 MW.The Wairakei Ring circuits have sufficient capacity for south power flows for theduration of the forecast period. However, there may be transmission constraintssouth of the Wairakei Ring (see Section 6.4.5).System condition 3 (east flow)This system condition tests the ability of the Wairakei Ring circuits to supply the Bayof Plenty region during high demand and medium generation in that region,specifically:island peak load in North Islandhigh geothermal generation in the Wairakei Ring areamedium generation in the Bay of Plenty region with the biggest generator in theregion out of service (Kawerau geothermal generator is out of service).medium to high generation (including peakers) elsewhere to balance generationwith demand, andHVDC north transfer but not exceeding 1,400 MW.The following issues were identified:The Ohakuri–Wairakei circuit may overload for an outage of the Atiamuri–Whakamaru, Te Mihi–Whakamaru or Wairakei–Whakamaru circuits.The Atiamuri–Whakamaru circuit may overload for an outage of the Ohakuri–Wairakei circuitThe Ohakuri–Wairakei circuit may overload for the outage of a 220 kV bus atWhakamaru, Atiamuri or Wairakei.The Atiamuri–Whakamaru circuit may overload for the outage of a 220 kV bus atWairakei.Impact of generation scenariosThe five generation scenarios described in Chapter 5 have the following impacts onthe Wairakei Ring circuits.For system condition 1 (north power flow through the Wairakei Ring circuits to supplythe Upper North Island), all of the generation scenarios have a substantial impact onWairakei Ring power flows. Higher levels of power flow through the Wairakei Ringmay overload the Atiamuri–Ohakuri, Ohakuri–Wairakei and Atiamuri–Whakamarucircuits. Generation scenario 1 (‘sustainable path’) has the most significant impact,as it has the highest net increase in the Bay of Plenty and Wairakei areas comparedto the other generation scenarios.For system condition 2 (south power flow through the Wairakei Ring circuits), all ofthe generation scenarios may cause overloading on the circuits between Wairakeiand Bunnythorpe due to additional generation in the Wairakei Ring. Also, theOhakuri–Atiamuri–Whakamaru circuit may overload for an outage of the Te Mihi–Whakamaru circuit, as this outage causes some power to flow from Wairakei, north toWhakamaru and then south to Bunnythorpe. Generation scenario 1 (‘sustainablepath’) and scenario 3 (‘medium renewables’) have the biggest impact on power flowsin the Wairakei ring for this condition.For system condition 3 (east power flow through the Wairakei Ring), generationscenario 5 (‘high gas discovery’) has the highest impact on circuits supplying the Bayof Plenty region. This generation scenario has the lowest net increase in generationin the Bay of Plenty region. Therefore, there are higher levels of power flow throughthe Wairakei Ring to supply the Bay of Plenty region, which may overload theWairakei–Ohakuri–Atiamuri–Whakamaru circuits.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 55

Chapter 6: Grid BackboneOutagesThe main connection to the Bay of Plenty region is through the Wairakei–Ohakuri andAtiamuri–Whakamaru circuits. An outage of either circuit puts the whole Bay ofPlenty region on n security.Outages of the Wairakei–Whakamaru and Wairakei–Te Mihi–Whakamaru circuits arealso likely to cause generation constraints, requiring replacement generation in otherareas such as the Auckland region.Resolving projectsDuring peak demand periods in the Bay of Plenty region, generation must run in theregion to prevent overloading of the Wairakei–Ohakuri–Atiamuri–Whakamaru circuits.Historically, generation in the Bay of Plenty region has been available during peakperiods, and we expect this will continue in the short term. However, in the longerterm, the region’s dependence on local hydro generation may expose it to insufficienttransmission capacity within the Wairakei Ring in dry years.Transmission solutions to prevent overloading of the Wairakei–Ohakuri–Atiamuri–Whakamaru circuits include:variable line ratings, which will alleviate some of the overloads in the short termreconductoring the Wairakei–Ohakuri–Atiamuri circuits, followed by the Atiamuri–Whakamaru circuit, if required, orconstructing a new 220 kV Wairakei–Atiamuri circuit (bypassing Ohakuri) asstage 1, followed by a second Atiamuri–Whakamaru circuit, if necessary, asstage 2.The Wairakei–Ohakuri–Atiamuri–Whakamaru circuits have already been thermallyupgraded, and a further thermal upgrade is not technically feasible. A secondWairakei–Atiamuri circuit is one option which keeps the Bay of Plenty region on n-1security during outages of the Wairakei–Ohakuri or Atiamuri–Whakamaru circuits. Itis unlikely that lack of security to the Bay of Plenty during outages will by itself providesufficient benefit to justify the second circuit.We will monitor the generation developments in the Wairakei Ring area and the Bayof Plenty region, to determine if a transmission upgrade investigation is required.6.4.4 Taranaki transmission capacityOverviewTaranaki generation is connected to the North Island grid backbone via Stratford withtwo 220 kV circuits north to Huntly and two circuits south to Bunnythorpe.Figure 6-7 shows the grid backbone circuits for the Taranaki area betweenBunnythorpe and Huntly.562013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 6: Grid BackboneFigure 6-7: 220 kV circuits between Bunnythorpe and HuntlyHuntlyTe KowhaiStratfordTaumarunuiCircuitSummer/WinterratingBunnythorpe–Brunswick–1 and 2 695/712 MVA 1Brunswick–Stratford–1, 2, and 3232/287 MVAHuntly–Stratford–1 354/354 MVA 1Stratford–Taumarunui–1 (from Stratford) 455/455 MVA 2Stratford–Taumarunui–1 (from Taumarunui) 343/343 MVA 2Taumarunui–Te Kowhai–1469/492 MVAHuntly–Te Kowhai–1 (from Huntly) 301/301 MVA 2Huntly–Te Kowhai (from Te Kowhai) 469/492 MVA 21. This rating is due to a component other than the conductor.2. The circuit rating depends on the direction of power flow. This is due toprotection settings.BrunswickBunnythorpeApproved projectsThere are no approved grid backbone projects in the Taranaki area.The following sections assess the Taranaki transmission capability following thecommitted upgrades in the North Island. The assessment is based on representativesystem conditions, to determine how different generation development scenariosinteract with the circuits out of Taranaki.System condition 1 (north flow)This system condition tests power flowing north through the circuits between Stratfordand Huntly to Auckland and Northland:island peak load in the North Islandhigh generation in Taranakithe biggest generator in Auckland is out of service i.e. Otahuhu CCGTmoderate generation in the Northland, Auckland and Huntly area 21medium to high generation elsewhere to balance generation with demand, andHVDC north transfer varies between 900 MW and 1,200 MW depending ongeneration and demand in the North Island.21Generation in the Northland, Auckland and Huntly area assumed for this system condition is690 MW at Huntly and 155 MW at Southdown.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 57

Chapter 6: Grid BackboneFor this system condition, an outage of one of the Huntly–Stratford circuits mayoverload the other circuit and may also lead to dynamic and transient instability.For high levels of generation in the Taranaki area, power also flows to Bunnythorpebefore flowing north through the Central North Island grid backbone 22 .System condition 2 (south flow)This system condition tests power flowing mainly south through the circuits betweenStratford and Bunnythorpe to the HVDC link, specifically:low North Island load (approximately 45% of peak load)high generation in Taranakimedium to low generation elsewhere to balance generation with demand, andHVDC south transfer of between 700 MW and 1000 MW, depending ongeneration and demand in the North Island.For this system condition, an outage of one of the Brunswick–Stratford circuits mayoverload the remaining two Brunswick–Stratford circuits 23 during summer ratings.The 110 kV circuits between Stratford and Waverley may also overload due to thelimiting station equipment at Hawera.Impact of generation scenariosThe five generation scenarios described in Chapter 5 have the following impacts onthe circuits out of Taranaki.For system condition 1 (north power flow from Stratford to Huntly), generationscenario 5 (‘high gas discovery’) has the highest impact at the end of the forecastperiod, as it has the highest net increase in generation in the Taranaki area. Theoverloads on the Huntly–Stratford circuits are dependent on:Auckland and Northland loadAuckland and Northland generationTaranaki generation, andlower North Island generation.For system condition 2 (south power flow from Stratford to Bunnythorpe), all thegeneration scenarios have minimal impact within the forecast period on the Taranakitransmission capacity except for generation scenario 5 (‘high gas discovery’).Generation scenarios 1 to 4 include the decommissioning of the Taranaki combinedcyclegas turbine while generation scenario 5 does not. This scenario has a netincrease of up to 410 MW of new gas-fired peakers and combined-cycle gas turbines.Some of the generation scenarios may result in overloads on the parallel 110 kVcircuits between Stratford and Bunnythorpe.OutagesAn outage of any of the circuits out of Taranaki i.e. between Stratford and Huntly orbetween Stratford and Bunnythorpe, may cause generation constraints, which requirereplacement generation in other areas.2223Central North Island 220 kV circuits such as Tokaanu–Whakamaru may overload during highTaranaki generation and HVDC north flow. See Section 6.4.5 for more information about this issue.Central North Island 220 kV circuits such as Bunnythorpe–Tokaanu and Bunnythorpe–Tangiwai mayoverload before the Brunswick–Stratford circuits overload for high HVDC south flow. See Section6.4.5 for more information about this issue.582013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 6: Grid BackboneResolving projectsTo prevent overloading on the circuits out of Taranaki during HVDC north and southflow, the Taranaki generation can be constrained. Alternatively, transmissionsolutions could include:thermally upgrading and/or reconductoring the Brunswick–Stratford circuitsreconductoring the Huntly–Stratford circuits 24 , orconstructing a new transmission line between Taumarunui and Whakamaru.To resolve the overloads on the 110 kV circuits, we are planning to rebuild theHawera 110 kV bus (see chapter 12 section 12.8.2 for more information).The tuning of the generator excitation systems and power system stabilisers affectsthe transient and dynamic stability to transfer power out of Taranaki betweenStratford and Huntly. However a stability limitation remains possible under certainsystem conditions particularly during circuit outages. We will monitor the generationdevelopments in the Taranaki region to determine if a transmission upgradeinvestigation is required.6.4.5 Central North Island transmission capacityOverviewThe circuits between Bunnythorpe and Whakamaru/Wairakei comprise the:two Bunnythorpe–Tokaanu–Whakamaru circuits, andBunnythorpe–Tangiwai–Rangipo–Wairakei circuits.Figure 6-8 shows the grid backbone circuits in the Central North Island area.Figure 6-8: 220 kV Central North Island circuitsWhakamaruTokaanuWairakeiRangipoTangiwaiCircuitBunnythorpe–Tokaanu 1 and 2Bunnythorpe–Tangiwai 1Rangipo–Tangiwai 1Rangipo–WairakeiTokaanu–Whakamaru 1 and 2Summer/Winterrating307/335 MVA239/291 MVA239/291 MVA364/396 MVA307/335 MVABunnythorpe24The Huntly–Stratford circuits have a maximum operating temperature of 120°C, which is themaximum practical operating temperature. Therefore, a thermal upgrade is not possible.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 59

Chapter 6: Grid BackboneApproved projectsThere are no grid backbone approved projects in the Central North Island area.The following sections assess the transmission capability of the Central North Islandgrid backbone following the committed upgrades in the North Island. Theassessment is based on representative system conditions, to determine how differentgeneration development scenarios interact with the circuits in the Central NorthIsland.System condition 1 (north flow)This system condition tests power flowing north through the circuits in the CentralNorth Island towards Whakamaru or Wairakei, specifically:island peak load in the North Islandhigh renewable generation including wind, wave, tidal, and solarmedium generation (including peakers) elsewhere to balance generation withdemand, andHVDC north transfer varies between 600 MW and 1,000 MW depending onTokaanu generation.For high generation in the Taranaki area, some of the Taranaki generation flows intoBunnythorpe. This can cause an overload on the Central North Island circuits.The following issues were identified.A Tokaanu–Whakamaru circuit may overload for an outage of the otherTokaanu–Whakamaru circuit, any of the Bunnythorpe–Tangiwai–Rangipo–Wairakei circuits, or one of the circuits between Stratford and Huntly.A Bunnythorpe–Tokaanu circuit may overload for an outage of the otherBunnythorpe–Tokaanu circuit or any section of the Bunnythorpe–Tangiwai–Rangipo–Wairakei circuit.The Bunnythorpe–Tangiwai–Rangipo–Wairakei circuits may overload for anoutage of a Bunnythorpe–Tokaanu–Whakamaru circuit.The Tokaanu–Whakamaru circuits may overload for a Wairakei, Whakamaru orTokaanu 220 kV bus outage.The Bunnythorpe–Tokaanu circuits may overload for a Wairakei, Bunnythorpe orWhakamaru 220 kV bus outage.The Bunnythorpe–Tangiwai–Rangipo–Wairakei circuits may overload for aBunnythorpe, Tokaanu or Whakamaru 220 kV bus outage.There is a regional 110 kV single circuit between Bunnythorpe and Arapuni (viaMataroa, Ohakune, and Ongarue) which will overload before the 220 kV circuitsconstrain north transfer.System condition 2 (south flow)This system condition tests power flowing south through the circuits in the CentralNorth Island towards Bunnythorpe:low North Island load (approximately 45% of peak load)low renewable generation including wind, wave, tidal, and solarhigh geothermal generation in the Wairakei Ring arealow generation elsewhere to balance generation with demand, andHVDC south transfer varies between 700 MW and 1000 MW depending onTokaanu generation.The following issues were identified.602013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 6: Grid BackboneThe Bunnythorpe–Tangiwai–Rangipo circuits may overload for outages of aBunnythorpe–Tokaanu–Whakamaru circuit or a Wairakei–Te Mihi–Whakamarucircuit in the Wairakei ring.The Bunnythorpe–Tangiwai–Rangipo circuits may overload for a Bunnythorpe,Tokaanu or Whakamaru 220 kV bus outage.A Bunnythorpe–Tokaanu circuit may come close to overloading for an outage ofthe other Bunnythorpe–Tokaanu circuit or a Bunnythorpe 220 kV bus section.There is also low voltage at Bunnythorpe, Tangiwai, and Tokaanu for high HVDCsouth transfer and low generation in the Lower North Island.Impact of generation scenariosThe five generation scenarios described in Chapter 5 have the following impacts onthe Central North Island circuits.For system condition 1 (north power flow from Bunnythorpe to Whakamaru/Wairakei),generation scenario 2 (‘Wind’) and 5 (‘high gas discovery’) have the largest netincrease of generation into Bunnythorpe. Scenario 2 has generation flow from theWellington region, and scenario 5 has generation flow from the Taranaki region. Theadditional generation increases power flows through the Central North Island,assuming the new generation displaces thermal and hydro generation in the upperNorth Island, which will increase the overloading on the circuits.For system condition 2 (south power flow from Whakamaru/Wairakei toBunnythorpe), generation scenario 4 (‘coal’) has the highest impact on the circuits inthe Central North Island, as it has the lowest net increase in generation in theWellington area. With a reduced amount of new generation in the Wellington area,more power is required to flow through the circuits between Whakamaru/Wairakeiand Bunnythorpe to supply demand in the Wellington area and the South Island viathe HVDC link. Low voltage at Bunnythorpe, Tangiwai, and Tokaanu will also occurin later years.OutagesAn outage of any of the Central North Island circuits may cause generationconstraints, which require replacement generation in other areas.Resolving projectsFor the circuits between Whakamaru and Bunnythorpe, the requirement to upgrade islargely dictated by generation development in the area. The upgrade options can beseparated into two tranches depending on the amount of new generation.In tranche 1, the range of options includes:limiting the power flow on 110 kV regional network between Mataroa andOhakune through a Special Protection Scheme (SPS), series reactor or apermanent system split (putting four regional grid exit points on n security)reconductoring the Tokaanu–Whakamaru circuits, andthermally upgrading or reconductoring the Bunnythorpe–Tangiwai–Rangipocircuits.Tranche 1 options may enable up to 500 MW of new generation (at n security)connected at or near to Bunnythorpe. The project cost falls within band F.In tranche 2, the range of options will enable more generation beyond the options fortranche 1. The range of options includes:reconductoring the Bunnythorpe–Tokaanu circuitsproviding new transmission capacity between Bunnythorpe and Whakamaru by:2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 61

Chapter 6: Grid Backbone• reusing the existing 220 kV single circuit line route between Bunnythorpe andWairakei for a replacement double-circuit• constructing a new double-circuit 220 kV or 400 kV circuit betweenBunnythorpe and Whakamaru, or• constructing an HVDC ‘light’ link between Bunnythorpe and Whakamaru.Constructing a new line from Taumarunui to Whakamaru (to divert power flowfrom the Central North Island grid backbone), andInstalling a Lower North Island-wide System Protection Scheme to enable newgeneration.The details and range of options in tranche 2 will be investigated.We will monitor generation developments in the Central North Island area, todetermine the level of transmission upgrades required including the need for reactivedevices to alleviate the low voltage issues.6.4.6 Wellington area transmission capacityOverviewThe 220 kV circuits in the Wellington area between Bunnythorpe and Wellingtoncomprise:two circuits connecting directly between Haywards and Bunnythorpeone Haywards–Linton–Bunnythorpe circuit, with Tararua Wind Central connectedoff the Linton–Bunnythorpe section of the circuit, andone Wilton–Linton–Bunnythorpe circuit.Figure 6-9 shows the grid backbone circuits in the Wellington area.Figure 6-9: 220 kV circuits in the Wellington areaBunnythorpeLintonHaywardsCircuitBunnythorpe–Haywards 1 and 2Bunnythorpe–Linton–Wilton 1Bunnythorpe–Tararua Wind Central–Linton 1Haywards–Linton 1Haywards–Wilton 1Summer/Winterrating307/335 MVA694/764 MVA694/764 MVA694/762 MVA694/762 MVAWiltonWe have recently commissioned a special protection scheme on the 110 kVBunnythorpe–Woodville circuits. This scheme enables higher HVDC transfer byreducing constraints on the parallel 110 kV network.Approved projectsThere are no approved grid backbone projects for the Wellington area.We submitted an Investment Proposal to the Commerce Commission in December2011 to reconductor the two direct Bunnythorpe–Haywards circuits because ofcondition assessment. We took the opportunity to also provide an incrementalincrease in the capacity of the circuits. The Commerce Commission challenged theeconomic justification for increasing the capacity. We are investigating alternative622013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 6: Grid Backboneoptions. We anticipate seeking approval from the Commission for an alternative planin the second quarter of 2013.The project cost falls within band F and construction is expected to be completed bythe fourth quarter of 2019.The following sections assess the Wellington area’s transmission capability followingthe committed upgrades in the North Island. The assessment is based onrepresentative system conditions, to determine how different generation developmentscenarios interact with the circuits in the Wellington area.System condition 1 (HVDC north flow)This system condition tests power flowing north through the circuits in the Wellingtonarea towards Bunnythorpe, specifically:off-peak load in the Wellington region (between 30-90% of summer peak load)summer peak load in the rest of the North Islandhigh renewable generation including wind, wave, tidal, and solarmedium to high generation (including peakers) elsewhere to balance generationwith demand, andHVDC north transfer varies between 800 MW and 1,200 MW depending on NorthIsland generation and demand.The following issues were identified:A Bunnythorpe–Haywards circuit may overload for a Bunnythorpe 220 kV busoutage.The regional Bunnythorpe-Woodville circuits may overload for a Bunnythorpe orHaywards 220 kV bus outage.High power flows on the regional 110 kV circuits between Bunnythorpe–Woodville aremanaged with the existing special protection scheme at Woodville.System condition 2 (HVDC south flow)This system condition tests power flowing south through the circuits in the Wellingtonarea towards Haywards and Wilton, specifically:low North Island load (approximately 45% of peak load)low renewable generation including wind, wave, tidal, and solarhigh geothermal generation in the Wairakei Ring areamedium to low generation elsewhere, andHVDC south varies between 475 MW and 900 MW depending on North Islandgeneration and demand. The following issues were identified:the two Bunnythorpe–Haywards circuits may overload for outages of theHaywards–Linton or Wilton–Linton–Bunnythorpe circuitsthe Bunnythorpe–Haywards-2 circuit may overload for an outage of theBunnythorpe 220 kV bus section that connects the Bunnythorpe–Haywards–1and Bunnythorpe–Linton–1 circuits.Some regional 110 kV circuits may also overload and constrain HVDC south transfer,in particular the two Bunnythorpe–Woodville circuits.There are also voltage issues for the loss of a 220 kV circuit between Bunnythorpeand Wellington during high HVDC south transfer and low generation in the Wellingtonarea.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 63

Chapter 6: Grid BackboneImpact of generation scenariosThe five generation scenarios described in Chapter 5 have the following impacts onthe circuits in the Wellington area.Generation scenario 1 (‘sustainable path’), 2 (‘wind’) and 3 (‘medium renewables’)have more than 600 MW of wind generation connected at Linton. To connect thisamount of generation a 220 kV bus is required at Linton to share the generationbetween the Bunnythorpe–Linton–Wilton and Bunnythorpe–Linton–Haywards circuits.For system condition 1 (north power flow from Wellington to Bunnythorpe), generationscenario 2 (‘wind’) has the highest impact on the circuits in the lower North Island, asit has the largest increase in wind generation at Linton (955 MW by 2028). Scenarios1 and 2 also have a substantial increase in lower North Island generation. Thisincrease in lower North Island generation results in the following additional circuitoverloads:The Bunnythorpe–Tararua–Linton circuit may overload for an outage of theBunnythorpe–Linton–1 or Bunnythorpe–Haywards circuits.The Bunnythorpe–Linton–1 circuit may overload for an outage of theBunnythorpe–Tararua–Linton circuit.The Bunnythorpe–Tararua–Linton circuit may overload for a 220 kV bus outageat Bunnythorpe, or Haywards.The Bunnythorpe-Linton circuit may overload for a 220 kV bus outage atHaywards.For system condition 2 (south power flow from Bunnythorpe to Wellington),generation scenarios 4 (‘coal’) and 5 (‘high gas discovery’) have the lowest netincrease in generation in the Wellington area. With a lower amount of newgeneration in Wellington, more power is required to flow through the circuits betweenBunnythorpe and Wellington to supply Wellington area demand and the South Islandvia the HVDC linkOutagesAn outage of any of the 220 kV circuits in the Wellington area during HVDC north orsouth flow may cause generation constraints, requiring replacement generation inother areas.Resolving projectsThe impact of a 220 kV Bunnythorpe or Haywards bus contingency can be reducedthrough reconfiguring the Bunnythorpe and Haywards busses (see chapter 11section 11.9, and chapter 14 section 14.9 respectively for more information).For the two direct circuits between Bunnythorpe and Haywards, we believe that it isuneconomic to increase their rating to increase the transmission capacity (other thana possible small increase in rating following reconductoring – refer to Approvedprojects above). However, a higher amount of power transfer between Bunnythorpeand Haywards is possible with a Special Protection Scheme (SPS). The SPS willautomatically reduce the power flowing on the HVDC link (after Pole 3 iscommissioned) if the two direct Bunnythorpe–Haywards circuits overload, subject toother constraints within the power system. We will monitor the level of constraintcaused by these circuits to determine when an investigation to implement an SPS isrequired.The overloads on the two circuits between Bunnythorpe and Linton are driven by theamount of generation connected at Linton. We will monitor the amount of generationbeing connected at Linton to determine if a transmission upgrade investigation isrequired.642013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 6: Grid BackboneFor the two regional 110 kV Bunnythorpe–Woodville circuits, we have installed anSPS to increase south-flow transmission capacity. The SPS may require expandingto include 220 kV contingencies (see chapter 11 section 11.8.3 for more details). Wewill monitor new generation connections to determine if an investigation tore-conductor the circuits to a higher rating is required.There is significant potential wind generation in the Wairarapa. One option toconnect this generation is to build a new 220 kV transmission line from the Wairarapato Bunnythorpe or Linton.6.5 South Island grid backbone overview6.5.1 Existing South Island transmission configurationThe South Island grid backbone comprises 220 kV circuits with:three circuits from Islington to Kikiwafour circuits from Twizel and Livingstone in the Waitaki Valley area to Islingtoncircuits within the Waitaki Valley, between Twizel and Livingstone, which connectsix large hydro power stations and the HVDC linkthree circuits from Roxburgh to Twizel and Livingstone in the Waitaki Valley area,andfour circuits from Roxburgh to Invercargill/North Makarewa (two via Three MileHill) and nine circuits within the Southland area.Power flows either north or south on the inter-island HVDC link, depending on thetime of day or year. During daylight periods, power tends to flow north to meet peakdemand. However, during light load periods, power can flow south to conserve thelevel of South Island hydro storage, especially during periods of low hydro inflow.Figure 6-10 shows a simplified schematic of the existing South Island grid backbone.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 65

Chapter 6: Grid BackboneFigure 6-10: South Island grid backbone schematicKikiwaSTC-2CulverdenWaiparaBromleyIslingtonSVC-3SVC-9220 kVAshburtonTekapo BTimaruTwizelOhau AOhau BOhau CBenmoreWaitakiAviemoreLivingstoneCromwellClydeNasebyManapouriRoxburghThree Mile HillKEY220 kV CIRCUITNorth MakarewaInvercargillSVC220 kV SUBSTATION BUSGENERATORSTATIC VAR COMPENSATORSTCSTATIC SYNCHRONOUS COMPENSATORTiwaiCAPACITOR662013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 6: Grid Backbone6.5.2 Future South Island grid backboneFigure 6-11 and Figure 6-12 provide an indication of the South Island transmissionbackbone development in the medium term (the next 15 years), and longer term(beyond 2028), respectively.We will install an additional bus coupler circuit breaker at Islington in 2014, to improvevoltage stability for the Upper South Island following a bus fault and to increasesecurity.Further investments in the Upper South Island to maintain voltage stability and meetload growth will also be required. We are consulting on two options:increasing the dynamic reactive support at and around the Islington 220 kV bus,andbussing all four 220 kV circuits into the Upper South Island at Orari.In the longer term, further upgrades for the Upper South Island may be required forvoltage stability or thermal capacity reasons. Options include:bussing all three circuits north of Islington with an HVDC tap-off near Waiparaconstructing a second Islington–Twizel circuit providing a fifth circuit into theUpper South Island 25 , andconstructing a second Islington–Livingstone circuit providing a fifth circuit into theUpper South Island 26 .The options for a fifth circuit into Islington could be implemented in stages, with thefirst stage terminating at Orari (or Ashburton) and the second stage deferred for anumber of years.The Upper South Island voltage stability is an ongoing issue. We will continue tostudy the additional reactive support requirements to maintain Upper South Islandvoltage stability as regional load continues to grow.Within the Waitaki Valley area, there is an approved project to increase thetransmission capacity of the Aviemore–Waitaki–Livingstone circuits 27 . There is alsoan approved project to increase the capacity of the Aviemore–Benmore circuits,which will be reviewed in mid-2013 to optimise its implementation date.Between Roxburgh and the Waitaki Valley, there is an approved project to increasethe transmission capacity of the Roxburgh–Clyde circuits 28 . There is also anapproved project to increase the capacity of the Cromwell–Twizel and Roxburgh–Naseby–Livingstone circuits, which will be reviewed in mid-2013 to optimise itsimplementation date.For the area below Roxburgh, the 110 kV regional network limits the capacity of the220 kV grid backbone. There is an approved project to remove this regional gridconstraint by installing a 220/110 kV connection at Gore. There is also an approvedproject to further increase the grid backbone capacity by installing a series capacitoron the North Makarewa–Three Mile Hill circuit, which we have put on hold due to adecreased load forecast. We will review the need for the series capacitor in 2015 andperiodically thereafter. We expect an upgrade such as a series capacitor or anotheroption may be required in about 2020.We will also strengthen the resilience of some critical substations to mitigate highimpact low probability events.25262728The second Islington–Twizel circuit could be on a new single-circuit line, or on a new double-circuitline and the existing single-circuit line dismantled.The second Islington–Livingstone circuit could be on a new single-circuit line, or on a new doublecircuitline and the existing single-circuit line dismantled.Increasing the capacity of the Aviemore–Waitaki–Livingstone circuits is programmed for Q2 in 2015.Increasing the capacity of the Clyde–Roxburgh circuits is programmed for Q2 in 2014.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 67

Chapter 6: Grid BackboneFigure 6-11: Indicative South Island grid backbone schematic to 2028KikiwaSTC-2* Although this diagram shows newdynamic and static reactive supportsinstalled at Islington, and a newswitching station at Orari, this isindicative only as options are stillbeing investigated.*IslingtonSVCSVC-3SVC-9CulverdenWaiparaBromley*AshburtonTekapo BTwizelTimaru*OrariOhau AOhau BOhau CBenmoreAviemoreWaitakiCromwellNasebyLivingstoneClydeManapouriRoxburghKEYNEW ASSETSUPGRADED ASSETS220 kVThree Mile HillGoreNorth MakarewaInvercargillTiwai682013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 6: Grid BackboneFigure 6-12: Longer-term indicative South Island grid backbone schematicHaywardsSTC-2KikiwaInangahuaWaiparaCulverden*350 kVIslingtonSTCSVCSVC-3SVC-9Bromley* Although this diagram shows a few development pathsfor the future South Island grid backbone transmissionsystem, it is not intended to indicate a preference. Optionwill be finalised closer to the date that transmissionreinforcement is needed.**SVCAshburtonTekapo B*OrariOhau ATwizelTimaruOhau BOhau CBenmoreAviemoreWaitakiCromwellNasebyLivingstoneClydeManapouriRoxburghKEYNEW ASSETSUPGRADED ASSETSThree Mile HillGoreNorth MakarewaInvercargillTiwai2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 69

Chapter 6: Grid Backbone6.6 South Island grid backbone issues and project optionsThe South Island grid backbone comprises four areas indicated in Figure 6-13. Table6-3 summarises issues involving the South Island grid backbone for the next 15years. For more information about a particular issue, refer to the listed sectionnumber.Table 6-3: South Island grid backbone transmission issuesSectionnumberIssue6.6.1 Upper South Island voltage stability6.6.2 Upper South Island transmission capacity6.6.3 Transmission capacity north of Roxburgh and within the Waitaki Valley6.6.4 Transmission capacity south of RoxburghFigure 6-13: South Island grid backbone areaUpper SouthIsland areaWaitaki Valley areaNorth of Roxburgh areaSouth of Roxburgh areaSouthland area702013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 6: Grid Backbone6.6.1 Upper South Island voltage stabilityOverviewMost of the Upper South Island load is supplied through four 220 kV circuits from theWaitaki Valley. The Upper South Island area has relatively little generation comparedwith load. The generation is connected to the regional grid or embedded within thedistribution networks.The transmission capacity to supply the Upper South Island is limited by voltagestability. Voltage stability within this area is influenced by:the reactive power losses due to the transmission system within the areathe reactive power demand due to load composition in the area (in particular theproportion and type of motor load), andgeneration in the area.Reactive support for the Upper South Island is provided by:synchronous condensers 29 and SVCs at Islingtona STATCOM at Kikiwa, andgrid backbone capacitor banks at Islington on the grid backbone and,regional grid capacitor banks at Islington, Bromley, Southbrook, Blenheim, Stoke,Greymouth, and Hokitika.The contingencies which may cause a voltage stability issue are:from winter 2018, an outage of an Ashburton bus section 30from winter 2019, an outage of an Islington bus section 31 , andfrom winter 2021, an outage of the Islington–Tekapo B circuit.Approved projectsWe regularly invest in grid upgrades to raise the voltage stability limit, to match loadgrowth. We are committed to installing an additional bus coupler circuit breaker atIslington in 2014, to address Upper South Island voltage stability up to winter 2018.Voltage stability will be an ongoing issue which will require regular investments tomatch load growth.Impact of generation scenariosThe five generation scenarios described in Chapter 5 have the following impacts onthe Upper South Island backbone grid.All generation scenarios have new generation or demand side reduction within theUpper South Island. This will improve voltage stability, which may defer or replacethe need for transmission investment. Generation scenarios 1 (‘sustainable path’), 2(‘wind’), and 3 (‘medium renewables’) have the highest amount of new generation.Generation scenarios 4 (‘coal’), and 5 (‘high gas discovery’) have the least newgeneration over the next five years, and would be insufficient to defer transmissioninvestment.293031The Islington synchronous condensers will be decommissioned in 2014.The critical Ashburton bus section outage disconnects the Ashburton–Timaru–Twizel andAshburton–Bromley circuits.The critical Islington bus section outage disconnects: Islington–Tekapo–B and Islington–T7(220/66 kV transformer).2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 71

Chapter 6: Grid BackboneOutagesAn outage of a circuit or other transmission element for maintenance will increase thereactive power losses of the transmission system. This requires maintenance to bescheduled for a low load period, load reduction, generation to be constrained on,and/or additional investment in reactive support.Resolving projectsWe will install a sixth bus coupler at Islington in 2014 to create an additional bus zoneto minimise equipment tripping following a bus fault, and so improve voltage stability.We have also commenced an investigation to determine the amount of additionalreactive support required in the next tranche of investments to relieve the UpperSouth Island voltage stability issue. Transmission options include:a combination of static and dynamic reactive support around Islington andBromley, and/orsectionalising the 220 kV circuits from the Waitaki Valley to Islington by bussingthem at one or two new switching stations at Orari, which may also require about7 km of line to be upgraded or replaced.In the longer-term, transmission options include:installing approximately 350 Mvar of additional reactive support by 2028, andreinforcing the Upper South Island transmission capacity (see Section 6.6.2),which also addresses the voltage stability issue.6.6.2 Upper South Island transmission capacityOverviewPower transfer to the Upper South Island is through four 220 kV circuits from theWaitaki Valley.The Islington 220 kV bus is a single major node, supplying a large proportion of theload in Christchurch (along with Bromley), Nelson-Marlborough and the West Coast.There is a risk that high impact low probability single events at Islington can cause asignificant or total loss of supply, either with all equipment in service or duringmaintenance outages.Approved projectsThere are no approved grid backbone projects in the Upper South Island area fortransmission capacity.System condition (north flow)The Upper South Island has relatively little generation compared with load, even atminimum load. Therefore, power always flows from the Waitaki Valley northwards.The n-1 transmission (thermal) limit for the Upper South Island area is forecast tobind in 2025.Impact of generation scenariosThe five generation scenarios described in chapter 5 all have new generation north ofIslington, or demand response to reduce peak demand. More generation or demandresponse defers the onset of the n-1 transmission limit.722013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 6: Grid BackboneOutages“Outage windows” are required so a circuit can be taken out of service formaintenance while managing the grid to provide n-1 security. The number andduration of outage windows available for maintenance depends on the load, loadmanagement, and generation within the area. It is possible that insufficient outagewindows will be available within the forecast period to enable the requiredmaintenance, or for upgrading circuits.Resolving projectsOptions to address the n-1 transmission capacity towards the end of the forecastperiod include:an HVDC tap-off from the existing HVDC line north of Christchurch, ora new transmission line to Islington. This could be built in stages, terminating atOrari (if built) or Ashburton.These resolving projects may need to be brought forward a few years to ensure thereare enough opportunities to take equipment out of service for maintenance.We will monitor the loading on the Upper South Island circuits to determine when atransmission upgrade investigation is required.6.6.3 Transmission capacity north of Roxburgh and within the Waitaki ValleyOverviewTwo sub-areas make up the grid backbone in the area: within the Waitaki Valley, andfrom Roxburgh to the Waitaki Valley.The grid backbone within the Waitaki Valley connects the:Upper South Island area, at Twizel and LivingstoneWaitaki Valley hydro generators 32 at six substationsinter-island HVDC link at Benmore, andtransmission system to Roxburgh, from Twizel and Livingstone.The direction and amount of power flowing through the circuits within the WaitakiValley depends on the load in the Upper South Island, the generation in the area, theamount and direction of HVDC transfer, and the net Otago/Southland load.The grid backbone from Roxburgh to the Waitaki Valley provides throughtransmissionto the Otago/Southland area. The direction of the power flow may benorth or south, depending on the generation and load in the Otago/Southland area.The power flow within the sub-area is also significantly influenced by the generationat Clyde and, to a lesser extent, by the load off-take at Cromwell and Naseby.Approved projectsThe Clutha–Upper Waitaki Lines Project (CUWLP) is an approved suite of projects 33to increase transmission capacity for:low generation in the Otago/Southland area, which causes high ‘south’ powerflows from within the Waitaki Valley to Roxburgh, andhigh generation in the Otago/Southland area, which causes high ‘north’ powerflows from Roxburgh to the Waitaki Valley.3233The six hydro power stations that connect to the grid backbone in the Waitaki Valley are: Ohau A,Ohau B, Ohau C, Benmore, Aviemore, and Waitaki.The Clutha–Upper Waitaki Lines Project (CUWLP) was previously referred to as the Lower SouthIsland Renewables Grid Upgrade Project, approved by the Electricity Commission in August 2010.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 73

Chapter 6: Grid BackboneThe first tranche of projects is to increase the transmission capacity to address highsouth power flows. We will duplex the:Clyde–Roxburgh–1 and 2 circuits in 2014, andAviemore–Waitaki–Livingstone circuits in 2015.Duplexing these circuits approximately doubles the south transmission thermalcapacity 34 to export power from the Waitaki Valley to Roxburgh, (from 250-280 MW to560-590 MW) 35 . There is no significant change in the north transmission thermalcapacity.The second tranche of projects is to:duplex the Roxburgh–Naseby–Livingstone circuitsduplex the Aviemore–Benmore–1 and 2 circuits, andthermally upgrade Cromwell–Twizel–1 and 2 circuits.The primary benefit of the second tranche of projects is to increase the northtransmission thermal capacity. When there is high generation in the Otago/Southlandarea, and at Roxburgh and Clyde, power is exported to the Upper South Island areaand/or the HVDC link at Benmore. The increase in transmission thermal capacity isprogressive, with increased transmission capacity available at the completion of eachupgrade. The north transmission thermal capacity increases from its existing level of200-590 MW to 790-1,260 MW 36 once all the upgrades are completed.The justification for increasing the north transmission thermal capacity is twofold, toenable:full output from existing generators at Clyde, Roxburgh and the Otago/Southlandarea, andnew generation projects in the Otago/Southland area.The second tranche also significantly increases the south transmission thermalcapacity, to 560–590 MW. However, it is expected that most of this southtransmission capacity will not be required.We will review the second tranche of projects in 2013, to optimise the timing of theupgrades.Figure 6-14 shows the circuits in the Waitaki Valley after the upgrades.343536The increase in south transmission capacity occurs only after all the referenced circuits areduplexed; there is no significant increase in south transmission capacity with only some of thecircuits duplexed.The amount of power that can be exported from the Waitaki Valley to Roxburgh varies withgeneration, particularly generation at Clyde power station, and varies to a lesser extent with load.The limits are measured across the Livingstone–Naseby and Cromwell–Twizel–1 and 2 circuits inthe Roxburgh–Waitaki Valley area.The amount of power that can be sent from Roxburgh to the Waitaki Valley varies with generationand load. The large range for north transmission capacity is mainly due to the effect of generationat Clyde, ranging from full output of 432 MW to 0 MW. The limits are measured across the Naseby–Roxburgh and Clyde–Roxburgh–1 and 2 circuits.742013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 6: Grid BackboneFigure 6-14: 220 kV circuits between Roxburgh and Twizel after CUWLP upgradeTwizelOhau COhau BAviemoreBenmoreWaitakiCircuitSummer/WinterratingAviemore–Benmore–1 and 2 609/671 MVA 1Aviemore–Waitaki–1609/671 MVALivingstone–Waitaki–1609/671 MVALivingstone–Naseby–1 609/671 MVA 1Naseby–Roxburgh–1 609/671 MVA 1Clyde–Cromwell–Twizel–1 and 2 561/617 MVA 1Clyde–Roxburgh–1 and 2 709/781 MVABenmore–Twizel–1404/493 MVABenmore–Ohau B–1558/614 MVAOhau B–Twizel–3694/764 MVABenmore–Ohau C–2558/614 MVAOhau C–Twizel–4694/764 MVACromwellClydeNasebyLivingstone1 The timing to upgrade these circuits will bereviewed in 2013. The summer/winter rating forthese circuits prior to upgrade is:202/246 MVA for Aviemore–Benmore–1 and 2,Roxburgh–Naseby–Livingstone–1, and385/470 MVA for Cromwell–Twizel–1 and 2.RoxburghThe following sections assess the transmission capability following the CUWLPupgrade. The assessment is based on representative system conditions, todetermine how different generation development scenarios interact with the WaitakiValley area.System condition 1 (north flow)This system condition tests power flowing from the Lower South Island to theupgraded HVDC link, specifically:maximum South Island generationoff peak South Island load (approximately 65% of island peak)maximum HVDC north transfer of 1,000 MWThere were no issues with transmission capacity for north flow for the forecast period.System condition 2 (south flow)This system condition tests power flowing south of Roxburgh/Clyde during a period ofextremely low southern generation, fully utilising the upgraded HVDC links south flowcapacity. To avoid overloading the grid backbone (after the CUWLP projects arecompleted) in:2018, a minimum total of about 350 MW of generation is required at Manapouri,Roxburgh and Clyde power stations2028, a minimum total of about 630 MW is required at Manapouri, Roxburgh andClyde power stations.Impact of generation scenariosThe five generation scenarios described in Chapter 5 have the following impacts onthe circuits within the Waitaki Valley area.There were no issues with transmission capacity for north flow for all generationscenarios.High levels of power flow south towards Roxburgh, with high levels of HVDC southflow, may overload the Benmore–Twizel circuit.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 75

Chapter 6: Grid BackboneAs noted in the previous section for system condition 2 (south flow), minimum levelsof generation are required south of Roxburgh/Clyde. Any new generation south ofRoxburgh increases the options for providing the minimum generation requirements,assisting in the management of the power system.OutagesThe transmission capacity is reduced during outages, which may require generationin the Waitaki Valley or Lower South Island area to be constrained.Resolving projectsFor very high power flows from the Waitaki Valley to the Lower South Island, theBenmore–Twizel circuit capacity will need to be increased. Transmission solutions toprevent overloading of the Benmore–Twizel circuit include 37 :implementing variable line ratings to alleviate some overloads in the short term,andthermally upgrading and/or reconductoring the Benmore–Twizel circuit.We will monitor the loading of the Benmore–Twizel circuit to determine if atransmission upgrade investigation is required.Any further increase in south transmission capacity beyond that provided by the suiteof CUWLP projects will require a new transmission line. We will continue to monitorthe load and minimum generation levels to determine if a new line investigation isrequired, although there is no such need at present..6.6.4 Transmission capacity south of RoxburghOverviewThe grid backbone south of Roxburgh is primarily a six circuit “triangle” betweenRoxburgh, Three Mile Hill and Invercargill/North Makarewa. There are also ninecircuits connecting Invercargill, North Makarewa, Manapouri and Tiwai.There is a low capacity 110 kV regional network which operates in parallel with thegrid backbone between Roxburgh, Halfway Bush, and Invercargill (see Chapter 19).The capacity of this regional network limits the capacity of the grid backbone.The magnitude and direction of power flows on the grid backbone are dominated bythe large hydro generation station at Manapouri and the large load at Tiwai.The main issue for the grid backbone in this area is the transmission capacitysupplying the regional load when Manapouri generation is low and Southlanddemand is high. An outage of one of the two Invercargill–Roxburgh circuits mayresult in:overloading of the other Invercargill–Roxburgh circuitlow voltages in Southland, andoverloading of the regional 110 kV network between Gore and Roxburgh and theRoxburgh 220/110 kV transformer (see Chapter 19 for more information).These issues are presently managed by constraining on minimum levels ofgeneration and voltage support at Manapouri.Figure 6-15 shows the 220 kV grid backbone circuits south of Roxburgh.37We believe that only a relatively small increase in the rating of the Benmore–Twizel circuit isrequired (about 20%), and that reconductoring the circuit is not required.762013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 6: Grid BackboneFigure 6-15: Grid backbone circuits south of RoxburghManapouriNorth MakarewaTiwaiRoxburgh Circuit Summer/WinterratingInvercargill–Roxburgh–1 and 2 347/382 MVAInvercargill–Manapouri–2311/380 MVAInvercargill–North Makarewa–1 404/457 MVA 1Three Manapouri–North Makarewa–1, 2 and 3 311/380 MVAInvercargill–Tiwai–1 and 2 385/457 MVAMile HillGoreNorth Makarewa–Tiwai–1 and 2 385/470 MVARoxburgh–Three Mile Hill–1 and 2 385/470 MVAInvercargillNorth Makarewa–Three Mile Hill–1 and 2 347/382 MVA1. The winter rating is presently limited by a substation componentlimit; with this limit resolved, the winter rating will be 493 MVA.2. The winter rating is presently limited by a substation componentlimit; with this limit resolved, the winter rating will be 470 MVA.Approved projectsThe Lower South Island Reliability Grid Upgrade Plan is a suite of projects toincrease the grid backbone transmission capacity for power flow south fromRoxburgh.Projects to remove the constraint on the grid backbone caused by the regional110 kV grid include (see Chapter 19 for more information):replacement of the Roxburgh 220/110 kV transformer with a higher ratedtransformer, commissioned in November 2012 (this has slightly eased, but notremoved, the existing constraints),replacing the Invercargill 220/110 kV transformer with a transformer which has anon-load tap changer in 2014, andproviding a 220/110 kV connection at Gore, and reconfigure the 110 kV networkin 2015-2016 38 (this will provide a measureable increase in south transmissioncapacity).There is also an approved project to further increase the south transmission capacityby installing a series capacitor on one of the two North Makarewa–Three Mile Hillcircuits. We have put this project on hold due to a lower load forecast. We willreview the need for the series capacitor in 2015 and periodically thereafter. Weexpect a series capacitor or another option may be required in about 2015.System condition 1 (north flow)This system condition tests power flowing north to Roxburgh, specifically:maximum South Island generationoff peak South Island load (approximately 65% of island peak), andmaximum HVDC north transfer of 1,000 MWThere are no issues with the transmission capacity south of Roxburgh during northpower flow for the forecast period.System condition 2 (south flow)This system condition tests power flowing south of Roxburgh during periods of lowgeneration, particularly at Manapouri. To avoid overloading of the grid backbone(after the Lower South Island Reliability upgrades are completed), increasedminimum generation in the Southland area is required as the load in the areaincreases. In 2028, approximately 330 MW of generation will be required (principally38The build date for the Gore 220/110 kV transformer is an estimate and is dependent on whenTranspower acquires the property rights for a short length of 220 kV transmission line.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 77

Chapter 6: Grid Backbonefrom Manapouri) to avoid overloading of the grid backbone circuits supplying theSouthland load.Impact of Generation scenariosThe five generation scenarios described in Chapter 5 have the following impacts onthe circuits south of Roxburgh.Generation scenario 4 (‘Coal’) connects new generation at North Makarewa (two400 MW lignite plants in 2025, and 2028). This will cause the Invercargill–NorthMakarewa circuit to overload, even with all circuits in service.Connecting new generation to one of the North Makarewa–Gore–Three Mile Hillcircuits may cause the circuit to overload. Generation will not be connected to thesecond circuit, as this is reserved for a series capacitor 39 .There are no other grid backbone issues with additional generation (although allgeneration scenarios have 110 kV regional grid issues, see Chapter 19).Any additional generation will assist in managing the power system during periods oflow generation.OutagesThe transmission capacity is reduced during outages, which will constrain theminimum and maximum generation in the Otago-Southland area.Resolving projectsThe above issues emerge late in the forecast period.Transmission solutions to prevent overloading of the Invercargill–North Makarewacircuit include a combination of:reconfiguring the grid by bussing the Invercargill–Manapouri circuit at NorthMakarewathermally upgrading the Invercargill–North Makarewa circuit(s), possiblycombined with variable line ratings, and/orreconductoring the Invercargill–North Makarewa circuits.Transmission solutions to prevent overloading of the North Makarewa–Gore–ThreeMile Hill circuit include:installing a protection scheme to automatically reduce generation if the circuitoverloadsthermally upgrading the circuits, combined with variable line rating and/orreconductoring of (part of) the circuit.Any further increase in south transmission capacity following completion of the LowerSouth Island Reliability projects will require a new transmission line. The presentload forecasts do not indicate the need for a new transmission line.The low voltage during high levels of south transmission can be addressed by:increasing the rating of the existing North Makarewa capacitors from 50 Mvar to75 Mvar 40installing additional capacitorsoperating Manapouri generators at 0 MW to provide voltage support.3940It is technically possible to connect generation and a series capacitor to the same circuit, but this isnot normally done because of potential overvoltage and resonance issues.The two existing 50 Mvar capacitors at North Makarewa are designed to be easily upgraded to75 Mvar.782013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 6: Grid Backbone6.7 HVDC link overviewThe High Voltage Direct Current (HVDC) link connects the North and South Islands.For the North Island, the HVDC link provides access to the South Island’s large hydrogeneration capacity, which may be important for the North Island in peak winterperiods. For the South Island, the HVDC link provides access to the North Island’sgas and coal generation, which is important for the South Island during dry periods.Without the HVDC link, more generation in both the North and South Islands wouldbe needed. In addition, the HVDC link is essential for the electricity market as itallows generators in the North and South Islands to compete, putting downwardpressure on prices and minimising the need to invest in expensive new generatingstations. The HVDC link also plays an important part in allowing renewable energysources to be managed between the two islands.6.7.1 Existing HVDC link configurationThe original mercury arc converter (Pole 1) has now been decommissioned. Figure6-16 shows a simplified schematic of the existing HVDC link, which comprises:a thyristor converter (Pole 2), with a converter station at Benmore in the SouthIsland and Haywards in the North Islandprotection and control systems at Benmore and Haywardsa 350 kV bipolar transmission line, 534 km long from Benmore to Fighting Bay onthe shore of Cook Strait in the South Island and 37 km long from Haywards toOteranga Bay on the shore of Cook Strait in the North Islandthree 350 kV undersea 40 km cables, with cable terminal stations at Fighting Bayand Oteranga Bay, anda land electrode at Bog Roy near Benmore in the South Island and a shoreelectrode at Te Hikowhenua near Haywards in the North Island.Figure 6-16: Existing HVDC linkC7HAYWARDS110 kVF147.5 MvarF2T1HAYWARDS220 kVBENMORE220 kVT2BENMORE16 kV+ 270 kV535 km DC linesection – SouthIslandCable 6Pole 1 assets35 km DC linesectionNorth IslandC8C10C160 MvarR140 MvarT2F150.5 MvarPole 2 assetsC9C260 MvarT5Ground (Earth/Sea) Return Current modeF379.3 MvarF479.3 MvarPole 2(existing thyristorConverters 700 MW)- 350 kV40 km Cook StraitCablesCable 5Cable 4C3 C435 MvareachF3106.3 MvarF4106.3 MvarR540 Mvar6.7.2 Future HVDC link configurationFigure 6-17 shows a simplified schematic of the HVDC link as it will be following thecompletion of the Pole 3 project in 2013. The Pole 3 project will install newconverters similar to the existing Pole 2 converters, and connected to the 220 kVbuses at Haywards and Benmore. The work includes:2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 79

Chapter 6: Grid Backbonenew thyristor based converters at Benmore and Haywards, including theassociated converter transformers and DC smoothing reactorsnew 220 kV AC filters at Benmore and Haywardsreplacement of the existing 110 kV AC filters at Haywardsrefurbishment of all synchronous condensers at Haywards and new 110/11 kVtransformers for four of the condensers, andreplacement of HVDC protection and controls.Figure 6-17: Pole 2/Pole 3 HVDC linkCable 5+ 350 kVCable 6New 220 kV Filter/sNew 220 kVFilter/sPole 3Thyristorconverters(700 MW)New StatcomT1C7ExistingC8Stage 1 – 1000 MWStage 2 – 1200 MWC160 MvarR140 MvarT2C9C10BENMORE220kVF379.3 MvarF479.3 Mvar- 350 kV535 km DCline sectionSouth IslandCable 440 km Cook StraitCablesPole 2existingThyristorconverters(700 MW)35 km DC linesection NorthIslandF3106. 3 MvarF4106. 3 MvarC2HAYWARDS220kVC3 C435 Mvareach60 MvarT5R540 MvarHAYWARDS110kVC7-C1065 MvareachNew5 th /7 thFilter/sFigure 6-18 shows a simplified diagram for a possible further expansion of the HVDClink to 1,400 MW north capacity following completion of the Pole 3 project. Thiswould involve the installation of:one additional submarine cableadditional filters at both Benmore and Haywards, andadditional dynamic reactive support at Haywards.802013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 6: Grid BackboneFigure 6-18: Possible future HVDC linkCable 5+ 350 kVCable 6220 kV Filter/sStatcom220 kVFilter/sPole 3Thyristorconverters(700 MW)New 220 kV Filter/sNew StatcomT1C7New 220 kVFilter/sExisting aftercompletion of Stage 2Stage 3 – 1400 MWC160 MvarR140 MvarT2C8C9C10BENMORE220kVF379.3 MvarF479.3 Mvar- 350 kV535 km DCline sectionSouth IslandCable 7Cable 440 km Cook StraitCablesPole 2Thyristorconverters(700 MW)35 km DC linesection NorthIslandF3106. 3 MvarF4106. 3 MvarC2HAYWARDS220kVC3 C435 Mvareach60 MvarT5R540 MvarHAYWARDS110kVC7-C1065 Mvareach5 th /7 thFilter/s6.8 HVDC link issues and project options6.8.1 HVDC link capacityIn 1992, the HVDC link capacity was 1,240 MW, with a Pole 1 capacity of 640 MWand a Pole 2 capacity of 700 MW.The HVDC link capacity is now significantly lower as Pole 1 has now beende-commissioned. Pole 2 is normally available, with a maximum transfer of 700 MW.However, with only Pole 2 in operation, the HVDC link transfer is dependent on thereserve cover available, which significantly reduces the maximum practical transferlimit.It is economic to restore the HVDC link capacity.The Pole 3 project will provide an HVDC link capacity of 1,000 MW (north and southpower flow), with a possible increase to 1,200 MW in 2014. It will not always bepossible to use the full capacity of the HVDC link. Power transfer may be limited bythe availability of instantaneous reserves and the capacity of the North and SouthIsland transmission networks (refer to Sections 6.4 and 6.6 respectively).The other sections of the Annual Planning Report assume that the Pole 3 project toreplace Pole 1 is completed in 2013.6.8.2 State of existing equipmentPole 1Half of Pole 1 was decommissioned in December 2009 and the second half wasdecommissioned on 1 August 2012.With Pole 1 de-commissioned, HVDC bipole operation is not available. Withoutbipole operation, the HVDC is in monopolar operation, which results in:reduced HVDC capacity (one pole rather than two poles in operation)increased reserve cover from generation and load required for a Pole trip, andground (sea/earth) return current.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 81

Chapter 6: Grid BackboneFor the reserve cover, in bipole operation should one pole fail then the remaining polecan increase its power transfer, which provides some self-cover. This could be partialor full load cover depending on pre-fault power flow of the remaining pole. There isno self-cover possible in monopolar operation with only HVDC Pole 2 in service.The maximum possible transfer with only Pole 2 in service is 700 MW. However, thenormal link transfer is dependent on the reserve cover available. This significantlyreduces the practical transfer limit at most times.Also, a planned or unplanned outage under monopolar operation decouples the twoislands, reducing the generation available to both islands and introducing priceseparation (or reduced competition).For the ground (sea/earth) return current, in monopolar operation all of the HVDCcurrent flows in the ground. 41 To date, we have not had any problems with groundreturn current, other than wear on the sea/earth electrodes.Pole 2Pole 2 was commissioned in 1991, with a design life of 35 years for the main circuitequipment, although most of the equipment is expected to last longer. Some maincircuit equipment is also common to both poles (neutral bus and electrode lineequipment), which was also installed in the early 1990s.The nominal rating of Pole 2 is 560 MW, with a continuous overload of 700 MW. Thecontinuous overload has proved very beneficial for limiting reserve requirements andmanaging emergency conditions.HVDC controlsThe HVDC controls and protections were installed with Pole 2 in the early 1990’s.The control systems face obsolescence because their life (about 15-20 years) isshorter than that of the main circuit equipment, thus requiring at least one fullreplacement within the lifetime of the HVDC converter equipment.HVDC transmission linesThe transmission line was originally built for +/- 250 kV, 1200 A operation (600 MWbipole operation). During the hybrid link upgrade, the line was re-insulated to operateat 350 kV and thermally upgraded for maximum continuous current of 2000 A.Therefore, the line is capable of 700 MW per pole or 1,400 MW bipole operation.The conductor on a short section of the line in the North Island (Churton Parkdeviation) may need to be replaced within the forecast period based on conditionassessment. Most of the other conductor in the North and South Islands is expectedto have a remaining service life of several decades.About 100 of the 1,530 towers in the South Island were replaced to correct conductorclearance and tower strength issues as part of line maintenance work.HVDC submarine cablesThree cables (each rated 500 MW at 350 kV) were installed as part of the Hybrid DClink upgrade project in the early 1990s.Between 1991 and 2004, the three cables performed well with no major issues orfailures. In October 2004, a cable failed and was out of service for six months forrepairs. It was fortunate that this fault was in shallow water in Oteranga Bay so it41In balanced bipole operation, the dc current in both poles is equal and opposite (within an accuracyof about 4 amps). Thus the current in one Pole returns through the other Pole, and the 4 amps ofunbalanced current flows in the ground (sea/earth) electrode.822013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 6: Grid Backbonecould be repaired using a locally available barge, with sufficient time to mobilise arepair before the limited weather window in February/March ended.The cause of failure is difficult to establish, and the balance of probabilities indicatesthat it is likely to be a localised problem. However, it is also possible there is a latentdesign weakness or manufacturing defect which could result in another fault in thecable, or even one of the other cables.There is a Cable Protection Zone (CPZ) to exclude external activities which mightdamage the cables. This is ensured by constant marine patrols preventing fishingand trawling activities within the CPZ. Regular Remote Operated Vehicle (ROV)surveys are also undertaken to monitor the external condition of the cable and theenvironmental factors affecting the cables.The cables’ design and the CPZ help ensure the cables will achieve or exceed their40 year design life. However, sea conditions and seabed movement makes CookStrait one of the most aggressive locations for submarine cables in the world. Theabrasion-corrosion conditions in Cook Strait are understood and mechanicaldeterioration is likely to determine the life expectancy of the cables.HVDC electrodesA bipolar HVDC link operating with balanced current in both poles has only a smallamount of residual ground current. In unbalanced bipolar operation, or in monopolaroperation, a return current path needs to be provided.The return current path is via the earth (ground), which requires a land electrode atBog Roy, for Benmore, and a shore electrode at Te Hikowhenua, for Haywardsstation. These electrodes are designed for continuous operation at 2000 amps. Thiscorresponds to 700 MW monopolar operation at 350 kV DC. It is capable ofoperating at 2400 A for intermittent (few hours at a time) operation.Monopolar operation depends on the availability and integrity of the electrodes. Thelong term impact of operating in continuous monopolar operation at high power levelsis not readily available. Since the partial and then full decommissioning of Pole 1,HVDC monopolar operation has been the normal operating mode. We and ourcontractors carry out regular maintenance work to ensure the integrity of theelectrodes, and the electrodes remain within their design limits.Synchronous condensersThere are eight synchronous condensers at Haywards, providing reactive supportand improving system strength to enable stable operation of the HVDC link. Thenumber of synchronous condensers that need to be in service depends on the HVDCbipole power transfer, if all other system conditions are equal.Four condensers are connected to the tertiary windings of the 220/110/11 kVinterconnecting transformers. Two condensers are connected through recentlyinstalled new 110/11 kV transformers. The other two condensers are connected tothe tertiary windings of the Pole 1 converter transformers. The Pole 1 transformersare nearing the end of their reliable economic life.The condensers were installed between 1955 and 1965 and are of very robust designand construction. Good international practice is for major overhaul and invasivemaintenance every 15-20 years, which was last done in 1989-1992. In addition,much of the auxiliary equipment either no longer meets modern practice or is nearingthe end of its reliable economic life.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 83

Chapter 6: Grid Backbone6.8.3 Approved HVDC link projects (Stage 1 and 2)The HVDC Pole 3 project is an approved project, presently under construction, toincrease the HVDC link capacity (refer to Section 6.8.1) and address equipmentissues (refer to section 6.8.2). The Pole 3 project is in two stages:Stage 1 provides an HVDC link capacity of 1,000 MW, andStage 2 provides an HVDC link capacity of 1,200 MW.Figure 6-17 (in Section 6.7.2) shows a simplified diagram for the two stages.The commissioning of Pole 3 has the potential to significantly affect the operation ofthe power system and the electricity market. An industry group coordinates outageand commissioning activities to minimise these impacts.HVDC converters (Stage 1 – 1,000 MW)Pole 3 will have a nominal operating DC voltage of 350 kV and a continuous currentrating of 2000 A, to give a 700 MW converter. The upper limit on the voltage is set bythe existing line design and cable ratings. The maximum nominal current is limited bythe line rating and the continuous rating of the new Pole 3 equipment.A 30 minute overload capacity of 1,000 MW for Pole 3 reduces the overall systemreserve requirements.HVDC transfer north up to 1,000 MW in balanced 500/500 MW bipole operation ispossible.Pole 3 is programmed for completion in the second quarter of 2013.Only three cables are available, which limits the self-cover of the HVDC for a poletrip:Pole 3 will have two cables connected, so the short-term 1,000 MW capacity ofPole 3 is matched by the 1,000 MW cable capacity, but may be limited by thesteady-state 700 MW rating of the transmission line. Pole 3 will provide aminimum cover up to 700 MW for a failure of Pole 2.Pole 2 will have one cable connected, so the 700 MW capacity of Pole 2 will belimited by the 500 MW rating of the cable. Pole 2 will provide cover up to500 MW for a failure of Pole 3.As discussed in Section 6.8.1, the south transfer capability is limited by the capacityof the AC network in the North and South Islands, and varies significantly with thesystem demand in the Wellington region because of the AC system limitation. TheHVDC controls will apply a maximum south transfer limit of 750 MW to represent thisAC system limitation with all equipment in service and at a time of minimum systemdemand. The south transfer capability will reduce below this value as the demandincreases (and during equipment outages).110 kV filters at HaywardsThe 110 kV connected filters at Haywards, installed as part of the original HVDC Linkin the mid-1960s, will be replaced by 5 th /7 th harmonic filters.Synchronous condensers at HaywardsThe eight existing condensers will be retained and refurbished. The two condensersthat are connected to the Pole 1 mercury arc valve converter transformers will bereconnected to new 110/11 kV transformers. This work is programmed forcompletion in the second quarter of 2014.842013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 6: Grid BackbonePole 2 and Bipole protection and controlThe Pole 2 and Bipole control systems will be replaced with identical technology tothat of new Pole 3. The Pole 2 valve firing controls will be replaced as part of the newPole 2 control system, and will interface to the existing valve based electronics (whichwill be retained) at the thyristors. This work is programmed for completion in the thirdquarter of 2013.The new control system will be very flexible. It will monitor and control the HVDCtransfer to manage system conditions at Haywards and Benmore and on the ACnetwork at Haywards. The flexibility of the new control system will provide options tomodify it, allowing the AC network to operate above the n-1 limit by relying on theHVDC control system to prevent post-contingency overloads.Haywards STATCOM (Stage 2 – 1,200 MW)In addition to the existing synchronous condensers, additional dynamic reactivepower capacity will be required to achieve HVDC capacity greater than 1,000 MW,driven by two major functional requirements to:provide reactive support and improve voltage stabilitylimit excessive transient or temporary overvoltage (TOV) following a bipole trip.A STATCOM will provide the necessary dynamic reactive support for HVDC capacityof 1,200 MW. The STATCOM has a nominal rating of +60/-60 Mvar and a short-termrating which is expected to be a minimum of +100/-180 Mvar. This work isprogrammed for completion in the first quarter of 2014.HVDC north transfer up to 1,200 MW is possible with unbalanced 700/500 MWoperation of Pole 3/Pole 2.Only three cables are available, which limits the self-cover of the HVDC for a pole tripas described for Stage 1.As for Stage 1, the south transfer capability is limited by the capacity of the ACnetwork and will vary significantly with the system demand in the Wellington region.The HVDC controls at Stage 2 will limit the maximum south transfer to 850 MW withall equipment in service and at a time of minimum system demand. The increasefrom Stage 1 is due to the additional reactive support provided by the STATCOM.The south transfer capability will reduce below this value as the demand increases(and during equipment outages).HVDC line ratingEach of the poles on the HVDC line has a steady state rating of 700 MW, whereasPole 3 will have a minimum short-term rating of 1,000 MW for 30 minutes. The fullshort-term rating of Pole 3 may be restricted by the rating of the line, which dependson its pre-contingency loading and ambient air temperature.6.8.4 Further HVDC developmentsHVDC link expansion to 1,400 MWFollowing the Pole 3 project, the HVDC Link can be further expanded to 1,400 MWnorth transfer capacity with the installation of:one additional submarine cableadditional filters at both Benmore and Haywards, andadditional dynamic reactive support at Haywards.Figure 6-18 (in Section 6.7.2) shows a simplified diagram for this possible upgrade.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 85

Chapter 6: Grid BackboneThe HVDC controls will limit the maximum south transfer to 950 MW with allequipment in service and at a time of minimum system demand. The increase fromStage 2 is due to the additional reactive support at Haywards. The south transfercapability will reduce as demand increases (and during equipment outages).When planning for the additional cable, the condition and risks associated with theexisting cables will also be reviewed and the need for a spare (fifth) cable will beassessed.The timing for this possible upgrade will be assessed following completion of thePole 3 project. The earliest anticipated date for expansion to 1,400 MW is presently2017 and we anticipate seeking approval from the Commission in 2014. This wouldbe a major capex proposal and our project reference is HVDC-TRAN-DEV-03.We anticipate that a capacity increase to 1,400 MW will be sufficient to enablediversity of generation in the North and South Islands for the foreseeable future.HVDC line ratingThe HVDC line’s capacity could be increased to allow the unconstrained use of theconverters’ short-term overload rating for all operating conditions. We will monitor theuse of the HVDC link to determine if and when an investigation for an upgrade of theHVDC line may be required. This is a possible major capex proposal and weanticipate seeking approval for this project at a date to be advised. Our projectreference is HVDC-TRAN-DEV-02.862013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 7: Northland Region7 Northland Regional Plan7.1 Regional overview7.2 Northland transmission system7.3 Northland demand7.4 Northland generation7.5 Northland significant maintenance work7.6 Future Northland projects summary and transmission configuration7.7 Changes since the 2012 Annual Planning Report7.8 Northland transmission capability7.9 Northland bus security7.10 Other regional items of interest7.11 Northland generation scenarios, proposals and opportunities7.1 Regional overviewThis chapter details the Northland regional transmission plan. We base this regionalplan on an assessment of available data, and welcome feedback to improve its valueto all stakeholders.Figure 7-1: Northland regionConstruction voltages shown. System as at March 2013.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 87

Chapter 7: Northland RegionThe Northland region load includes greater Auckland loads such as Henderson andAlbany, a major industrial load at Bream Bay, and loads at smaller regional centres tothe north.We have assessed the Northland region’s transmission needs over the next 15 yearswhile considering longer-term development opportunities. Specifically, thetransmission network needs to be flexible to respond to a range of future service andtechnology possibilities, taking into consideration:the existing transmission networkforecast demandforecast generationequipment replacement based on condition assessment, andpossible technological development.7.2 Northland transmission systemThis section highlights the state of the Northland regional transmission network. Theexisting transmission network is set out geographically in Figure 7-1 andschematically in Figure 7-2.Figure 7-2: Northland transmission schematicKaitaiaLines company assets33 kV110 kV110 kVKaikohe33 kVKensington33 kVBream Bay33 kVMaungatapere110 kVMarsden220 kV220 kV110 kVMaungaturoto110 kV33 kVWellsford110 kVKEYSVC220kV CIRCUIT110kV CIRCUIT50kV CIRCUITSUBSTATION BUSTRANSFORMERLOADCAPACITORSTATIC VARCOMPENSATORBONDED CIRCUIT33 kVHuapai220 kV110 kV220 kV 110 kVHendersonVECTORWAIRAU ROAD110 kV33 kVSilverdale33 kVSVC220 kV33 kVAlbanyOtahuhu Southdown Mount RoskillAUCKLAND33 kVHepburn Road882013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 7: Northland Region7.2.1 Transmission into the regionThe Northland region is supplied through Auckland by a 220 kV double-circuit linefrom Otahuhu, with Southdown generation station connected into one of these circuitsjust north of Otahuhu, and a 110 kV double-circuit line from Mount Roskill to HepburnRoad.The Northland region’s generation capacity is well short of that needed to meet localdemand, and so it must import most of its power through Auckland.We have committed to a major project to improve security of supply into theNorthland region. The North Auckland and Northland (NAaN) project (see Chapter 8for more information) includes a 220 kV cable from Pakuranga to Penrose and on toAlbany. This will approximately double the n-1 capacity into Northland, and willprovide diversity by taking a different route across Auckland from the existing 220 kVcircuits. When required, a second 220 kV cable will be installed along a similar cableroute.7.2.2 Transmission within the regionTransmission within the Northland region consists of three sub-regions.The first sub-region consists of five substations 42 within the Auckland city area. Thesubstations are connected through high capacity 220 kV circuits or relatively highcapacity 110 kV circuits. There are five capacitor banks and a static var compensator(SVC) for voltage support.The second sub-region is the high capacity 220 kV double-circuit line from Huapai toMarsden and Bream Bay. Two static synchronous compensators (STATCOMs) arebeing installed at Marsden for voltage support.The third sub-region is around Maungatapere, supplied mainly through the 110 kVdouble-circuit Marsden–Maungatapere line. There is also a low capacity doublecircuit Henderson–Maungatapere line, with substations at Wellsford andMaungaturoto. From Maungatapere there is a 110 kV double-circuit line toKensington and a 110 kV double-circuit line to Kaikohe. At present, voltage supportfor the sub-region is provided by capacitors at Kaitaia and, within the distributionnetwork, at Kaikohe.There are five 220/110 kV interconnecting transformers: two at Henderson, one atAlbany, and two at Marsden.7.2.3 Additional voltage supportThe sub-region around Maungatapere will require additional voltage support in boththe short and long term. Technically, the most effective voltage support solution is toover-compensate the system by installing additional capacitors at Kaitaia, so reactivepower flows from Kaitaia to Kaikohe and Maungatapere.If additional voltage support is installed at Maungatapere instead of Kaitaia, thenhigher capacity equipment must be installed to achieve the same voltage set point forthe region. The increased capacity may require STATCOMs or similar technology tobe considered rather than lower cost capacitors.7.2.4 Longer-term development pathThe North Island Grid Upgrade (NIGU) and North Auckland and Northland (NAaN)projects are expected to secure transmission into Northland well beyond the 15-yearforecast period. In the longer term, an additional 220 kV circuit will be required to42The five lower sub-region substations are Henderson, Huapai, Albany, Silverdale and HepburnRoad.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 89

Chapter 7: Northland Regionretain adequate security. This is likely to be a second cable between Penrose andAlbany.No new transmission lines are expected to be required from the North Isthmus toNorthland to provide additional transmission capacity. At most, the remaining simplex220 kV circuit from Huapai to Bream Bay and Marsden may need to bereconductored to duplex, and the two 110 kV Henderson–Maungatapere circuits mayalso need to be reconductored.A new transmission line will be required from the North Isthmus to Northland if anincrease in security is required at some time in the future, particularly if securityneeds to be maintained during maintenance outages.7.3 Northland demandThe after diversity maximum demand (ADMD) for the Northland region is forecast togrow on average by 2.0% annually over the next 15 years, from 930 MW in 2013 to1,260 MW by 2028. This is higher than the national average demand growth of 1.5%annually.Figure 7-3 shows a comparison of the 2012 APR and 2013 APR forecast 15-yearmaximum demand (after diversity 43 ) for the Northland region. The forecasts arederived using historical data, and modified to account for customer information, whereappropriate. The power factor at each grid exit point is also derived from historicaldata. See Chapter 4 for more information about demand forecasting.Figure 7-3: Northland region after diversity maximum demand forecastTable 7-1 lists forecast peak demand (prudent growth) for each grid exit point for theforecast period, as required for the Grid Reliability Report.43The after diversity maximum demand (ADMD) for the region will be less than the sum of theindividual grid exit point peak demands, as it takes into account the fact that the peak demand doesnot occur simultaneously at all the grid exit points in the region.902013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 7: Northland RegionTable 7-1: Forecast annual peak demand (MW) at Northland grid exit points to 2028Grid exit pointPowerfactorNext 5 yearsPeak demand (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Albany 33 kV 0.99 168 172 175 179 182 186 193 201 209 216 224Albany 110 kV1 0.97 158 161 165 168 171 175 182 189 196 203 210– Wairau RdBream Bay 0.96 46 46 47 48 49 49 51 52 54 55 57Henderson 0.99 128 131 135 138 141 145 152 160 167 175 182Hepburn Road 0.99 158 161 165 168 171 175 182 189 196 203 210Kaikohe 2 0.97 57 58 59 61 62 63 66 68 71 73 76Kensington 3 0.99 65 65 65 65 65 65 65 65 65 65 65Maungatapere4 0.97 48 49 51 53 55 57 61 65 69 73 77110 kVMaungatapere110 kV –Dargaville1.00 13 14 14 14 14 15 15 16 16 17 18Maungaturoto 1.00 18 18 19 19 19 20 20 21 22 22 23Silverdale 1.00 84 86 88 91 93 95 100 105 110 115 119Wellsford 1.00 35 36 37 38 39 39 41 43 46 48 491. A new grid exit point at Wairau Road is planned for commissioning in 2013. This will take some loadfrom the Albany 110 kV grid exit point, although the exact split is not known.2. Kaikohe is supplied on two 110 kV feeders from Maungatapere. In previous years, the APR providedseparate load forecasts for Kaikohe and Kaitaia; these are now combined in a single load forecast forKaikohe.3. The customer advised that offtake at Kensington will be is limited to 65 MW with growth atMaungatapere.4. The customer advised of load transfers between Kensington and Maungatapere. These affect theobserved peaks with the amount varying year-on-year.7.4 Northland generationThe Northland region’s generation capacity is approximately 54 MW, well short of thelocal demand.Table 7-2 lists the generation forecast for each grid injection point for the forecastperiod, as required for the Grid Reliability Report. This includes all known andcommitted generation stations including those embedded within the relevant locallines company’s network (Vector, Northpower or Top Energy). 44Table 7-2: Forecast annual generation capacity (MW) at Northland grid injection pointsto 2028 (including existing and committed generation)Grid injection point(location ifembedded)Next 5 yearsGeneration capacity (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Albany (Rosedale 1 ) 3 3 3 3 3 3 3 3 3 3 3Bream Bay (MarsdenDiesel)9 9 9 9 9 9 9 9 9 9 9Kaikohe (Ngawha) 27 27 27 27 27 27 27 27 27 27 27Maungatapere(Wairua)5 5 5 5 5 5 5 5 5 5 544Only generators with a capacity greater than 1 MW are listed. Generation capacity is rounded to thenearest megawatt.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 91

Chapter 7: Northland RegionGrid injection point(location ifembedded)Next 5 yearsGeneration capacity (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Silverdale (Redvale) 10 10 10 10 10 10 10 10 10 10 101. Rosedale generation is limited to approximately 1 MW due to insufficient gas at the site. This amountis not expected to rise significantly within the next few years.7.5 Northland significant maintenance workOur capital project and maintenance works are integrated to enable system issues tobe resolved if possible when assets are replaced or refurbished. Table 7-3 lists thesignificant maintenance-related work 45 proposed for the Northland region for the next15 years that may significantly impact related system issues or connected parties.Table 7-3: Proposed significant maintenance workDescriptionAlbany 220/110/11 kVinterconnecting transformerexpected end-of-lifeHenderson 220/110/11 kVinterconnecting transformersexpected end-of-lifeHenderson 33 kV outdoor to indoorconversionHepburn Road 33 kV outdoor toindoor conversionKensington supply transformerexpected end-of-lifeMaungaturoto 33 kV outdoor toindoor conversionWellsford supply transformersexpected end-of-lifeTentativeyearRelated system issues2022-2024 The appropriate replacement option will beconsidered and carried out in conjunction with theHenderson interconnecting transformersreplacement. See Section 7.8.1 for moreinformation.2023-2025 The appropriate replacement option will beconsidered and carried out in conjunction with theAlbany interconnecting transformer replacement.See Section 7.8.1 for more information.2014-2016 Henderson supply transformer n-1 capacity islimited by transformer branch component limits.The work to remove these limits will becoordinated with the 33 kV outdoor to indoorconversion work. See Section 7.8.10 for moreinformation.2014-2016 No system issues are identified within theforecast period.2027-2029 The forecast load at Kensington already exceedsthe Kensington transformer n-1 capacity. SeeSection 7.8.12 for information.2017-2019 No system issues are identified within theforecast period.2015–2017 The forecast load at Wellsford already exceedsthe transformer n-1 capacity. See Section 7.8.15for more information.7.6 Future Northland projects summary and transmission configurationTable 7-4 lists projects to be carried out in the Northland region within the next 15years.Figure 7-4 shows the possible configuration of Northland transmission in 2028, withnew assets, upgraded assets, and assets undergoing significant maintenance withinthe forecast period.Table 7-4: Projects in the Northland region up to 2028Circuit/site Projects StatusAlbanyReplace interconnecting transformer.Resolve supply transformers’ protection and circuit breaker limits.ProposedPossible45This may include replacement of the asset due to its condition assessment.922013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 7: Northland RegionAlbany–Wairau Road–Hobson Street–PenroseConstruct a new 220 kV underground cable link.CommittedHendersonHenderson–WellsfordReplace switchgear on the interconnecting transformers.Replace interconnecting transformers.Install a new 220/33 kV supply transformerConvert 33 kV outdoor switchgear to an indoor switchboard.Install a special protection scheme to automatically split the system.PossiblePossiblePossibleProposedPossibleHepburn Road Convert 33 kV outdoor switchgear to an indoor switchboard. ProposedHuapai Split the Huapai 220 kV bus. PossibleKaikohe–MaungatapereThermal upgrade the circuits.PossibleKaitaia Install a second 20 Mvar binary switched capacitor bank. PossibleKensingtonMarsdenMaungaturotoReplace supply transformers with higher-rated units.Upgrade 33 kV switchboard.Install two new STATCOMs.Install a third interconnecting transformer.Convert 220 kV and 110 kV buses to three zonesConvert 33 kV outdoor switchgear to an indoor switchboard.Resolve supply transformers’ protection and metering limits.PossiblePossibleCommittedPossiblePossibleProposedPossibleSilverdale Recalibrate supply transformers’ metering parameters. PossibleWellsfordResolve supply transformers’ protection and metering limits.Replace existing 110/33 kV supply transformers.PossibleProposedWairau Road Construct a new grid exit point. Committed2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 93

Chapter 7: Northland RegionFigure 7-4: Possible Northland transmission configuration in 2028KaitaiaLines company assets33 kV110 kV110 kVKaikohe33 kVKensington33 kVMaungatapere110 kVMarsdenBream Bay33 kV220 kV220 kVSTCSTC110 kVMaungaturoto33 kV**110 kVWellsford110 kV**33 kVKEYSilverdaleNEW ASSETSUPGRADED ASSETSASSETS SCHEDULEDFOR REPLACEMENT*MINOR UPGRADEHuapai220 kV110 kV**33kV***SVC220 kV33 kVAlbany33 kV220 kV 110 kVHenderson110 kVOtahuhu**Southdown Mount RoskillAUCKLAND33 kVHepburnRoadWAIRAU ROAD220 kV33 kVVECTORWAIRAU ROADHobson Street / PenroseAUCKLANDLines company assets7.7 Changes since the 2012 Annual Planning ReportTable 7-5 lists the specific issues that are either new or no longer relevant within theforecast period when compared to last year's report.Table 7-5: Changes since 2012IssuesBream Bay supply transformer capacityDargaville supply transformer capacityDargaville transmission securityKensington transmission securityMaungatapere supply transformer capacityChangeRemoved. Protection upgraded resulting in highertransformer capacity.Removed. Assets transferred to Northpower.Removed. Assets transferred to Northpower.Removed. A revised load forecast due todistribution network development and load shiftingmeans this is no longer an issue.Removed. Assets transferred to Northpower.7.8 Northland transmission capabilityTable 7-6 summarises issues involving the Northland region for the next 15 years.For more information about a particular issue, refer to the listed section number.942013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 7: Northland RegionTable 7-6: Northland region transmission issuesSectionnumberIssueRegional7.8.1 Henderson interconnecting transformer capacity7.8.2 Henderson–Wellsford transmission capacity7.8.3 Marsden interconnecting transformer capacity7.8.4 North Auckland and the Northland region transmission capacity7.8.5 North of Henderson transmission capacity7.8.6 North of Huapai transmission security7.8.7 North of Marsden low voltage7.8.8 Upper North Island voltage instability for grid backbone contingenciesSite by grid exit point7.8.9 Albany supply transformer capacity7.8.10 Henderson supply transformer capacity7.8.11 Kaikohe–Maungatapere 110 kV transmission capacity7.8.12 Kensington supply transformer capacity7.8.13 Maungaturoto supply transformer capacity7.8.14 Silverdale supply transformer capacity7.8.15 Wellsford supply transformer capacityBus Security7.9.1 Transmission bus security7.9.2 Henderson–Wellsford7.9.3 Henderson–Hepburn Road7.9.4 North of Marsden low voltage7.8.1 Henderson interconnecting transformer capacityProject reference: HEN-POW_TFR-EHMT-01Project status/type: Possible, Base CapexIndicative timing: 2023Indicative cost band: AIssueThere are two 220/110 kV interconnecting transformers at Henderson, providing:a total nominal installed capacity of 400 MVA, andn-1 capacity of 229/229 MVA 46 (summer/winter).Loading on these transformers may exceed their n-1 capacity during peak load from2014.In addition, Vector is able to transfer approximately 90 MW of load from Penrose toMount Roskill. If this occurs during peak load periods, the load on the Hendersoninterconnecting transformers will exceed their n-1 capacity from 2013.46The transformer’s capacity is limited by switchgear; with this limit resolved, the n-1 capacity will be254/270 MVA summer/winter.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 95

Chapter 7: Northland RegionSolutionCommissioning of the NAaN project, scheduled for completion in 2013, will delay theissue to 2023.If required, we will replace the limiting switchgear on the Henderson interconnectingtransformers to enable full use of their post-contingency capacity of 254/270 MVA(summer/winter).In addition, the interconnecting transformers at Henderson have an expected end-oflifewithin the forecast period. One possible option is to replace both existinginterconnecting transformers at Henderson with 250 MVA units. The appropriatereplacement option will be considered and carried out in conjunction with the Albanyinterconnecting transformer replacement (see Section 7.5).7.8.2 Henderson–Wellsford transmission capacityProject reference:Project status/type:Indicative timing: 2024Indicative cost band:HEN_MPE-TRAN-EHMT-01Possible, Base CapexCIssueThere are two 110 kV circuits between Henderson and Wellsford, each rated at55/68 MVA (summer/winter). An outage of one Henderson–Wellsford circuit willcause the other circuit to exceed its capacity from 2024.SolutionThe most likely solution will be to split the 110 kV network between Henderson andMaungatapere to remove the overload. Another possible option is to thermallyupgrade the Henderson–Wellsford circuits. The options to resolve the issue will beinvestigated closer to the need date.7.8.3 Marsden interconnecting transformer capacityProject reference:Project status/type:Indicative timing: 2023Indicative cost band:MDN-POW_TFR-DEV-01Possible, Base CapexNew interconnecting transformer: BIssueThere are two 220/110 kV interconnecting transformers at Marsden, providing:a total nominal installed capacity of 300 MVA, andn-1 capacity of 180/188 MVA (summer/winter).Loading on these transformers may exceed their n-1 capacity during peak load from2023.SolutionThe Marsden site allows a third 220/110 kV transformer and three bus sections.7.8.4 North Auckland and the Northland region transmission capacityProject context:Project reference:Project status/type:NAaNALB_PAK-TRAN-DEV-01Committed, to meet the Grid Reliability Standard (core grid)962013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 7: Northland RegionIndicative timing: Q4 2013Indicative cost band:GIssueTwo 220 kV Henderson–Otahuhu circuits supply the Northland region’s load, with theparallel 110 kV Otahuhu–Roskill–Hepburn–Henderson circuits supplying MountRoskill from both the north and south under normal grid configuration. The 220 kVcircuit capacities are limited by station equipment at Henderson to 915 MVA percircuit. The conductor rating of each circuit is 938/984 MVA (summer/winter).An outage of a Henderson–Otahuhu circuit may cause the Henderson–Southdowncircuit to exceed its branch rating by winter 2017.A double-circuit outage of the 220 kV Henderson–Otahuhu line will result in asignificantly lower capacity for supplying the North Auckland and Northland load viathe 110 kV transmission network.SolutionWe are committed to implementing the NAaN project in 2013 (see Chapter 8 for moreinformation). This will ensure loading on the 220 kV Henderson–Otahuhu circuitsremain within the n-1 capacity, and improve reliability of supply to the Northlandregion.7.8.5 North of Henderson transmission capacityProject status/type:This issue is for information onlyIssueThe 220 kV Henderson–Huapai–1 circuit is rated at 457/457 MVA 47 (summer/winter).An outage of the parallel 220 kV Albany–Henderson–3 circuit may cause the 220 kVHenderson–Huapai–1 circuit to exceed its branch rating during peak winter loadperiods.The present system allows transfer of the Liverpool Street load through Vector’snetwork to Mount Roskill, if required. This will increase the loading on theHenderson–Huapai–1 circuit.SolutionCompletion of the NAaN project in 2013 provides a second 220 kV connection intoAlbany from the south, resolving the capacity issue in the long term.7.8.6 North of Huapai transmission securityProject reference:Project status/type:Indicative timing: 2016Indicative cost band:HPI-BUSC-DEV-01Possible, Base CapexAIssueThe Huapai switching station comprises three circuit breakers:one on each of the 220 kV circuits connecting Marsden and Bream Bay, and47The capacity of this circuit is limited by substation equipment at Henderson; with this limit resolved,the capacity will be 666/740 MVA (summer/winter).2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 97

Chapter 7: Northland Regiona shared circuit breaker for the two incoming 220 kV circuits from Albany andHenderson.If the shared circuit breaker fails to trip following a fault, both the incoming circuits willtrip, leaving the entire load north of Huapai supplied by the low capacity 110 kVHenderson–Maungatapere circuits. This will result in significant load shedding.SolutionSplitting the Huapai bus once the NAaN project is completed (see Chapter 8 for moreinformation) will resolve this issue when the grid is under normal configuration. Thesplit will be closed during outages of 220 kV circuits which reduce the transmissioncapacity into Albany (for example, a Henderson–Otahuhu circuit or a NAaN cablecircuit between Penrose and Albany) to avoid placing Albany and the Northlandregion on n security.7.8.7 North of Marsden low voltageProject reference:Project status/type:Indicative timing: 2017-2018Indicative cost band:MDN-REA_PWRS-DEV-01Possible, Base Capex and/or customer-specificBIssueIncreasing load lowers the voltage in the Northland region. As a result, if Ngawha isgenerating 10 MW, an outage of:the 220 kV Huapai–Marsden circuit from 2013 will cause low voltages at theMarsden and Bream Bay 220 kV buses, and the Kaikohe 110 kV point of service.one of the 110 kV Marsden–Maungatapere circuits will cause low voltages atMaungatapere and Kaikohe from 2013, andone of the 110 kV Kaikohe–Maungatapere circuits will cause low voltages atKaikohe from 2013.Solution220 kV circuit outageThe low voltage issues due to the loss of a 220 kV circuit will be solved by installingtwo STATCOMs at Marsden, with commissioning scheduled for 2013 (see Chapter 8,Section 8.8.1). This will resolve the low voltage issue due to a 220 kV circuit outage,for the forecast period and beyond.110 kV circuit outageThe Ngawha generation station is embedded behind the Kaikohe supply bus. IfNgawha is generating 25 MW, the issue can be delayed to until 2018.In the longer term, the low voltage issue due to the loss of a 110 kV circuit can beresolved as a transmission investment by installing reactive support at Kaitaia and/orMaungatapere, or as a non-transmission alternative by installing capacitors atKaikohe. The reactive support is most effective if installed at Kaitaia to avoid lowvoltages at all other substations. Greater amounts of reactive support are required ifthe reactive support is solely at Kaikohe or Maungatapere.Addressing the low voltage issue due to the loss of a 110 kV circuit involves atrade-off between operating at a lower than normal voltage, transmission investment982013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 7: Northland Regionin reactive support, and investment within the distribution network (non-transmissionalternatives). Options include 48 :operating at a low voltage (for example, 0.9 p.u. at the Kaitaia 110 kV bus), andfollowing a circuit outage, automatically switching in the existing binary switchedcapacitors at Kaitaiaoperating within the standard voltage range by switching in the Kaitaia capacitors,and accepting a 20% voltage drop should the Kaitaia capacitors tripinstalling 20 Mvar of binary switched capacitors at Kaitaia (a duplicate of theexisting binary switched capacitor bank there), so the voltage is always within thestandard range, orinstalling 60 Mvar at Maungatapere by 2018 and 80 Mvar by 2022, so the voltageis always within the standard range.Capacitor-based reactive support at Maungatapere will require many small capacitorbanks to limit the voltage step when switching the capacitors. This may result in anunrealistic capacitor bank installation, requiring a STATCOM instead.Installing capacitors at Kaitaia will result in a leading power factor at theTranspower/Top Energy boundary.7.8.8 Upper North Island voltage instability for grid backbone contingenciesProject status/type: See Chapter 6, Sections 6.4.1 and 6.4.2IssueAs demand in the Auckland and Northland regions grows, voltage stability marginswill deteriorate to the point where there are several generators and circuitcontingencies on the grid backbone that can cause voltage control problems withinthe Northland region (see Chapter 6, Sections 6.4.1 and 6.4.2, for more information).SolutionWe have proposed and committed to a number of projects to solve the issuesidentified. These are detailed under the North Island Grid Backbone Issues andProject Options (see Chapter 6, Sections 6.4.1 and 6.4.2 for more information).7.8.9 Albany supply transformer capacityProject reference:Project status/type:Indicative timing: 2023Indicative cost band:ALB-POW_TFR_EHMT-01Possible, Base CapexAIssueThree 220/33 kV transformers (two rated at 100 MVA and one at 120 MVA) supplyAlbany’s load, providing:a total nominal installed capacity of 320 MVA, andn-1 capacity of 234/234 MVA 49 (summer/winter).The peak load at Albany is forecast to exceed the transformers’ n-1 winter capacityby approximately 1 MW in 2026, increasing to approximately 9 MW in 2028 (seeTable 7-7).4849The figures given in the options list are with the existing four 5 Mvar of capacitors at Kaikohe, withinTop Energy’s network. Other figures apply if the capacitors are not available.The transformers’ capacity is limited by a protection limit; with this limit resolved, the n-1 capacity willbe 244/258 MVA (summer/winter).2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 99

Chapter 7: Northland RegionTable 7-7: Albany supply transformer overload forecastCircuit/gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Albany 0.99 0 0 0 0 0 0 0 0 0 1 9SolutionResolving the transformers’ protection and circuit breaker limits will solve the issuebeyond the forecast period. We will discuss with the customer closer to the needdate. Future investment will be customer driven.7.8.10 Henderson supply transformer capacityProject reference:Project status/type:Indicative timing:Indicative cost band:HEN-POW_TFR-EHMT-02Possible, customer-specificTo be advisedBIssueTwo 220/33 kV transformers supply Henderson’s load, providing:a total nominal installed capacity of 240 MVA, andn-1 capacity of 135/135 MVA 50 (summer/winter).The peak load at Henderson is forecast to exceed the transformers’ n-1 wintercapacity by approximately 3 MW in 2014, increasing to approximately 54 MW in 2028(see Table 7-8).Table 7-8: Henderson supply transformer overload forecastCircuit/gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Henderson 0.99 0 3 7 10 13 17 24 32 39 47 54SolutionWe will convert the Henderson 33 kV outdoor switchgear to an indoor switchboardwithin the next five years. This will raise the n-1 limit but will not resolve the issue.In addition, Vector has the ability to shift load between Henderson and HepburnRoad, providing an operational solution when the issue arises. A longer-term optionis to install a third supply transformer.7.8.11 Kaikohe–Maungatapere 110 kV transmission capacityProject reference:Project status/type:Indicative timing:Indicative cost band:KOE_MPE-TRAN-EHMT-01Possible, customer-specificTo be advisedTo be advised50The transformers’ capacity is limited by a bus section, circuit breaker and disconnector; with theselimits resolved, the n-1 capacity will be 144/150 MVA (summer/winter).1002013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 7: Northland RegionIssueTwo 110 kV Kaikohe–Maungatapere circuits supply Kaikohe. The two circuitsprovide:a total nominal installed capacity of 141/155 MVA (summer/winter), andn-1 capacity of 63/77 MVA (summer/winter).The peak load of Kaikohe may already exceed the transmission n-1 capacity for anoutage of a Kaikohe–Maungatapere circuit at Maungatapere when Ngawha is notgenerating.SolutionThe Ngawha generation station is embedded behind the Kaikohe supply bus. IfNgawha is generating near its 25 MW maximum, the issue can be delayed to untilnearly the end of the forecast period. Installing reactive support (see Section 7.8.7),particularly at Kaikohe, will also delay the issue.The issue may also be managed operationally by Top Energy limiting the net peakload to the circuit’s capacity. A possible longer-term option is to thermally upgradethe Kaikohe–Maungatapere circuits. Future investment will be customer driven.7.8.12 Kensington supply transformer capacityProject reference:Project status/type:Indicative timing:Indicative cost band:KEN-SUB-EHMT-01Possible, customer-specificTo be advisedTo be advisedIssueTwo 110/33 kV transformers supply Kensington’s load, providing:a total nominal installed capacity of 100 MVA, andn-1 capacity of 59/62 MVA (summer/winter).An outage of one Kensington–Maungatapere circuit and a supply transformer willcause the remaining supply transformer to exceed its n-1 winter capacity byapproximately 10 MW in 2013 (see Table 7-9).Table 7-9: Kensington supply transformer overload forecastCircuit/gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Kensington 0.99 10 10 10 10 10 10 10 10 10 10 10SolutionLoad growth at Kensington is expected to be limited by Northpower to within the n-1capacity of the transformers. If a higher load off-take is required, options include:automatically shedding load if a transformer overloadsreplacing the transformers (and 33 kV switchboard) with higher rated units, andinstalling a 110 kV bus. 5151Kensington is configured as two transformer-feeder circuits (as there is no 110 kV bus) and a circuitoutage will cause an outage of the associated circuit. Therefore, the load off-take is limitedpre-contingency so that, following an outage, the load on the remaining transformer-circuit is withinthe rating of the in-service equipment.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 101

Chapter 7: Northland RegionIn addition, the Kensington supply transformers have an expected end-of-life withinthe forecast period. Future investment will be customer driven.7.8.13 Maungaturoto supply transformer capacityProject reference:Project status/type:Indicative timing: 2018Indicative cost band:MTO-POW_TFR-EHMT-01Possible, Base CapexAIssueTwo 110/33 kV transformers supply Maungaturoto’s load, providing:a total nominal installed capacity of 50 MVA, andn-1 capacity of 20/20 MVA 52 (summer/winter).The peak load at Maungaturoto is forecast to exceed the transformers’ n-1 wintercapacity by 1 MW in 2018, increasing to approximately 4 MW in 2028 (see Table7-10).Table 7-10: Maungaturoto supply transformer overload forecastCircuit/gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Maungaturoto 1.0 0 0 0 0 0 1 1 2 2 3 4SolutionWe will convert the Maungaturoto 33 kV outdoor switchyard to an indoor switchboardwithin the next 5-10 years. Protection and metering limits will be resolved at thesame time. This will solve the supply transformer capacity issue for the forecastperiod and beyond.7.8.14 Silverdale supply transformer capacityProject reference:Project status/type:Indicative timing: 2024Indicative cost band:SVL-POW_TFR-EHMT-01Possible, Base CapexAIssueTwo 110/33 kV transformers supply Silverdale’s load, providing:a total nominal installed capacity of 220 MVA, andn-1 capacity of 109/109 MVA 53 (summer/winter).The peak load at Silverdale is forecast to exceed the transformers’ n-1 wintercapacity by approximately 2 MW in 2024, increasing to approximately 14 MW in 2028(see Table 7-11).Table 7-11: Silverdale supply transformer overload forecastCircuit/grid Power Transformer overload (MW)5253The transformers’ capacity is limited by protection and metering limits; with these limits resolved, then-1 capacity will be 31/33 MVA (summer/winter).The transformers’ capacity is limited by a metering limit, followed by a cable limit (120 MVA); withthese limits resolved, the n-1 capacity will be 126/132 MVA (summer/winter).1022013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 7: Northland Regionexit point factorNext 5 years5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Silverdale 1.00 0 0 0 0 0 0 0 0 2 10 14SolutionRecalibrating the metering parameters resolves the issue for the forecast period andbeyond.7.8.15 Wellsford supply transformer capacityProject reference:Project status/type:Indicative timing:Indicative cost band:WEL-POW_TFR-EHMT-01Possible, Base CapexTo be advisedAIssueTwo 110/33 kV transformers supply Wellsford’s load, providing:a total nominal installed capacity of 60 MVA, andn-1 capacity of 31/31 MVA 54 (summer/winter).The peak load at Wellsford already exceeds the transformers’ n-1 winter capacity,and the overload is forecast to increase to approximately 20 MW in 2028 (see Table7-12). Both existing transformers are made up of three single-phase units, with nospare unit on site.Table 7-12: Wellsford supply transformer overload forecastCircuit/gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Wellsford 0.99 6 7 8 9 10 10 12 14 17 19 20SolutionWe are investigating resolving the protection and metering limits to enable use of thetransformers’ full capacity. This will increase the n-1 capacity to 37/39 MVA(summer/winter), deferring the issue for two years.Both 110/33 kV transformers at Wellsford have an expected end-of-life within the nextfive years. We will discuss with Vector the rating and timing for the replacementtransformers.7.9 Northland bus securityThe 2013 APR has been expanded to include issues arising from the outage of asingle bus section rated at 50 kV and above for the next 15 years.Bus outages disconnect more than one power system component (for example, othercircuits, transformers, reactive support or generators). Therefore, bus outages maycause greater issues than a single circuit or transformer outage (although the risk of abus fault is low, being less common than a circuit or transformer outage).54The transformers’ capacity is limited by protection equipment and metering limits; with these limitsresolved, the n-1 capacity will be 37/39 MVA (summer/winter).2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 103

Chapter 7: Northland Region7.9.1 Transmission bus securityTable 7-13 lists bus outages that cause voltage issues or a total loss of supply.Generators are included only if a bus outage disconnects the whole generationstation or causes a widespread system impact. Supply bus outages, typically 11 kVand 33 kV, are not listed.Table 7-13: Transmission bus outagesTransmissionbus outageLoss ofsupplyGenerationdisconnectionTransmissionissueFurtherinformationHepburn Road110 kVHenderson–Wellsfordoverloading7.9.2Marsden 220 kVHenderson–Hepburn Roadoverloading7.9.3Maungatapere110 kVNorth of Marsden low voltage 7.9.4There is no total loss of supply or generation due to bus fault.7.9.2 Henderson–Wellsford overloadingProject reference: HEN_WEL-TRAN-EHMT-01Project status/type: Possible, Base CapexIndicative timing: 2020Indicative cost band: CIssueA 220 kV bus section outage at Marsden that disconnects the Huapai–Marsden–1circuit and T5 interconnecting transformer will cause the Henderson–Wellsford–1 and2 circuits to overload from 2020.SolutionOptions to resolve the issue include either:providing sufficient reactive support north of Marsden (see Section 7.8.7), whichresolves the issue up to 2024splitting or thermally upgrading the Henderson–Wellsford–1 and 2 circuits (seeSection 7.8.2).We will investigate options to resolve the issue closer to the need date.7.9.3 Henderson–Hepburn Road overloadingProject reference:Project status/type:Indicative timing: 2025Indicative cost band:HEN_HEP-TRAN-EHMT-01Possible, Base CapexTo be advisedIssueAn outage of a 110 kV bus section at Hepburn Road will cause the Henderson–Hepburn Road–3 and 4 circuits to exceed their thermal capacity from 2025.SolutionA number of other network developments, particularly in the Auckland region, arelikely to influence the severity and timing of this issue. We will monitor this issue asthese developments take place.1042013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 7: Northland Region7.9.4 North of Marsden low voltageProject reference: MDN-REA_PWRS-DEV-01Project status/type: Possible, Base Capex and/or customer-specificIndicative timing: 2017-2018Indicative cost band: BIssueAn outage of a 110 kV bus section at Maungatapere disconnects half of all thecircuits and transformers connected at Maungatapere. This will cause low voltages atKaikohe, Dargaville, Maungatapere and Kensington from 2013.SolutionThe low voltage issue can be resolved by installing reactive support in the affectedarea. The reactive support is most effective if installed at Kaitaia to avoid lowvoltages at all other substations. This solution is similar to the low voltage issue for asingle circuit outage (see Section 7.8.7 for more information), although a greater levelof reactive support is required.7.10 Other regional items of interestThere are no other items of interest identified to date beyond those set out in Section7.8 and 7.9. See Section 7.11 for more information about generation scenarios,proposals and opportunities relevant to this region.7.11 Northland generation scenarios, proposals and opportunitiesThis section details relevant regional issues for selected generation scenarios,generation proposals under investigation by developers and in the public domain, orother generation opportunities. The impact of committed generation projects on thegrid backbone is dealt with separately in Chapter 6.The maximum generation that can be connected depends on several factors andusually falls within a range. Generation developers should consult with us at an earlystage of their investigations to discuss connection issues.7.11.1 Impact of generation scenarios on regional planThe generation scenarios (see Chapter 5) represent a series of possible futuregeneration outcomes. This section presents only those scenarios relevant to thisregion for the next 15 years.There are no additional issues within the region with any of the generation scenarios.Generation expansion under all scenarios is within the capability of the existing grid.7.11.2 Maximum regional generationThe following maximum generation estimates assume a light North Island load profileand that existing generation is high (Ngawha generating 25 MW).For generation connected at the Maungatapere 110 kV bus, the maximum generationthat can be injected under n-1 is approximately 300 MW. Generation is constrainedby one Marsden interconnector when the other interconnector is out of service.For generation connected at the Huapai 220 kV bus, the maximum generation thatcan be injected under n-1 is approximately 560 MW. This constraint is due to theHenderson–Huapai 1 circuit overloading when Albany–Huapai 1 is out of service.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 105

Chapter 7: Northland RegionThis may increase to 750 MW if a substation equipment constraint on this circuit isremoved.7.11.3 Generation injection at MaungatapereGeneration of approximately 300-350 MW can be connected directly or indirectly tothe Maungatapere 110 kV bus. This includes generation at Kaikohe, and for somesystem configurations, generation connected to the 110 kV Henderson–Maungatapere line (see also Section 7.11.4). Higher levels of generation may bemade possible by replacing some equipment at substations, upgrading the Marsdeninterconnection capacity, and thermally upgrading the Henderson–Maungatapereline.7.11.4 Generation connected to the 110 kV Henderson–Maungatapere lineThere is a 110 kV double-circuit line from Henderson to Wellsford, Maungaturoto, andMaungatapere. Each circuit is rated at 56/68 MVA (summer/winter). Generation upto a total of approximately 200 MW can be connected, provided a system split is putin place with half the generation transmitted towards Maungatapere and half towardsHenderson. In addition, if one circuit is out of service, the generation must beautomatically reduced to match the capacity of the remaining circuit.The two circuits can be thermally upgraded to allow approximately 300 MW ofgeneration, or have replacement conductors to allow even greater generation.Generation transmitted towards Maungatapere forms part of the generation injectionlimit into Maungatapere (see Section 7.11.3 for more information).7.11.5 Generation connected to the 220 kV Huapai–Marsden lineThere is a 220 kV double-circuit line from Huapai (north of Auckland) to Marsden andBream Bay (in Northland), which is the main connection to the Northland region. Onecircuit is predominantly a simplex conductor and the other is a duplex conductor, withratings of 333/370 MVA and 666/740 MVA 55 , respectively.Generation can be connected along this line, not just at existing substations.Maximum generation of between 300 MW and 500 MW may be possible dependingon which circuit the generation connects into, with the simplex Bream Bay–Huapaiconductor being the limiting component. New generation elsewhere in the Northlandregion will reduce this limit.7.11.6 Generation connected to the 220kV bus at MarsdenFor generation connected at the Marsden 220 kV bus, the maximum generation thatcan be injected under n-1 is approximately 600 MW. The constraint is due to theBream Bay–Huapai 1 circuit overloading for an outage of the Albany–Huapai–Marsden line.7.11.7 Generation connected to the 110kV bus at MarsdenFor generation connected at the Marsden 110 kV bus, the maximum generation thatcan be injected under n-1 is approximately 275 MW. The constraint is due to oneMarsden interconnecting transformer overloading for an outage of the paralleltransformer.55The actual circuit rating is presently limited to 457 MVA due to some substation equipment, which isrelatively easy and inexpensive to replace in the context of generation connection. Therefore, thelimit is ignored in the context of this discussion.1062013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 8: Auckland Region8 Auckland Regional Plan8.1 Regional overview8.2 Auckland transmission system8.3 Auckland demand8.4 Auckland generation8.5 Auckland significant maintenance work8.6 Future Auckland projects summary and transmission configuration8.7 Changes since the 2012 Annual Planning Report8.8 Auckland transmission capability8.9 Auckland bus security8.10 Other regional items of interest8.11 Auckland generation scenarios, generation proposals and opportunities8.1 Regional overviewThis chapter details the Auckland regional transmission plan. We base this regionalplan on an assessment of available data, and welcome feedback to improve its valueto all stakeholders.Figure 8-1: Auckland regionConstruction voltages shown. System as at March 2013.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 107

Chapter 8: Auckland RegionThe Auckland region has some of the highest load densities in New Zealand, coupledwith relatively low levels of local generation.We have assessed the Auckland region’s transmission needs over the next 15 yearswhile considering longer-term development opportunities. Specifically, thetransmission network needs to be flexible to respond to a range of future service andtechnology possibilities, taking into consideration:the existing transmission networkforecast demandforecast generationequipment replacement based on condition assessment, andpossible technological development.8.2 Auckland transmission systemThis section highlights the state of the Auckland regional transmission network. Theexisting transmission network is set out geographically in Figure 8-1 andschematically in Figure 8-2.Figure 8-2: Auckland transmission schematicNORTHLANDHenderson Hepburn RoadVECTOR CBD22 kVVECTOR CBD33 kVPenrose220 kV110 kVMount Roskill22 kV110 kVSouthdownPakuranga33 kV220 kV220 kVSCKEY220kV CIRCUIT110kV CIRCUITSUBSTATION BUSTRANSFORMERTEE POINTLOADCAPACITORUNDERGROUND CABLEBONDED CIRCUITMangere33 kV 110 kV220 kV110 kVOtahuhuCombinedCycleWiri33 kVSC110 kVOtahuhu110 kV22 kV220 kVBrownhill220 kV110 kVSCSYNCHRONOUS CONDENSER33 kVGENERATORTakaniniBombayGlenbrook33 kV 220 kV33 kV 220 kVDrury220 kVHuntlyWAIKATOOhinewai Whakamaru Arapuni HamiltonWAIKATOWhakamaru1082013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 8: Auckland Region8.2.1 Transmission into/through the regionAs approximately 70% of the Auckland and Northland regions’ peak electricitydemand is supplied by generation located south of Bombay, transmission isnecessary to keep the energy flowing into Auckland and through to North Aucklandand the Northland region.There are two major projects and a series of minor projects that we are progressingto ensure that the Auckland region has secure transmission as demand grows.Broader project descriptions that provide a context for the issues identified in latersections include the:North Auckland and Northland (NAaN) grid upgrade project, andUpper North Island Reactive Support (UNIRS) project.North Auckland and Northland (NAaN) grid upgrade projectThis committed project adds new transmission capacity between the Pakuranga,Penrose, and Albany substations. It also enables the building of new grid exit pointsat Hobson Street (Auckland CBD) and Wairau Road (North Shore) as well asreinforcing transmission in the Auckland region and across into the Northland region.The 220 kV circuit from Pakuranga to Penrose:increases capacity to the Penrose 220 kV bus by adding a third 220 kV circuitalongside the existing 220 kV Otahuhu–Penrose double-circuit line, andbuilds on the NIGU project by increasing the diversity for transmission from thesouth into the Auckland region, as there will be 220 kV transmission fromPakuranga to Otahuhu and Penrose.The 220 kV circuit from Penrose to Albany:increases capacity to the Northland region which is currently supplied by two220 kV circuits from Otahuhu to Hendersonbuilds on the NIGU project by increasing the diversity for transmission from thesouth into the Northland region (including the North Isthmus), as there will be220 kV transmission from Pakuranga, through Penrose, to Albanyprovides capacity and security to Vector’s Hobson Street and Wairau Roadsubstations through a 220 kV connection to the Albany–Penrose circuit, andenables Vector to redistribute load from existing grid exit points, particularly theAlbany 33 kV and 110 kV (Wairau Road) loads and Auckland CBD loads.Upper North Island Reactive Support (UNIRS) projectThe purpose of this project is to relieve voltage stability issues associated with anoutage of major generators and/or circuits supplying the Upper North Island area (seeChapter 6). It includes installing dynamic reactive support at Penrose and Marsden.8.2.2 Transmission and distribution network within the regionThe Auckland transmission network consists of three layers: the 220 kV network, the110 kV network, and the 110 kV distribution system owned by Vector.220 kV transmission networkThe 220 kV network supplies Auckland from two different locations:The first route supplies Otahuhu from the south via a double-circuit line fromHuntly, a double-circuit line from Whakamaru via Ohinewai, and two single-circuitlines from Whakamaru.• The 220 kV network splits from Otahuhu, with one network supplying Penrosevia a double-circuit line, and the other network supplying the Northland region(including the North Isthmus) via a second double-circuit line to Henderson.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 109

Chapter 8: Auckland RegionThe second route supplies Pakuranga from the south via a double circuit 220 kVline from Whakamaru to Brown Hill then 220 kV cables from Brown Hill toPakuranga.• This network already connects to Otahuhu through a double-circuit line. Aftercompletion, the NAaN project will connect Pakuranga to Albany via Penrose,Hobson Street and Wairau Road with 220 kV cable.110 kV transmission networkThe 110 kV transmission network is split into two parts at Otahuhu.One half of the 110 kV network supplies Penrose in parallel with the 220 kVOtahuhu–Penrose double circuit line, with 220/110 kV interconnectors atOtahuhu and Penrose. The 110 kV system also connects to the Waikato regionvia a Bombay–Wiri–Otahuhu double-circuit line, with power flow generally southout of Otahuhu.The other half of the 110 kV network supplies Mangere and Mount Roskill in adouble-circuit ring, extending from Mount Roskill through a double-circuit 110 kVconnection to substations in the Northland region (at Henderson and Albany).There are 220/110 kV interconnections at Otahuhu, Henderson, and Albany,making the 110 kV network parallel with the 220 kV Otahuhu–Henderson doublecircuitline. Power flow is generally into Mount Roskill on all circuits, from bothOtahuhu and the Northland region.110 kV distribution systemVector’s 110 kV distribution system connects from Penrose to Mount Roskill viaVector’s Liverpool Street substation, and is normally split between Mount Roskill andLiverpool Street. However, it is often used to transfer the Liverpool Street load (up to90 MW) between the Penrose and Mount Roskill substations.8.2.3 Reactive powerTo improve the network voltage and voltage stability, static capacitors are installed atthe Otahuhu, Penrose, and Bombay substations. Condensers at Otahuhu providedynamic reactive power under contract.8.2.4 Longer-term development pathWe have identified a longer-term development path to address issues involvingtransmission into, within and through the Auckland region, which will be re-examinedwhen the need arises. The timing of the transmission investments depends on thenet load of the Auckland and Northland regions. New generation in the region ordemand-side response may defer transmission investment. Similarly, regionalgeneration retirement or increased demand will bring forward the need fortransmission investment.Possible future upgrades include, but are not limited to the following:Installation of series compensation on the 220 kV Pakuranga–Whakamarucircuits to improve load sharing with the other 220 kV circuits. Ultimately, theBrownhill–Whakamaru section of the Pakuranga–Whakamaru circuits will beupgraded to operate at 400 kV, by installing 400/220 kV transformers at Brownhilland Whakamaru.Increasing the transfer capacity into Auckland by building a switching station atBrownhill and cable circuits from Brownhill to Otahuhu.Possibly increasing the capacity of the 110 kV circuits between Arapuni andOtahuhu via thermal upgrades or reconductoring with higher-capacity conductors.Transmission reinforcement within the Auckland region via additional 220 kVcable circuits between Pakuranga, Penrose, and Mount Roskill, with a220/110 kV connection at Mount Roskill.1102013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 8: Auckland RegionTransmission reinforcement into the Northland region via a second cablebetween Penrose and Albany.Additional static and dynamic reactive power support approximately every 8-10years to ensure power system voltage stability, and sufficient reserves aremaintained to cover the worst transmission contingency. The seriescompensation on the 220 kV Pakuranga–Whakamaru circuits may be broughtforward because of its positive contribution to voltage stability and reduction intransmission losses.Beyond the next 30 years, new transmission capacity may be required into Auckland,which can be provided by a new 400 kV line, an HVDC link or refurbishment of theexisting lines.The development of the Auckland spatial plan (particularly in the South Aucklandarea) will significantly influence future options for increasing transmission capacityinto Auckland.Figure 8-3 provides an indication of the possible transmission development within andthrough Auckland in the longer-term (beyond 2028).Figure 8-3: Indicative Auckland region schematic beyond 2028VECTOR CBD NETWORKNORTHLANDHendersonHepburn RoadNORTHLANDAlbany / Wairau RoadHobsonStreet110 kV220 kVMVAR110 kV220 kV220 kVPenrose110 kVMountRoskillSouthdown220 kVPakurangaMVAR220 kVKEYMangere110 kV220 kV110 kVOtahuhuCombinedCycleMVAROtahuhu110 kV220 kVNEW ASSETSUPGRADED ASSETSWiri110 kV110 kVBombayBrownhill220 kV400 kVTakaniniHuntlyOhinewaiWhakamaru Arapuni HamiltonWAIKATOWhakamaru8.3 Auckland demandThe after diversity maximum demand (ADMD) for the Auckland region is forecast togrow on average by 2.1% annually over the next 15 years, from 1,536 MW in 2013 to2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 111

Chapter 8: Auckland Region2,104 MW by 2028. This is higher than the national average demand growth of 1.5%annually.Figure 8-4 shows a comparison of the 2012 and 2013 APR forecast 15-yearmaximum demand (after diversity 56 ) for the Auckland region. The forecasts arederived using historical data, and modified to account for customer information, whereappropriate. The power factor at each grid exit point is also derived from historicaldata. See Chapter 4 for more information about demand forecasting.Figure 8-4: Auckland region after diversity maximum demand forecastTable 8-1 lists forecast peak demand (prudent growth) for each grid exit point for theforecast period, as required for the Grid Reliability Report.Table 8-1: Forecast annual peak demand (MW) at Auckland grid exit points to 2028Grid exit pointPowerfactorNext 5 yearsPeak demand (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Bombay 33 kV 1 0.99 25 25 26 13 13 14 0 0 0 0 0Bombay 110 kV 1 1.00 56 57 58 73 74 76 93 96 100 104 107Glenbrook 33 kV 1.00 116 120 120 120 120 120 120 120 120 120 120Glenbrook NZSteel1.00 72 72 72 72 72 72 72 72 72 72 72Hobson Street 2, 3 0.98 114 117 121 125 129 134 143 152 161 170 179Mangere 33 kV 0.98 117 120 122 125 127 130 135 140 145 151 156Mangere 110 kV 0.87 53 53 53 53 53 53 53 53 53 53 53Meremere 4 0.95 15 16 16 0 0 0 0 0 0 0 0Mt Roskill 22 kV 0.98 146 149 152 155 158 161 168 174 181 187 194Mt Roskill110 kV –0.97 65 66 67 67 68 69 71 73 75 77 7956The after diversity maximum demand (ADMD) for the region will be less than the sum of theindividual grid exit point peak demands, as it takes into account the fact that the peak demand doesnot occur simultaneously at all the grid exit points in the region.1122013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 8: Auckland RegionGrid exit pointKingslandPowerfactorPeak demand (MW)Next 5 years5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Otahuhu 1.00 65 67 68 69 71 72 75 78 81 84 87Pakuranga 0.99 162 165 169 172 176 179 186 194 201 208 216Penrose 22 kV 0.97 61 62 64 65 66 68 70 73 76 79 81Penrose 33 kV 0.98 320 330 340 350 361 371 394 417 440 463 485Penrose 110 kV– Liverpool 0.98 114 117 121 125 129 134 143 152 161 170 179Street 3Penrose 110 kV– Quay Street 5 0.98 0 0 0 0 0 0 0 0 0 0 0Takanini 6 0.99 128 130 133 135 138 141 147 152 158 164 169Wiri 0.99 92 94 96 97 99 101 105 110 114 118 1221. The customer advised that approximately half of the load will shift from Bombay 33 kV to Bombay110 kV in 2016, with the balance of the load shifting in 2020.2. A new grid exit point at Hobson Street is planned to be commissioned in 2013. Some of thePenrose–Liverpool Street load will be transferred to Hobson Street.3. The 50/50 load split between Hobson Street and Penrose–Liverpool Street is an estimate only.Paralleling of the Vector and Transpower networks between these grid exit points is beingconsidered.4. The customer advised that the load at Meremere will be shifted to Huntly (in the Waikato region) in2016. This load is currently supplied from out Bombay grid exit point.5. The Penrose 110 kV–Quay Street load has been transferred to Penrose–Liverpool Street and thePenrose–Quay Street circuits decommissioned.6. The customer advised that their forecast is lower than Transpower’s forecast.8.4 Auckland generationThe Auckland region’s generation capacity is approximately 681 MW.Table 8-2 lists the generation forecast for each grid injection point for the forecastperiod, as required for the Grid Reliability Report. This includes all known existingand committed generation stations including those embedded within the relevant locallines company’s network (Vector or Counties Power). 57No new generation is known to be committed in the Auckland region for the forecastperiod.Table 8-2: Forecast annual generation capacity (MW) at Auckland grid injection points to2028 (including existing and committed generation)Grid injection point(location if embedded)Next 5 yearsGeneration capacity (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Glenbrook 1 112 112 112 112 112 112 112 112 112 112 112Mangere (WatercareMangere)7 7 7 7 7 7 7 7 7 7 7Otahuhu B CCGT 380 380 380 380 380 380 380 380 380 380 380Otahuhu(Greenmount Landfill)Penrose (AucklandHospital)6 6 6 6 6 6 6 6 6 6 64 4 4 4 4 4 4 4 4 4 457Only generators with capacity greater than 1 MW are listed. Generation capacity is rounded to thenearest megawatt.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 113

Chapter 8: Auckland RegionGrid injection point(location if embedded)Next 5 yearsGeneration capacity (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Southdown CCGT 175 175 175 175 175 175 175 175 175 175 175Takanini(Whitford Landfill)3 3 3 3 3 3 3 3 3 3 31. This value includes an embedded generating unit with a nominal rating of 38 MW. However, itscontinuous output is approximately 25 MW.8.5 Auckland significant maintenance workOur capital project and maintenance works are integrated to enable system issues tobe resolved if possible when assets are replaced or refurbished. Table 8-3 lists thesignificant maintenance-related work 58 proposed for the Auckland region for the next15 years that may significantly impact related system issues or connected parties.Table 8-3: Proposed significant maintenance workDescriptionBombay supply transformersexpected end-of-life, and33 kV outdoor to indoorconversionMangere 33 kV outdoor toindoor conversionMount Roskill supplytransformer T3 expected end-oflife,and22 kV outdoor to indoorconversionOtahuhu interconnectingtransformer expected end-of-lifeOtahuhu supply transformersexpected end-of-lifePenrose–T10 interconnectingtransformer expected end-of-lifePenrose supply transformersexpected end-of-life, and33 kV outdoor to indoorconversionTakanini 33 kV outdoor toindoor conversionWiri supply transformerexpected end-of-life, and 33 kVoutdoor to indoor conversionTentativeyear2018-20202015-2017Related system issuesBombay supply transformer capacities are sufficient forthe forecast period. The customer may relinquish33 kV supply from Bombay within 10-20 years.2014-2016 The forecast load will exceed the transformer n-1capacity from 2013, due to a protection limit. Ifappropriate, the work to resolve this limit will becoordinated with the 33 kV outdoor to indoor conversionwork. See Section 8.8.5 for more information.2015-20192017-2019The Mount Roskill load is forecast to exceed thetransformer n-1 capacity from 2013. See Section 8.8.6for more information.2019-2021 The options to replace the transformers must becoordinated with the:Penrose–T10 interconnecting transformer replacement– see Section 8.8.3 for more informationOtahuhu–Wiri transmission capacity issue – seeSection 8.8.8 for more information, andOtahuhu–Penrose 110 kV transmission capacity issue– see Section 8.8.7 for more information.2021-2023 The Otahuhu load already exceeds the transformers’n-1 capacity. See Section 8.8.9 for more information.2017-2019 This work will be coordinated with the Otahuhuinterconnecting transformer replacement. See Section8.8.3 for more information.2026-20282012-2014A spare transformer enables us to manage the existingthree supply transformers for the next 15 years. SeeSection 8.8.11 for more information2014-2016 Takanini supply transformer n-1 capacity is limitedtransformer branch component limits. If appropriate, thework to resolve these limits will be coordinated with the33 kV outdoor to indoor conversion work. See Section8.8.12 for more information.2014-20172015-2017The Wiri load is forecast to exceed the transformer n-1capacity by 2019. See Section 8.8.13 for moreinformation.58This may include replacement of the asset due to its condition assessment.1142013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 8: Auckland Region8.6 Future Auckland projects summary and transmission configurationTable 8-4 lists projects to be carried out in the Auckland region within the next 15years.Figure 8-5 shows the possible configuration of Auckland transmission in 2028, withnew assets, upgraded assets, and assets undergoing significant maintenance withinthe forecast period.Table 8-4: Projects in the Auckland region up to 2028Circuit/site Projects StatusAlbany–Penrose 220 kV cables between Albany and Penrose. CommittedBombayReplace 110/33 kV supply transformers.Convert 33 kV outdoor switchgear to an indoor switchboard.ProposedProposedHobson Street New substation at Hobson Street. CommittedMangereMount RoskillOtahuhuOtahuhu–PenroseResolve supply transformer protection limits.Convert 33 kV outdoor switchgear to an indoor switchboard.Replace Mount Roskill–T3 supply transformer.Convert 22 kV outdoor switchgear to an indoor switchboard.Replace Otahuhu–T2 and T4 interconnecting transformers.Replace 220/22 kV supply transformers.Install a new 220/22 kV supply transformer.110 kV bus reconfiguration.Increase the 110 kV circuit’s capacity.PossibleProposedProposedProposedPossibleProposedPossiblePossiblePossibleOtahuhu–Wiri Increase transmission capacity to Wiri. PossiblePakuranga–PenrosePenroseTakaniniWiriInstall 220 kV cable between Pakuranga and Penrose.Install a new +/- 40 Mvar STATCOM at 33 kV bus.Replace Penrose–T10 interconnecting transformer.Replace 220/33 kV supply transformer.Convert 33 kV outdoor switchgear to an indoor switchboard.Upgrade supply transformer branch limiting components.Convert 33 kV outdoor switchgear to an indoor switchboard.Resolve supply transformers’ protection limits.New or upgrade the existing supply transformers’ capacity.Convert 33 kV outdoor switchgear to an indoor switchboard.CommittedCommittedProposedProposedProposedPossibleProposedPossiblePossibleProposed2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 115

Chapter 8: Auckland RegionFigure 8-5: Possible Auckland transmission configuration in 2028NORTHLANDHenderson Hepburn RoadNORTHLANDAlbany / Wairau RoadHobsonStreet110 kV220 kVVECTOR CBDVECTOR CBDVECTOR CBD22 kV33 kVSTCPenrose110 kV220 kVMount Roskill22 kV110 kVSouthdown220 kVPakuranga33 kV220 kVMangere*220 kV110 kVOtahuhu110 kV22 kVKEYNEW ASSETSUPGRADED ASSETSASSETS SCHEDULEDFOR MAINTENANCE*MINOR UPGRADETakanini*33 kV 110 kV*OtahuhuCombinedCycleWiri*33 kV 110 kV110 kVBombay220 kVBrownhill220 kV33 kV*220 kVGlenbrookDrury33 kV220 kV220 kVHuntlyWAIKATOOhinewaiWhakamaruArapuni HamiltonWAIKATOWhakamaru8.7 Changes since the 2012 Annual Planning ReportTable 8-5 lists the specific issues that are either new or no longer relevant within theforecast period when compared to last year's report.Table 8-5: Changes since 2012IssuesNo new issues or projects completed since 2012.ChangeNo change.8.8 Auckland transmission capabilityTable 6-2 summarises issues involving the Auckland region for the next 15 years.For more information about a particular issue, refer to the listed section number.1162013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 8: Auckland RegionTable 8-6: Auckland region transmission issuesSectionnumberIssueRegional8.8.1 Auckland region voltage quality8.8.2 North Auckland and Northland regional transmission security8.8.3 Otahuhu interconnecting transformer capacitySite by grid exit point8.8.4 Hobson Street supply security8.8.5 Mangere supply transformer capacity8.8.6 Mount Roskill supply transformer capacity8.8.7 Otahuhu–Penrose 110 kV transmission capacity8.8.8 Otahuhu–Wiri 110 kV transmission capacity8.8.9 Otahuhu supply transformer capacity8.8.10 Penrose 220 kV transmission security8.8.11 Penrose 33 kV supply transformer capacity8.8.12 Takanini supply transformer capacity8.8.13 Wiri supply transformer capacity8.8.14 Wiri Tee transmission capacityBus security8.9.1 Transmission bus security8.9.2 Bombay–Wiri Tee transmission capacity8.9.3 Otahuhu–Mangere–Mount Roskill8.8.1 Auckland region voltage qualityProject context:UNIRS – Chapter 6, see Section 6.4.1 (UNIRS)IssueAs demand grows in the Auckland and Northland regions, regional voltages maydeteriorate to a point where the outage of a 220 kV circuit may cause voltagecollapse.Generation located in the Auckland and Northland regions is insufficient to meetreactive power demand. Reactive power from non-generation sources such as shuntcapacitors, series capacitors, static synchronous compensators (STATCOM), staticvar compensators (SVC) and condensers is required to ensure the maintenance ofacceptable voltage levels and quality.SolutionWe have a number of projects underway to improve Auckland voltage, including aSTATCOM at Penrose and a STATCOM at Marsden. Despite these projects,Auckland voltage stability is an ongoing issue requiring regular study as the Aucklandand Northland regional loads grow.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 117

Chapter 8: Auckland Region8.8.2 North Auckland and Northland regional transmission securityProject context:NAaNProject reference: ALB_PAK-TRAN-DEV-01Project status/type: Committed, Major Capex ProposalIndicative timing: Q4 2013Indicative cost band: GIssueThere are three issues with respect to Auckland transmission security.North Auckland and Northland supply can be maintained with n-1 security untilwinter 2016. From that date, further transmission reinforcement or a transmissionalternative will be required.North Auckland and Northland load is supplied by a single 220 kV double-circuitoverhead line, leaving this significant load at risk from a double-circuit outage.Vector requires transmission reinforcement in the Auckland CBD (Hobson Street)and on the North Shore (Wairau Road, in the Northland region) in 2014 and2013, respectively.SolutionWe have committed to install a 220 kV cable between the Pakuranga, Penrose andAlbany substations, which:provides security of supply for North Auckland and Northland beyond 2016improves transmission diversity into North Auckland and Northland, andconnects to new grid exit points at Hobson Street and Wairau Road.The cable will provide a capacity of approximately 790 MVA (winter). As the cablewill have significantly lower impedance than the parallel 220 kV overheadtransmission circuits between Otahuhu, Henderson, and Albany, more power will flowthrough the cable than in the parallel circuits. A series reactor in the cable circuit isincluded to balance the power flow between the parallel routes.8.8.3 Otahuhu interconnecting transformer capacityProject status/type:This issue is for information onlyIssueThe Otahuhu 110 kV bus is normally operated split with two separate buses to givebetter load distribution and manage fault levels.There are two pairs of 220/110 kV interconnecting transformers at Otahuhu.One pair (T2 and T4, rated at 100 MVA and 200 MVA, respectively) supplies the110 kV bus section with circuits to Bombay, Penrose and Wiri 110 kV substations,providing:a total nominal installed capacity of 300 MVA, andn-1 capacity of 135/145 MVA (summer/winter).One pair (T3 and T5, rated at 250 MVA each) supplies the 110 kV bus section withcircuits to the Mangere and Mount Roskill 110 kV substations, providing:a total nominal installed capacity of 500 MVA, andn-1 capacity of 318/332 MVA (summer/winter).Otahuhu–T2 and T4 are effectively in parallel with the Penrose–T6 and T10interconnecting transformers through the Otahuhu–Penrose transmission system.1182013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 8: Auckland RegionToward the end of the forecast period, the T2 transformer may exceed its postcontingencycapacity at peak load times for an outage of the T4 transformer.SolutionThe recent conversion of Pakuranga from 110 kV to 220 kV reduced the load on theOtahuhu–T2 and T4, and Penrose–T6 and T10 transformers. These transformersnow have sufficient capacity until the Auckland CBD load reaches approximately300 MW. This is likely to occur in the second half of the forecast period or beyond.Any load permanently transferred to Hobson Street will also reduce the loading on theinterconnecting transformers at Otahuhu and Penrose.Additionally, the Otahuhu–T2, T4 and Penrose–T10 interconnecting transformershave an expected end-of-life within the forecast period. We will investigate thequantity and ratings for the replacement interconnecting transformers.8.8.4 Hobson Street supply securityProject context:NAaNProject reference: HOB-SUBEST-DEV-01Project status/type: Committed, customer-specificIndicative timing: 2014Indicative cost band: D (including an initial 250 MVA 220/110 kV transformer)IssueVector has indicated that to ensure security of supply, it requires reinforcement of itsHobson Street substation by 2014.SolutionA new 220/110 kV grid exit point will be built at Hobson Street connecting to the newAlbany–Penrose cable (see Section 8.8.2). This will also allow Vector to transfersome load from the Penrose 110 kV grid exit point.8.8.5 Mangere supply transformer capacityProject reference: MNG-POW_TFR-01Project status/type: Possible, Base CapexIndicative timing: 2013Indicative cost band: AIssueTwo 110/33 kV transformers supply Mangere’s load, providing:a total nominal installed capacity of 240 MVA, andn-1 capacity of 118/118 MVA 59 (summer/winter).The peak load at Mangere is forecast to exceed the transformers’ n-1 winter capacityby 8 MW in 2013, increasing to approximately 47 MW in 2028 (see Table 8-7).Table 8-7: Mangere supply transformer overload forecastGrid exitpointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Mangere 0.98 8 11 13 16 18 21 26 31 36 42 4759The transformers’ capacity is limited by a protection equipment limit; with this limit resolved, the n-1capacity will be 138/144 MVA (summer/winter).2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 119

Chapter 8: Auckland RegionSolutionWe will discuss options with Vector. Possible solutions include:resolving the protection limit of the transformers which will solve the overloadissue until 2020, orlimiting the peak load to the transformer capacity, with future load growthtransferred to other grid exit points.Future development options to increase transformer capacity for this grid exit pointwill be customer driven.In addition, we also plan to convert the Mangere 33 kV outdoor switchgear to anindoor switchboard within the next five years.8.8.6 Mount Roskill supply transformer capacityProject status/type:This issue is for information onlyIssueThree 110/22 kV transformers (one rated at 50 MVA and two at 70 MVA each) supplyMount Roskill’s load, providing:a total nominal installed capacity of 190 MVA, andn-1 capacity of 140/141 MVA 60 (summer/winter).The peak load at Mount Roskill is forecast to exceed the transformers’ n-1 wintercapacity by 17 MW in 2013, increasing to 65 MW in 2028 (see Table 8-8).Table 8-8: Mount Roskill supply transformer overload forecastGrid exitpointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Mount Roskill 0.98 17 20 23 26 29 32 39 45 52 58 65SolutionThe issue can be managed operationally in the short-term.The Mount Roskill–T3 supply transformer has an expected end-of-life within theforecast period. In addition, we also plan to convert the 22 kV outdoor switchyard toan indoor switchboard within the forecast period.We will discuss the ratings and timing for the replacement transformer with Vector.Further development options to increase transformer capacity for this grid exit pointwill be customer driven.8.8.7 Otahuhu–Penrose 110 kV transmission capacityProject reference: OTA_PEN-TRAN-EHMT-01OTA_PEN-TRAN-EHMT-02Project status/type: Resolve terminal spans constraint at Otahuhu: possible, Base CapexReplace transformers: possible, Base CapexIndicative timing: Resolve terminal spans constraint: 2021Upgrade transmission circuit: to be advisedIndicative cost band: Resolve terminal spans constraint: AReplace transformers: C60The transformer’s capacity is limited by a circuit breaker limit on the 50 MVA transformer and relaylimits on the 70 MVA transformers; with auxiliary equipment limits resolved, the n-1 capacity will be145/152 MVA (summer/winter).1202013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 8: Auckland RegionIssueThe 110 kV Otahuhu–Penrose circuit is rated at 177/195 MVA (summer/winter). Aftercommissioning of the NIGU project, an outage of the Penrose 220/110 kV T10transformer will cause the circuit to overload from 2021.SolutionThe Otahuhu–Penrose 110 kV circuit is limited by the terminal spans at Otahuhu andPenrose substations. With this limit removed, the circuit rating is 191/210 MVA,which will delay the issue in the short term.Longer-term solutions include:replacing the old Otahuhu–T2 and T4 interconnecting transformers with higherimpedance transformers (see also Section 8.8.3)thermally upgrading the circuit to a higher temperature, orreconductoring the circuit with a higher capacity conductor.8.8.8 Otahuhu–Wiri 110 kV transmission capacityProject reference:Project status/type:Indicative timing:Indicative cost band:OTA_WIR-TRAN-DEV-01Possible, Base CapexTo be advisedCIssueTwo 110 kV Bombay–Wiri–Otahuhu circuits supply Wiri’s load, with the:Bombay–Wiri section of each circuit rated at 62/76 MVA (summer/winter), andOtahuhu–Wiri section of each circuit rated at 92/101 MVA (summer/winter).Wiri is a double hard tee connection, and an outage of one of the 110 kV Bombay–Wiri–Otahuhu circuits is forecast to overload the Otahuhu–Wiri section of theremaining circuit during summer peak load periods from 2013. This will occur duringperiods of high Auckland generation and low Waikato generation.SolutionIn the short term, Vector can limit Wiri load with future load growth transferred toother grid exit points. Possible longer-term options are:a new 110 kV cable from Otahuhu connecting to a new 110/33 kV supplytransformer at Wiria new 110/33 kV transformer at Otahuhu and a new 33 kV cable connected intoWirireconductoring the 110 kV Otahuhu–Wiri circuits with higher capacity conductor,ora new 220/110 kV connection at Bombay substation on the Huntly–Otahuhucircuit (to reinforce the supply to Wiri from Bombay) and a 110 kV bus at Wiri.See also the Wiri supply transformer capacity issue (Section 8.8.14) and theBombay–Wiri Tee transmission capacity issue (Section 8.9.2).8.8.9 Otahuhu supply transformer capacityProject reference:Project status/type:Indicative timing:Indicative cost band:OTA-POW_TFR-EHMT-01New transformer: possible, customer-specificTo be advisedB2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 121

Chapter 8: Auckland RegionIssueTwo 220/22 kV transformers supply Otahuhu’s load, providing:a total nominal installed capacity of 100 MVA, andn-1 capacity of 59/59 MVA 61 (summer/winter).The peak load at Otahuhu is forecast to exceed the n-1 winter capacity by 1 MW in2013, increasing to approximately 23 MW in 2028 (see Table 8-9).Table 8-9: Otahuhu supply transformer overload forecastGrid exitpointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Otahuhu 1.00 1 3 4 5 7 8 11 14 17 20 23SolutionUpgrading the LV cable and removing the bushing constraints on the supplytransformers will not resolve the issue.We will discuss other options with Vector, which include:limiting peak load to the firm transformer capacity, with future load growthtransferred to other grid exit pointsadding a third supply transformer, orreplacing the two existing supply transformers with higher-rated units.Both supply transformers have an expected end-of-life within the forecast period. Wewill discuss the ratings and timing for the replacement transformers with Vector.Further development options to increase transformer capacity for this grid exit pointwill be customer driven.8.8.10 Penrose 220 kV transmission securityProject context:NIGU and UNIRSSee Section 6.4.2 (NIGU project) and Section 8.8.2 (NAaN)IssueThe two 220 kV Otahuhu–Penrose circuits are rated at 469/492 MVA(summer/winter). During peak demand periods, an outage of one Otahuhu–Penrosecircuit may cause the other circuit to exceed the conductor rating from 2017.SolutionWe are committed to installing a 220 kV Pakuranga–Penrose cable circuit as part ofthe NAaN project, scheduled for completion in 2013 (see Section 8.8.2). This willaddress the issue until approximately 2028 or beyond, when a second 220 kVPakuranga–Penrose circuit will be required.8.8.11 Penrose 33 kV supply transformer capacityProject status/type:This issue is for information only61The transformers’ capacity is limited by LV cable ratings, followed by a transformer bushings limit(64 MVA); with these limits resolved, the n-1 capacity will be 67/71 MVA (summer/winter).1222013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 8: Auckland RegionIssueThree 220/33 kV transformers (two rated at 200 MVA and one at 160 MVA) supplyPenrose’s load, providing:a total nominal installed capacity of 560 MVA, andn-1 capacity of 429/450 MVA (summer/winter).The peak load at Penrose is forecast to exceed the transformers’ n-1 winter capacityby approximately 16 MW in 2022, increasing to approximately 88 MW in 2028 (seeTable 8-10).Table 8-10: Penrose supply transformer overload forecastGrid exitpointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Penrose 0.98 0 0 0 0 0 0 0 16 40 64 88SolutionWe are discussing future development options for this connection point with Vector.It is expected that the peak load will be limited to the firm transformer capacity, withfuture load growth transferred to other grid exit points. Vector has announced plansto build a new zone substation at Newmarket that will eventually take load off thePenrose 33 kV bus.A 220/33 kV system spare supply transformer is located at Penrose. This allows usto manage outages of the existing three supply transformers for the next 15 years (inparticular, allowing the existing T9 transformer to undergo extensive preventativemaintenance). The firm capacity is not increased, because only three of the fourtransformers are permanently connected.Additionally, we also plan to convert the Penrose 33 kV outdoor switchyard to anindoor switchboard within the forecast period.8.8.12 Takanini supply transformer capacityProject reference: Upgrade transformer branch limiting components: TAK-POW_TFR-EHMT-01Project status/type: Upgrade transformer branch limiting components: possible, Base CapexIndicative timing: 2014-2016Indicative cost band: Upgrade transformer branch limiting components: AIssueTwo 220/33 kV transformers supply Takanini’s load, providing:a total nominal installed capacity of 300 MVA, andn-1 capacity limit of 126/126 MVA 62 (summer/winter).The peak load at Takanini is forecast to exceed the transformers’ n-1 winter capacityby 9 MW in 2013, increasing to approximately 50 MW in 2028 (see Table 8-11).Table 8-11: Takanini supply transformer overload forecastGrid exitpointPowerfactorTransformer overload (MW)62The transformers’ capacity is limited by protection equipment limit, followed by the circuit breaker(137 MVA) and 33 kV bus (137 MVA) limits; with these limits resolved, the n-1 capacity will be188/198 MVA (summer/winter).2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 123

Chapter 8: Auckland RegionNext 5 years5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Takanini 0.99 9 11 14 16 19 22 28 33 39 45 50SolutionVector has advised that they expect to keep peak load within the transformers’ n-1capacity for several years.The Takanini 33 kV outdoor switchyard will be converted into an indoor switchboardwithin the next five years. Upgrading the protection, circuit breaker and busbar inconjunction with the 33 kV conversion provides sufficient capacity beyond theforecast period; however, the 33 kV equipment will have an unusually high rating.The equipment configuration is also unusual for the high level of load forecast forTakanini. The transformers are connected in a double tee configuration to the 220 kVcircuits, which is typically used for loads less than half that at Takanini. Also, typicallytwo transformers are used to supply a maximum of 120 to 150 MW of load 63 , afterwhich a third transformer is installed. It is expected that a third supply transformerand a 220 kV bus upgrade will be required within the forecast period to improve thelevel of security at Takanini.Further development options to increase the transformer capacity for this grid exitpoint will be customer driven.8.8.13 Wiri supply transformer capacityProject reference: Upgrade protection: WIR-POW_TFR-EHMT-01Upgrade transformer capacity: WIR-POW_TFR-EHMT-02Project status/type: Upgrade protection: possible, Base CapexUpgrade transformer capacity: possible, customer-specificIndicative timing: Upgrade protection: 2019Upgrade transformer capacity: 2021Indicative cost band: Upgrade protection: AUpgrade transformer capacity: BIssueTwo 110/33 kV transformers supply Wiri’s load, providing:a total nominal installed capacity of 200 MVA, andn-1 capacity limit of 106/106 MVA 64 (summer/winter).The peak load at Wiri will exceed the transformers’ summer n-1 capacity byapproximately 1 MW in 2020, increasing to approximately 18 MW in 2028 (see Table8-12).Table 8-12: Wiri supply transformer overload forecastGrid exitpointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Wiri 0.99 0 0 0 0 0 0 1 6 10 14 186364The Takanini load is forecast to reach 130 MW in 2014 and 150 MW in 2021.The transformers’ capacity is limited by protection equipment limit; with this limit resolved, the n-1capacity will be 109/115 MVA (summer/winter).1242013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 8: Auckland RegionSolutionResolving the protection equipment limits will delay the overload until 2021. We willdiscuss future supply options with Vector, including:limiting peak load to the firm transformer capacity (i.e. 106/106 MVA), with futureload growth transferred to other grid exit points, and/orreplacing the existing transformers with two 120 MVA units, orinstalling a third supply transformer.The solution to the Otahuhu–Wiri transmission capacity issue may also address theWiri supply transformer capacity issue (see Section 8.8.8).The Wiri single phase supply transformers have an expected end-of-life within thenext five years. In addition, we also plan to convert the Wiri 33 kV outdoor switchyardto an indoor switchboard within the same timeframe.We will discuss with Vector the rating, timing and number of transformerreplacements in conjunction with the transformer upgrade and 33 kV outdoor toindoor switchyard conversion work.Any future transformer upgrade will be customer driven.8.8.14 Wiri Tee transmission capacityProject status/type:This issue is for information onlyIssueWiri is connected to the Bombay–Wiri–Otahuhu circuits through the Wiri Tee circuitsections, each rated at 92/101 MVA (summer/winter).The peak load at Wiri already exceeds the circuits’ n-1 summer capacity.SolutionThis issue arises along with the Otahuhu–Wiri circuit issue (see Section 8.8.8) and isexpected to be resolved with that issue’s solution. Although the Wiri Tee section isonly approximately 90 metres in length, it crosses over a motorway, which isexpected to complicate an otherwise relatively minor project to increase this circuitsection’s capacity.8.9 Auckland bus securityThe 2013 APR has been expanded to include issues arising from the outage of asingle bus section rated at 50 kV and above for the next 15 years.Bus outages disconnect more than one power system component (for example, othercircuits, transformers, reactive support or generators). Therefore, bus outages maycause greater issues than a single circuit or transformer outage (although the risk of abus fault is low, being less common than a circuit or transformer outage).8.9.1 Transmission bus securityTable 8-13 lists bus outages that cause voltage issues or a total loss of supply.Generators are included only if a bus outage disconnects the whole generationstation or causes a widespread system impact. Supply bus outages, typically 11 kVand 33 kV, are not listed.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 125

Chapter 8: Auckland RegionTable 8-13: Transmission bus outagesTransmissionbus outageLoss ofsupplyGenerationdisconnectionTransmissionissueFurtherinformationBombay 110 kV Bombay 33 kV See note 1Mount Roskill 110 kVSouthdown 220 kVOtahuhu 110 kVMeremere See note 2Mount Roskill110 kVMount Roskill22 kVSouthdownBombay–Wiri TeeoverloadingOtahuhu–Mangere–MountRoskill overloading1. Bombay has two 110 kV bus sections. However, both Bombay supply transformers are connected tothe same 110 kV bus section.2. Meremere is supplied from the Bombay 33 kV, so issues affecting Bombay also affects Meremere (seeSection 9.9.3).The customers (Counties Power, Vector, or Mighty River Power) have not requesteda higher security level. If increased bus security is required, the options typicallyinclude bus reconfiguration and/or additional bus circuit breakers. Future investmentwill be customer driven.8.9.2 Bombay–Wiri Tee transmission capacity8.9.28.9.3Project status/type:This issue is for information onlyIssueThe Bombay–Wiri Tee section of the Bombay–Otahuhu circuits are rated at62/76 MVA (summer/winter). The Bombay–Wiri Tee–2 will overload from 2013 for a110 kV bus section outage at Otahuhu that disconnects:Otahuhu–T4, andOtahuhu–Wiri Tee–1 and 2.SolutionThe overload occurs due to unequal load sharing of the Wiri supply transformersbecause the transformers have different characteristics and the Wiri 110 kV bus issplit. Most of the options to address the Otahuhu–Wiri 110 kV transmission capacity(see Section 8.8.8) or the Wiri supply transformer capacity (see Section 8.8.13) willalso address this issue.Another option is to close the Wiri 110 kV bus split, which addresses the issue untilnearly the end of the forecast period, when additional reactive support at Bombay isrequired to remove the overload until after the forecast period.8.9.3 Otahuhu–Mangere–Mount Roskill overloadingProject reference: OTA-BUSG-EHMT-01Project status/type: Possible, Base CapexIndicative timing: 2021Indicative cost band: A1262013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 8: Auckland RegionIssueThe Mangere–Mount Roskill circuits are rated at 95/105 MVA (summer/winter).These circuits will overload from 2023 with the outage of a 110 kV bus section atOtahuhu that disconnects:Otahuhu–T3, andOtahuhu–Mount Roskill–1 and 2.The Otahuhu–Mount Roskill 110 kV circuits are rated at 95/102 MVA 65(summer/winter). These circuits will overload from 2021 for an outage of a 110 kVbus section at Otahuhu that disconnects:Otahuhu–T5Mangere–Otahuhu–1 and 2, andOtahuhu Capacitors C11 and C12.SolutionOne option is to reconfigure the Otahuhu 110 kV bus to swap the position of theMangere–Otahuhu–1 and Otahuhu–Mount Roskill–2 circuits on the bus. Thisresolves the issue until the end of the forecast period.8.10 Other regional items of interestThere are no other items of interest identified to date beyond those set out inSection 8.8 and Section 8.9. See Section 8.11 for information about generationscenarios, proposals and opportunities relevant to this region.8.11 Auckland generation scenarios, generation proposals and opportunitiesThis section details relevant regional issues for selected generation proposals underinvestigation by developers and in the public domain, or other generationopportunities. The impact of committed generation projects on the grid backbone isdealt with separately in Chapter 6.The maximum generation that can be connected depends on several factors andusually falls within a range. Generation developers should consult with us at an earlystage of their investigations to discuss connection issues.8.11.1 Impact of generation scenarios on regional planThe generation scenarios (detailed in Chapter 5) represent a series of possible futuregeneration outcomes. This section presents only those scenarios relevant to thisregion for the next 15 years.Generation scenario 1-3 includes approximately 500 to 770 MW of thermalgeneration and peak load reduction at Otahuhu by 2028.Scenarios 4 and 5 anticipate approximately 1200 MW of thermal generation and peakload reduction at Otahuhu by 2028.New generation or peak load reduction at Otahuhu will have a minimal impact ontransmission within the Auckland region. There may be some delay in replacingsupply transformers depending on the location of any load reduction. The main effectwill be a transmission load reduction on circuits forming the grid backbone intoAuckland.65The circuits’ capacity is limited by a cable limit. With this limit resolved; the circuits’ capacity will be95/105 MVA (summer/winter).2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 127

Chapter 8: Auckland RegionThere will also be increased loading on the existing Otahuhu–T2 and T4interconnecting transformers and 110 kV Otahuhu–Wiri circuits during periods of lowWaikato generation and high Auckland area generation. See Sections 8.8.3 and8.8.8 for more information about this issue.New generation at Otahuhu will also:complement existing and planned reactive voltage support in the Auckland andNorthland regions, anddelay the installation and/or extend the longevity of the reactive supportreinforcements.As Southdown is electrically close to Otahuhu, a reduction in generation atSouthdown will reduce the effect of new generation at Otahuhu and vice versa.New generation in Northland will reduce cross-Auckland transmission load. However,the intermittent nature of wind generation means that it will not delay any requiredtransmission reinforcement.8.11.2 Maximum regional generationThe Auckland region has some of the highest load densities in New Zealand, coupledwith relatively low levels of local generation, and so there is no practical limit to themaximum generation that can be connected within the region. However, there will belimits on the maximum generation that can be connected at a substation or along anexisting line due to the rating of the existing circuits.8.11.3 Auckland generation issuesThere are numerous inter-related issues with supplying the load within the Aucklandregion, as discussed earlier in this chapter. In addition, the increase in fault level dueto generators will be an issue for some parts of the transmission and/or distributionsystems.Therefore, depending on its connection point, new generation within the Aucklandregion may assist in addressing an issue, make it worse, have no effect, or mayrequire specific additional transmission investment to enable connection. Fault-levelissues may also preclude new generation connection in some locations.1282013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 9: Waikato Region9 Waikato Regional Plan9.1 Regional overview9.2 Waikato transmission system9.3 Waikato demand9.4 Waikato generation9.5 Waikato significant maintenance work9.6 Future Waikato projects summary and transmission configuration9.7 Changes since the 2012 Annual Planning Report9.8 Waikato transmission capability9.9 Waikato bus security9.10 Other regional items of interest9.11 Waikato generation scenarios, proposals and opportunities9.1 Regional overviewThis chapter details the Waikato regional transmission plan. We base this regionalplan on an assessment of available data, and welcome feedback to improve its valueto all stakeholders.Figure 9-1: Waikato regionConstruction voltages shown. System as at March 2013.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 129

Chapter 9: Waikato RegionThe Waikato region comprises two distinct transmission networks, 110 kV and220 kV, of which the 220 kV network forms part of the grid backbone. The 220 kVcircuits enter the region from Stratford, Tokaanu, and Wairakei. The 110 kV circuitsenter the region from Kinleith to Arapuni, and from Ongarue to Hangatiki. Thenorthern boundary is crossed by the:220 kV circuits from Huntly, Ohinewai, and Whakamaru, and110 kV circuits from Hamilton and Arapuni.We have assessed the Waikato region’s transmission needs over the next 15 yearswhile considering longer-term development opportunities. Specifically, thetransmission network needs to be flexible to respond to a range of future service andtechnology possibilities, taking into consideration:the existing transmission networkforecast demandforecast generationequipment replacement based on condition assessment, andpossible technological development.9.2 Waikato transmission systemThis section highlights the state of the Waikato regional transmission network. Theexisting transmission network is set out geographically in Figure 9-1 andschematically in Figure 9-2.Figure 9-2: Waikato transmission schematicAUCKLANDDrury OtahuhuAUCKLANDBombay OtahuhuKopu66 kV110 kV33 kVWaihou110 kVWaikino110 kV33 kV220 kV 33 kVOhinewaiPiako110 kVKEY220kV CIRCUIT110kV CIRCUITSUBSTATION BUSTRANSFORMERTEE POINTHuntlyTe KowhaiHamilton11 kV 220 kVCambridge11 kVKarapiro110 kV110 kVHinuera33 kVLOADCAPACITORGENERATOR220 kV 33 kV110 kV33 kV110 kVArapuniTe AwamutuHangatiki33 kV110 kV11 kV110 kVWaipapa220 kVKinleithMaraetai220 kVTarukengaAtiamuriBAY OF PLENTYKawerauOhakuri220 kV220 kVWairakeiAUCKLANDBrownhillOngarueCENTRAL NORTH ISLANDStratford TaumarunuiTARANAKI220 kVWhakamaruTokaanuCENTRAL NORTH ISLAND220 kVTe MihiCENTRAL NORTH ISLAND1302013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 9: Waikato Region9.2.1 Transmission into the regionThis region’s generation contributes a significant portion of total North Islandgeneration and exceeds local demand. Surplus generation is exported over the220 kV transmission system to the rest of the country. The 220 kV transmissionnetwork has enough capacity to provide n-1 security to the local load indefinitely.The recently commissioned 400 kV-capable transmission line 66 between Whakamaruand Pakuranga (Auckland) will reduce loading on the 220 kV and 110 kV circuitswithin the Waikato region.9.2.2 Transmission within the regionThe 110 kV transmission system within the region predominantly supplies andconnects the rest of the Waikato region, including most of the regional load and someregional generation.Transmission system issuesThe 110 kV transmission network predominantly comprises low capacity circuitswhich results in capacity and supply security issues for some outages. It also resultsin generation restrictions, particularly at Arapuni, even with all circuits in service.Maintenance security issuesThe 220/110 kV interconnection at Hamilton supplies most of the load in the Waikatoregion. The outage of a 220 kV circuit to Hamilton or a 220/110 kV interconnectingtransformer at Hamilton will place many grid exit points in the region on n security.We will consider options to increase the security of this interconnection to provide fullor partial n-1 security.9.2.3 Longer-term development pathWe will continue to resolve the short and long-term issues in the region, including the:Waikato 110 kV transmission network (the 110 kV circuits that operate in parallelwith the grid backbone between Tarukenga and Bombay)110 kV Thames Valley spur, andHamilton interconnecting transformer capacity and maintenance security.Additionally, in order to meet high load growth in the Tauranga area, one option is atransmission connection between Waihou and a new grid exit point north ofTauranga. This may involve converting parts of the Thames Valley spur to 220 kV.The following projects represent possible grid backbone developments through theWaikato region:installing series capacitors on the 220 kV Brownhill–Whakamaru circuits (likelywithin the forecast period)converting the 220 kV Brownhill–Whakamaru circuits to 400 kV operation byinstalling 400/220 kV interconnecting transformers at Brownhill and Whakamaru(likely beyond the forecast period).9.3 Waikato demandThe after diversity maximum demand (ADMD) for the Waikato region is forecast togrow on average by 1.7% annually over the next 15 years, from 506 MW in 2013 to653 MW by 2028. This is higher than the national average demand growth of 1.5%annually.66This is a 400 kV-capable line forming part of the North Island Grid Upgrade (NIGU) project. SeeChapter 6 for more information.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 131

Chapter 9: Waikato RegionFigure 9-3 shows a comparison of the 2012 and 2013 APR forecast 15-yearmaximum demand (after diversity 67 ) for the Waikato region. The forecasts arederived using historical data, and modified to account for customer information, whereappropriate. The power factor at each grid exit point is also derived from historicaldata. See Chapter 4 for more information about demand forecasting.Figure 9-3: Waikato region after diversity maximum demand forecastTable 9-1 lists forecasts peak demand (prudent growth) for each grid exit point for theforecast period, as required for the Grid Reliability Report.Table 9-1: Forecast annual peak demand (MW) at Waikato grid exit points to 2028Grid exit pointPowerfactorNext 5 yearsPeak demand (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Cambridge 0.98 43 43 44 45 45 46 47 49 50 52 53Hamilton 11 kV 1.00 45 46 24 0 0 0 0 0 0 0 0Hamilton 33 kV 1 0.99 157 160 187 215 219 224 233 242 252 261 270Hamilton NZR 0.80 8 8 8 8 8 8 8 8 8 8 8Hangatiki 0.92 31 31 32 33 33 34 35 37 38 39 41Hinuera 2 0.94 50 44 45 46 47 48 50 53 55 57 60Huntly 4 0.99 25 26 26 43 43 44 46 47 49 50 52Kopu -0.99 50 52 53 54 55 57 60 63 66 68 71Piako 3 0.99 24 25 25 26 27 27 29 30 32 33 34Putaruru 2 0.94 0 8 8 8 8 9 9 9 10 10 11Te Awamutu 0.98 40 40 41 41 42 43 44 45 47 48 49Te Kowhai 1 0.97 103 105 110 112 114 116 121 125 130 134 139Waihou 3 0.97 36 37 38 39 40 41 43 45 47 49 5267The after diversity maximum demand (ADMD) for the region will be less than the sum of theindividual grid exit point peak demands, as it takes into account the fact that the peak demand doesnot occur simultaneously at all the grid exit points in the region.1322013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 9: Waikato RegionGrid exit pointPowerfactorNext 5 yearsPeak demand (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Waikino 0.99 45 46 47 49 50 51 54 56 59 61 64Whakamaru 1.00 11 11 11 11 12 12 12 13 13 14 141. The forecast is distorted by frequent and regular load shifting between Hamilton and Te Kowhai.2. Some load will be shifted from Hinuera to a proposed new grid exit point at Putaruru in 2014/15.3. Piako is a new grid exit point being established in 2013 with load switched from Waihou.4. Load switched from Meremere in 2016.9.4 Waikato generationThe Waikato region’s generation capacity is 2,419 MW.Table 9-2 lists the generation forecast for each grid injection point for the forecastperiod, as required for the Grid Reliability Report. This includes all known andcommitted generation stations including those embedded within the relevant locallines company’s network (Waipa Networks, WEL Networks, The Lines Company orPowerco). 68Table 9-2: Forecast annual generation capacity (MW) at Waikato grid injection points to2028 (including existing and committed generation)Grid injection point(location ifembedded)Next 5 yearsGeneration capacity (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Arapuni 197 197 197 197 197 197 197 197 197 197 197Atiamuri 84 84 84 84 84 84 84 84 84 84 84Hangatiki(Mangapehi)2 2 2 2 2 2 2 2 2 2 2Huntly 1198 1198 1198 1198 1198 1198 1198 1198 1198 1198 1198Karapiro 90 90 90 90 90 90 90 90 90 90 90Maraetai 360 360 360 360 360 360 360 360 360 360 360Mokai 112 112 112 112 112 112 112 112 112 112 112Ohakuri 112 112 112 112 112 112 112 112 112 112 112Te Awamutu (AnchorProducts)4 4 4 4 4 4 4 4 4 4 4Te Kowhai (Te Rapa) 44 44 44 44 44 44 44 44 44 44 44Te Kowhai (Te Uku) 64 64 64 64 64 64 64 64 64 64 64Waikino (TirohiaLandfill)1 1 1 1 1 1 1 1 1 1 1Waipapa 51 51 51 51 51 51 51 51 51 51 51Whakamaru 100 100 100 100 100 100 100 100 100 100 1009.5 Waikato significant maintenance workOur capital project and maintenance works are integrated to enable system issues tobe resolved if possible when assets are replaced or refurbished. Table 9-3 lists thesignificant maintenance-related work 69 proposed for the Waikato region for the next15 years that may significantly impact related system issues or connected parties.6869Only generators with a capacity greater than 1 MW are listed. Generation capacity is rounded to thenearest megawatt.This may include replacement of the asset due to its condition assessment.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 133

Chapter 9: Waikato RegionTable 9-3: Proposed significant maintenance workDescriptionTentativeyearRelated system issuesArapuni–Ongarue–A linereconductoring (Arapuni–Rangitoto section)Cambridge 11 kV switchgearreplacementHamilton–T5 supply transformerexpected end-of-lifeHangatiki–T1 and T2 supplytransformers’ expected end-of-lifeHinuera–T1 and T2 supplytransformers’ expected end-of-lifeWaihou supply transformers’expected end-of-lifeWaihou 33 kV outdoor to indoorconversion, and 110 kVsubstation rebuild2016-2017 An increase in rating will be investigated to addresspotential issues beyond the forecast period.2013 Upgrading the 11 kV switchgear will improve theCambridge supply transformer n-1 capacity issue.See Section 9.8.6 for more information.2022-2024 A significant increase in supply transformer capacityis required within the forecast period. Increasing thecapacity of T5 will reduce the transformer overload.See Section 9.8.7 for more information.2016-2018 Upgrading the transformers’ capacity is one of thepossible options to resolve the transformer overloadissue. See Section 9.8.8 for more information.2027-2028 Upgrading the capacity of T1 is one of the possibleoptions (following construction of Putaruru) toresolve the transformer loading issue. T2 is forecastto exceed its n-1 capacity towards the end of theforecast period. See Section 9.8.9 for moreinformation.2015-2017 Upgrading the transformers’ capacity is one of thepossible options (following construction of Piako) toresolve the transformer overloading issue. SeeSection 9.8.17 for more information.The replacement transformer with on-load tapchanging capability will improve the voltage profileat Waihou. See Section 9.8.5 for more information.2013-2015 No system issues are identified within the forecastperiod.Waikino supply transformers’expected end-of-life, and33 kV outdoor to indoorconversion2020-20222016-2018Upgrading the transformers’ capacity is one of thepossible options to resolve the transformeroverloading issue. See Section 9.8.18 for moreinformation.The replacement transformer with on-load tapchanging capability will improve the voltage profileat Waikino. See Section 9.8.5 for more information.9.6 Future Waikato projects summary and transmission configurationTable 9-4 lists projects to be carried out in the Waikato region within the next 15years.Figure 9-4 shows the possible configuration of Waikato transmission in 2028, withnew assets, upgraded assets, and assets undergoing significant maintenance withinthe forecast period.Table 9-4: Projects in the Waikato region up to 2028Circuit/site Projects StatusArapuni Close the 110 kV bus. CommittedArapuni–Kinleith Increase the line capacity by reconductoring/thermal upgrading. PossibleCambridge Replace 11 kV switchgear. CommittedHamiltonHamilton–WaihouInstall a new 220/110 kV interconnecting transformer.Install a new 220/33 kV supply transformer.Add a third 220 kV bus section.Replace the 220/33 kV T5 supply transformer.Increase the line capacity by building a new 110 kV Hamilton–Waihou circuit or upgrade the 110 kV Hamilton–Piako circuits.PossiblePossiblePossibleProposedPossible1342013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 9: Waikato RegionCircuit/site Projects StatusHangatiki Replace the 110/33 kV supply transformers with higher rated units. PossibleHinuera Replace the 110/33 kV supply transformers. ProposedKopuResolve supply transformer protection limits.Replace transformers with higher rated units.PossiblePossiblePutaruru New grid exit point. PossibleTe AwamutuTe KowhaiWaihouWaikinoNew transmission circuit from Hangatiki.Resolve supply transformer protection limits.Install radiators and fans on the existing supply transformers.Install a new 220/33 kV supply transformer.Rebuild 110 kV structure.Replace the 110/33 kV supply transformers.Convert 33 kV outdoor switchgear to an indoor switchboard.Install new capacitors.Install new capacitors.Replace the 110/33 kV supply transformers.Convert 33 kV outdoor switchgear to an indoor switchboard.PossiblePossibleCommittedPossibleProposedProposedProposedPossiblePossibleProposedProposedFigure 9-4: Possible Waikato transmission configuration in 2028DruryOtahuhuAUCKLANDBombay OtahuhuKopu66 kV110 kVHuntly33 kVOhinewai220 kVPiako110 kV33 kVWaihou110 kV110 kV33 kVWaikino220 kVHamiltonTe Kowhai220 kVKarapiro110 kV11 kVCambridge110 kVHinuera33 kV220 kV 33 kVTe Awamutu110 kV110 kV33 kVArapuni110 kVPutaruru110 kVHangatiki33 kV110 kV**11 kVWaipapa220 kVMaraetai220 kVAtiamuri220 kVKinleithTarukengaBAY OF PLENTYKawerauOhakuriAUCKLANDBrownhill220 kV Wairakei(1)Ongarue Stratford TaumarunuiTARANAKI(1) the transmission backbone section identifies twodevelopment paths for the lower North Island:- upgrade existing lines, and/or- new transmission lineAlthough this diagram shows upgrading of existinglines, it is not intended to indicate a preference asboth options are still being investigated.Tokaanu220 kVWhakamaruCENTRAL NORTH ISLANDWairakeiTe Mihi/WairakeiKEYNEW ASSETSUPGRADED ASSETSASSETS SCHEDULEDFOR REPLACEMENTMINOR UPGRADE*9.7 Changes since the 2012 Annual Planning ReportTable 9-5 lists the specific issues that are either new or no longer relevant within theforecast period when compared to last year's report.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 135

Chapter 9: Waikato RegionTable 9-5: Changes since 2012IssuesPiako transmission securityChangeNew issue.9.8 Waikato transmission capabilityTable 9-6 summarises issues involving the Waikato region for the next 15 years. Formore information about a particular issue, refer to the listed section number.Table 9-6: Waikato regional transmission issuesSectionnumberIssueRegional9.8.1 Arapuni–Hamilton 110 kV transmission capacity9.8.2 Arapuni–Kinleith 110 kV transmission capacity9.8.3 Hamilton interconnecting transformer capacity9.8.4 Hamilton–Piako–Waihou 110 kV transmission capacity9.8.5 Piako–Waihou–Waikino–Kopu spur low voltageSite by grid exit point9.8.6 Cambridge supply transformer capacity9.8.7 Hamilton 220/33 kV and 110/11 kV supply transformer capacity9.8.8 Hangatiki supply transformer capacity9.8.9 Hinuera supply transformer capacity9.8.10 Hinuera transmission security9.8.11 Kopu supply transformer capacity9.8.12 Maraetai–Whakamaru transmission capacity9.8.13 Piako transmission security9.8.14 Te Awamutu supply transformer capacity9.8.15 Te Awamutu transmission security9.8.16 Te Kowhai substation developments9.8.17 Waihou supply transformer capacity9.8.18 Waikino supply transformer capacityBus security9.9.1 Transmission bus security9.9.3 Bombay–Hamilton 110 kV transmission capacity9.9.2 Hangatiki supply security9.9.4 Piako–Waihou–Waikino–Kopu spur bus security9.8.1 Arapuni–Hamilton 110 kV transmission capacityProject status/type:This issue is for information onlyIssueThe two 110 kV Arapuni–Hamilton circuits are each rated at 51/62 MVA(summer/winter).The Arapuni 110 kV bus is currently permanently split with two bus sections:1362013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 9: Waikato RegionArapuni G1-4 generators, Arapuni–Bombay–1, Arapuni–Hamilton–1 and 2,Arapuni–Hangatiki–1, and the Arapuni–Ongarue–1 circuits on one bus (northbus)Arapuni–Kinleith–1 and 2 circuits on the other bus (south bus), andArapuni G5-8 are selectable between the two bus sections.Cost benefit analysis showed that permanently splitting the bus is economic until theTarukenga interconnecting transformers are replaced (see Section 9.10.1).With the Arapuni bus split open:Arapuni north bus generation may be constrained pre-contingency to manage theloading on a Arapuni–Hamilton circuit for an outage of the other Arapuni–Hamilton circuit, andthe Arapuni runback is enabled on Arapuni G1-4 to reduce generation if anArapuni–Hamilton circuit overloads.With the Arapuni bus split closed, and following the commissioning of the Tarukengainterconnecting transformers:Arapuni generation may be constrained pre-contingency to manage the loadingon an Arapuni–Hamilton circuit for an outage of the other Arapuni–Hamilton orHamilton–Whakamaru circuitthe Arapuni runback is enabled on Arapuni G1-4 to reduce generation if anArapuni–Hamilton circuit overloads.The worst case conditions occur during:summer, when Huntly generation is sometimes restricted due to high rivertemperatures, andhigh hydro inflow periods, when renewable generation south of Whakamaru isdispatched ahead of thermal generation in the upper North Island.SolutionThe commissioning of the new Pakuranga–Whakamaru line, and other projects beingimplemented or considered as solutions to other issues, will relieve the loading on the110 kV Arapuni–Hamilton circuits. The other projects include the Wairakei–Whakamaru–C line (see Chapter 6), the Tarukenga interconnecting transformerreplacement (see Chapter 10, Section 10.5) and the new Putaruru grid exit point (seeSection 9.8.10).The existing Arapuni bus split configuration is not a long-term solution, as it restrictsmaintenance access to the 110 kV circuits. An investigation into longer-term optionsto resolve this issue is ongoing. However, a preliminary assessment of theInvestment Test indicates that reconductoring the 110 kV circuits to remove theoverload may not be economic. A condition assessment shows that the existingconductor will not require replacement within the forecast period.9.8.2 Arapuni–Kinleith 110 kV transmission capacityProject reference: ARI_KIN-TRAN-EHMT-01Project status/type: Possible, Base CapexIndicative timing: 2022-2028Indicative cost band: AIssueThere are two 110 kV Arapuni–Kinleith circuits (1 and 2), rated at 57/70 MVA and63/77 MVA (summer/winter), respectively. There is a possibility of a new grid exit2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 137

Chapter 9: Waikato Regionpoint (Putaruru) being single tee-connected part way along Arapuni–Kinleith circuit 2in 2014 70 (see Section 9.8.10 for more information).Loading on the 110 kV Arapuni–Kinleith circuits may exceed their n-1 capacity undercertain operating conditions.With the Arapuni bus split open 71 , factors contributing to this overload include:the summer ratings period, andfull generation from three Arapuni generation units connected to the south bus.With the Arapuni bus split closed, factors contributing to this overload include:high net load at Kinleith (for example when Kinleith generation is off during highpulp and paper plant production periods)high generation at Arapunihigh Huntly and Auckland-area generation, andhigh south power flow (for example, HVDC south power flow).Additionally, the 110 kV circuits between Kinleith and Lichfield are often opened toprevent overloading during some outages in the Bay of Plenty region. The Kinleithload is then supplied by the two 110 kV Arapuni–Kinleith circuits and generation atKinleith. For some system conditions 72 the load at Kinleith may be on n securitywhen the system is split.Peak load at Kinleith is approximately 95 MW (offset by up to 40 MW of on-sitegeneration) and is forecast to remain steady. The net Kinleith load rarely exceeds75 MW. The typical daily peaks are between 55 MW and 65 MW.SolutionIn the short-term, loading on the Arapuni–Kinleith circuits is managed by:opening the Arapuni bus split, andrestricting Arapuni south bus generation during summer ratings.Following the commissioning of the Pakuranga–Whakamaru double-circuit line andthe new Putaruru grid exit point, the Arapuni bus split will be opened less frequently.In the medium-term, possible options to relieve the loading on Arapuni–Kinleith duringsouth power flow include:special protection schemes, orreconfiguration of the Kinleith 110 kV bus.In the longer-term, possible options to increase the capacity of the Arapuni–Kinleithcircuits include:reconductoring Arapuni–Kinleith–1, andthermally upgrading the Arapuni–Putaruru line section.Acquisition of property easements may be required for reconductoring work in somecases.9.8.3 Hamilton interconnecting transformer capacityProject reference: HAM-POW_TFR-DEV-01Project status/type: Possible, Base CapexIndicative timing: 2025Indicative cost band: New interconnecting transformer: B707172Putaruru load is expected to be approximately 7 MW from 2014.See also Section 9.10.1 for a discussion on the Arapuni bus split.During high Kinleith load and when the Kinleith generator is unavailable.1382013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 9: Waikato RegionIssueTwo three-phase interconnecting transformers at Hamilton supply much of theWaikato 110 kV transmission network load, as well as a small proportion of theAuckland and Bay of Plenty 110 kV loads under certain system conditions. Thesetransformers provide:a total nominal installed capacity of 420 MVA, andn-1 capacity of 243/243 MVA 73 (summer/winter).During low 110 kV generation in Waikato (Arapuni and Karapiro generation) and highWaikato demand, the load on the Hamilton interconnecting transformers may exceedtheir n-1 capacity. This overloading issue worsens:with low Upper North Island generation, andafter completion of the Tarukenga interconnecting transformer replacementproject (see Chapter 10, Section 10.10.2).SolutionThe North Island Grid Upgrade Project reduces the loading on the Hamiltoninterconnecting transformers. In the short term, we anticipate this issue will bemanaged operationally with generation rescheduling and load management.However, with low upper North Island generation and/or higher load growth, theremay not be enough Waikato 110 kV generation to manage this issue towards the endof the forecast period.We are also discussing options for the long-term supply of Hamilton City with WELNetworks (see Section 9.8.7). If the existing 110/11 kV load at Hamilton is moved tothe 33 kV bus, the loading on the Hamilton transformers will decrease.Options to address the issue (when required) include a new 220/110 kV transformer:in parallel with the existing transformers, orat a new substation, connected to the intersection of the 220 kV Otahuhu–Whakamaru C line and the 110 kV Hamilton–Waihou A line.The second option improves security during maintenance outages of the 220 kVcircuits supplying Hamilton, and forms the connection point for a third circuit toWaihou (instead of a Hamilton connection, see Section 9.8.4 for more information).9.8.4 Hamilton–Piako–Waihou 110 kV transmission capacityProject reference: HAM_WHU-TRAN-DEV-01Project status/type: Possible, customer-specificIndicative timing: 2017Indicative cost band: Third Hamilton–Waihou circuit: DReconductoring Hamilton–Piako circuit: CIssueTwo 110 kV Hamilton–Piako–Waihou circuits supply the ‘Valley Spur’ (Piako, Waihou,Waikino, and Kopu), each circuit having a summer/winter capacity of 154/168 MVA.Valley Spur summer and winter peak loads are increasingly similar, with 2012 peaksof approximately 126 MW and 137 MW, respectively.The peak load on the Valley Spur is forecast to exceed the circuits’ n-1 summercapacity by approximately 2 MW in 2017, increasing to approximately 42 MW in 2028(see Table 9-7).73The transformers’ capacity is limited by protection equipment; with this limit resolved, then-1 capacity will be 248/259 MVA (summer/winter).2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 139

Chapter 9: Waikato RegionLow voltage along the Valley Spur exacerbates the transmission loading issue (seeSection 9.8.5 for more information).Table 9-7: Valley Spur circuit overload forecastCircuit/grid exitpointNext 5 yearsCircuit overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Valley Spur 0 0 0 0 2 5 13 20 27 35 42SolutionFollowing the commissioning of the new grid exit point at Piako, approximately 40%of the Waihou load was shifted to Piako, and consequently the circuit overloadingissue will only occur between Hamilton and Piako within the forecast period.We will investigate the installation of capacitors to relieve the Valley Spur low voltageissues (see Section 9.8.5 for more information). This provides an interim solution tothe Hamilton–Waihou circuits’ capacity issue, delaying the need for furthertransmission reinforcement by approximately one year.In the short-term, the overload can be managed operationally.Possible longer-term options include:constructing a third 110 kV Hamilton–Waihou circuit of a similar capacity to theexisting circuits, orupgrading the existing 110 kV Hamilton–Piako circuits to increase their summercapacity.The timing and choice of the capacity reinforcement option will be influenced by loadgrowth and developments within Powerco’s network, such as load transfer from theValley Spur to the Hinuera grid exit point (see Section 9.8.9). Future investment willbe customer driven.Depending on the solution, we may need to purchase easements for either a new lineor for some parts of an upgraded line.9.8.5 Piako–Waihou–Waikino–Kopu spur low voltageProject reference: VLYS-REA_PWRS-DEV-01Project status/type: New capacitors: possible, customer-specificReplace Waihou and Waikino supply transformers: proposed, Base CapexIndicative timing: New capacitors: 2014-2017Supply transformer replacement: 2015-2022Indicative cost band: New capacitors: AWaihou supply transformer replacement: BWaikino supply transformer replacement: BIssueSupply bus voltages at the Waihou and Waikino grid exit points are forecast to fallbelow 0.95 pu following an outage of one 110 kV Hamilton–Waihou circuit. Inaddition, the step voltage change for such an outage will exceed 5%. Both grid exitpoints have supply transformers with off-load tap changers.SolutionWe are investigating options to maintain voltage at the Waihou and Waikino buses.Possible options include:installing two 20 Mvar capacitors (along the Valley Spur), which will also deferValley Spur investment (see Section 9.8.4 for more information), or1402013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 9: Waikato Regionreplacing the existing transformers at Waikino and Waihou, which are due forreplacement in the next 10 years, with on-load tap changing transformers, andinstalling a lesser number of capacitors.Property issues may arise if there is a need to expand the substation toaccommodate the new capacitors. Future investment will be customer driven.9.8.6 Cambridge supply transformer capacityProject reference: CBG-SUBEST-EHMT-01Project status/type: Committed, Base CapexIndicative timing: Q2 2013Indicative cost band: AIssueTwo 110/11 kV transformers supply Cambridge’s load, providing:a total nominal installed capacity of 80 MVA, andn-1 capacity of 38/38 74 MVA (summer/winter).The peak load at Cambridge is forecast to exceed the transformers’ n-1 wintercapacity by approximately 6 MW in 2013, increasing to approximately 17 MW in 2028(see Table 9-8).In addition, the two Hamilton–Cambridge–Karapiro circuits supplying Cambridge donot have line circuit breakers at Cambridge and a fault on either circuit will disconnectone supply transformer.Table 9-8: Cambridge supply transformer overload forecastCircuit/gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Cambridge 0.98 6 7 8 8 9 10 11 13 14 15 17SolutionThe Cambridge 11 kV switchgear is currently being replaced. This resolves the busand protection limits, providing sufficient capacity until 2017 when the transformers’n-1 winter capacity will be exceeded by approximately 1 MW. This overload willincrease to approximately 8 MW in 2028. We will discuss the options to increase thesupply transformers’ n-1 capacity with Waipa Networks closer to this time. Futureinvestment will be customer driven.9.8.7 Hamilton 220/33 kV and 110/11 kV supply transformer capacityProject reference: HAM-POW_TFR-DEV-01Project status/type: Possible, customer-specificIndicative timing: New supply transformer at Hamilton: 2015Indicative cost band: Cost for one new supply transformer: AIssueHamilton has both an 11 kV and a 33 kV supply bus. In 2015, the 11 kV supply willbe decommissioned and the load transferred to the 33 kV.Two 110/11 kV transformers supply Hamilton’s 11 kV load, providing:74The transformers’ capacity is limited by the 11 kV bus and protection limits; with these limitsresolved, the n-1 capacity will be 45/47 MVA (summer/winter).2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 141

Chapter 9: Waikato Regiona total nominal installed capacity of 80 MVA, andn-1 capacity of 40/40 75 MVA (summer/winter).The peak load at Hamilton 11 kV is forecast to exceed the transformers’ n-1 wintercapacity by approximately 7 MW in 2013, increasing to approximately 8 MW in 2014(see Table 9-9).Two 220/33 kV transformers supply Hamilton’s 33 kV load, providing:a total nominal installed capacity of 220 MVA, andn-1 capacity of 124/132 MVA (summer/winter).The peak load at Hamilton 33 kV is forecast to exceed the transformers’ n-1 wintercapacity by approximately 31 MW in 2013. When the 11 kV supply bus isdecommissioned and the load is transferred to the 33 kV bus, the 220/33 kVtransformer is forecast to exceed its n-1 winter capacity by approximately 61 MW in2015, increasing to approximately 144 MW in 2028 (see Table 9-9).Table 9-9: Hamilton supply transformer overload forecastCircuit/gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Hamilton 11 kV 1.00 7 8 0 0 0 0 0 0 0 0 0Hamilton 33 kV 0.99 31 34 61 89 93 98 107 116 126 135 144WEL Networks is capable of significant load shifting between Hamilton and TeKowhai, so the combined load is compared with the total supply transformer capacityat both grid exit points.Four 220/33 kV transformers at Hamilton and Te Kowhai supply the total Hamiltoncity 33 kV load, providing:a total nominal installed capacity of 420 MVA, andn-1 capacity of 342/350 MVA (summer/winter).The total load is forecast to be 223 MW in 2013, increasing to 360 MW by 2028. Thetotal supply transformer capacity will not be exceeded until approximately 2025.SolutionAn interim solution to resolve the 220/33 kV supply transformer capacity issue is totransfer load to the Te Kowhai grid exit point (see Section 9.8.16). Table 9-9 showsthat significant load transfers will be required. A long-term solution involves theinstallation of a third 220/33 kV supply transformer at Hamilton.In addition, the Hamilton–T5 transformer has an expected end-of-life within the next10-15 years. We will discuss with WEL Networks the appropriate rating and timingfor the replacement transformer. Future investment will be customer driven.9.8.8 Hangatiki supply transformer capacityProject reference: HTI-POW_TFR-DEV-01Project status/type: Upgrade transformers’ capacity: possible, customer-specificIndicative timing: 2017Indicative cost band: B75The transformers’ capacity is limited by the 11 kV transformer branch component; with this limitresolved, the n-1 capacity will be 48/51 MVA (summer/winter).1422013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 9: Waikato RegionIssueTwo 110/33 kV transformers supply Hangatiki’s load, providing:a total nominal installed capacity of 40 MVA, andn-1 capacity of 22/24 MVA (summer/winter).Hangatiki winter and summer load peaks are similar. The peak load at Hangatiki isforecast to exceed the transformers’ n-1 summer capacity by approximately 11 MW in2013, increasing to approximately 21 MW in 2028 (see Table 9-10).Table 9-10: Hangatiki supply transformer overload forecastCircuit/gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Hangatiki 0.92 11 12 12 13 14 14 16 17 19 20 21SolutionThere is a possibility of new embedded generation in this area that may reduce peaktransformer loading. The Hangatiki transformers are single-phase units, with a noncontractedspare available on site.We are discussing longer-term options with The Lines Company, such as replacingthe existing transformers with two 40 MVA supply transformers. In addition, all theHangatiki supply transformers are approaching their expected end-of-life within thenext five years.Future investment will be customer driven.9.8.9 Hinuera supply transformer capacityProject reference: New grid exit point: PAU-SUBEST-DEV-01Transformer replacement: HIN-POW_TFR-REPL-01Project status/type: New grid exit point: possible, customer-specificTransformer replacement: possible, customer-specificIndicative timing: New grid exit point: 2014-2015Transformer replacement: to be advisedIndicative cost band: New grid exit point: CTransformer replacement: AIssueTwo 110/33 kV transformers (rated at 30 MVA and 50 MVA) supply Hinuera’s load,providing:a total nominal installed capacity of 80 MVA, andn-1 capacity of 37/40 MVA (summer/winter).The peak load at Hinuera is forecast to exceed the transformers’ n-1 winter capacityby approximately 15 MW in 2013. The overload will decrease in 2014 if Putaruru iscompleted. The transformers’ n-1 winter capacity will be exceeded by approximately8 MW in 2014, increasing to approximately 24 MW in 2028 (see Table 9-11).2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 143

Chapter 9: Waikato RegionTable 9-11: Hinuera supply transformer overload forecastCircuit/gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Hinuera 0.94 15 8 9 11 12 13 15 17 20 22 24Hinuera –no Putaruru0.94 15 16 17 19 20 21 24 27 29 32 35SolutionIn the short-term, load may be transferred within the Powerco network from Hinuerato Waihou to resolve this issue.Powerco is planning to increase transmission security in the Hinuera area with a newgrid exit point near Putaruru, which will be connected to the existing 110 kV Arapuni–Kinleith–2 circuit (see Section 9.8.10). This new grid exit point will reduce Hinueraload by approximately 15%, which will reduce but not resolve the Hinuera supplytransformer overload issue.We will discuss with Powerco the options to relieve this issue, one of which is toreplace the 30 MVA transformer with a 60 MVA unit. With the new Putaruru grid exitpoint, this will provide n-1 security of supply until 2028 76 .In addition, both Hinuera supply transformers have an expected end-of-life towardsthe end of the forecast period. Any future investment or transformer upgrade will becustomer driven.9.8.10 Hinuera transmission securityProject reference: PAU-SUBEST-DEV-01Project status/type: Possible, customer-specificIndicative timing: 2014/2015Indicative cost band: CIssueA single 110 kV circuit from Karapiro supplies Hinuera’s load, providing:a capacity of 63/77 MVA (summer/winter), andno n-1 security (given there is only one supplying circuit).Peak load in the Hinuera area is forecast to be 50 MW in 2013, increasing to 60 MWin 2028.SolutionPowerco is considering increasing transmission security to Hinuera’s load with a newgrid exit point near Putaruru (connected to the existing 110 kV Arapuni–Kinleith–2circuit). Land will need to be acquired for the new grid exit point.Some of Hinuera’s load will be transferred to Putaruru, with most of the remaindersecured by backfeeding within the local lines distribution system from Putaruru orWaihou. Future investment will be customer driven.9.8.11 Kopu supply transformer capacityProject reference:Resolve protection limit: KPU-POW_TFR-EHMT-01Upgrade transformer capacity: KPU-POW_TFR-DEV-0176The 50 MVA transformer’s capacity is limited by 33 kV metering; this limit will bind from 2017 if it isnot resolved.1442013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 9: Waikato RegionProject status/type: Resolve protection limit: possible, Base CapexUpgrade transformer capacity: possible, customer-specificIndicative timing: Resolve protection limit: 2013Upgrade transformer capacity: 2023Indicative cost band: Resolve protection limit: AUpgrade transformer capacity: BIssueTwo 110/66 kV transformers supply Kopu’s load, providing:a total nominal installed capacity of 120 MVA, andn-1 capacity of 45/45 MVA 77 (summer/winter).The peak load at Kopu is forecast to exceed the transformers’ n-1 capacity byapproximately 6 MW in 2013, increasing to approximately 27 MW in 2028 (see Table9-12).Table 9-12: Kopu supply transformer overload forecastCircuit/gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Kopu -0.99 6 7 9 10 11 13 15 18 21 24 27SolutionResolving the protection limit will increase the transformers’ n-1 capacity to64/67 MVA (summer/winter), providing sufficient capacity until 2023. Following theprotection upgrade, the peak load at Kopu is forecast to exceed the transformers’ n-1winter capacity by approximately 1 MW in 2023. This overload will increase toapproximately 8 MW in 2028.We will discuss options to increase the supply transformers’ n-1 capacity withPowerco closer to this time. Alternatives may include:replacing the existing transformers with higher capacity units, orconverting some 66 kV feeders to 110 kV operation.Future investment will be customer driven.9.8.12 Maraetai–Whakamaru transmission capacityProject status/type:This issue is for information onlyIssueThe 220 kV Maraetai–Whakamaru–1 and 2 circuits are each rated at 202/246 MVA(summer/winter). These circuits carry the combined 411 MW output from theWaipapa and Maraetai generation stations to Whakamaru.An outage of one of the Maraetai–Whakamaru circuits, restricts generation toapproximately 50% of full capacity in summer and 60% of full capacity in winter.SolutionIn case of a contingency, a generation runback scheme is in place to reducegeneration to the available capacity of the remaining circuit. This situation has beenconsidered satisfactory since the generation was first installed, and there are noplans to make transmission network changes at this stage.77The transformers’ capacity is limited by protection equipment; with this limit resolved, the n-1capacity will be 64/67 MVA (summer/winter).2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 145

Chapter 9: Waikato Region9.8.13 Piako transmission securityProject status/type:This issue is for information onlyIssuePiako is supplied from the two 110 kV Hamilton–Piako–Waihou circuits, but there isonly one supply transformer (owned by Powerco). The supply transformer can beselected to either circuit, but not to both circuits at the same time, resulting in no n-1security.SolutionIn the short term, the lack of n-1 security can be resolved operationally. In 2-3 years’time, Powerco will install a second supply transformer in a double tee configuration.This will provide n-1 security.9.8.14 Te Awamutu supply transformer capacityProject reference: TMU-POW_TFR-EHMT-01Project status/type: Possible, Base CapexIndicative timing: 2013Indicative cost band: AIssueTwo 110/11 kV transformers supply Te Awamutu’s load, providing:a total nominal installed capacity of 80 MVA, andn-1 capacity of 41/41 MVA 78 (summer/winter).The peak load at Te Awamutu is forecast to exceed the transformers’ n-1 capacity byapproximately 1 MW in 2013, increasing to approximately 11 MW in 2028 (see Table9-13).Table 9-13: Te Awamutu supply transformer overload forecastCircuit/gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Te Awamutu 0.98 1 2 2 3 3 4 5 7 8 9 11SolutionResolving the protection limit will increase the transformers’ n-1 capacity to52/54 MVA (summer/winter), providing sufficient capacity for the forecast period andbeyond.9.8.15 Te Awamutu transmission securityProject reference: HTI_TMU-TRAN-DEV-01Project status/type: Possible, customer-specificIndicative timing: 2015Indicative cost band: DIssueA single 110 kV circuit from Karapiro supplies Te Awamutu’s load, providing:78The transformers’ capacity is limited by protection equipment; with this limit resolved, the n-1capacity will be 52/54 MVA (summer/winter).1462013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 9: Waikato Regiona capacity of 63/77 MVA (summer/winter), andno n-1 security (given there is only one supplying circuit).Te Awamutu’s peak load is forecast to be 40 MW in 2013, increasing to 49 MW in2028.SolutionWaipa Networks may construct a new 110 kV circuit from Hangatiki to Te Awamutu(to be operated by Transpower) to provide n-1 security. Future investment will becustomer driven.9.8.16 Te Kowhai substation developmentsProject reference: Supply transformer upgrade: TWH-POW_TFR-EHMT-01New supply transformer: TWH-POW_TFR-DEV-01Project status/type: Supply transformer upgrade: committed, customer-specificNew supply transformer: possible, customer-specificIndicative timing: Supply transformer upgrade: Q2 2013New supply transformer 2018Indicative cost band: Supply transformer upgrade: ANew supply transformer: CIssueTwo 220/33 kV transformers supply Te Kowhai’s load, providing:a total nominal installed capacity of 200 MVA, andn-1 capacity of 109/109 MVA (summer/winter).There are also two embedded generators (Te Uku and Te Rapa) at Te Kowhai. Thenet load in 2012 ranged from an injection of approximately 76 MW to an off take ofapproximately 98 MW. WEL Networks is developing their distribution network totransfer load from Hamilton to Te Kowhai.SolutionThe distribution network is capable of substantial load shifting from Hamilton to TeKowhai, while the supply capacity at Hamilton is highly constrained (see Section9.8.7). Following discussions with WEL Networks, we are:increasing the rating of the two existing supply transformers by installing radiatorsand fans in 2013, increasing the n-1 capacity to 132 MVA, andproposing to install a third 120 MVA, 220/33 kV supply transformer at Te Kowhaiin about 2018.9.8.17 Waihou supply transformer capacityProject reference: WHU-POW_TFR-REPL-01Project status/type: Possible, Base CapexIndicative timing: 2015-2017Indicative cost band: BIssueThree 110/33 kV transformers supply Waihou’s load, providing:a total nominal installed capacity of 60 MVA, andn-1 capacity of 48/51 MVA (summer/winter).Waihou winter and summer peak loads are similar. The peak load at Waihou isforecast to exceed the transformers’ n-1 summer capacity by approximately 2 MW in2022, increasing to approximately 8 MW in 2028 (see Table 9-14).2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 147

Chapter 9: Waikato RegionTable 9-14: Waihou supply transformer overload forecastCircuit/gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Waihou 0.97 0 0 0 0 0 0 0 2 4 6 8SolutionFollowing a supply transformer contingency (for example, a unit failure), restoration offull capacity can be achieved by:shifting load to other grid exit points, andswapping a transformer unit with an on-site spare unit, taking up to 14 hours tocomplete.These transformers have an expected end-of-life within the next 10-15 years. We willdiscuss with Powerco the appropriate rating timing and number of replacementtransformers. In addition, we will convert the 33 kV outdoor switchyard to an indoorswitchboard within the next five years. Future investment will be customer driven.9.8.18 Waikino supply transformer capacityProject reference: WKO-POW_TFR-REPL-01Project status/type: Possible, Base CapexIndicative timing: 2020-2022Indicative cost band: BIssueTwo 110/33 kV transformers supply Waikino’s load, providing:a total nominal installed capacity of 60 MVA, andn-1 capacity of 37/39 MVA (summer/winter).The peak load at Waikino is forecast to exceed the transformers’ n-1 summercapacity by approximately 6 MW in 2013, increasing to approximately 25 MW in 2028(see Table 9-15).Table 9-15: Waikino supply transformer overload forecastCircuit/gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Waikino 0.99 6 7 8 9 10 12 14 17 19 22 25SolutionIn the short-term, operational measures can be used to manage this issue. We willdiscuss with Powerco the options to increase the supply transformers’ n-1 capacity.In addition, the existing supply transformers at Waikino will approach their expectedend-of-life within the next 5-10 years, and conversion of the existing 33 kV switchgearfrom outdoor to an indoor switchboard is planned for around the same time.9.9 Waikato bus securityThe 2013 APR has been expanded to include issues arising from the outage of asingle bus section rated at 50 kV and above for the next 15 years.Bus outages disconnect more than one power system component (for example, othercircuits, transformers, reactive support or generators). Therefore, bus outages may1482013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 9: Waikato Regioncause greater issues than a single circuit or transformer outage (although the risk of abus fault is low, being less common than a circuit or transformer outage).9.9.1 Transmission bus securityTable 9-16 lists bus outages that cause voltage issues or a total loss of supply.Generators are included only if a bus outage disconnects the whole generationstation or causes a widespread system impact. Supply bus outages, typically 11 kVand 33 kV, are not listed.Table 9-16: Transmission bus outagesTransmissionbus outageLoss ofsupplyGenerationdisconnectionTransmissionissueFurtherinformationArapuni North 110 kV Hangatiki 9.9.2Atiamuri 220 kVAtiamuriBombay 110 kVBombay–Hamiltonoverloading9.9.3Hamilton 220 kVHamilton 55 kVHamilton low voltage See note 1Hangatiki 110 kVHinuera 110 kVHangatikiHinueraKarapiro 110 kV Hinuera See note 2Te Awamutu See note 3KarapiroOhakuri 220 kVMaraetai 220 kVOhakuriMaraetaiWaipapa See note 4Te Awamutu 110 kVWhakamaru 220 kVTe AwamutuWhakamaruMokaiWaihou 110 kV Kopu 9.9.4Piako 9.9.4Waihou 9.9.4Waikino 9.9.4Waikino 110 kVKopuWaikino1. A bus section outage that disconnects the Hamilton–Ohinewai circuit will cause low voltages (seeSection 9.10.3)2. A bus outage at Karapiro disconnects the single circuit to Hinuera, causing a loss of supply. SeeSection 9.8.10 for improving transmission security to Hinuera.3. A bus outage at Karapiro disconnects the single circuit to Te Awamutu, causing a loss of supply. SeeSection 9.8.14 for an option to address the issue.4. There is a single circuit between Waipapa and Maraetai. A bus outage at Maraetai disconnects thecircuit and, therefore, also disconnects Waipapa power station.The customers (KiwiRail, The Lines Company, Powerco, Waipa Networks, WELNetworks, or Mighty River Power) have not requested a higher security level. Unlessotherwise noted, we do not propose to increase bus security and future investment islikely to be customer driven.If increased bus security is required, the options typically include bus reconfigurationand/or additional bus circuit breakers.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 149

Chapter 9: Waikato Region9.9.2 Hangatiki supply securityProject status/type:This issue is for information onlyIssueTwo 110 kV circuits supply Hangatiki’s load (Arapuni–Hangatiki and Arapuni–Hangatiki–Ongarue) and connect to the same north bus section at Arapuni.A fault on the north bus will cause a voltage collapse and subsequent loss of supplyat Hangatiki.SolutionThe issue will be resolved following replacement of the Tarukenga interconnectingtransformers (Bay of Plenty region) and reconfiguring the Arapuni bus so the twocircuits from Hangatiki connect to separate bus sections (see Section 9.10.1 for moreinformation).9.9.3 Bombay–Hamilton 110 kV transmission capacityProject status/type:This issue is for information onlyIssueThere are three 110 kV circuits connecting the Waikato and Auckland regions:Two Bombay–Hamilton circuits each rated at 51/62 MVA (summer/winter).One Arapuni–Bombay circuit rated at 51/62 MVA (summer/winter).A Bombay 110 kV bus section outage that disconnects the Bombay–Hamilton–2,Bombay–Otahuhu–2, and Arapuni–Bombay–1 circuits may overload the Bombay–Hamilton–1 circuit from about 2018 for:high Auckland loadlow Huntly and Auckland area generation, andhigh Waikato generation.SolutionWe anticipate this issue will be managed operationally with generation reschedulingand load management.9.9.4 Piako–Waihou–Waikino–Kopu spur bus securityProject status/type:This issue is for information onlyIssueThere are single bus sections at Waihou and Waikino. A bus fault at:Waihou will result in a loss of supply at Piako, Waihou, Waikino, and Kopu.Waikino will result in a loss of supply at Waikino and Kopu.An outage of the 110 kV bus section at Hamilton that disconnects the Hamilton–Piakocircuit normally supplying the Piako tee connected load (see Section 9.8.13) will alsoresult in higher loading on the other Hamilton–Piako circuit section than described bythe Hamilton–Piako–Waihou 110 kV transmission capacity issue (see Section 9.8.4for more information). This is because Piako is supplied indirectly from Hamilton viathe Waihou 110 kV bus rather than directly from the Hamilton 110 kV bus.1502013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 9: Waikato RegionSolutionA limited amount of load can be backfeed through the Powerco transmission networkfrom Tauranga, Piako and Hinuera.For the Hamilton 110 kV bus outage, in the short term the overloading of theHamilton–Piako circuit section can be managed by switching Piako to the normallyopen Piako tee circuit. In the medium term, Powerco plan to install a second supplytransformer at Piako (see Section 9.8.13), which will address the issue.It is expected that the Waihou 110 kV bus will need to be substantially rebuilt basedon a condition assessment in approximately five years. We will investigate upgradingthe bus security in conjunction with the rebuild. This will address the issue for aWaihou bus outage.There are no proposals to improve security for a Waikino bus outage. Futureinvestment will be customer driven.9.10 Other regional items of interest9.10.1 Arapuni bus reconfigurationProject status/type:This issue is for information onlyIssueThe 110 kV bus at Arapuni is currently permanently split with two bus sections:The Arapuni G1-4 generators, Arapuni–Bombay, Arapuni–Hamilton–1 and 2,Arapuni–Hangatiki, and the Arapuni–Ongarue circuits on one bus (north bus).The Arapuni–Kinleith–1 and 2 circuits on the other bus (south bus).Arapuni G5-8 are selectable between the two bus sections.A fault on the north bus will result in voltage collapse and subsequent loss of supplyat Hangatiki (see Section 9.9.2).For the Bay of Plenty region (see Chapter 10), a fault on the Arapuni south busresults in Kinleith and Lichfield being supplied from Tarukenga. This causes theKinleith–Lichfield–Tarukenga circuits to overload if Kinleith is not generating. It alsocauses low voltage at the Kinleith 33 kV bus.SolutionFollowing the replacement of the Tarukenga interconnecting transformers 79 , theArapuni 110 kV bus split will be closed and reconfigured so in normal operation:Arapuni G1-4 generators, one Arapuni–Hamilton circuit, one Arapuni–Kinleithcircuit, and the Arapuni–Hangatiki circuit are on the north busone Arapuni–Hamilton circuit, one Arapuni–Kinleith circuit, the Arapuni–Bombaycircuit and the Arapuni–Ongarue circuit are on the south bus, andArapuni G5-8 are selectable between the two bus sections.This bus configuration will address the:voltage issue at Hangatiki for a fault on the Arapuni north bus (Section 9.9.2), andloading on the Kinleith–Lichfield–Tarukenga and the Kinleith 33 kV low voltageissue for a fault on the Arapuni south bus.79Scheduled for replacement in the third quarter of 2014 (see Chapter 10, Section 10.10.2).2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 151

Chapter 9: Waikato Region9.10.2 Cambridge spur capacityProject status/type:This issue is for information onlyIssueThe Cambridge Spur connects three loads (at Cambridge, Te Awamutu, and Hinuera)and generation at Karapiro. Two 110 kV Hamilton–Cambridge circuits supply thespur, each with a capacity of 57/70 MVA (summer/winter).The combined load on the spur was approximately 109 MW in summer 2012, forecastto increase to approximately 128 MW by 2028. Generation from Karapiro is used toavoid exceeding the n-1 capacity of the Hamilton–Cambridge circuits, especially insummer. The minimum generation is approximately 56 MW in 2013, increasing to80 MW in 2028. 80SolutionIn the short to medium term, generation from Karapiro will manage the loading on theHamilton–Cambridge circuits. Karapiro has an installed capacity of 90 MW andtypically generates 40 MW during low load periods and 80 to 90 MW during peaks.The typical generation at peak load offsets the load up to around 2028. Theproposed Hangatiki–Te Awamutu 110 kV circuit (see Section 9.8.15) may increase ordecrease the loading on the spur, depending on the generation and load over a widepart of the power system. However, with load growth and during periods of low waterinflow, eventually there will be insufficient generation to avoid an issue with the n-1capacity of the Hamilton–Cambridge circuits.We will monitor the loading on the spur to determine when an issue may arise.Mitigation measures may include reconfiguring the grid or load control when there isan overload, or increasing the capacity of the Hamilton–Cambridge circuits.9.10.3 Hamilton low voltageProject status/type:This issue is for information onlyIssueDuring periods of high load and low Waikato 110 kV generation, the Hamilton 220 kVbus will have low voltage (below 0.9 pu) towards the end of the forecast period for theloss of the 220 kV Hamilton–Ohinewai circuit.SolutionWe will investigate options to resolve this issue closer to the time it occurs. Some ofthe options include:reactive support in the Waikato 110 kV transmission network, anda third 220 kV connection to Hamilton (see Section 9.10.4).9.10.4 Hamilton transmission security during maintenanceProject status/type:This issue is for information onlyIssueWhen a 220 kV Hamilton–Whakamaru circuit, a 220 kV Hamilton–Ohinewai circuit ora Hamilton 220/110 kV transformer is out for maintenance, the Waikato 110 kV80Shifting load from Hinuera to a new grid exit point at Putaruru (see Section 9.8.9) changes theminimum generation to approximately 50 MW in 2014 and approximately 70 MW in 2028.1522013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 9: Waikato Regionsystem is split so it does not form a parallel connection with the 220 kV system. Thisplaces a considerable part of the Waikato region on n security. 81SolutionWe will investigate if it is economic to provide full or partial n-1 security duringmaintenance. It is expected this investigation will begin in 2-5 years, afterdevelopment options are addressed for other issues such as the:Hamilton supply transformer overloading issue (see Section 9.8.7)supply to Wiri (Bombay interconnecting transformer, see Chapter 8, Section8.8.8)Te Awamutu transmission security (see Section 9.8.15), andArapuni bus security (see Section 9.10.1).Options include a:third 220 kV circuit into Hamilton, and/orthird 220/110 kV transformer at Hamilton, or250 MVA 220/110 kV transformer at a new substation, connected to theintersection of the 220 kV Otahuhu–Whakamaru–C line and the 110 kVHamilton–Waihou–A line.9.11 Waikato generation scenarios, proposals and opportunitiesThis section details relevant regional issues for selected generation scenarios,generation proposals under investigation by developers and in the public domain, orother generation opportunities. The impact of committed generation projects on thegrid backbone is dealt with separately in Chapter 6.The maximum generation that can be connected depends on several factors andusually falls within a range. Generation developers should consult with us at an earlystage of their investigations to discuss connection issues.9.11.1 Impact of generation scenarios on regional planThe generation scenarios (see Chapter 5) represent a series of possible futuregeneration outcomes. This section presents only those scenarios relevant to thisregion for the next 15 years.All the generation scenarios anticipate the retirement of three or four Huntly coal unitsover the next 15 years. Generation scenarios 1 and 2 anticipate greater than800 MW of new generation in the Waikato region (544 MW wind generation and260 MW thermal peakers). Generation scenarios 3, 4 and 5 anticipate only one new160 MW thermal peaker scenario.At Hangatiki, generation scenarios 1 and 2 anticipate 44 MW of new wind generationin 2019 and scenario 2 anticipates an additional 54 MW of wind generation in 2027.For information about the impact of a new generation connection at Hangatiki, seeSection 9.11.3.9.11.2 Hauauru Ma Raki wind stationThe proposed Hauauru Ma Raki wind generation station may generate up to540 MW, and will connect to the 220 kV double-circuit transmission line betweenHuntly and Drury.81The load on n security is the Valley Spur (Piako, Waihou, Waikino, and Kopu), the Cambridge spur(Cambridge, Karapiro, Hinuera and Te Awamutu), Bombay (depending on system conditions), andHamilton (for 220 kV circuit outages only).2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 153

Chapter 9: Waikato RegionIf it is necessary to cater for a generation scenario with maximum wind generationand maximum Huntly generation (assuming sustained low hydro generation), then itmay be necessary to reconductor the two 220 kV Huntly–Ohinewai circuits, andthermally upgrade the 220 kV circuit between the wind generation connection andDrury.9.11.3 Hangatiki generationThere are prospects to connect up to approximately 40 MW of generation atHangatiki. This generation will worsen the overloading issue on the 110 kV Arapuni–Hamilton circuits (see Section 9.8.1 for more information).To prevent the overloading of these circuits under a wide range of load andgeneration scenarios, the following upgrades will be required:Runback schemes at Arapuni and/or HangatikiReconductoring the 110 kV Arapuni–Hamilton circuitsFor example, during 2013 winter peak loads, with combined Huntly, Otahuhu, andSouthdown generation of 1,525 MW and Arapuni generation of 180 MW, generationexceeding 18 MW at Hangatiki will cause the Arapuni–Hamilton circuits to overloadfollowing a contingent event.In addition, any new generation on the 110 kV transmission network in the Waikatoregion will add to the 110 kV Arapuni–Kinleith and 110 kV Bombay–Hamilton loading(see Section 9.8.2 and 9.9.3 respectively). Options to enable this level of generationinclude generation runback schemes, generation re-scheduling, and possiblyreconductoring the Bombay–Hamilton circuit. Possible overloading of the two 110 kVArapuni–Kinleith circuits may need to be addressed, but this may be requiredirrespective of additional generation at Hangatiki.1542013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 10: Bay of Plenty Region10 Bay of Plenty Regional Plan10.1 Regional overview10.2 Bay of Plenty transmission system10.3 Bay of Plenty demand10.4 Bay of Plenty generation10.5 Bay of Plenty significant maintenance work10.6 Future Bay of Plenty projects summary and transmission configuration10.7 Changes since the 2012 Annual Planning Report10.8 Bay of Plenty transmission capability10.9 Bay of Plenty bus security10.10 Other regional items of interest10.11 Bay of Plenty generation scenarios, proposals and opportunities10.1 Regional overviewThis chapter details the Bay of Plenty regional transmission plan. We base thisregional plan on an assessment of available data, and welcome feedback to improveits value to all stakeholders.Figure 10-1: Bay of Plenty regionConstruction voltages shown. System as at March 2013.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 155

Chapter 10: Bay of Plenty RegionThe Bay of Plenty region has a mix of growing provincial cities (Mount Maunganui,Tauranga, and Rotorua) together with smaller, less active rural localities (Waiotahiand Te Kaha) and heavy industry (Kawerau, and Kinleith Pulp and Paper Mills).We have assessed the Bay of Plenty region’s transmission needs over the next 15years while considering longer-term development opportunities. Specifically, thetransmission network needs to be flexible to respond to a range of future service andtechnology possibilities, taking into consideration:the existing transmission networkforecast demandforecast generationequipment replacement based on condition assessment, andpossible technological development.10.2 Bay of Plenty transmission systemThis section highlights the state of the Bay of Plenty regional transmission network.The existing transmission network is set out geographically in Figure 10-1 andschematically in Figure 10-2.Figure 10-2: Bay of Plenty transmission schematic11 kV110 kVMount Maunganui33 kV110 kVTauranga33 kV110 kVKaitimako220 kV110 kV33 kV33 kV Te Matai110 kVOkereEdgecumbe110 kV33 kVWaiotahi110 kV50 kVTe Kaha11 kV11 kV220 kVWAIKATOArapuniLichfield110 kV220 kVTarukenga110 kV11 kVWheao110 kVKawerau110 kV 220 kV11 kVKEY220kV CIRCUIT110kV CIRCUIT50kV CIRCUITSUBSTATION BUSTRANSFORMER11 kV 33 kV110 kV11 kVTEE POINTLOAD11 kVRotoruaOwhata11 kV11 kV(TASMAN)CAPACITORGENERATOR110 kVKinleith33 kVAtiamuriOhakuriWAIKATO110 kVMatahina G1Matahina G2Aniwhenua10.2.1 Transmission into the regionBay of Plenty generation is lower than maximum local demand, with the deficitimported through the National Grid during peak load conditions, and any surplusexported during light load conditions.The 220 kV Whakamaru–Atiamuri and Ohakuri–Wairakei circuits connect the regionto the rest of the National Grid. The Bay of Plenty load is predominantly suppliedthrough these circuits, and their capacity is expected to be adequate for the next 20to 30 years to supply the regional load. The Bay of Plenty region will be on n securitywhenever one circuit is out of service.1562013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 10: Bay of Plenty RegionThere is also a low capacity 110 kV Tarukenga–Kinleith–Arapuni connection. Thisconnection is presently split at Arapuni to prevent it overloading. 8210.2.2 Transmission within the regionThe transmission network in the Bay of Plenty region comprises 220 kV and 110 kVcircuits with interconnecting transformers located at Tarukenga, Kaitimako,Edgecumbe, and Kawerau. There is also a single 50 kV circuit between Waiotahiand Te Kaha. Reactive power support is provided by 25 Mvar capacitors at Taurangaand Mount Maunganui.The Bay of Plenty is on n security when either one of the following circuits is out ofservice:220 kV Atiamuri–Tarukenga–1 or 2220 kV Kawerau–Ohakuri.The western Bay of Plenty area is on n security when either one of the following is outof service:220 kV Kaitimako–Tarukenga–1 or 2Kaitimako 220/110 kV transformers.We are also discussing with Powerco and Unison options to increase the:capacity into and around Rotorua which may involve line upgrades betweenTarukenga and Rotorua, and/or new supply transformers at Rotorua and Owhata,andsupply security by building a new grid exit point at Papamoa to alleviate loadgrowth at Mount Maunganui.Generation and interruptible load connected directly or indirectly to the Kawerau110 kV bus must sometimes be constrained to prevent overloading of the 220/110 kVtransformers. There is a total of 235 MW installed generation capacity (Aniwhenua,Kawerau Geothermal, Matahina and Norske-Skog) and other smaller embeddedgeneration stations at Kawerau.We have implemented an interim reconfiguration of the 110 kV grid betweenEdgecumbe, Kawerau and Matahina to allow greater generation export. The interimgrid reconfiguration applies until the Kawerau–T12 transformer is replaced with ahigher-rated transformer in early 2014. This will relieve the existing generationconstraints and allow for a small increase in future generation injecting into theKawerau 110 kV bus.10.2.3 Longer-term development pathNo firm options have been developed for the Bay of Plenty region beyond theplanning period. However, long-term planning for recent projects has indicated thefollowing possible developments in the 10-20 year range.A third interconnecting transformer at Kaitimako.A third interconnecting transformer at Tarukenga.Additional reactive support in the western Bay of Plenty area.Capacity upgrades on the Okere–Te Matai, Kaitimako–Te Matai and Okere–Tarukenga circuits.In the longer term, one possible development is a connection from north of Taurangato the existing Waihou substation in the Waikato region. This may be required tomeet long-term load growth in the fast-growing Tauranga area, and improve securityduring maintenance outages.82See Chapter 9, Section 9.10.1 for further information on the Arapuni bus split.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 157

Chapter 10: Bay of Plenty RegionThere is the potential for significant additional geothermal generation in the easternBay of Plenty area, around Kawerau. If significant generation eventuates, then astaged transmission capacity upgrade will be required (see Section 10.11.2 for moreinformation).10.3 Bay of Plenty demandThe after diversity maximum demand (ADMD) for the Bay of Plenty region is forecastto grow on average by 1.2% annually over the next 15 years, from 548 MW in 2013 to660 MW by 2028. This is lower than the national average demand growth of 1.5%annually.Figure 10-3 shows a comparison of the 2012 and 2013 APR forecast 15-yearmaximum demand (after diversity 83 ) for the Bay of Plenty region. The forecasts arederived using historical data, and modified to account for customer information, whereappropriate. The power factor at each grid exit point is also derived from historicaldata. See Chapter 4 for more information about demand forecasting.Figure 10-3: Bay of Plenty region after diversity maximum demand forecastTable 10-1 lists forecasts peak demand (prudent growth) for each grid exit point forthe forecast period, as required for the Grid Reliability Report.Table 10-1: Forecast annual peak demand (MW) at Bay of Plenty grid exit points to 2028Grid exit pointPowerfactorNext 5 yearsPeak demand (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Edgecumbe 0.96 68 69 71 73 75 77 81 85 89 93 97Kaitimako 1 0.98 22 22 23 23 29 29 31 32 33 34 36Kawerau Horizon 0.98 21 22 22 23 24 24 25 27 28 29 30Kawerau T6-T9 2 1.00 90 90 90 90 90 90 90 90 90 90 9083The after diversity maximum demand (ADMD) for the region will be less than the sum of theindividual grid exit point peak demands, as it takes into account the fact that the peak demand doesnot occur simultaneously at all the grid exit points in the region.1582013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 10: Bay of Plenty RegionGrid exit pointKawerau–T11/T14PowerfactorNext 5 yearsPeak demand (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 20280.98 85 85 85 85 85 85 85 85 85 85 85Kinleith 11 kV -0.94 84 84 84 84 84 84 84 84 84 84 84Kinleith 33 kV 0.98 25 25 26 26 27 27 28 29 30 31 33Lichfield 0.95 10 10 10 10 10 10 10 11 11 11 11Mt Maunganui3 0.99 67 69 50 51 53 54 58 61 64 68 7133 kVOwhata 0.99 16 17 17 17 17 18 18 19 19 20 20Papamoa 3 0.99 0 0 21 22 23 23 25 26 28 29 30Rotorua 11 kV 0.97 37 38 38 38 39 39 39 40 41 41 42Rotorua 33 kV 0.97 49 50 50 51 51 51 52 53 54 55 56Tarukenga 11 kV 1.00 12 12 13 13 13 13 14 14 14 15 15Tauranga 11 kV 0.99 32 32 33 34 30 30 32 34 35 37 38Tauranga 33 kV 0.95 79 81 83 85 87 89 94 98 103 108 112Te Kaha 0.97 2 2 2 2 2 2 2 2 3 3 3Te Matai 2 0.96 34 35 35 36 37 38 39 41 43 44 46Waiotahi 0.99 12 12 12 13 13 13 14 14 15 16 161. The customer advises that an estimated 5 MW load will be shifted from Tauranga 11 kV to Kaitimakoin 2017 (associated with establishment of the Pyes Pa substation).2. After earlier announcements, Norse-Skog halved production at its mill in Kawerau on 9 January2013.The implication of this lower level of production is not yet incorporated into this demandforecast.3. The customer advises that the Papamoa East grid exit point is scheduled for commissioning in 2015with load then switched from the Mt Maunganui grid exit point.10.4 Bay of Plenty generationThe Bay of Plenty region’s generation capacity is approximately 388 MW.Kaimai is a run of river scheme that varies between 14 MW and 42 MW, injecting intothe Tauranga 33 kV bus. Typically, 14 MW is the minimum generation available fromthe scheme, which is used to offset peak grid exit point loads, but only if sufficientwater is available.Table 10-2 lists the generation forecast for each grid injection point for the forecastperiod, as required for the Grid Reliability Report. This includes all known andcommitted generation stations including those embedded within the relevant locallines company’s network (Horizon, Unison, or Powerco). 84Table 10-2: Forecast annual generation capacity (MW) at Bay of Plenty grid injectionpoints to 2028 (including existing and committed generation)Grid injection point(location if embedded)Next 5 yearsGeneration capacity (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Aniwhenua 25 25 25 25 25 25 25 25 25 25 25Edgecumbe (Bay Milk) 10 10 10 10 10 10 10 10 10 10 10Kawerau (BOPE) 6 6 6 6 6 6 6 6 6 6 6Kawerau (TPP) 37 37 37 37 37 37 37 37 37 37 3784Only generators with a capacity greater than 1 MW are listed. Generation capacity is rounded to thenearest megawatt.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 159

Chapter 10: Bay of Plenty RegionGrid injection point(location if embedded)Next 5 yearsGeneration capacity (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Kawerau (KAG) 105 105 105 105 105 105 105 105 105 105 105Kawerau (KA24) 9 9 9 9 9 9 9 9 9 9 9Kawerau (Norske Skog) 25 25 25 25 25 25 25 25 25 25 25Kinleith 28 28 28 28 28 28 28 28 28 28 28Matahina 80 80 80 80 80 80 80 80 80 80 80Mount Maunganui(Alliance Agri)Rotorua(Fletcher Forests)Rotorua (Wheao, FlaxyScheme)7 7 7 7 7 7 7 7 7 7 73 3 3 3 3 3 3 3 3 3 324 24 24 24 24 24 24 24 24 24 24Tauranga (Kaimai) 42 42 42 42 42 42 42 42 42 42 4210.5 Bay of Plenty significant maintenance workOur capital project and maintenance works are integrated to enable system issues tobe resolved if possible when assets are replaced or refurbished. Table 10-3 lists thesignificant maintenance-related work 85 proposed within the Bay of Plenty region forthe next 15 years that may significantly impact related system issues or connectedparties.Table 10-3: Proposed significant maintenance workDescription Tentative year Related system issuesEdgecumbe 33 kV outdoor toindoor conversion, andEdgecumbe supply transformersexpected end-of-life2013-20152027-2029The forecast load will exceed the transformer’sn-1 capacity from 2013. See Section 10.8.4 formore information.Edgecumbe interconnectingtransformers expected end-of-lifeKawerau 11 kV switchgearreplacement, and110/11 kV supply transformersexpected end-of-lifeAll Kinleith 110/11 kV supplytransformers expected end-of-life,and 11 kV indoor switchboardreplacementKinleith–T4 supply transformerexpected end-of-lifeOwhata supply transformersexpected end-of-life, and 11 kVswitchgear replacementRotorua110/11 kV supplytransformers expected end-of-lifeTarukenga interconnectingtransformers replacement2024-2026 The Edgecumbe interconnecting transformersare normally open to reduce generationconstraints at Kawerau. See Section 10.11.2 formore information.2016-20172019-2021Replacing these transformers will affect the11 kV fault level. See Section 10.11.2 for moreinformation.2016-2021 No system issues are identified within theforecast period.2016-2018 Changing the transformer’s vector group willenable T4 and T5 to operate in parallel. This isone option to provide n-1 security to the 33 kVbus. See Section 10.8.9 for more information.2016-20182027-2028Upgrading the transformers’ capacity will resolvethe transformer overloading issue. See Section10.8.12 for more information.2012-2014 A project is underway to replace thesetransformers with 35 MVA units. See Section10.8.13 for more information.2013-2014 Committed system development will reduceconstraints on the 110 kV transmission networkbetween Tarukenga and Arapuni. See Section10.10.2 for more information.85This may include replacement of the asset due to its condition assessment.1602013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 10: Bay of Plenty RegionDescription Tentative year Related system issuesTe Kaha substationredevelopmentTe Matai–T1 supply transformerexpected end-of-lifeWaiotahi 110/11 kV supplytransformers expected end-of-life2012-2014 A project is underway to improve the reliability ofsupply to Te Kaha.2025-2027 Upgrading the transformer capacity will resolvethe transformer overload issue. See Section10.8.17 for more information.2019-2021 Upgrading the transformer’s capacity will resolvethe transformer overloading issue. See Section10.8.18 for more information.10.6 Future Bay of Plenty projects summary and transmission configurationTable 10-4 lists projects to be carried out in the Bay of Plenty region within the next15 years.Figure 10-4 shows the possible configuration of Bay of Plenty transmission in 2028,with new assets, upgraded assets, and assets undergoing significant maintenancewithin the forecast period.Table 10-4: Projects in the Bay of Plenty region up to 2028Circuit/site Projects StatusEdgecumbeKawerauIncrease the supply transformer protection settings – interim solution.Replace the supply transformers with higher-rated units.Remove or replace the interconnecting transformers.Convert the 33 kV outdoor switchgear to an indoor switchboard.Increase the 220/110 kV transformer capacity.Replace the 110/11 kV T1 and T2 supply transformers.Replace the 11 kV switchgear.PossiblePossibleProposedProposedCommittedProposedProposedKaitimako Install a third interconnecting transformer. PossibleKinleithOwhataReplace the 110/11 kV supply transformers.Replace the 11 kV indoor switchboard.Replace the 110/33 kV T4 supply transformer.Replace the 110/33 kV T5 supply transformer with higher-rated unit.Replace the 110/11 kV supply transformers.Replace the 11 kV switchgear.ProposedProposedProposedPossiblePossibleProposedPapamoa Construct a new grid exit point. PossibleRotorua–TarukengaThermally upgrade the circuit.PossibleRotorua Replace the 110/11 kV supply transformers with higher-rated units. CommittedTarukengaReplace the 220/110 kV interconnecting transformers.Install a second 110/11 kV supply transformer.CommittedPossibleTauranga Upgrade the 110/11 kV transformers’ branch limiting components PossibleTe Kaha Substation re-development. ProposedTe Matai Replace the existing 30 MVA supply transformer. ProposedWaiotahi Replace the 110/11 kV supply transformers with higher rated units. Possible2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 161

Chapter 10: Bay of Plenty RegionFigure 10-4: Possible Bay of Plenty transmission configuration in 2028Mount Maunganui33 kVTauranga11 kV*110 kV110 kV33 kV110 kVKaitimako220 kV110 kVPapamoa33 kVTe Matai33 kV110 kV OkereEdgecumbe110 kV33 kVWaiotahi110 kV50 kVTe Kaha11 kV11 kV220kVWAIKATOArapuniLichfield110 kV11 kV220 kVTarukenga110 kV11 kVWheao110 kV110 kV11 kV33 kV 11 kVRotorua OwhataKawerau110 kV 220 kV11 kV11 kV11 kV(TASMAN)KEYNEW ASSETSUPGRADED ASSETSASSETS SCHEDULEDFOR REPLACEMENTMINOR UPGRADE*110 kV33 kVKinleithAtiamuriWAIKATOOhakuri110 kVMatahinaAniwhenua10.7 Changes since the 2012 Annual Planning ReportTable 10-5 lists the specific issues that are either new or no longer relevant within theforecast period when compared to last year's report.Table 10-5: Changes since 2012IssuesTarukenga interconnecting transformer capacityTauranga 33 kV supply transformer capacityKaitimako interconnecting transformer capacityKawerau–T1 and T2 supply transformer capacityKinleith 110/11 kV supply securityChangeRemoved. This is no longer an issue within theforecast period after the completion of theKaitimako 220/110 kV interconnection project.Removed. This is no longer an issue within theforecast period after the completion of the 33 kVindoor switchboard project, which removes thetransformer branch limits.New issue.New issue.New issue.10.8 Bay of Plenty transmission capabilityTable 10-6 summarises issues within the Bay of Plenty region for the next 15 years.For more information about a particular issue, refer to the listed section number.Table 10-6: Bay of Plenty region transmission issuesSectionnumberIssueRegional10.8.1 Kawerau 110 kV generation constraint10.8.2 Kaitimako interconnecting transformer capacity10.8.3 Tauranga and Mount Maunganui transmission securitySite by grid exit point1622013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 10: Bay of Plenty RegionSectionnumberIssue10.8.4 Edgecumbe supply transformer capacity10.8.5 Kaitimako supply security10.8.6 Kawerau–T1 and T2 supply transformer capacity10.8.7 Kawerau–Matahina 110 kV transmission security and capacity10.8.8 Kinleith–Tarukenga 110 kV transmission capacity10.8.9 Kinleith 110/33 kV supply security, supply transformer capacity10.8.10 Kinleith 110/11 kV supply security10.8.11 Mount Maunganui supply transformer capacity10.8.12 Owhata supply transformer capacity10.8.13 Rotorua supply transformer capacity10.8.14 Rotorua–Tarukenga 110 kV transmission capacity10.8.15 Tarukenga supply security10.8.16 Tauranga 11 kV supply transformer capacity10.8.17 Te Matai supply transformer capacity10.8.18 Waiotahi supply transformer capacity10.8.19 Waiotahi and Te Kaha supply securityBus security10.9.1 Transmission bus security10.9.4 Kinleith 110 kV bus security10.9.5 Rotorua area bus security10.9.2 Kaitimako 110 kV bus security10.8.1 Kawerau 110 kV generation constraintProject reference: Interconnecting transformer: KAW-POW_TFR-DEV-01Project status/type: Committed, Base CapexIndicative timing: Interconnecting transformer: 2014Indicative cost band: Interconnecting transformer: BIssueGeneration at Aniwhenua, Matahina and KAG, and embedded generation withinHorizon’s distribution network and within the Norske-Skog mill, all connects to theKawerau 110 kV bus. The Kawerau 110 kV bus is connected to the rest of thesystem via the:Kawerau 220/110 kV transformer–T12 (100 MVA, 20% impedance)Kawerau 220/110 kV transformer–T13 (100 MVA, 10% impedance), andlow capacity 110 kV circuits (Kawerau–Edgecumbe–1 and 2, each rated at48/59 MVA (summer/winter), in series with Edgecumbe–Owhata rated at57/69 MVA (summer/winter)).There is an existing constraint for exporting generation from the Kawerau 110 kV busunder the following situations.High generation and low demand at Kawerau.An under-frequency event for a Huntly generation trip or loss of the HVDCrequiring increased generation and the tripping of interruptible load.An outage of a 110 kV Edgecumbe–Kawerau circuit or the 220/110 kVinterconnecting transformer.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 163

Chapter 10: Bay of Plenty RegionA recently commissioned Norske-Skog 25 MW generator connected to the Kawerau110 kV bus will increase the occurrence of generation constraints at Kawerau.SolutionWe will replace the Kawerau–T12 transformer 86 with a 250 MVA 10% impedancetransformer. The project is expected to be completed in 2014.This will relieve existing generation constraints and allow for a small increase in futuregeneration connections at the Kawerau 110 kV bus.We will not be able to replace a transformer before 2014 due to the lead time requiredfor its purchase, installation and commissioning and have implemented an interimgrid reconfiguration to relieve constraints until this occurs.The interim grid reconfiguration connects the Kawerau–Matahina–2 circuit directly tothe Edgecumbe–Kawerau–2 circuit, bypassing Kawerau to create a single circuitbetween Matahina and Edgecumbe, and splitting the Matahina bus. TheEdgecumbe–Kawerau–1 circuit is open during this period (see Figure 10-2).See Section 10.11.2 for possible longer-term development options.10.8.2 Kaitimako interconnecting transformer capacityProject reference: KMO-POW_TFR-DEV-01Project status/type: Possible, Base CapexIndicative timing: 2026Indicative cost band: BIssueTwo 220/110 kV interconnecting transformers at Kaitimako supply Kaitimako,Tauranga, Mount Maunganui and part of Te Matai load, providing:a total nominal installed capacity of 300 MVA, andn-1 capacity of 217/225 MVA (summer/winter).An outage of one interconnecting transformer may cause the other to exceed its n-1capacity from 2026 87 .SolutionThe proposed new grid exit point at Papamoa (see Section 10.10.1) will defer theoverload issue until 2027. Operational measures, such as load restrictions andincreased output from embedded hydro generation (assuming water availability) maydefer the overload for another few years. In the longer term, a third interconnectingtransformer will be required at Kaitimako.10.8.3 Tauranga and Mount Maunganui transmission securityProject reference:Project status/type:Indicative timing:Indicative cost band:PPM-SUBEST-DEV-01Possible, customer-specificTo be advisedBIssueTauranga and Mount Maunganui are supplied from Kaitimako through the following110 kV circuits (see Figure 10-5):8687The Kawerau 220/110 kV T12 transformer is 100 MVA, 20% impedance.It is assumed that Kaimai (embedded at Tauranga) is generating 14 MW.1642013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 10: Bay of Plenty RegionKaitimako–Tauranga–1, rated at 96/105 MVA (summer/winter)Kaitimako–Mount Maunganui–1, rated at 63/77 MVA (summer/winter), anda shared Kaitimako–Tauranga–Mount Maunganui–2 circuit with the followingratings.• Kaitimako–Poike section 96/105 MVA (summer/winter).• Poike–Tauranga section 96/105 MVA (summer/winter).• Poike–Mount Maunganui 63/77 MVA (summer/winter).Figure 10-5: Kaitimako grid configurationMount Maunganui110 kVTaurangaPoike110 kV 110 kVTe Matai110 kVKaitimakoTarukenga/Okere/Owhata220 kVTarukengaFor Tauranga and Mount Maunganui, the Kaitimako–Poike circuit section willoverload 87 for an outage of the:Kaitimako–Tauranga–1 circuit during peak load periods from 2015, andKaitimako–Mount Maunganui–1 circuit during peak load periods from 2020.For Mount Maunganui, an outage of the Kaitimako–Mount Maunganui–1 circuit orPoike–Mount Maunganui circuit section will overload the other circuit from 2015.For Tauranga, an outage of the Kaitimako–Tauranga–1 circuit or Poike–Taurangacircuit section will overload the other circuit from 2015. 87SolutionThe overloading of the Kaitimako–Poike circuit section is addressed by an existingspecial protection scheme, which will reconfigure the Kaitimako–Tauranga–MountMaunganui–2 circuit at Tauranga or Mount Maunganui to remove the overload. Thisaddresses the issue only until the load at Tauranga exceeds the rating of theKaitimako–Poike circuit (2015) and at Mount Maunganui until the load exceeds therating for the Poike–Mount Maunganui circuit (2015).We will discuss options to address the Tauranga security issue with Powerco, whichinclude:transferring more load from Tauranga to the new Kaitimako grid exit point, andshort-term operational measures to limit the Tauranga load and/or constrain-ongeneration at Kaimai.The transmission capacity into Mount Maunganui is limited to approximately 75 MWby the rating of the Kaitimako–Mount Maunganui circuit. This constraint will beaddressed by:transferring load from Mount Maunganui to a proposed new Papamoa grid exitpoint (see Section 10.10.1), andoperational measures (if required in the short term) to limit the Mount Maunganuiload.Land will need to be acquired for the new grid exit point at Papamoa.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 165

Chapter 10: Bay of Plenty RegionFuture investment will be customer driven.10.8.4 Edgecumbe supply transformer capacityProject reference: Upgrade protection: EDG-POW_TFR-EHMT-01Upgrade transformer: EDG-POW_TFR-EHMT-02Project status/type: Upgrade protection: possible, Base CapexUpgrade transformer: possible, customer-specificIndicative timing: Upgrade protection: 2016Upgrade transformer: to be advisedIndicative cost band: Upgrade protection: AUpgrade transformer: CIssueTwo 220/33 kV transformers supply Edgecumbe’s load, providing:a total nominal installed capacity of 100 MVA, andn-1 capacity of 60/60 MVA 88 (summer/winter).The peak load at Edgecumbe is forecast to exceed the transformers’ n-1 wintercapacity by approximately 11 MW in 2013, increasing to approximately 40 MW in2028 (see Table 10-7).Table 10-7: Edgecumbe supply transformer overload forecastCircuits/gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Edgecumbe 0.96 11 13 15 17 18 20 24 28 32 36 40SolutionResolving the protection limit will reduce the overload to 4 MW in 2013, increasing to33 MW in 2028. We will discuss with Horizon Energy future supply options, whichinvolve:limiting the load or transferring some load to another grid exit point in the shortterm, andreplacing the existing transformers with higher-rated units in the long term.We will also convert the Edgecumbe 33 kV outdoor switchgear to an indoorswitchboard within the next five years, and raise the protection limit in conjunctionwith the conversion work.In addition, the two supply transformers have an expected end-of-life at the end of theforecast period. Any future transformer upgrade will be customer driven.10.8.5 Kaitimako supply securityProject status/type:This issue is for information onlyIssueA single 110/33 kV, 75 MVA transformer supplies load at Kaitimako resulting in non-1 security. Some of the 11 kV Tauranga load will be shifted to Kaitimako, which isforecast to grow to 36 MW by 2028 (see also Section 10.8.3).88The transformers’ capacity is limited by protection settings; with this limit resolved, the n-1 capacitywill be 67/71 MVA (summer/winter).1662013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 10: Bay of Plenty RegionSolutionThe lack of n-1 security can be managed operationally by transferring load toTauranga. Future investment will be customer driven.10.8.6 Kawerau–T1 and T2 supply transformer capacityProject reference: KAW-POW_TFR-REPL-01Project status/type: Proposed, Base CapexIndicative timing: 2019-2021Indicative cost band: To be advisedIssueKawerau–T1 and T2 transformers supply Horizon Energy’s load, providing:a total nominal installed capacity of 40 MVA, andn-1 capacity of 25/27 MVA (summer/winter).The Horizon Energy’s peak load is forecast to exceed the transformers’ n-1 wintercapacity by approximately 1 MW in 2020, increasing to approximately 6 MW in 2028(see Table 10-8).Table 10-8: Kawerau–T1 and T2 supply transformer overload forecastCircuits/gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Kawerau 11 kV 0.98 0 0 0 0 0 0 1 2 4 5 6SolutionThe two supply transformers are approaching their expected end-of-life within thenext 5-10 years. We will discuss with Horizon Energy the rating and timing for thesereplacement transformers. Future investment will be customer driven.10.8.7 Kawerau–Matahina 110 kV transmission security and capacityProject status/type:This issue is for information onlyIssueThe 110 kV Kawerau–Matahina line comprises two circuits each rated at 88/98 MVA(summer/winter).Until the new Kawerau 220/110 kV transformer is commissioned, the interim gridreconfiguration at Matahina (see Section 10.8.1 for more information) will result in non-1 security for Matahina and Aniwhenua generation.After the new Kawerau 220/110 kV transformer is commissioned, the Kawerau andMatahina 110 kV buses will be returned to their normal configuration. The loss of oneKawerau–Matahina circuit may overload the remaining circuit with high generation atMatahina and Aniwhenua.SolutionThe overload can be managed operationally by restricting the maximum generation atMatahina and Aniwhenua. This situation is considered satisfactory, and there are noplans to make transmission network changes at this stage. Future investment will becustomer driven.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 167

Chapter 10: Bay of Plenty Region10.8.8 Kinleith–Tarukenga 110 kV transmission capacityProject status/type:This issue is for information onlyIssueThe 110 kV Kinleith–Lichfield–Tarukenga–1 and 2 circuits are rated at 51/62 MVAand 63/77 MVA (summer/winter), respectively. These circuits may overload duringlow Arapuni and/or Upper North Island generation, if either of the following circuits isout of service:220 kV Hamilton–Whakamaru, or110 kV Kinleith–Lichfield–Tarukenga–1 or 2.SolutionThis issue is managed with the Arapuni bus split 89 and generation limits at Arapuni.This issue will be alleviated, but not eliminated, by the following committed projects:the North Island Grid Upgrade (now complete)the Wairakei–Whakamaru–C line project, andthe Tarukenga interconnecting transformer replacement.It is expected that the Arapuni bus split will be closed following the completion ofthese projects, and confirmation by a net benefit test. Operational measures willcontinue to be used to manage the constraints for the forecast period and beyond.10.8.9 Kinleith 110/33 kV supply security, supply transformer capacity and low voltageProject reference: KIN-POW_TFR-EHMT-01Project status/type: Possible, customer-specificIndicative timing: 2016Indicative cost band: AIssueTwo 110/33 kV transformers (rated at 20 MVA and 30 MVA) supply Kinleith’s 33 kVload, providing:a total nominal installed capacity of 50 MVA, andn-1 capacity of 24/25 MVA (summer/winter).The supply transformers cannot be connected to the 33 kV bus at the same time, dueto different vector groups. The load is normally supplied by the 30 MVA transformer,and there is a loss of supply when transferring load between the two transformers.The peak 33 kV load at Kinleith is forecast to exceed the n-1 winter capacity of the20 MVA transformer by approximately 1 MW in 2013, increasing to approximately9 MW in 2028 (see Table 10-9).Table 10-9: Kinleith 33 kV supply transformer overload forecastCircuits/gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Kinleith 33 kV 0.98 1 1 2 2 3 3 4 5 7 8 9The Kinleith 33 kV bus has low voltages for some system conditions 89 , partiallybecause the transformer has no on-load tap changer.89See Chapter 9, Section 9.10.1 for more information about the Arapuni bus split.1682013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 10: Bay of Plenty RegionSolutionWe are discussing options with Powerco and Carter Holt Harvey. One possibleoption is to replace the 20 MVA transformer with a 40 MVA transformer. In addition,the 30 MVA transformer is approaching its expected end-of-life within the next fiveyears. The appropriate rating and vector group for the replacement transformer willalso be considered, in conjunction with the replacement work. The replacementtransformer will have an on-load tap changer, which will address the low voltageissue. Any future transformer upgrade will be customer driven.10.8.10 Kinleith 110/11 kV supply securityProject status/type:This issue is for information onlyIssueFour 110/11 kV supply transformers supply the Carter Holt Harvey pulp and papermill. Each transformer normally supplies a separate 11 kV bus section to limit thefault level to the mill. Therefore, the 11 kV loads do not have no-break transformersecurity for fault outages, but do have no-break security for planned outages.SolutionThe lack of n-1 security will be managed operationally in the medium term.The 11 kV switchboard and four supply transformers will reach their expected end-oflifewithin the next 5-10 years. We will discuss with Powerco and Carter Holt Harveyreplacement options, and possible options to resolve the lack of n-1 security.10.8.11 Mount Maunganui supply transformer capacityProject status/type:This issue is for information onlyIssueTwo 110/33 kV transformers supply Mount Maunganui’s load, providing:a total nominal installed capacity of 150 MVA, andn-1 capacity of 87/87 90 MVA (summer/winter).The peak load at Mount Maunganui is forecast to exceed the transformers’ n-1 wintercapacity by approximately 2 MW in 2018, increasing to approximately 26 MW in 2028(see Table 10-10).Table 10-10: Mount Maunganui supply transformer overload forecastCircuits/gridexit pointMountMaunganui(no Papamoa)PowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 20280.98 0 0 0 0 0 2 7 12 16 21 26SolutionThe transmission capacity into Mount Maunganui is limited to approximately 75 MWby the rating of the Kaitimako–Mount Maunganui circuit (see Section 10.8.3), whichlimits the maximum load before the transformer limit applies. This constraint will be90The transformers’ capacity is limited by the protection limit; with this limit resolved, the n-1 capacitywill be 87/98 MVA (summer/winter).2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 169

Chapter 10: Bay of Plenty Regionaddressed by transferring load from Mount Maunganui to a proposed new grid exitpoint at Papamoa (see Section 10.10.1 for more information).10.8.12 Owhata supply transformer capacityProject reference: OWH-POW_TFR-EHMT-01Project status/type: Possible, customer-specificIndicative timing: 2016-2018Indicative cost band: To be advisedIssueTwo 110/11 kV transformers supply Owhata’s load, providing:a total nominal installed capacity of 20 MVA, andn-1 capacity of 11/12 MVA (summer/winter).The peak load at Owhata is forecast to exceed the transformers’ n-1 winter capacityby approximately 4 MW in 2013, increasing to approximately 8 MW in 2028 (seeTable 10-11).Table 10-11: Owhata supply transformer overload forecastCircuits/gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Owhata 0.99 4 5 5 5 5 6 6 7 7 8 8SolutionPresently, operational measures can be taken to prevent transformer overloads in theevent of a transformer failure.In the short term, Unison has a number of smart grid projects underway to increaseload shifting between Owhata and Rotorua, which will also reduce loading on the110 kV Rotorua–Tarukenga circuits (see Section 10.8.14).In the medium to long-term, Unison is expected to permanently shift load fromRotorua to Owhata, with both 11 kV and 33 kV feeders. Options to replace theexisting transformers with higher rated units include:two transformers which are reconfigurable between 110/11 kV and 110/33 kVtwo 110/33/11 kV transformers, orone 110/33 kV, one 110/11 kV and one 33/11 kV transformer.Additionally, the 110/11 kV supply transformers at Owhata are approaching theirexpected end-of-life within the next five years. We do not anticipate any propertyissues, as the transformer replacement work can be carried out within the existingsubstation boundary. Future investment will be customer driven.10.8.13 Rotorua supply transformer capacityProject reference: ROT-POW_TFR-EHMT-01Project status/type: Committed, Base CapexIndicative timing: 2012-2014Indicative cost band: BIssueTwo 110/11 kV transformers supply Rotorua’s 11 kV load, providing:a total nominal installed capacity of 40 MVA, and1702013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 10: Bay of Plenty Regionn-1 capacity of 25/27 MVA (summer/winter).The peak load at Rotorua is forecast to exceed the transformers’ n-1 winter capacityby approximately 12 MW in 2013, increasing to approximately 17 MW in 2028 (seeTable 10-12).Table 10-12: Rotorua supply transformer overload forecastCircuits/gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Rotorua 0.97 12 13 13 13 14 14 14 15 16 16 17There are also two 110/33 kV supply transformers supplying the 33 kV load atRotorua providing:a total nominal capacity of 120 MVA, andn-1 capacity of 66/66 91 MVA (summer/winter).The Rotorua 33 kV peak load is not forecast to exceed the 110/33 kV transformers’capacity for the duration of the forecast period.SolutionIn the short term, Unison advises that load can be transferred within its network toTarukenga and Owhata following a 110/11 kV transformer failure.We have agreed with Unison to install two 35 MVA replacement transformers,providing n-1 capacity of 38 MVA 92 . Unison will limit the maximum load to 38 MVA.This solution, combined with the 110 kV Rotorua bus reconfiguration (see Section10.9.5), is expected to provide n-1 transformer capacity for the forecast period.10.8.14 Rotorua–Tarukenga 110 kV transmission capacity and securityProject reference:Project status/type:Indicative timing:Indicative cost band:ROT_TRK-TRAN-EHMT-01Possible, customer-specificTo be advisedAIssueThe 110 kV Rotorua–Tarukenga line comprises two circuits, each rated at 63/77 MVA(summer/winter). The 110 kV bus at Rotorua is split so that:the local generation at Wheao and one Rotorua 110/33 kV transformer isconnected to the Rotorua–Tarukenga–2 circuit, andboth Rotorua 110/11 kV transformers and one 110/33 kV transformer (i.e. themajority of the load) is supplied from the 110 kV Rotorua–Tarukenga–1 circuit.An outage of the 110 kV Rotorua–Tarukenga–2 circuit:results in the loss of Wheao generation, andoverloads the remaining 110 kV Rotorua–Tarukenga–1 circuit (as it supplies allRotorua’s load).An outage of the 110 kV Rotorua–Tarukenga–1 circuit results in a loss of supply tothe entire Rotorua 11 kV load.9192The transformers’ capacity is limited by the protection limit; with this limit resolved, the n-1 capacitywill be 68/71 MVA (summer/winter).The n-1 capacity is set by the rating of the 11 kV switchboard.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 171

Chapter 10: Bay of Plenty RegionSolutionWe are discussing future supply options with Unison (the local lines company) andTrustpower (owner of the embedded generation connecting at Rotorua), whichinclude:in the short term, transferring load within Unison’s network to Tarukenga andOwhata to reduce the Rotorua load to within the capacity of the 110 kV Rotorua–Tarukenga circuits, and/orin the longer term, thermally upgrading the existing 110 kV Rotorua–Tarukengacircuits to 90/100 MVA (summer/winter), which may require easements oversome parts of the line.Limiting the 11 kV load to within the rating of the 110/11 kV transformers (see Section10.8.13) and reconfiguring the Rotorua 110 kV bus (see Section 10.9.5) will securethe Rotorua 11 kV and 33 kV load. Future investment will be customer driven.10.8.15 Tarukenga supply securityProject reference:Project status/type:Indicative timing:Indicative cost band:TRK-POW_TFR-DEV-01Possible, customer-specificTo be advisedAIssueA single 110/11 kV, 20 MVA supply transformer supplies Tarukenga’s load resultingin no n-1 security. Tarukenga’s peak load is forecast to grow to 15 MW by 2028.SolutionUnison can backfeed the Tarukenga load from the Rotorua 11 kV bus if required.However, at times it may not be possible to backfeed all the load due to thetransmission capacity into Rotorua (see Section 10.8.14). The lack of n-1 securitycan be managed operationally in the short term.We are discussing options with Unison, such as installing a second 110/11 kVtransformer to increase the supply security at Tarukenga. Future investment will becustomer driven.10.8.16 Tauranga 11 kV supply transformer capacityProject reference:Project status/type:Indicative timing:Indicative cost band:TGA-POW_TFR-EHMT-01Possible, customer-specificTo be advisedAIssueTwo 110/11 kV transformers supply Tauranga’s 11 kV load, providing:a total nominal installed capacity of 60 MVA, andn-1 capacity of 30/30 MVA 93 (summer/winter).The peak load on the Tauranga 11 kV bus is forecast to exceed the transformers’ n-1winter capacity by approximately:4 MW in 20132 MW in 2017 following some load shifting to Kaitimako, and93The transformers’ capacity is limited by low voltage cables, protection and metering limits, and theseries reactors; with these limits resolved, the n-1 capacity will be 45/45 MVA (summer/winter).1722013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 10: Bay of Plenty Region11 MW in 2028 (see Table 10-13).Table 10-13: Tauranga 11 kV supply transformer overload forecastCircuits/gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Tauranga 11 kV 0.99 4 5 5 6 2 3 4 6 7 9 11SolutionA possible option is to limit the load or to transfer additional load to Kaitimako.In the longer-term, resolving the low voltage cable limit and the protection limit 94 willprovide sufficient n-1 capacity to meet the load growth within the forecast period.Future investment will be customer driven.10.8.17 Te Matai supply transformer capacityProject status/type:This issue is for information onlyIssueTwo 110/33 kV transformers (rated at 30 MVA and 40 MVA) supply Te Matai’s load,providing:a total nominal installed capacity of 70 MVA, andn-1 capacity of 36/39 MVA (summer/winter).The peak load at Te Matai is forecast to exceed the transformers’ n-1 winter capacityby approximately 1 MW in 2015, increasing to approximately 11 MW in 2028 (seeTable 10-14).Table 10-14: Te Matai supply transformer overload forecastCircuits/gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Te Matai 0.96 0 0 1 1 2 3 5 6 8 10 11SolutionThe issue will be managed operationally in the short term. In addition, the Te Matai30 MVA supply transformer has an expected end-of-life at the end of the forecastperiod. We will discuss with Powerco the timing and rating of the replacementtransformer.Future investment will be customer driven.10.8.18 Waiotahi supply transformer capacityProject reference:Project status/type:Indicative timing:Indicative cost band:WAI-POW_TFR-EHMT-01Possible, customer-specificTo be advisedB94Resolving the low voltage cables, metering and protection limits will increase the n-1 capacity to40/40 MVA (summer/winter), which is the limit of the series reactors. This is sufficient to meet theload growth within the forecast period.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 173

Chapter 10: Bay of Plenty RegionIssueTwo 110/11 kV transformers supply Waiotahi’s load, providing:a total nominal installed capacity of 20 MVA, andn-1 capacity of 11/12 MVA (summer/winter).The transformers also supply Te Kaha’s load via an 11/50 kV step-up transformer atWaiotahi. The combined peak load at Waiotahi is forecast to exceed thetransformers’ n-1 winter capacity by approximately 4 MW in 2013, increasing to 9 MWin 2028 (see Table 10-15).Table 10-15: Waiotahi supply transformer overload forecastCircuits/gridexit pointWaiotahi (andTe Kaha)PowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 20280.99 4 4 4 5 5 6 6 7 8 8 9SolutionWe will discuss with Horizon Energy options to increase the transformer capacity.Additionally, the 110/11 kV supply transformers at Waiotahi will approach theirexpected end-of-life within the next 5-10 years. We will discuss with Horizon Energythe rating and timing for these replacement transformers.We do not anticipate any property issues as the transformer replacement work can becarried out within the existing substation boundary.Future investment will be customer driven.10.8.19 Waiotahi and Te Kaha supply securityProject status/type:This issue is for information onlyIssueWaiotahi and Te Kaha are supplied by one transmission circuit (a 110 kV circuit toWaiotahi and a 50 kV circuit to Te Kaha) resulting in no n-1 security.Both loads are supplied by a single Edgecumbe–Waiotahi circuit with the:Waiotahi 11 kV load supplied through two 10 MVA transformers, andTe Kaha 11 kV load supplied through one:Solution• 11/50 kV, 3 MVA step up transformer at Waiotahi• 50 kV Te Kaha–Waiotahi circuit, and• 50/11 kV, 2.5 MVA transformer at Te Kaha.The lack of n-1 security can be managed operationally. Future investment will becustomer driven.10.9 Bay of Plenty bus securityThe 2013 APR has been expanded to include issues arising from the outage of asingle bus section rated at 50 kV and above for the next 15 years.Bus outages disconnect more than one power system component (for example, othercircuits, transformers, reactive support or generators). Therefore, bus outages may1742013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 10: Bay of Plenty Regioncause greater issues than a single circuit or transformer outage (although the risk of abus fault is low, being less common than a circuit or transformer outage).10.9.1 Transmission bus securityTable 10-16 lists bus outages that cause voltage issues or a total loss of supply.Generators are included only if a bus outage disconnects the whole generationstation or causes a widespread system impact. Supply bus outages, typically 11 kVand 33 kV, are not listed.Table 10-16: Transmission bus outagesTransmissionbus outageEdgecumbe 110 kVEdgecumbe 220 kVKaitimako 110 kVLoss ofsupplyTe KahaWaiotahiEdgecumbeKawerau 110 kV Kawerau –Horizon EnergyKinleith 110 kV Kinleith –PowercoMount Maunganui110 kVOwhata 110 kVRotorua 110 kVKinleith – CarterHolt HarveyMount MaunganuiOwhataRotorua 11 kVGenerationdisconnectionMatahina – G2Matahina – G1TransmissionissueTe Matai–KaitimakooverloadingOkere–Te MataioverloadingFurtherinformation10.9.210.9.310.9.410.9.4Tarukenga 110 kV Rotorua 11 kV 10.9.5Tauranga 110 kVTe Matai 110 kVWaiotahi 110 kVRotorua 33 kV 10.9.5Tarukenga 10.9.5Tauranga 11 kVTauranga 33 kVTe MataiTe KahaWaiotahiThe customers (Carter Holt Harvey, Horizon Energy, Norske Skog, Powerco, ToddEnergy, TrustPower, or Unison) have not requested a higher security level. Futureinvestment will be customer driven.If increased bus security is required, the options typically include bus reconfigurationand/or additional bus circuit breakers.10.9.2 Kaitimako 110 kV bus securityProject status/type:This issue is for information only2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 175

Chapter 10: Bay of Plenty RegionIssueThere are three 110 kV bus sections at Kaitimako. An outage of two of the bussections will result in transmission constraints, while an outage of one 110 kV busdisconnects the:220/110 kV Kaitimako–T4 interconnecting transformer110 kV Mount Maunganui–Kaitimako circuit, and110 kV Kaitimako–Te Matai circuit.This bus outage is the worst contingency affecting Kaitimako interconnectingtransformer capacity (see Section 10.8.2). In this case, the remaining interconnectingtransformer may overload from 2024.An outage of another 110 kV bus disconnects the:220/110 kV Kaitimako–T2 interconnecting transformer110 kV Kaitimako–Tauranga–1 circuit110/11 kV Kaitimako–T1 supply transformer.This bus outage results in a loss of supply at Kaitimako (see Section 10.8.5). Thisload could ordinarily be backfeed from Tauranga; however, the simultaneous loss ofthe Kaitimako–Tauranga–1 circuit will result in Tauranga being supplied from theKaitimako–Mount Maunganui–Tauranga–2 circuit only, which may restrict the amountof load that can be transferred to Tauranga.SolutionSee section:10.8.2 for the solution to the Kaitimako interconnecting transformer overload, thatneeds to be advanced to 2024 to manage a 110 kV bus outage, and10.8.3 for solutions to the capacity constraints into Tauranga. These constraintsneed to be resolved to allow Kaitimako load to be backfeed from Tauranga duringa Kaitimako 110 kV bus fault.10.9.3 Okere–Te Matai 110 kV transmission capacityProject status/type:This issue is for information onlyIssueThe outage of a Kaitimako 220 kV bus section disconnects a:220/110 kV Kaitimako interconnecting transformer, and220 kV Kaitimako–Tarukenga circuit.This issue causes an increase in the power flow from Okere to Te Matai and on toKaitimako. The Okere–Te Matai circuit may overload during periods of high loadtowards the end of the forecast period.The establishment of a new grid exit point at Papamoa (see Section 10.10.1) willincrease the loading on the Okere–Te Matai circuit.SolutionA third interconnecting transformer at Kaitimako will resolve the overloading issue forthe forecast period and beyond (see Section 10.8.2).10.9.4 Kinleith 110 kV bus securityProject status/type:This issue is for information only1762013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 10: Bay of Plenty RegionIssueThere are two 110 kV bus sections at Kinleith.An outage of one Kinleith 110 kV bus section disconnects the:110 kV Arapuni–Kinleith–1 and 2 circuits110/33 kV Kinleith–T4 supply transformer, and110/11 kV Kinleith–T3 supply transformer.This bus outage results in a loss of supply to Powerco and Carter Holt Harvey. If theArapuni bus split is open 95 there will be a loss of connection for the Mighty RiverPower generation connected to the Arapuni south bus. Depending on the generationat Kinleith, this outage may also result in low voltage on the remaining Kinleith 110 kVsupply buses.An outage of the remaining Kinleith 110 kV bus section disconnects the:110 kV Kinleith–Lichfield–1 and 2 circuits110/11 kV Kinleith–T1 supply transformer110/11 kV Kinleith–T2 supply transformer, and110/33/11 kV Kinleith–T5 supply transformer.This bus outage will result in a loss of supply at Kinleith. If the Arapuni bus split isopen 95 , the Mighty River Power generation connected to the Arapuni south bus andthe remaining Kinleith load will be operating as an island, which is unlikely to besustainable. A loss of connection for Mighty River Power and a loss of supply forPowerco and Carter Holt Harvey will be required before normal operation canresume.SolutionWe will discuss options with Powerco and Carter Holt Harvey to determine if it iseconomic to resolve the issue. The options will be considered in conjunction withaddressing the Kinleith 110/33 kV supply transformer security and capacity issue (seeSection 10.8.9) and the Kinleith 110/11 kV supply transformer supply security (seeSection 10.8.10).10.9.5 Rotorua area bus securityProject status/type:This issue is for information onlyIssueThere are two 110 kV bus sections at Tarukenga, one of which causes a securityissue for the three grid exit points supplying the Rotorua area. 96 In addition, theRotorua 110 kV bus is split and the supply transformers are not evenly distributedacross the split (see Section 10.8.14).An outage of one Tarukenga 110 kV bus section disconnects the:110 kV Rotorua–Tarukenga–1 circuit110 kV Tarukenga–Owhata–Te Matai circuit110 kV Lichfield–Tarukenga–2 circuit220/110 kV Tarukenga–T2 interconnecting transformer110/11 kV Tarukenga–T4 supply transformer.This bus outage will result in a loss of supply to the:9596See Chapter 9, Section 9.10.1 for more information about the Arapuni bus split.The three grid exit points supplying the Rotorua area are Tarukenga, Rotorua and Owhata.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 177

Chapter 10: Bay of Plenty RegionTarukenga 11 kV bus – as there is only one 110/11 kV supply transformer atTarukengaRotorua 11 kV bus – as the Rotorua 110 kV bus is split and both 110/11 kVtransformers at Rotorua are supplied via the Rotorua–Tarukenga–1 circuitPossibly the Rotorua 33 kV bus – as the supply transformer protection mayoperate to protect the 110/33 kV transformers from low voltage and high reverseflows.This loss of supply will leave Unison with only one point of supply at Owhata, whichwill be supplied via low capacity circuits from Te Matai and Edgecumbe. The voltageat Owhata is likely to limit the amount of load that Unison can backfeed through their11 kV network in Rotorua.SolutionThe Rotorua 110/11 kV supply transformers are scheduled for replacement within thenext five years with higher rated transformers (see Section 10.8.13). This will allowthe Rotorua 110 kV bus split to be reconfigured such that the two 110/11 kVreplacement transformers will be connected to each side of the split. With thisreconfiguration, an outage of the Tarukenga 110 kV bus section still leaves two of thefour supply transformers at Rotorua in service to supply the Rotorua 11 kV and 33 kVload, and there is a loss of supply to the Tarukenga 11 kV load only. It may not bepossible for Unison to transfer the entire Tarukenga load to Rotorua because two ofthe four supply transformers at Rotorua will be out of service.A second supply transformer at Tarukenga will prevent this loss of supply (seeSection 10.8.15).10.10 Other regional items of interest10.10.1 Papamoa grid exit pointWe are discussing with Powerco the establishment of a new grid exit point atPapamoa, connected to the 110 kV Kaitimako–Te Matai circuit. The new grid exitpoint is to cater for load growth, which is predominantly transferred from MountMaunganui (see also Section 10.8.3).10.10.2 Tarukenga interconnecting transformer replacementDue to their condition, the existing 200 MVA, 5% and 3.6% impedance Tarukengainterconnecting transformers are being replaced with two 150 MVA, 15% impedancetransformers.The capacity reduction is possible because the Western Bay of Plenty is transferredto 220 kV by the Kaitimako–Tarukenga circuits’ upgrade to 220 kV operation. Theincrease in impedance helps to reduce the through-transmission in the 110 kVtransmission network towards Kinleith (see Section 10.8.8).10.11 Bay of Plenty generation scenarios, proposals and opportunitiesThis section details relevant regional issues for selected generation proposals underinvestigation by developers and in the public domain, or other generationopportunities. The impact of committed generation projects on the grid backbone isdealt with separately in Chapter 6.The maximum generation that can be connected depends on several factors andusually falls within a range. Generation developers should consult with us at an earlystage of their investigations to discuss connection issues.1782013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 10: Bay of Plenty Region10.11.1 Impacts of the generation scenarios on the regional planThe generation scenarios (see Chapter 5) represent a series of possible futuregeneration outcomes. This section presents only those scenarios relevant to thisregion for the next 15 years.All generation scenarios anticipate new generation connected at the Kawerau 110 kVbus. See Section 10.8.1 for information about the existing constraints on 110 kVgeneration at Kawerau. See Section 10.11.2 for information about the impacts fromconnecting additional generation at Kawerau and the likely system developments torelieve the constraints.Generation scenarios 1, 2 and 3 anticipate new generation connected at theKaitimako 110 kV bus which decreases the loading on the Kaitimako interconnectingtransformers and the 110 kV Okere–Te Matai circuit, and could potentially defer thetransmission reinforcement involving Kaitimako and the 110 kV Okere–Te Mataicircuit.10.11.2 Generation connection at KawerauThere are a number of other future generation connection proposals at Kawerau (forinformation about the existing constraints on Kawerau 110 kV generation see Section10.8.1.), as the area has significant geothermal resources. If more thanapproximately 60 to 70 MW of additional generation connects directly or indirectly tothe Kawerau 110 kV bus, then the likely system developments will involve:replacing the Kawerau–T13 transformer (220/110 kV, 100 MVA) with a 250 MVAtransformersplitting the 110 kV Kawerau–Edgecumbe circuits, andreplacing the Edgecumbe 220/110 kV transformers and returning them to service.If there is little change in the generation connected to the Kawerau 110 kV bus, thenthe Edgecumbe 220/110 kV transformer will be decommissioned and not replaced.Connecting more than approximately 80 MW of generation at Kawerau (to the 110 kVor 220 kV busses), however, will also overload the 220 kV Edgecumbe–Kawerau orKawerau–Ohakuri circuits if the other circuit is out of service. Options to address theissue include either:automatically reducing or tripping generation if an overload occursincreasing the thermal rating of the circuitsa second 220 kV Edgecumbe–Kawerau circuitThe increased generation at Kawerau may increase the 11 kV supply bus anddistribution system fault levels sufficiently to exceed their fault-level capacities. Thisparticularly applies if new generation is connected directly to the supply bus, and mayalso be an issue if the generation is embedded within the distribution system. Thismay require the replacement of the existing supply transformers with higherimpedancetransformers and/or replacement of the existing 11 kV switchboard.We are currently in discussions with Horizon Energy regarding the 11 kV fault levelissue. The 11 kV switchboard and the 110/11 kV supply transformers at Kawerau aredue for replacement within the next 10 years (see Section 10.5). We will consideroptions to reduce the 11 kV fault level when the equipment is due for replacement.10.11.3 Generation connection to 220 kV Edgecumbe–Tarukenga circuitsThe area around the Edgecumbe–Tarukenga–1 and 2 circuits has a number ofpotential geothermal developments, with the potential for approximately 250 MW ofgeneration to connect to these circuits, depending on developments at Kawerau,before system upgrades are required. This capability decreases for outages of some220 kV circuits in the Bay of Plenty region.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 179

Chapter 10: Bay of Plenty Region10.11.4 Generation connection to the Okere–Te Matai circuitSome generation prospects exist close to the 110 kV Okere–Te Matai circuit, or closeto Okere on one of the other circuits passing through the area. These circuits canbecome highly loaded for some circuit outages when there is high demand. Underthese conditions, the generation may need to be reduced or switched off.1802013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 11: Central North Island Region11 Central North Island Regional Plan11.1 Regional overview11.2 Central North Island transmission system11.3 Central North Island demand11.4 Central North Island generation11.5 Central North Island significant maintenance work11.6 Future Central North Island projects and transmission configuration11.7 Changes since the 2012 Annual Planning Report11.8 Central North Island transmission capability11.9 Central North Island bus supply security11.10 Other regional items of interest11.11 Central North Island generation scenarios, proposals and opportunities11.1 Regional overviewThis chapter details the Central North Island regional transmission plan. We basethis regional plan on an assessment of available data, and welcome feedback toimprove its value to all stakeholders.Figure 11-1: Central North Island regionConstruction voltages shown. System as at March 2013.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 181

Chapter 11: Central North Island RegionThe Central North Island region includes a mix of grid exit points, from the large loadat Palmerston North and environs (supplied from Bunnythorpe and Linton) tonumerous medium to small loads. There is also a large industrial load at Tangiwai.We have assessed the Central North Island region’s transmission needs over thenext 15 years while considering longer-term development opportunities. Specifically,the transmission network needs to be flexible to respond to a range of future serviceand technology possibilities, taking into consideration:the existing transmission networkforecast demandforecast generationequipment replacement based on condition assessment, andpossible technological development.11.2 Central North Island transmission systemThis section highlights the state of the Central North Island regional transmissionnetwork. The existing transmission network is set out geographically in Figure 11-1and schematically in Figure 11-2.Figure 11-2: Central North Island transmission schematic33 kVOngarue110 kVWAIKATOHangatiki110 kV National ParkOhakuriWAIKATOWhakamaruTe Mihi33 kV220 kVPoihipiAratiatia220 kVWairakeiNgatamarikiNga AwaPurua220 kV11 kVOhaaki33 kV220 kVTARANAKIWanganuiBrunswickOhakune11 kV110 kV33 kV33 kVMataroa110 kVTangiwai11 kV55kV(NZR)220 kV220 kVTokaanu220 kVRangipo110 kVRedclyffe WhirinakiHAWKES BAYFernhillWaipawa33 kV220 kV11 kV33 kV110 kVMarton33 kV55 kV(NZR)110 kVBunnythorpe11 kVDannevirke110 kVTe ApitiTararua33 kVLintonMangahao110 kV33 kVHaywards WiltonWELLINGTONParaparaumu11 kV110 kVWoodvilleKEY33 kV220kV CIRCUIT110 kV110kV CIRCUITMangamaire33kV CIRCUITSUBSTATION BUSTRANSFORMERTEE POINTLOADMastertonCAPACITORWELLINGTONGENERATOR11.2.1 Transmission into the regionThe Central North Island region comprises 220 kV and 110 kV transmission circuitswith interconnecting transformers located at Bunnythorpe. The direction of powerflow through the region, north or south, is set by generation and loads outside theregion.All the 220 kV circuits form part of the grid backbone. The 110 kV transmissionnetwork is mainly supplied through the 220/110 kV interconnecting transformers atBunnythorpe, plus low capacity connections to other regions.1822013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 11: Central North Island RegionThe Central North Island region is a main corridor for 220 kV transmission circuitsthrough the North Island. The 220 kV transmission system connects Bunnythorpefrom the south, and Wairakei and Tokaanu from the North.There is an approved project to replace the 220 kV single circuit Wairakei–Poihipi–Whakamaru line connecting to the Waikato region with a double-circuit line.Most of the Central North Island’s generation capacity is connected to the 220 kV andis significantly in excess of the local demand. Surplus generation is exported over theNational Grid to other demand centres.11.2.2 Transmission within the regionThe 110 kV transmission system within the Central North Island region mainlyconsists of low-capacity circuits. The transmission system may impose constraintsunder certain operating conditions. Operational measures taken to ensure the110 kV circuits operate within their thermal capacity are:normally splitting the 110 kV system at:• Waipawa, for the Fernhill–Waipawa circuits, and• Mangahao and Paraparaumu, for the Mangahao–Paraparaumu circuits.managing generation output to avoid overloading of the 110 kV:• Bunnythorpe–Woodville circuits• circuits between Bunnythorpe and Arapuni (Waikato region), and• circuits between Bunnythorpe and Stratford (Taranaki region).Special protection schemes are also used to automatically reconfigure the grid orreduce generation to ensure the circuits operate within their thermal capacity.Schemes that are normally in service are at Tokaanu and Woodville.11.2.3 Longer-term development pathLonger-term development plans are being formed as part of the Lower North Islandinvestigation.The transmission development in this region will largely depend on the magnitudeand location of future generation, and the commissioning of new generation in theregion may bring forward the need for transmission investment. Possible upgradesinclude duplexing the existing 220 kV lines, and rebuilding some of the 110 kV linesfor 220 kV operation.11.3 Central North Island demandThe after diversity maximum demand (ADMD) for the Central North Island region isforecast to grow on average by 1.1% annually over the next 15 years, from 333 MWin 2013 to 390 MW by 2028. This is lower than the national average demand growthof 1.5% annually.Figure 11-3 shows a comparison of the 2012 and 2013 APR forecast 15-yearmaximum demand (after diversity 97 ) for the Central North Island region. Theforecasts are derived using historical data, and modified to account for customerinformation, where appropriate. The power factor at each grid exit point is alsoderived from historical data. See Chapter 4 for more information about demandforecasting.97The after diversity maximum demand (ADMD) for the region will be less than the sum of theindividual grid exit point peak demands, as it takes into account the fact that the peak demand doesnot occur simultaneously at all the grid exit points in the region.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 183

Chapter 11: Central North Island RegionFigure 11-3: Central North Island region after diversity maximum demand forecastTable 11-1 lists forecasts peak demand (prudent growth) for each grid exit point forthe forecast period, as required for the Grid Reliability Report.Table 11-1: Forecast annual peak demand (MW) at Central North Island grid exit pointsto 2028Grid exit pointBunnythorpe33 kVBunnythorpe –NZRPowerfactorNext 5 yearsPeak demand (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 20280.97 119 122 124 127 129 132 137 143 148 153 1590.79 8 8 8 8 8 8 8 8 8 8 8Dannevirke 0.97 15 16 16 16 16 16 17 17 18 18 19Linton 0.99 72 74 75 77 78 80 83 87 90 93 96Mangamaire 0.97 12 12 13 13 13 13 14 14 14 15 15Mangahao 0.95 44 44 45 46 46 47 48 50 51 53 54Marton 0.97 17 17 18 18 18 18 18 19 19 20 20Mataroa 0.98 8 8 8 9 9 9 9 9 10 10 10National Park 0.98 8 8 8 9 9 9 9 9 10 10 10Ohaaki 0.94 6 6 6 6 6 6 6 7 7 7 7Ohakune 1 0.98 11 9 10 10 10 10 11 11 12 12 13Ongarue 0.98 11 11 11 11 11 11 11 12 12 12 12Tokaanu 0.99 10 10 11 11 11 11 11 12 12 12 13Tangiwai 11 kV 1 0.98 44 47 47 48 48 49 50 51 52 53 54Tangiwai NZR 0.81 10 10 10 10 10 10 10 10 10 10 10Woodville 0.98 4 4 4 4 4 5 5 5 5 5 5Waipawa 0.96 22 23 23 23 24 24 25 26 26 27 28Wairakei 0.90 50 51 51 52 53 54 55 57 59 60 621. The customer advised a 2 MW load shift from Ohakune to the Tangiwai 11 kV bus planned for 2014.1842013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 11: Central North Island Region11.4 Central North Island generationThe Central North Island region’s generation capacity is 1,334 MW, increasing to1,448 MW after the commissioning of Te Mihi geothermal power plants. Thisgeneration contributes a significant portion of the total North Island generation andexceeds local demand. Surplus generation is exported over the National Grid toother demand centres.Table 11-2 lists the generation forecast for each grid injection point for the forecastperiod, as required for the Grid Reliability Report. This includes all known andcommitted generation stations including those embedded within the relevant locallines company’s network (Powerco, The Lines Company, Scanpower, Centralines, orElectra). 98Table 11-2: Forecast annual generation capacity (MW) at Central North Island gridinjection points to 2028 (including existing and committed generation)Grid injection point(location ifembedded)Next 5 yearsGeneration capacity (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Aratiatia 78 78 78 78 78 78 78 78 78 78 78Bunnythorpe (TararuaWind Stage 2)Linton (Tararua WindStage 1)36 36 36 36 36 36 36 36 36 36 3632 32 32 32 32 32 32 32 32 32 32Linton (Totara Road) 1 1 1 1 1 1 1 1 1 1 1Mangahao 42 42 42 42 42 42 42 42 42 42 42Nga Awa Purua 140 140 140 140 140 140 140 140 140 140 140Nga Awa Purua –Ngatamariki82 82 82 82 82 82 82 82 82 82 82Ohaaki 46 46 46 46 46 46 46 46 46 46 46Ongarue (Mokauiti,Kuratau and WairereFalls)13 13 13 13 13 13 13 13 13 13 13Poihipi 51 51 51 51 51 51 51 51 51 51 51Rangipo 120 120 120 120 120 120 120 120 120 120 120Tararua Wind Central– Tararua Stage 3Tararua Wind Central(Te Rere Hau)93 93 93 93 93 93 93 93 93 93 9349 49 49 49 49 49 49 49 49 49 49Te Mihi 166 166 166 166 166 166 166 166 166 166 166Tokaanu 240 240 240 240 240 240 240 240 240 240 240Wairakei 161 109 109 109 109 109 109 109 109 109 109Wairakei (Hinemaiaia) 7 7 7 7 7 7 7 7 7 7 7Wairakei (Rotokawa) 35 35 35 35 35 35 35 35 35 35 35Wairakei (Te Huka) 23 23 23 23 23 23 23 23 23 23 23Woodville – Te Apiti 90 90 90 90 90 90 90 90 90 90 9011.5 Central North Island significant maintenance workOur capital project and maintenance works are integrated to enable system issues tobe resolved if possible when assets are replaced or refurbished. Table 11-3 lists the98Only generators with a capacity greater than 1 MW are listed. Generation capacity is rounded to thenearest megawatt.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 185

Chapter 11: Central North Island Regionsignificant maintenance-related work 99 proposed for the Central North Island regionfor the next 15 years that may significantly impact related system issues or connectedparties.Table 11-3: Proposed significant maintenance workDescriptionTentativeyearRelated system issuesBunnythorpe interconnectingtransformers expected end-of-lifeBunnythorpe 33 kV outdoor toindoor conversion2014-2016 Options for the replacement transformers are underinvestigation. See Section 11.8.1 for moreinformation.2013-2014 The forecast load at Bunnythorpe will exceed thetransformers’ capacity from 2013. See Section11.8.4 for more information.Linton 33 kV outdoor to indoorconversion andsupply transformer replacementMangahao supply transformersexpected end-of-life, and33 kV outdoor to indoor conversion2017-20192013-20142020-20222014-2016The forecast load at Linton will exceed thetransformers’ capacity from 2018. See Section11.8.5 for more information.Managing Mangahao generation can reduce thetransformer’s loading. See Section 11.8.6 for moreinformation.Marton supply transformersexpected end-of-lifeMataroa supply transformerexpected end-of-lifeNational Park supply transformerexpected end-of-lifeOhakune supply transformerexpected end-of-life2023-2026 The forecast load will exceed the transformers’capacity from 2023. See Section 11.8.8 for moreinformation.2017-2019 No n-1 security at Mataroa. See Section 11.8.10for more information.2013-2015 No n-1 security at National Park. See Section11.8.11 for more information.2013-2015 The discussion on options to increase the supplysecurity and transformer capacity is underway. SeeSection 11.8.12 for more information.Ongarue 33 kV supply transformerexpected end-of-life, andOngarue 33 kV outdoor to indoorconversion2025-20262017-2019No n-1 security at Ongarue. See Section 11.8.13for more information.Wairakei supply transformersexpected end-of-life2024-2026 No system issues are identified within the forecastperiod.11.6 Future Central North Island projects and transmission configurationTable 11-4 lists projects to be carried out in the Central North Island region within thenext 15 years.Figure 11-4 shows the possible configuration of Central North Island transmission in2028, with new assets, upgraded assets, and assets undergoing significantmaintenance within the forecast period.Table 11-4: Projects in the Central North Island region up to 2028Circuits/site Projects StatusBunnythorpeReplace existing interconnecting transformers with two150 MVA units.Convert 33 kV outdoor switchgear to an indoor switchboard.Rearrange the 220 kV bus configuration.PossibleProposedPossibleBunnythorpe–Haywards Bunnythorpe–Haywards–A and B reconductoring. PreferredBunnythorpe–Mataroa Install a series reactor. PossibleBunnythorpe–WoodvilleUpgrade the special protection scheme or reconductor theBunnythorpe–Woodville circuit or convert the circuit’soperating voltage.Possible99This may include replacement of the asset due to its condition assessment.1862013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 11: Central North Island RegionCircuits/site Projects StatusLintonMangahaoMartonConvert the 33 kV outdoor switchgear to an indoorswitchboard.Replace the supply transformer.Replace supply transformers.Convert the 33 kV outdoor switchgear to an indoorswitchboard.Resolve the supply transformers’ metering and protectionlimits.Replace the supply transformers.ProposedProposedProposedProposedPossibleProposedMataroa Replace the supply transformer. ProposedNational Park Replace the supply transformer. ProposedOhakune Replace the supply transformer with a higher rated unit. PossibleOngarueReplace the supply transformer.Convert the 33 kV outdoor switchgear to an indoorswitchboard.ProposedProposedTangiwai Replace the 11 kV switchgear. ProposedHaywards–Bunnythorpe–Tokaanu–WhakamaruWaipawaIncrease the transmission circuit capacities.Resolve the supply transformers’ metering and protectionlimits.PossiblePossibleWairakei Replace the supply transformers. ProposedWairakei–WhakamaruBuild a new 220 kV double circuit transmission line anddismantle the existing 220 kV Wairakei–Whakamaru–B singlecircuit transmission line.CommittedWoodville Resolve the supply transformers’ metering equipment limit. PossibleFigure 11-4: Possible Central North Island transmission configuration in 2028TARANAKIWanganui33 kVOngarue110 kVBrunswickOhakuneWAIKATOHangatiki11 kV110 kVBunnythorpe110 kV National Park33 kV33 kVMataroa110 kV220 kVOhakuriWAIKATOWhakamaruTe MihiTangiwai11 kV55kV(NZR)(1)220 kV220 kV33 kVTokaanuPoihipi220 kVWairakei220 kVAratiatiaNgatamariki220 kVRangipoNga AwaPurua110 kV*11 kV11 kV220 kVOhaaki33 kV220 kVWhirinakiRedclyffeHAWKES BAY*FernhillWaipawa33 kV33 kVMarton**110 kV55 kV(NZR)33 kV110 kV11 kVDannevirke110 kVTe Apiti(1) The transmission backbone sectionidentifies two possible developmentpaths for the lower North Island:- upgrade the existing lines, and- new transmission lineAlthough this diagram shows upgradingof the existing lines, it is not intended toindicate a preference as both optionsare still being investigated.(1)Haywards WiltonWELLINGTONTararua33 kVLintonMangahao110 kV33 kVParaparaumuMastertonWELLINGTON33 kV110 kVMangamaire* *11 kV110 kVWoodvilleKEYNEW ASSETSUPGRADED ASSETSASSETS SCHEDULEDFOR REPLACEMENTMINOR UPGRADE*2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 187

Chapter 11: Central North Island Region11.7 Changes since the 2012 Annual Planning ReportTable 11-5 lists the specific issues that are either new or no longer relevant within theforecast period when compared to last year's report.Table 11-5: Changes since 2012IssuesMarton low voltageMataroa and National Park low voltageWaipawa low voltageWoodville supply transformer capacityChangeNew issue.New issue.New issue.New issue.11.8 Central North Island transmission capabilityTable 11-6 summarises issues involving the Central North Island region for the next15 years. For more information about a particular issue, refer to the listed sectionnumber.Table 11-6: Central North Island region transmission issuesSectionnumberIssueRegional11.8.1 Bunnythorpe interconnecting transformer capacity11.8.2 Bunnythorpe–Mataroa 110 kV transmission capacity11.8.3 Bunnythorpe–Woodville 110 kV transmission capacitySite by grid exit point11.8.4 Bunnythorpe supply transformer capacity11.8.5 Linton supply transformer capacity11.8.6 Mangahao supply transformer capacity11.8.7 Marton low voltage11.8.8 Marton supply transformer capacity11.8.9 Mataroa and National Park low voltage11.8.10 Mataroa supply transformer security11.8.11 National Park transmission and supply transformer security11.8.12 Ohakune supply security and capacity11.8.13 Ongarue supply transformer security11.8.14 Tokaanu supply transformer security11.8.15 Waipawa low voltage11.8.16 Waipawa supply transformer capacity and security11.8.17 Woodville supply transformer capacityBus security11.9.1 Transmission bus security11.9.2 Central North Island region low voltage11.8.1 Bunnythorpe interconnecting transformer capacityProject reference: BPE-POW_TFR-EHMT-01Project status/type: Possible, Base CapexIndicative timing: 2014-20161882013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 11: Central North Island RegionIndicative cost band:BIssueThere are three interconnecting transformers at Bunnythorpe, each rated at 50 MVA,providing:a total nominal installed capacity of 150 MVA, andn-1 capacity of 116/125 MVA (summer/winter).Loading on the Bunnythorpe interconnecting transformers may exceed their n-1capacity for high Central North Island and Wellington loads, coupled with low localgeneration in Wellington.SolutionThis issue can be managed using operational measures by constraining:Mangahao generation onHVDC transfer to high north flow, orCentral North Island regional load down.The Bunnythorpe interconnecting transformers have an expected end-of-life withinthe forecast period. One option is to replace these with two 150 MVA transformers.11.8.2 Bunnythorpe–Mataroa 110 kV transmission capacityProject reference:Project status/type:Indicative timing:Indicative cost band:BPE_MTR–TRAN-EHMT-01Possible, Base Capex. This project is part of the lower North Islandtransmission capacity investigation.To be advisedAIssueThe Bunnythorpe–Mataroa single circuit is rated at 57/70 MVA (summer/winter). Thiscircuit can overload for some generation dispatch patterns such as high HVDC northpower flow, high wind generation in the lower North Island, low Arapuni generation,and an outage of a 220 kV Huntly–Stratford, Stratford–Taumarunui, Bunnythorpe–Tokaanu, Tokaanu–Whakamaru or Rangipo–Wairakei circuit.SolutionThis issue can be managed operationally by limiting the HVDC north power flow,and/or increasing Arapuni generation, and/or opening the Arapuni–Ongarue circuit(leaving Ongarue, National Park, Ohakune, and Mataroa on n security).A short-term option is automatically opening the circuit when it overloads.Longer-term options are to reduce the power flow along the Bunnythorpe–Mataroacircuit by installing a series reactor, or increase the circuit’s rating by reconductoring.11.8.3 Bunnythorpe–Woodville 110 kV transmission capacityProject reference:Project status/type:Indicative timing:Indicative cost band:BPE_WDV-TRAN-EHMT-01Possible, Base Capex. This project is part of the lower North Islandtransmission capacity investigation,Special protection scheme upgrade: to be advisedCircuit reconductoring or convert circuit’s operating voltage: 2015-2020Special protection scheme upgrade: ACircuit reconductoring or convert circuit’s operating voltage: to be advised2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 189

Chapter 11: Central North Island RegionIssueThe Bunnythorpe–Woodville circuits are rated at 57/70 MVA (summer/winter). Theloading on these circuits depends on the HVDC transfer direction and level, Te Apitigeneration levels and the load in Wellington, Wairarapa, Dannevirke, and Waipawa.The circuits may overload for an outage of:one circuit overloading the remaining circuit during high south flow, orsome 220 kV circuits between Bunnythorpe and Haywards, overloading theBunnythorpe–Woodville circuits.A special protection scheme at Woodville will prevent overloading for a Bunnythorpe–Woodville outage by:detecting an outage of a Bunnythorpe–Woodville 110 kV circuit causingoverloading of the remaining Bunnythorpe–Woodville circuitopening the Mangamaire–Woodville circuit at Woodville to prevent throughtransmission, andremoving Te Apiti generation if the overload on Bunnythorpe–Woodville remains.SolutionThe existing special protection scheme will resolve the issue caused by an outage ofa Bunnythorpe–Woodville 110 kV circuit.The overloading for a 220 kV circuit outage between Bunnythorpe and Haywards canbe managed operationally by:restricting HVDC south power flow, and/orrestricting Te Apiti generation, oropening either the 110 kV Mangamaire–Woodville circuit or the Mangamaire–Masterton circuit, leaving Mangamaire on n security.Longer-term options, which do not require operational measures include:upgrading the existing special protection scheme to operate for a 220 kV circuitoutage (also requiring a bus protection upgrade at Woodville)reconductoring the 110 kV Bunnythorpe–Woodville circuits with a higher ratedconductor, orconverting the Bunnythorpe–Woodville circuits to 220 kV operation.11.8.4 Bunnythorpe supply transformer capacityProject status/type:This issue is for information onlyIssueTwo 220/33 kV transformers supply Bunnythorpe’s load, providing:a total nominal installed capacity of 166 MVA, andn-1 capacity of 100/100 MVA 100 (summer/winter).The peak load at Bunnythorpe is forecast to exceed the transformers’ n-1 wintercapacity by approximately 14 MW in 2013, increasing to approximately 53 MW in2028 (see Table 11-7). Tararua wind generation (Stage 2) is connected to theBunnythorpe 33 kV bus, and the forecast assumes minimum generation of 7 MWcoincident with the peak load.100 The transformers’ capacity is limited by cable ratings; with this limit resolved, the n-1 capacity will be101/106 MVA (summer/winter).1902013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 11: Central North Island RegionTable 11-7: Bunnythorpe supply transformer overload forecastCircuit/gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Bunnythorpe 0.97 14 16 19 21 24 26 31 37 42 48 53SolutionIncreasing the transformers’ cable limit will not solve the overload issue. In the shortterm, Powerco can transfer load within the distribution system to Linton following acontingency. We are discussing longer-term options with Powerco, which include:load transfer to Linton (see Section 11.8.5), anda third supply transformer at Bunnythorpe.We have also discussed with Powerco conversion of the Bunnythorpe 33 kV outdoorswitchyard to an indoor switchboard. Future investment will be customer driven.11.8.5 Linton supply transformer capacityProject status/type:This issue is for information onlyIssueTwo 220/33 kV transformers (rated at 60 MVA and 100 MVA) supply Linton’s load,providing:a total nominal installed capacity of 160 MVA, andn-1 capacity of 77/81 MVA (summer/winter).The peak load at Linton is forecast to exceed the transformers’ n-1 winter capacity byapproximately 1 MW in 2020, increasing to approximately 14 MW in 2028 (see Table11-8). Tararua wind generation (Stage 1) is connected to the Linton 33 kV bus, andthe forecast assumes minimum generation of 7 MW coincident with the peak load.Table 11-8: Linton supply transformer overload forecastCircuit/gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Linton 0.99 0 0 0 0 0 0 1 4 7 11 14SolutionLinton normally has two 100 MVA transformers, but one failed and has beentemporarily replaced with a 60 MVA transformer. We will discuss options withPowerco, which include:retaining the 60 MVA transformer permanently, and using operational measuresto manage the overload, andreplacing the 60 MVA transformer if load is transferred from Bunnythorpe (seeSection 11.8.4).We will also discuss with Powerco converting the Linton 33 kV outdoor switchyard toan indoor switchboard. Future investment will be customer driven.11.8.6 Mangahao supply transformer capacityProject status/type:This issue is for information only2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 191

Chapter 11: Central North Island RegionIssueTwo 110/33 kV transformers supply Mangahao’s load, providing:a total nominal installed capacity of 60 MVA, andn-1 capacity of 37/39 MVA (summer/winter).The peak load at Mangahao is forecast to exceed the transformers’ n-1 wintercapacity by approximately 9 MW in 2013, increasing to approximately 20 MW in 2028(see Table 11-9). The Mangahao generation station is connected to the 33 kV bus,and the forecast assumes that Mangahao is not generating during peak load periods.Table 11-9: Mangahao supply transformer overload forecastCircuit/gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Mangahao 0.95 9 10 11 11 12 13 14 16 17 19 20SolutionIf Mangahao generates at 20 MW or more, this issue could be delayed beyond theforecast period. The supply transformer overload is managed operationally asMangahao generation is usually available during peak load periods.We will also convert the Mangahao 33 kV outdoor switchgear to an indoorswitchboard within the next five years. In addition, both Mangahao supplytransformers will approach their expected end-of-life within the next 5-10 years. Wewill discuss with Electra and Todd Energy the timing and options for these works.Future investment will be customer driven.11.8.7 Marton low voltageProject status/type:This issue is for information onlyIssueThe supply bus voltage at Marton is forecast to fall below 0.95 pu following an outageof a:Bunnythorpe–Marton–Wanganui circuit, orBunnythorpe 110 kV bus section.Marton has supply transformers with off-load tap changers.SolutionThis issue can be managed operationally by managing Taranaki generation andHVDC transfer during peak load periods.11.8.8 Marton supply transformer capacityProject reference: MTN-POW_TFR-EHMT-01Project status/type: Possible, Base CapexIndicative timing: 2023Indicative cost band: ATwo 110/33 kV transformers (rated at 20 MVA and 30 MVA) supply Marton’s33 kV load, providing:a total nominal installed capacity of 50 MVA, and1922013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 11: Central North Island Regionn-1 capacity of 20/20 MVA 101 (summer/winter).The peak load at Marton is forecast to exceed the transformers’ n-1 winter capacityby approximately 1 MW from 2023 (see Table 11-10).Table 11-10: Marton supply transformer overload forecastCircuit/gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Marton 0.97 0 0 0 0 0 0 0 0 1 1 1SolutionResolving the metering equipment limit will solve the transformers’ n-1 capacity issuewithin the forecast period.In addition, both Marton supply transformers will approach their expected end-of-lifewithin the forecast period. We will discuss with Powerco the rating and timing for thereplacement transformers. Future investment will be customer driven.11.8.9 Mataroa and National Park low voltageProject status/type:This issue is for information onlyIssueSupply bus voltages at Mataroa and National Park are forecast to fall below 0.95 pufollowing an outage of a:Bunnythorpe–Mataroa–1 circuit, orBunnythorpe 110 kV bus section.Both grid exit points have supply transformers with off-load tap changers.SolutionThis issue can be managed operationally by constraining on generation at Arapuni.11.8.10 Mataroa supply transformer securityProject status/type:This issue is for information onlyIssueThe load at Mataroa is supplied by a single 110/33 kV, 30 MVA supply transformercomprising three single-phase units, resulting in no n-1 security.SolutionA spare on-site unit may be able to provide backup following a unit failure, withreplacement taking 8-14 hours. However, this is an uncontracted spare, which maynot be available when needed. Powerco considers the lack of n-1 security can beresolved operationally for the forecast period.The Mataroa supply transformer is approaching its expected end-of-life within thenext five years. We will discuss with Powerco the future supply options at Mataroa.Future investment will be customer driven.101 The transformers’ capacity is limited by metering equipment, followed by an LV bushing limit (24MWA) and a protection limit (25 MVA); with these limits resolved, the n-1 capacity will be 26/27MVA (summer/winter).2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 193

Chapter 11: Central North Island Region11.8.11 National Park transmission and supply transformer securityProject status/type:This issue is for information onlyIssueThe load at National Park is supplied through a single 110 kV transmission circuit anda single 110/33 kV, 10 MVA supply transformer comprising three single-phase units,resulting in no n-1 security.SolutionA spare on-site unit provides backup following a unit failure, with replacement taking8-14 hours. Some load can also be backfeed through The Lines Companydistribution system and they consider the lack of n-1 security can be resolvedoperationally for the forecast period.The National Park supply transformer is also approaching its expected end-of-lifewithin the next five years. We are discussing future supply options with The LinesCompany to increase supply security. Future investment will be customer driven.11.8.12 Ohakune supply security and capacityProject reference:Project status/type:Indicative timing:Indicative cost band:OKN-POW_TFR-DEV-01Possible, customer-specific2016, subject to agreement with The Lines CompanyAIssueThe load at Ohakune is supplied by a single 110/11 kV, 10 MVA supply transformercomprising three single-phase units (currently with one on-site spare). This meansOhakune has no n-1 security, although the spare on-site unit provides backupfollowing a unit failure (with replacement taking 8-14 hours).The peak load at Ohakune is forecast to exceed the transformer’s continuouscapacity by approximately 2 MW in 2013. The overload will decrease when load isshifted to Tangiwai, increasing again to approximately 3 MW in 2028 (see Table11-11).Table 11-11: Ohakune supply transformer overload forecastCircuit/gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Ohakune 0.98 2 0 0 1 1 1 2 2 2 3 3SolutionThe local lines companies, Powerco and The Lines Company, have not requested ahigher security level at Ohakune. We are discussing long-term options, whichinclude:using operational measures to constrain load within the transformer’s ratingthe customer using diesel generation to remain within the transformer’s rating,andinstalling a higher rated transformer.In addition, the Ohakune supply transformer is approaching its expected end-of-lifewithin the next five years. We will discuss the timing for the replacement transformerwith the local lines companies. Future investment will be customer driven.1942013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 11: Central North Island Region11.8.13 Ongarue supply transformer securityProject status/type:This issue is for information onlyIssueThe load at Ongarue is supplied by a single 110/33 kV, 20 MVA supply transformercomprising three single-phase units, resulting in no n-1 security.SolutionMost load can be backfed through The Lines Company’s distribution system. TheLines Company considers the lack of n-1 security can be resolved operationally forthe forecast period.We will also convert the Ongarue 33 kV outdoor switchgear to an indoor switchboardwithin the next 5-10 years. Also the Ongarue supply transformer will approach itsexpected end-of-life towards the end of the forecast period. We will discuss with TheLines Company the timing of the switchgear conversion work and transformerreplacement options. Future investment will be customer driven.11.8.14 Tokaanu supply transformer securityProject status/type:This issue is for information onlyIssueThe load at Tokaanu is supplied by a single 220/33 kV, 20 MVA supply transformer,with a second transformer that can be manually switched into service when required.This means that Tokaanu does not have seamless n-1 security. Tripping the on-loadtransformer will result in a loss of supply until the other transformer is manuallyswitched into service.SolutionThe Lines Company considers the lack of n-1 security can be resolved operationallyfor the forecast period. Future investment will be customer driven.11.8.15 Waipawa low voltageProject status/type:This issue is for information onlyIssueWaipawa is normally supplied at 110 kV from Bunnythorpe via Dannevirke. Thesupply bus voltages at Waipawa are forecast to fall below 0.95 pu following an outageof a Waipawa–Dannevirke–Woodville circuit. In addition, this outage causes a stepvoltage change greater than 5%.The Waipawa supply transformers and Bunnythorpe interconnecting transformershave off-load tap changers, so these transformers cannot be used to manage thevoltage.SolutionReplacing the Bunnythorpe interconnecting transformer with 150 MVA transformerswith on-load tap changers (see Section11.8.1) will improve, but not eliminate the lowvoltage issue.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 195

Chapter 11: Central North Island RegionThe Waipawa 110 kV disconnectors have recently been replaced with motoriseddisconnectors. Therefore, if low voltage occurs, the load can be quickly transferredfrom the Central North Island to the Hawkes Bay region.In the longer-term, the 110/33 kV supply transformers can be replaced withtransformers that have on-load tap changers. Future investment will be customerdriven.11.8.16 Waipawa supply transformer capacity and securityProject reference: WPW-POW_TFR-EHMT-01Project status/type: Possible, Base CapexIndicative timing: 2017Indicative cost band: AIssueWaipawa has loads at 33 kV and 11 kV. Two 110/33 kV transformers (rated at20 MVA and 30 MVA) supply Waipawa’s load, providing:a total nominal installed capacity of 50 MVA, andn-1 capacity of 26/26 MVA 102 (summer/winter).The peak load at Waipawa is forecast to exceed the transformers’ n-1 winter capacityby approximately 1 MW in 2017, increasing to approximately 5 MW in 2028 (seeTable 11-12).Table 11-12: Waipawa supply transformer overload forecastCircuit/gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Waipawa 0.96 0 0 0 0 1 1 2 2 3 4 5A single 33/11 kV, 10 MVA transformer supplies Waipawa’s 11 kV load, resulting inno n-1 security.SolutionResolving the 110/33 kV transformers’ metering and protection limits will delay thetransformers’ capacity issue for a few years. We will discuss with Centralines thefuture supply options for Waipawa.Centralines considers the lack of n-1 security for Waipawa’s 11 kV load can beresolved operationally within the forecast period. Future investment will be customerdriven.11.8.17 Woodville supply transformer capacityProject reference: WDV-POW_TFR-EHMT-01Project status/type: Possible, Base CapexIndicative timing: 2023Indicative cost band: ATwo 110/11 kV transformers supply Woodville’s 11 kV load, providing:a total nominal installed capacity of 20 MVA, andn-1 capacity of 5/5 MVA 103 (summer/winter).102 The transformers’ capacity is limited by a metering limit, followed by protection and transformerbushing (27 MVA) limits; with these limits resolved, the n-1 capacity will be 29/30 MVA(summer/winter).1962013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 11: Central North Island RegionThe peak load at Woodville is forecast to exceed the transformers’ n-1 winter capacityby approximately 1 MW from 2023 (see Table 11-13).Table 11-13: Woodville supply transformer overload forecastCircuit/gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Woodville 0.98 0 0 0 0 0 0 0 0 1 1 1SolutionResolving the metering equipment limit will solve the transformers’ n-1 capacity issuewithin the forecast period.11.9 Central North Island bus supply securityThe 2013 APR has been expanded to include issues arising from the outage of asingle bus section rated at 50 kV and above for the next 15 years.Bus outages disconnect more than one power system component (for example, othercircuits, transformers, reactive support or generators). Therefore, bus outages maycause greater issues than a single circuit or transformer outage (although the risk of abus fault is low, being less common than a circuit or transformer outage).11.9.1 Transmission bus securityTable 11-14 lists bus outages that cause voltage issues or a total loss of supply.Generators are included only if a bus outage disconnects the whole generationstation or causes a widespread system impact. Supply bus outages, typically 11 kVand 33 kV, are not listed.Table 11-14: Transmission bus outagesTransmissionbus outageAratiatia 220 kVBunnythorpe 110 kVBunnythorpe 220 kVMangamaire 110 kVMataroa 110 kVNga Awa Purua220 kVOhakune 110 kVOngarue 110 kVRangipo 220 kVTokaanu 220 kVLoss ofsupplyMangamaireMataroaOhakuneOngarueTokaanuGenerationdisconnectionAratiatiaTransmissionissueBunnythorpe–WoodvilleoverloadingBunnythorpe–WoodvilleoverloadingFurtherinformationSee note 1See Note 2Regional low voltage 11.9.2Nga Awa Purua See note 3Ngatamariki See note 3RangipoWanganui 110 kV Marton See note 4Woodville 110 kV Dannevirke See note 5103 The transformers’ capacity is limited by metering equipment; with this limit resolved, the n-1 capacitywill be 13/14 MVA (summer/winter).2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 197

Chapter 11: Central North Island RegionTransmissionbus outageLoss ofsupplyGenerationdisconnectionTransmissionissueFurtherinformationWaipawa See note 5WoodvilleTe ApitiWairakei 220 kV Aratiatia See note 6Wairakei See note 71. An outage of a Bunnythorpe 110 kV bus section will also disconnect a Bunnythorpe–Woodville circuit,which may overload the remaining circuit. A special protection scheme at Woodville will operate toremove the overload (see Section 11.8.3). The bus outage may also cause the supply bus voltage atWaipawa to fall below 0.95 pu. See Section 11.8.15 for options to address the low voltage atWaipawa.2. An outage of a Bunnythorpe 220 kV bus section disconnects circuits to Haywards. This may causeboth Bunnythorpe–Woodville circuits to overload, which is not prevented by the special protectionscheme at Woodville (see Section 11.8.3).3. Nga Awa Purua has a single bus, with a single connection to Ngatamariki. A bus outage at Nga AwaPurua will disconnect all generation at Nga Awa Purua and Ngatamariki.4. Marton is supplied from the Bunnythorpe–Marton–Wanganui circuits. Because there is no bus zoneprotection at Wanganui (in the Taranaki region), a fault on the Wanganui 110 kV bus will disconnectboth circuits, causing a loss of supply at Marton.5. Dannevirke and Waipawa are normally supplied via the Waipawa–Dannevirke–Woodville circuits as aspur from Woodville. An outage of the Woodville 110 kV bus disconnects both circuits, causing a lossof supply.6. Aratiatia is connected to Wairakei through a single circuit. A Wairakei bus outage that disconnects thiscircuit disconnects the Aratiatia generation station.7. Following the commissioning of the Wairakei–Whakamaru–C line. A Wairakei bus outage willdisconnect the Wairakei generation station.The customers (Mighty River Power, Scanpower, Powerco, The Lines Company, orCentralines) have not requested a higher security level. If increased bus security isrequired, the options typically include bus reconfiguration and/or additional bus circuitbreakers. Future investment is likely to be customer driven.11.9.2 Central North Island region low voltageProject reference:Project status/type:Indicative timing:Indicative cost band:BPE_BUSC–EHMT-01Possible, Base CapexTo be advisedTo be advisedIssueMany of the supply transformers and the Bunnythorpe interconnecting transformershave off-load tap changers, so cannot be used to manage voltage. During periods ofhigh Wellington load and low local generation, the supply bus voltages in the regionare forecast to fall below 0.95 pu following an outage of the Bunnythorpe 220 kV bussection that disconnects the:220 kV Bunnythorpe–Brunswick–1 circuit220 kV Bunnythorpe–Haywards–2 circuit220 kV Bunnythorpe–Linton–1 circuit220 kV Bunnythorpe–Tokaanu–2 circuit220/110 kV Bunnythorpe–T3 interconnecting transformer, and220/33 kV Bunnythorpe–T10 supply transformer.The low supply bus voltages may occur at Waipawa, Marton and/or Wanganui (in theTaranaki region), depending on system conditions.In addition, the step voltage change for this outage will exceed 5% at some grid exitpoints.1982013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 11: Central North Island RegionSolutionReplacing the Bunnythorpe interconnecting transformer with 150 MVA transformerswith on-load tap changers (see Section 11.8.1) will improve the supply bus voltages,but will also lower 220 kV voltages, which in turn restricts power transfer betweenBunnythorpe and Wellington.Rearranging the bus connections at Bunnythorpe and/or installing a fourth 220 kVbus coupler will provide n-1 bus security.11.10 Other regional items of interestThere are no other items of interest identified to date beyond those inSection 11.8 and Section 11.9. See Section 11.11 for specific generation scenarios,proposals and opportunities relevant to this region.11.11 Central North Island generation scenarios, proposals and opportunitiesThis section details relevant regional issues for selected generation proposals underinvestigation by developers and in the public domain, or other generationopportunities. The impact of committed generation projects on the grid backbone isdealt with separately in Chapter 6.The maximum generation that can be connected depends on several factors andusually falls within a range. Generation developers should consult with us at an earlystage of their investigations to discuss connection issues.11.11.1 Impact of generation scenarios on regional planThe generation scenarios (see Chapter 5) represent a series of possible futuregeneration outcomes. This section presents only those scenarios relevant to thisregion for the next 15 years.All of the generation scenarios anticipate substantial new geothermal generation inthe next 5-10 years in the Wairakei ring area. See Section 11.11.2 for informationabout the opportunities for generation in the area.Generation scenarios 1 to 4 anticipate substantial new wind generation connected ator near Linton. See section 11.11.4 for information about the opportunities forgeneration in the area.Generation scenarios 1, 2 and 4 anticipate renewable generation connected in thecentral plateau region between Tangiwai and Rangipo. See Chapter 6, Section 6.4.5for information about the opportunities for generation in the area.None of the generation scenarios anticipates generation connected to the CentralNorth Island 110 kV network but do anticipate generation in the 110 kV networks ofthe Wellington, Waikato and Taranaki regions. This generation may reduce theloading on the Bunnythorpe interconnecting transformers depending on the load andgeneration patterns.11.11.2 Additional geothermal generationThere are a number of recently or soon-to-be commissioned geothermal generationdevelopments in the region connecting into or near the Wairakei Ring. We arereplacing the existing Wairakei–Poihipi–Whakamaru–1 circuit with a new overheaddouble-circuit line between Wairakei and Whakamaru. This will increase the powerflow capacity through the Wairakei Ring (see Chapter 6, Section 6.4.3, for moreinformation).2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 199

Chapter 11: Central North Island Region11.11.3 Tauhara geothermal stationTauhara will connect into a 220 kV circuit from Wairakei to the Hawkes Bay region.Maungaharuru wind generation station, and Hawke’s Bay wind stations) in theHawkes Bay region will also connect to the same circuit (see Chapter 13, Section13.11.3), which has enough capacity for the two generation connections.There is potential for further geothermal generation development in the Tauhara area,as well as further wind and hydro generation development in the Hawkes Bay area.This additional potential generation will require Tauhara to be connected to both220 kV circuits from Wairakei to the Hawkes Bay region, and a thermal upgrade ofthe circuits between Wairakei and Tauhara.11.11.4 Additional wind generation connection to the 220 kV circuits betweenBunnythorpe and WellingtonThere are several investigations and proposals for wind station connections to the220 kV double-circuit line between Bunnythorpe, Linton, and Wellington, which couldoccur at Linton or at new connection points along the line.This is a high-capacity line and the effect of some additional generation ontransmission capacity between Bunnythorpe and Wellington will be a small netpercentage increase or decrease in transfer capacity, depending on the direction ofpower flow. A total of approximately 830 MW maximum generation injection into boththe Bunnythorpe–Tararua Wind Central–Linton and Bunnythorpe–Linton 220 kVcircuits will not cause system issues.The wind generation resource under investigation is so large, however, that it isunlikely to be economical to connect it all to these 220 kV circuits because oftransmission constraints.11.11.5 Additional generation connected to the 110 kV busesThere are several possible wind generation sites close to the 110 kV transmissioncircuits that run from Mangamaire to Woodville, Dannevirke, and Waipawa. Thecapacity on the existing 110 kV Masterton–Mangamaire–Woodville andBunnythorpe–Woodville circuits enables the connection of approximately 80 MW ofadditional generation, depending on where the generation is connected. Higherlevels of generation may require occasional generation constraints or incrementaland/or major system upgrades (including new lines).11.11.6 Puketoi rangesThere are several prospective wind generation sites in the Puketoi ranges, with acombined capacity of many hundreds of megawatts. The closest network is the 110kV transmission network (see Section 11.11.5), which is not nearby. If windgeneration is developed in this area, then a single new transmission line may possiblyconnect all this wind generation to the National Grid at Bunnythorpe.Generation from the Puketoi ranges can also connect along the 220 kV double-circuitline from Bunnythorpe to Wellington. However, care is required to ensure that thetotal generation from the Puketoi ranges, plus other generation along the 220 kVBunnythorpe–Wellington line, does not become too high (see Section 11.11.4). It isalso possible that some of the 110 kV lines may be rationalised as part of this work.2002013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 12: Taranaki Region12 Taranaki Regional Plan12.1 Regional overview12.2 Taranaki transmission system12.3 Taranaki demand12.4 Taranaki generation12.5 Taranaki significant maintenance work12.6 Future Taranaki projects summary and transmission configuration12.7 Changes since the 2012 Annual Planning Report12.8 Taranaki transmission capability12.9 Taranaki bus security12.10 Other regional items of interest12.11 Taranaki generation scenarios, proposals and opportunities12.1 Regional overviewThis chapter details the Taranaki regional transmission plan. We base this regionalplan on an assessment of available data, and welcome feedback to improve its valueto all stakeholders.Figure 12-1: Taranaki regionConstruction voltages shown. System as at March 2013.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 201

Chapter 12: Taranaki RegionThe Taranaki region includes a mix of medium sized and small grid exit points, andindustrial loads.We have assessed the Taranaki region’s transmission needs over the next 15 yearswhile considering longer-term development opportunities. Specifically, thetransmission network needs to be flexible to respond to a range of future service andtechnology possibilities, taking into consideration:the existing transmission networkforecast demandforecast generationequipment replacement based on condition assessment, andpossible technological development.12.2 Taranaki transmission systemThis section highlights the state of the Taranaki regional transmission network. Theexisting transmission network is set out geographically in Figure 12-1 andschematically in Figure 12-2.Figure 12-2: Taranaki transmission schematicWaikatoHuntly Te KowhaiNewPlymouth220 kV33 kV110 kVCarrington Street33 kVHuirangi33 kVMotunui33 kV55 kV(NZR)220 kVTaumarunui110 kV110 kV110 kVMcKee33 kV33 kVStratfordOpunake110 kV220 kV110 kVTaranakiCombinedCycle200 MWPeakers220 kV110 kVKapuni110 kVPatea33 kVHaweraWhareroa33 kVKupeBrunswick33 kVBunnythorpeCENTRAL NORTH ISLANDKEY220kV CIRCUIT110kV CIRCUITSUBSTATION BUSTRANSFORMER110 kV11 kVWaverleyWanganui33 kVTEE POINT110 kVLOADCAPACITORGENERATORSERIES REACTORWITH A BYPASSEDSWITCHMarton/BunnythorpeCENTRAL NORTH ISLAND12.2.1 Transmission into the regionThe Taranaki region connects to the National Grid through 220 kV circuits that runnorth to Huntly and south-east to Bunnythorpe. Under normal operation, generationexceeds demand in this region and power is exported to the rest of the National Grid.Between Stratford and Bunnythorpe there is a 110 kV line in parallel with the 220 kVline. Power transfer south of Stratford can be constrained by the parallel 110 kVcircuits under certain operating conditions.2022013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 12: Taranaki RegionWe reconductored the 110 kV circuits between Stratford and Wanganui with a higherratedconductor to maximise the through flow on the 220 kV circuits. The full benefitof the higher-rated conductor is limited by the rating of the Hawera 110 kV bus, whichwill be upgraded as part of redeveloping the Hawera, and is scheduled for completionin 2014.12.2.2 Transmission within the regionThe 220 kV Taranaki transmission network forms part of the grid backbone.The parallel 110 kV transmission network within the region has both capacity andvoltage issues under certain operating conditions.Some parts of the 110 kV transmission network are almost fully utilised by existinggeneration and new generation connections will need to occur at points where thereis spare capacity, or transmission upgrades may be required.12.2.3 Longer-term development pathNo significant new transmission is expected to be required in the Taranaki region.New generation connection may require nearby circuits to be thermally upgraded orreconductored for additional capacity to export the generation.High levels of new generation, such as two or more additional combined cycle gasturbines, may require additional transmission circuits in and adjacent to the Taranakiregion to transfer generation out of the region.12.3 Taranaki demandThe after diversity maximum demand (ADMD) for the Taranaki region is forecast togrow on average by 1.1% annually over the next 15 years, from 213 MW in 2013 to250 MW by 2028. This is lower than the national average demand growth of 1.5%annually.Figure 12-3 shows a comparison of the 2012 and 2013 APR forecast 15-yearmaximum demand (after diversity 104 ) for the Taranaki region. The forecasts arederived using historical data, and modified to account for customer information, whereappropriate. The power factor at each grid exit point is also derived from historicaldata. See Chapter 4 for more information about demand forecasting.104 The after diversity maximum demand (ADMD) for the region will be less than the sum of theindividual GXP peak demands, as it takes into account the fact that the peak demand does not occursimultaneously at all the GXPs in the region.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 203

Chapter 12: Taranaki RegionFigure 12-3: Taranaki region after diversity maximum demand forecastFigure 12-1 lists forecast peak demand (prudent growth) at each grid exit point for theforecast period, as required for the Grid Reliability Report.Table 12-1: Forecast annual peak demand (MW) at Taranaki grid exit points to 2028Grid exit pointPowerfactorNext 5 yearsPeak demand (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Brunswick 0.94 41 42 42 43 44 45 47 49 51 52 54Carrington1 0.96 65 67 68 69 71 72 75 78 81 84 87StreetHuirangi 1 0.91 17 18 18 18 19 19 20 21 22 22 23Hawera 0.93 30 31 31 32 32 33 34 35 36 37 38Hawera – Kupe 1.00 12 12 12 12 12 12 12 12 12 12 12Motunui 0.92 11 11 11 11 11 11 11 11 11 11 11New Plymouth –Moturoa1.00 23 23 24 24 25 25 26 27 28 30 31Opunake 0.92 12 12 13 13 13 13 14 14 14 15 15Stratford 33 kV 0.91 30 30 31 31 32 32 33 34 35 35 36Stratford 220 kV 1.00 11 11 11 11 11 12 12 12 13 13 13Taumarunui 0.84 11 11 11 11 11 11 11 11 11 11 11Wanganui 0.94 49 50 51 52 53 54 56 58 61 63 65Waverley 0.92 4 4 4 4 5 5 5 5 5 5 51. Load shifting between Carrington Street and Huirangi affects both peak forecasts. The customeradvises that they are considering switching the Bell Block load from Carrington Street to Huirangi by2015, which is not reflected in the load forecast.12.4 Taranaki generationThe Taranaki region’s generation capacity increased to 833 MW after the 2012commissioning of the Todd Energy 100 MW McKee Power Plant. The region imports2042013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 12: Taranaki Regionand exports power to the National Grid depending on the level of dispatched thermalgeneration.Table 12-2 lists the generation forecast at each grid injection point for the forecastperiod, as required for the Grid Reliability Report. This includes all known andcommitted generation stations including those embedded within the relevant locallines company’s network (Powerco). 105Table 12-2: Forecast annual generation capacity (MW) at Taranaki grid injection pointsto 2028 (including existing and committed generation)Grid injection point(location if embedded)Next 5 yearsGeneration capacity (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Carrington St (Mangorei) 5 5 5 5 5 5 5 5 5 5 5Hawera – Kiwi Dairy(Whareroa)70 70 70 70 70 70 70 70 70 70 70Hawera – Patea 31 31 31 31 31 31 31 31 31 31 31Hawera (Patearoa) 2 2 2 2 2 2 2 2 2 2 2Huirangi (Mangahewa) 9 9 9 9 9 9 9 9 9 9 9Huirangi (Motukawa) 5 5 5 5 5 5 5 5 5 5 5Kapuni 25 25 25 25 25 25 25 25 25 25 25McKee 100 100 100 100 100 100 100 100 100 100 100Taranaki Combined Cycle 385 385 385 385 385 385 385 385 385 385 385Stratford Peaker 200 200 200 200 200 200 200 200 200 200 200Stratford (StratfordAustral Pacific)1 1 1 1 1 1 1 1 1 1 112.5 Taranaki significant maintenance workOur capital project and maintenance works are integrated to enable system issues tobe resolved if possible when assets are replaced or refurbished. Table 12-3 lists thesignificant maintenance-related work 106 proposed for the Taranaki region for the next15 years that might significantly impact related system issues or connected parties.Table 12-3: Proposed significant maintenance workDescriptionBrunswick supply transformerexpected end-of-lifeHawera 110 kV rebuild, and33 kV outdoor to indoorconversionHawera supply transformersexpected end-of-lifeHuirangi supply transformersexpected end-of-lifeTentativeyearRelated system issues2017-2019 No n-1 security at Brunswick. The forecast load atBrunswick already exceeds the transformer’s capacity.Future investment will be customer driven. See Section12.8.3 for more information.2013-2014 The work involves rationalising the 110 kV bus to easemaintenance outages and increasing the 110 kV busrating. The new rating will match the new Stratford andWaverley circuits.2028-2029 The forecast load will exceed the supply transformers’ n-1thermal capacity from 2018. See Section 12.8.7 for moreinformation.2019-2021 The forecast load at Huirangi already exceeds thetransformers’ n-1 capacity. See Section 12.8.8 for moreinformation.Motunui 11 kV switchgear 2019-2020 No system issues are identified within the forecast period.105Only generators with a capacity greater than 1 MW are listed. Generation capacity is rounded to thenearest megawatt.106 This may include replacement of the asset due to its condition assessment.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 205

Chapter 12: Taranaki RegionDescriptionreplacementNew Plymouth interconnectingtransformer expected end-oflifeStratford interconnectingtransformer expected end-oflifeStratford supply transformersexpected end-of-lifeWanganui supply transformersexpected end-of-lifeTentativeyearRelated system issues2021-2022 There are system issues associated with an outage of theNew Plymouth interconnecting transformer. See Section12.8.1 for more information.2023-2025 The interconnecting transformer will exceed its n-1capacity under certain operating conditions. See Section12.8.1 for more information.2013-2014 The forecast load already exceeds the supplytransformers’ n-1 thermal capacity. See Section 12.8.10for more information.2016-2017 The forecast load of Wanganui already exceeds thetransformers’ n-1 capacity. See Section 12.8.11 for moreinformation.12.6 Future Taranaki projects summary and transmission configurationTable 12-4 lists projects to be carried out in the Taranaki region within the next 15years.Figure 12-4 shows the possible configuration of Taranaki transmission in 2028, withnew assets, upgraded assets, and assets undergoing significant maintenance withinthe forecast period.Table 12-4: Projects in the Taranaki region up to 2028Circuits/site Projects StatusBrunswickResolve the metering limit.Install a second supply transformer.PossiblePossibleBrunswick–Stratford Upgrade the circuit’s capacity. PossibleCarrington StreetCarrington Street–StratfordHaweraUpgrade the supply transformer’s protection limit.Upgrade the supply transformer branch limiting components.Increase the circuit’s capacity by thermally upgrading the terminalspans near Carrington Street.Rebuild the 110 kV bus.Convert the 33 kV outdoor switchgear to an indoor switchboard.Replace the supply transformers with higher rated units.Install reactive support at Hawera.PossiblePossiblePossibleProposedProposedPossiblePossibleHuirangi Replace the supply transformers with higher-rated units. PossibleNew PlymouthReplace the interconnecting transformer.Install a second interconnecting transformer.PossiblePossibleOpunake Resolve the metering limit. PossibleStratfordReplace the interconnecting transformer.Replace the supply transformers with higher-rated units.ProposedCommittedWanganui Replace the supply transformers with higher-rated units. Committed2062013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 12: Taranaki RegionFigure 12-4: Possible Taranaki transmission configuration in 2028New Plymouth33 kV110 kVWaikatoHuntly Te Kowhai220 kVCarrington Street110 kV**33 kVHuirangi33 kV110 kVMotunui33 kV110 kV55 kV(NZR)220 kVTaumarunuiMcKeeOpunake33 kV**110 kV33 kV110 kVStratfordTaranakiCombinedCycle200 MWPeakers220 kV220 kVKEY110 kVKapuni110 kVPatea WhareroaKupe33 kVHawera 33 kVBrunswick*33 kVBunnythorpeCENTRAL NORTH ISLANDNEW ASSETSUPGRADED ASSETSASSETS SCHEDULEDFOR REPLACEMENTMINOR UPGRADE*110 kV11 kVWaverleyWanganui33 kV110 kVMarton/BunnythorpeCENTRAL NORTH ISLAND12.7 Changes since the 2012 Annual Planning ReportTable 12-5 lists the specific issues that are either new or no longer relevant within theforecast period when compared to last year's report.Table 12-5: Changes since 2012IssuesHawera–Waverley line reconductoring projectBrunswick supply transformer capacityChangeRemoved. Project completed.New issue.12.8 Taranaki transmission capabilityTable 12-6 summarises issues involving the Taranaki region for the next 15 years.For more information about a particular issue, refer to the listed section number.Table 12-6: Taranaki region transmission issuesSectionnumberIssueRegional12.8.1 North Taranaki transmission capacity and low voltage issues12.8.2 Stratford–Hawera–Waverley–Wanganui 110 kV transmission capacitySite by grid exit point12.8.3 Brunswick supply security and capacity12.8.4 Carrington Street supply transformer capacity12.8.5 Hawera voltage quality12.8.6 Hawera (Kupe) supply security12.8.7 Hawera supply transformer capacity2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 207

Chapter 12: Taranaki RegionSectionnumberIssue12.8.8 Huirangi supply transformer capacity12.8.9 Opunake supply transformer capacity12.8.10 Stratford supply transformer capacity12.8.11 Wanganui supply transformer capacity12.8.12 Waverley supply securityBus security12.9.1 Transmission bus security12.9.2 Stratford bus security12.8.1 North Taranaki transmission capacity and low voltage issuesProject reference: TRNK-TRAN-EHMT-01Project status/type: Stratford interconnecting transformer capacity: possible, Base CapexReconfigure 220 kV to 110 kV operation: to be advisedReplace Carrington Street–Stratford circuits’ terminal span equipment:possible, Base CapexUpgrade Huirangi transformer: possible, Base CapexIndicative timing: 2017-2022Indicative cost band: New interconnecting transformer: BReconfigure 220 kV to 110 kV operation: to be advisedReplace Carrington Street–Stratford circuits’ terminal span equipment: AUpgrade Huirangi transformer: BIssueThe 220/110 kV, 100 MVA interconnecting transformer at Stratford operates inparallel with the 220/110 kV, 200 MVA interconnecting transformer at New Plymouthto supply Taranaki’s load. The Stratford transformer also assists with throughtransmission on the 110 kV transmission network between Bunnythorpe andStratford.The Stratford and New Plymouth transformers provide:a total nominal installed capacity of 295 MVA, andn-1 capacity of 135/143 MVA (summer/winter).An outage of the New Plymouth interconnecting transformer may cause:the Stratford interconnecting transformer to exceed its n-1 capacity (the loadingon this interconnecting transformer depends on the 110 kV Taranaki generation)the Carrington Street–Stratford circuit to exceed its thermal capacity, andlow voltage at the Huirangi 33 kV supply bus.SolutionPossible solutions include:installing a second 220/110 kV interconnecting transformer at (or near) NewPlymouth, and we anticipate land acquisition is required for the secondtransformeroperating the 220 kV New Plymouth–Stratford circuits at 110 kV,decommissioning the New Plymouth 220/110kV interconnection and raising theStratford interconnection capacity to 250 MVAconstraining-on generation in the 110 kV network to reduce loading and maintainvoltage qualityupgrading the thermal capacity of the Carrington Street terminating spans of theCarrington Street–Stratford circuits, and2082013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 12: Taranaki Regionreplacing the Huirangi supply transformers with transformers with on-load tapchangers.In addition, the interconnecting transformers at New Plymouth and Stratford have anexpected end-of-life within the forecast period. We will investigate the rating andtiming of the replacement transformers, and a possible alternate transmissionconfiguration.12.8.2 Stratford–Hawera–Waverley–Wanganui 110 kV transmission capacityProject reference: HWA-BUSG-EHMT-01Project status/type: Proposed, Base CapexIndicative timing: 2014Indicative cost band: AIssueThe 110 kV Stratford–Hawera–Waverley–Wanganui transmission capacitysometimes constrains high south power flow for an outage of a parallel 220 kV circuitbetween Stratford and Bunnythorpe. This is due to the rating of the Hawera 110 kVbus. 107 A series reactor and automatic bus splitting scheme have been installed atHawera, and are available for use during prolonged periods of low South Island hydrostorage. These raise but do not eliminate the constraint level.SolutionDuring an outage of a 220 kV circuit between Stratford and Bunnythorpe, anautomatic protection scheme will remove post-contingency overloads on the 110 kVHawera–Waverley circuit by splitting the Hawera 110 kV bus. Patea and the 33 kVload will be connected only to the Hawera–Stratford circuit. Whareroa and Kupe willbe connected only to the 110 kV Hawera–Waverley circuit.The limiting equipment will be replaced as part of the Hawera bus refurbishment, afterwhich the series reactor at Hawera will be decommissioned.12.8.3 Brunswick supply security and capacityProject reference: Upgrade metering: BRK-POW_TFR-EHMT-01New transformer: BRK-POW_TRF-DEV-01Project status/type: Upgrade metering: possible, Base CapexNew transformer: possible, customer-specificIndicative timing: Upgrade metering: 2014New transformer: 2017-2019Indicative cost band: Upgrade metering: ANew transformer: BIssueA single 220/33 kV, 50 MVA 108 transformer bank supplies load at Brunswick resultingin no n-1 security.There is a non-contracted on-site spare transformer, allowing possible replacementwithin 8-14 hours following a unit failure (if the spare unit is available). The peak loadat Brunswick is forecast to exceed the transformer’s continuous capacity byapproximately 4 MW in 2013, increasing to approximately 18 MW in 2028 (see Table12-7).107 The 110 kV Stratford to Wanganui transmission capacity is limited by station equipment at Hawerato 76/76 MVA (summer/winter).108 The transformer’s meter accuracy limit of 39 MVA prevents the full nominal installed capacity beingavailable.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 209

Chapter 12: Taranaki RegionSome load may need to be curtailed during the transformer outage period, as there isonly limited capacity within the Powerco network to transfer load.Table 12-7: Brunswick supply transformer overload forecastCircuit/gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Brunswick 0.94 4 5 6 7 8 8 10 12 14 16 18SolutionIn the short term, resolving the transformer’s meter accuracy limit will solve theoverload issue until 2019. We are discussing longer-term future supply options withPowerco, one of which is to install a second supply transformer to provide n-1security.The existing transformer will also approach its expected end-of-life within the next 5-10 years. We will discuss with Powerco the appropriate rating and timing for thereplacement transformers. Future investment will be customer driven.12.8.4 Carrington Street supply transformer capacityProject reference: Upgrade protection: CST-POW_TFR-EHMT-01Upgrade branch components: CST-POW_TFR-EHMT-02Project status/type: Upgrade protection: possible, Base CapexUpgrade branch components: possible, customer-specificIndicative timing: 2014Indicative cost band: Upgrade protection: AUpgrade branch components: AIssueTwo 110/33 kV transformers supply Carrington Street’s load, providing:a total nominal installed capacity of 150 MVA, andn-1 capacity of 64/64 MVA 109 (summer/winter).The transformers’ capacity is limited by 33 kV equipment limitations 109 . The peakload at Carrington Street is forecast to exceed the n-1 winter capacity by 4 MW in2013, increasing to approximately 26 MW in 2028 (see Table 12-8).Table 12-8: Carrington Street supply transformer overload forecastCircuit/gridexit pointCarringtonStreetPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 20280.96 4 6 7 8 10 11 14 17 20 23 26SolutionIn the short-term the overload can be managed operationally. In the medium term,options include:shifting load to the Huirangi grid exit point (see Section 12.8.8), and109 The transformers’ capacity is limited by a relay (65 MVA), followed by LV bus section anddisconnector limits (69 MVA), current transformer limit (71 MVA) and circuit breaker limit (91 MVA);with these limits resolved, the n-1 capacity will be 104/109 MVA (summer/winter).2102013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 12: Taranaki Regionupgrading the 33 kV equipment.This will resolve the issue for the forecast period and beyond. Future investment willbe customer driven.12.8.5 Hawera voltage qualityProject reference: HWA-C_BANKS-DEV-01Project status/type: Possible, Base CapexIndicative timing: 2015-2020Indicative cost band: AIssueAn outage of the 110 kV Hawera–Stratford circuit can result in low voltage andvoltage drops greater than 5% when there is no local generation available at Hawera.When this occurs, Hawera is supplied from a 143 kilometre spur line fromBunnythorpe. As the spur load grows, the voltage quality issues progressively ariseat Waverley, and Wanganui.Patea (31 MW) and Whareroa (70 MW) inject into the Hawera 110 kV bus, but havedifficulty providing voltage support.SolutionWe are investigating options for resolving the low voltage issues at Hawera, whichinclude:obtaining greater reactive support from the generatorsinstalling under-voltage load shedding capability, andinstalling reactive support at the Hawera 33 kV bus.Installing approximately 16 Mvar of capacitors at the Hawera 33 kV bus, in blocks of2.5 to 3.0 Mvar per capacitor, will maintain a minimum bus voltage of 95% until 2028.12.8.6 Hawera (Kupe) supply securityProject status/type:This issue is for information onlyIssueA single 110/33 kV, 30 MVA supply transformer supplies the Origin EnergyResources Kupe load, resulting in no n-1 security.The load can be transferred to the other supply transformers at Hawera by closing the33 kV bus coupler for maintenance outages, and after the supply transformer trips.SolutionThe load is fixed industrial, supplied by a dedicated transformer that meets thecustomer’s requirements.12.8.7 Hawera supply transformer capacityProject status/type:This issue is for information onlyIssueTwo 110/33 kV transformers supply Hawera’s load, providing:a total installed capacity of 60 MVA, and2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 211

Chapter 12: Taranaki Regionn-1 capacity of 35/35 MVA 110 (summer/winter).The peak load at Hawera is forecast to exceed the transformers’ n-1 summercapacity by 1 MW in 2018, increasing to approximately 6 MW in 2028 (see Table12-9).Table 12-9: Hawera supply transformer overload forecastCircuit/gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Hawera 0.93 0 0 0 0 0 1 2 3 4 5 6SolutionThe interim solution is to close the 33 kV bus coupler and supply the Powerco loadfrom the remaining Hawera supply transformer and the single Kupe supplytransformer.A possible longer-term option is to replace the existing transformers with two 50 to60 MVA units.Both Hawera supply transformers have an expected end-of-life at the end of theforecast period. We will discuss with Powerco the appropriate rating and timing forthe replacement transformers. Future investment will be customer driven.12.8.8 Huirangi supply transformer capacityProject reference: HUI-POW_TFR-EHMT-01Project status/type: Possible, customer-specificIndicative timing: 2019-2021Indicative cost band: BIssueTwo 110/33 kV transformers supply Huirangi’s load, providing:a total installed capacity of 40 MVA, andn-1 capacity of 22/24 MVA (summer/winter).The peak load at Huirangi is forecast to exceed the transformers’ n-1 summercapacity by 1 MW in 2020, increasing to approximately 4 MW in 2028 (see Table12-10).Table 12-10: Huirangi supply transformer overload forecastCircuit/gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Huirangi 0.91 0 0 0 0 0 0 1 1 2 3 4SolutionThe interim solution is for Powerco to control the Bell Block load shift from CarringtonStreet to Huirangi.Powerco is considering shifting load from Carrington Street to Huirangi. We areinvestigating the replacement of the existing transformers with two 50 MVA units.110 The transformers’ capacity is limited by 33 kV bus section limit; with this limit resolved, the n-1capacity will be 37/39 MVA (summer/winter).2122013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 12: Taranaki RegionBoth Huirangi supply transformers have an expected end-of-life within the next 5-10years. Future investment will be customer driven.12.8.9 Opunake supply transformer capacityProject reference: OPK-POW_TFR-EHMT-01Project status/type: Possible, Base CapexIndicative timing: 2014Indicative cost band: AIssueTwo 110/33 kV transformers supply Opunake’s load, providing:a total nominal installed capacity of 60 MVA, andn-1 capacity of 14/14 MVA 111 (summer/winter).The peak load at Opunake is forecast to exceed the winter n-1 capacity by 1 MW in2014, increasing to approximately 3 MW by 2028 (see Table 12-11).Table 12-11: Opunake supply transformer overload forecastCircuit/gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Opunake 0.92 0 1 1 1 1 1 2 2 2 3 3SolutionResolving the metering limit will provide n-1 capacity for the forecast period andbeyond.12.8.10 Stratford supply transformer capacityProject reference: SFD-POW_TFR-REPL-01Project status/type: Committed, Base CapexIndicative timing: 2014Indicative cost band: BIssueTwo 110/33 kV transformers supply Stratford’s load, providing:a total nominal installed capacity of 40 MVA, andn-1 capacity of 23/24 MVA 112 (summer/winter).The peak load at Stratford already exceeds the transformers’ n-1 summer capacityand the overload is forecast to increase to approximately 16 MW by 2028 (see Table12-12).Table 12-12: Stratford supply transformer overload forecastCircuit/gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Stratford 0.91 9 10 10 11 11 11 12 13 14 15 16111 The transformers’ capacity is limited by metering limit; with this limit resolved, the n-1 capacity will be38/40 MVA (summer/winter).112 The transformers’ winter capacity is limited by the cable rating; with this limit resolved, the n-1 wintercapacity will be 25 MVA.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 213

Chapter 12: Taranaki RegionSolutionWe will replace the supply transformers with two 40 MVA units in 2014.12.8.11 Wanganui supply transformer capacityProject reference: WGN-POW_TFR-REPL-01Project status/type: Committed, Base CapexIndicative timing: 2016-2017Indicative cost band: BIssueThere are two 110/33 kV transformers (20 MVA and 30 MVA) at Wanganui, providing:a total nominal installed capacity of 50 MVA, andn-1 capacity of 24/24 MVA 113 (summer/winter).The peak load at Wanganui already exceeds the transformers’ n-1 winter capacityand the overload is forecast to increase to approximately 43 MW in 2028 (see Table12-13).Table 12-13: Wanganui town supply transformer overload forecastCircuit/gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Wanganui 0.92 27 28 29 30 31 32 34 37 39 41 43SolutionIn the short term, load can be shifted to Brunswick, although some load restrictionmay be needed because of limited capacity within the Powerco network or thecapacity of the Brunswick transformer. We have a committed project to replace thetwo Wanganui transformers with two 40 MVA units.12.8.12 Waverley supply securityProject status/type:This issue is for information onlyIssueA single 110/11 kV, 10 MVA transformer supplies load at Waverley resulting in no n-1security.SolutionThere is a national off-site spare transformer, allowing replacement within 2-4 weeksfollowing a unit failure. Powerco considers the issue can be resolved operationally forthe forecast period. Any future investment will be customer driven.12.9 Taranaki bus securityThe 2013 APR has been expanded to include issues arising from the outage of asingle bus section rated at 50 kV and above for the next 15 years.Bus outages disconnect more than one power system component (for example, othercircuits, transformers, reactive support or generators). Therefore, bus outages may113The transformers’ capacity is limited by the transformer LV bushing; with this limit resolved, the n-1capacity will be 27/28 MVA (summer/winter).2142013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 12: Taranaki Regioncause greater issues than a single circuit or transformer outage (although the risk of abus fault is low, being less common than a circuit or transformer outage).12.9.1 Transmission bus securityTable 12-14 lists bus outages that cause voltage issues or a total loss of supply.Generators are included only if a bus outage disconnects the whole generationstation or causes a widespread system impact. Supply bus outages, typically 11 kVand 33 kV, are not listed.Table 12-14: Transmission bus outagesTransmissionbus outageLoss ofsupplyGenerationdisconnectionTransmissionissueFurtherinformationHawera 110 kVHawera – Kupeand PowercoPatea – HaweraWhareroa – HaweraNew Plymouth 110kVNew Plymouth –MoturoaSee note 1Stratford 110 kV Kapuni 12.9.2Wanganui 110kVWaverley 110 kVWanganuiWaverley1. This is a core grid bus, but only the local load is affected.The customer (Origin, or Powerco) has not requested a higher security level. Futureinvestment is likely to be customer driven. If increased bus security is required, theoptions typically include bus reconfiguration and/or additional bus circuit breakers.12.9.2 Stratford bus securityProject status/type:This issue is for information onlyIssueThe Kapuni generation is ‘tee’ connected to the 110 kV Opunake–Stratford–2 circuit.An outage of the bus section at Stratford that connects this circuit disconnectsKapuni. Kapuni is also automatically disconnected at Opunake because Opunakehas a split bus.SolutionThis issue is managed operationally. If n-1 security is required, options include:upgrading Kapuni to a ‘double tee’ connection, andinstalling line circuit breakers at Opunake and operating the bus solid.Future investment will be customer driven.12.10 Other regional items of interestThere are no other items of interest identified to date beyond those set out inSection 12.8 and 7.9. See Section 12.11 for information about generation scenarios,proposals and opportunities relevant to this region.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 215

Chapter 12: Taranaki Region12.11 Taranaki generation scenarios, proposals and opportunitiesThis section details relevant regional issues for selected generation scenarios,generation proposals under investigation by developers and in the public domain, orother generation opportunities. The impact of committed generation projects on thegrid backbone is dealt with separately in Chapter 6.The maximum generation that can be connected depends on several factors andusually falls within a range. Generation developers should consult with us at an earlystage of their investigations to discuss connection issues.12.11.1 Impact of generation scenarios on regional planThe generation scenarios (see Chapter 5) represent a series of possible futuregeneration outcomes. This section presents only those scenarios relevant to thisregion for the next 15 years.Generation scenarios 1 and 2 anticipate new generation connection at Hawera,Waverley, Wanganui and McKee. Under light load and high Taranaki generation, theadditional generation will cause some Taranaki 110 kV circuits to overload. Theinterconnecting transformers may also need to be upgraded to avoid overloading.Generation scenarios 3, 4, and 5 anticipate thermal generation connection of greaterthan 100 MW into the Carrington Street–Stratford circuit, which will require a thermalupgrade to provide unconstrained generation dispatch. See Section 12.11.4 for moreinformation.12.11.2 Maximum regional generationFor generation connections at the Stratford 220 kV bus, the maximum generation thatcan be injected under n-1 is approximately 380 to 410 MW in addition to the existingand newly commissioned 200 MW Stratford peakers and 100 MW McKee generators.Generation injection into the Stratford 220 kV bus depends on the direction of HVDCpower flows and system constraints around the Wairakei ring.Generation stability issues will also need to be addressed (see Chapter 6, Section6.4.4).12.11.3 Waverley wind generation stationThere is a potential for wind generation near Waverley. Connection options includethe nearby 110 kV Hawera–Wanganui circuit, or the three nearby 220 kV Brunswick–Stratford circuits.We have upgraded the 110 kV Stratford–Wanganui circuits (see Section 12.8.2).Approximately 70 to 110 MW of additional generation can be connected betweenStratford and Wanganui. However, the Stratford interconnecting transformer needsto be upgraded to avoid thermal overload.The three 220 kV Brunswick–Stratford circuits are part of the grid backboneconnecting Taranaki to the rest of the National Grid. The loading on these threecircuits is approximately equal, which maximises their transfer capacity. In order tomaintain the existing transfer capacity, a large wind generation station will need to beconnected to all three circuits, or the capacity of one or more of the circuits will needto be increased.12.11.4 Additional generation at other locationsThere are no issues with connecting new generation at the New Plymouth 220 kV bus(other than stability issues). However, the maximum generation injection into theNew Plymouth 110 kV bus is approximately between 70 to 85 MW. Generationinjection into Carrington Street–Stratford circuit is restricted to approximately 852162013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 12: Taranaki RegionMW 114 at n-1 security, under light load conditions. Any generation injecting into thisbus will play a significant role in regulating the 110 kV bus voltages in the northernpart of the Taranaki region.Exploration for more gas inshore and offshore continues in the Taranaki region andhas a potential for further gas-fired generation development. Depending on the sizeof new generation, connection to the 220 kV and few 110 kV lines in the northernTaranaki area might be possible without a major line capacity upgrade.The Opunake–Stratford circuit has sufficient capacity for approximately 50 MW ofnew generation on a secure double circuit.114 This level of generation assumes the last two spans of the Carrington Street–Huirangi circuit areupgraded to 75ºC. Without this upgrade, maximum generation is approximately 50 MW.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 217

Chapter 13: Hawke’s Bay Region13 Hawke’s Bay Regional Plan13.1 Regional overview13.2 Hawke’s Bay transmission system13.3 Hawke’s Bay demand13.4 Hawke’s Bay generation13.5 Hawke’s Bay significant maintenance work13.6 Future Hawke’s Bay projects summary and transmission configuration13.7 Changes since the 2012 Annual Planning Report13.8 Hawke’s Bay transmission capability13.9 Hawke’s Bay bus security13.10 Other regional items of interest13.11 Hawke’s Bay generation scenarios, proposals and opportunities13.1 Regional overviewThis chapter details the Hawke’s Bay regional transmission plan. We base thisregional plan on an assessment of available data, and welcome feedback to improveits value to all stakeholders.Figure 13-1: Hawke’s Bay regionConstruction voltages shown. System as at March 2013.2182013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 13: Hawke’s Bay RegionThe Hawke’s Bay region load includes a mix of significant provincial cities (Napier,Hastings and Gisborne), heavy industry (the Panpac Mill), and smaller towns (Wairoaand Havelock North).We have assessed the Hawke’s Bay region’s transmission needs over the next 15years while considering longer-term development opportunities. Specifically, thetransmission network needs to be flexible to respond to a range of future service andtechnology possibilities, taking into consideration:the existing transmission networkforecast demandforecast generationequipment replacement based on condition assessment, andpossible technological development.13.2 Hawke’s Bay transmission systemThis section highlights the state of the Hawke’s Bay regional transmission network.The existing transmission network is set out geographically in Figure 13-1 andschematically in Figure 13-2.Figure 13-2: Hawke’s Bay transmission schematicTokomaru BayCENTRAL NORTH ISLANDWairakei110 kV11 kVTuaiGisborne50 kV110 kV110 kV11 kVWairoa11 kVWhirinaki220 kVKEYRedclyffe220kV CIRCUIT110kV CIRCUIT33 kV110 kV220 kV33 kVWhakatuSUBSTATION BUSTRANSFORMERTEE POINTLOADCAPACITORFernhill220 kVBONDED CIRCUITGENERATOR33 kV110 kVWaipawaCENTRAL NORTH ISLAND2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 219

Chapter 13: Hawke’s Bay Region13.2.1 Transmission into the regionTransmission into the Hawke’s Bay region is via two 220 kV circuits from Wairakeithat supply the Whirinaki and Whakatu loads directly, and via two 220/110 kVinterconnecting transformers at Redclyffe.Two 110 kV circuits also connect Fernhill to Waipawa in the south and are normallyopen at Waipawa.13.2.2 Transmission within the region220/110 kV interconnectionThe majority of the region’s load is supplied via the 220/110 kV transformers atRedclyffe. The transformer capacity may need to be increased as load grows, and/ornew generation is connected to the 110 kV transmission network.110 kV circuitsTransmission within the region is predominantly at 110 kV. The two circuits supplyingGisborne may require a rating increase within the forecast period. For new generationor load connections that exceed the current forecasts in this APR, some 110 kV linesmay require capacity upgrades.13.2.3 Longer-term development pathThe two 220 kV circuits from Wairakei are expected to be adequate for the next 30-40years of regional load growth. Additional reactive support will be required over thisperiod, and the region will be on n security whenever one circuit is out of service formaintenance.The two 220 kV circuits may need to be thermally upgraded to export power from theregion during low load periods if there is a large increase in new generation. A new220 kV line from the Bunnythorpe area to the Hawke’s Bay region may also beconsidered if an increase in security is required.We expect the development of new generation in the Hawke’s Bay region to drive theneed for system upgrades.13.3 Hawke’s Bay demandThe after diversity maximum demand (ADMD) for the Hawkes Bay region is forecastto grow on average by 0.9% annually over the next 15 years, from 320 MW in 2013 to364 MW by 2028. This is lower than the national average demand growth of 1.5%annually.Figure 13-3 shows a comparison of the 2012 and 2013 APR forecast 15-yearmaximum demand (after diversity 115 ) for the Hawke’s Bay region. The forecasts arederived using historical data, and modified to account for customer information, whereappropriate. The power factor at each grid exit point is also derived from historicaldata. See Chapter 4 for more information about demand forecasting.115 The after diversity maximum demand (ADMD) for the region will be less than the sum of theindividual grid exit point peak demands, as it takes into account the fact that the peak demand doesnot occur simultaneously at all the grid exit points in the region.2202013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 13: Hawke’s Bay RegionFigure 13-3: Hawke’s Bay region after diversity maximum demand forecastTable 13-1 lists forecast peak demand (prudent growth) at each grid exit point for theforecast period, as required for the Grid Reliability Report.Table 13-1: Forecast annual peak demand (MW) at Hawke’s Bay grid exit points to 2028Grid exit pointPowerfactorNext 5 yearsPeak demand (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Fernhill 0.96 56 57 58 58 59 60 62 64 66 68 70Gisborne 0.98 50 52 53 54 55 57 60 63 66 68 71Redclyffe 0.97 78 79 80 81 83 84 86 89 91 93 96Tuai 0.97 1 1 1 1 1 1 1 1 1 1 1Wairoa 0.95 10 10 11 11 11 11 12 12 13 13 14Whirinaki 1.00 84 84 84 84 84 84 84 84 84 84 84Whakatu 0.97 99 100 101 103 105 106 109 113 116 119 12313.4 Hawke’s Bay generationThe Hawke’s Bay region’s generation capacity is 325 MW. This includes the 155 MWdiesel-fired Whirinaki peaker plant, which was acquired by Contact Energy in late2011, and will now be operated more flexibly without the previous regulatedconditions.Generation from Tuai, Kaitawa, and Piripaua hydro generation stations arecollectively referred to as the Waikaremoana Hydro Scheme, and connect to the Tuai110 kV bus.Embedded within the Wairoa distribution system are two 2.5 MW Waihi generators.During periods of low load, Wairoa can export up to 1 MW into the 110 kVtransmission network. Trustpower is constructing a new 3.8 MW hydro generator inthe Esk Valley with commissioning due in June 2013.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 221

Chapter 13: Hawke’s Bay RegionTable 13-2 lists the generation forecast at each grid injection point for the forecastperiod, as required for the Grid Reliability Report. This includes all known andcommitted generation stations including those embedded within the relevant locallines company’s network (Unison or Eastland Networks). 116Table 13-2: Forecast annual generation capacity (MW) at Hawke’s Bay grid injectionpoints to 2028 (including existing and committed generation)Grid injectionpoint (location ifembedded)Next 5 yearsGeneration capacity (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Gisborne 1 4 4 4 4 4 4 4 4 4 4 4Gisborne (Matawai) 2 2 2 2 2 2 2 2 2 2 2Kaitawa 36 36 36 36 36 36 36 36 36 36 36Piripaua 42 42 42 42 42 42 42 42 42 42 42Redclyffe(Ravensdown)8 8 8 8 8 8 8 8 8 8 8Tuai 60 60 60 60 60 60 60 60 60 60 60Wairoa (Waihi) 5 5 5 5 5 5 5 5 5 5 5Whirinaki 155 155 155 155 155 155 155 155 155 155 155Whirinaki (Pan Pac) 13 13 13 13 13 13 13 13 13 13 131. Mobile diesel units are situated in the Gisborne and Tokomaru Bay areas.13.5 Hawke’s Bay significant maintenance workOur capital project and maintenance works are integrated to enable system issues tobe resolved if possible when assets are replaced or refurbished. Table 13-3 lists thesignificant maintenance-related work 117 proposed for the Hawke’s Bay region for thenext 15 years that may significantly impact related system issues or connectedparties.Table 13-3: Proposed significant maintenance workDescriptionFernhill supply transformersexpected end-of-life, and33 kV outdoor to indoor conversionRedclyffe outdoor to indoorconversionTuai supply transformer expectedend-of-lifeWairoa supply transformersexpected end-of-lifeWhakatu 33 kV outdoor to indoorconversionWhirinaki 11 kV Bus B and Cswitchboard replacementTentativeyear2018-20202013-2015Related system issuesThe forecast load at Fernhill already exceeds thetransformers’ n-1 winter capacity. See Section13.8.5 for more information.2012-2014 No system issues are identified within theforecast period.2013-2015 There is no n-1 security at Tuai. Futureinvestment will be customer driven. See Section13.8.9 for more information.2015-2017 The forecast load at Wairoa may exceed thetransformers’ n-1 summer capacity for a low loadpower factor. See 13.8.10 for more information.2012-2014 An outdoor to indoor conversion project isunderway.2023-2025 No system issues are identified within theforecast period.116 Only generators with a capacity greater than 1 MW are listed. Generation capacity is rounded to thenearest megawatt.117 This may include replacement of the asset due to its condition assessment.2222013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 13: Hawke’s Bay Region13.6 Future Hawke’s Bay projects summary and transmission configurationTable 13-4 lists the projects to be carried out in the Hawke’s Bay region within thenext 15 years.Figure 13-4 shows the possible configuration of Hawke’s Bay transmission in 2028,with new assets, upgraded assets, and assets undergoing significant maintenancewithin the forecast period.Table 13-4: Projects in the Hawkes Bay region up to 2028Circuit/site Projects StatusFernhillReplace the supply transformers.Convert the 33 kV outdoor switchgear to an indoor switchboard.PossibleProposedGisborne–Tuai Upgrade the Gisborne–Tuai conductor capacity. PossibleGisborneRecalibrate the supply transformers’ metering parameters.Install a new 110 kV capacitor bank.PossiblePossibleRedclyffe Replace the supply transformers with two 120 MVA units. CommittedTuai Replace the supply transformer. ProposedWairoa Replace the supply transformers. ProposedWhakatu Convert the 33 kV outdoor switchgear to an indoor switchboard. CommittedWhirinaki Replace the 11 kV Bus B and C switchboards. ProposedFigure 13-4: Possible Hawke’s Bay transmission configuration in 2028Tokomaru BayCENTRAL NORTH ISLANDWairakei110 kV11 kVTuai*50 kVGisborne110 kV110 kV11 kVWairoa11 kVWhirinaki220 kVRedclyffe33 kV220 kV110 kV33 kVKEYFernhill33 kV220 kVWhakatuNEW ASSETSUPGRADED ASSETSASSETS SCHEDULEDFOR REPLACEMENT*MINOR UPGRADE110 kVWaipawaCENTRAL NORTH ISLAND2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 223

Chapter 13: Hawke’s Bay Region13.7 Changes since the 2012 Annual Planning ReportTable 13-5 lists the specific issues that are either new or no longer relevant within theforecast period when compared to last year's report.Table 13-5: Changes since 2012IssuesNo new issues or projects completed since 2012ChangeNo change13.8 Hawke’s Bay transmission capabilityTable 13-6 summarises the issues involving the Hawke’s Bay region for the next 15years. For more information about a particular issue, refer to the listed sectionnumber.Table 13-6: Hawke’s Bay region transmission issuesSectionnumberIssueRegional13.8.1 Hawke’s Bay voltage quality13.8.2 Fernhill–Redclyffe 110 kV transmission capacity13.8.3 Redclyffe–Tuai 110 kV transmission capacity13.8.4 Redclyffe interconnecting transformer capacitySite by grid exit point13.8.5 Fernhill supply transformer capacity13.8.6 Gisborne 110 kV voltage quality13.8.7 Gisborne supply capacity13.8.8 Redclyffe supply transformer capacity13.8.9 Tuai supply security13.8.10 Wairoa supply transformer capacity13.8.11 Whakatu supply transformer capacityBus security13.9.1 Transmission bus security13.8.1 Hawke’s Bay voltage qualityProject status/type:This issue is for information onlyIssueThe Hawke’s Bay transmission network is primarily supplied from the 220 kVRedclyffe bus, which is in turn supplied from the grid backbone by two 220 kV circuitsfrom Wairakei. The 138 MW Waikaremoana hydro scheme connects to the 110 kVnetwork, which also supplies the region’s load.The loss of a 220 kV circuit at high load and minimal Waikaremoana generation canresult in low voltages at the:110 kV bus at Gisborne, and the issue progressively arises at other high voltagebuses as load increases, andsupply buses at Fernhill and Redclyffe, which do not have on-load tap changers.2242013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 13: Hawke’s Bay RegionSolutionThe low voltage risk is managed operationally by constraining-on generators atWaikaremoana so that the generators’ reactive support is available. As the Hawke’sBay load increases, a 220 kV circuit outage will require more Waikaremoanagenerators to be in service for reactive support.There is a project underway to replace the Redclyffe supply transformers, which willhave on-load tap changers. We are also in discussions with Unison about the supplytransformer replacement at Fernhill. 118 Replacement transformers with on-load tapchangers will resolve low voltages on the Fernhill and Redclyffe supply buses.We consider the issue can be resolved operationally within the forecast period.13.8.2 Fernhill–Redclyffe 110 kV transmission capacityProject status/type:This issue is for information onlyIssueThere are two 110 kV Fernhill–Redclyffe circuits, each rated at 51/62 MVA(summer/winter). During periods of high load and low Tuai generation, power flowsfrom Redclyffe to Tuai via the 110 kV:Redclyffe–Tuai circuits, andFernhill–Redclyffe circuits and Fernhill–Tuai circuit (as per the blue load arrows inFigure 13-5).In these situations, an outage of one Fernhill–Redclyffe circuit can overload the othercircuit.Figure 13-5: Power flow from Redclyffe to Tuai during high load and low Tuai generation110 kVTuai110 kVGisborne110 kVWairoaRedclyffe110 kV220 kVFernhill 110 kVSolutionOptions to relieve a remaining Fernhill–Redclyffe circuit from overloading include thefollowing:Constraining-on the Waikaremoana hydro generation with a minimum value thatcontrols the Fernhill–Redclyffe circuit power flows. Minimum generation for the118 The supply transformers at Fernhill and Redclyffe have an expected end-of-life within the next 10years and are scheduled for replacement within the next 5-10 years.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 225

Chapter 13: Hawke’s Bay Region2013 winter peak is approximately 13 MW, increasing to approximately 45 MW in2028.Unbonding the 110 kV Fernhill–Tuai circuits. This increases the impedance of theRedclyffe–Fernhill–Tuai path and reduces the power flow through the Fernhill–Redclyffe circuits. This option does not eliminate the requirement to constrain-onWaikaremoana generation but does reduce the level of minimum generation.An investigation showed that unbonding the Fernhill–Tuai circuit is not economicallyviable. The estimated generation and demand growth in the region shows that thisoption is more likely to have an economic benefit beyond the forecast period.Future investment will be customer driven.13.8.3 Redclyffe–Tuai 110 kV transmission capacityProject status/type:This issue is for information onlyIssueThere are two 110kV Redclyffe–Tuai circuits, each rated at 57/70 MVA(summer/winter). During periods of low load and high Tuai generation, power flowsfrom Tuai to Redclyffe (as per the blue load arrows in Figure 13-6) via the 110 kV:Redclyffe–Tuai circuits, andFernhill–Tuai circuit.In these situations, an outage of the Fernhill–Tuai circuit can overload bothRedclyffe–Tuai circuits.Figure 13-6: Power flow from Tuai to Redclyffe during low load and high Tuai generation110 kVTuai110 kVGisborne110 kVWairoaRedclyffe110 kV220 kVFernhill110 kVSolutionThe 110 kV Redclyffe–Tuai circuit constraints are managed operationally by limitingthe maximum Waikaremoana hydro scheme generation.We consider the issue can be resolved operationally for the forecast period.2262013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 13: Hawke’s Bay Region13.8.4 Redclyffe interconnecting transformer capacityProject status/type:This issue is for information onlyIssueTwo 220/110 kV interconnecting transformers at Redclyffe supply the majority of theHawke’s Bay load (except the load at Whirinaki and Whakatu, which is supplied fromthe 220 kV transmission system). The transformers provide:a nominal installed capacity of 160 MVA, andn-1 capacity of 101/107 MVA (summer/winter).An outage of either interconnecting transformer will overload the remainingtransformer during periods of:high load and minimal Waikaremoana generation, orlow load and high Waikaremoana generation.The peak 110 kV load is forecast to exceed the transformers’ n-1 winter capacity byapproximately 47 MW in 2013, increasing to approximately 77 MW in 2028 (seeTable 13-7). The forecast assumes minimal Waikaremoana generation of 12 MW.Table 13-7: Redclyffe 220/110 kV transformer overload forecastCircuit/grid exit pointNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Redclyffe 47 49 51 53 55 57 61 65 69 74 77SolutionThe overload is managed operationally by transferring load (within Unison’s network)from the 110 kV transmission network to the 220 kV transmission network, and byconstraining-on generation at Waikaremoana. As the Hawke’s Bay load continues togrow, more Waikaremoana generation will need to be constrained-on more frequentlyduring an outage of an interconnecting transformer at Redclyffe.The application of the Grid Investment Test shows that installing a third 220/110 kVtransformer or replacing the existing transformers with higher rated units isuneconomic at present. The transformer loading can be managed operationally.13.8.5 Fernhill supply transformer capacityProject reference: FHL-POW_TFR-EHMT-01Project status/type: Possible, customer-specificIndicative timing: 2018-2020Indicative cost band: BIssueTwo 110/33 kV transformers (rated at 30 MVA and 50 MVA) supply Fernhill’s load,providing:a nominal installed capacity of 80 MVA, andn-1 capacity of 35/35 MVA 119 (summer/winter).119 The transformers’ capacity is limited by the rating of the 33 kV overhead bus and LV bushings limits;with these limits resolved, the n-1 capacity will be 42/45 MVA (summer/winter).2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 227

Chapter 13: Hawke’s Bay RegionThe peak load at Fernhill already exceeds the transformers’ n-1 winter capacity byapproximately 23 MW, and the overload is forecast to increase to approximately37 MW in 2028 (see Table 13-8).Table 13-8: Fernhill supply transformer overload forecastCircuit/gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Fernhill 0.95 23 24 25 26 27 27 29 31 33 35 37SolutionThe short-term operational solution involves a load transfer within the Unison networkfollowing a transformer outage.Possible longer-term solutions include replacing the 30 MVA transformer with an 80MVA transformer.Both the existing single-phase supply transformers at Fernhill will approach theirexpected end-of-life within the next 5-10 years. In addition, we also plan to convertthe Fernhill 33 kV outdoor switchgear to an indoor switchboard within the next fiveyears.We will discuss with Unison the future supply options as well as the coordination ofthe transformer capacity upgrade with the transformer replacement work. Futureinvestment will be customer driven.13.8.6 Gisborne 110 kV voltage qualityProject status/type:This issue is for information onlyIssueThe Gisborne 110 kV bus voltage can fall below 99 kV when either one of theGisborne–Tuai–1 or 2 circuits is out of service, especially during high load, lowgeneration periods.SolutionThe short-term operational solutions include:in the case of planned outages, dispatching the Waikaremoana hydro generationstation to raise the local 110 kV bus voltage to 116 kV (this is not a preferredlong-term solution as it limits the maximum active power generation), orraising the 110 kV voltage at Redclyffe.A possible longer-term option includes installing additional 10 to 20 Mvar capacitorsat Gisborne. Installing capacitors at Gisborne 50 kV bus or within the distributionnetwork will also help to extend the Gisborne supply transformers’ real powercapacity. See Section 13.8.7 for more information.13.8.7 Gisborne supply capacityProject reference: Line capacity: GIS_TUI-TRAN-EHMT-01Transformer capacity: GIS-POW_TFR-EHMT-01New capacitor: GIS-C_BANKS-DEV-01Project status/type: Line capacity: possible, customer-specificTransformer capacity: proposed, Base CapexNew capacitor: possible, customer-specificIndicative timing: Line capacity: 2017Transformer capacity: 20182282013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 13: Hawke’s Bay RegionIndicative cost band:New capacitor: to be advisedLine capacity: to be advisedTransformer capacity: ANew capacitor: AIssueThe Gisborne load is supplied by:two 110 kV circuits, each rated at 48/59 MVA (summer/winter) from Tuai, andtwo 110/50 kV transformers, providing:• a nominal installed capacity of 120 MVA, and• n-1 capacity of 63/63 MVA 120 (summer/winter).The peak load at Gisborne is forecast to exceed the:circuits’ n-1 capacity from 2017 for an outage of one Gisborne–Tuai circuit, andtransformers’ n-1 winter capacity by 1 MW in 2018, increasing to approximately16 MW in 2028 (see Table 13-9).Table 13-9: Gisborne–Tuai circuit and Gisborne supply transformer overload forecastCircuit/gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Gisborne–Tuai NA 0 0 0 0 2 3 6 9 12 15 17Gisborne 0.98 0 0 0 0 0 1 4 7 10 13 16SolutionWe will discuss future supply options with Eastland. In the short-term, one possibleoption is to operationally manage the issue by limiting the load at Gisborne to thesupply transformers’ and circuits’ capacity.For the Gisborne–Tuai circuits, possible longer-term solutions include:installing a 10 Mvar capacitor on the Gisborne 50 kV bus or within the distributionnetwork, which will resolve the overloading issue to near the end of the forecastperiod, thenthermally upgrading or reconductoring part or all of both circuits.For the supply transformer, recalibrating the metering will resolve the overloadingissue for the forecast period and beyond.13.8.8 Redclyffe supply transformer capacityProject reference: RDF-POW_TFR-EHMT-01Project status/type: Committed, customer-specificIndicative timing: Q3 2013Indicative cost band: CIssueTwo 110/33 kV transformers (rated at 40 MVA and 50 MVA) supply Redclyffe’s load,providing:a nominal installed capacity of 90 MVA, andn-1 capacity of 43/43 MVA 121 (summer/winter).120 The transformers’ capacity is limited by the metering equipment; with these limits resolved, the n-1capacity will be 73/77 MVA (summer/winter).2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 229

Chapter 13: Hawke’s Bay RegionThe peak load at Redclyffe already exceeds the transformers’ n-1 winter capacity byapproximately 34 MW, and the overload is forecast to increase to approximately52 MW in 2028 (see Table 13-10).Table 13-10: Redclyffe supply transformer overload forecastCircuit/gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Redclyffe 0.97 34 36 36 37 38 39 42 44 47 49 52SolutionWe have entered into an agreement with Unison to replace the existing transformerswith two 120 MVA transformers that will provide a secure supply for the forecastperiod and beyond.13.8.9 Tuai supply securityProject status/type:This issue is for information onlyIssueA single 110/11 kV, 2.2 MVA transformer supplies the load at Tuai, resulting in no n-1security. This transformer is also approaching its expected end-of-life within the nextfive years.SolutionThe lack of n-1 security can be managed operationally. However, we will discusswith Eastland Network Limited the options for increasing security and coordinatingoutages to minimise supply interruptions when replacing this transformer.13.8.10 Wairoa supply transformer capacityProject status/type:This issue is for information onlyIssueTwo 110/11 kV transformers supply Wairoa‘s load, providing:a nominal installed capacity of 20 MVA, andn-1 capacity of 11/12 MVA (summer/winter).An outage of one transformer will cause the remaining transformer to exceed its n-1summer capacity by 1 MW in 2017, increasing to 3 MW in 2028 (see Table 13-11).Table 13-11: Wairoa supply transformer overload forecastCircuit/Gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Wairoa 0.95 0 0 0 0 1 1 1 2 2 3 3121 The transformers’ capacity is limited by LV circuit breaker and disconnector limits, followed byprotection and LV bushing limits of 48 MVA; with these limits resolved, the n-1 capacity will be 49/53MVA (summer/winter).2302013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 13: Hawke’s Bay RegionSolutionEastland Network Limited can manage the issue operationally.Both Wairoa supply transformers are approaching their expected end-of-life within thenext five years. We will discuss with Eastland Network the appropriate timing andcapacity for the replacement transformers.Future investment will be customer driven.13.8.11 Whakatu supply transformer capacityProject status/type:This issue is for information onlyIssueTwo 220/33 kV transformers supply Whakatu‘s load, providing:a nominal installed capacity of 200 MVA, andn-1 capacity of 116/121 MVA (summer/winter).An outage of one transformer will cause the remaining transformer to exceed its n-1winter capacity by 2 MW in 2016, increasing to 22 MW in 2028 (see Table 13-12).Table 13-12: Whakatu supply transformer overload forecastCircuit/gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Whakatu 0.96 0 0 0 2 4 5 8 12 15 18 22SolutionUnison can shift load between the Whakatu and Fernhill grid exit points. Futureinvestment will be customer driven.13.9 Hawke’s Bay bus securityThe 2013 APR has been expanded to include issues arising from the outage of asingle bus section rated at 50 kV and above for the next 15 years.Bus outages disconnect more than one power system component (for example, othercircuits, transformers, reactive support or generators). Therefore, bus outages maycause greater issues than a single circuit or transformer outage (although the risk of abus fault is low, being less common than a circuit or transformer outage).13.9.1 Transmission bus securityTable 13-13 lists bus outages that cause voltage issues or a total loss of supply.Generators are included only if a bus outage disconnects the whole generationstation or causes a widespread system impact. Supply bus outages, typically 11 kVand 33 kV, are not listed.Table 13-13: Transmission bus outagesTransmissionbus outageFernhill 110 kVGisborne 110 kVLoss ofsupplyFernhillGisborneGenerationdisconnectionTransmissionissueFurtherinformationRedclyffe 110 kV Redclyffe 220/110 kV See note 12013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 231

Chapter 13: Hawke’s Bay RegionTransmissionbus outageLoss ofsupplyGenerationdisconnectionTransmissionissueFurtherinformationtransformer overloadingRedclyffe 220 kVRedclyffe 220/110 kVtransformer overloadingSee note 1Tuai 110 kVTuaiWhirinaki 220 kV Whirinaki See note 2Whirinaki – G1,G2, G3See note 21. An outage of a Redclyffe 110 kV or 220 kV bus section disconnects a 220/110 kV transformer. Thismay cause the remaining transformer to overload (see Section 13.8.4).2. Whirinaki has a single bus zone, so a bus fault disconnects all generation and supply transformers(causing a total loss of supply). An increase in bus security is not expected to be economicallyjustified.The customers (Genesis, Contact, Unison, Eastland, or Pan Pac) have not requesteda higher security level. If increased bus security is required, the options typicallyinclude bus reconfiguration and/or additional bus circuit breakers. Future investmentis likely to be customer driven.13.10 Other regional items of interestThere are no other items of interest identified to date beyond those inSections 13.8 and 11.9. See Section 11.11 for information about generationscenarios, proposals and opportunities relevant to this region.13.11 Hawke’s Bay generation scenarios, proposals and opportunitiesThis section details relevant regional issues for selected generation scenarios,generation proposals under investigation by developers and in the public domain, orother generation opportunities. The impact of committed generation projects on thegrid backbone is dealt with separately in Chapter 6.The maximum generation that can be connected depends on several factors andusually falls within a range. Generation developers should consult with us at an earlystage of their investigations to discuss connection issues.13.11.1 Impact of generation scenarios on regional planThe generation scenarios (see Chapter 5) represent a series of possible futuregeneration outcomes. This section presents only those scenarios relevant to thisregion for the next 15 years.Generation scenarios 1 and 2 anticipate the connection of 50 MW of new hydrogeneration at Wairoa. This level of generation will need to connect at 110 kV,potentially requiring the Wairoa 110 kV split bus to be upgraded to a solid bus toprovide security and operational flexibility.No issues are anticipated by generation scenarios 3, 4 or 5.13.11.2 Maximum regional generationAll generation in excess of the load is exported from the Hawke’s Bay region over the220 kV double-circuit line from Redclyffe to Wairakei. Each circuit is rated at478/583 MVA (summer/winter, subject to replacing some substation equipment), andthere is scope for thermally upgrading the circuits to approximately 690/760 MVA(summer/winter). Additional reactive power sources such as capacitors may berequired as these circuits are relatively long (137 kilometres), and they absorbreactive power when highly loaded.2322013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 13: Hawke’s Bay RegionGeneration connected to grid exit points on the 110 kV network in the Hawke’s Bayregion is exported via the Redclyffe interconnecting transformers. Eachinterconnecting transformer has a 24-hour post-contingency rating of 114/120 MVA(summer/winter).Estimates for maximum generation assume a North Island light load profile, andassume existing generation is high (Waikaremoana is generating 139 MW).For generation connected at the Redclyffe 220 kV bus, the maximum generation thatcan be injected under n-1 is approximately 530 MW, or approximately 650 MW if the220 kV circuit station constraints are removed. The constraint is due to an overloadof the 220 kV Redclyffe–Whirinaki circuit when the 220 kV Redclyffe–Wairakei circuitis out of service.For generation connected at the Redclyffe 110 kV bus, the maximum generation thatcan be injected under n-1 is approximately 10 MW. The constraint is due to anoverload of the Redclyffe interconnecting transformer when the other interconnectingtransformer is out of service.13.11.3 Titiokura and Hawke’s Bay wind generation stations, and Tauhara geothermalstationMaungaharuru wind generation station (formerly known as Titiokura, and Hawke’sBay wind farms) is approximately 27 km from Whirinaki, with a capacity of up toapproximately 330 MW. A 220 kV double-circuit line traverses the site, and is themain supply to the Hawke’s Bay area from Wairakei.The proposed Tauhara geothermal generation station in the Central North Islandregion also connects to one of the 220 kV circuits to Wairakei.There are no issues with connecting the wind and geothermal generation into thesame 220 kV circuits to Wairakei (see Chapter 11, Section 11.11.4).13.11.4 Additional generation connected to the 110 kV networkThere are a number of potential wind and hydro generation prospects that mayconnect into one or more of the 110 kV circuits in the region.The impact new generation has on circuit loading depends on the connection’slocation and configuration. For some connection locations and configurations,altering the hydro generation at Tuai removes the circuit overloads, although this mayadversely impact the energy market. To increase transmission capacity, the circuitswill need to be reconductored and/or the Fernhill–Tuai circuit unbonded.The Redclyffe 220/110 kV interconnecting transformer capacity may also need to beincreased to avoid overloading when there is high generation and low load, as powerflows from the 110 kV transmission network into the 220 kV transmission network.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 233

Chapter 14: Wellington Region14 Wellington Regional Plan14.1 Regional overview14.2 Wellington transmission system14.3 Wellington demand14.4 Wellington generation14.5 Wellington significant maintenance work14.6 Future Wellington projects summary and transmission configuration14.7 Changes since the 2012 Annual Planning Report14.8 Wellington transmission capability14.9 Wellington bus security14.10 Other regional items of interest14.11 Wellington generation scenarios, proposals and opportunities14.1 Regional overviewThis chapter details the Wellington regional transmission plan. We base this regionalplan on an assessment of available data, and welcome feedback to improve its valueto all stakeholders.Figure 14-1: Wellington regionConstruction voltages shown. System as at March 2013.2342013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 14: Wellington RegionThe Wellington region is the major load centre (comprising both residential andcentral business district loads) of the southern North Island.We have assessed the Wellington region’s transmission needs over the next 15 yearswhile considering longer-term development opportunities. Specifically, thetransmission network needs to be flexible to respond to a range of future service andtechnology possibilities, taking into consideration:the existing transmission networkforecast demandforecast generationequipment replacement based on condition assessment, andpossible technological development.14.2 Wellington transmission systemThis section highlights the state of the Wellington regional transmission network. Theexisting transmission network is set out geographically in Figure 14-1 andschematically in Figure 14-2.Figure 14-2: Wellington transmission schematicCENTRAL NORTH ISLANDMangahaoBunnythorpeParaparaumu110 kV33 kVCENTRAL NORTH ISLANDMangamaire110 kV33 kVPauatahanui33 kV110 kV110 kVMasterton33 kV110 kVGreytownUpper Hutt33 kV110 kVTakapuRoad33 kV220 kVSCSCHVDCSCSCHaywards110 kVSC SC SC SC11 kV220 kV33 kVWilton110 kVKaiwharawhara Melling11 kV33 kV11 kVGracefield 33 kV110 kV11 kVCentral Park33 kVKEY220kV CIRCUIT110kV CIRCUITSUBSTATION BUSTRANSFORMERTEE POINTLOADCAPACITORUNDERGROUND CABLE3 WDG TRANSFORMERSCSYNCH CONDENSORWest Wind33 kVHVDCREACTORHVDC LINK14.2.1 Transmission into the regionThe Wellington region is connected to the rest of the National Grid through 220 kVcircuits from Bunnythorpe and the HVDC inter-island link. A main corridor for throughtransmission between the North and South Islands, the loading of theses circuitsdepends largely on HVDC power flow from the South Island, and generation from theCentral North Island.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 235

Chapter 14: Wellington RegionThe HVDC’s link North Island terminal is at Haywards. The HVDC link can transferup to 666 MW to the South Island depending on the load and generation in theWellington region), and up to 700 MW from the South Island.We are carrying out a project to replace Pole 1 of the inter-island HVDC link with anew pole in 2013 122 . The new pole (Pole 3), together with the existing Pole 2, willincrease the capacity of the overall HVDC link to 1,000 MW from 2012, and1,200 MW from 2014. Pole 1 has been fully decommissioned and removed.The Wellington region’s generation capacity is much lower than the local load,requiring power to be imported into the region.14.2.2 Transmission within the regionThe region has some of the higher load densities in the North Island, coupled withrelatively low levels of local generation.Transmission within the Wellington region comprises:220 kV circuits entering the region from Bunnythorpe110 kV circuits entering the region from Mangamairethe HVDC link supporting the 220 kV transmission network at Haywards, andinterconnecting transformers located at Haywards and Wilton.The 2013 Wellington regional plan considers the transmission network fromDecember 2012 onwards, when the HVDC link will comprise Pole 2 and Pole 3.The reactive support in the region is mainly provided from the Haywards substation,and some contribution from the West Wind generation station.14.2.3 Longer-term development pathIt is expected that no new major transmission lines will be required into the Wellingtonregion. However, reconductoring some existing lines for increased capacity may berequired, depending on future generation developments within or outside the region.Within the region, it is possible that additional circuit(s) and/or a new substation maybe required for increased security to Wellington city, if this is shown to beeconomically justified.In addition, there will be incremental upgrades within existing substations to increasesecurity of supply within the region, particularly to Wellington city.14.3 Wellington demandThe after diversity maximum demand (ADMD) for the Wellington region is forecast togrow on average by 1.5% annually over the next 15 years, from 756 MW in 2013 to934 MW by 2028. This is similar to the forecast national average demand growth.Figure 14-3 shows a comparison of the 2012 and 2013 APR forecast 15-yearmaximum demand (after diversity 123 ) for the Wellington region. The forecasts arederived using historical data, and modified to account for customer information, whereappropriate. The power factor at each grid exit point is also derived from historicaldata. See Chapter 4 for more information about demand forecasting.122The old Pole 1 was finally decommissioned in August 2012123 The after diversity maximum demand (ADMD) for the region will be less than the sum of theindividual grid exit point peak demands, as it takes into account the fact that the peak demand doesnot occur simultaneously at all the grid exit points in the region.2362013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 14: Wellington RegionFigure 14-3: Wellington region after diversity maximum demand forecastTable 14-1 lists the peak demand forecast (prudent growth) at each grid exit point forthe forecast period, as required for the Grid Reliability Report.Table 14-1: Forecast annual peak demand (MW) for Wellington grid exit points to 2028Grid exit pointPowerfactorNext 5 yearsPeak demand (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Central Park 11 kV 0.97 25 25 26 26 27 27 28 29 30 31 33Central Park 33 kV 0.99 180 183 187 191 194 198 206 214 222 231 239Gracefield 0.99 65 67 68 69 71 72 75 78 81 84 87Greytown 0.97 12 13 13 13 13 14 14 15 15 16 16Haywards 11 kV 0.99 24 24 24 25 25 26 27 28 29 30 31Haywards 33 kV 0.97 20 21 21 22 22 23 23 24 25 26 27Kaiwharawhara 0.95 46 47 48 49 50 51 53 55 57 59 61Masterton 0.98 53 55 56 57 59 60 63 66 70 73 76Melling 11 kV 0.98 31 31 32 33 33 34 35 37 38 39 41Melling 33 kV 1.00 53 54 55 56 57 59 61 63 66 68 71Pauatahanui 0.98 25 25 26 26 27 27 28 30 31 32 33Paraparaumu 0.99 70 71 72 73 74 75 77 79 81 83 86Takapu Road 0.99 102 104 106 108 110 113 117 122 126 131 136Upper Hutt 0.99 35 35 36 37 38 38 40 41 43 45 46Wilton 0.98 63 65 66 67 69 70 73 76 78 81 8414.4 Wellington generationThe Wellington region’s generation capacity is 167 MW, which is much lower than thelocal load. Most of the generation capacity is from wind generation stations, thelargest being West Wind at 143 MW.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 237

Chapter 14: Wellington RegionTable 14-2 lists the generation forecast for each grid injection point for the forecastperiod, as required for the Grid Reliability Report. This includes all known andcommitted generation stations, including those embedded within the relevant locallines company’s network (Wellington Electricity Lines Limited, Powerco, andElectra). 124Mill Creek is a new committed wind generation project in the Wellington region for theforecast period.Table 14-2: Forecast annual generation capacity (MW) for Wellington grid injectionpoints to 2028 (including existing and committed generation)Grid injection point(location ifembedded)Central Park(Southern Landfill)Central Park(Wellington Hospital)Next 5 yearsGeneration capacity (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 20281 1 1 1 1 1 1 1 1 1 110 10 10 10 10 10 10 10 10 10 10Greytown (Hau Nui) 9 9 9 9 9 9 9 9 9 9 9Masterton(Kourarau A and B)Haywards(Silverstream)1 1 1 1 1 1 1 1 1 1 13 3 3 3 3 3 3 3 3 3 3West Wind 143 143 143 143 143 143 143 143 143 143 143Wilton (Mill Creek) 0 60 60 60 60 60 60 60 60 60 60HVDC – Haywards220 kV 1 HVDC NorthTransfer1000 1000 1200 1200 1200 1200 1200 1200 1200 1200 12001. The fourth cable may be installed after 2016 as an additional stage in the HVDC development,increasing the HVDC link capacity to 1,400 MW.14.5 Wellington significant maintenance workOur capital project and maintenance works are integrated to enable system issues tobe resolved if possible when assets are replaced or refurbished. Table 14-3 lists thesignificant maintenance-related work 125 proposed for the Wellington region for thenext 15 years that may significantly impact related system issues or connectedparties.Table 14-3: Proposed significant maintenance workDescriptionCentral Park 110/33 kV supplytransformers expected end-oflifeCentral Park–Wilton–2 and 3circuits reconductoringGracefield 33 kV switchgearreplacementGreytown 33 kV outdoor toindoor conversionTentativeyearRelated system issues2013-2014 The option to replace or to extend the existingtransformers’ operational lives is under investigation.See Section 14.8.2 for more information.2018-2019 Maintenance work. See Section 14.10.1 for moreinformation.2018-2019 The forecast load will exceed the transformer’s n-1cable capacity from 2028. See Section 14.8.3 formore information.2019-2021 No system issues are identified within the forecastperiod.Haywards supply transformers 2016-2018 The forecast loads connected at 33 kV and 11 kV124 Only generators with capacity greater than 1 MW are listed. Generation capacity is rounded to thenearest megawatt.125 This may include replacement of the asset due to its condition assessment.2382013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 14: Wellington RegionDescriptionexpected end-of-life, and33 kV outdoor to indoorconversionKaiwharawhara supplytransformers expected end-oflifeMangahao–Paraparaumucircuits reconductoringMelling 110/33 kV supplytransformers expected end-oflifePauatahanui supply transformerT1 expected end-of-lifeTakapu Road outdoor to indoorconversionUpper Hutt supply transformersexpected end-of-life, and33 kV outdoor to indoorconversionWilton 110 kV busrationalisation, and33 kV outdoor to indoorconversionTentativeyear2014-2016Related system issuesbuses will exceed the transformers’ capacity from2013. See Section 14.8.4 for more information.2013-2014 The forecast load will exceed the transformers’ n-1capacity from 2013. See Section 14.8.5 for moreinformation.2017-2019 Permanent system split at Paraparaumu. SeeSection14.8.8 for more information.2021-2022 The forecast load will exceed the transformer’s n-1capacity from 2021 (assuming the metering limit isresolved). See Section 14.8.7 for more information.2020-2021 The forecast load will exceed the transformers' n-1capacity from 2013. See Section 14.8.9 for moreinformation.2014-2015 The forecast load will exceed the transformers' n-1capacity from 2014. See Section 14.8.10 for moreinformation.2026-20282015-20162013-20142013-2015Resolving the protection and metering limits will solvethe transformer’s n-1 capacity for the forecast period.See Section 14.8.11 for more information.See Section 14.9.2 for more information.14.6 Future Wellington projects summary and transmission configurationTable 14-4 lists projects to be carried out in the Wellington region within the next 15years.Figure 14-4 shows the possible configuration of Wellington transmission in 2028,with new assets, upgraded assets, and assets undergoing significant maintenancewithin the forecast period.Table 14-4: Projects in the Wellington region up to 2028Circuit/site Projects StatusCentral ParkCentral Park–WiltonReplace the 110/33 kV supply transformers with higher rated units.New 110 kV grid exit point.Reconductor the Central Park–Wilton–2 and 3 circuits.PossiblePossibleProposedGracefield Upgrade the transformer 33 kV cable PossibleGreytown Convert the 33 kV outdoor switchgear to an indoor switchboard. ProposedHaywards Install HVDC Pole 3.Replace the Haywards supply transformers with two 110/33/11 kVunits.Convert the 33 kV outdoor switchgear to an indoor switchboardHaywards–MellingUpgrade the Haywards–Melling–1 and 2 circuits.CommittedPossibleProposedPossibleKaiwharawhara Replace the 110/11 kV supply transformer CommittedMangahao–ParaparaumuReconductor the Mangahao–Paraparaumu circuits.ProposedMasterton Install capacitors on the Masterton 110 kV bus. PossibleMellingResolve the 110/33 kV transformers’ metering limit.Resolve the 110/11 kV transformers’ protection limit.Replace the 110/33 kV supply transformers.PossiblePossibleProposed2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 239

Chapter 14: Wellington RegionCircuit/site Projects StatusParaparaumuClose 110 kV bus.Convert to 220 kV operation or a third supply transformer atParaparaumu.PossiblePossiblePauatahanui Replace the supply transformers with two higher-rated units. PossiblePauatahanui–Takapu RoadTakapu RoadUpper HuttWiltonUpgrade the Pauatahanui–Takapu Road circuit capacity.Convert the 33 kV outdoor switchgear to an indoor switchboard.Replace the existing supply transformers with higher-rated units.Resolve the protection and metering limits on the supply transformersReplace the supply transformer.Convert the 33 kV outdoor switchgear to an indoor switchboard.Install a bus coupler at Upper Hutt 110 kV bus.Rationalise the 110 kV.Convert the 33 kV outdoor switchgear to an indoor switchboard.Install a third Wilton 110 kV bus sectionInstall a new 220/110 kV interconnecting transformer.PossibleProposedPossibleProposedProposedProposedPossibleProposedProposedCommittedPossibleFigure 14-4: Possible Wellington transmission configuration in 2028CENTRAL NORTH ISLANDMangahaoBunnythorpe33 kVParaparaumu220 kV(1)CENTRAL NORTH ISLANDMangamaire110 kVPauatahanui33 kV110 kV110 kV*33 kVMasterton33 kV110 kV**GreytownUpper Hutt33 kV220 kV33 kVWilton*(2)110 kV110 kVTakapuRoadKaiwharawhara11 kV11 kV33 kVMelling33 kVCentral Park220 kV11 kVGracefield*SC*SC SC**STCSCSC SC110 kVSTC110 kV33 kVHVDCSC SCHVDCHaywards11 kV33 kV110 kVKEYNEW ASSETSUPGRADED ASSETSASSETS SCHEDULEDFOR REPLACEMENTMINOR UPGRADE*(1) The transmission backbone section identifies twopossible development paths for the lower North Island:- upgrade existing lines, and- new transmission lineAlthough this diagram shows upgrading of the existinglines, it is not intended to indicate a preference as bothoptions are still being investigated.West Wind33 kV(2) Although this diagram shows the new Wellingtoninterconnecting transformer at Wilton, it is notintended to indicate a preference as various optionsare still being investigated.14.7 Changes since the 2012 Annual Planning ReportTable 14-5 lists the specific issues that are either new or no longer relevant within theforecast period when compared to last year's report.Table 14-5: Changes since 2012IssueGracefield supply transformer capacityGreytown supply transformer capacityChangeNew issue.Removed. The previous high customer forecasts have beenrevised downwards.2402013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 14: Wellington RegionIssueWilton supply transformer capacityChangeRemoved. The protection limits have been increased.14.8 Wellington transmission capabilityTable 14-6 summarises issues involving the Wellington region for the next 15 years.For more information about a particular issue, refer to the listed section number.Table 14-6: Wellington region transmission issuesSectionnumberIssueRegional14.8.1 Wellington interconnecting transformer capacitySite by grid exit point14.8.2 Central Park supply transformer capacity14.8.3 Gracefield supply transformer capacity14.8.4 Haywards supply transformer capacity and security14.8.5 Kaiwharawhara supply capacity and security14.8.6 Masterton supply transformer capacity14.8.7 Melling supply capacity and voltage quality14.8.8 Paraparaumu transmission security and supply transformer capacity14.8.9 Pauatahanui transmission security and supply transformer capacity14.8.10 Takapu Road supply transformer capacity14.8.11 Upper Hutt supply transformer capacityBus security14.9.1 Transmission bus security14.9.4 Central Park and West Wind bus security14.9.5 Takapu Road–Wilton voltage quality and transmission capacity14.9.3 Wairarapa low voltage14.9.2 Wellington interconnecting transformer overloading14.8.1 Wellington interconnecting transformer capacityProject reference: WIL-POW_TFR-DEV-03Project status/type: Possible, Base CapexIndicative timing: 2018Indicative cost band: BIssueThe Wellington 110 kV transmission network is predominantly supplied by220/110 kV interconnecting transformers, with three transformers at Haywards andone transformer at Wilton.The three Haywards transformers have:a nominal installed capacity of 600 MVA, andn-1 capacity of 465/486 MVA (summer/winter).The Wilton transformer has:a nominal installed capacity of 250 MVA, andn-1 capacity of 293/306 MVA (summer/winter).2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 241

Chapter 14: Wellington RegionThe loading of these interconnecting transformers depends on the Wellingtonregional load, wind generation, and the HVDC transfer level and direction (north orsouth power flow).The Haywards interconnecting transformers will exceed their n-1 winter capacity fromaround 2015 (depending on Wellington load, HVDC transfer magnitude, anddirection).SolutionWe are investigating options for a new 250 MVA transformer in the Wellingtontransmission network.14.8.2 Central Park supply transformer capacityProject reference: CPK-POW_TFR-DEV-01Project status/type: Upgrade transformer capacity: possible, customer-specificIndicative timing: Upgrade transformer capacity: 2014Indicative cost band: Upgrade transformer capacity: CIssueThree 110/33 kV transformers (one rated at 120 MVA, and two rated at 100 MVA)supply Central Park’s 33 kV and 11 kV loads, providing:a total nominal installed capacity of 320 MVA, andn-1 capacity of 217/223 MVA 126 (summer/winter).The peak load at Central Park for the combined 33 kV and 11 kV load is forecast toexceed the transformers’ n-1 winter capacity by approximately 2 MW in 2013,increasing to approximately 68 MW in 2028 (see Table 14-7)Two 33/11 kV transformers supply Central Park’s 11 kV load, providing:a total nominal installed capacity of 50 MVA, andn-1 capacity of 29/29 MVA 127 (summer/winter).The peak load at Central Park 11 kV is forecast to exceed the transformers’ n-1summer capacity by approximately 1 MW in 2016, increasing to approximately 7 MWin 2028 (see Table 14-7).Table 14-7: Central Park supply transformer overload forecastCircuit/gridexit pointCentral Park110/33 kVCentral Park33/11 kVPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 20280.99 2 6 10 14 18 23 32 41 50 59 680.94 0 0 0 1 1 2 3 4 5 6 7SolutionPossible solutions include the following:For the 110/33 kV supply transformer capacity issue:• resolve the LV cable limit will solve the issue until 2016126 The transformers’ capacity is limited by the LV cable; with this limit resolved, the n-1 capacity will be217/228 MVA (summer/winter).127 The transformers’ capacity is limited by the LV protection equipment; with this limit resolved, the n-1capacity will be 29/30 MVA (summer/winter).2422013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 14: Wellington Region• replace the transformers with higher capacity units, and• limit the load to within the capacity of the transformers and load transfer toWilton or construct a new grid exit point.For the 33/11 kV supply transformer capacity issue:• resolve the transformers’ protection limit (which will not solve thetransformer overload issue), and• operationally manage the transformer overload.The two 100 MVA supply transformers at Central Park are approaching theirexpected end-of-life within the next five years. Options include:extending the transformers’ livesreplacing the transformers with 120 MVA units, andtransferring load to Wilton or a new grid exit point.While 120 MVA units will increase the supply capacity, on their own they will notresolve the capacity issue in the long-term. In addition, Wellington Electricity isconsidering load shifting from Kaiwharawhara to the Central Park grid exit point.We will discuss future supply options with Wellington Electricity. Future investmentwill be customer driven.14.8.3 Gracefield supply transformer capacityProject reference: GFD-POW_TFR-EHMT-01Project status/type: Possible, customer-specificIndicative timing: 2028Indicative cost band: AIssueTwo 110/33 kV transformers supply Gracefield’s load, providing:a total nominal installed capacity of 170 MVA, andn-1 capacity of 89/89 MVA 128 (summer/winter).The peak load at Gracefield is forecast to exceed the transformers’ n-1 wintercapacity by approximately 3 MW in 2028 (see Table 14-8).Table 14-8: Gracefield supply transformer overload forecastCircuit/gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Gracefield 0.99 0 0 0 0 0 0 0 0 0 0 3SolutionIncreasing the rating of the 33 kV cable will solve the transformers’ n-1 capacity issuewithin the forecast period.Future investment will be customer driven.14.8.4 Haywards supply transformer capacity and securityProject reference: HAY-POW_TFR-DEV-01Project status/type: Possible, customer-specificIndicative timing: 2016128 The transformers’ capacity is limited by the LV cable, followed by LV protection equipment(102 MVA) limit; with these limits resolved, the n-1 capacity will be 110/115 MVA (summer/winter).2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 243

Chapter 14: Wellington RegionIndicative cost band:CIssueThe Haywards grid exit point supplies load at 33 kV and 11 kV.One 110/33 kV, 20 MVA transformer supplies the load at the 33 kV bus resulting inno n-1 security. This load can be back fed through the Wellington Electricity network.The Haywards 33 kV peak load is forecast to exceed the transformer’s capacity byapproximately 2 MW in 2013, increasing to approximately 8 MW in 2028 (see Table14-9).One 110/11 kV, 20 MVA transformer supplies the load at the 11 kV bus resulting inno n-1 security. Wellington Electricity can backfeed some load through their networkand the Haywards local service transformer.The Haywards 11 kV peak load is forecast to exceed the transformers’ capacity byapproximately 4 MW in 2013, increasing to approximately 12 MW in 2028 (see Table14-9).Table 14-9: Haywards supply transformer overload forecastCircuit/grid exitpointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Haywards 33 kV 0.97 2 2 2 3 3 4 5 6 6 7 8Haywards 11 kV 0.99 4 4 5 5 6 6 7 8 9 10 12SolutionWe are discussing future supply options with Wellington Electricity. The short-termsolution is to manage the load operationally. A possible long-term option is to replacethe supply transformers with two new 110/33/11 kV, 60 MVA transformers, providingn-1 security to both the 11 kV and 33 kV buses.Both supply transformers at Haywards are approaching their expected end-of-lifewithin the next five years. We will discuss the appropriate rating and timing of thereplacement transformers with Wellington Electricity.14.8.5 Kaiwharawhara supply capacity and securityProject status/type:This is for information onlyIssueThe Kaiwharawhara load is supplied by two:110 kV circuits, each rated at 56/66 MVA 129 (summer/winter) from Wilton, and110/11 kV supply transformers, providing:• a total nominal installed capacity of 70 MVA, and• n-1 capacity of 38/38 MVA 130 (summer/winter).Kaiwharawhara peak load occurs during the summer period. The Kaiwharawharasubstation is configured with no 110 kV bus (each transformer is connected to one110 kV circuit only in a transformer-feeder arrangement) and is operated with a split129 The Kaiwharawhara–Wilton circuits are limited by the cable rating; with this limit resolved, the n-1capacity will be 56/68 MVA (summer/winter).130 The transformers’ capacity is limited by the 11 kV circuit breaker owned by the local distributioncompany; with this limit resolved, the n-1 capacity will be 41/43 MVA (summer/winter).2442013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 14: Wellington Region11 kV bus. Tripping either one of the transformer feeders will result in a loss ofsupply to half the load. If this load is transferred to the remaining transformer feeder,the total Kaiwharawhara peak load is forecast to exceed the:transformers’ n-1 summer capacity by approximately 14 MW in 2013, increasingto approximately 29 MW in 2028 (see Table 14-10), andcircuits’ n-1 summer capacity from 2013.Table 14-10: Kaiwharawhara supply transformer overload forecastCircuit/grid exitpointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Kaiwharawhara 0.95 14 15 16 17 18 19 21 23 25 27 29SolutionWellington Electricity considers the issue can be managed operationally bytransferring excess load to other grid exit points through the distribution network.Future investment will be customer driven.14.8.6 Masterton supply transformer capacityProject status/type:This is for information onlyIssueTwo 110/33 kV transformers supply Masterton’s load, providing:a total nominal installed capacity of 120 MVA, andn-1 capacity of 75/78 MVA (summer/winter).The peak load at Masterton is forecast to exceed the transformers’ n-1 wintercapacity by approximately 1 MW in 2025, increasing to approximately 5 MW in 2028(see Table 14-11).Table 14-11: Masterton supply transformer overload forecastCircuit/gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Masterton 0.98 0 0 0 0 0 0 0 0 0 2 5SolutionWe will discuss future options with Powerco closer to the time when the issue arises.Future investment will be customer driven.14.8.7 Melling supply capacity and voltage qualityProject reference: Circuit capacity upgrade: HAY_MLG-TRAN-EHMT-01Resolve protection and metering limits: MLG-POW_TFR-EHMT-01Project status/type: Circuit capacity upgrade: possible, customer-specificResolve protection and metering limits: possible, Base CapexIndicative timing: Circuit capacity upgrade: 2020Resolve protection and metering limits: 2013Indicative cost band: Circuit capacity upgrade: to be advisedResolve protection and metering limits: AIssueThe Melling load is supplied by:2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 245

Chapter 14: Wellington Regiontwo 110 kV circuits, each rated at 95/101 MVA 131 (summer/winter) fromHaywards, andtwo 110/33 kV transformers supplying Melling’s 33 kV load, providing:• a total nominal installed capacity of 100 MVA, and• n-1 capacity of 52/52 MVA 132 (summer/winter), andtwo 110/11 kV transformers supplying Melling’s 11 kV load, providing:• a total nominal installed capacity of 50 MVA, and• n-1 capacity of 30/30 MVA 133 (summer/winter).In terms of Melling’s peak load:The combined 33 kV and 11 kV load is forecast to exceed the circuits’ n-1 wintercapacity from 2020.The 33 kV load is forecast to exceed the transformers’ n-1 winter capacity by4 MW in 2013, increasing to approximately 22 MW in 2028 (see Table 14-12).The 11 kV load is forecast to exceed the transformers’ n-1 winter capacity by3 MW in 2013, increasing to approximately 13 MW in 2028 (see Table 14-12).The 33 kV bus voltage is forecast to fall below 0.95 pu, from 2013.Table 14-12: Hayward–Melling circuit and Melling supply transformer overload forecastCircuit/grid exitpointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Hayward–Melling N/A 0 0 0 0 0 0 2 6 9 13 17Melling 33 kV 1.00 4 6 7 8 9 10 12 15 17 20 22Melling 11 kV 0.98 3 4 4 5 6 6 8 9 10 12 13SolutionPossible solutions include the following.For the 110 kV circuit capacity, use the short-term rating for the circuit, thermallyupgrade the circuits, or reconductor the line.For the 110/33 kV supply transformer capacity, resolving the metering limit willsolve the transformers’ n-1 winter capacity issue until 2021.For the 110/11 kV supply transformer capacity, resolving the protection limit willsolve the transformers’ n-1 winter capacity until 2014.We will discuss future supply options with Wellington Electricity. In the short term,one possible option is to operationally manage the issue by limiting the load atMelling to the supply transformers’ and circuits’ capacity. A possible longer-termsolution is to develop the distribution network to limit the load within the capacity ofthe circuits and transformers.In addition, both Melling 110/33 kV supply transformers have an expected end-of-lifewithin the next 10 years. Any replacement supply transformers will have on-load tapchangers, which will resolve the low voltage issues. We will discuss the appropriaterating and timing for the replacement transformers with Wellington Electricity. Futureinvestment will be customer driven.131 The Haywards–Melling circuits are limited by the cable rating; with this limit resolved, the n-1capacity will be 95/105 MVA (summer/winter).132 The transformers’ capacity is limited by metering equipment; with this limit resolved, the n-1 capacitywill be 64/67 MVA (summer/winter).133 The transformers’ capacity is limited by HV protection equipment; with this limit resolved, the n-1capacity will be 32/34 MVA (summer/winter).2462013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 14: Wellington Region14.8.8 Paraparaumu transmission security and supply transformer capacityProject reference: 220 kV connection: PRM-SUBEST-DEV-01Closing 110 kV bus: PRM-BUSC-EHMT-01A third supply transformer: PRM-POW_TFR-DEV-01Project status/type: 220 kV connection: possible, Base Capex and/or customer-specificClosing 110 kV bus: possible, customer-specificA third supply transformer: possible, customer-specificIndicative timing: 220 kV connection or a third supply transformer: 2015Closing 110 kV bus: 2013Indicative cost band: 220 kV connection: CClosing 110 kV bus: AA third supply transformer: BIssueThe Paraparaumu load is supplied by two:110 kV circuits, each rated at 95/105 MVA (summer/winter), from Takapu Roadvia Pauatahanui to Paraparaumu110 kV circuits, each rated at 49/60 MVA (summer/winter), from Mangahao toParaparaumu, and110/33 kV supply transformers, providing:• a nominal installed capacity of 120 MVA, and• n-1 capacity of 70/74 MVA (summer/winter).A system split is permanently in place north of Paraparaumu. This prevents the110 kV circuits becoming a parallel path to the 220 kV circuits from Bunnythorpe toHaywards and consequently constraining those circuits. Paraparaumu substation isalso configured with a split 110 kV bus.The issues at Paraparaumu involve the following:The forecast peak load will exceed the supply transformers’ n-1 winter capacityby approximately 5 MW in 2013, increasing to approximately 20 MW in 2028 (seeTable 14-13).An outage of a Paraparaumu–Pauatahanui–Takapu Road circuit will cause the:• n-1 capacity of the Pauatahanui–Takapu Road circuit section to beexceeded from 2014, and• transmission bus voltage to fall below 0.9 pu from winter 2020.Table 14-13: Paraparaumu supply transformer overload forecastCircuit/gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Paraparaumu 0.99 5 6 7 8 9 10 12 14 16 18 20SolutionThe Paraparaumu peak load occurs for only a short period each day during winterevenings.There are two development paths for Paraparaumu: 220 kV and 110 kV.The 220 kV development option is to supply Paraparaumu through two 220/33 kVtransformers teed off the Bunnythorpe–Haywards–1 and 2 circuits. The 110 kVcircuits into Paraparaumu would be dismantled.The 110 kV development option retains the existing 110 kV assets. In the short-term:the 110 kV Paraparaumu bus is closed to improve the security for Paraparaumuload2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 247

Chapter 14: Wellington RegionElectra shifts load growth to Mangahao, andload is restricted post-contingency as required.Possible long-term 110 kV-based solutions include:an additional supply transformer at Paraparaumu, supplied from the Mangahao–Paraparaumu circuits, so the Paraparaumu load is divided into two grid exit pointsreplacing the Paraparaumu transformer with 100 MVA units and restricting theParaparaumu load to the transformers’ n-1 capacity.upgrading Mangahao transformer to provide 60 MVA n-1 capacity and shiftingfurther load growth to Mangahao, andreconductoring the Pauatahanui–Takapu Road circuit sections.Property issues are not anticipated for the additional supply transformers atParaparaumu because the existing substation has sufficient room to accommodatethe new equipment. However, designated land will be required for the 220 kVdeviation to Paraparaumu.We are discussing future supply options with Electra. Future investment will becustomer driven.14.8.9 Pauatahanui transmission security and supply transformer capacityProject reference:Upgrade transformer capacity: PNI-POW_TFR-DEV-01Upgrade circuit capacity:PNI_TKR-TRAN-EHMT-01Project status/type: Upgrade transformer capacity: possible, customer-specificUpgrade circuit capacity: possible, Base CapexIndicative timing: 2020Indicative cost band: Upgrade transformer capacity: BUpgrade circuit capacity: CIssueThe Pauatahanui load is supplied by two:110 kV circuits, each rated at 95/105 MVA (summer/winter), from Takapu Road(and onto Paraparaumu), and110/33 kV transformers supply Pauatahanui’s load, providing:• a total nominal installed capacity of 40 MVA, and• n-1 capacity of 22/24 MVA (summer/winter).The issues at Pauatahanui involve the following:The peak load at Pauatahanui is forecast to exceed the transformers’ n-1 wintercapacity by approximately 2 MW in 2013, increasing to approximately 10 MW in2028 (see Table 14-14).An outage of a Paraparaumu–Pauatahanui–Takapu Road circuit will cause the:• remaining circuit to exceed the n-1 capacity of the Pauatahanui–TakapuRoad circuit section from 2014• supply bus voltage to fall below 0.95 pu from winter 2013, and• transmission bus voltage to fall below 0.9 pu from winter 2028.Table 14-14: Pauatahanui supply transformer overload forecastCircuit/Gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Pauatahanui 0.98 2 3 3 4 5 5 6 7 8 9 102482013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 14: Wellington RegionSolutionIn the short-term, the lack of n-1 capacity for the circuits and transformers can bemanaged operationally.Longer term, one supply transformer at Pauatahanui will approach its expected endof-lifewithin the next 5-10 years. Wellington Electricity is also consideringdevelopments within their distribution network to transfer load from Takapu Road toPauatahanui (see Section 14.8.10). If this occurs, then the overload will be greaterthan forecast in Table 14-14 and an increase in the supply transformers’ capacity willbe required. Future investment will be customer driven.The load transfer also requires the capacity of the Pauatahanui–Takapu Road circuitsection to be addressed. One option is to transfer the Paraparaumu load to the220 kV, or develop Paraparaumu so it has a 110 kV ‘north’ and ‘south’ infeed (seeSection 14.8.8). Another option is to reconductor the Pauatahanui–Takapu Roadcircuit section.14.8.10 Takapu Road supply transformer capacityProject reference:Project status/type:Indicative timing:Indicative cost band:TKR-POW_TFR-DEV-01Possible, customer-specificTo be advisedBIssueTwo 110/33 kV transformers supply Takapu Road’s load, providing:a total nominal installed capacity of 180 MVA, andn-1 capacity of 111/116 MVA (summer/winter).The peak load at Takapu Road is forecast to exceed the transformers’ n-1 wintercapacity by approximately 3 MW in 2017, increasing to approximately 28 MW in 2028(see Table 14-15)Table 14-15: Takapu Road supply transformer overload forecastCircuit/gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Takapu Road 0.99 0 0 0 0 3 5 9 14 19 23 28SolutionWe will discuss future options with Wellington Electricity. Possible longer-termoptions include:replacing the existing supply transformers with two 120 MVA units and limiting theload growth to the transformer’s n-1 capacityinstalling a third supply transformer, andtransferring load to the Pauatahanui grid exit point.Future investment will be customer driven. In addition, we also plan to convert theTakapu Road 33 kV outdoor switchgear to an indoor switchboard within the next fiveyears.14.8.11 Upper Hutt supply transformer capacityProject reference: UHT-POW_TFR-EHMT-01Project status/type: Proposed, Base CapexIndicative timing: 20162013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 249

Chapter 14: Wellington RegionIndicative cost band:AIssueTwo 110/33 kV transformers supply Upper Hutt’s load, providing:a total nominal installed capacity of 80 MVA, andn-1 capacity of 38/38 MVA 134 (summer/winter).The peak load at Upper Hutt is forecast to exceed the transformers’ n-1 wintercapacity by approximately 1 MW in 2016, increasing to approximately 10 MW in 2028(see Table 14-16).Table 14-16: Upper Hutt supply transformer overload forecastCircuit/gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Upper Hutt 0.99 0 0 0 1 1 2 4 5 7 8 10SolutionResolving the protection equipment limit and recalibrating the metering parameterswill provide sufficient n-1 capacity for the forecast period.In addition, the Upper Hutt 33 kV outdoor switchgear will be converted to an indoorswitchboard within the next five years. Also, both the supply transformers have anexpected end-of-life at the end of the forecast period. We will discuss the rating andtiming for these replacement transformers with Wellington Electricity. Futureinvestment will be customer driven.14.9 Wellington bus securityThe 2013 APR has been expanded to include issues arising from the outage of asingle bus section rated at 50 kV and above for the next 15 years.Bus outages disconnect more than one power system component (for example, othercircuits, transformers, reactive support or generators). Therefore, bus outages maycause greater issues than a single circuit or transformer outage (although the risk of abus fault is low, being less common than a circuit or transformer outage).14.9.1 Transmission bus securityTable 14-17 lists bus outages that cause voltage issues or a total loss of supply.Generators are included only if a bus outage disconnects the whole generationstation or causes a widespread system impact. Supply bus outages, typically 11 kVand 33 kV, are not listed.Table 14-17: Transmission bus outagesTransmissionbus outageLoss ofsupplyGenerationdisconnectionTransmissionissueFurtherinformationHaywards 110 kV Haywards See note 1Wellington 220/110 kVtransformer overload14.9.2Masterton 110 kVMastertonUpper Hutt 110 kV Upper Hutt 14.9.3134 The transformers’ capacity is limited by protection equipment, followed by the metering (41 MVA)limits; with these limits resolved, the n-1 capacity will be 51/54 MVA (summer/winter).2502013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 14: Wellington RegionTransmissionbus outageLoss ofsupplyGenerationdisconnectionTransmissionissueFurtherinformationWairarapa low voltages 14.9.3Wilton 110 kV Central Park 14.9.4Kaiwharawhara See note 2West Wind 14.9.4Takapu Road–WiltonoverloadingLow transmission andsupply bus voltages14.9.514.9.51. Haywards has a single 110/33 kV and a single 110/11 kV supply transformer. A bus outage willdisconnect one but not both supply transformers, causing a partial loss of supply. Replacing thetransformers with two 110/33/11 kV banks (see Section 14.8.4) will give bus security2. An outage of a Wilton bus section will disconnect one of the two Kaiwharawhara circuits. BecauseKaiwharawhara has no 110 kV bus, this will cause a partial interruption to the load at Kaiwharawhara(see Section 14.8.5).The bus outages that result in a loss of supply are non-core grid. The customers(Wellington Electricity, Powerco, Electra, or Meridian) have not requested a highersecurity level. We do not propose to increase bus security and future investment islikely to be customer driven.If increased bus security is required, the options typically include bus reconfigurationand/or additional bus circuit breakers.14.9.2 Wellington interconnecting transformer overloadingProject reference: WIL-POW_TFR-DEV-03Project status/type: Possible, Base CapexIndicative timing: 2018Indicative cost band: BIssueThe Wellington 110 kV transmission network is predominantly supplied by220/110 kV interconnecting transformers, with three transformers at Haywards andone at Wilton. The loading of these interconnecting transformers depends on theWellington regional load, wind generation, and the HVDC transfer level and direction(north or south power flow).The worst contingency affecting the Wellington 110 kV supply capacity is an outageof a bus section at Haywards that disconnects several components, including the lossof:two of the three 220/110 kV transformersreactive voltage support (condensers 7 and 8, and filter 1), andseveral circuits, which increases reactive power absorption and decreasesvoltage.The remaining Haywards–T2 interconnecting transformer will exceed its n-1 wintercapacity from 2013. The Wilton interconnecting transformer will exceed its n-1 wintercapacity from approximately 2017 (depending on Wellington load, HVDC transfermagnitude, and direction).SolutionWe are investigating a Haywards 110 kV bus operational split to manage the bus faultto address the low voltage and transformer overloading issues.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 251

Chapter 14: Wellington RegionWe are also investigating options for a new 250 MVA transformer in the Wellingtontransmission network. See section 14.8.1 for more information.14.9.3 Wairarapa low voltageProject reference: Upper Hutt bus coupler: UHT-BUSC-EHMT-01Masterton capacitor bank: MST-C_BANKS-DEV-01Project status/type: Possible, Base CapexIndicative timing: 2024Indicative cost band: Upper Hutt bus coupler: AMasterton capacitor bank: AIssueFollowing an outage of the Upper Hutt 110 kV bus the:transmission bus voltages at Greytown and Masterton are forecast to fall below0.90 pu from winter 2017supply bus voltage at Greytown is forecast to fall below 0.95 pu from winter 2025,andsupply bus voltage at Masterton is forecast to fall below 0.95 pu from winter2026.SolutionPossible options to address the low voltages include either:a wider voltage agreement at Greytown and Masterton to allow 110 kV voltagesof 0.85 pu, which will solve the issue until 2024installing a bus coupler at Upper Huttinstalling a 10 Mvar capacitor at Masterton.We do not expect it to be economic to implement any option to address the lowvoltage issues14.9.4 Central Park and West Wind bus securityProject reference: WIL-BUSC-EHMT-01Project status/type: Committed, Base CapexIndicative timing: 2015-2016Indicative cost band: AIssueThree 110 kV circuits from Wilton are directly connected to the supply transformers atCentral Park, where there is no 110 kV bus.The worst contingency affecting Central Park supply security is an outage of a 110 kVWilton bus section that disconnects several circuits, including the Central Park–WestWind–Wilton–2 and 3 circuits, after which only one 110 kV circuit and one 110/33 kVsupply transformer remain in service.The combined 33 kV and 11 kV load at Central Park exceeds the capacity of theremaining:110 kV Central Park–Wilton–1 circuit from 2013, and110/33 kV Central Park–T5 supply transformer from 2013.In addition, the Wilton bus fault that disconnects the Central Park–West Wind–Wilton–2 and 3 circuits also disconnects the West Wind wind generation station.2522013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 14: Wellington RegionSolutionWe have committed to constructing a third Wilton 110 kV bus section. This willsecure the Central Park load for a Wilton 110 kV bus outage. It will also disconnectonly half of the West Wind generation station. 135 This project is expected to becompleted in 2015.14.9.5 Takapu Road–Wilton voltage quality and transmission capacityProject reference: A third 110 kV bus section: WIL-BUSC-EHMT-01Interconnecting transformer: WIL-POW_TFR-DEV-03Project status/type: A third 110 kV bus section: committed, Base CapexInterconnecting transformer: possible, Base CapexIndicative timing: A third 110 kV bus section: 2015-2016Interconnecting transformer: 2015-2020Indicative cost band: A third 110 kV bus section: AInterconnecting transformer: BThe Wellington 110 kV network is predominantly supplied via the Haywards andWilton 220/110 kV interconnecting transformers. An outage of a Wilton 110 kV bussection disconnects several components, including the Wilton 220/110 kVinterconnecting transformer and a Takapu Road–Wilton circuit. This outage mayresult in low voltages at Central Park, Kaiwharawhara and Wilton, and overloading ofthe remaining Takapu Road–Wilton circuit.Depending on the generation output and reactive support from West Wind the:transmission bus voltages are forecast to fall below 0.90 pu at Wilton,Kaiwharawhara, and Central Park between 2013 and 2023 (2028 forKaiwharawhara)supply bus voltage at Central Park 33 kV is forecast to fall below 0.95 pubetween 2014 and 2025, andTakapu Road–Wilton circuit is forecast to exceed its capacity between 2019 and2027.SolutionWe have committed to constructing a third Wilton 110 kV bus section. This project isexpected to be completed in 2015. The low voltage issue is solved by connecting theWilton–T8 interconnecting transformer and Takapu Road–Wilton–1 and 2 circuits todifferent bus sections (see Section 14.9.4).We are also investigating options for a new 250 MVA transformer in the Wellingtontransmission network.14.10 Other regional items of interest14.10.1 Central Park supply security during maintenanceThere are three 110 kV Central Park–Wilton circuits that supply the Central Park load.There is no 110 kV bus at Central Park, so an outage of one circuit will cause the lossof one transformer connected in series with the circuit.Wellington Electricity has indicated concern over a lack of supply security at CentralPark. When a circuit is taken out of service for maintenance, a loss of another circuitduring high load periods will cause the third supply transformer to overload and trip,resulting in a total loss of supply.This issue is being addressed in the short term by installing a 110/33 kV specialprotection scheme at Central Park to automatically shed load. This issue can be135 West Wind is operated as two half stations, each on n security.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 253

Chapter 14: Wellington Regionaddressed in the long term by installing a 110 kV bus at Central Park, or transferringload to Wilton or a new grid exit point in Wellington.14.11 Wellington generation scenarios, proposals and opportunitiesThis section details relevant regional issues for selected generation scenarios,generation proposals under investigation by developers and in the public domain, orother generation opportunities. The impact of committed generation projects on thegrid backbone is dealt with separately in Chapter 6.The maximum generation that can be connected depends on several factors andusually falls within a range. Generation developers should consult with us at an earlystage of their investigations to discuss connection issues.See also Chapter 11, Section 11.11.4 for more information about connecting windgeneration in the lower North Island.14.11.1 Impact of generation scenarios on regional planThe generation scenarios (see Chapter 5) represent a series of possible futuregeneration outcomes. This section presents only those scenarios relevant to thisregion for the next 15 years.All of the generation scenarios include the Mill Creek wind farm. See section 14.11.3for more information.Generation scenarios 1, 2 and 4 include 50 to100 MW of demand-side response.There may be some delay in replacing supply transformers depending on the locationof any load reduction.A decreased loading on the 220/110 kV interconnecting transformers and the deferralof the sixth interconnecting transformer potentially occurs due to:Demand-side response anticipated by scenarios 1, 2 and 4, (provided that is theload reduction is located at grid exit points other than Wilton)peak thermal generation at Gracefield anticipated by scenario 1 and 5, andwind generation at Takapu Road anticipated scenario 2.14.11.2 Generation connection options - generalMost of the transmission network in the region is used to supply load rather thanconnect generation. In general, there are no issues with connecting up to severalhundred megawatts of generation to these circuits. Higher generation levels reversethe power flow direction, and approach the circuits’ ratings. As a result, depending onwhere generation is located, some comparatively minor upgrades may be required,such as increasing the 220/110 kV interconnection capacity.However, the capacity of the core grid between regions may constrain the generation.14.11.3 Mill Creek wind farmA wind generation station embedded within the 33 kV distribution system at Wiltonwill not cause any connection issues.14.11.4 Generation connection to the 110 kV network in the Wairarapa areaThere is a 110 kV double-circuit line from Haywards to Upper Hutt, Greytown, andMasterton, and a single-circuit line from Masterton to Mangamaire and Woodville (inthe Central North Island region).The amount of generation that can be installed depends on its location along the110 kV line, and any line upgrades. Approximately 180 MW of generation can2542013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 14: Wellington Regionconnect at Masterton under normal operating conditions. Other generation locationsand upgrade options may result in maximum generation levels ranging fromapproximately 0 (zero) to 180 MW.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 255

Chapter 15: Nelson-Marlborough Region15 Nelson-Marlborough Regional Plan15.1 Regional overview15.2 Nelson-Marlborough transmission system15.3 Nelson-Marlborough demand15.4 Nelson-Marlborough generation15.5 Nelson-Marlborough significant maintenance work15.6 Future Nelson-Marlborough projects summary and transmission configuration15.7 Changes since the 2012 Annual Planning Report15.8 Nelson-Marlborough transmission capability15.9 Nelson-Marlborough bus security15.10 Other regional items of interest15.11 Nelson-Marlborough generation scenarios, proposals and opportunities15.1 Regional overviewThis chapter details the Nelson-Marlborough regional transmission plan. We basethis regional plan on an assessment of available data, and welcome feedback toimprove its value to all stakeholders.Figure 15-1: Nelson-Marlborough regionConstruction voltages shown. System as at March 2013.2562013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 15: Nelson-Marlborough RegionThe Nelson-Marlborough region includes a mix of significant and growing provincialcities (Nelson, Richmond, and Blenheim) together with smaller rural localities (theGolden Bay area).We have assessed the Nelson-Marlborough region’s transmission needs over thenext 15 years while considering longer-term development opportunities. Specifically,the transmission network needs to be flexible to respond to a range of future serviceand technology possibilities, taking into consideration:the existing transmission networkforecast demandforecast generationequipment replacement based on condition assessment, andpossible technological development.15.2 Nelson-Marlborough transmission systemThis section highlights the state of the Nelson-Marlborough regional transmissionnetwork. The existing transmission network is set out geographically in Figure 15-1and schematically in Figure 15-2.Figure 15-2: Nelson-Marlborough transmission schematicMotupipi(Network Tasman)Upper TakakaCobb66 kV66 kVMotueka11 kV66 kV110 kVKEY220kV CIRCUIT110kV CIRCUIT66 kVStoke220 kV33 kVBlenheim110 kV33 kV66kV CIRCUITSUBSTATION BUSTRANSFORMERLOADCAPACITOR110 kV3 WDG TRANSFORMERREACTORGENERATORWEST COASTKikiwaArgyleKikiwa15.2.1 Transmission into the regionThe Nelson-Marlborough region is connected to the rest of the National Grid via220 kV circuits from the Waitaki Valley with significant load off-take in the SouthCanterbury and Canterbury regions. Therefore, supply to the Nelson-Marlboroughregion is affected by transmission capacity from the Waitaki Valley.The region is predominantly supplied by three 220 kV circuits between the Islingtonand Kikiwa substations, with some generation from the hydro generation stationsconnected at Cobb (which is strategic to the Golden Bay spur) and Argyle.15.2.2 Transmission within the regionThe transmission within the region comprises:220 kV circuits from Kikiwa to Stoke2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 257

Chapter 15: Nelson-Marlborough Regionparallel 110 kV circuits forming a ‘triangle’ between Kikiwa, Stoke, and Blenheim220/110 kV and 110/66 kV interconnecting transformers at Stoke, anda 66 kV transmission spur supplying the Golden Bay area.The reactive power support in this region is provided from the 60 Mvar capacitors atStoke and 20.4 Mvar capacitors at Blenheim.15.2.3 Longer-term development pathThe two existing 220 kV Kikiwa–Stoke circuits have enough capacity to provide n-1security within the region for the next 20-30 years.As the Nelson-Marlborough region relies on generation several hundred kilometresaway, there will be an on-going need for investment in reactive support (such as theSTATCOM at Kikiwa and additional capacitors) to support the voltage.The 110 kV Blenheim–Argyle–Kikiwa line may need upgrading if there is more thanone significant new generator connected along the line, at Blenheim or embeddedbehind the Blenheim grid exit point.Increased 220/110 kV interconnecting transformer capacity will be required beyondthe forecast period at Kikiwa and/or Stoke. The capacity of the 110 kV Kikiwa–Stokecircuit may also need to be increased as this circuit is an important connectionbetween the 220/110 kV transformers at Kikiwa and Stoke.In the longer term, it may be economic to convert the section of 66 kV line from Stoketo Motueka to 110 kV. This conversion does not need to be investigated untilapproximately 2020, with possible implementation in approximately 2025.15.3 Nelson-Marlborough demandThe after diversity maximum demand (ADMD) for the Nelson-Marlborough region isforecast to grow on average by 1.3% annually over the next 15 years, from 240 MWin 2013 to 290 MW by 2028. This is lower than the national average demand growthof 1.5% annually.Figure 15-3 shows a comparison of the 2012 and 2013 APR forecast 15-yearmaximum demand (after diversity 136 ) for the Nelson-Marlborough region. Theforecasts are derived using historical data, and modified to account for customerinformation, where appropriate. The power factor at each grid exit point is alsoderived from historical data. See Chapter 4 for more information about demandforecasting.136 The after diversity maximum demand (ADMD) for the region will be less than the sum of theindividual grid exit point peak demands, as it takes into account the fact that the peak demand doesnot occur simultaneously at all the grid exit points in the region.2582013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 15: Nelson-Marlborough RegionFigure 15-3: Nelson-Marlborough region after diversity maximum demand forecastTable 15-1 lists the peak demand forecast (prudent growth) for each grid exit point forthe forecast period, as required for the Grid Reliability Report.Table 15-1: Forecast annual peak demand (MW) at Nelson-Marlborough grid exit pointsto 2028Grid exit pointPowerfactorNext 5 yearsPeak demand (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Blenheim 0.98 79 81 82 84 86 88 92 96 99 103 107Motueka 0.98 20 20 21 21 21 21 22 22 23 24 24Motupipi 0.95 8 9 9 9 9 9 10 10 10 11 11Stoke 1.00 138 141 143 146 149 151 157 162 168 173 17815.4 Nelson-Marlborough generationThe Nelson-Marlborough region’s generation capacity is 57 MW, which is lower thanlocal demand, requiring power to be imported through the National Grid.Table 15-2 lists the generation forecast for each grid injection point for the forecastperiod, as required for the Grid Reliability Report. This includes all known generationstations, including those embedded within the relevant local lines company’s network(Network Tasman or Marlborough Lines). 137No new generation is known to be committed in the Nelson-Marlborough region forthe forecast period.137 Only generators with capacity greater than 1 MW are listed. Generation capacity is rounded to thenearest megawatt.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 259

Chapter 15: Nelson-Marlborough RegionTable 15-2: Forecast annual generation capacity (MW) at Nelson-Marlborough gridinjection points to 2028 (including existing and committed generation)Grid injection point(location ifembedded)Argyle – Branch RiverSchemeNext 5 yearsGeneration capacity (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 202811 11 11 11 11 11 11 11 11 11 11Cobb 32 32 32 32 32 32 32 32 32 32 32Blenheim(Lulworth Wind)Blenheim(Marlborough LinesDiesel)1 1 1 1 1 1 1 1 1 1 19 9 9 9 9 9 9 9 9 9 9Blenheim (Waihopai) 3 3 3 3 3 3 3 3 3 3 3Motupipi (Onekaka) 1 1 1 1 1 1 1 1 1 1 115.5 Nelson-Marlborough significant maintenance workOur capital project and maintenance works are integrated to enable system issues tobe resolved if possible when assets are replaced or refurbished. Table 15-3 lists thesignificant maintenance related work 138 proposed for the Nelson-Marlborough regionfor the next 15 years that may significantly impact related system issues or connectedparties.Table 15-3: Proposed significant maintenance workDescriptionBlenheim supply transformersexpected end-of-lifeBlenheim 33 kV capacitorbanks replacementStoke 11 kV capacitor bankreplacementStoke 110/66 kVinterconnecting transformerexpected end-of-lifeStoke supply transformersexpected end-of-life, and33 kV outdoor to indoorconversionTentativeyearRelated system issues2018-2020 The option to replace or extend transformer life is underinvestigation.2015-2017 See Chapter 6 for information about the Upper SouthIsland voltage issue. The rating of the replacementcapacitors is yet to be determined.2014-2016 See Chapter 6 for information about the Upper SouthIsland voltage issue. The rating of the replacementcapacitors is yet to be determined.2020-2022 Upgrading the transformer’s capacity is one of thepossible options to resolve the transformer overloadingissue. See Section 15.8.2 for more information2013-2014 A new switchboard has been installed and a project isunder way to replace the transformers with two120 MVA units. See Section 15.8.7 for moreinformation.15.6 Future Nelson-Marlborough projects summary and transmissionconfigurationTable 15-4 lists projects to be carried out in the Nelson-Marlborough region within thenext 15 years.Figure 15-4 shows the possible configuration of Nelson-Marlborough transmission in2028, with new assets, upgraded assets, and assets undergoing significantmaintenance within the forecast period.138 This may include replacement of the asset due to its condition assessment.2602013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 15: Nelson-Marlborough RegionTable 15-4: Projects in the Nelson-Marlborough region up to 2028Circuit/site Projects StatusBlenheimReplace the supply transformers.Replace the 33 kV capacitor banks.ProposedProposedBrightwater New grid exit point. PossibleKikiwa–Stoke Upgrade the conductor capacity PossibleMotueka Install new capacitors. PreferredRiwaka Install a new grid exit point. PreferredStokeResolve the 220/110 kV interconnecting transformer’s branch limit.Install a new 110/66 kV interconnecting transformer.Replace the 110/66 kV interconnecting transformer.Replace the 220/33 kV supply transformers with two higher-ratedunits.Convert the 33 kV outdoor switchgear to an indoor switchboard.Replace the 11 kV capacitor banks.PossiblePreferredProposedCommittedProposedProposedFigure 15-4: Possible Nelson-Marlborough transmission configuration in 2028Motupipi(Network Tasman)Upper Takaka66 kVRiwaka66 kV 33 kVMotueka11 kVKEYCobb66 kV66 kV66 kV110 kVStoke*220 kV33 kV110 kVNEW ASSETSUPGRADED ASSETSASSETS SCHEDULEDFOR REPLACEMENTMINOR UPGRADE*Brightwater33 kV220 kVBlenheim33 kV110 kVKikiwaArgyleWEST COASTKikiwa15.7 Changes since the 2012 Annual Planning ReportTable 6-1 lists the specific issues that are either new or no longer relevant within theforecast period when compared to last year's report.Table 15-5: Changes Since 2012IssuesNo new issues or projects completed since 2012ChangeNo change15.8 Nelson-Marlborough transmission capabilityTable 15-6 summarises issues involving the Nelson-Marlborough region for the next15 years. For more information about a particular issue, refer to the listed sectionnumber.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 261

Chapter 15: Nelson-Marlborough RegionTable 15-6: Nelson-Marlborough region transmission issuesSectionnumberIssueRegional15.8.1 Stoke 220/110 kV interconnecting transformer capacity15.8.2 Stoke 110/66 kV interconnecting transformer capacitySite by grid exit point15.8.3 Cobb–Motueka 66 kV transmission capacity15.8.4 Kikiwa–Stoke 110 kV transmission capacity15.8.5 Motueka supply transformer capacity15.8.6 Motupipi single supply security15.8.7 Stoke supply transformer capacityBus security15.9.1 Transmission bus security15.9.2 Blenheim supply security and voltage15.8.1 Stoke 220/110 kV interconnecting transformer capacityProject reference: STK-POW_TFR-EHMT-01Project status/type: Resolving station equipment limits: possible, Base CapexIndicative timing: 2023-2028Indicative cost band: AIssueA single 220/110 kV interconnecting transformer at Stoke provides a 110 kVinterconnection to the Nelson-Marlborough region. This transformer has:a nominal installed capacity of 150 MVA, andn-1 capacity of 160/160 139,140 MVA (summer/winter).The Stoke 220/110 kV transformer is effectively operating in parallel with the150 MVA interconnecting transformer at Kikiwa. An outage of the Kikiwa transformerresults in the Stoke transformer supplying the Nelson-Marlborough and West Coastregions. 141 This may cause the Stoke transformer to overload and cause low voltageissues within the West Coast region (see Chapter 16). The loading on the Stoketransformer depends on the generation in the Nelson-Marlborough and West Coastregions.SolutionIn the short term, these issues will be managed operationally via generationrescheduling and load management. Resolving station equipment constraints on theinterconnecting transformer and managing the generation level in the Nelson–Marlborough and West Coast regions will resolve the issue for the forecast period.In the longer term, a second 220/110 kV transformer may be required at Kikiwa.139 Stoke has only one 220/110 kV, 150 MVA interconnecting transformer. The n-1 capacity is theresult of the transformer essentially operating in parallel with the Kikiwa–T2 (150 MVA).140 The transformer’s capacity is limited by 110 kV disconnectors; with this limit resolved, the n-1capacity will be 180/188 MVA (summer/winter).141 The normal operating arrangement is only Kikiwa–T2 (150 MVA) provides a 110 kV interconnectionto the West Coast region, and Kikiwa–T1 (50 MVA) supplies the local 11 kV load.2622013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 15: Nelson-Marlborough Region15.8.2 Stoke 110/66 kV interconnecting transformer capacityProject reference:Project status/type:Indicative timing:Indicative cost band:STK-POW_TFR-EHMT-02Preferred, customer-specificTo be advisedAIssueThe Golden Bay loads at the Motueka and Motupipi grid exit points are supplied by:a single 110/66 kV, 23 MVA transformer at Stoke, andthe Cobb generation station.With no Cobb generation, the peak load at Golden Bay is forecast to exceed theStoke transformer’s continuous rating by approximately 5 MW in 2013, increasing toapproximately 11 MW in 2028 (see Table 15-7).Table 15-7: Stoke 110/66 kV transformer overload forecastCircuit/gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 Years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Golden Bay 0.98 5 5 6 6 7 7 8 9 10 11 11SolutionThe short-term operational solution requires Cobb to generate at or above a minimumoutput to avoid overloading the Stoke transformer.The transformer has an expected end-of-life within the next 5-10 years. We arediscussing longer-term solutions with Network Tasman and Trustpower. Thepreferred option is to install a 40 MVA transformer in parallel with the existinginterconnecting transformer. This (in conjunction with some generation from Cobb)will provide secure supply to the Golden Bay area for the forecast period and beyond.Installing a second Stoke 110/66 kV interconnecting transformer does not raiseproperty issues as the existing substation has sufficient room to accommodate thenew transformer.Future investment will be customer driven.15.8.3 Cobb–Motueka 66 kV transmission capacityProject status/type:This issue is for information onlyIssueThe three circuits connecting Cobb, Motueka, and Upper Takaka include the:Cobb–Motueka–2 circuit rated at 21/26 MVA (summer/winter)Motueka–Upper Takaka–1 circuit rated at 21/25 MVA (summer/winter), andCobb–Upper Takaka–1 circuit rated at 29/35 MVA (summer/winter).An outage of one of the Cobb–Motueka–2, Motueka–Upper Takaka–1 orCobb–Upper Takaka–1 circuit will limit the Cobb generation station’s output.SolutionThe issue is managed operationally with an automatic generation runback scheme toconstrain Cobb generation to match the remaining circuits’ capacity. This isconsidered adequate and future investment will be customer driven.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 263

Chapter 15: Nelson-Marlborough Region15.8.4 Kikiwa–Stoke 110 kV transmission capacityProject reference: KIK_STK-TRAN-EHMT-01Project status/type: Possible, Base CapexIndicative timing: Beyond 2020Indicative cost band: AIssueThere are two 110 kV circuits connecting the Nelson-Marlborough and West Coastregions:Kikiwa–Stoke–3 circuit rated at 56/68 MVA (summer/winter), andKikiwa–Argyle–Blenheim–Stoke–1 circuit rated at 56/68 MVA (summer/winter).An outage of a Stoke 220/110 kV interconnecting transformer results in Nelson–Marlborough region supply from the interconnection at Kikiwa, via the two 110 kVcircuits. The Kikiwa–Stoke–3 circuit may overload when Nelson-Marlborough regionload is high coupled with low local generation.SolutionThis issue can be managed operationally by constraining generation levels at Cobband Argyle. A longer-term solution is to thermally upgrade the Kikiwa–Stoke 110 kVcircuit.15.8.5 Motueka supply transformer capacityProject reference: New capacitors: MOT-C_BANKS-DEV-01New grid exit point: MOT-SUBEST-DEV-01Project status/type: New capacitors and grid exit point: preferred, customer-specificIndicative timing: New capacitors: 2014New grid exit point: 2016Indicative cost band: Install new capacitor: ANew grid exit point: CIssueTwo 66/11 kV transformers supply Motueka’s load, providing:a total nominal installed capacity of 40 MVA, andn-1 capacity of 23/23 MVA 142 (summer/winter).The peak load at Motueka is forecast to exceed the transformers’ n-1 winter capacityby approximately 1 MW in 2013, increasing to approximately 5 MW in 2028 (seeTable 15-8).Table 15-8: Motueka supply transformer overload forecastCircuit/gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Motueka 0.98 1 2 2 2 2 3 3 4 4 5 5SolutionWe have discussed future supply options with Network Tasman. The preferred longtermdevelopment option involves:142 The transformers’ capacity is limited by the bus section limit of 23 MVA, and cable limit of 24 MVA;with these limits resolved, the n-1 capacity will be 24/25 MVA (summer/winter).2642013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 15: Nelson-Marlborough Regioninstalling two 2.2 Mvar capacitors at Motueka, which will extend the transformer’sreal power capacity up to 2021, andestablishing a new grid exit point near Riwaka, connecting to the 66 kVStoke–Upper Takaka lines.Installing new capacitor banks does not raise new property issues as the existingsubstation has sufficient room to accommodate the new equipment. NetworkTasman has designated land for the new Riwaka grid exit point.15.8.6 Motupipi single supply securityProject status/type:This issue is for information onlyIssueMotupipi is supplied by a single 66 kV circuit from Upper Takaka, which means it hasno n-1 security.The forecast load growth at Motupipi will not exceed the present circuit rating for theforecast period and beyond.Motupipi’s point of connection is the 66 kV line termination, so the loading of thesupply transformer rests with the customer.SolutionThe lack of n-1 security can be managed operationally. Future investment will becustomer driven.15.8.7 Stoke supply transformer capacityProject reference: Replace transformer: STK-POW_TFR-REPL-01New grid exit point: STK-SUBEST-DEV-01Project status/type: Replace transformer: committed, Base CapexNew grid exit point: possible, customer-specificIndicative timing: Replace transformer: Q4 2013New grid exit point: 2020Indicative cost band: Replace transformer: CNew grid exit point: CIssueThree 220/33 kV transformers supply Stoke’s load, providing:a total nominal installed capacity of 150 MVA, andn-1 capacity of 114/114 MVA 143 (summer/winter).The peak load at Stoke already exceeds the transformers’ n-1 winter capacity and theoverload is forecast to increase to approximately 68 MW in 2028 (see Table 15-9).Table 15-9: Stoke supply transformer overload forecastCircuits/gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Stoke 1.00 27 30 33 35 38 41 46 52 57 62 68143 The transformers’ capacity is limited by protection equipment; with this limit resolved, the n-1capacity will be 124/133 MVA (summer/winter).2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 265

Chapter 15: Nelson-Marlborough RegionSolutionThe supply transformers are made up of three single-phase units with a contractedon-site spare, allowing replacement within 8-14 hours following a unit failure.We are replacing the existing transformers with two 120 MVA units with a postcontingency rating of 143 MVA, which gives an additional 29 MVA n-1 capacity. Thetransformer overloading issue can be resolved initially by operational measures and,in the longer-term, by a new grid exit point at Brightwater connected to the 220 kVKikiwa–Stoke circuits (see Section 15.10.1). Network Tasman has designated landfor a new grid exit point.15.9 Nelson-Marlborough bus securityThe 2013 APR has been expanded to include issues arising from the outage of asingle bus section rated at 50 kV and above for the next 15 years.Bus outages disconnect more than one power system component (for example, othercircuits, transformers, reactive support or generators). Therefore, bus outages maycause greater issues than a single circuit or transformer outage (although the risk of abus fault is low, being less common than a circuit or transformer outage).15.9.1 Transmission bus securityTable 15-10 lists the bus outages that cause voltage issues or a total loss of supply.Generators are included only if a bus outage disconnects the whole generationstation or causes a widespread system impact. Supply bus outages, typically 11 kVand 33 kV, are not listed.Table 15-10: Transmission bus outagesTransmissionbus outageLoss ofsupplyGenerationdisconnectionTransmissionissueFurtherinformationArgyle 110 kVArgyleBlenheim 110 kV Blenheim 15.9.2Argyle See note 1Cobb 66 kVCobbStoke 66 kVStoke 110 kVGolden Bay spurBlenheimGolden Bay spur See note 2Upper Takaka 66 kV Motupipi See note 31. There is no bus protection at Blenheim, so bus faults remove all connected circuits from service. Thisincludes the Blenheim–Argyle–Kikiwa circuit, causing a loss of connection at Argyle.2. The Golden Bay spur supplies load at Motueka and Motupipi and connects generation at Cobb. Anoutage of the Stoke 110 kV or 66 kV bus will disconnect the spur. This may or may not cause a loss ofsupply, depending on the balance of load and generation on the spur.3. Motupipi is supplied on a single circuit from Upper Takaka. An outage on the Upper Takaka bus willdisconnect the circuit, causing a total loss of supply at Motupipi.The customers (Network Tasman, TrustPower, or Marlborough Lines) have notrequested a higher security level. If increased bus security is required, the optionstypically include bus reconfiguration and/or additional bus circuit breakers. Futureinvestment is likely to be customer driven.15.9.2 Blenheim supply security and voltage qualityProject status/type:This is for information only2662013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 15: Nelson-Marlborough RegionIssueThere is a single 110 kV bus section at Blenheim, resulting in no n-1 security.Additionally, there are three 110 kV circuits (two circuits from Stoke and one fromArgyle) supplying Blenheim’s load. A fault on the:Blenheim 110 kV bus will result in a total loss of supply to the load, andStoke 110 kV bus will cause low voltage issue, which may lead to voltagecollapse resulting in a loss of supply at Blenheim. The Blenheim load will beconstrained to approximately 50 MW due to the voltage stability and the capacityof the 110 kV Blenheim–Argyle–Kikiwa circuit.SolutionThe faulted bus section at Blenheim and Stoke can be isolated via bus disconnectors,restoring supply to Blenheim. If n-1 connection security is eventually required, then a110 kV bus coupler will need to be installed. Future investment will be customerdriven.15.10 Other regional items of interest15.10.1 Brightwater grid exit pointProject reference:Project status/type:Indicative timing:Indicative cost band:STK-SUBEST-DEV-01Possible, customer-specificTo be advisedCBrightwater is a proposed new 220/33 kV grid exit point connected to a Kikiwa–Stokecircuit. Load will be transferred from Stoke to Brightwater, so the load at Stokeremains within the capacity of the Stoke supply transformers (see Section 15.8.7). Itwill also provide diversity for the Stoke load.The timing for the new Brightwater grid exit point will be determined by NetworkTasman. Network Tasman has designated land for the new grid exit point.15.10.2 Golden Bay voltage qualityProject reference:Project status/type:Indicative timing:Indicative cost band:MOT-C_BANKS-DEV-01New capacitor at Motueka: preferred, customer-specificNew capacitor at Motueka :To be advisedNew capacitor at Motueka: AIssueTwo 66 kV circuits connect Cobb generation to the transmission grid. Loss of theCobb–Motueka–Stoke–2 circuit during a planned maintenance outage of the Cobb–Upper Takaka–1 circuit results in disconnection of Cobb generation from the grid andcauses low voltage within the Golden Bay.SolutionPossible development options include installing:capacitors at Motueka and/or Motupipi for voltage support, and reducingvoltage step down post-contingency, orcapacitor banks at Motueka, which will also help to extend the Motuekasupply transformers’ n-1 real power capacity for the forecast period andbeyond (see Section 15.8.5).2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 267

Chapter 15: Nelson-Marlborough Region15.11 Nelson-Marlborough generation scenarios, proposals and opportunitiesThis section details relevant regional issues for selected generation scenarios,generation proposals under investigation by developers and in the public domain, orother generation opportunities. The impact of committed generation projects on thegrid backbone is dealt with separately in Chapter 6.The maximum generation that can be connected depends on several factors andusually falls within a range. Generation developers should consult with us at an earlystage of their investigations to discuss connection issues.15.11.1 Impact of generation scenarios on regional planThe generation scenarios (see Chapter 5) represent a series of possible futuregeneration outcomes. This section presents only those scenarios relevant to thisregion for the next 15 years.Only generation scenario 1 and 2 anticipate new generation in the region. Section15.11.2 discusses the impacts from connecting 150 MW of wind generation atBlenheim in 2022 (generation scenario 1). Section 15.11.3 discusses the impactsfrom connecting 73 MW of hydro generation at the 110 kV Argyle–Blenheim circuit in2025 (generation scenarios 1 and 2).Generation scenario 1 also anticipates 50 MW of solar generation at Stoke 33 kV busin 2026. This generation effectively reduces the loading on the Stoke 220/33 kVsupply transformers. However, this generation is forecast for 2026, which is too lateto affect the Stoke supply transformer issue (see Section 15.8.7).15.11.2 Maximum regional generationThe maximum generation estimates assume a light South Island load profile and highgeneration in the Nelson-Marlborough region (with Cobb generating 27 MW).For generation connected at the Stoke 220 kV bus, the maximum generation that canbe injected under n-1 is approximately 380 MW. The constraint is due to the 220 kVKikiwa–Stoke circuit overloading when the other circuit is out of service.Generation up to approximately 130 MW can be connected at the Blenheim 110 kVbus, or to the two 110 kV Blenheim–Stoke circuits. Higher levels of generation(approximately 160 MW of generation injection under n-1) require a thermal upgradeof the 110 kV Kikiwa–Stoke–3 circuit and a protection upgrade on the Blenheim–Stoke–1 circuit. Further increases require a thermal upgrade of the 110 kVBlenheim–Argyle–Kikiwa circuit.15.11.3 Generation on the Blenheim–Argyle–Kikiwa circuitBlenheim–Argyle–Kikiwa is a single 110 kV circuit rated at 56/68 MVA. Themaximum generation that can be connected to this circuit depends on the location ofthe connection. With all circuits in service, approximately 50 MW can be connected,in addition to the existing generation injected at Argyle. Generation levels above thiswill need to be embedded within the Marlborough Lines network. Generationrestrictions may also be needed for some outages. Alternatively, increasing therating of the circuit is also technically possible.15.11.4 Generation connection to the 66 kV networkThe existing Cobb hydro generation station is already connected to the 66 kVtransmission network, and its output must occasionally be constrained if a circuit isout of service or to prevent overloading of the Stoke 110/66 kV transformer.Approximately 10 MW of additional generation can be connected if controls areinstalled to automatically reduce generation for some outages, and the Stoke2682013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 15: Nelson-Marlborough Region110/66 kV transformer capacity is increased. The 66 kV transmission lines have avariety of conductor types and ratings. Thermally upgrading or replacing the sectionswith the lowest capacities allows an additional 15 to 30 MW of generation before theremaining sections require upgrading.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 269

Chapter 16: West Coast Region16 West Coast Regional Plan16.1 Regional overview16.2 West Coast transmission system16.3 West Coast demand16.4 West Coast generation16.5 West Coast significant maintenance work16.6 Future West Coast projects summary and transmission configuration16.7 Changes since the 2012 Annual Planning Report16.8 West Coast transmission capability16.9 West Coast bus security16.10 Other regional items of interest16.11 West Coast generation scenarios, proposals and opportunities16.1 Regional overviewThis chapter details the West Coast regional transmission plan. We base thisregional plan on an assessment of available data, and welcome feedback to improveits value to all stakeholders.Figure 16-1: West Coast regionConstruction voltages shown. System as at March 2013.2702013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 16: West Coast RegionThe West Coast region includes a mix of significant and growing provincial cities(Dobson, Greymouth, Hokitika), and smaller, lower-growth rural localities.We have assessed the West Coast region’s transmission needs over the next 15years while considering longer-term development opportunities. Specifically, thetransmission network needs to be flexible to respond to a range of future service andtechnology possibilities, taking into consideration:the existing transmission networkforecast demandforecast generationequipment replacement based on condition assessment, andpossible technological development.16.2 West Coast transmission systemThis section highlights the state of the West Coast regional transmission network.The existing transmission network is set out geographically in Figure 16-1 andschematically in Figure 16-2.Figure 16-2: West Coast transmission schematic110 kVNELSON - MARLBOROUGHStoke Argyle StokeSTC11 kV220 kVKikiwaWaimangaroa110 kVOrowaitiWestportRobertsonStreet(Buller Electricity)110 kV11 kVMurchison110 kVInangahuaIslingtonCANTERBURY11 kV110 kVAtarauGreymouth(Westpower) 110 kV11 kV 66 kV11 kV33 kVReeftonDobson33 kV66 kVKEY220kV CIRCUIT110kV CIRCUIT50/66kV CIRCUITSUBSTATION BUSTRANSFORMER3 WDG TRANSFORMERHokitika(Westpower)11 kV66 kVKumara(Westpower)STCTEE POINTLOADCAPACITORSTATCOM66 kVOtira66 kV11 kV11 kVArthur’s Pass66 kV66 kVCastle Hill11 kVColeridgeCANTERBURY2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 271

Chapter 16: West Coast Region16.2.1 Transmission into the regionThe West Coast region is connected to the National Grid via a 220/110 kVinterconnection at Kikiwa and two 66 kV circuits from Coleridge. The 220/110 kVinterconnection at Kikiwa is effectively operating in parallel with the transformer atStoke (in the Nelson–Marlborough region).The regional generation is lower than the regional demand. Most of the regional loadis supplied from remote generation in the Waitaki Valley, with significant load off-takein the South Canterbury and Canterbury regions.16.2.2 Transmission within the regionThe transmission within the region:comprises 110 kV and 66 kV transmission circuits, with two 110/66 kVinterconnecting transformers at Dobsonconnects to the rest of the National Grid through two 220/110 kV interconnectingtransformers at Kikiwa (one on standby) and two 66 kV circuits at Coleridge, andderives reactive support from a STATCOM at Kikiwa and capacitor banks atGreymouth and Hokitika.Most of the assets at Robertson Street, Reefton, Atarau, Greymouth, and Hokitika areowned by the associated local lines company (Westpower or Buller Network).The West Coast load is mostly supplied from the northern infeed, with power flowingthrough the region via the 110 kV:circuits from Kikiwa to Dobson via Inangahua, andspur from Inangahua to Robertson Street and Westport.Some loads are fed from the south via low capacity 66 kV circuits from Coleridge,which also provide significant voltage support to the region.16.2.3 Longer-term development pathThe 220/110 kV interconnection at Kikiwa is effectively operating in parallel with the220/110kV interconnecting transformer at Stoke. In the longer-term, the transformercapacity needs to be increased at Kikiwa and/or Stoke to meet load growth andtransmission security requirements to the West Coast region.Possible transmission reinforcement via a third 110 kV circuit connecting betweenKikiwa and Inangahua, additional reactive support, 66 kV transmissionreconfiguration (Kawhaka bonding), and Dobson–Greymouth capacity upgrades maybe required to support the load growth and transmission security in the West Coastregion in the longer-term.Transmission system developments may also be required if there is furthergeneration development. If there is a significant increase in generation, then some ofthe circuits between Kikiwa and Inangahua may need to be operated at 220 kV.16.3 West Coast demandThe after diversity maximum demand (ADMD) for the West Coast region is forecast togrow on average by 2.3% annually over the next 15 years, from 61 MW in 2013 to86 MW by 2028. This is higher than the national average demand growth of 1.5%annually.2722013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 16: West Coast RegionFigure 16-3 shows a comparison of the 2012 and 2013 APR forecast 15-yearmaximum demand (after diversity 144 ) for the West Coast region. The forecasts arederived using historical data, and modified to account for customer information, whereappropriate. The power factor at each grid exit point is also derived from historicaldata. See Chapter 4 for more information about demand forecasting.Figure 16-3: West Coast region after diversity maximum demand forecastTable 16-1 lists forecast peak demand (prudent growth) for each grid exit point in theWest Coast region for the forecast period, as required for the Grid Reliability Report.Table 16-1: Forecast annual peak demand (MW) at West Coast grid exit points to 2028Grid exitpointPowerfactorNext 5 yearsPeak demand (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Arthur’s Pass 1.00 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4Atarau 1.00 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0Castle Hill 1.00 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8Dobson 0.98 16.3 16.6 16.9 17.2 17.5 17.8 18.4 19.0 19.7 20.3 21.0Greymouth 0.98 15.3 15.6 15.9 16.2 16.6 16.9 17.6 18.3 19.0 19.6 20.3Hokitika 0.98 16.9 21.2 21.4 21.7 22.0 22.2 22.8 23.4 23.9 24.5 25.1Kikiwa 1.00 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0Kumara 0.95 1.9 1.9 1.9 1.9 1.9 1.9 1.9 1.9 1.9 1.9 1.9Murchison 0.98 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0Robertson1 0.99 12.2 15.5 18.7 19.0 19.2 19.5 20.1 20.6 21.2 21.7 22.3StreetOtira 0.78 0.7 0.7 0.7 0.7 0.7 0.7 1.5 1.5 1.5 1.5 1.5Reefton 0.99 11.2 11.4 11.7 11.9 12.1 12.4 12.9 13.4 13.9 14.4 14.9Westport 0.96 10.1 10.3 10.4 10.6 10.7 10.9 11.2 11.6 11.9 12.2 12.6144 The after diversity maximum demand (ADMD) for the region will be less than the sum of theindividual grid exit point peak demands, as it takes into account the fact that the peak demand doesnot occur simultaneously at all the grid exit points in the region.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 273

Chapter 16: West Coast RegionGrid exitpointPowerfactorNext 5 yearsPeak demand (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 20281. The customer AMP advises of new mining loads likely in 2014.16.4 West Coast generationThe West Coast region’s generation capacity is 30 MW, which is lower than the localdemand and the deficit is imported through the National Grid.Table 16-2 lists the generation forecast for each grid injection point in the West Coastregion for the forecast period, as required for the Grid Reliability Report. This includesall known generation stations including those embedded within the relevant local linescompany’s network (Westpower, Buller Networks, Network Tasman, or Orion). 145Kumara does not have significant water storage but is expected to supply an averageof 4 MW during summer peaks. The new 6 MW Amethyst “run of the river” hydroproject and the Kawatiri Energy Lake Rochfort Hydro scheme are both expected to beoperational in 2013.Table 16-2: Forecast annual generation capacity (MW) at West Coast grid injectionpoints to 2028 (including existing and committed generation)Grid injectionpoint (location ifembedded)Next 5 yearsGeneration capacity (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Dobson (Arnold) 3 3 3 3 3 3 3 3 3 3 3Hokitika(Amethyst)Hokitika (McKaysCreek)Hokitika (Wahapo-Okarito Forks)6 6 6 6 6 6 6 6 6 6 61 1 1 1 1 1 1 1 1 1 13 3 3 3 3 3 3 3 3 3 3Robertson Street(Kawatiri Hydro) 1 4 4 4 4 4 4 4 4 4 4 4Kumara (Kumara2 10 10 10 10 10 10 10 10 10 10 10and Dillmans)Kumara (HokitikaDiesel)3 3 3 3 3 3 3 3 3 3 31. As advised in the Buller Electricity Asset Management Plan 2012.2. Kumara and Dillmans share the same water and are offered into the market as a single 10 MWgenerator.16.5 West Coast significant maintenance workOur capital project and maintenance works are integrated to enable system issues tobe resolved if possible when assets are replaced or refurbished. Table 16-3 lists thesignificant maintenance-related work 146 proposed for the West Coast region for thenext 15 years that may significantly impact related system issues or connectedparties.145 Only generators with capacity greater than 1 MW are listed. Generation capacity is rounded to thenearest megawatt.146 This may include replacement of the asset due to its condition assessment.2742013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 16: West Coast RegionTable 16-3: Proposed significant maintenance workDescriptionArthur’s Pass supply transformerexpected end-of-lifeCastle Hill supply transformerexpected end-of-lifeMurchison supply transformerexpected end-of-lifeKikiwa 220/110/11 kVtransformer replacementWestport 11 kV switchboardreplacementTentativeyearRelated system issues2013-2015 There is no n-1 security at Arthur’s Pass. Futureinvestment will be customer-driven. See Section16.8.4 for more information.2013-2015 There is no n-1 security at Castle Hill. Futureinvestment will be customer-driven. See Section16.8.5 for more information.2016-2018 No n-1 security at Murchison. Future investmentwill be customer-driven. See Section 16.8.8 formore information.2022-2024 Upgrading the transformer’s capacity and operatingin parallel with Kikiwa–T2. See Section 16.8.2 and16.8.3.2015-2017 No system issues are identified within the forecastperiod.16.6 Future West Coast projects summary and transmission configurationTable 16-4 lists projects to be carried out in the West Coast region within the next 15years.Figure 16-4 shows the possible configuration of West Coast transmission in 2028,with new assets, upgraded assets and assets undergoing significant maintenancewithin the forecast period.Table 16-4: Projects in the West Coast region up to 2028Circuit/site Projects StatusArthur’s Pass Replace the supply transformer. ProposedCastle Hill Replace the supply transformer. ProposedDobsonResolve the protection limits on the supply transformers.Resolve the supply transformer’s branch limiting component.Install new capacitors.PossiblePossiblePossibleDobson–Greymouth Increase the line thermal capacity. PossibleHokitikaInangahua–Murchison–KikiwaIncrease the line thermal capacity between Kumara, Hokitikaand Otira.Increase the line thermal capacity.PossiblePossibleKikiwa Replace Kikiwa–T1 with a higher-rated unit. PossibleMurchison Replace the supply transformer. ProposedWestport Replace the 11 kV switchboard. Proposed2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 275

Chapter 16: West Coast RegionFigure 16-4: Possible West Coast transmission configuration in 2028NELSON - MARLBOROUGHStoke Argyle Stoke110 kVSTC11 kVWaimangaroa110 kV220 kVKikiwaWestport11 kV110 kVOrowaiti110 kVRobertsonStreet(Buller Electricity)110 kVInangahua11 kVMurchisonIslingtonCANTERBURYAtarauGreymouth(Westpower) 110 kV11 kV33 kVReefton11 kV66 kV*Dobson33 kV66 kVKEYHokitika(Westpower)11 kV66 kVKumara(Westpower)KawhakaNEW ASSETSUPGRADED ASSETSASSETS SCHEDULEDFOR REPLACEMENTMINOR UPGRADE*66 kVOtira66 kV66 kVArthur’s PassCastle Hill66 kVColeridgeCANTERBURY16.7 Changes since the 2012 Annual Planning ReportTable 16-5 lists the specific issues that are either new or no longer relevant within theforecast period when compared to last year's report.Table 16-5: Changes since 2012IssuesNo new issues and no projects have been completed since 2012ChangeNo change16.8 West Coast transmission capabilityTable 16-6 summarises issues involving the West Coast region for the next 15 years.For more information about a particular issue, refer to the listed section number.2762013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 16: West Coast RegionTable 16-6: West Coast region transmission issuesSectionnumberIssueRegional16.8.1 Inangahua–Murchison–Kikiwa transmission capacity16.8.2 Kikiwa interconnecting transformer capacity16.8.3 West Coast low voltageSite by grid exit point16.8.4 Arthur’s Pass transmission and supply security16.8.5 Castle Hill transmission and supply security16.8.6 Dobson supply transformer capacity16.8.7 Hokitika transmission capacity16.8.8 Kikiwa supply security16.8.9 Murchison transmission and supply security16.8.10 Otira supply securityBus security16.9.1 Transmission bus security16.9.2 West Coast voltage quality and transmission capacity16.8.1 Inangahua–Murchison–Kikiwa transmission capacityProject reference: IGH_MCH_KIK-TRAN-EHMT-01Project status/type: Possible, Base CapexIndicative timing: 2022Indicative cost band: Thermal upgrade: ASpecial protection scheme: To be advisedIssueThere are two parallel 110 kV circuits between Inangahua and Kikiwa, the:110 kV Inangahua–Murchison–Kikiwa circuit, rated at 56/68 MVA(summer/winter), and110 kV Inangahua–Kikiwa–2 circuit, rated at 92/101 MVA (summer/winter).An outage of the 110 kV Inangahua–Kikiwa–2 circuit will cause:the parallel 110 kV Inangahua–Murchison–Kikiwa circuit to overload fromapproximately 2022, andlow voltage at the West Coast 110 kV bus from approximately 2026 (see Section16.8.3 for more information).SolutionPossible options to resolve the transmission capacity issue include:thermally upgrading the 110 kV Inangahua–Murchison–Kikiwa circuit, ora special protection scheme to trip load post-contingency.The preferred option is to thermally upgrade the 110 kV Inangahua–Murchison–Kikiwa circuit. However, initial application of the Grid Investment Test indicates thatthis option has no overall economic benefit. We will investigate other options toresolve this issue closer to the need date.See Section 16.8.3 for possible options to resolve the low voltage issue.Easements may be required for some parts of the thermal upgrade project.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 277

Chapter 16: West Coast Region16.8.2 Kikiwa interconnecting transformer capacityProject reference:Project status/type:Indicative timing:Indicative cost band:KIK-POW_TFR-EHMT-01Possible, Base CapexTo be advisedBIssueThere are two 220/110 kV interconnecting transformers at Kikiwa, T1 and T2 rated at50 MVA and 150 MVA, respectively. The normal operating arrangement is to haveKikiwa–T1 supply the local 11 kV load only and Kikiwa–T2 providing the 110 kVinterconnection with the West Coast region. Kikiwa–T2 also operates in parallel withthe 150 MVA Stoke–T7 interconnecting transformer in the Nelson-Marlborough regiondue to the 110 kV network connections between them.The loss of the Stoke interconnecting transformer means the Kikiwa interconnectingtransformer supplies both the West Coast and Nelson-Marlborough load, which mayoverload for:high West Coast and Nelson-Marlborough loads, andlow generation in the West Coast and Nelson-Marlborough regions.SolutionThis issue may be managed operationally with generation from Cobb and Kumara forthe forecast period (provided water is available). Transpower will work with thegenerators to manage this constraint.A possible longer-term option is to replace Kikiwa–T1 with a higher-rated transformerthat can operate in parallel with Kikiwa–T2 and Stoke–T7.16.8.3 West Coast low voltageProject reference: WCST-C_BANKS-DEV-01Project status/type: Possible, Base CapexIndicative timing: 2027Indicative cost band: New capacitors: ASpecial protection scheme: to be advisedIssueLow voltage will occur on the 110 kV transmission system in the region towards theend of the forecast period following an outage of the:Kikiwa–T2 interconnecting transformer, or110 kV Inangahua–Kikiwa–2 circuit.SolutionThe 110 kV low voltage issues can be addressed by a local voltage qualityagreement if appropriate for the short term. Possible transmission solutions include:installing new capacitors at Dobsona special protection scheme to shed load post contingency, andreplacing Kikiwa–T1 with a higher-rated transformer, which will address the lowvoltage issue following a Kikiwa–T2 outage (this option also resolves the Kikiwainterconnecting transformer capacity issue described in Section 16.8.2).We will investigate options closer to the need date.2782013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 16: West Coast Region16.8.4 Arthur’s Pass transmission and supply securityProject status/type:This issue is for information onlyIssueThe two circuits supplying Arthur’s Pass only have line circuit breakers and protectionat Coleridge and Otira. A fault on any section of the Coleridge–Castle Hill–Arthur’sPass–Otira circuits will result in a loss of supply to Arthur’s Pass load.Additionally, a single 66/11 kV, 3 MVA transformer supplies load at Arthur’s Pass,resulting in no n-1 security. Load growth is not forecast to exceed the transformerrating within the forecast period.SolutionThe lack of n-1 security can be managed operationally. There is a non-contractedon-site spare transformer, allowing possible replacement within 8 to 14 hoursfollowing a unit failure (if the spare unit is available).This transformer is also approaching its expected end-of-life within the next fiveyears. We will discuss with Orion options for increasing security and coordinatingoutages to minimise supply interruptions when replacing this transformer.16.8.5 Castle Hill transmission and supply securityProject status/type:This issue is for information onlyIssueThe two circuits supplying Castle Hill only have line circuit breakers and protection atColeridge and Otira. A fault on any section of the Coleridge–Castle Hill–Arthur’sPass–Otira circuits will result in a loss of supply to Castle Hill load.Additionally, a single 66/11 kV, 3.75 MVA transformer supplies load at Castle Hill,resulting in no n-1 security. Load growth is not forecast to exceed the transformerrating within the forecast period.SolutionThe lack of n-1 security can be managed operationally. There is a non-contractedon-site spare transformer, allowing possible replacement within 8 to 14 hoursfollowing a unit failure (if the spare unit is available).This transformer is also approaching its expected end-of-life within the next fiveyears. We will discuss with Orion options for increasing security and coordinatingoutages to minimise supply interruptions when replacing this transformer.16.8.6 Dobson supply transformer capacityProject reference:Project status/type:Indicative timing: 2024Indicative cost band: AUpgrade protection: DOB-POW_TFR-EHMT-01Upgrade protection: possible, Base CapexIssueTwo 66/33 kV transformers supply Dobson’s load, providing:a nominal installed capacity of 40 MVA, and2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 279

Chapter 16: West Coast Regionn-1 capacity of 17/17 MVA 147 (summer/winter).The peak load at Dobson is forecast to exceed the transformers’ n-1 winter capacityby approximately 1 MW in 2024, increasing to approximately 2 MW in 2028,assuming 3 MW from the embedded generation at Arnold 148 (see Table 16-7).Table 16-7: Dobson supply transformer overload forecastCircuit/Gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Dobson 0.98 0 0 0 0 0 0 0 0 1 2 2SolutionWe will use operational measures (Arnold generation) in the short to medium term.Possible longer-term options include resolving the transformers’ protection and LVcable limits (providing n-1 capacity beyond the forecast period) or increasing theembedded generation. Options will be investigated closer to the need date. Futureinvestment will be customer driven.16.8.7 Hokitika transmission capacityProject reference:Project status/type:Indicative timing: 2020Indicative cost band: CHKK-TRAN-EHMT-01Possible, Base CapexIssueTwo circuits supply the Hokitika grid exit point:Hokitika–Kumara rated at 27/32 MVA (summer/winter), andHokitika–Otira rated at 27/32 MVA (summer/winter).An outage of one circuit will cause the other to exceed its thermal capacity from 2020.The 66 kV line from Coleridge to Kumara is predominantly strung with a copperconductor, and therefore cannot be thermally upgraded.SolutionTranspower will investigate options closer to the need date. Previous investigationsidentified a system reconfiguration including:decommissioning the Kumara–Otira circuitbonding the circuits between Kumara and Kawhaka 149 , and between Otira andKawhaka, andreconductoring the low-capacity section of the line from Kawhaka to Hokitika, andthermally upgrading the other section.This maintains n-1 security to Hokitika by providing two higher-capacity circuits.147 The transformers’ capacity is limited by protection equipment, followed by the LV cable (21 MVA)limits; with these limits resolved, the n-1 capacity will be 22/23 MVA (summer/winter).148 Arnold is very reliable in producing 3 MW of generation, so its output is considered in the overloadforecast. Without Arnold, there is an overload of 1 MW in 2013, increasing to 3 MW in 2020.149 Kawhaka is the point where the lines carrying the Kumara–Otira, Otira–Hokitika and Hokitika–Kumara circuits meet.2802013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 16: West Coast RegionThe overloading then shifts to the Dobson–Greymouth circuit. Options to addressthis issue include constraining on generation at Kumara, thermally upgrading thecircuit, or load transfer from Greymouth to Dobson.The previous investigations, however, also indicated that the system reconfigurationmay be uneconomic. An alternative is to automatically reduce load at Hokitikafollowing a circuit outage, causing a partial loss of supply.We will investigate the appropriate solution for this issue closer to the need date.16.8.8 Kikiwa supply securityProject status/type:This issue is for information onlyIssueThe Kikiwa load is normally supplied from the 11 kV tertiary winding of Kikiwa–T1interconnecting transformer, with a backup supply from the T2 interconnectingtransformer. Transferring the load between T1 and T2 requires a short interruption tothe load.An outage of the 11 kV switchgear or fault limiting reactor requires a total loss ofsupply, so there is no n-1 security for these assets.SolutionThe brief interruption to load and lack of n-1 security can be managed operationally.Future investment will be customer driven.16.8.9 Murchison transmission and supply securityProject status/type:This issue is for information onlyIssueThe load at Murchison is supplied by:two circuits, which do not have line circuit breakers at Murchison, anda single 110/11 kV, 5 MVA transformer.A fault on either circuit or the supply transformer will result in a loss of supply toMurchison.There is a short duration loss of supply whenever the circuits supplying Murchisonare switched for maintenance.SolutionThe lack of n-1 security can be managed operationally. We are installingdisconnecting circuit breakers to avoid the loss of supply to Murchison duringswitching for line maintenance.Additionally, the supply transformer has an expected end-of-life within the forecastperiod. We will discuss options with Network Tasman for increasing security andcoordinating outages to minimise supply interruptions when replacing the Murchisonsupply transformer.16.8.10 Otira supply securityProject status/type:This issue is for information only2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 281

Chapter 16: West Coast RegionIssueOtira is supplied by a single 66/11 kV, 2.5 MVA transformer, resulting in no n-1security. Load growth is not forecast to exceed the transformer rating within theforecast period.SolutionThe Otira transformer is a three-phase unit. The lack of n-1 security can be managedoperationally.16.9 West Coast bus securityThe 2013 APR has been expanded to include issues arising from the outage of asingle bus section rated at 50 kV and above for the next 15 years.Bus outages disconnect more than one power system component (for example, othercircuits, transformers, reactive support or generators). Therefore, bus outages maycause greater issues than a single circuit or transformer outage (although the risk of abus fault is low, being less common than a circuit or transformer outage).16.9.1 Transmission bus securityTable 16-8 lists bus outages that cause voltage issues or a total loss of supply.Generators are included only if a bus outage disconnects the whole generationstation or causes a widespread system impact. Supply bus outages, typically 11 kVand 33 kV, are not listed.Table 16-8: Transmission bus outagesTransmissionbus outageArthur’s Pass 66 kVAtarau 110 kVCastle Hill 66 kVLoss ofsupplyArthur’s PassAtarauCastle HillGenerationdisconnectionTransmissionissueFurtherinformationColeridge 66 kV Arthur’s Pass See note 1Dobson 66 kVCastle Hill See note 1DobsonKikiwa 110 kV West Coast load 16.9.2Kikiwa 220 kVInangahua 110 kVMurchison 110 kVKikiwaWest Coast load 16.9.2Robertson StreetWest Coast load 16.9.2WestportMurchisonOtira 66 kV Arthur’s Pass See note 1Castle Hill See note 1Otira1. There is no bus protection at Coleridge or Otira, so bus faults remove all connected circuits fromservice. This includes the Coleridge–Castle Hill–Arthur’s Pass–Otira circuit, causing a loss of supplyat Castle Hill and Arthur’s Pass.The customers (Buller Networks, Westpower, Network Tasman, or Orion) have notrequested a higher security level. If increased bus security is required, the optionstypically include bus reconfiguration and/or additional bus circuit breakers. Futureinvestment will be customer driven.2822013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 16: West Coast Region16.9.2 West Coast voltage quality and transmission capacityProject status/type:This issue is for information onlyIssueThe West Coast 110 kV load is mainly supplied from the National Grid via two 110 kVInangahua–Kikiwa circuits, with lower capacity 66 kV backup circuits from Coleridge.There are single 110 kV bus sections at Kikiwa and at Inangahua, so a bus outagewill disconnect both circuits. This will cause:low voltage issues at all 110 kV and 66 kV buses, andtransmission circuit capacity issues in the West Coast region.The effect of the low voltages and circuit overloading is difficult to predict. Theoutcome is heavily influenced by the local generation and load composition at thetime of the outage. The low voltages may cause enough motor load to trip so thetransmission system stays intact and continues to supply the remaining load.Otherwise, one or more circuits will trip, causing a total loss of supply to some or all ofthe grid exit points in the region.In addition, an outage of the Kikiwa 220 kV bus, which disconnects the Kikiwa–T2interconnecting transformer, will cause the transmission bus voltages in the region tofall below 0.90 pu towards the end of the forecast period.SolutionThe customers (Westpower, Buller Networks, Network Tasman, and Orion) have notrequested a higher security level and there are no plans to increase bus security.Replacing the Kikiwa–T1 interconnecting transformer with a higher rated unit (seeSections 16.8.2 and 16.8.3) will address the issue of a Kikiwa 220 kV bus outage.16.10 Other regional items of interestThere are no other items of interest identified to date beyond those inSection 16.8 and 8.9. See Section 8.11 for information about generation scenarios,proposals and opportunities relevant to this region.16.11 West Coast generation scenarios, proposals and opportunitiesThis section details relevant regional issues for selected generation scenarios,generation proposals under investigation by developers and in the public domain, orother generation opportunities. The impact of committed generation projects on thegrid backbone is dealt with separately in Chapter 6.The maximum generation that can be connected depends on several factors andusually falls within a range. Generation developers should consult with us at an earlystage of their investigations to discuss connection issues.16.11.1 Impact of generation scenarios on regional planThe generation scenarios (see Chapter 5) represent a series of possible futuregeneration outcomes. This section presents only those scenarios relevant to thisregion for the next 15 years.All generation scenarios except scenario 3 anticipate some new generationconnections in the West Coast region.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 283

Chapter 16: West Coast RegionAt Dobson, generation may connect to the 66 kV or 33 kV bus. If generation isconnected to the 33 kV bus, generation may be constrained by the 66/33 kV supplytransformer capacity under light load conditions and for supply transformer outages.Generation scenario 2 anticipates a total of 115 MW generation connections onto theInangahua–Waimangaroa–Robertson Street–Westport spur. Section 16.11.3discusses the impacts and the likely system developments to relieve the constraints.16.11.2 Maximum regional generationMaximum generation estimates assume a South Island light load profile and that thegeneration in the West Coast region is high (with Kumara generating 10 MW).For generation connected at the Kikiwa 220 kV bus, the maximum generation thatcan be injected under n-1 is approximately 800 MW. The constraint is the Islington–Kikiwa–2 or 3 circuit when either one of the two circuits is out of service.For a West Coast load of 35 MW, the estimated maximum generation injection 150 atthe two key busses is as follows:At the Kikiwa 110 kV bus, under normal operating conditions, the maximum is260 MW to avoid overloading the Kikiwa–T2 interconnecting transformer. Thegeneration injection value decreases to approximately 135 MW for an outage ofKikiwa–T2 to avoid overloading the 110 kV Kikiwa–Stoke circuitsAt the Inangahua 110 kV bus under normal operating conditions, the maximum isapproximately 165 MW to avoid overloading the 110 kV Inangahua–Murchison–Kikiwa–1 circuit. The generation injection value decreases to approximately95 MW for an outage of the 110 kV Inangahua–Murchison–Kikiwa–2 circuit toavoid overloading the Kikiwa–Stoke circuit.Generation connected to the West Coast 66 kV transmission network may beconstrained by several low capacity 66 kV circuits.16.11.3 Generation connected to the Inangahua to Westport spurTwo circuits form the Inangahua to Westport spur, with substations at Waimangaroa,Robertson Street and Westport. The Inangahua–Waimangaroa–1 circuit is rated at101/111 MVA (summer/winter) and the Inangahua–Waimangaroa–2 circuit is rated at56/68 (summer/winter).Depending on the amount of generation connected to the spur, it may be necessaryto:close the split at the Waimangaroa 110 kV businstall a special protection scheme to allow unconstrained generation injection,and/orincrease the circuit capacity between Waimangaroa, Inangahua, and Kikiwa.Generation connected to the spur also forms part of the maximum level of generationthat can be connected within the region (see Section 16.11.2).150 The generation injection at a bus applies if the generation is connected directly at the bus, orindirectly at other locations within the region. For example, generation at Dobson or along theWaimangaroa spur connects indirectly to the Inangahua bus and Kikiwa bus. Generation connectedto the 110 kV system in the Nelson–Marlborough region (Chapter 15) also injects indirectly to theKikiwa 110 kV bus.2842013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 17:Canterbury Region17 Canterbury Regional Plan17.1 Regional overview17.2 Canterbury transmission system17.3 Canterbury demand17.4 Canterbury generation17.5 Canterbury significant maintenance work17.6 Future Canterbury projects summary and transmission configuration17.7 Changes since the 2012 Annual Planning Report17.8 Canterbury transmission capability17.9 Canterbury bus security17.10 Other regional items of interest17.11 Canterbury generation scenarios, proposals and opportunities17.1 Regional overviewThis chapter details the Canterbury regional transmission plan. We base this regionalplan on an assessment of available data, and welcome feedback to improve its valueto all stakeholders.Figure 17-1: Canterbury regionConstruction voltages shown. System as at March 2013.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 285

Chapter 17: Canterbury RegionThe Canterbury region load includes Christchurch together with smaller rurallocalities.We have assessed the Canterbury region’s transmission needs over the next 15years while considering longer-term development opportunities. Specifically, thetransmission network needs to be flexible to respond to a range of future service andtechnology possibilities, taking into consideration:the existing transmission networkforecast demandforecast generationequipment replacement based on condition assessment, andpossible technological development.17.2 Canterbury transmission systemThis section highlights the state of the Canterbury regional transmission network.The existing transmission network is set out geographically in Figure 17-1 andschematically in Figure 17-2.Figure 17-2: Canterbury transmission schematicKEY220kV CIRCUIT66kV CIRCUITSUBSTATION BUSNELSON - MARLBOURGHKikiwaKikiwa66 kV33 kVCulverdenTRANSFORMERTEE POINTLOADCAPACITORWaipara33 kVSCsvc3 WDG TRANSFORMERREACTORGENERATORSYNCHRONOUS CONDENSERSTATIC VAR COMPENSATORAshley66 kV11 kV66 kV66 kVSouthbrook33 kVLines company assets1 August 2012WEST COASTOtira Castle Hill66 kV11 kVKaiapoiPapanui11 kV66 kV66 kVAddington11 kVColeridge66 kV11 kV66 kV 33 kVHororata66 kVSCSCSVCIslingtonSVC11 kV66 kV33 kV220 kVBromley11 kV66 kV220 kVTekapo BLivingstoneSOUTH CANTERBURYTwizelAshburton66 kV66 kV220 kV33 kV33 kVSpringston17.2.1 Transmission into the regionThe Canterbury region has some of the highest load densities in the South Island,coupled with relatively low levels of local generation. As Canterbury’s peak electricitydemand is supplied by generation located in the South Canterbury region,transmission is necessary to keep power flowing into and through the region to thetop of the South Island.2862013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 17:Canterbury Region17.2.2 Transmission within the regionFrom the Waitaki Valley, the region is supplied by four 220 kV transmission circuits,three from Twizel and one from Livingstone. The transmission network within thisregion comprises 220 kV and 66 kV transmission circuits, with 220/66 kVinterconnecting transformers at Islington, Bromley, and Waipara.There are eight 220/66 kV interconnecting transformers: three at Bromley, three atIslington and two at Waipara.Reactive support for the region (and grid backbone) is provided by:synchronous condensers, static var compensators, and capacitor banks atIslingtoncapacitor banks at Bromley, anda single 33 Mvar capacitor at Southbrook.17.2.3 Longer-term development pathWe are investigating transmission capacity enhancement and future reactive supportrequirements in the Canterbury region and the Upper South Island to increase boththermal constraints and voltage stability limits. This is to ensure that Canterbury hassecure transmission into and through the region, as demand continues to grow.Beyond the next 30 years, new transmission capacity may be required into theCanterbury region, provided by a new 220 kV line, an HVDC tap-off, or therefurbishment of the existing lines. New generation in the Upper South Island ordemand-side responses may defer transmission investment.17.3 Canterbury demandThe after diversity maximum demand (ADMD) for the Canterbury region is forecast togrow on average by 2.0% annually over the next 15 years, from 783 MW in 2013 to1,034 MW by 2028. This is higher than the national average demand growth of 1.5%annually.The after effects of the September 2010 earthquake and the significant February2011 aftershock centred in Christchurch have affected electricity demand in theCanterbury region. The latest forecast was determined after discussion with OrionNetworks, which reported an approximate 10% reduction in energy demand sinceFebruary 2011, although this did not flow through to peak demand for the year due toan unusually cold weather event in August. We have made suitable adjustments toour models to account for the earthquake impact and also allow for much of the lostdemand to slowly return and this feeds into the higher than average regional growthrate forecast.Figure 17-3 shows a comparison of the 2012 and 2013 APR forecast 15-yearmaximum demand (after diversity 2 ) for the Canterbury region. The forecasts arederived using historical data, and modified to account for customer information, whereappropriate. The power factor at each grid exit point is also derived from historicaldata. See Chapter 4 for more information about demand forecasting.2The after diversity maximum demand (ADMD) for the region will be less than the sum of theindividual grid exit point peak demands, as it takes into account the fact that the peak demand doesnot occur simultaneously at all the grid exit points in the region.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 287

Chapter 17: Canterbury RegionFigure 17-3: Canterbury region after diversity maximum demand forecastTable 17-1 lists forecast peak demand (prudent growth) for each grid exit point for theforecast period, as required for the Grid Reliability Report.Table 17-1: Forecast annual peak demand (MW) at Canterbury grid exit points to 2028Grid exit pointPowerfactorNext 5 yearsPeak demand (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Addington 11 kV 7 0.99 71 74 76 79 80 81 83 85 88 90 92Addington 66 kV 7 0.99 100 104 107 110 114 117 125 130 133 136 140Ashburton 33 kV 1 0.96 28 29 30 30 23 0 0 0 0 0 0Ashburton 66 kV 1 0.92 146 149 153 157 166 185 194 203 212 221 230Ashley 2 0.91 13 15 21 21 22 22 23 25 26 27 29Bromley 11 kV 7 0.99 41 42 43 44 45 45 46 47 48 49 50Bromley 66 kV 7 1.00 115 119 122 125 129 132 139 144 147 150 153Coleridge 0.99 1 1 1 1 1 1 1 1 1 1 1Culverden 33 kV 3 0.98 19 20 20 21 22 23 25 27 29 30 32Hororata 33 kV 6 0.95 30 25 25 25 26 18 19 19 20 21 22Hororata 66 kV 5,6 0.97 28 28 18 18 18 27 27 28 29 29 30Islington 33 kV 0.97 80 81 82 83 84 85 87 89 91 94 96Islington 66 kV 6,7 1.00 89 90 91 92 93 95 97 99 102 104 107Islington 66 kV–7 1.00 121 122 124 126 128 130 134 138 142 146 150PapanuiKaiapoi 1.00 28 28 29 29 30 30 32 33 34 35 37Kimberley 4 0.95 0 12 12 13 17 17 17 19 19 19 19Middleton 7 0.97 32 33 33 34 34 35 36 37 38 39 40Southbrook 2 0.97 45 46 44 46 47 48 51 53 56 58 61Springston 33 kV 5 0.99 51 37 38 39 39 35 36 38 39 40 422882013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 17:Canterbury RegionGrid exit pointPowerfactorNext 5 yearsPeak demand (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Springston 66 kV 5 0.99 23 42 64 64 68 79 79 80 81 81 82Waipara 33 kV 2 0.96 9 7 7 7 8 8 8 8 8 8 9Waipara 66 kV 0.95 12 13 13 13 14 14 15 15 16 17 171. This forecast allows for strong growth, including some migration of load from Christchurch, loadswitching between Ashburton 33 kV and Ashburton 66 kV, and a staged migration from Ashburton 33kV over 2014 to 2021.2. The customer advised that the Ashley grid exit point will be upgraded by 2014 to supply thesurrounding Ashley, Loburn and Balcairn areas currently supplied from Southbrook and Waipara.3. The customer expects ongoing irrigation load increases.4. The new Kimberley grid exit point will operate from 2014 for load associated with Darfield Dairy plantand irrigation schemes.5. The customer advised of future load shifts associated with their Larcomb, Highfield and Dunsandelsubstations.6. The customer advised of future load shift associated with their Hororata substation.7. The customer is developing their network. The customer forecasts a different distribution of loadbetween grid exit points, but the total is largely in agreement with Transpower’s forecast.17.4 Canterbury generationThe Canterbury region’s generation capacity is 79 MW, which is lower than localdemand and the deficit is imported through the National Grid from the Waitaki valley.Table 17-2 lists the generation forecast for each grid injection point for the forecastperiod, as required for the Grid Reliability Report. This includes all known andcommitted generation stations including those embedded within the relevant locallines company’s network (Electricity Ashburton, Orion or Mainpower). 151No new generation is known to be committed in the Canterbury region for the forecastperiod.Table 17-2: Forecast annual generation capacity (MW) at Canterbury grid injectionpoints to 2028 (including existing and committed generation)Grid injection point(location ifembedded)Next 5 yearsGeneration capacity (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Ashburton (Highbank) 25 25 25 25 25 25 25 25 25 25 25Ashburton (Montalto) 2 2 2 2 2 2 2 2 2 2 2Bromley (City Waste) 3 3 3 3 3 3 3 3 3 3 3Bromley (QE2 diesel) 4 4 4 4 4 4 4 4 4 4 4Coleridge 45 45 45 45 45 45 45 45 45 45 4517.5 Canterbury significant maintenance workOur capital project and maintenance works are integrated to enable system issues tobe resolved if possible when assets are replaced or refurbished.Table 17-3 lists the significant maintenance-related work 152 proposed for theCanterbury region for the next 15 years that may significantly impact related systemissues or connected parties.151 Only generators with a capacity greater than 1 MW are listed. Generation capacity is rounded to thenearest megawatt.152 This may include replacement of the asset due to its condition assessment.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 289

Chapter 17: Canterbury RegionTable 17-3: Proposed significant maintenance workDescriptionAddington 11 kV switchboard No.2replacement, andAddington supply transformersexpected end-of-lifeAshley supply transformersexpected end-of-lifeBromley 220/66 kV transformersexpected end-of-lifeBromley 66/11 kV transformer’sexpected end-of-lifeHororata 33 kV outdoor to indoorconversionIslington–T3 and T7 interconnectingtransformers expected-end-of-life,and Islington 33 kV outdoor toindoor conversionKaiapoi 11 kV switchgearreplacementSpringston 33 kV outdoor to indoorconversionWaipara 33 kV outdoor to indoorconversionTentativeyear2013-20162023-2024Related system issuesOrion is planning to reconfigure its 11 kVdistribution system, which will be co-ordinatedwith the switchboard replacement. See Section17.10.3 for more information.2016-2018 The forecast load at Ashley exceeds thetransformers’ n-1 capacity from 2013. SeeSection 17.8.3 for more information.2018-2020 No system issues are identified within theforecast period.2023-2024 No system issues are identified within theforecast period.2018-2020 No system issues are identified within theforecast period.2022-20242017-2019The peak load is forecast to exceed thetransformers’ n-1 capacity from 2019. SeeSection 17.8.1 for more information.2019-2020 No system issues are identified within theforecast period.2015-2017 No system issues are identified within theforecast period.2016-2018 No system issues are identified within theforecast period.17.6 Future Canterbury projects summary and transmission configurationTable 17-4 lists projects to be carried out in the Canterbury region within the next 15years.Figure 17-4 shows the possible configuration of Canterbury transmission in 2028,with new assets, upgraded assets, and assets undergoing significant maintenancewithin the forecast period.Table 17-4: Projects in the Canterbury region up to 2028Circuit/site Projects StatusAddingtonAshburtonAshleyBromleyCulverdenReplace 11 kV switchboard No.2.Replace the T5, T6, and T7 supply transformers.Install a new 220/66 kV supply transformer.Install a new grid exit point (Electricity Ashburton).Replace the existing supply transformers.Install a third 66/11 kV supply transformer.Replace the existing 220/66 kV transformers.Replace the existing 66/11 kV supply transformers.Install a capacitor at Bromley transformer’s tertiary winding.Replace the 220/33 kV transformers with higher capacity 220/66 kVtransformers.ProposedProposedCommittedPossibleProposedPossiblePossiblePossiblePossiblePossibleHororata Convert the 33 kV outdoor switchgear to an indoor switchboard. ProposedIslingtonInstall a new 220/66 kV interconnecting transformer.Replace the existing 220/66 kV interconnecting transformers.Convert the 33 kV outdoor switchgear to an indoor switchboard.Install new grid exit point (Orion)PossibleProposedProposedPossibleKaiapoi Replace the 11 kV switchgear Proposed2902013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 17:Canterbury RegionCircuit/site Projects StatusSouthbrookResolve the supply transformers’ branch component limits.Install two new 66 kV feeders.PossiblePossibleSpringston Convert 33 kV outdoor switchgear to an indoor switchboard. ProposedWaipara Convert 33 kV outdoor switchgear to an indoor switchboard. ProposedFigure 17-4: Possible Canterbury transmission configuration in 2028NELSON - MARLBOURGHKikiwaKikiwaKEYNEW ASSETSUPGRADED ASSETSASSETS SCHEDULEDFOR REPLACEMENTMINOR UPGRADE*66 kVCulverdenWaipara33 kV66 kVAshley66 kV11 kV*Southbrook33 kV*66 kVWEST COASTOtira Castle HillKaiapoi66 kV11 kVMiddleton66 kVAddington11 kVColeridge66 kV11 kV66 kV 33 kVHororata66 kVSVCIslingtonSVC66 kV33 kV220 kV11 kV66 kV220 kVBromleyNew grid exitPoint (Orion)66 kVNew grid exit point(Electricity Ashburton)Tekapo BLivingstoneSOUTH CANTERBURY66 kVTwizel66 kVAshburton66 kV33 kVSpringston220 kV33 kV17.7 Changes since the 2012 Annual Planning ReportThere are no specific issues that are either new or no longer relevant within theforecast period when compared to last year's report.17.8 Canterbury transmission capabilityTable 17-5 summarises issues involving the Canterbury region for the next 15 years.For more information about a particular issue, refer to the listed section number.Table 17-5: Canterbury region transmission issuesSectionnumberIssueRegional17.8.1 Islington 220/66 kV transformer capacitySite by grid exit point17.8.2 Ashburton 220/66 kV supply transformer capacity17.8.3 Ashley supply transformer capacity17.8.4 Bromley 220/66 kV transformer capacity and voltage quality2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 291

Chapter 17: Canterbury RegionSectionnumberIssue17.8.5 Coleridge supply transformer security17.8.6 Culverden supply transformer capacity17.8.7 Hororata and Kimberley voltage quality17.8.8 Hororata supply transformer capacity17.8.9 Southbrook supply transformer capacity17.8.10 Springston transmission capacity17.8.11 Waipara supply transformer securityBus Security17.9.1 Transmission bus security17.9.2 Ashburton bus security17.9.3 Regional low voltage17.8.1 Islington 220/66 kV transformer capacityProject reference:Project status/type:Indicative timing:Indicative cost band:A fourth 220/66 kV transformer: ISL-POW_TFR-DEV-01A new grid exit point (Orion): ISL-SUBEST-DEV-01A fourth 220/66 kV transformer: possible, Base CapexA new grid exit point (Orion): possible, customer-specificA fourth 220/66 kV transformer: to be advisedA new grid exit point: about 2019A fourth 220/66 kV transformer: BA new grid exit point: CIssueThree 220/66 kV interconnecting transformers at Islington supply the loads for NorthCanterbury, Christchurch, and Springston, providing:a total nominal installed capacity of 650 MVA, andn-1 capacity of 504/532 MVA (summer/winter).The peak load at the Islington 66 kV bus is forecast to exceed the transformers’winter n-1 capacity from 2019. The forecast assumes Coleridge generation is13 MW.SolutionA staged development plan was developed in discussion with Orion. The plan’s firststage increases the 220/66 kV transformer capacity at Bromley, and transfers loadfrom Islington to Bromley in 2019 (see Section 17.8.4). Additional longer-termdevelopment options being investigated include:establishing a new 220/66 kV grid exit point south of Christchurch (seeSection 17.10.2), which will also resolve the Springston transmission line capacityissue (see Section 17.8.10) 153replacing the two lowest rated transformers with higher rated transformers, and/orinstalling a fourth 220/66 kV interconnecting transformer at Islington (which willincrease the fault level at Islington, at downstream substations, and associatedsupply buses, which would require resolution).In addition, two of the existing transformers are approaching their expected end-of-lifewithin the next 10-15 years.153 Acquisition of substation land may be required for establishing a new 220/66 kV southern grid exitpoint.2922013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 17:Canterbury RegionThe likely development option is to retain the existing transformers in the short tomedium-term, and transfer load to Bromley and a new south grid exit point. The endof-lifetransformers are likely to be replaced with higher-rated units. In addition, itmay be necessary to install a fourth (system spare) transformer to manage outagesfor maintenance.17.8.2 Ashburton 220/66 kV supply transformer capacityProject reference: New 220/66 kV transformer: ASB-POW_TFR-DEV-02A new grid exit point (Electricity Ashburton): ASB-SUBEST-DEV-01Project status/type: New 220/66 kV transformer: committed, customer-specificA new grid exit point: possible, customer-specificIndicative timing: New 220/66 kV transformer: 2014A new grid exit point: about 2018Indicative cost band: New 220/66 kV transformer: AA new grid exit point: CIssueTwo 220/66 kV transformers supply Ashburton’s 66 kV load, providing:a total nominal installed capacity of 220 MVA, andn-1 capacity of 120/126 MVA (summer/winter).The Ashburton 66 kV bus is connected to embedded generation at Highbank andMontalto, which may export power to the National Grid during periods of low demand.The peak load connected to the Ashburton 66 kV bus is forecast to exceed thetransformer’s n-1 summer capacity by approximately 18 MW in 2013, increasing toapproximately 114 MW in 2028 (see Table 17-6).Table 17-6: Ashburton 220/66 kV supply transformer overload forecastCircuit/Grid exitpointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Ashburton (66 kV) 0.92 18 34 38 41 45 54 77 86 95 105 114SolutionThe committed solution is to install a third 220/66 kV, 120 MVA supply transformer.This will address the transformers n-1 capacity issue beyond the forecast period. Asan interim measure, the load can be secured by transferring load to the Ashburton33 kV transmission network and/or utilising the embedded generation.In the longer term, load may be transferred to a new grid exit point (see Section17.10.1).17.8.3 Ashley supply transformer capacityProject reference: ASY-POW_TFR-EHMT-01Project status/type: Replace transformers with higher-rated units: possible, customer-specificNew 66/11 kV supply: possible, customer-specificIndicative timing: 2016Indicative cost band: Replace transformers with higher-rated units: ANew 66/11 kV supply: AIssueTwo 66/11 kV transformers supply Ashley’s load, providing:a total nominal installed capacity of 20 MVA, andn-1 capacity of 11/12 MVA (summer/winter).2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 293

Chapter 17: Canterbury RegionThe peak load at Ashley is forecast to exceed the transformers’ n-1 winter capacity byapproximately 2 MW in 2013, increasing to approximately 18 MW in 2028 (see Table17-7).Table 17-7: Ashley supply transformer overload forecastCircuit/gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Ashley 0.87 2 4 10 10 11 12 13 14 15 17 18SolutionWe are discussing options with Mainpower to increase the supply capacity at Ashley,which includes:installing higher rated 66/11 kV supply transformers, orinstalling a third 66/11 kV transformer.In addition, the existing supply transformers are approaching their expected end-oflifewithin the next five years. We are discussing the appropriate rating and timing forthe replacement transformers with Mainpower. Future investment will be customerdriven.17.8.4 Bromley 220/66 kV transformer capacity and voltage qualityProject reference: Replace transformers with higher-rated units: BRY-POW_TFR-EHMT-02Install capacitor: BRY-C_BANKS-DEV-01Project status/type: Replace transformers with higher-rated units: possible, customer-specificInstall capacitor: possible, customer-specificIndicative timing: Replace transformers with higher-rated units: 2019Install capacitor: to be advisedIndicative cost band: Replace transformers with higher-rated units: B (cost band for onetransformer)Install capacitor: AIssueThree 220/66 kV transformers supply Bromley’s 66 kV and 11 kV loads, providing:a total nominal installed capacity of 380 MVA, andn-1 capacity of 250/264 MVA (summer/winter).The load on the transformers is radially connected, enabling them to be consideredas supply transformers.Orion is planning to transfer load in 2019 from Islington to Bromley, which will exceedthe transformers’ n-1 capacity. Additional voltage support will also be needed for theincreased load.SolutionTwo of the 220/66 kV transformers at Bromley have an expected end-of-life within thenext 5-10 years. Replacing the two transformers with higher rated units in 2019 willresolve the capacity issue beyond 2019.Installing capacitors at the Bromley transformer’s tertiary winding will resolve the lowvoltage issue. Future investment will be customer driven.17.8.5 Coleridge supply transformer securityProject status/type:This issue is for information only2942013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 17:Canterbury RegionIssueA single 66/11 kV, 2.5 MVA three phase supply transformer supplies the load atColeridge, resulting in no n-1 security.SolutionThere is an off-site spare transformer that can take several days to install. Orionaccepts this level of security. Future investment will be customer driven.17.8.6 Culverden supply transformer capacityProject reference:Project status/type:Indicative timing:Indicative cost band:CUL-POW_TFR-DEV-01Possible, customer-specificTo be advisedTo be advisedIssueTwo 220/33 kV transformers supply the 33 kV and 66 kV loads at Culverden,providing:a total nominal installed capacity of 60 MVA, andn-1 capacity of 31/32 MVA (summer/winter).The peak load at Culverden is forecast to exceed the supply transformers’ n-1summer capacity by approximately 1 MW in 2022, increasing to approximately 7 MWin 2028 (see Table 17-8).Table 17-8: Culverden supply transformer overload forecastCircuit/gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Culverden 0.97 0 0 0 0 0 0 0 1 3 5 7SolutionWe will discuss options with Mainpower closer to the need date. Options includereplacing the existing supply transformers with higher capacity units and changing theoperating voltage to 220/66 kV. Future investment will be customer driven.17.8.7 Hororata and Kimberley voltage quality and transmission capacityProject status/type:This issue is for information onlyIssueHororata and Kimberley 154 substations are supplied from:Islington by two 66 kV Hororata–Kimberley–Islington circuits, each rated at59/62 MVA (summer/winter), andColeridge and the West Coast by two 66 kV Coleridge–Hororata circuits, eachrated at 30/37 MVA (summer/winter).With low Coleridge generation (three of the five units out of service), the combined n-1 load at Hororata and Kimberley must be below approximately 70 MW to avoid low66 kV bus voltages.154 Kimberley is a new 66 kV grid exit point to be commissioned in 2013 (see Section 17.10.4).2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 295

Chapter 17: Canterbury RegionIn addition, the combined load may exceed the n-1 thermal capacity of the Islington–Kimberly–Hororata circuits. This could occur from 2014 if Coleridge generation isunavailable. However, this issue will not constrain the load because the voltageconstraint binds first.SolutionFor a combined load of 70 MW there is a low voltage intertrip scheme installed atHororata to manage the voltage quality at Hororata and Kimberley in the short-term.We are presently investigating options to resolve these issues. Solutions may includecapacitors, an extended intertrip scheme, and constraining-on generation. Weanticipate that the solution to the voltage issue will also resolve the circuit thermalconstraint.Future investment will be customer driven.17.8.8 Hororata supply transformer capacityProject status/type:This issue is for information onlyIssueTwo 66/33 kV transformers supply Hororata 33 kV load, providing:a total nominal capacity of 34 MVA, andn-1 capacity of 23/23 MVA 155 (summer/winter).Hororata’s peak load, which occurs in summer, already exceeds the transformers’ n-1summer capacity in 2013. The load is forecast to:not exceed the transformers’ capacity from 2018 to 2024, andexceed the transformers’ n-1 summer capacity by approximately 2 MW in 2028(see Table 17-9).Table 17-9: Hororata supply transformer overload forecastCircuit/grid exitpointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Hororata (33 kV) 0.95 10 5 5 6 6 0 0 0 0 1 2SolutionThe supply transformer capacity issue can be managed operationally in the shortterm by shifting load to the Hororata 66 kV bus. Some load will be shifted to Kimberly(see Section 17.10.4) in 2014. In the longer term, Orion will shift load from the 33 kVto the 66 kV bus, which will remove the overload issue. Future investment will becustomer driven.17.8.9 Southbrook supply transformer capacityProject reference:Project status/type:Indicative timing:Indicative cost band:SBK-TRAN-DEV-01Possible, customer-specificTo be advisedTo be advisedIssueTwo 66/33 kV transformers supply Southbrook’s load, providing:155 The transformers’ capacity is limited by bus section rating; with this limit resolved, the n-1 capacitywill be 23/24 MVA (summer/winter).2962013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 17:Canterbury Regiona total nominal installed capacity of 80 MVA, andn-1 capacity of 47/47 MVA 156 (summer/winter).Southbrook’s peak load, which occurs in summer, is forecast to exceed thetransformer’s n-1 summer capacity by approximately 4 MW in 2014. The overloadwill decrease when Mainpower transfers some load from the Southbrook 33 kV bus tothe 66 kV bus. However, this will not resolve the overload, which will increase toapproximately 19 MW in 2028 (see Table 17-10).Table 17-10: Southbrook supply transformer overload forecastCircuit/gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Southbrook 0.97 3 4 2 4 5 6 9 11 14 16 19SolutionThe issue can be managed operationally. Alternatively, resolving all transformers’branch component limits will solve the overloading issue until 2019. Mainpowerintends to transfer some load from the Southbrook 33 kV bus to the 66 kV bus, byestablishing two new 66 kV feeders from Southbrook. We are discussing the optionswith Mainpower. Future investment will be customer driven.17.8.10 Springston transmission capacityProject status/type:This issue is for information onlyIssueTwo 66 kV Islington–Springston circuits supply Springston’s load, providing:a total nominal installed capacity of 110/121 MVA (summer/winter), andn-1 capacity of 55/61 MVA (summer/winter).Springston’s peak load, which occurs in summer, is forecast to exceed the circuits’ n-1 summer capacity from 2013.SolutionIn the short-term, Orion can transfer load between Springston and Hororata followinga contingency.Longer-term solutions include the following:During 2011, Orion installed new 66 kV capacity in the area from Islington, whichwill relieve the loading on the existing circuits in the short term. Orion intends toprogressively extend the 66 kV capacity in the area to reduce load on Springstonover the next 10 years.A new 220/66 kV grid exit point south of Christchurch to remove load fromSpringston (see Section 17.10.2).In addition, we also plan to convert the Springston 33 kV outdoor switchyard to anindoor switchboard within the next 5-10 years.156 The transformers’ capacity is limited by circuit breaker and disconnector, followed by the LV cable(49 MVA) and protection equipment (50 MVA) limits; with these limits resolved, the n-1 capacity willbe 55/57 MVA (summer/winter).2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 297

Chapter 17: Canterbury Region17.8.11 Waipara supply transformer securityProject status/type:This issue is for information onlyIssueA single 66/33 kV, 16 MVA transformer supplies load at Waipara resulting in no n-1security.SolutionMainpower is capable of transferring load from the 33 kV to 66 kV network, and hasindicated it will continue with the present level of security. Future investment will becustomer driven.17.9 Canterbury bus securityThe 2013 APR has been expanded to include issues arising from the outage of asingle bus section rated at 50 kV and above for the next 15 years.Bus outages disconnect more than one power system component (for example, othercircuits, transformers, reactive support or generators). Therefore, bus outages maycause greater issues than a single circuit or transformer outage (although the risk of abus fault is low, being less common than a circuit or transformer outage).17.9.1 Transmission bus securityTable 17-11 lists bus outages that cause voltage issues or a total loss of supply.Generators are included only if a bus outage disconnects the whole generationstation or causes a widespread system impact. Supply bus outages, typically 11 kVand 33 kV, are not listed.Table 17-11: Transmission bus outagesTransmission busoutageLoss of supplyGenerationdisconnectionTransmission issueFurtherinformationAshburton 220 kV Ashburton 17.9.2Ashley 66 kVAshleyAshburton low voltages 17.9.3Bromley 220 kV Bromley low voltages 17.9.3Coleridge 66 kVHororata 66 kVColeridgeHororataColeridgeIslington 220 kV Islington area low voltages 17.9.3Kaiapoi 66 kVKaiapoiSouthbrook 66 kV Kaiapoi See note 1Waipara 66 kVSouthbrook See note 1Waipara1. We are investigating the option of installing a bus circuit breaker at Southbrook to improve security atthe request of Mainpower.The customers (Orion, Electricity Ashburton, MainPower, or TrustPower) have notrequested a higher security level, unless otherwise noted. Future investment is likelyto be customer driven. If increased bus security is required, the options typicallyinclude bus reconfiguration and/or additional bus circuit breakers.2982013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 17:Canterbury Region17.9.2 Ashburton bus securityProject status/type:This issue is for information onlyIssueAshburton has two 220/66 kV supply transformers on different bus sections. A busoutage disconnects one of the transformers, and the peak load exceeds the n-1capacity of the remaining transformer.Ashburton also has two 220/33 kV supply transformers on the same bus section. Abus outage disconnects both transformers.SolutionFor the 220/66 kV transformers, we have committed to installing a third transformer(see Section 17.8.2) on a third bus section.For the 220/33 kV transformers, in the short term the issue can be managedoperationally. In the medium term, the 33 kV load will be transferred to the 66 kV(see Section 17.3) and the 220/33 kV transformers will be decommissioned.17.9.3 Regional low voltageProject reference: Upper South Island voltage stability (see Chapter 6, Section 6.6.1)IssueThere are two 220 kV bus sections at Ashburton. A fault at a 220 kV bus section atAshburton results in low voltage issues in the Christchurch area from 2020.There are two 220 kV bus sections at Bromley. A bus fault on either of the Bromley220 kV bus sections will result in low voltages in the Christchurch area from 2025. Afault on a bus section will cause low voltages at Bromley when Orion shifts load toBromley in 2019 (see Section 17.8.4).There are five 220 kV bus sections at Islington. A 220 kV bus fault at Islington willresult in voltage issues in the Christchurch area from 2018.SolutionProjects to address Upper South Island voltage stability (see Chapter 6, Section6.6.1) are expected to resolve these issues.17.10 Other regional items of interest17.10.1 New Ashburton grid exit pointWe are investigating a second Ashburton grid exit point to supply the distribution loadto the west of Ashburton. The connection configuration for the new grid exit point isyet to be finalised. It will be supplied from one or both the 220 kV Islington–Livingstone and Islington–Tekapo–B circuits and will be required in 4-10 years.17.10.2 New southern grid exit point for OrionOrion is planning for a new 220/66 kV grid exit point in the Rolleston-Springston areasouth of Christchurch. The new grid exit point may connect to the 220 kV Islington–Livingstone circuit or one of the Ashburton–Islington/Ashburton–Bromley circuits andwill be required by around 2020.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 299

Chapter 17: Canterbury Region17.10.3 Decommissioning two Addington 66/11 kV transformersOrion is planning a staged development of their 11 kV distribution system suppliedfrom Addington, which will reduce the 11 kV load at Addington.Two 66/11 kV transformers (T2 and T3) are relatively new three-phase units and willremain. The other three transformers (T5, T6, and T7) are made up of single-phaseunits, and are scheduled for replacement by around 2023. Following discussions withOrion, the intention is to decommission T5 in 2013 and decommission T6 and T7 byaround 2019. The Addington 11 kV load will be limited to within the capacity of thetwo remaining transformers (n-1 capacity of 39/40 MVA summer/winter).In addition, the Addington 11 kV No. 2 indoor switchboard is scheduled forreplacement by around 2014. The configuration of the replacement switchboard willbe compatible with the longer-term site developments.17.10.4 Kimberley substationFonterra has a 5.5 MVA dairy processing plant at Darfield, presently supplied fromthe Hororata 33 kV bus. An expansion in 2013 will add an additional 6 MVA,requiring the dairy plant’s load to be supplied from a new substation (Kimberley)connected to the 66 kV Hororata–Islington–1 and 2 circuits.The increase in load may adversely affect the voltage quality at Hororata andKimberley following a circuit outage, depending primarily on the system load and thelevel of generation at Coleridge (see Section 17.8.7).17.11 Canterbury generation scenarios, proposals and opportunitiesThis section details relevant regional issues for selected generation scenarios,generation proposals under investigation by developers and in the public domain, orother generation opportunities. The impact of committed generation projects on thegrid backbone is dealt with separately in Chapter 6.The maximum generation that can be connected depends on several factors andusually falls within a range. Generation developers should consult with us at an earlystage of their investigations to discuss connection issues.17.11.1 Impact of generation scenarios on regional planThe generation scenarios (see Chapter 5) represent a series of possible futuregeneration outcomes. This section presents only those scenarios relevant to thisregion for the next 15 years.All generation scenarios in the Canterbury region anticipate demand side response atIslington. The peak load reduction will have a minimal impact on transmission withinthe Canterbury region. There may be some delay in replacing supply transformersdepending on the location of any load reduction. The main effect will be atransmission load reduction on circuits forming the grid backbone into Canterbury.No issues are anticipated by any of the generation scenarios.17.11.2 Maximum regional generationThe Canterbury region has some of the highest load densities in the South Island,coupled with relatively low levels of local generation. Therefore, there is no practicallimit to the generation that can be connected within the region. However, there will belimits on the generation that can be connected at a particular substation or along anexisting line due to the rating of the existing circuits.3002013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 17:Canterbury Region17.11.3 Mount Cass wind generation stationThere is a proposal to install a 60 MW (approximately) wind generation station atMount Cass, which can be connected to the Waipara 66 kV bus without anyrestrictions when all transmission assets are in service. Generation greater than60 MW will require automatic controls to limit generation following some outages, toprevent circuits from overloading.17.11.4 Inland Canterbury wind sitesWind maps show that inland Canterbury has good wind resources for windgeneration, but most of the area is distant from significant transmission.There are two 66 kV Islington–Hororata circuits rated at 60/63 MVA, and twoHororata–Coleridge circuits rated at 30/37 MVA (reconductoring a section of whichincreases this rating to 48/53 MVA). It is possible to connect over 100 MW ofgeneration if connected directly to the Hororata 66 kV bus or up to approximately therating of a single circuit if the generation is connected onto a circuit.Hundreds of megawatts of generation can be connected to the 220 kV Islington–Kikiwa circuits north of Christchurch, the limit of which depends on the location of theconnection point and the number of circuits it is connected to.There is some spare capacity south of Christchurch to connect generation into the220 kV Islington–Livingstone circuit, the primary purpose of which is to supply loadsin and north of Christchurch. Connecting too much generation to this circuit willoverload it, and reduce the amount of load that can be supplied into and north ofChristchurch. Approximately 400 MW can be connected (more if the circuit sectionfrom the Rangitata River to Islington is thermally upgraded).2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 301

Chapter 18:South Canterbury Region18 South Canterbury Regional Plan18.1 Regional overview18.2 South Canterbury transmission system18.3 South Canterbury demand18.4 South Canterbury generation18.5 South Canterbury significant maintenance work18.6 Future South Canterbury projects summary and transmission configuration18.7 Changes since the 2012 Annual Planning Report18.8 South Canterbury transmission capability18.9 South Canterbury bus security18.10 Other regional items of interest18.11 South Canterbury generation scenarios, proposals and opportunities18.1 Regional overviewThis chapter details the South Canterbury regional transmission plan. We base thisregional plan on an assessment of available data, and welcome feedback to improveits value to all stakeholders.Figure 18-1: South Canterbury regionConstruction voltages shown. System as at March 2013.3022013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 18: South Canterbury RegionThe South Canterbury region includes a mix of significant and growing provincialcities (Timaru and Oamaru) and agricultural industries (Bells Pond, Black Point,Studholme, Temuka, and Waitaki).We have assessed the South Canterbury region’s transmission needs over the next15 years while considering longer-term development opportunities. Specifically, thetransmission network needs to be flexible to respond to a range of future service andtechnology possibilities, taking into consideration:the existing transmission networkforecast demandforecast generationequipment replacement based on condition assessment, andpossible technological development.18.2 South Canterbury transmission systemThis section highlights the state of the South Canterbury regional transmissionnetwork. The existing transmission network is set out geographically in Figure 18-1and schematically in Figure 18-2.Figure 18-2: South Canterbury transmission schematicHaywardsCANTERBURYIslingtonAshburtonTekapo A33 kV11 kV110 kV220 kVOhau ATekapo BTwizel33 kV 220 kVOhau C220 kV220 kV220 kVBenmoreCromwellOhau B220 kV220 kVAviemoreNasebyOTAGO - SOUTHLAND110 kV11 kVAlburyWaitakiBlack Point110 kV11 kV33 kVLivingstone220 kV220 kVBells Pond110 kVOamaru110 kV33 kV220 kVGlenavyTemuka33 kV110 kV110 kV11 kVTimaru* Note: Studholme split is110 kV closed during peak dairy11 kV season (October-April)StudholmeKEYHVDC Link220kV CIRCUIT110kV CIRCUITSUBSTATION BUSTRANSFORMERTEE POINTLOADCAPACITORGENERATOR2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 303

Chapter 18:South Canterbury Region18.2.1 Transmission into the regionSeveral major 220 kV lines serve the South Canterbury region, connecting it toChristchurch and the upper South Island to the north, and the Otago Southlandregion to the south.This region contributes a major portion of the generation in the South Island, feedingthe 220 kV transmission network from the Tekapo, Ohau, and Waitaki Valleygeneration stations. Peak load in the region (approximately 195 MW in 2012) isapproximately 11% of the region’s generation capacity, so the need for transmissioncapacity into the region is driven by generation export requirements, and the need totransfer power from the lower South Island to the upper South Island.18.2.2 Transmission within the regionThe South Canterbury regional transmission network comprises 220 kV and 110 kVtransmission circuits, with interconnecting transformers at Timaru and Waitaki. Allsignificant loads in the South Canterbury region are supplied via the 110 kVtransmission network running up the east coast from Oamaru to Temuka.The 110 kV transmission network is normally split at Studholme, but this split isclosed during the peak dairy season (October–April) to increase the supply security.The split creates two radial feeds incorporating the:Timaru 220/110 kV interconnecting transformers supplying Timaru, Albury,Tekapo A and Temuka, andWaitaki 220/110 kV interconnecting transformers supplying Studholme, BellsPond, Black Point, and Oamaru.Up to 25 MW of generation is injected directly into the 110 kV transmission networkfrom Tekapo A.Much of the 110 kV transmission network is reaching its capacity, as are theinterconnecting transformers at Timaru. This is mainly due to growth associated withthe dairy industry, and irrigation in particular.We have a number of investigations and projects planned or underway to supportdemand growth and supply security in the South Canterbury region. These includeinvestigating:managing or increasing the 220/110 kV transformer capacity in the regiona new grid exit point at Livingstone.18.2.3 Longer-term development pathLong-term development plans may include new 220 kV connections to offload thehighly loaded 110 kV transmission network.Some demand-side response may be appropriate to allow the economic connectionof large rural loads such as irrigation.18.3 South Canterbury demandThe after diversity maximum demand (ADMD) for the South Canterbury region isforecast to grow on average by 2.9% annually over the next 15 years, from 192 MWin 2013 to 292 MW by 2028. This is higher than the national average demand growthof 1.5% annually.3042013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 18: South Canterbury RegionFigure 18-3 shows a comparison of the 2012 and 2013 APR forecast 15-yearmaximum demand (after diversity 157 ) for the South Canterbury region. The forecastsare derived using historical data, and modified to account for customer information,where appropriate. The power factor at each grid exit point is also derived fromhistorical data, and is used to calculate the real power capacity for power transformerand transmission line. See Chapter 4 for more information about demandforecasting.Figure 18-3: South Canterbury region after diversity maximum demand forecastTable 18-1 lists forecast peak demand (prudent growth) for each grid exit point for theforecast period, as required for the Grid Reliability Report.Table 18-1: Forecast annual peak demand (MW) at South Canterbury grid exit points to2028Grid exit pointPowerfactorNext 5 yearsPeak demand (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Albury 0.94 4 4 4 4 5 5 5 5 5 5 6Bells Pond 1 0.95 8 8 8 9 9 17 18 18 10 11 11Black Point 1 0.96 13 21 21 24 25 27 28 28 29 30 30Oamaru 2 0.96 42 44 46 47 55 57 61 64 66 67 69St Andrews 1 0.95 0 0 0 0 35 45 45 45 45 45 45Studholme 1 0.95 17 19 25 27 32 33 36 37 38 39 39Tekapo A 1.00 5 5 6 6 6 6 7 7 8 8 9Temuka 0.96 61 65 67 68 70 76 80 83 87 91 94Timaru 1 0.98 67 68 68 69 69 71 72 72 73 74 75Twizel 1.00 6 6 10 10 10 10 11 11 11 11 12Waitaki 1.00 7 7 7 7 7 7 8 8 8 9 9157The after diversity maximum demand (ADMD) for the region will be less than the sum of theindividual grid exit point peak demands, as it takes into account the fact that the peak demand doesnot occur simultaneously at all the grid exit points in the region.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 305

Chapter 18:South Canterbury RegionGrid exit pointPowerfactorNext 5 yearsPeak demand (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 20281. These grid exit points have forecasts that include likely step changes in demand identified indiscussions with the customer. Loads include irrigation schemes and associated dairy industrydevelopment.2. An allowance has been retained in 2017 for a possible new Holcim cement plant. No decision toproceed has yet been made.18.4 South Canterbury generationThe South Canterbury region’s generation capacity is 1,746 MW. This represents amajor portion of total South Island generation and significantly exceeds local demand.Surplus generation is exported via the National Grid to other demand centres in theSouth Island, and via the HVDC link to the North Island.Table 18-2 lists the generation forecast for each grid injection point in the SouthCanterbury region for the forecast period, as required for the Grid Reliability Report.This includes all known and committed generation stations including those embeddedwithin the relevant local lines company’s network (either Network Waitaki or AlpineEnergy). 158No new generation is known to be committed in the South Canterbury region for theforecast period.Table 18-2: Forecast annual generation capacity (MW) at South Canterbury grid injectionpoints to 2028 (including existing and committed generation)Grid injection point(location ifembedded)Next 5 yearsGeneration capacity (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Albury (Opuha) 8 8 8 8 8 8 8 8 8 8 8Aviemore 220 220 220 220 220 220 220 220 220 220 220Benmore 540 540 540 540 540 540 540 540 540 540 540Ohau A 264 264 264 264 264 264 264 264 264 264 264Ohau B 212 212 212 212 212 212 212 212 212 212 212Ohau C 212 212 212 212 212 212 212 212 212 212 212Tekapo A 25 25 25 25 25 25 25 25 25 25 25Tekapo B 160 160 160 160 160 160 160 160 160 160 160Waitaki 105 105 105 105 105 105 105 105 105 105 10518.5 South Canterbury significant maintenance workOur capital project and maintenance works are integrated to enable system issues tobe resolved if possible when assets are replaced or refurbished. Table 18-3 lists thesignificant maintenance-related work 159 proposed for the South Canterbury region forthe next 15 years that may significantly impact related system issues or connectedparties.158 Only generators with capacity greater than 1 MW are listed. Generation capacity is rounded to thenearest megawatt.159 This may include replacement of the asset due to its condition assessment.3062013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 18: South Canterbury RegionTable 18-3: Proposed significant maintenance workDescriptionAlbury supply transformerexpected end-of-lifeStudholme supply transformerexpected end-of-lifeTimaru 110 kV busrationalisationTimaru supply transformers T2and T3 expected end-of-lifeTwizel 33 kV outdoor to indoorconversionWaitaki interconnectingtransformers expected end-oflifeTentativeyearRelated system issues2017-2019 There is no n-1 security at Albury. Future investmentwill be customer driven. See Section 18.8.4 for moreinformation.2015-2017 The load at Studholme exceeds the supplytransformers’ n-1 capacity. See Section 18.8.10 formore information.2013-2015 The 110 kV rationalisation and protection work needs tobe coordinated with the supply and interconnectingtransformer development work at Timaru. See Sections18.8.2 and 18.8.13 for more information.2012-2014 A project is under way to replace these transformerswith higher-rated units. See Section 18.8.13 for moreinformation.2018-2020 No system issues are identified within the forecastperiod.2015-2017 The options to replace the interconnecting transformersare related to the Lower Waitaki Valley Reliabilityproject. See Sections 18.8.1 and 18.8.3 for moreinformation.18.6 Future South Canterbury projects summary and transmissionconfigurationTable 18-4 lists projects to be carried out in the South Canterbury region within thenext 15 years.Figure 18-4 shows the possible configuration of South Canterbury transmission in2028, with new assets, upgraded assets, and assets undergoing significantmaintenance within the forecast period.Table 18-4: Projects in the South Canterbury region up to 2028Circuit/site Projects StatusAlbury Replace the supply transformer. ProposedBenmore–Twizel Upgrade the circuit’s thermal capacity (see Chapter 6, Section 6.6.3for more information)PossibleOrari Install a new switching station. PossibleLivingstone Install two 220/66 kV or 220/33 kV supply transformers. PossibleStudholme Replace the existing supply transformers with higher-rated units. PossibleSt Andrews Install a new grid exit point. PossibleTekapo A Resolve the 11/33 kV supply transformer protection limits. . PossibleTemuka–Timaru Upgrade the circuit’s thermal capacity. PossibleTemuka Install a new supply transformer. PossibleTimaruRationalise the 110 kV bus.Upgrade the supply transformer capacity.Install an additional interconnecting transformer or transformers.CommittedCommittedPossibleTwizel Convert the 33 kV outdoor switchgear to indoor. ProposedWaitakiClutha-UpperWaitaki LineProjectReplace the interconnecting transformers.Install a second 11/33 kV supply transformer.Replace the 11/33 kV supply transformer with higher rated unit.Replace the following circuits with duplex conductor:220 kV Aviemore–Benmore–1 and 2 circuits.220 kV Aviemore–Waitaki–Livingstone–1 circuit.220 kV Livingstone–Naseby–Roxburgh–1 circuit.220 kV Clyde–Roxburgh–1 and 2 circuits (Otago-SouthlandProposedPossiblePossibleCommitted2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 307

Chapter 18:South Canterbury RegionCircuit/site Projects StatusLower WaitakiValley ReliabilityProjectregion).Thermally upgrade the 220 kV Cromwell–Twizel–1 and 2 circuits.Possible options include the following:Build a new 110 kV line between Livingstone and Oamaru.Reconductor/thermally upgrade the 110 kV circuits betweenWaitaki, Oamaru and Timaru.Install capacitors at Oamaru.Figure 18-4: Possible South Canterbury transmission configuration in 2028PossibleHaywardsCANTERBURYIslingtonAshburtonTekapo A33 kV110 kV11 kVTekapo B220 kV110 kV220 kVOrariTemuka33 kV220 kVOhau A33 kV Twizel220 kV Ohau BOhau C220 kV11 kV220 kV220 kVBenmore220 kVAviemore11 kV 220 kVAlburySt Andrews220 kV11 kV220 kV110 kVWaitaki11 kVBlack PointStudholme110 kV33 kVBells Pond KEY110 kVGlenavy110 kV110 kV11 kVTimaruNEW ASSETSUPGRADED ASSETSASSETS SCHEDULEDFOR REPLACEMENT*MINOR UPGRADELivingstoneCromwellNasebyOTAGO - SOUTHLAND220 kV66 kV33 kV110 kVOamaru18.7 Changes since the 2012 Annual Planning ReportTable 18-5 lists the specific issues that are either new or no longer relevant within theforecast period when compared to last year's report.Table 18-5: Changes since 2012IssuesNo new issues or projects completed.ChangeNo change.18.8 South Canterbury transmission capabilityTable 18-6 summarises issues involving the South Canterbury region for the next 15years. For more information about a particular issue, refer to the listed sectionnumber.3082013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 18: South Canterbury RegionTable 18-6: South Canterbury region transmission issuesSectionnumberIssueRegional18.8.1 Oamaru–Waitaki voltage quality and transmission security18.8.2 Timaru interconnecting transformer capacity18.8.3 Waitaki 220/110 kV interconnecting transformer capacitySite by grid exit point18.8.4 Albury supply security and supply transformer capacity18.8.5 Albury and Tekapo A transmission security18.8.6 Bells Pond single supply security18.8.7 Black Point single supply security18.8.8 Oamaru supply transformer capacity18.8.9 Studholme single supply security18.8.10 Studholme supply transformer capacity18.8.11 Tekapo A supply security and supply transformer capacity18.8.12 Temuka transmission security and supply transformer capacity18.8.13 Timaru supply transformer capacity18.8.14 Twizel supply securityBus security18.9.1 Transmission bus security18.9.2 Timaru 110 kV transmission security18.8.1 Oamaru–Waitaki voltage quality and transmission securityProject context:Lower Waitaki Valley ReliabilityProject reference: Reactive support: OAM-C_BANKS-DEV-01New grid exit point: LIV-SUBEST-DEV-01Project status/type: Reactive support: possible, customer-specificNew grid exit point: possible, customer-specificIndicative timing: Reactive support: 2014-2017New grid exit point: to be advisedIndicative cost band: Reactive support: ANew grid exit point: CIssueTwo 110 kV circuits from Waitaki supply the Oamaru, Black Point, Bells Pond, andStudholme grid exit points, which include the:Oamaru–Black Point–Waitaki–1 circuit (which supplies Black Point via a teeconnection), andOamaru–Studholme–Bells Pond–Waitaki–2 circuit (which supplies the Bells Pondand Studholme loads from tee connections).The underlying load growth forecast for this area is considerably higher than thenational average, and is mainly due to irrigation and the dairy industry. There is also apossible major new industrial load at Oamaru.VoltageThe load at these four grid exit points peaks in summer. The voltage at the Oamaru110 kV bus can fall below 0.9 pu with the loss of the:Oamaru–Black Point–Waitaki circuit, or2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 309

Chapter 18:South Canterbury RegionOamaru–Studholme–Bells Pond–Waitaki circuit.There is also a voltage quality issue with a large voltage step immediately followingthe outage of either circuit. Lack of availability of tap changing at the Waitakiinterconnecting transformers limits flexibility in voltage control on the Oamaru–Waitaki110 kV circuits. There are no steady state voltage issues at Oamaru 33 kV, due to therange of the supply transformer on-load tap changers.In the medium term, there are voltage stability issues, which might occur from 2015with underlying load growth at Studholme, Bells Pond, and Black Point.OverloadingThermal overloads occur by summer 2013/14 on:one Glenavy–Oamaru circuit section following an outage of the parallel circuitthe Bells Pond–Waitaki section during an outage of the Oamaru–Black Point–Waitaki circuit or any of the Twizel–Timaru–Ashburton circuits, andthe Black Point–Waitaki section during an outage of the Oamaru–Studholme–Bells Pond–Waitaki circuit.SolutionWe are investigating a range of short-term options, and the solution may include oneor more of the following:Load management at the Oamaru and Waitaki Valley grid exit pointsImplementing system splits at Studholme.Post-contingency load shedding at Oamaru and other grid exit points.A Wider Voltage Agreement at 110 kV buses will manage the voltage issue in theshort-term. In the medium term, the voltage issues can be resolved by installingapproximately 30 Mvar of reactive support at Oamaru. This also providesapproximately 7 MW additional capacity on the Glenavy–Oamaru circuit.Additional reactive support will be required in the longer term. However, the reactivesupport’s size and the location will depend on the development undertaken to resolvethe capacity issue.A range of long-term options has been investigated to resolve the capacity issue,including:transferring load from Oamaru to a new grid exit point at the existing Livingstoneswitching station (see Section 18.10.2)a new 110 kV Livingstone–Oamaru line, and/orreconductoring and thermally upgrading the existing 110 kV circuits and providingadditional reactive support.Easements may be required for the line upgrade work, and will be required for anynew lines.We are discussing development options with the local lines companies (NetworkWaitaki and Alpine Energy). A major driver of the transmission upgrade is thepossible major new industrial load at Oamaru. We do not expect to propose majorupgrades unless this load becomes committed.18.8.2 Timaru interconnecting transformer capacityProject reference: Interconnecting transformer capacity: TIM-POW_TFR-EHMT-02Project status/type: Interconnecting transformer capacity: possible, Base CapexIndicative timing: Interconnecting transformer capacity: 2018-2020Indicative cost band: Interconnecting transformer capacity: C3102013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 18: South Canterbury RegionIssueTwo 220/110 kV interconnecting transformers at Timaru supply the loads at Timaru,Temuka, Albury and Tekapo A, providing:a total nominal installed capacity of 240 MVA, andn-1 capacity of 122/125 MVA 160 (summer/winter).An outage of one transformer might cause the other transformer to exceed its n-1capacity already during peak periods, if Tekapo A is not generating, and from 2018 ifTekapo A is at maximum generation. In addition, some development options for theLower Waitaki Valley area might increase the loading on these transformers, one ofwhich is supplying Studholme from Timaru instead of Waitaki (see Sections 18.8.1).SolutionThe options to address this issue include one or more of the following:Peak load management or load sheddingReducing reactive power flow through the Timaru interconnecting transformersvia 110 kV reactive support.Increasing installed capacity using one of several possible configurations of theexisting and new interconnecting transformers.18.8.3 Waitaki 220/110 kV interconnecting transformer capacityProject reference: WTK-POW_TFR-EHMT-01Project status/type: Proposed, Base CapexIndicative timing: 2014-2019Indicative cost band: BIssueTwo 220/110 kV interconnecting transformers (T23 and T24) at Waitaki supply theWaitaki 110 kV loads at Black Point, Bells Pond, Oamaru, and Studholme, providing:a total nominal installed capacity of 130 MVA, andn-1 capacity of 80/85 MVA (summer/winter).The loading on the two transformers is unequal because of the system configuration(no 110 kV bus at Waitaki and only Oamaru is connected to both circuits). Thesetransformers have a higher capacity than the circuits they supply, so they are not thefirst constraint. However, under some upgrade scenarios for the Waitaki–Oamarutransmission, the capacity of the 110 kV Waitaki–Oamaru circuits (as well as the loadplaced on them) will exceed the interconnecting transformers’ n-1 capacity.In addition, the tap changers on these transformers are unable to be operated due totheir condition. This exacerbates voltage issues on the Lower Waitaki 110 kVtransmission system (see Section 18.8.1).SolutionThese transformers have an expected end-of-life within the next 10 years. The needto increase the interconnection capacity in conjunction with the necessarymaintenance work will depend on the preferred option arising from the Lower WaitakiValley Reliability investigation (see Section 18.8.1).160 The transformers’ winter capacity is limited by protection equipment; with this limit resolved, the n-1capacity will be 122/127 MVA (summer/winter).2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 311

Chapter 18:South Canterbury Region18.8.4 Albury supply security and supply transformer capacityProject status/type:This issue is for information onlyIssueA single 110/11 kV, 5 MVA transformer supplies load at Albury resulting in no n-1security.In addition, Albury is connected to embedded generation at Opuha, which may exportpower to the National Grid during periods of low demand.The peak load at Albury is forecast to exceed the transformer’s summer capacity byapproximately 1 MW from 2024 (see Table 18-7).Table 18-7: Albury supply transformer overload forecastCircuit/gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Albury 0.99 0 0 0 0 0 0 0 0 1 1 1SolutionAlpine Energy can supply Albury’s load from Timaru after a short loss of supply, andthe transformer overload can be addressed with generation from Opuha. Therefore,the issue can be managed operationally for the forecast period. Future investmentwill be customer driven.In addition, the supply transformer has an expected end-of-life within the next 10years. We will discuss options with Alpine Energy for increasing supply security andcoordinating outages to minimise supply interruptions when replacing thistransformer.18.8.5 Albury and Tekapo A transmission securityProject status/type:This issue is for information onlyIssueA single 110 kV Tekapo A–Albury–Timaru circuit connects Tekapo A, Albury, andOpuha to the National Grid. If the circuit trips, demand located at Albury andTekapo A will lose supply, and generation located at Tekapo A and Opuha willdisconnect from the National Grid.SolutionAlbury and Tekapo A demand may be restored by local Opuha and Tekapo Ageneration. Alpine Energy considers the issue can be managed operationally for theforecast period. Future investment will be customer driven.18.8.6 Bells Pond single supply securityProject reference:Project status/type:Indicative timing:Indicative cost band:BPD-BUSC-DEV-01Possible, customer-specificTo be advisedTo be advised3122013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 18: South Canterbury RegionIssueBells Pond has a single 110 kV circuit connected to an Oamaru–Waitaki circuit,resulting in no n-1 security.SolutionAlpine Energy has requested a higher security level. We are discussing possibleoptions with Alpine Energy, which include:building a 110 kV bus at Bells Pondconnecting to the other 110 kV Oamaru–Waitaki circuit, anda new grid exit point connected to the Islington–Livingstone circuit (seeSection 18.10.2).Future investment will be customer driven.18.8.7 Black Point single supply securityProject status/type:This issue is for information onlyIssueBlack Point has a single 110 kV circuit connected to an Oamaru–Waitaki circuit,resulting in no n-1 security.SolutionNetwork Waitaki has not requested a higher security level and there are currently noplans to increase supply security at this grid exit point. Future investment will becustomer driven.18.8.8 Oamaru supply transformer capacityProject reference: LIV-SUBEST-DEV-01Project status/type: Possible, customer-specificIndicative timing: 2016Indicative cost band: CIssueTwo 110/33 kV transformers supply Oamaru’s load, providing:a total nominal installed capacity of 120 MVA, andn-1 capacity of 62/62 MVA 161 (summer/winter).The peak load at Oamaru is forecast to exceed the transformers’ n-1 summercapacity by approximately 1 MW in 2016, increasing to approximately 22 MW in 2028(see Table 18-8).Table 18-8: Oamaru supply transformer overload forecastCircuit/gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Oamaru 0.96 0 0 0 1 9 11 14 18 19 21 22161 The transformers’ capacity is limited by protection equipment limits, followed by the circuit breaker(71 MVA) limits; with these limits resolved, the n-1 capacity will be 72/76 MVA (summer/winter).2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 313

Chapter 18:South Canterbury RegionSolutionThe 110 kV circuits supplying these transformers have a lower capacity 162 than thetransformers (see Section 18.8.1). Therefore, the transformers are not the firstconstraint on Oamaru load.The customer is considering the option of a new grid exit point at Livingstone (seeSection 18.10.2) to enable load shift from Oamaru to Livingstone, and restricting theOamaru load to within the n-1 capacity of the 110 kV circuits. Future investment willbe customer driven.18.8.9 Studholme single supply securityProject status/type:See Section 18.8.1 for more informationIssueThe Studholme–Timaru circuit is split during the dairy off-season (May to September),and Studholme is supplied by the Oamaru–Studholme–Bells Pond–Waitaki circuit.This reduces losses that occur when power flows through the 110 kV system fromWaitaki to Timaru. In the event of a fault on the Oamaru–Studholme–Bells Pond–Waitaki circuit, the supply automatically transfers to the Studholme–Timaru line. Thisresults in approximately 25 seconds loss of supply at Studholme before the switchingoccurs.However, a brief loss of supply to the local dairy factory at Studholme can causesignificant economic losses, so the split is closed during the peak dairy season(October to April).As load increases in the Lower Waitaki area, closing the split will create overloadingissues on the Waitaki–Bells Pond section of the Oamaru–Studholme–Bells Pond–Waitaki circuit. We may be unable to close the split during peak summer load periodsfrom 2013/14.SolutionLong-term development may form a part of the Lower Waitaki Valley Reliabilityproject (see Section 18.8.1).18.8.10 Studholme supply transformer capacityProject reference:Project status/type:Indicative timing:Indicative cost band:Upgrade transformer capacity: STU-POW_TFR-EHMT-01New grid exit point: STU-SUBEST-DEV-01Upgrade transformer capacity: possible, customer-specificNew grid exit point: possible, customer-specificUpgrade transformer capacity: 2014 (subject to Alpine Energy agreement)New grid exit point: to be advisedUpgrade transformer capacity: BNew grid exit point: CIssueTwo 110/11 kV transformers supply Studholme’s load, providing:a total nominal installed capacity of 20 MVA, andn-1 capacity of 11/12 MVA (summer/winter).The peak load at Studholme already exceeds the transformers’ n-1 summer capacity,and the overload is forecast to increase to approximately 28 MW in 2028 (see Table18-9). However, part of this increase is due to a single load from a proposed162 The lowest rated circuit section (Black Point–Oamaru) is rated at 50/60 MVA summer/winter.3142013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 18: South Canterbury Regionirrigation scheme in 2017. This may be supplied from a new grid exit point in the areanorth of Studholme.Table 18-9: Studholme supply transformer overload forecastCircuit/gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Studholme 0.95 6 8 14 15 21 22 25 26 27 27 28Studholme has an unusual 110 kV bus arrangement, where the two transformershave no dedicated 110 kV circuit breakers. This means that both supply transformerswill be tripped to clear a transformer fault, causing a loss of supply at Studholme.Supply can be restored after the faulted transformer is disconnected.SolutionWe are discussing possible solutions with Alpine Energy, which include:replacing the existing transformers with higher-rated units, andbuilding a new grid exit point north of Studholme near St Andrews (if newirrigation load is committed) on the 220 kV Islington–Livingstone circuit, andtransferring some of the Studholme load (see Section 18.10.1).Acquisition of substation land will be required for establishing a new grid exit point.An additional consideration is that both Studholme supply transformers areapproaching their expected end-of-life within the next five years. If an agreement toproceed with the transformer upgrade has not been made prior to the need forreplacement, we will discuss the transformer capacity upgrade project with AlpineEnergy in conjunction with the replacement work.18.8.11 Tekapo A supply security and supply transformer capacityProject reference: TKA-POW_TFR-EHMT-01Project status/type: Possible, Base CapexIndicative timing: 2022Indicative cost band: AIssueA single 110/11 kV, 35 MVA transformer in series with a single 33/11 kV, 10 MVA 163transformer supplies load at Tekapo, resulting in no n-1 security.The peak load at Tekapo A is forecast to exceed the 33/11 kV transformer’s wintercapacity by approximately 1 MW in 2022, increasing to approximately 2 MW in 2028(see Table 18-10).Table 18-10: Tekapo A supply transformer overload forecastCircuit/Gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Tekapo A 1.00 0 0 0 0 0 0 0 1 1 2 2163The transformer’s protection limit of 7 MVA and metering equipment limit of 8 MVA prevent thefull nominal installed capacity being available.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 315

Chapter 18:South Canterbury RegionSolutionAlpine Energy considers that the lack of n-1 security can be managed operationallyfor the forecast period. Resolving the protection limits will provide sufficient capacityfor the duration of the forecast period. Future investment will be customer driven.18.8.12 Temuka transmission security and supply transformer capacityProject reference:Project status/type:Indicative timing:Indicative cost band:Additional transformer: TMK-POW_TFR-DEV-02Upgrade circuit capacity: TIM_TMK-TRAN-EHMT-01New grid exist point: TMK-SUBEST-DEV-01Possible, customer-specificTo be advisedAdditional transformer: BUpgrade circuit capacity: BNew grid exit point: to be advisedIssueTwo 110 kV Timaru–Temuka circuits, each rated at 70/77 MVA (summer/winter),supply the Temuka 33 kV load.An outage of one of these circuits will cause the other circuit to exceed its thermalcapacity from 2013 during summer peak demand periods. Also, there is no 110 kVbus at Temuka. Therefore, a circuit outage will also result in the loss of the110/33 kV supply transformer connected to this circuit.At Temuka, two 110/33 kV transformers supply the 33 kV load, providing:a total nominal installed capacity of 108 MVA, andn-1 capacity of 61/63 MVA (summer/winter).The peak load at Temuka is forecast to exceed the transformers’ n-1 summercapacity by approximately 5 MW in 2013, increasing to approximately 38 MW in 2028(see Table 18-11).Table 18-11: Temuka supply transformer overload forecastCircuit/gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Temuka 0.96 5 8 10 12 15 19 23 27 30 34 38SolutionWe are discussing options with Alpine Energy. A long-term solution involves:paralleling the existing transformers and installing a new 120 MVA transformer,andupgrading the 110 kV circuits between Timaru and Temuka, ora new connection to the 220 kV Islington–Waitaki circuit, west of Temuka.The addition of a new transformer will not raise new property issues as it can beimplemented within the existing substation boundary. However, upgrading thecapacity of the 110 kV Temuka–Timaru circuits may require easements.A long-term solution will depend on whether there is likely to be further growth at theClandeboye dairy factory, which accounts for more than half the demand at this gridexit point.18.8.13 Timaru supply transformer capacityProject reference:TIM-POW_TFR-EHMT-013162013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 18: South Canterbury RegionProject status/type: Committed, customer-specificIndicative timing: 2014Indicative cost band: CIssueThree 110/11 kV transformers supply Timaru’s load, providing:a total nominal installed capacity of 77 MVA (one 27 MVA and two 25 MVA), andn-1 capacity of 54/56 MVA (summer/winter).The peak load at Timaru already exceeds the transformers’ n-1 winter capacity, andthe overload is forecast to increase to approximately 22 MW in 2028 (see Table18-12).Table 18-12: Timaru supply transformer forecast overloadCircuit/gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Timaru 0.96 14 15 15 16 18 18 19 19 20 21 22There is a non-contracted spare transformer unit on site, allowing possiblereplacement within 8-14 hours following a unit failure (if the spare unit is available).Alpine Energy can also transfer some load from Timaru following a transformer fault.SolutionWe are committed to replacing the existing three 110/11 kV supply transformers withthree 47 MVA units.18.8.14 Twizel supply securityProject status/type:This issue is for information onlyIssueTwo 220/33 kV transformers supply the Twizel load, providing:a total nominal installed capacity of 40 MVA, andn-1 capacity of 26/27 MVA (summer/winter).The loads supplied from the Twizel 33 kV bus have n transformer security, becausethe supply bus is split. Hydro generation and control structures in the area (Ohau A,B & C, Tekapo B, Ruataniwha and Pukaki) take their local supply from this bus, and itis split to reduce the risk of losing supply to all sites simultaneously.Alpine Energy takes 33 kV supply from one side of the split, and Network Waitakitakes supply from the other side of the split.The bus split can be closed to avoid loss of supply during transformer maintenance,and in a short time following an unplanned transformer outage.SolutionAlpine Energy, Network Waitaki, Meridian and Genesis consider that the present levelof security can be managed operationally. Future developments will be customerdriven.18.8.15 Waitaki single supply security and supply transformer capacityProject reference:Increase transformer capacity by adding fans and pumps: WTK-POW_TFR-EHMT-012013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 317

Chapter 18:South Canterbury RegionInstall a second supply transformer: WTK-POW_TFR-DEV-01Project status/type: Possible, customer-specificIndicative timing: Increase transformer capacity by adding fans and pumps: 2014Install a second supply transformer: to be advisedIndicative cost band: Increase transformer capacity by adding fans and pumps: AInstall a second supply transformer: AIssueA single 33/11 kV, 5.5 MVA transformer supplies load at Waitaki resulting in no n-1security.Network Waitaki can supply some of the Waitaki load from Twizel after a short loss ofsupply. However, the peak Waitaki load is forecast to exceed the continuous supplytransformer capacity by approximately 1 MW in 2013, increasing to approximately3 MW in 2028 (see Table 18-13). Network Waitaki has requested options for securityand capacity enhancements.Table 18-13: Waitaki supply transformer overload forecastCircuit/gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Waitaki 0.97 1 1 2 2 2 2 2 3 3 3 3SolutionWe are investigating options with Network Waitaki to increase capacity and securityof supply in the area.A possible solution to increase the security of supply involves installing a secondsupply transformer.Possible options to resolve the capacity issues include one or more of the following:transferring 2 MW of load to another grid exit point (for example, a new point ofsupply at Livingstone – see Section 18.8.1), delaying the issue until 2022using the overload capacity of the transformerincreasing the capacity of the supply transformer, orreplacing the transformer with a higher-rated unit.Future investment will be customer driven.18.9 South Canterbury bus securityThe 2013 APR has been expanded to include issues arising from the outage of asingle bus section rated at 50 kV and above for the next 15 years.Bus outages disconnect more than one power system component (for example, othercircuits, transformers, reactive support or generators). Therefore, bus outages maycause greater issues than a single circuit or transformer outage (although the risk of abus fault is low, being less common than a circuit or transformer outage).18.9.1 Transmission bus securityTable 18-14 lists bus outages that cause voltage issues or a total loss of supply.Generators are included only if a bus outage disconnects the whole generationstation or causes a widespread system impact. Supply bus outages, typically 11 kVand 33 kV, are not listed.3182013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 18: South Canterbury RegionTable 18-14: Transmission bus outagesTransmissionbus outageLoss ofsupplyGenerationdisconnectionTransmissionissueFurtherinformationAlbury 110 kV Albury 18.9.2Tekapo A 18.9.2Opuha 18.9.2Tekapo A 18.9.2Timaru 110 kV Albury 18.9.2Studholme 18.9.2Tekapo A 18.9.2Temuka 18.9.2Timaru 18.9.2Opuha 18.9.2Tekapo A 18.9.2Studholme 110kV Studholme 18.9.2The customers (Alpine Energy, or Genesis) have not requested a higher securitylevel (excluding the Timaru 110 kV bus). Future investment is likely to be customerdriven. If increased bus security is required, the options typically include busreconfiguration and/or additional bus circuit breakers.18.9.2 Timaru 110 kV transmission securityProject reference: TIM-BUSC-DEV-01Project status/type: Committed, Base CapexIndicative timing: 2013-2014Indicative cost band: AIssueThe Timaru 110 kV bus operates as a single zone and supplies the entire loads atTimaru and Temuka, connects directly to Albury and Tekapo A via a single 110 kVcircuit, and supplies Studholme when the system is split at Studholme (seeSection 18.8.9). A 110 kV bus fault at Timaru will cause:a total loss of supply to Timaru and Temukaa total loss of supply at Tekapo A and the disconnection of the Tekapo Agenerationthe disconnection of Albury, possibly causing a loss of supply to Albury, and thedisconnection of Opuha generation if islanding is unsuccessful, anda loss of supply to Studholme if the system is split at Studholme.SolutionConverting the Timaru 110 kV bus to three zones, combined with the supplytransformer upgrade (see Section 18.8.13) will secure the Timaru load. The buszones will also secure the Temuka load. There may still be a loss of supply andgeneration disconnection at Tekapo A, Albury and Opuha for an outage of the bussection connecting the single Tekapo A–Albury–Timaru circuit. Similarly, there willstill be a loss of supply to Studholme if the system is split at Studholme for an outageof the bus section connecting the Studholme–Timaru circuit.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 319

Chapter 18:South Canterbury Region18.10 Other regional items of interest18.10.1 St Andrews substationSt Andrews is a possible new substation supplied from the 220 kV Islington–Livingstone circuit. It would supply load, principally irrigation, in the area betweenTimaru and the Waitaki River. This substation is considered as part of the loadforecast from 2017 (see Section 18.3). It may also allow the load off-take atStudholme to be managed if load is transferred from Studholme to St Andrews (seeSection 18.8.2).It is unlikely that the load could be supplied from the 110 kV network in the area,because the cost to increase the 110 kV network’s capacity is expected to be higherthan connection to the 220 kV system.Future investment will be customer driven.18.10.2 Livingstone substationInstalling supply transformers at the Livingstone switching station is one option toaddress a number of issues on the south side of the Waitaki River. The issuesinclude:Oamaru–Waitaki voltage quality and transmission security (see Section 18.8.1).Black Point single supply security (see Section 18.8.7).Oamaru supply transformer capacity (see Section 18.8.8).Waitaki supply transformer capacity (see Section 18.8.14).Future investment will be customer driven.18.11 South Canterbury generation scenarios, proposals and opportunitiesThis section details relevant regional issues for selected generation scenarios,generation proposals under investigation by developers and in the public domain, orother generation opportunities. The impact of committed generation projects on thegrid backbone is dealt with separately in Chapter 6.The maximum generation that can be connected depends on several factors andusually falls within a range. Generation developers should consult with us at an earlystage of their investigations to discuss connection issues.18.11.1 Impact of generation scenarios on regional planThe generation scenarios (see Chapter 5) represent a series of possible futuregeneration outcomes. This section presents only those scenarios relevant to thisregion for the next 15 years.Generation scenarios 1, 2 and 4 anticipate North Bank generation connectingbetween Waitaki and Bells Pond tee, between Waitaki and Black Point tee, and to the220 kV Islington–Livingstone circuit. See Section 18.11.2 for more information aboutthis generation.Generation connecting to the 110 kV network will reduce loading on the Waitaki220/110 kV interconnecting transformers, and on sections of the Oamaru–Waitaki110 kV circuits between Waitaki and the generation injection points.Dispatch will also be constrained by overloading on line sections between thegeneration injection points and Oamaru.To allow new generation to connect without dispatch constraints will requireupgrading the line sections between the injection points and Oamaru.3202013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 18: South Canterbury Region18.11.2 North Bank projectThe proposed North Bank hydro project, located on the north bank of the WaitakiRiver, consists of two hydro generation stations with a total capacity of approximately265 MW.The proposed connection option is one generation station connecting to the 110 kVGlenavy–Waitaki–A line, and the other generation station connecting to the 220 kVRoxburgh–Islington–A line. It is likely that the Lower Waitaki Valley grid upgrade planmay have some effect on the generation dispatch for the generation stationconnecting to the 110 kV line. At times, depending on the connection configuration,some generation may be constrained post-contingency. The generation connectionconfiguration is yet to be finalised.18.11.3 Wind generationThere are no issues with connecting wind or other generation at existing substationswithin the Waitaki Valley at 220 kV.Connecting too much generation to one of the four circuits to Christchurch may causeit to overload and reduce the maximum load that can be supplied across the circuits.The maximum generation that can be connected varies with the point of connectionand the circuit. Connections close to the Waitaki Valley enable the most generation,approximately equal to the circuit rating. The best-case location and circuit willenable 400 to 700 MW of generation. The worst-case location and circuit will notsupport the dispatch of generation.Unless the 110 kV Tekapo A–Albury–Timaru circuit is upgraded, there is limitedopportunity to connect new generation because of the existing generation atTekapo A, and the Opuha generation embedded at Albury.The other 110 kV circuits in the South Canterbury region can support generationconnections up to or slightly higher than the circuit rating.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 321

Chapter 19: Otago-Southland Region19 Otago-Southland Regional Plan19.1 Regional overview19.2 Otago-Southland transmission system19.3 Otago-Southland demand19.4 Otago-Southland generation19.5 Otago-Southland significant maintenance work19.6 Future Otago-Southland projects summary and transmission configuration19.7 Changes since the 2012 Annual Planning Report19.8 Otago-Southland transmission capability19.9 Otago-Southland bus security19.10 Other regional items of interest19.11 Otago-Southland generation scenarios, proposals and opportunities19.1 Regional overviewThis chapter details the Otago-Southland regional transmission plan. We base thisregional plan on an assessment of available data, and welcome feedback to improveits value to all stakeholders.Figure 19-1: Otago-Southland regionConstruction voltages shown. System as at March 2013.3222013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 19: Otago-Southland RegionThe Otago-Southland region includes a mix of significant and growing provincial cities(Dunedin and Invercargill) together with smaller rural localities (Queenstown andWanaka), and the largest electricity consumer in New Zealand, Tiwai Point AluminiumSmelter.We have assessed the Otago-Southland region’s transmission needs over the next15 years while considering longer-term development opportunities. Specifically, thetransmission network needs to be flexible to respond to a range of future service andtechnology possibilities, taking into consideration:the existing transmission networkforecast demandforecast generationequipment replacement based on condition assessment, andpossible technological development.19.2 Otago-Southland transmission systemThis section highlights the state of the Otago-Southland regional transmissionnetwork. The existing transmission network is set out geographically in Figure 19-1and schematically in Figure 19-2.Figure 19-2: Otago-Southland transmission schematicSOUTH CANTERBURYTwizelCromwell220 kV33 kVNasebySOUTH CANTERBURYLivingstoneFrankton33 kV220 kV33 kV110 kV220 kVClyde33 kVPalmerston33 kVRoxburgh110 kV220 kVManapouri110 kV33 kV110 kV220 kVThreeMile Hill220 kVHalfway Bush220 kVNorth Makarewa220 kV33 kV110 kVGore33 kVBrydone110 kV 11 kV110 kV33 kVEdendale220 kV 33 kVSouth Dunedin110 kVBerwick110 kVKEY33 kV220kV CIRCUITBalclutha110kV CIRCUIT33kV CIRCUITSUBSTATION BUS220 kVTRANSFORMER33 kVInvercargill3 WDG TRANSFORMERTEE POINTLOADTiwai220 kVCAPACITORGENERATOR19.2.1 Transmission into the regionThere are issues with the transmission capacity to transfer power into or out of theOtago-Southland region.When Otago-Southland generation is high, transmission capacity from Roxburgh mayconstrain generation dispatch within the region for some outages. With low Otago-Southland generation, the transmission capacity of the circuits from Twizel and2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 323

Chapter 19: Otago-Southland RegionLivingstone to Roxburgh may exceed their thermal ratings to supply the deficit powerto the region.Under the Clutha-Upper Waitaki Lines Project (formerly known as Lower South IslandFacilitating Renewables), we have committed to upgrading the Clyde–Roxburgh andAviemore–Waitaki–Livingstone circuits by 2014. In mid-2013, we will review thetiming for the delivery of the remaining sections, namely:reconductoring the Livingstone–Naseby–Roxburgh, Aviemore–Benmore circuits,andthermally upgrading the Cromwell–Twizel circuits.See Chapter 6, Section 6.6.3, for more information.19.2.2 Transmission within the regionThe transmission within the Otago-Southland region comprises 220 kV and 110 kVtransmission circuits with interconnecting transformers located at Cromwell, HalfwayBush, Roxburgh and Invercargill.Capacitors are installed at North Makarewa to improve the system voltage andvoltage stability performance. There are also capacitors on the supply bus atBrydone for power factor correction and system voltage.The region can be divided into four load centres.The Southland 220 kV region, comprising Tiwai, Invercargill, and NorthMakarewa substations, is predominantly supplied from Manapouri, or via the220 kV Invercargill–Roxburgh circuits at times of low Manapouri generation.The Dunedin region, comprising South Dunedin, Halfway Bush and Palmerston,is predominantly supplied via Three Mile Hill.The Southland 110 kV network is supplied via the three interconnectingtransformers at Halfway Bush, Roxburgh, and Invercargill.The Central Otago area represents load supplied from Cromwell and Frankton viathe Cromwell interconnecting transformers.The 110 kV transmission network within the Otago-Southland region predominantlycomprises low-capacity circuits supplying the smaller centres within the region. Bothcapacity and voltage issues arise during outages. In addition, most of thetransformers connected to the 110 kV transmission network are older, single-phaseunits, with an expected end-of-life within the next 20 years.We have committed to implementing the Lower South Island Reliability Project toincrease the capacity of the 110 kV and 220 kV transmission network within theregion. It addresses existing issues and provides the foundation for future upgradeswhen required. The project includes a new 220/110 kV interconnection at the Goresubstation, replacing the Invercargill 220/110 kV transformer with a unit with anon-load tap changer, and replacing the Roxburgh 220/110 kV transformer with ahigher-rated unit (recently completed). The project also included a series capacitoron a North Makarewa–Three Mile Hill circuit. However, due to a reduced loadforecast, the need for the series capacitor was reassessed. It is expected to berequired in about 2025, but this will be reassessed in 2015. See Chapter 6, Section6.6.4, for more information.19.2.3 Longer-term development pathThe Lower South Island Reliability Project addresses existing issues and provides thefoundation for future upgrades when required, which will potentially include additionalreactive support and increased line compensation.3242013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 19: Otago-Southland Region19.3 Otago-Southland demandThe after diversity maximum demand (ADMD) for the Otago-Southland region isforecast to grow on average by 0.6% annually over the next 15 years, from 1,140 MWin 2013 to 1,250 MW by 2028. This is lower than the national average demandgrowth of 1.5% annually.Figure 19-3 shows a comparison of the 2012 and 2013 APR forecast 15-yearmaximum demand (after diversity 164 ) for the Otago-Southland region. The forecastsare derived using historical data, and modified to account for customer information,where appropriate. The power factor at each grid exit point is also derived fromhistorical data. See Chapter 4 for more information about demand forecasting.Figure 19-3: Otago-Southland region after diversity maximum demand forecastTable 19-1: lists forecast peak demand (prudent growth) for each grid exit point forthe forecast period, as required for the Grid Reliability Report.Table 19-1: Forecast annual peak demand (MW) at Otago-Southland grid exit points to2028Grid exit pointPowerfactorNext 5 yearsPeak demand (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Balclutha 0.95 31 31 32 33 33 34 35 37 38 40 41Brydone 0.79 11 11 11 11 11 11 11 11 11 11 11Cromwell 1.00 34 35 36 37 38 39 41 43 45 47 49Clyde 0.96 10 10 11 11 11 11 12 12 13 13 14Edendale 1 0.95 31 36 37 38 40 41 43 45 48 50 52Frankton 1.00 59 61 63 64 66 67 71 74 78 81 84Gore 2 0.97 34 34 35 56 56 57 59 60 62 63 65164 The after diversity maximum demand (ADMD) for the region will be less than the sum of theindividual grid exit point peak demands, as it takes into account the fact that the peak demand doesnot occur simultaneously at all the grid exit points in the region.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 325

Chapter 19: Otago-Southland RegionGrid exit pointPowerfactorNext 5 yearsPeak demand (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Halfway Bush -1 3 0.98 90 91 82 83 84 85 88 90 92 95 97Halfway Bush -2 3 0.98 45 45 41 42 42 43 44 45 46 47 48Invercargill 0.99 106 108 110 112 115 117 121 126 130 135 139Naseby 0.99 32 32 33 34 34 35 36 38 39 41 42North Makarewa 0.97 60 61 63 64 65 66 69 72 75 77 80Palmerston 0.97 10 10 11 11 11 11 12 12 13 13 14South Dunedin 0.98 78 79 95 96 97 98 100 102 104 106 108Tiwai 0.96 640 640 640 645 650 655 665 675 685 690 6901. The prudent forecast allows for incremental demand growth at the Edendale Dairy plant.2. The prudent forecast has included 20 MW of new load at Gore to reflect plans by Solid Energy todevelop the processing of lignite into briquettes or liquid fuels. This is now in doubt.3. The peak demand forecast at Halfway Bush 1 and 2 is shown as an average historical percentage ofthe expected aggregated demand at Halfway Bush. Historically there has been load shifting betweenthe two, giving much higher individual peak demands.19.4 Otago-Southland generationThe Otago-Southland region’s generation capacity is 1,831 MW. 165 This generationusually contributes a major portion of the total South Island generation and exceedslocal demand. Surplus generation is exported over the National Grid to other demandcentres in the South Island.Table 19-2 lists the generation forecast for each grid injection point for the forecastperiod, as required for the Grid Reliability Report. This includes all known andcommitted generation stations, including those embedded within the relevant locallines company’s network (PowerNet, OtagoNet, or Aurora). 166Table 19-2: Forecast annual generation capacity (MW) at Otago-Southland grid injectionpoints to 2028 (including existing and committed generation)Grid injectionpoint (location ifembedded)Next 5 yearsGeneration capacity (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Clyde 432 432 432 432 432 432 432 432 432 432 432Manapouri 840 840 840 840 840 840 840 840 840 840 840Roxburgh 320 320 320 320 320 320 320 320 320 320 320Balclutha (Mt.Stuart)Berwick/HalfwayBush (Waiporiand Mahinerangi)8 8 8 8 8 8 8 8 8 8 88436843684368436Clyde (Fraser) 3 3 3 3 3 3 3 3 3 3 3Clyde (HorseshoeBend hydro andwind)42424242Clyde (Talla Burn) 3 3 3 3 3 3 3 3 3 3 3Clyde (Teviot andKowhai)112112112112843642112843642112843642112843642112843642112843642112843642112165 This excludes the resource consent applications for the Clyde and Roxburgh generation stationcapacity increases.166 Only generators with a capacity greater than 1 MW are listed. Generation capacity is rounded to thenearest megawatt.3262013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 19: Otago-Southland RegionGrid injectionpoint (location ifembedded)Cromwell(Roaring Meg)Frankton (WyeCreek)Halfway Bush(Deep Stream)Naseby (FallsDam)Next 5 yearsGeneration capacity (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 20284 4 4 4 4 4 4 4 4 4 41 1 1 1 1 1 1 1 1 1 15 5 5 5 5 5 5 5 5 5 51 1 1 1 1 1 1 1 1 1 1Naseby (Paerau) 10 10 10 10 10 10 10 10 10 10 10North Makarewa(Monowai)North Makarewa(White Hill)7 7 7 7 7 7 7 7 7 7 758 58 58 58 58 58 58 58 58 58 5819.5 Otago-Southland significant maintenance workOur capital project and maintenance works are integrated to enable system issues tobe resolved if possible when assets are replaced or refurbished. Table 19-3 lists thesignificant maintenance-related work 167 proposed for the Otago-Southland region forthe next 15 years that may significantly impact related system issues or connectedparties.Table 19-3: Proposed significant maintenance workDescription Tentative year Related system issuesBalclutha 33 kV outdoor to indoorconversionEdendale 110/33 kV supplytransformers expected end-of-lifeGore 110/33 kV supplytransformers expected end-of-life,and33 kV outdoor to indoorconversionHalfway Bush interconnectingtransformer expected end-of-lifeHalfway Bush 110/33 kV supplytransformer expected end-of-lifeHalfway Bush 33 kV outdoor toindoor conversionHalfway Bush 220/33 kV supplytransformer expected end-of-lifeInvercargill interconnectingtransformer expected end-of-lifeNaseby 220/33 kV supplytransformers replacement and33 kV outdoor to indoorconversion2013-2014 Capacitors incorporated into the Lower SouthIsland Reliability Project will be installed at thesame time. See Section 19.8.1 for moreinformation.2027-2029 The forecast load at Edendale exceeds thetransformers’ n-1 capacity from 2015. SeeSection 19.8.4 for more information.2025-20272015-2017We will investigate the timing and rating of thereplacement transformers. See Section 19.8.6for more information.2013-2015 This work will be coordinated with thereplacement of the supply transformers tominimize outages.2014-20162014-20162024-2026The Halfway Bush load already exceeds thetransformer’s n-1 capacity. The overloadingissue is currently managed operationally. Thiswork will be coordinated with the replacement ofthe interconnecting transformers. SeeSection 19.8.7 for more information.2013-2014 The transformer replacement is incorporated intothe Lower South Island Reliability Project. SeeSection 19.8.1 for more information.2018-2020 The forecast load at Naseby exceeds thetransformers’ n-1 capacity from 2018. We willinvestigate the timing and rating of thereplacement transformers. See Section 19.8.9for more information.167 This may include replacement of the asset due to its condition assessment.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 327

Chapter 19: Otago-Southland RegionDescription Tentative year Related system issuesNorth Makarewa 220 kV capacitorbank replacementPalmerston supply transformerexpected end-of-life, and 33 kVoutdoor to indoor conversionSouth Dunedin 220/33 kV supplytransformer expected end-of-life,and 33 kV outdoor to indoorconversion2020-2022 Increasing the rating of the capacitor banks willbe investigated as part of the replacement. SeeSection 19.8.1 for more information.2016-2018 There is no n-1 security at Palmerston.Discussion about future supply security atPalmerston is currently underway. See Section19.8.11 for more information.2024-20262012-2014Resolving the metering and protection limits willsolve the transformers’ n-1 capacity issue for theforecast period. See Section 19.8.13 for moreinformation.19.6 Future Otago-Southland projects summary and transmissionconfigurationTable 19-4 lists projects to be carried out in the Otago-Southland region within thenext 15 years.Figure 19-4 shows the possible configuration of Otago-Southland transmission in2028, with new assets, upgraded assets, and assets undergoing significantmaintenance within the forecast period.Table 19-4: Projects in the Otago-Southland region up to 2028Circuit/site Projects StatusBalcluthaClyde–RoxburghCromwellCromwell–FranktonCromwell–TwizelEdendaleFranktonGoreHalfway BushInvercargillLivingstone–NasebyNaseby–RoxburghNasebyNorthMakarewa–ThreeUpgrade the supply transformer branch limiting components.Upgrade the supply transformer protection.Convert the 33 kV outdoor switchgear to an indoor switchboard.Install 33 kV capacitors.Increase the 220 kV circuit capacities by duplexing the linesconnecting Clyde and Roxburgh.Upgrade the supply transformer protection, and branch limitingcomponents.Thermally upgrade the circuits.Increase the 220 kV circuit capacities by thermally upgrade the linesconnecting Cromwell and Twizel.Upgrade the cable on the supply transformers.Replace the supply transformers with two higher-rated units.Upgrade the supply transformer (T4) branch limiting components.Replace the two parallel transformers with a higher rated unit.Install two 220/110 kV interconnecting transformers.Replace the supply transformers.Convert the 33 kV outdoor switchgear to an indoor switchboard.Replace two 110/33 kV supply transformers with one 220/33 kV unit.Replace the 220/33 kV supply transformer.Replace the 220/110 kV interconnecting transformer.Convert the 33 kV outdoor switchgear to an indoor switchboard.Close 33 kV bus.Replace the 220/110 kV transformer with a higher-rated unit.Upgrade supply transformer metering equipment.Increase the 220 kV circuit capacity by duplexing the line connectingLivingstone and Naseby.Increase the 220 kV circuit capacity by duplexing the line connectingNaseby and Roxburgh.Replace the supply transformers with two higher-rated units.Convert the 33 kV outdoor switchgear to an indoor switchboard.Install a series capacitor on one of the North Makarewa–Three MileHill circuits.PossiblePossibleProposedCommittedCommittedProposedPossibleCommittedPossiblePossiblePossiblePossibleCommittedProposedProposedProposedProposedProposedProposedPossibleCommittedPossibleCommittedCommittedPossibleProposedCommitted3282013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 19: Otago-Southland RegionCircuit/site Projects StatusMile HillNorth MakarewaPalmerstonSouth DunedinReplace the shunt capacitors.Replace 220/33 kV transformers with 220/66 kV units.Replace the supply transformer.Convert the 33 kV outdoor switchgear to an indoor switchboard.Upgrade the supply transformer metering equipment.Replace the 220/33 kV T1 supply transformer.Convert the 33 kV outdoor switchgear to an indoor switchboard.ProposedPossibleProposedProposedPossibleProposedProposedFigure 19-4: Possible Otago-Southland transmission configuration in 2028SOUTH CANTERBURYTwizelCromwell*220 kV33 kVNasebySOUTH CANTERBURYLivingstoneFrankton33 kV*110 kV33 kV220 kV220 kV33 kVClydePalmerston33 kVRoxburgh110 kVManapouri220 kV110 kV110 kV33 kV220 kVThreeMile Hill220 kVHalfway Bush220 kV*66 kV110 kVGore33 kV220 kV 33 kVSouth Dunedin110 kVBerwickNorth Makarewa220 kV110kV*Brydone110 kV 11 kV*110 kV33 kVEdendale220 kV33 kVInvercargill*110 kV33 kVBalcluthaKEYNEW ASSETSUPGRADED ASSETSASSETS SCHEDULEDFOR REPLACEMENTMINOR UPGRADE*Tiwai220 kV19.7 Changes since the 2012 Annual Planning ReportTable 19-5 lists the specific issues that are either new or no longer relevant within theforecast period when compared to last year's report.Table 19-5: Changes Since 2012IssuesRoxburgh interconnecting transformer capacityChangeRemoved. This asset has been replaced with ahigher-rated unit as part of the Lower South Islandreliability Project.19.8 Otago-Southland transmission capabilityTable 19-6 summarises issues involving the Otago-Southland region for the next 15years. For more information about a particular issue, refer to the listed sectionnumber.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 329

Chapter 19: Otago-Southland RegionTable 19-6: Otago-Southland region transmission issuesSectionnumberIssueRegional19.8.1 Southland transmission capacity and low voltageSite by grid exit point19.8.2 Balclutha supply transformer capacity19.8.3 Cromwell supply transformer capacity19.8.4 Edendale supply transformer capacity19.8.5 Frankton transmission and supply security19.8.6 Gore supply transformer capacity19.8.7 Halfway Bush supply transformer capacity19.8.8 Invercargill supply transformer capacity19.8.9 Naseby supply transformer capacity19.8.10 North Makarewa supply transformer capacity19.8.11 Palmerston supply security and supply transformer capacity19.8.12 Palmerston transmission security19.8.13 South Dunedin supply transformer capacity19.8.14 Waipori transmission securityBus security19.9.1 Transmission bus security19.8.1 Southland transmission capacity and low voltageProject context:Lower South Island ReliabilityProject reference: STLD-TRAN-EHMT-01Project status/type: Committed, Major Capex ProposalIndicative timing: 2012-2015Indicative cost band: EIssueThe 220 kV Southland transmission network forms a geographical triangle linking thesubstations at Roxburgh, Halfway Bush and Invercargill. At each corner of thistriangle, a 220/110 kV interconnecting transformer supplies the 110 kV network.The 110 kV network features a similar geographical triangle between Roxburgh,Halfway Bush, and Gore, with a single 110 kV circuit from Gore to Brydone,Edendale, and Invercargill.This configuration can result in 110 kV network overloading and low voltages. At thetimes when Manapouri generation is low, the 220 kV network may also overload.OverloadingSome of the Southland 110 kV circuits and/or interconnecting transformers mayoverload for an outage of:some of the Southland 110 kV circuitsone of the 220 kV Invercargill–Roxburgh circuits, orone of the 220 kV Roxburgh–Three Mile Hill circuits.A 220 kV Invercargill–Roxburgh circuit may also overload for an outage of the parallelcircuit.3302013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 19: Otago-Southland RegionThe severity of these overloads depends on Roxburgh, Manapouri, and Waiporigeneration at the time of the outage.Low voltagesAn outage of some of the Southland transmission circuits or interconnectingtransformers may result in low voltages at Palmerston, Halfway Bush, Balclutha,Gore, and Edendale.An outage of the 110 kV Balclutha–Berwick–Halfway Bush circuit may result in lowvoltage at Balclutha and Gore.SolutionThe overloading issues can be managed operationally by regulating the amount ofgeneration at Manapouri, Waipori and Roxburgh. The extent to which generationmay need to be regulated will depend on the generation dispatched in the SouthIsland at the time. In addition, some load can be transferred from the Halfway Bush110 kV bus to the 220 kV bus, and some low voltage problems can be resolved usingthe existing transformer off-load tap changers.We have committed to implementing the Lower South Island Reliability Project toincrease the transmission capacity between Roxburgh and Invercargill. The projectincludes the following:Installing Special Protection Schemes to allow sufficient build time.Replacing the Roxburgh 220/110 kV interconnecting transformer with a 150 MVAunit (completed in November 2012).Replacing the existing Invercargill 220/110 kV interconnecting transformer withan 80 MVA unit.Installing shunt capacitors for reactive support at Balclutha.Installing a new 220/110 kV interconnection point comprising two 220/110 kVtransformers at Gore. A two kilometre 220 kV double-circuit line is connectedfrom the Gore substation to the 220 kV Three Mile Hill–North Makarewa line.Installing a series capacitor on one of the North Makarewa–Three Mile Hillcircuits. 168Possible property implications are as follows.Designation and acquisition of property rights will be required for the twokilometre 220 kV double-circuit line, which will tee connect from the Goresubstation to the 220 kV Three Mile Hill–North Makarewa line.Substation expansion will be required at Three Mile Hill to install the seriescapacitor.19.8.2 Balclutha supply transformer capacityProject reference:Project status/type:Indicative timing: 2013-2014Indicative cost band: ABAL-POW_TFR -EHMT-01Upgrade protection: possible, Base CapexUpgrade branch component: possible, Base CapexIssueTwo 110/33 kV transformers supply Balclutha’s load, providing:a total nominal installed capacity of 60 MVA, and168 Due to a reduced load forecast, the series capacitor is deferred. The need date is expected to beafter 2020, but this will be reviewed in 2015.2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 331

Chapter 19: Otago-Southland Regionn-1 capacity of 31/31 MVA 169 (summer/winter).The peak load at Balclutha is forecast to exceed the transformers’ n-1 winter capacityby approximately 5 MW in 2013, increasing to approximately 15 MW in 2028 (seeTable 19-7).Table 19-7: Balclutha supply transformer overload forecastCircuit/gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Balclutha 0.95 5 5 6 6 7 8 9 10 12 13 15SolutionThe overloading issues can be managed operationally. All the branch componentlimits will be removed as part of the 33 kV outdoor switchgear to indoor switchboardconversion, which will resolve the issue until 2018. The installation of new capacitorsat 33 kV (as part of the Lower South Island Reliability Project) will also release someadditional capacity. These works, planned for 2013-2014, will be coordinated and willallow the full capacity of the transformers to be used.19.8.3 Cromwell supply transformer capacityProject reference: Upgrade protection limit: CML-POW_TFR-EHMT-01Upgrade branch limiting components: CML-POW_TFR-EHMT-02Project status/type: Upgrade protection limit: possible, Base CapexUpgrade branch limiting components: possible, customer-specificIndicative timing: Upgrade protection limit: 2019Upgrade branch limiting components: 2025Indicative cost band: Upgrade protection limit: AUpgrade branch limiting components: AIssueTwo 220/110/33 kV transformers (rated at 73 MVA 170 and 50 MVA) supply Cromwell’s33 kV loads, with:a total nominal installed capacity of 123 MVA, andn-1 capacity of 41/41 MVA 171 (summer/winter).The peak load at Cromwell is forecast to exceed the transformers’ n-1 winter capacityby approximately 2 MW in 2022, increasing to approximately 8 MW in 2028 (seeTable 19-8).Table 19-8: Cromwell supply transformer overload forecastCircuit/gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Cromwell 1.0 0 0 0 0 0 0 0 2 4 6 8169 The transformers’ capacity is limited by the protection limit, followed by the metering limit of 34 MVA,and circuit breaker limit of 37 MVA; with these limits resolved the n-1 capacity will be 37/39 MVA(summer/winter).170 This is a bank of two transformers connected in parallel and operated as a single unit, with the 33 kVtransformer windings providing a combined nominal installed capacity of 73 MVA.171 The transformer’s capacity is limited by the protection limit of 41 MVA, followed by the currenttransformer, circuit breaker and disconnector limit of 46 MVA, and a bus section limit of 50 MVA;with these limits resolved, the n-1 capacity will be 65/68 MVA (summer/winter).3322013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 19: Otago-Southland RegionSolutionResolving the protection limit will provide sufficient n-1 capacity until 2024.Upgrading other transformer branch limiting components will resolve the issue for theforecast period and beyond. Future investment will be customer driven.19.8.4 Edendale supply transformer capacityProject reference: Upgrade protection: EDN-POW_TFR-EHMT-01Upgrade cable: EDN-POW_TFR-EHMT-02Upgrade transformer capacity: EDN-POW_TFR-EHMT-03Project status/type: Upgrade protection: possible, Base CapexUpgrade cable: possible, customer-specificUpgrade transformer capacity: possible, customer-specificIndicative timing: Upgrade protection: 2013Upgrade cable: 2013Upgrade transformer capacity: 2014Indicative cost band: Upgrade protection: AUpgrade cable: AUpgrade transformer capacity: BIssueTwo 110/33 kV transformers supply Edendale’s load, providing:a total nominal installed capacity of 60 MVA, andn-1 capacity of 32/32 MVA 172 (summer/winter).The peak load at Edendale is forecast to exceed the n-1 summer capacity byapproximately 2 MW in 2013, increasing to approximately 24 MW in 2028 (see Table19-9).Table 19-9: Edendale supply transformer overload forecastCircuit/gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Edendale 0.95 2 7 9 10 11 12 14 17 19 21 24SolutionResolving the cable limit will resolve the issue until 2014. We will discuss futuresupply options with PowerNet, including:operational management by transferring or limiting the load within the capabilityof the supply transformer, orreplacing the existing transformers with two higher-rated units.In addition, both supply transformers at Edendale have an expected end-of-life at theend of the forecast period. We will discuss the rating and timing for the replacementtransformers with PowerNet. Future investment will be customer driven.19.8.5 Frankton transmission and supply securityProject reference: Upgrade protection and metering: FKN-POW_TFR-EHMT-01Upgrade line thermal capacity: CML_FKN-TRAN-EHMT-01Upgrade transformer capacity: FKN-POW_TFR-EHMT-02Project status/type: Upgrade protection and metering: possible, Base CapexUpgrade line and transformer capacities: possible, customer-specificIndicative timing: Upgrade line thermal capacity: 2022Upgrade protection and metering, and transformer capacity: 2024172 The transformers’ capacity is limited by the cable and protection limit; with these limits resolved, then-1 capacity will be 34/36 MVA (summer/winter).2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 333

Chapter 19: Otago-Southland RegionIndicative cost band:Upgrade line thermal capacity: to be advisedUpgrade protection and metering: AUpgrade transformer capacity: AIssueTwo 110 kV Cromwell–Frankton circuits supply Frankton’s load, providing:a total nominal installed capacity of 127/155 MVA (summer/winter), andn-1 capacity of 63/76 MVA 173 (summer/winter).Two 110/33 kV transformers (rated at 66 MVA 174 and 85 MVA) supply Frankton’sload, providing:a total nominal installed capacity of 158 MVA, andn-1 capacity of 80/80 MVA 175 (summer/winter).There is no 110 kV bus at Frankton. A fault on either a circuit or Frankton supplytransformer will cause both the circuit and supply transformer to be taken out ofservice.The peak load at Frankton is forecast to exceed the circuits’ n-1 winter thermalcapacity from approximately 2022, and the transformers’ n-1 winter capacity byapproximately 3 MW in 2024, increasing to approximately 10 MW in 2028 (see Table19-10).Table 19-10: Frankton supply transformer and Cromwell–Frankton circuit overloadforecastCircuit/grid exitpointPowerfactorNext 5 yearsTransformer/circuit overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Frankton 1.0 0 0 0 0 0 0 0 0 3 7 10Cromwell–Frankton circuitsNA 0 0 0 0 0 0 0 3 6 10 13SolutionWe will discuss future supply options with Aurora closer to the time the issue arises.Possible options are:implementing Variable Line Ratings (VLR) and/or thermally upgrading theCromwell–Frankton circuitsresolving the transformer protection limit, andreplacing the existing bank of transformers with a higher-rated unit.Easements on some small parts of the line may be required for the thermal upgradework. Future investment will be customer driven.19.8.6 Gore supply transformer capacityProject reference:Project status/type:Indicative timing:Indicative cost band:GOR-POW_TFR-EHMT-01Possible, customer-specificTo be advisedReplace transformers with higher-rated units: B173 The circuits’ capacity is limited by a line trap; with this limit resolved, the n-1 capacity will be63/77 MVA (summer/winter).174This is a bank of two transformers connected in parallel and operated as a single unit, providing atotal nominal installed capacity of 66 MVA.175 The transformer’s capacity is limited by the protection limit, followed by the metering (82 MVA) andLV cable (90 MVA) limits; with these limits resolved, the n-1 capacity will be 77/82 MVA(summer/winter), which is the thermal limit of the bank of two parallel transformers.3342013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 19: Otago-Southland RegionIssueTwo 110/33 kV transformers supply Gore’s load, providing:a total nominal installed capacity of 60 MVA, andn-1 capacity of 37/39 MVA (summer/winter).The peak load at Gore is forecast to exceed the transformers’ n-1 winter capacity byapproximately 20 MW in 2016, increasing to approximately 29 MW in 2028 (seeTable 19-11).Table 19-11: Gore supply transformer overload forecastCircuit/gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Gore 0.97 0 0 0 20 21 21 23 24 26 27 29SolutionWe will discuss future supply options with PowerNet, including:load projections and developments in the areamanaging the load to within the capability of the existing transformers, orreplacing the existing transformers with two higher-rated units.In addition, both supply transformers have an expected end-of-life within the forecastperiod. We also plan to convert the Gore 33 kV outdoor switchgear to an indoorswitchboard within the next five years.The solutions do not raise property issues as the existing substation has sufficientroom to accommodate the transformers and an indoor switchboard.19.8.7 Halfway Bush supply transformer capacityProject reference: Close 33 kV bus: HWB-BUSG-EHMT-01Replace 110/33 kV transformers: HWB-POW_TFR-EHMT-01Replace 220/33kV transformers: HWB-POW_TFR-EHMT-02Project status/type: Close 33 kV bus: possible, customer-specificReplace 110/33 kV transformers: proposed, Base CapexReplace 220/33 kV transformers: proposed, Base CapexIndicative timing: 2016-2026Indicative cost band: To be advisedIssueThree transformers supply Halfway Bush’s 33 kV load, comprising:two 110/33 kV transformers, each with nominal capacity of 50 MVA, and n-1capacity of 54/57 MVA (summer/winter), andone 220/33 kV transformer, with a nominal capacity of 100 MVA, and n-1capacity of 112/112 MVA 176 (summer/winter).We operate the 33 kV bus split with:both 110/33 kV transformers connected in parallel supplying one bus section, andthe 220/33 kV transformer supplying the other bus section, resulting in nocontinuous n-1 supply security.176 The transformers’ capacity is limited by a protection limit; with this limit resolved, the n-1 capacity willbe 113/119 MVA (summer/winter).2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 335

Chapter 19: Otago-Southland RegionThe 33 kV bus split can be closed during an outage of any one of the threetransformers supplying the 33 kV load. This provides an n-1 capacity of107/114 MVA (summer/winter) for an outage of the 220/33 kV transformer.The peak load at Halfway Bush is forecast to exceed the transformer’s n-1 wintercapacity by approximately 12 MW in 2013, increasing to approximately 23 MW in2028 177 (see Table 19-12).Table 19-12: Halfway Bush supply transformer overload forecastCircuit/gridexit pointHalfwayBush–1 and 2PowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 20280.98 12 14 0 2 4 5 9 12 16 20 23SolutionThe Halfway Bush supply transformer loading may be reduced by:transferring load between the Halfway Bush 110 kV and 220 kV buses with the33 kV bus split, and/orincreasing the output from Waipori generation injecting into the Halfway Bush33 kV bus, and/ortransferring up to 5 MW via Aurora’s distribution network to South Dunedin.We are investigating closing the 33 kV bus permanently. This requires the 33 kV faultlevel, load sharing between the transformers, and the 33 kV bus voltage set-point andvoltage control to be checked for satisfactory system operation.All three supply transformers have an expected end-of-life within the forecast period.After discussions with Aurora, we are intending to replace the two 110/33 kV, 50 MVAsupply transformers with a single 220/33 kV, 120 MVA supply transformer by 2016.The old 220/33 kV, 100 MVA supply transformer will be replaced with a 120 MVA unitby 2026. The transformer replacements, with generation from Mahinerangi andWaipori as required, are expected to be sufficient well beyond the forecast period.Converting the 33 kV outdoor switchgear to an indoor switchboard is also scheduledto be carried out within the next five years, and we are co-ordinating this with some ofAurora’s feeder rationalization projects.Future investment will be customer driven.19.8.8 Invercargill supply transformer capacityProject reference: INV-POW_TFR-EHMT-01Project status/type: Possible, Base CapexIndicative timing: 2013Indicative cost band: AIssueTwo 220/33 kV transformers supply Invercargill’s load, providing:a total nominal installed capacity of 240 MVA, andn-1 capacity of 109/109 MVA 178 (summer/winter).177 This forecast assumes that Waipori station injects 16 MW of power into the Halfway Bush 33 kV bus.178 The transformers’ capacity is limited by metering equipment; with this limit resolved, the n-1 capacitywill be 143/143 MVA (summer/winter).3362013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 19: Otago-Southland RegionThe peak load at Invercargill is forecast to exceed the transformers’ n-1 wintercapacity by approximately 1 MW in 2013, increasing to approximately 34 MW in 2028(see Table 19-13).Table 19-13: Invercargill supply transformer overload forecastCircuit/gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Invercargill 0.99 1 3 5 7 10 12 16 21 25 30 34SolutionRecalibrating the metering parameters at Invercargill will solve the issue within theforecast period.19.8.9 Naseby supply transformer capacityProject reference: NSY-POW_TFR-EHMT-01Project status/type: Possible, customer-specificIndicative timing: 2018-2020Indicative cost band: BIssueTwo 220/33 kV transformers supply Naseby’s load, providing:a total nominal installed capacity of 70 MVA, andn-1 capacity of 35/35 MVA (summer/winter).The peak load at Naseby is forecast to exceed the transformers’ n-1 summer capacityby approximately 1 MW in 2018, increasing to approximately 8 MW in 2028 (seeTable 19-14).Table 19-14: Naseby supply transformer overload forecastCircuit/gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Naseby 0.99 0 0 0 0 0 1 2 4 5 6 8SolutionWe will discuss future supply options with PowerNet, which include:managing the load to within the capability of the existing transformers, orreplacing the existing transformers with two higher-rated units.In addition, converting the 33 kV outdoor switchgear to an indoor switchboard is alsoscheduled to be carried out at about the same time. We will discuss the rating andtiming for the replacement transformers with PowerNet, and co-ordinate the outdoorto indoor conversion project with the replacement work.Future investment will be customer driven.19.8.10 North Makarewa supply transformer capacityProject reference: NMA-POW_TFR-EHMT-01Project status/type: Possible, customer-specificIndicative timing: 2019Indicative cost band: To be advised2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 337

Chapter 19: Otago-Southland RegionIssueTwo 220/33 kV transformers supply North Makarewa’s load, providing:a total nominal installed capacity of 120 MVA, andn-1 capacity of 67/67 MVA 179 (summer/winter).The peak load at North Makarewa is forecast to exceed the transformers’ n-1 wintercapacity by approximately 1 MW in 2022, increasing to approximately 9 MW in2028 180 (see Table 19-15).Table 19-15: North Makarewa supply transformer overload forecastCircuit/gridexit pointNorthMakarewaPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 20280.97 0 0 0 0 0 0 0 1 4 6 9SolutionWe have discussed future supply options with PowerNet, which intends to replace thetwo existing 220/33 kV supply transformers with new 220/66 kV units by 2019.Future investment will be customer driven.19.8.11 Palmerston supply security and supply transformer capacityProject status/type:This issue is for information onlyIssueA single 110/33 kV, 10 MVA supply transformer comprising three single-phase unitssupplies the load at Palmerston, resulting in no n-1 security. The peak load atPalmerston is forecast to exceed the transformers’ capacity by approximately 1 MWin 2013, increasing to approximately 4 MW in 2028 (see Table 19-16).Table 19-16: Palmerston supply transformer overload forecastCircuit/gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028Palmerston 0.97 1 1 1 1 2 2 2 3 3 4 4SolutionThere is a non-contracted spare unit on-site unit providing backup after a unit failure,with replacement taking 8-14 hours. A limited amount of load can also be backfeedthrough the OtagoNet transmission network.This transformer also has an expected end-of-life within the next five years. We arediscussing future development options with OtagoNet. Future investment will becustomer driven.179 The transformers’ capacity is limited by an LV cable limit, followed by the circuit breaker (69 MVA)and disconnector (71 MVA) limits; with these limits resolved, the n-1 capacity will be 76/79 MVA(summer/winter).180 This forecast assumes that White Hills wind generation station injects 11 MW of power into the NorthMakarewa 33 kV bus.3382013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 19: Otago-Southland Region19.8.12 Palmerston transmission securityProject status/type:This issue is for information onlyIssueTwo 110 kV circuits supply Palmerston’s load, which include the:Halfway Bush–Palmerston–1 circuit, andHalfway Bush–Palmerston–2 circuit.Neither circuit has a circuit breaker at Palmerston, preventing the two circuits fromnormally operating in parallel. The Halfway Bush–Palmerston–2 circuit is normallyopen and the loss of the Halfway Bush–Palmerston–1 circuit will result in a short lossof supply to Palmerston until the other circuit can be put into service. Consequently,Palmerston has no continuous n-1 supply security.SolutionThe issue can be managed operationally. Future investment will be customer driven.19.8.13 South Dunedin supply transformer capacityProject reference: SDN-POW_TFR-EHMT-01Project status/type: Possible, Base CapexIndicative timing: 2015Indicative cost band: AIssueTwo 220/33 kV transformers supply South Dunedin’s load, providing:a total nominal installed capacity of 200 MVA, andn-1 capacity of 81/81 MVA 181 (summer/winter).The peak load at South Dunedin is forecast to exceed the transformers’ n-1 wintercapacity by approximately 15 MW in 2015, increasing to approximately 29 MW in2028 (see Table 19-17).Table 19-17: South Dunedin supply transformer overload forecastCircuit/gridexit pointPowerfactorNext 5 yearsTransformer overload (MW)5-15 years out2013 2014 2015 2016 2017 2018 2020 2022 2024 2026 2028South Dunedin 0.98 0 0 15 16 17 18 20 22 24 27 29SolutionRecalibrating the metering parameters at South Dunedin resolves the issue within theforecast period.In addition, the South Dunedin 33 kV outdoor switchyard will be converted to anindoor switchboard within the next five years. We will resolve the metering limitsduring the conversion work. Also, the South Dunedin–T1 supply transformer has anexpected end-of-life in the next 10-15 years. We will discuss the rating and timing forthe replacement transformer with Aurora.181 The transformers’ capacity is limited by metering equipment, followed by the protection limit of110 MVA; with these limits resolved, the n-1 capacity will be 132/139 MVA (summer/winter).2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 339

Chapter 19: Otago-Southland Region19.8.14 Waipori transmission securityProject status/type:This issue is for information onlyIssueWaipori generation injects into the Berwick 110 kV bus. The 110 kV Balclutha–Berwick and Berwick–Halfway Bush circuits have no line protection at the Berwickend, and both circuits will trip in the event of a line fault. This will disconnect Waiporigeneration from the National Grid, resulting in no n-1 connection security.SolutionTrustpower has not requested a higher security level and there are no plans toincrease supply security at this grid injection point. Future investment will becustomer driven. If n-1 connection security is eventually required, then lineprotection, together with the associated 110 kV current transformers and a voltagetransformer at Berwick, will need to be installed.19.9 Otago-Southland bus securityThe 2013 APR has been expanded to include issues arising from the outage of asingle bus section rated at 50 kV and above for the next 15 years.Bus outages disconnect more than one power system component (for example, othercircuits, transformers, reactive support or generators). Therefore, bus outages maycause greater issues than a single circuit or transformer outage (although the risk of abus fault is low, being less common than a circuit or transformer outage).19.9.1 Transmission bus securityTable 19-18 lists bus outages that cause voltage issues or a total loss of supply.Generators are included only if a bus outage disconnects the whole generationstation or causes a widespread system impact. Supply bus outages, typically 11 kVand 33 kV, are not listed.Table 19-18: Transmission bus outagesTransmissionbus outageBalclutha 110 kVBrydone 110 kVEdendale 110 kVGore 110 kVLoss ofsupplyBalcluthaBrydoneEdendaleGoreGenerationdisconnectionTransmissionissueFurtherinformationHalfway Bush 110 kV Halfway Bush 33kV 19.9.2PalmerstonHalfway Bush 220 kV Halfway Bush 33kV 19.9.2The customers (Aurora, PowerNet, OtagoNet, Solid Energy, or Dongwha Patinna)have not requested a higher security level. Future investment will be customerdriven. If increased bus security is required, the options typically include busreconfiguration and/or additional bus circuit breakers.19.9.2 Halfway Bush securityProject status/type:This issue is for information only3402013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Chapter 19: Otago-Southland RegionIssueThe Halfway Bush 33 kV bus is normally split.One side of the 33 kV bus is supplied through a single 220/33 kV supply transformer.An outage of the associated 220 kV bus will disconnect the single supply transformerand cause a loss of supply.The other side of the 33 kV bus is supplied through two 110/33 kV supplytransformers. An outage of the 110 kV bus will disconnect both supply transformersand cause a loss of supply.SolutionThis issue is managed operationally. Following a 220 kV or 110 kV bus outage, the33 kV bus split is closed, restoring the 33 kV supply.The two 110/33 kV supply transformers will be replaced with one 220/33 kVtransformer and the 33 kV bus split closed (See Section 19.8.7). The two 220/33 kVsupply transformers (the existing transformer and the new transformer) will each beon a separate 220 kV bus. Supply will be maintained for an outage of a 220 kV bus.19.10 Other regional items of interestThere are no other items of interest identified to date beyond those inSection 19.8 and Section 19.9. See Section 19.11 for more information aboutgeneration scenarios, proposals and opportunities relevant to this region.19.11 Otago-Southland generation scenarios, proposals and opportunitiesThis section details relevant regional issues for selected generation scenarios,generation proposals under investigation by developers and in the public domain, orother generation opportunities. The impact of committed generation projects on thegrid backbone is dealt with separately in Chapter 6.The maximum generation that can be connected depends on several factors andusually falls within a range. Generation developers should consult with us at an earlystage of their investigations to discuss connection issues.19.11.1 Impact of generation scenarios on regional planThe generation scenarios (see Chapter 5) represent a series of possible futuregeneration outcomes. This section presents only those scenarios relevant to thisregion for the next 15 years.Generation scenario 4 anticipates the connection of new thermal generation at NorthMakarewa in 2025 and 2028 (a 400 MW generic lignite thermal plant on each year).For a variety of contingencies affecting the connectivity of North Makarewa to theregion and under light load conditions the Invercargill-North Makarewa circuits couldoverload. Possible solutions could include constraining generation or increasing thecapacity of the circuits.No issues are anticipated by scenarios 1, 2, 3 and 5.19.11.2 Maximum regional generationOtago-Southland is a generation-rich region. Surplus generation export isconstrained by the 220 kV Naseby–Roxburgh–Livingstone circuit ratings. At times,existing generation needs to be constrained under light load conditions to avoidoverloading of the 220 kV Naseby–Roxburgh–Livingstone circuit under both normal2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 341

Chapter 19: Otago-Southland Regionoperating conditions and during contingent events (see Chapter 6 for moreinformation).The Clutha-Upper Waitaki Lines Project (formerly known as the Lower South IslandFacilitating Renewables Project) is an approved project to upgrade the circuitsbetween the Waitaki Valley and Roxburgh (see Chapter 6 for more details). This inturn increases the generation export limit from the region, which removes the existingconstraints that occur at times and enables new generation connections. Thephasing and timing of the upgrades is under periodic review, with the next review inmid-2013. This is to ensure we commit expenditure for the upgrades only wheneconomically justified based on committed new generation (or load reduction).19.11.3 Mahinerangi wind generation stationExpansion of the Mahinerangi wind generation station beyond stage 1 can beaccommodated on the National Grid via the two 110 kV Halfway Bush–Roxburghcircuits.Only relatively minor upgrades within the Otago-Southland region are required toenable the connection of over 200 MW of Mahinerangi generation. Potentialupgrades include increasing the Roxburgh 220/110 kV transformer capacity (anapproved project that is part of the Lower South Island Reliability Project), a thermalupgrade of part of the two 110 kV Roxburgh–Halfway Bush circuits, and increasingthe Halfway Bush 220/110 kV transformer capacity. These upgrades may not berequired, depending on the staged development of the wind generation station, loadgrowth, and the economic level of trade-off between Mahinerangi generation,Waipori, and generation connections to the Roxburgh 110 kV bus.19.11.4 Edendale–Gore wind generation stationsThere are a number of wind generation prospects in the area to the south-east of theline between Edendale and Gore.One option is to connect wind generation to the relatively low capacity 110 kV singlecircuitline that runs between the Invercargill and Halfway Bush substations, whichconnects through the Edendale, Brydone, and Gore substations. This 110 kV linecannot be thermally upgraded. Approximately 100 to 120 MW of wind generation canbe connected at a substation (or less if at a new connection point along the line), butwill need to be constrained for outages of circuits within the region.Another option is to connect the wind generation stations to the 220 kV double-circuitNorth Makarewa–Three Mile Hill line. Approximately 350 MW of generation can beconnected, but parts of the line will need to be thermally upgraded.3422013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Appendix A: Grid Reliability ReportAppendix AGrid reliability reportA.1Ten year forecast of demand at each grid exit point12.76 Transpower to publish grid reliability report12.76(1) Transpower must publish a grid reliability report setting out:12.76(1)(a)a forecast of demand at each grid exit point over the next ten yearsThe table below provides a forecast of demand at each grid exit point. These can also beviewed within the respective regional plans in Chapters 7-19.Table A.1: Ten year forecast of demand at each grid exit pointPrudent peak demand(MW) forecast2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023NORTHLANDAlbany 33 kV 168 172 175 179 182 186 190 193 197 201 205Albany 110 kV (WairauRoad) 158 161 165 168 171 175 178 182 185 189 192Bream Bay 46 46 62 63 64 64 65 66 66 67 68Dargaville 128 131 135 138 141 145 149 152 156 160 163Henderson 158 161 165 168 171 175 178 182 185 189 192Hepburn Road 57 58 59 61 62 63 64 66 67 68 70Kensington 65 65 65 65 65 65 65 65 65 65 65Maungatapere 33 kV 48 49 51 53 55 57 59 61 63 65 67Maungatapere 110 kV 13 14 14 14 14 15 15 15 16 16 16Maungaturoto 18 18 19 19 19 20 20 20 21 21 21Silverdale 84 86 88 91 93 95 98 100 102 105 107Wellsford 35 36 37 38 39 39 40 41 42 43 45Region peak 932 951 984 1004 1025 1046 1067 1089 1111 1133 1155Region demand atisland peak892 910 942 962 981 1002 1023 1044 1065 1087 1108AUCKLANDBombay 33 kV 25 25 26 13 13 14 14 0 0 0 0Bombay 110 kV 56 57 58 73 74 76 77 93 94 96 98Glenbrook 33 kV 116 120 120 120 120 120 120 120 120 120 120Glenbrook NZ Steel 72 72 72 72 72 72 72 72 72 72 72Hobson Street 119 123 128 132 137 142 146 151 156 160 165Mangere 33 kV 117 120 122 125 127 130 132 135 137 140 143Mangere 110 kV 53 53 53 53 53 53 53 53 53 53 53Meremere 15 16 16 0 0 0 0 0 0 0 0Mt Roskill 22 kV 146 149 152 155 158 161 164 168 171 174 177Mt Roskill 110 kV –Kingsland 66 67 68 70 71 72 72 73 74 75 76Otahuhu 65 67 68 69 71 72 74 75 77 78 792013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 343

Appendix A: Grid Reliability ReportPrudent peak demand(MW) forecast2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023Pakuranga 162 165 169 172 176 179 183 186 190 194 197Penrose 22 kV 61 62 64 65 66 68 69 70 72 73 74Penrose 33 kV 320 330 340 350 361 371 383 394 406 417 428Penrose 110 kV -Liverpool Street 119 123 128 132 137 142 146 151 156 160 165Penrose 110 kV - QuayStreet 0 0 0 0 0 0 0 0 0 0 0Takanini 128 130 133 135 138 141 144 147 149 152 155Wiri 92 94 96 97 99 101 103 105 108 110 112Region peak 1536 1574 1609 1632 1669 1707 1746 1786 1826 1866 1906Region demand atisland peak 1478 1515 1549 1572 1608 1645 1683 1722 1761 1800 1840WAIKATOCambridge 43 43 44 45 45 46 47 47 48 49 49Hamilton 11 kV 45 46 24 0 0 0 0 0 0 0 0Hamilton 33 kV 157 160 187 215 219 224 228 233 238 242 247Hamilton NZR 8 8 8 8 8 8 8 8 8 8 8Hangatiki 31 31 32 33 33 34 35 35 36 37 37Hinuera 50 44 45 46 47 48 49 50 52 53 54Huntly 25 26 26 43 43 44 45 46 46 47 48Kopu 50 52 53 54 55 57 58 60 61 63 64Piako 24 25 25 26 27 27 28 29 30 30 31Putaruru 0 8 8 8 8 9 9 9 9 9 10Te Kowhai 40 40 41 41 42 43 43 44 45 45 46Te Awamutu 103 105 110 112 114 116 119 121 123 125 128Waihou 36 37 38 39 40 41 42 43 44 45 46Waikino 45 46 47 49 50 51 52 54 55 56 58Whakamaru 11 11 11 11 12 12 12 12 13 13 13Region peak 506 515 527 549 558 566 575 585 594 602 611Region demand atisland peak 465 473 485 506 514 523 531 540 548 557 565BAY OF PLENTYEdgecumbe 68 69 71 73 75 77 79 81 83 85 87Kaitimako 22 22 23 23 29 29 30 31 31 32 33Kawerau Horizon 21 22 22 23 24 24 25 25 26 27 27Kawerau T6-T9 90 90 90 90 90 90 90 90 90 90 90Kawerau T11/ T14 85 85 85 85 85 85 85 85 85 85 85Kinleith 11 kV 84 84 84 84 84 84 84 84 84 84 84Kinleith 33 kV 25 25 26 26 27 27 28 28 29 29 30Lichfield 10 10 10 10 10 10 10 10 10 11 11Mt Maunganui 33 kV 67 69 50 51 53 54 56 58 59 61 63Owhata 16 17 17 17 17 18 18 18 18 19 19Papamoa 0 0 21 22 23 23 24 25 25 26 273442013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Appendix A: Grid Reliability ReportPrudent peak demand(MW) forecast2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023Rotorua 11 kV 37 38 38 38 39 39 39 39 40 40 40Rotorua 33 kV 49 50 50 51 51 51 52 52 53 53 54Tauranga 11 kV 12 12 13 13 13 13 13 14 14 14 14Tauranga 33 kV 32 32 33 34 30 30 31 32 33 34 34Tarukenga 11 kV 79 81 83 85 87 89 92 94 96 98 101Te Kaha 2 2 2 2 2 2 2 2 2 2 3Te Matai 34 35 35 36 37 38 38 39 40 41 42Waiotahi 12 12 12 13 13 13 13 14 14 14 15Region peak 548 555 561 569 576 584 591 599 607 615 623Region demand atisland peak 501 508 514 521 527 534 542 549 556 564 571CENTRAL NORTH ISLANDBunnythorpe 33 kV 119 122 124 127 129 132 134 137 140 143 145Bunnythorpe NZR 8 8 8 8 8 8 8 8 8 8 8Dannevirke 15 16 16 16 16 16 17 17 17 17 18Linton 72 74 75 77 78 80 82 83 85 87 88Mangamaire 12 12 13 13 13 13 13 14 14 14 14Mangahao 44 44 45 46 46 47 48 48 49 50 51Marton 17 17 18 18 18 18 18 18 19 19 19Mataroa 8 8 8 9 9 9 9 9 9 9 9National Park 8 8 8 9 9 9 9 9 9 9 9Ohaaki 6 6 6 6 6 6 6 6 6 7 7Ohakune 11 9 10 10 10 10 11 11 11 11 12Ongarue 11 11 11 11 11 11 11 11 12 12 12Tokaanu 10 10 11 11 11 11 11 11 11 12 12Tangiwai 11 kV 44 47 47 48 48 49 49 50 50 51 51Tangiwai NZR 10 10 10 10 10 10 10 10 10 10 10Woodville 4 4 4 4 4 5 5 5 5 5 5Waipawa 22 23 23 23 24 24 24 25 25 26 26Wairakei 50 51 51 52 53 54 54 55 56 57 58Region peak 333 337 341 345 349 353 357 361 365 369 373Region demand atisland peak 306 310 313 317 321 325 329 333 337 340 344TARANAKIBrunswick 41 42 42 43 44 45 46 47 48 49 50Carrington Street 65 67 68 69 71 72 74 75 77 78 79Huirangi 17 18 18 18 19 19 20 20 20 21 21Hawera 32 32 32 33 33 34 34 35 35 36 37Hawera (Kupe) 12 12 12 12 12 12 12 12 12 12 12Motunui 11 11 11 11 11 11 11 11 11 11 11Moturoa 23 23 24 24 25 25 26 26 27 27 28Opunake 12 12 13 13 13 13 13 14 14 14 14Stratford 33 kV 30 31 31 32 32 32 33 33 34 34 352013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 345

Appendix A: Grid Reliability ReportPrudent peak demand(MW) forecast2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023Stratford 220 kV 11 11 12 12 12 12 12 12 13 13 13Taumarunui 11 11 11 11 11 11 11 11 11 11 11Wanganui 49 50 51 52 53 54 55 56 57 58 60Waverley 4 4 4 4 5 5 5 5 5 5 5Region peak 213 215 218 220 223 225 228 231 233 236 238Region demand atisland peak 201 203 205 208 210 213 215 218 220 223 225HAWKE’S BAYFernhill 56 57 58 58 59 60 61 62 63 64 65Gisborne 50 52 53 54 55 57 58 60 61 63 64Redclyffe 78 79 80 81 83 84 85 86 87 89 90Tuai 1 1 1 1 1 1 1 1 1 1 1Wairoa 10 10 11 11 11 11 12 12 12 12 12Whirinaki 84 84 84 84 84 84 84 84 84 84 84Whakatu 99 100 101 103 105 106 108 109 111 113 114Region peak 320 323 326 329 332 335 338 341 344 347 350Region demand atisland peak 253 255 258 260 262 265 267 270 272 275 277WELLINGTONCentral Park 11 kV 25 25 26 26 27 27 28 28 29 29 30Central Park 33 kV 180 183 187 191 194 198 202 206 210 214 218Gracefield 65 67 68 69 71 72 74 75 77 78 79Greytown 12 13 13 13 13 14 14 14 14 15 15Haywards 11 kV 24 24 24 25 25 26 26 27 28 28 29Haywards 33 kV 20 21 21 22 22 23 23 23 24 24 25Kaiwharawhara 46 47 48 49 50 51 52 53 54 55 56Masterton 53 55 56 57 59 60 62 63 65 66 68Melling 11 kV 31 31 32 33 33 34 35 35 36 37 37Melling 33 kV 53 54 55 56 57 59 60 61 62 63 65Pauatahanui 25 25 26 26 27 27 28 28 29 30 30Paraparaumu 70 71 72 73 74 75 76 77 78 79 80Takapu Road 102 104 106 108 110 113 115 117 120 122 124Upper Hutt 35 35 36 37 38 38 39 40 41 41 42Wilton 63 65 66 67 69 70 71 73 74 76 77Region peak 756 768 780 792 804 817 830 842 855 868 880Region demand atisland peak 711 723 735 747 759 771 784 796 809 822 834NELSON-MARLBOROUGHBlenheim 79 81 82 84 86 88 90 92 94 96 97Motueka 20 20 21 21 21 21 22 22 22 22 23Motupipi 8 9 9 9 9 9 10 10 10 10 10Stoke 138 141 143 146 149 151 154 157 160 162 1653462013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Appendix A: Grid Reliability ReportPrudent peak demand(MW) forecast2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023Region peak 238 242 246 250 254 257 261 265 269 272 276Region demand atisland peak 212 215 218 222 225 229 232 235 239 242 245WEST COASTArthur’s Pass 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4Atarau 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0Castle Hill 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8Dobson 16.3 16.6 16.9 17.2 17.5 17.8 18.1 18.4 18.7 19.0 19.4Greymouth 15.3 15.6 15.9 16.2 16.6 16.9 17.2 17.6 17.9 18.3 18.6Hokitika 18.3 21.2 21.4 21.7 22.0 22.2 22.5 22.8 23.1 23.4 23.6Kikiwa 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0Kumara 1.9 1.9 1.9 1.9 1.9 1.9 1.9 1.9 1.9 1.9 1.9Murchison 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0Orowaiti 12.2 15.5 18.7 19.0 19.2 19.5 19.8 20.1 20.3 20.6 20.9Otira 0.7 0.7 0.7 0.7 0.7 0.7 1.5 1.5 1.5 1.5 1.5Reefton 11.2 11.4 11.7 11.9 12.1 12.4 12.6 12.9 13.1 13.4 13.6Westport 10.1 10.3 10.5 10.6 10.8 10.9 11.1 11.3 11.4 11.6 11.8Region peak 60 65 68 70 71 72 74 75 76 78 79Region demand atisland peak 47 48 51 52 53 54 55 57 58 59 60CANTERBURYAddington 11 kV -1 71 74 76 79 80 81 82 83 84 85 87Addington 11 kV -2 100 104 107 110 114 117 121 125 128 130 131Addington 66 kV 28 29 30 30 23 0 0 0 0 0 0Ashburton 33 kV 146 149 153 157 166 185 189 194 198 203 207Ashburton 66 kV 13 15 21 21 22 22 23 23 24 25 25Ashley 41 42 43 44 45 45 46 46 47 47 48Bromley 11 kV 115 119 122 125 129 132 136 139 143 144 145Bromley 66 kV 1 1 1 1 1 1 1 1 1 1 1Coleridge 19 20 20 21 22 23 24 25 26 27 28Culverden 33 kV 30 25 25 25 26 18 18 19 19 19 20Culverden 66 kV 28 28 18 18 18 27 27 27 28 28 28Hororata 33 kV 80 81 82 83 84 85 86 87 88 89 90Hororata 66 kV 89 90 91 92 93 95 96 97 98 99 100Islington 33 kV 121 122 124 126 128 130 132 134 136 138 140Islington 66 kV 28 28 29 29 30 30 31 32 32 33 34Islington 66 kV -Papanui 0 12 12 13 17 17 17 17 17 19 19Kaiapoi 32 33 33 34 34 35 35 36 37 37 38Middleton 45 46 44 46 47 48 49 51 52 53 55Southbrook 51 37 38 39 39 35 36 36 37 38 38Springston 33 kV 23 42 64 64 68 79 79 79 80 80 80Springston 66 kV 9 7 7 7 8 8 8 8 8 8 82013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 347

Appendix A: Grid Reliability ReportPrudent peak demand(MW) forecast2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023Waipara 33 kV 12 13 13 13 14 14 14 15 15 15 16Waipara 66 kV 71 74 76 79 80 81 82 83 84 85 87Region peak 783 806 830 850 870 884 903 921 940 956 971Region demand atisland peak 754 775 799 819 838 852 870 888 906 922 937SOUTH CANTERBURYAlbury 4 4 4 4 5 5 5 5 5 5 5Bells Pond 8 8 8 9 9 17 17 18 18 18 10Black Point 13 21 21 24 25 27 27 28 28 28 29Oamaru 42 44 46 47 55 57 59 61 62 64 65St Andrews 0 0 0 0 35 45 45 45 45 45 45Studholme 5 5 6 6 6 6 7 7 7 7 8Tekapo A 61 64 66 67 69 76 78 80 81 83 85Temuka 67 68 68 69 69 71 71 72 72 72 73Timaru 6 6 10 10 10 10 11 11 11 11 11Twizel 7 7 7 7 7 7 8 8 8 8 8Waitaki 4 4 4 4 5 5 5 5 5 5 5Region peak 192 204 216 223 243 266 270 273 277 280 277Region demand atisland peak 139 141 142 145 166 178 181 184 186 189 186OTAGO-SOUTHLANDBalclutha 31 31 32 33 33 34 35 35 36 37 37Brydone 11 11 11 11 11 11 11 11 11 11 11Cromwell 34 35 36 37 38 39 40 41 42 43 44Clyde 10 10 11 11 11 11 12 12 12 12 12Edendale 31 36 37 38 40 41 42 43 44 45 46Frankton 59 61 63 64 66 67 69 71 72 74 76Gore 34 34 35 56 56 57 58 59 59 60 61Halfway Bush -1 115 117 103 105 106 108 109 110 112 113 115Halfway Bush -2 108 110 111 112 114 115 116 118 119 121 122Invercargill 106 108 110 112 115 117 119 121 124 126 128Naseby 32 32 33 34 34 35 36 36 37 38 38North Makarewa 60 61 63 64 65 66 68 69 71 72 73Palmerston 10 10 11 11 11 11 12 12 12 12 12South Dunedin 78 79 95 96 97 98 99 100 101 102 103Tiwai 640 640 640 645 650 655 660 665 670 675 680Region peak 1142 1148 1153 1181 1187 1193 1199 1206 1212 1218 1223Region demand atisland peak 1114 1121 1126 1154 1161 1167 1174 1180 1187 1193 11993482013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Appendix A: Grid Reliability ReportA.2Ten year forecast of supply at each grid injection point12.76 Transpower to publish grid reliability report12.76(1) Transpower must publish a grid reliability report setting out:12.76(1)(b)a forecast of supply at each grid injection point over the next ten yearsThe table below provides a forecast of supply at each grid injection point. These can also beviewed within the respective regional plans in Chapters 7-19.Table A.2: Ten year forecast of generation capacity at each grid injection pointGrid injection point(location if embedded)2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023NORTHLANDAlbany (Rosedale 1 ) 3 3 3 3 3 3 3 3 3 3 3Bream Bay (MarsdenDiesel)9 9 9 9 9 9 9 9 9 9 9Kaikohe (Ngawha) 27 27 27 27 27 27 27 27 27 27 27Maungatapere(Wairua)5 5 5 5 5 5 5 5 5 5 5Silverdale (Redvale) 10 10 10 10 10 10 10 10 10 10 10AUCKLANDGlenbrook 112 112 112 112 112 112 112 112 112 112 112Mangere (WatercareMangere)7 7 7 7 7 7 7 7 7 7 7Otahuhu B CCGT 380 380 380 380 380 380 380 380 380 380 380Otahuhu (GreenmountLandfill)Penrose (AucklandHospital)5 5 5 5 5 5 5 5 5 5 54 4 4 4 4 4 4 4 4 4 4Southdown CCGT 175 175 175 175 175 175 175 175 175 175 175Takanini (Whitford Landfill) 3 3 3 3 3 3 3 3 3 3 3WAIKATOArapuni 197 197 197 197 197 197 197 197 197 197 197Atiamuri 84 84 84 84 84 84 84 84 84 84 84Huntly 1198 1198 1198 1198 1198 1198 1198 1198 1198 1198 1198Karapiro 90 90 90 90 90 90 90 90 90 90 90Maraetai 360 360 360 360 360 360 360 360 360 360 360Mokai 112 112 112 112 112 112 112 112 112 112 112Ohakuri 112 112 112 112 112 112 112 112 112 112 112Te Awamutu (AnchorProducts)4 4 4 4 4 4 4 4 4 4 4Te Kowhai (Te Rapa) 44 44 44 44 44 44 44 44 44 44 44Te Kowhai (Te Uku) 64 64 64 64 64 64 64 64 64 64 64Waikino (Tirohia Landfill) 1 1 1 1 1 1 1 1 1 1 1Waipapa 51 51 51 51 51 51 51 51 51 51 512013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 349

Appendix A: Grid Reliability ReportGrid injection point(location if embedded)2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023Whakamaru 100 100 100 100 100 100 100 100 100 100 100BAY OF PLENTYAniwhenua 25 25 25 25 25 25 25 25 25 25 25Edgecumbe (Bay Milk) 10 10 10 10 10 10 10 10 10 10 10Kawerau (BOPE) 6 6 6 6 6 6 6 6 6 6 6Kawerau (TPP) 37 37 37 37 37 37 37 37 37 37 37Kawerau - KAG 105 105 105 105 105 105 105 105 105 105 105Kawerau (KA24) 9 9 9 9 9 9 9 9 9 9 9Kawerau (Norske Skog) 25 25 25 25 25 25 25 25 25 25 25Kinleith 28 28 28 28 28 28 28 28 28 28 28Matahina 80 80 80 80 80 80 80 80 80 80 80Mount Maunganui (BallanceAgri)7 7 7 7 7 7 7 7 7 7 7Rotorua (Fletcher Forests) 3 3 3 3 3 3 3 3 3 3 3Rotorua (Wheao, Flaxy,Kaingaroa)24 24 24 24 24 24 24 24 24 24 24Tauranga (Kaimai) 42 42 42 42 42 42 42 42 42 42 42CENTRAL NORTH ISLANDAratiatia 78 78 78 78 78 78 78 78 78 78 78Bunnythorpe (Tararua WindStage 2)Linton (Tararua Wind Stage1)36 36 36 36 36 36 36 36 36 36 3632 32 32 32 32 32 32 32 32 32 32Linton (Totara Road) 1 1 1 1 1 1 1 1 1 1 1Mangahao 42 42 42 42 42 42 42 42 42 42 42Nga Awa Purua 140 140 140 140 140 140 140 140 140 140 140Nga Awa Purua -Ngatamariki82 82 82 82 82 82 82 82 82 82 82Ohaaki 46 46 46 46 46 46 46 46 46 46 46Ongarue (Mokauiti, Kuratauand Wairere Falls)13 13 13 13 13 13 13 13 13 13 13Poihipi 51 51 51 51 51 51 51 51 51 51 51Rangipo 120 120 120 120 120 120 120 120 120 120 120Tararua Wind Central(Tararua Stage 3)Tararua Wind Central (TeRere Hau)93 93 93 93 93 93 93 93 93 93 9349 49 49 49 49 49 49 49 49 49 49Te Mihi 166 166 166 166 166 166 166 166 166 166 166Tokaanu 240 240 240 240 240 240 240 240 240 240 240Wairakei 161 161 109 109 109 109 109 109 109 109 109Wairakei (Hinemaiaia) 7 7 7 7 7 7 7 7 7 7 7Wairakei (Rotokawa) 35 35 35 35 35 35 35 35 35 35 35Wairakei (Te Huka) 23 23 23 23 23 23 23 23 23 23 23Woodville - Te Apiti 90 90 90 90 90 90 90 90 90 90 903502013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Appendix A: Grid Reliability ReportGrid injection point(location if embedded)2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023TARANAKICarrington St (Mangorei) 5 5 5 5 5 5 5 5 5 5 5Hawera - Kiwi Dairy(Whareroa)70 70 70 70 70 70 70 70 70 70 70Hawera – Patea 31 31 31 31 31 31 31 31 31 31 31Hawera (Patearoa) 2 2 2 2 2 2 2 2 2 2 2Huirangi (Mangahewa) 9 9 9 9 9 9 9 9 9 9 9Huirangi (Motukawa) 5 5 5 5 5 5 5 5 5 5 5Kapuni 25 25 25 25 25 25 25 25 25 25 25McKee 100 100 100 100 100 100 100 100 100 100 100Taranaki Combined Cycle 385 385 385 385 385 385 385 385 385 385 385Stratford Peaker 200 200 200 200 200 200 200 200 200 200 200Stratford (Stratford AustralPacific)1 1 1 1 1 1 1 1 1 1 1HAWKES BAYGisborne 4 4 4 4 4 4 4 4 4 4 4Gisborne (Matawai) 2 2 2 2 2 2 2 2 2 2 2Kaitawa 36 36 36 36 36 36 36 36 36 36 36Piripaua 42 42 42 42 42 42 42 42 42 42 42Redclyffe (Ravensdown) 8 8 8 8 8 8 8 8 8 8 8Tuai 60 60 60 60 60 60 60 60 60 60 60Wairoa (Waihi) 5 5 5 5 5 5 5 5 5 5 5Whirinaki 155 155 155 155 155 155 155 155 155 155 155Whirinaki (Pan Pac) 13 13 13 13 13 13 13 13 13 13 13WELLINGTONCentral Park (SouthernLandfill)Central Park (WellingtonHospital)1 1 1 1 1 1 1 1 1 1 110 10 10 10 10 10 10 10 10 10 10Greytown (Hau Nui) 9 9 9 9 9 9 9 9 9 9 9Masterton (Kourarau Aand B)1 1 1 1 1 1 1 1 1 1 1Haywards (Silverstream) 3 3 3 3 3 3 3 3 3 3 3West Wind 143 143 143 143 143 143 143 143 143 143 143NELSON-MARLBOROUGHArgyle - Branch RiverScheme11 11 11 11 11 11 11 11 11 11 11Cobb 32 32 32 32 32 32 32 32 32 32 32Blenheim (Lulworth Wind) 1 1 1 1 1 1 1 1 1 1 1Blenheim(Marlborough Lines Diesel)9 9 9 9 9 9 9 9 9 9 9Blenheim (Waihopai) 3 3 3 3 3 3 3 3 3 3 3Motupipi (Onekaka) 1 1 1 1 1 1 1 1 1 1 12013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 351

Appendix A: Grid Reliability ReportGrid injection point(location if embedded)2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023WEST COASTDobson (Arnold) 3 3 3 3 3 3 3 3 3 3 3Hokitika (Amethyst) 6 6 6 6 6 6 6 6 6 6 6Hokitika (McKays Creek) 1 1 1 1 1 1 1 1 1 1 1Hokitika (Wahapo-OkaritoForks)Kumara (Kumara andDillmans)4 4 4 4 4 4 4 4 4 4 410 10 10 10 10 10 10 10 10 10 10Kumara (Hokitika Diesel) 3 3 3 3 3 3 3 3 3 3 3CANTERBURYAshburton (Highbank) 25 25 25 25 25 25 25 25 25 25 25Ashburton (Montalto) 2 2 2 2 2 2 2 2 2 2 2Bromley (City Waste) 3 3 3 3 3 3 3 3 3 3 3Bromley (QE2 diesel) 4 4 4 4 4 4 4 4 4 4 4Coleridge 45 45 45 45 45 45 45 45 45 45 45SOUTH CANTERBURYAlbury (Opuha) 8 8 8 8 8 8 8 8 8 8 8Aviemore 220 220 220 220 220 220 220 220 220 220 220Benmore 540 540 540 540 540 540 540 540 540 540 540Ohau A 264 264 264 264 264 264 264 264 264 264 264Ohau B 212 212 212 212 212 212 212 212 212 212 212Ohau C 212 212 212 212 212 212 212 212 212 212 212Tekapo A 25 25 25 25 25 25 25 25 25 25 25Tekapo B 160 160 160 160 160 160 160 160 160 160 160Waitaki 105 105 105 105 105 105 105 105 105 105 105OTAGO-SOUTHLANDClyde 432 432 432 432 432 432 432 432 432 432 432Manapouri 840 840 840 840 840 840 840 840 840 840 840Roxburgh 320 320 320 320 320 320 320 320 320 320 320Balclutha (Mt. Stuart) 8 8 8 8 8 8 8 8 8 8 8Berwick/Halfway Bush(Waipori and Mahinerangi)8436843684368436Clyde (Fraser) 3 3 3 3 3 3 3 3 3 3 3Clyde (Horseshoe Bendhydro and wind)424242Clyde (Talla Burn) 3 3 3 3 3 3 3 3 3 3 3Clyde (Teviot and Kowhai) 11211211242112Cromwell (Roaring Meg) 4 4 4 4 4 4 4 4 4 4 4Frankton (Wye Creek) 1 1 1 1 1 1 1 1 1 1 1843642112843642112843642112843642112843642112843642112843642112Halfway Bush (DeepStream)5 5 5 5 5 5 5 5 5 5 5Naseby (Falls Dam) 1 1 1 1 1 1 1 1 1 1 13522013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Appendix A: Grid Reliability ReportGrid injection point(location if embedded)2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023Naseby (Paerau) 10 10 10 10 10 10 10 10 10 10 10North Makarewa (Monowai) 7 7 7 7 7 7 7 7 7 7 7North Makarewa (WhiteHills Wind Farm)58 58 58 58 58 58 58 58 58 58 582013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 353

Appendix A: Grid Reliability ReportA.3Issues impacting on N-1 supply12.76 Transpower to publish grid reliability report12.76(1) Transpower must publish a grid reliability report setting out:12.76(1)(c) whether the power system is reasonably expected to meet the N-1criterion, including in particular whether the power system would be ina secure state at each grid exit point, at all times over the next tenyears.12.76(1)(d)proposals for addressing any matters identified in accordance with rule12.76(1)(c).The issues impacting n-1 are listed in the table below together with the projects resolvingthose issues. Details on both issues and projects are available from Chapters 6-19 of thisdocument.3542013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Appendix A: Grid Reliability ReportTable A.3: Backbone issues and resolving projectsIssue affecting n-1 Projects Indicative timing(June year)Project references(MCP) Major CapexProposal to CC(Forecast June years)InvestmenttypeUpper North Islandvoltage stabilityUpper North Island reactive support – Stage 2Pakuranga–Whakamaru series compensationUpper North Island reactive support – Post-NIGUP2013/14-2016/172019/202022/23UPNI-REA_SUP-DEV-02UPNI-REA_SUP-DEV-03UPNI-REA_SUP-DEV-04Approved2016/17To be advisedMCPMCPMCPTaranakitransmissioncapacityRe-tune generator excitation systems and/or install power systemstabilisers.To be advised TRNK-GEN_PSS-DEV-01 NA Base CapexUpper South Islandvoltage stabilityStage 1 – a sixth bus coupler at Islington.Stage 2 – Install additional shunt reactive support around Islington andBromley, or bus the existing circuits between Waitaki Valley and Islingtonwhere they converge near Orari.See Chapter 6 for more information.2015/162018/19ISL-BUS_SEC-EHMT-01WTKV-REA_PWRS-DEV-01GRD-BUSG_TRAN-DEV-01NAQ2 2013/14Base CapexMCPUpper South IslandtransmissioncapacityTransmissioncapacity south ofRoxburghOptions include:A new transmission line to Ashburton or Islington, oran HVDC tap-off from the existing line north of Christchurch.See Chapter 6 for more information.The projects include:Install special protection schemes on the 220 kV and 110 kV network.Replace interconnecting transformers at Invercargill.A new 220/110 kV interconnection at Gore.Install capacitor banks at Balclutha.Install a series capacitor on one of the North Makarewa–Three Mile Hillcircuits (The series capacitor is deferred due to reduced load forecast.The need date will be reviewed in 2015.)See Chapter 6 for more information.To be advised UPSI-TRAN-DEV-01 To be advised MCP2013/14-2015/16 LWSI-TRAN-EHMT-01 Approved MCP2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 355

Appendix A: Grid Reliability ReportA.4: Regional issues and resolving projectsRegion Issue affecting n-1 Option(s) to address the issue Indicativetiming(June year)Project references(MCP) MajorCapex Proposalto CC (ForecastJune years)Investment typeNorthlandHenderson interconnectingtransformer capacity(Issue arises from 2023)New grid exit point at Wairau Road.Replace limiting switchgear on the Henderson–T1 ifrequired.2013/142023/24WRD-SUBEST-DEV-01HEN-POW_TFR-EHMT-01NANACustomer-specificBase CapexHenderson–Wellsfordtransmission capacity(Issue arises from 2024)Marsden interconnectingtransformer capacity(Issue arises from 2023)Automatically split the 110 kV network betweenHenderson and Maungatapere or thermally upgradethe Henderson–Wellsford circuits.Install a 3 rd 220/110 kV transformer, and convert the220 kV and 110 kV buses to three zones.2024/25 HEN_MPE-TRAN-EHMT-01 NA Base Capex2023/24 MDN-POW_TFR-DEV-01 NA Base CapexNorth Auckland and theNorthland regiontransmission capacityNorth Auckland and Northland project (NAaN). Q4 2013/14 ALB_PAK-TRAN-DEV-01 Approved MCPNorth of Hendersontransmission capacity(Issue already exists)North of Huapaitransmission security(Issue already exists)North Auckland and Northland project (NAaN)provides a 2 nd 220 kV connection into Albany fromthe south.Splitting Huapai 220 kV bus once the NAaN projectis completed.NA NA NA NA2016/17 HPI-BUSC-DEV-01 NA Base CapexNorth of Marsden lowvoltage(Issue arises from 2013)Additional voltage support at Kaitaia orMaungatapere.2017/18-2018/19MDN-REA_PWRS-DEV-01 NA Base Capex and/orcustomer-specificUpper North Island voltageinstability for grid backbonecontingenciesUpper North Island reactive support – Stage 2Upper North Island reactive support – Post-NIGUP2013/14-2016/172022/23UPNI-REA_SUP-DEV-02UPNI-REA_SUP-DEV-03ApprovedTo be advisedMCPMCPAlbany supply transformercapacity(Issue arises from 2023)Resolve protection and circuit breaker limits. 2023/24 ALB-POW_TFR_EHMT-01 NA Base CapexHenderson supplytransformer capacityIn the short term, issue can be managedoperationally.In the long term, issue is resolved by installing aTo be advised HEN-POW_TFR-EHMT-02 NA Customer-specific3562013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Appendix A: Grid Reliability ReportRegion Issue affecting n-1 Option(s) to address the issue Indicativetiming(June year)Project references(MCP) MajorCapex Proposalto CC (ForecastJune years)Investment type(Issue arises from 2014)third supply transformer.Kaikohe–Maungatapere110 kV transmissioncapacity(Issue arises from 2013)Kensington supplytransformer capacity(Issue already exists)In the short term, issue can be managedoperationally.In the long term, issue is resolved by thermallyupgrade 110 kV Kaikohe–Maungatapere circuits.In the short term, issue can be managedoperationally.In the long term, issue is resolved by replacing thesupply transformers with higher rated units andupgrade the 33 kV switchboard.To be advised KOE_MPE-TRAN-EHMT-01 NA Customer-specificTo be advised KEN-SUB-EHMT-01 NA Customer-specificMaungaturoto supplytransformer capacity(Issue arises from 2018)Silverdale supplytransformer capacity(Issue arises from 2024)Resolve the protection and metering limits. 2018/19 MTO-POW_TFR-EHMT-01 NA Base CapexResolve the metering limits. 2024/25 SVL-POW_TFR-EHMT-01 NA Base CapexWellsford supply transformercapacity(Issue already exists)Transpower is currently investigating resolving theprotection limit.To be advised WEL-POW_TFR-EHMT-01 NA Base CapexAucklandAuckland region voltagequalityUpper North Island reactive support – Stage 2Upper North Island reactive support – Post-NIGUP2013/14-2016/172022/23UPNI-REA_SUP-DEV-02UPNI-REA_SUP-DEV-03ApprovedTo be advisedMCPMCPNorth Auckland andNorthland regionaltransmission securityOtahuhu interconnectingtransformer capacityInstall new 220 kV cables between Pakuranga,Penrose, and Albany.Issue can be managed operationally for the forecastperiod.Q4 2013/14 ALB_PAK-TRAN-DEV-01 Approved MCPNA NA NA NAHobson Street supplysecurity(Issue arises from 2014)New substation at Hobson Street. 2014/15 HOB-SUBEST-DEV-01 NA Customer-specificMangere supply transformer Limit the peak load to the transformer capacity 2013/14 MNG-POW_TFR_PTN-01 NA Base Capex2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 357

Appendix A: Grid Reliability ReportRegion Issue affecting n-1 Option(s) to address the issue Indicativetiming(June year)Project references(MCP) MajorCapex Proposalto CC (ForecastJune years)Investment typecapacity(Issue already exists)and/or increase the transformer protection limitswhich will resolve the issue until 2020.Mount Roskill supplytransformer capacity(Issue arises from 2013)Otahuhu supply transformercapacity(Issue arises from 2013)Otahuhu–Wiri 110 kVtransmission capacity(Issue arises already exists)Penrose 220 kVtransmission security(Issue already exists)Issue can be managed operationally for the forecastperiod.Limit the peak load to the transformer capacity, oradd a third supply transformer, or replace withexisting transformers with higher rated units.Transpower is investigating several options such as:A new cable from Otahuhu connecting to a new110/33 kV transformer at Wiri.A new 110/33 kV transformer at Otahuhu and anew 33 kV cable to WiriReconductor Otahuhu–Wiri circuit, orA new 220/110 kV connection at Bombay andsupply Wiri from here and a 110 kV bus at Wiri.Issue will be managed operationally until thecommissioning of a new 220 kV cable connectingPakuranga and Penrose.NA NA NA NATo be advised OTA-POW_TFR-EHMT-01 NA Customer-specificTo be advised OTA_WIR-TRAN-DEV-01 NA Base CapexQ4 2013/14 PAK_PEN-TRAN-DEV-01 Approved MCPOtahuhu–Penrose 110 kVtransmission capacity(Issue arises from 2021)In the short term, resolve the constraint on theterminal spans at Otahuhu and Penrosesubstations.In the long term, issue is resolved by replacingOtahuhu–T2 & T4 with higher impedancetransformers, or upgrade the Otahuhu–Penrosecircuit capacity.2021/22To be advisedOTA_PEN-TRAN-EHMT-01OTA_PEN-TRAN-DEV-01NANABase CapexBase CapexPenrose 33 kV supplytransformer capacity(Issue already exists)Issue can be managed operationally for the forecastperiod.NA NA NA NATakanini supply transformercapacity(Issue already exists)Upgrading the protection, circuit breaker and busbarin conjunction with the 33 kV conversion providessufficient capacity beyond the forecast period.2013/14-2016/17TAK-POW_TFR-EHMT-01 NA Base Capex3582013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Appendix A: Grid Reliability ReportRegion Issue affecting n-1 Option(s) to address the issue Indicativetiming(June year)Project references(MCP) MajorCapex Proposalto CC (ForecastJune years)Investment typeWiri supply transformercapacity(Issue arises from 2019)Resolving the protection constraints will delay theoverload until 2021.In the long term, issue is resolved, by limiting thepeak load to the transformer capacity or replaceexisting transformers with higher rated units.2018/192020/21WIR-POW_TFR-EHMT-01WIR-POW_TFR-EHMT-02NANABase CapexCustomer-specificWiri Tee transmissioncapacity(Issue already exists)Likely to be resolved by Otahuhu–Wiri 110 kVtransmission capacity solution.NA NA NA NAWaikatoArapuni–Hamilton 110 kVtransmission capacity(Issue already exists)Issue can be managed operationally for the forecastperiod.NA NA NA NAArapuni–Kinleith 110 kVtransmission capacity(Issue already exists)Hamilton interconnectingtransformer capacity(Issue already exists)In the short term opening Arapuni bus split andrestricting Arapuni south bus generation duringsummer rating.Possible medium term options are:Special protection scheme, orKinleith 110 kV bus reconfigurationPossible long term options are:reconductoring Arapuni–Kinleith–1, andthermally upgrading the Arapuni–Putaruru linesection.In the short term, issue can be managedoperationally.In the long term, issue is resolved by installing anew interconnecting transformer.NANA2022/23-2028/29NA2025/26NANAARI_KIN-TRAN-EHMT-01NAHAM-POW_TFR-DEV-01NANANANANANANABase CapexNABase CapexHamilton–Piako–Waihou110 kV transmissioncapacity(Issue arises from 2016)In the short term, issue can be managedoperationally.In the long term, issue is resolved by constructing anew Hamilton–Waihou or upgrading existingHamilton–Piakocircuits.NA2016/17NAHAM_WHU-TRAN-DEV-01NANANACustomer-specificPiako–Waihou–Waikino–Kopu spur low voltageInstall capacitors, either on the grid or within thedistribution network, orreplace supply transformers at Waikino and Waihou2014/15-2017/182015/16-VLYS-REA_PWS-DEV-01 NA Customer-specific2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 359

Appendix A: Grid Reliability ReportRegion Issue affecting n-1 Option(s) to address the issue Indicativetiming(June year)Project references(MCP) MajorCapex Proposalto CC (ForecastJune years)Investment type(Issue already exists) with on-load tap changers. 2022/23 NA Base CapexCambridge supplytransformer capacity(Issue already exists)Upgrade bus section and protection limits. Q2 2013/14 CBG-SUBEST-EHMT-01 NA Base CapexHamilton supply transformercapacity(Issue already exists)In the short term, issue can be managedoperationally.In the long term, issue is resolved by installing athird 220/33 kV supply transformer at Hamilton.NA2015/16NAHAM-POW_TFR-DEV-01NANANACustomer-specificHangatiki supply transformercapacity(Issue already exists)Replace the existing transformers with two 40 MVAunits.2017/18 HTI-POW_TFR-DEV-01 NA Customer-specificHinuera supply transformercapacity(Issue already exists)New grid exit point at Putaruru, andreplace the 30 MVA with a 60 MVA unit.2014/15To be advisedPAU-SUBEST-DEV-01HIN-POW_TFR-REPL-01NANACustomer-specificCustomer-specificHinuera transmissionsecurity(Issue already exists)New grid exit point at Putaruru. 2014/15 PAU-SUBEST-DEV-01 NA Customer-specificKopu supply transformercapacity(Issue already exists)Resolving the protection constraints will solve theissue until 2023.In the long term, issue is resolved by replacing theexisting supply transformers with two higher ratedunits.2013/142023/24KPU-POW_TFR-EHMT-01KPU-POW_TFR-DEV-01NANABase CapexCustomer-specificMaraetai–Whakamarutransmission capacity(Issue already exists)Piako transmission security(Issue already exists)Issue can be managed operationally for the forecastperiodIssue can be managed operationally for the forecastperiod.NA NA NA NANA NA NA NATe Awamutu supplytransformer capacity(Issue arises from 2015)Resolve the protection limits. 2013/14 TMU-POW_TFR-EHMT-01 NA Base Capex3602013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Appendix A: Grid Reliability ReportRegion Issue affecting n-1 Option(s) to address the issue Indicativetiming(June year)Project references(MCP) MajorCapex Proposalto CC (ForecastJune years)Investment typeTe Awamutu transmissionsecurity(Issue already exists)A new 110 kV transmission circuit from Hangatiki toTe Awamutu.2015/16 HTI_TMU-TRAN-DEV-01 NA Customer-specificTe Kowhai substationdevelopment(Issue already exists)Increasing the rating of the two existing supplytransformers, and installing a third supplytransformer at Te Kowhai.Q2 2013/142018/19TWH-POW_TFR-EHMT-01TWH-POW_TFR-DEV-01NANACustomer-specificCustomer-specificWaihou supply transformercapacity(Issue already exists)Replace the supply transformers with higher ratedunits.2015-2017 WHU-POW_TFR-REPL-01 NA Base CapexWaikino supply transformercapacity(Issue arises from 2012)In the short term, issue can be managedoperationally.In the long term, issue is resolved by increasing thesupply transformers’ capacity.NA2020/21-2022/23NAWKO-POW_TFR- REPL-01NANANABase CapexBay of PlentyKaitimako interconnectingtransformer capacity(Issue arises from 2026)Tauranga and MountMaunganui transmissionsecurity(Issue arises from 2015 andfrom 2020)A new interconnecting transformer at Kaitimako. 2026/27 KMO-POW_TFR-DEV-01 NA Base CapexNew grid exit point at Papamoa. To be advised PPM-SUBEST-DEV-01 NA Customer-specificEdgecumbe supplytransformer capacity(Issue already exists)Upgrade protection limit, andreplace transformers with higher rated units.2016/17To be advisedEDG-POW_TFR-EHMT-01EDG-POW_TFR-EHMT-02NANABase CapexCustomer-specificKaitimako supply security(Issue already exists)Issue can be managed operationally for the forecastperiod.NA NA NA NAKawerau–T1 and T2 supplytransformer capacity(Issue arises from 2019)Replace transformers with higher rated units. 2019/20 KAW-POW_TFR-REPL-01 NA Base CapexKawerau–Matahina 10 kVtransmission security andIssue can be managed operationally for the forecastperiod.NA NA NA NA2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 361

Appendix A: Grid Reliability ReportRegion Issue affecting n-1 Option(s) to address the issue Indicativetiming(June year)Project references(MCP) MajorCapex Proposalto CC (ForecastJune years)Investment typecapacity(Issue already exists)Kinleith–Tarukenga 110 kVtransmission capacity(Issue already exists)Kinleith 110/33 kV supplytransformer capacity(Issue arises from 2012)Mount Maunganui supplytransformer capacity(Issue arises from 2019)Issue can be managed operationally for the forecastperiod.Replace the 20 MVA supply transformer with a 40MVA unit.Issue can be managed operationally for the forecastperiod.NA NA NA NA2016/17 KIN-POW_TFR-EHMT-01 NA Customer-specificNA NA NA NAOwhata supply transformercapacity(Issue already exists)In the short term, issue can be managedoperationally.In the long term, issue is resolved by increasing theexisting transformers capacity. Three options arecurrently under review.NA2016/17-2018/19NAOWH-POW_TFR-EHMT-01NANANACustomer-specificRotorua supply transformercapacity(Issue arises from 2012)In the short term, issue can be managedoperationally.In the long term, issue is resolved by increasing the110/11 kV supply transformer capacity.NA2013/14-2014/15NAROT-POW_TFR-EHMT-01NANANABase CapexRotorua–Tarukenga 110 kVtransmission capacity andsecurity(Issue already exists)In the short term, issue can be managedoperationally.In the long term, issue is resolved by thermallyupgrading the Rotorua–Tarukenga circuits.NATo be advisedNAROT_TRK-TRAN-EHMT-01NANANACustomer-specificTarukenga supply security(Issue already exists)In the short term, issue can be managedoperationally.In the long term, issue is resolved by installing anew supply transformer at Tarukenga.NATo be advisedNATRK-POW_TFR-DEV-01NANANACustomer-specificTauranga 11 kV supplytransformer capacity(Issue arises from 2012)In the short term, issue can be managedoperationally.In the long term, issue is resolved by solving thetransformers’ low voltage cable limit and protectionlimit.NATo be advisedNATGA-POW_TFR-EHMT-01NANANACustomer-specific3622013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Appendix A: Grid Reliability ReportRegion Issue affecting n-1 Option(s) to address the issue Indicativetiming(June year)Project references(MCP) MajorCapex Proposalto CC (ForecastJune years)Investment typeTe Matai supply transformercapacity(Issue arises in 2015)Waiotahi supply transformercapacity(Issue arises from 2012)Waiotahi and Te Kahasupply security(Issue already exists)Issue can be managed operationally for the forecastperiod.Replace the existing transformers with two higherrated units.Issue can be managed operationally for the forecastperiod.NA NA NA NATo be advised WAI-POW_TFR-EHMT-01 NA Customer-specificNA NA NA NACentral NorthIslandBunnythorpe interconnectingtransformer capacity(Issue already exists)In the short term, issue can be managedoperationally.In the long term, issue is resolved by replacing theexisting transformers with higher rated units.NA2014/15-2016/17NABPE-POW_TFR-EHMT-01NANANABase CapexBunnythorpe–Mataroa110 kV transmissioncapacity(Issue already exists)In the short term, issue can be resolvedoperationally.In the long term, issue is resolved by installing eitherseries reactors or reconductor Bunnythorpe–Mataroa 110kV circuit.NATo be advisedNABPE_MTR-TRAN-EHMT-01NANANABase CapexBunnythorpe–Woodville110 kV transmissioncapacity(Issue already exists)Bunnythorpe supplytransformer capacity(Issue arises from 2012)Linton supply transformercapacity(Issue arises from 2015)In the short-term, issue can be managedoperationally.Longer-term options include:upgrade the existing SPS to operate for a 220 kVcircuit outagereconductor the Bunnythorpe–Woodville circuitswith higher rated conductors, orconvert the Bunnythorpe–Woodville circuits to 220kV operation.Issue can be managed operationally for the forecastperiod.Issue can be managed operationally for the forecastperiod.NATo be advised2015/16-2020/21NANABPE_WDV-TRAN-EHMT-01NA NA NA NANA NA NA NANANANANANABase Capex2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 363

Appendix A: Grid Reliability ReportRegion Issue affecting n-1 Option(s) to address the issue Indicativetiming(June year)Project references(MCP) MajorCapex Proposalto CC (ForecastJune years)Investment typeMangahao supplytransformer capacity(Issue arises from 2012)Marton low voltage(Issue already exists)Issue can be managed operationally for the forecastperiod.Issue can be managed operationally for the forecastperiod.NA NA NA NANA NA NA NAMarton supply transformercapacity(Issue arises from 2023)Resolve metering limits. 2023/24 MTN-POW_TFR-EHMT-01 NA Base CapexMataroa and National Parklow voltage(Issue already exists)Mataroa supply transformersecurity(Issue already exists)National Park transmissionand supply transformersecurity(Issue already exists)Issue can be managed operationally for the forecastperiod.Issue can be managed operationally for the forecastperiod.Issue can be managed operationally for the forecastperiod.NA NA NA NANA NA NA NANA NA NA NAOhakune supply securityand capacity(Issue arises from 2011)In the short term, issue can be managedoperationally.In the long term, issue is resolved by installing ahigher rated supply transformer.NA2016/17NAOKN-POW_TFR-DEV-01NANANACustomer-specificOngarue supply transformersecurity(Issue already exists)Tokaanu supply transformersecurity(Issue already exists)Waipawa low voltageIssue can be managed operationally for the forecastperiod.Issue can be managed operationally for the forecastperiod.Issue can be managed operationally for the forecastperiod.NA NA NA NANA NA NA NANA NA NA NA3642013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Appendix A: Grid Reliability ReportRegion Issue affecting n-1 Option(s) to address the issue Indicativetiming(June year)Project references(MCP) MajorCapex Proposalto CC (ForecastJune years)Investment typeWaipawa supply transformercapacity and security(Security issue alreadyexists, and capacity issuearises from 2017)Resolve the metering and protection limits on the110/33 kV transformers.The lack of n-1 security for 11 kV load can bemanaged operationally.2017/18NAWPW-POW_TFR-EHMT-01NANANABase CapexNAWoodville supply transformercapacity(Issue arises from 2024)Resolve the metering limit on the 110/11 kVtransformers.2023/24 WDV-POW_TFR-EHMT-01 NA Base CapexTaranakiNorth Taranaki transmissioncapacity and low voltageissues(Issue already exists)Stratford–Hawera–Waverley–Wanganui 110 kVtransmission capacity(Issue already exists)Options include:A second transformer at (or near) New Plymouth.Convert 220 kV New Plymouth–Stratford circuitsto 110 kV operation.Constraining on generation.Upgrade terminating spans capacity on theCarrington Street–Stratford circuitsReplace Huirangi supply transformers withtransformers with on load tap changers.2017/18-2022/23TRNK-TRAN-EHMT-01 NA Base CapexHawera bus refurbishment. 2014/15 HWA-BUSG-EHMT-01 NA Base CapexBrunswick supply security(Issue already exists)Resolve metering parameters’ limit, andadd a second transformer.2014/152017/18-2019/20BRK-POW_TFR-EHMT-01BRK-POW_TFR-DEV-01NANABase CapexCustomer-specificCarrington Street supplytransformer capacity(Issue arises from 2012)Upgrade protection equipment, and upgrade branchcomponent.2014/152014/15CST-POW_TFR-EHMT-01CST-POW_TFR-EHMT-02NANABase CapexCustomer-specificHawera voltage quality(Issue already exists)Install reactive support at Hawera. 2015/16-2020/21HWA-C_BANKS-DEV-01 NA Base CapexHawera (Kupe) supplysecurity(Issue already exists)Issue can be managed operationally for the forecastperiod.NA NA NA NA2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 365

Appendix A: Grid Reliability ReportRegion Issue affecting n-1 Option(s) to address the issue Indicativetiming(June year)Project references(MCP) MajorCapex Proposalto CC (ForecastJune years)Investment typeHawera supply transformercapacity(Issue arises from 2018)Issue can be managed operationally for the forecastperiod.NA NA NA NAHuirangi supply transformercapacity(Issue arises from 2020)In the short term, issue can be managedoperationally.In the long term, issue can be resolved by replacingthe existing supply transformers with two 50 MVAunits.NA2019/20-2021/22NAHUI-POW_TFR-EHMT-01NANANACustomer-specificOpunake supply transformercapacity(Issue arises from 2014)Resolve the metering and protection limits. 2014/15 OPK-POW_TFR-EHMT-01 NA Base CapexStratford supply transformercapacity(Issue already exists)Replace the supply transformers with two 40 MVAunits.2014/15 SFD-POW_TFR-REPL-01 NA Base CapexWanganui supplytransformer capacity(Issue already exists)In the short term, issue can be managedoperationally.In the long term, issue is resolved by replacing theexisting transformers with two 40 MVA units.NA2016/17-2017/18NAWGN-POW_TFR-REPL-01NANANABase CapexWaverly supply security(Issue already exists)Issue can be managed operationally for the forecastperiod.NA NA NA NAHawke’s BayHawke’s Bay voltage quality(Issue already exists)Issue can be managed operationally for the forecastperiod.NA NA NA NAFernhill–Redclyffe 110 kVtransmission capacity(Issue already exists)Issue can be managed operationally for the forecastperiod.NA NA NA NARedclyffe–Tuai 110 kVtransmission capacity(Issue already exists)Issue can be managed operationally for the forecastperiod.NA NA NA NARedclyffe interconnectingtransformer capacity(Issue already exists)Issue can be managed operationally for the forecastperiod.NA NA NA NA3662013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Appendix A: Grid Reliability ReportRegion Issue affecting n-1 Option(s) to address the issue Indicativetiming(June year)Project references(MCP) MajorCapex Proposalto CC (ForecastJune years)Investment typeFernhill supply transformercapacity(Issue already exists)Replace the 30 MVA with an 80 MVA unit. 2018/19-2020/21FHL-POW_TFR-EHMT-01 NA Customer-specificGisborne 110 kV voltagequalityIn the short term, issue can be managedoperationally for the forecast period.NA NA NA NAGisborne supply capacity(Issue arises from 2017)Install capacitor to resolve the overloading issue,then thermally upgrade, or reconductor part or all ofboth Gisborne–Tuai circuits, and recalibrateGisborne supply transformers’ metering parameters.To be advised2017/182018/19GIS-C_BANKS-DEV-01GIS_TUI-TRAN-EHMT-01GIS-POW_TFR-EHMT-01NANANACustomer-specificCustomer-specificBase CapexRedclyffe supply transformercapacity(Issue already exists)Replace supply transformers with two 120 MVAunits.Q3 2013/14 RDF-POW_TFR-EHMT-01 NA Customer-specificTuai supply security(Issue already exists)Issue can be managed operationally for the forecastperiod.NA NA NA NAWairoa supply transformercapacity(Issue arises from 2017)Issue can be managed operationally for the forecastperiod.NA NA NA NAWhakatu supply transformercapacity(Issue arises from 2016)Issue can be managed operationally for the forecastperiod.NA NA NA NAWellingtonWellington interconnectingtransformer capacity(Issue arises from 2015)Install a second 250 MVA interconnectingtransformer.2018/19 WIL-POW_TFR-DEV-03 NA Base CapexCentral Park supplytransformer capacity(110/33 kV transformercapacity issue arises from2013)(33/11 kV transformercapacity issue arises from2016)110/33 kV: replace the existing110/33 kVtransformers with 120 MVA units.33/11 kV: issue can be managed operationally forthe forecast period.2014/15NACPK-POW_TFR-DEV-01NANANACustomer-specificNA2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 367

Appendix A: Grid Reliability ReportRegion Issue affecting n-1 Option(s) to address the issue Indicativetiming(June year)Project references(MCP) MajorCapex Proposalto CC (ForecastJune years)Investment typeGracefield supplytransformer capacity(Issue arises from 2028)Resolve LV cable limit. 2028/29 GFD-POW_TFR-EHMT-01 NA Customer-specificHaywards supplytransformer capacity andsecurity(Issue already exists)Kaiwharawhara transmissionand supply security, andsupply transformer capacity(Issue already exists)Masterton supplytransformer capacity(Issue already exists)Replace existing transformers with two110/33/11 kV 60 MVA supply transformers.Issue can be managed operationally for the forecastperiod.Issue can be managed operationally for the forecastperiod.2016/17 HAY-POW_TFR-DEV-01 NA Customer-specificNA NA NA NANA NA NA NAMelling supply capacity(Hayward–Melling circuitcapacity issue arises from2020)(110/33 kV and 110/11 kVtransformer capacity issuesalready exists)Hayward–Melling: use the short term rating for thecircuit; thermally upgrade the circuits, orreconductor the line.110/33 kV: recalibrate the metering will defer theissue until 2021.110/11 kV: resolve HV protection limit will defer theissue until 2014. Transpower will discuss futuresupply options with Wellington Electricity.2020/212013/14HAY_MLG-TRAN-EHMT-01MLG-POW_TFR-EHMT-01NANACustomer-specificBase CapexParaparaumu transmissionsecurity and supplytransformer capacity(Issue already exists)In the short term, issue can be managedoperationally and closing 110 kV bus.In the long term, issue is resolved by supplyingParaparaumu from 220 kV line or additional supplytransformer supplied from Mangahao.2013/142015/16PRM-BUSC-EHMT-01PRM-SUBEST-DEV-01 orPRM-POW_TFR-DEV-01NANANACustomer-specificBase Capex and/orcustomer-specificPauatahanui transmissionsecurity and supplytransformer capacity(Issue already exists)In the short term, issue can be managedoperationally.In the long term, issue is resolved by upgrading thesupply transformer capacity, and supplyParaparaumu load from 220 kV line or reconductorNA2020/21NAPNI-POW_TFR-EHMT-01NANANACustomer-specific3682013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Appendix A: Grid Reliability ReportRegion Issue affecting n-1 Option(s) to address the issue Indicativetiming(June year)Project references(MCP) MajorCapex Proposalto CC (ForecastJune years)Investment typePauatahanui–Takapu Road circuit section. 2020/21 PNI_TKR-TRAN-EHMT-01 NA Base CapexTakapu Road supplytransformer capacity(Issue already exists)Upper Hutt supplytransformer capacity(Issue already exists)Increase the supply transformer capacity. To be advised TKR-POW_TFR-DEV-01 NA Customer-specificResolve protection and metering limits. 2016/17 UHT-POW_TFR-EHMT-01 NA Base CapexNelson-MarlboroughStoke 220/10 kVinterconnecting transformercapacity(Issue arises from 2023)Resolve the station equipment constraints, andoperationally manage via generation reschedulingand load management.2023/24-2028/29STK-POW_TFR-DEV-01 NA Base CapexStoke 110/66 kVinterconnecting transformercapacity(Issue already exists)Install a second interconnecting transformer. To be advised STK-POW_TFR-EHMT-02 NA Customer-specificKikiwa–Stoke 110 kVtransmission capacity(Issue arises from 2020)In the short term, issue can be managedoperationally.In the long term, issue is resolved by thermallyupgrade the Kikiwa–Stoke 110 kV circuit.NAPost 2020/21NAKIK_STK-TRAN-EHMT-01NANANABase CapexCobb–Motueka 66 kVtransmission capacity(Issue already exists)Issue can be managed operationally for the forecastperiod.NA NA NA NAMotueka supply transformercapacity(Issue already exists)Install capacitors at Motueka, andestablish a new grid exit point near Riwaka.To be advised2016/17MOT-C_BANKS-DEV-01MOT-SUBEST-DEV-01NANACustomer-specificCustomer-specificMotupipi single supplysecurity(Issue already exists)Issue can be managed operationally for the forecastperiod.NA NA NA NAStoke supply transformercapacity(Issue already exists)Replace existing supply transformers with two 120MVA units, followed by constructing a new grid exitpoint at Brightwater.Q4 2013/142020/21STK-POW_TFR-REPL-01STK-SUBEST-DEV-01NANABase CapexCustomer-specific2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 369

Appendix A: Grid Reliability ReportRegion Issue affecting n-1 Option(s) to address the issue Indicativetiming(June year)Project references(MCP) MajorCapex Proposalto CC (ForecastJune years)Investment typeWest CoastInangahua–Murchison–Kikiwa transmission capacity(Issue arises from 2017)Thermally upgrade the Inangahua–Murchison –Kikiwa circuit, or a special protection scheme to tripload post contingency.2022/23 IGH_MCH_KIK-TRAN-EHMT-01 NA Base CapexKikiwa interconnectingtransformer capacity(Issue already exists)In the short term, issue can be managedoperationally.In the long term, issue is resolved by replacingKikiwa–T1 with 150 MVA unitNATo be advisedNAKIK-POW_TFR-EHMT-01NANANABase CapexWest Coast low voltage(Issue arises from 2021)Arthur’s Pass transmissionand supply security(Issue already exists)Castle Hill transmission andsupply security(Issue already exists)Dobson supply transformercapacity(Issue arises in 2024)Hokitika transmissioncapacity(Issue arises in 2020)Kikiwa supply security(Issue already exists)Murchison transmission andsupply security(Issue already exists)Otira supply security(Issue already exists)Install additional capacitors, or a special protectionscheme to trip load post contingency, or replaceKikiwa–T1 with a higher rated unit.Issue can be managed operationally for the forecastperiod.Issue can be managed operationally for the forecastperiod.Upgrade Dobson supply transformer protection todefer the issue beyond the forecast period.Issue can be managed operationally in the shortterm.Longer term option is to implement the Kawakabonding project.Issue can be managed operationally for the forecastperiod.Issue can be managed operationally for the forecastperiod.Issue can be managed operationally for the forecastperiod.2027/28 WCST-C_BANKS-DEV-01 NA Base CapexNA NA NA NANA NA NA NA2024/25 DOB-POW_TFR-EHMT-01 NA Base Capex2020/21 HKK-TRAN-EHMT-01 NA Base CapexNA NA NA NANA NA NA NANA NA NA NA3702013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Appendix A: Grid Reliability ReportRegion Issue affecting n-1 Option(s) to address the issue Indicativetiming(June year)Project references(MCP) MajorCapex Proposalto CC (ForecastJune years)Investment typeCanterburyIslington 220/66 kVtransformer capacity(Issue arises in 2019)Options include:establish a new 220/66 kV grid exit point south ofChristchurch, andinstall a fourth 220/66 kV interconnectingtransformer at Islington.2019/20To be advisedISL-SUBEST-DEV-01ISL-POW_TFR-DEV-01NANACustomer-specificBase CapexAshburton supplytransformer capacity(Issue already exists)The committed option is to install a third 220/66 kVtransformer.In the long term, issue is resolved by transferringload to a new grid exit point.2014/152018/19ASB-POW_TFR-DEV-02ASB-SUBEST-DEV-01NANACustomer-specificCustomer-specificAshley supply transformercapacityReplace the existing 66/11 kV transformers with two40 MVA units.2016/17 ASY-POW_TFR-EHMT-01 NA Customer-specificBromley 220/66 kVtransformer capacity andvoltage quality(Issue arises in 2019)Replace the two transformers with two 150 MVAOLTC transformers.Install 11 kV capacitors at the Bromley transformer’stertiary winding.2019/20To be advisedBRY-POW_TFR-EHMT-02BRY-C_BANKS-DEV-01NANACustomer-specificCustomer-specificColeridge supply transformersecurity(Issue already exists)Issue can be managed operationally for the forecastperiod.NA NA NA NACulverden supplytransformer capacity(Issue arises from 2014)In the short term, issue can be managedoperationally in the short term.In the long term, issue is resolved by increasing theexisting supply transformers capacity and changingthe operating voltage to 220/66 kV transformers,NATo be advisedNACUL-POW_TFR-DEV-01NANANACustomer-specificHororata and Kimberleyvoltage quality andtransmission capacity(Issue arises 2013)Hororata supply transformercapacity and voltage quality(Issue already exists)Southbrook supplytransformer capacityIssue can be managed operationally for the forecastperiod.Issue can be managed operationally for the forecastperiod.Transfer load from 33 kV to 66 kV bus byestablishing two new 66 kV feeders fromNA NA NA NANA NA NA NATo be advised SBK-TRAN-DEV-01 NA Customer-specific2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 371

Appendix A: Grid Reliability ReportRegion Issue affecting n-1 Option(s) to address the issue Indicativetiming(June year)Project references(MCP) MajorCapex Proposalto CC (ForecastJune years)Investment type(Issue arises from 2013)Southbrook.Springston transmissionsecurity(Issue already exists)In the short term, issue can be resolvedoperationally.In the long term, issue is resolved by establishing anew 220/66 kV grid exit point south of Christchurch.NATo be advisedNATo be advisedNANANACustomer-specificWaipara single supplysecurity(Issue already exists)Issue can be managed operationally for the forecastperiod.NA NA NA NASouthCanterburyOamaru–Waitaki voltagequality and transmissionsecurity(Issue already exists)A new grid exit point at Livingstone (several optionsare being investigated as part of the Lower WaitakiValley Reliability project).Install reactive support at Oamaru.To be advised2014/15-2017/18LIV-SUBEST-DEV-01OAM-C_BANKS-DEV-01NANACustomer-specificCustomer-specificTimaru interconnectingtransformer capacity(Issue already exists)Increase interconnecting transformer capacity. 2018/19-2020/21TIM-POW_TFR-EHMT-02 NA Base CapexWaitaki 220/110 kVinterconnecting transformercapacity(Issue already exists)Replace the Waitaki interconnecting transformerswith higher rated units. The need will depend on thepreferred option from the Lower Waitaki ValleyReliability investigation.2014/15-2018/19WTK-POW_TFR-EHMT-01 NA Base CapexAlbury supply security andsupply transformer capacity(Security issue alreadyexists, and capacity issuearises from 2024)Albury and Tekapo Atransmission security(Issue already exists)Bells Pond single supplysecurity(Issue already exists)Issue can be managed operationally for the forecastperiod.Issue can be managed operationally for the forecastperiod.Possible options include building a 110 kV bus atBells Pond, connection to the other 110 kV circuit,and a new grid exit point.NA NA NA NANA NA NA NATo be advised BPD-BUSC-DEV-01 NA Customer-specific3722013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Appendix A: Grid Reliability ReportRegion Issue affecting n-1 Option(s) to address the issue Indicativetiming(June year)Project references(MCP) MajorCapex Proposalto CC (ForecastJune years)Investment typeBlack Point single supplysecurity(Issue already exists)Issue can be managed operationally for the forecastperiod.NA NA NA NAOamaru supply transformercapacity(Issue arises from 2016)A new grid exit point at Livingstone. To be advised LIV-SUBEST-DEV-01 NA Customer-specificStudholme single supplysecurity(Issue already exists)The long term solution will be part of the LowerWaitaki Valley Reliability project.see above see above see above see aboveStudholme supplytransformer capacity(Issue already exists)Replace transformers with higher rated units, andtransfer load to a new grid exit point near StAndrews.2014/15To be advisedSTU-POW_TFR-EHMT-01STU-SUBEST-DEV-01NANACustomer-specificCustomer-specificTekapo A supply securityand supply transformercapacity(Security issue alreadyexists, and capacity issuearises from 2022)Resolve protection and metering limits. 2022/23 TKA-POW_TFR-EHMT-01 NA Base CapexTemuka transmissionsecurity and supplytransformer capacity(Issue already exists)Install a new 120 MVA transformer and upgrade the110 kV Timaru–Temuka circuits, or a newconnection to the 220 kV Islington–Waitaki circuits,west of Temuka.To be advisedTo be advisedTo be advisedTMK-POW_TFR-DEV-02TIM_TMK-TRAN-EHMT-01TIM-SUBEST-DEV-01NANANACustomer-specificCustomer-specificCustomer-specificTimaru supply transformercapacity(Issue arises from 2012)Twizel supply security(Issue arises from 2012)Replace the existing transformers with three47 MVA units.Issue can be managed operationally for the forecastperiod.2014/15 TIM-POW_TFR-EHMT-01 NA Customer-specificNA NA NA NAWaitaki single supplysecurity and supplytransformer capacity(Issue already exists)Install a second supply transformer to resolvesupply security issue or increase supplytransformer’s capacity by adding fans and pumps tosolve supply capacity issue.To be advised2014/15WTK-POW_TFR-DEV-01WTK-POW_TFR-EHMT-01NANACustomer-specificCustomer-specific2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 373

Appendix A: Grid Reliability ReportRegion Issue affecting n-1 Option(s) to address the issue Indicativetiming(June year)Project references(MCP) MajorCapex Proposalto CC (ForecastJune years)Investment typeOtago-SouthlandSouthland transmissioncapacity and low voltageBalclutha supply transformercapacity(Issue arises from 2012)Resolve protection limits to defer the issue until2018.New capacitors (part of the Lower South IslandReliability project) will relief some additionalcapacity.Projects include:2011/12-An SPS to delay large investment and to allow2014/15sufficient build time.Replace Invercargill interconnecting transformerwith higher capacity units.Install shunt capacitors at Balclutha.Install a new 220/110 kV interconnection at Gore,andInstall a series capacitor on one of the NorthMakarewa–Three Mill Hill circuit. 1822013/14-2014/15STLD-TRAN-EHMT-01 Approved MCPBAL-POW_TFR_EHMT-01 NA Base CapexCromwell supply transformercapacity(Issue arises from 2021)Resolve protection limits to the issue until 2024.Upgrade branch limiting components will resolve theissue beyond the forecast period.2021/222025/26CML-POW_TFR-EHMT-01CML-POW_TFR-EHMT-02NANABase CapexCustomer-specificEdendale supply transformercapacity(Issue arises from 2013)In the short term, resolving the protection, and thecable limits will defer the issue until 2014.In the long term, issue is resolved by replacing thesupply transformers with two higher rated units.2013/142013/142014/15EDN-POW_TFR-EHMT-01EDN-POW_TFR-EHMT-02EDN-POW_TFR-EHMT-03NANANABase CapexCustomer-specificCustomer-specificFrankton transmission andsupply security(Issue arises from 2022)Thermally upgrade the Cromwell–Frankton circuits,and increase the protection and metering limits onFrankton–T4 transformer, and increase Frankton–T2A and T2B supply transformers’ capacities byadding pumps.2022/232024/252024/25CML_FKN-TRAN-EHMT-01FKN-POW_TFR-EHMT-01FKN-POW_TFR-EHMT-02NANANACustomer-specificBase CapexCustomer-specificGore supply transformercapacity(Issue arises from 2016)Replace transformers with two higher rated units. To be advised GOR-POW_TFR-EHMT-01 NA Customer-specificHalfway Bush supply Close 33 kV bus. To be advised HWB-BUSG-EHMT-01 NA Customer-specific182 Due to a reduced load forecast, the series capacitor is deferred. The need date is expected to be after 2020, but this will be reviewed in 2015.3742013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Appendix A: Grid Reliability ReportRegion Issue affecting n-1 Option(s) to address the issue Indicativetiming(June year)Project references(MCP) MajorCapex Proposalto CC (ForecastJune years)Investment typetransformer capacity(Issue already exists)Replace two 110/33 kV transformer with one 220/33kV 120 MVA unit, andreplace 220/33 kV transformer with one 120 MVAunit.2016/172026/27HWB-POW_TFR-EHMT-01HWB-POW_TFR-EHMT-02NANABase CapexBase CapexInvercargill supplytransformer capacity(Issue arises from 2013)Recalibrate metering parameters. 2013/14 INV-POW_TFR-EHMT-01 NA Base CapexNaseby supply transformercapacity(Issue arises from 2014)Replace the existing transformers with two higherrated units.2018/19-2020/21NSY-POW_TFR_EHMT-01 NA Customer-specificNorth Makarewa supplytransformer capacity(Issue arises from 2022)Palmerston supply securityand supply transformercapacity(Issue already exists)Palmerston transmissionsecurity(Issue already exists)Replace 220/33 kV transformers with two 220/66 kVunits.Issue can be managed operationally for the forecastperiod.Issue can be managed operationally for the forecastperiod.2018/19 NMA-POW_TFR-EHMT-01 NA Customer-specificNA NA NA NANA NA NA NASouth Dunedin supplytransformer capacity(Issue arises from 2015)Recalibrate metering parameters. 2014/15 SDN-POW_TFR-EHMT-01 NA Base CapexWaipori transmissionsecurity(Issue already exists)Issue can be managed operationally for the forecastperiod.NA NA NA NA2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 375

Appendix A: Grid Reliability ReportA.5: Regional transmission bus issues and resolving projectsRegion Issue affecting n-1 Transmission busoutageNorthlandHenderson–Wellsfordoverloading(Issue arises from 2020)Henderson–HepburnRoad overloading(Issue arises from 2025)Hepburn Road 110 kVMarsden 220 kVOption(s) to address the issueAdditional voltage supports at Kaitaia orMaungatapere, system split, or thermallyupgrade the Henderson–Wellsford circuits.There are a number of networkdevelopments in Auckland region that arelikely to influence the severity and timing ofthis issue. Transpower will monitor thisissue as these developments take place.Indicativetiming(June year)Project referencesInvestmenttype2020/21 HEN_WEL-TRAN-EHMT-01 Base Capex2025/26 HEN_HEP-TRAN-EHMT-01 Base CapexNorth of Marsden lowvoltage(Issue arises from 2013)Maungatapere 110 kVAt Marsden install a 3 rd 220/110 kVtransformer, and convert the 220 kV and110 kV buses to three zones.2017/18-2018/19To be advisedBase CapexAucklandBombay 33 kV loss ofsupply(Issue already exists)Bombay 110 kVIssue can be managed operationally forthe forecast period or reconfigure Bombaybus.NA NA CustomerspecificMeremere loss of supply(Issue already exists)Bombay 110 kVIssue will be managed operationally for theforecast period.NA NA NAMount Roskill 110 kV lossof supply(Issue already exists)Mount Roskill 110 kVInstall bus circuit breakers and reconfigureMount Roskill bus.To be advised To be advised CustomerspecificMount Roskill 22 kV lossof supply(Issue already exists)Mount Roskill 110 kVInstall bus circuit breakers and reconfigureMount Roskill bus.NA NA CustomerspecificSouthdown generationdisconnection(Issue already exists)Southdown 220 kV Install bus circuit breakers at Southdown. NA NA CustomerspecificBombay–Wiri Teeoverloading(Issue already exists)Otahuhu 110 kVMost options to address the Otahuhu–Wiri110 kV transmission capacity or Wirisupply transformer capacity will alsoaddress this issue.Otahuhu–Mangere–Mount Otahuhu 110 kV Reconfigure the Otahuhu 110 kV bus toswap the Mangere–Otahuhu–1 andNA To be advised Base Capex2021/22 OTA-BUSG-EHMT-01 Base Capex3762013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Appendix A: Grid Reliability ReportRegion Issue affecting n-1 Transmission busoutageOption(s) to address the issueIndicativetiming(June year)Project referencesInvestmenttypeRoskill overloading(Issue already exists)Otahuhu–Roskill–2 circuits on the bus.WaikatoHamilton 55 kV loss ofsupply(Issue already exists)Hamilton 220 kV Reconfigure Hamilton bus. NA NA CustomerspecificHangatiki loss of supply(Issue already exists)Hangatiki 220 kV orArapuni North 110 kVHangatiki 110 kV bus outage: install buscircuit breaker at Hangatiki.Arapuni North 110 kV bus outage: issuewill be resolved following the replacementof the Tarukenga interconnectingtransformers (Bay of Plenty region) andreconfiguring the Arapuni bus so the twocircuits from Hangatiki connect to separatebus sections.To be advised To be advised Base CapexHinuera loss of supply(Issue already exists)Kopu loss of supply(Issue already exists)Hinuera 110 kV orKarapiro 110 kVWaihou 110 kV or Waikino110 kVNew GXP at Putaruru NA PAU-SUBEST-DEV-01 CustomerspecificInstall bus circuit breakers at Kopu. NA NA CustomerspecificTe Awamutu loss ofsupply(Issue already exists)Te Awamutu 110 kV orKarapiro 110 kVA second Hangatiki–Te Awamutu circuitand install bus circuit breaker at TeAwamutu.NA NA CustomerspecificWaihou loss of supply(Issue already exists)Waihou 110 kVWaihou 110 kV bus will need to besubstantively rebuilt based on conditionassessment in about five years.Transpower will investigate upgrading thebus security in conjunction with the rebuild.NA NA CustomerspecificWaikino loss of supply(Issue already exists)Waihou 110 kV or Waikino110 kVInstall bus circuit breaker and reconfigureWaikino bus.NA NA CustomerspecificWhakamaru loss of supply(Issue already exists)Whakamaru 220 kVInstall additional supply transformer atWhakamaru.NA NA CustomerspecificAtiamuri generation Atiamuri 220 kV Install bus circuit breakers at Atiamuri. NA NA Customer-2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 377

Appendix A: Grid Reliability ReportRegion Issue affecting n-1 Transmission busoutageOption(s) to address the issueIndicativetiming(June year)Project referencesInvestmenttypedisconnection(Issue already exists)specificKarapiro generationdisconnection(Issue already exists)Karapiro 110 kVIssue can be resolved by installing buscircuit breakers at Karapiro.NA NA CustomerspecificMaraetai generationdisconnection(Issue already exists)Maraetai 220 kVReconductor Maraetai–Whakamaru circuitand install bus circuit breaker.NA NA CustomerspecificMokai generationdisconnection(Issue already exists)Whakamaru 220 kV Install additional transformer at Mokai. NA NA CustomerspecificOhakuri generationdisconnection(Issue already exists)Ohakuri 220 kVInstall additional bus circuit breakers andreconfigure Ohakuri bus.NA NA CustomerspecificWaipapa generationdisconnection(Issue already exists)Maraetai 220 kV A second Maraetai–Waipapa circuit. NA NA CustomerspecificBombay–Hamiltonoverloading(Issue already exists)Bombay 110 kVIssue can be managed operationally forthe forecast period.To be advised To be advised Base CapexBay of PlentyHamilton low voltage(Issue already exists)Edgecumbe loss of supply(Issue already exists)Hamilton 220 kVEdgecumbe 220 kVPossible options include:reactive support in the Waikato 110 kV,anda third 220 kV connection to Hamilton.Install bus circuit breakers and reconfigureEdgecumbe bus.To be advised To be advised Base CapexNA NA CustomerspecificKawerau (Horizon Energy)loss of supply(Issue already exists)Kawerau 110 kV Reconfigure Kawerau bus. NA NA CustomerspecificKinleith (Powerco) loss ofsupplyKinleith 110 kVOptions would be considered inconjunction with addressing the KinleithNA KIN-POW_TFR-EHMT-01 Customerspecific3782013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Appendix A: Grid Reliability ReportRegion Issue affecting n-1 Transmission busoutageOption(s) to address the issueIndicativetiming(June year)Project referencesInvestmenttype(Issue already exists)110/33 kV supply transformer security andcapacity issue.Kinleith (Carter HoltHarvey) loss of supply(Issue already exists)Kinleith 110 kVOptions would be considered inconjunction with addressing the Kinleith110/11 kV supply transformer supplysecurity.NA NA CustomerspecificMount Maunganui(Issue already exists)Mount Maunganui 110 kVInstall bus circuit breakers at MountMaunganui.To be advised To be advised Base CapexOwhata loss of supply(Issue already exists)Owhata 110 kV Install bus circuit breakers at Owhata. NA NA CustomerspecificRotorua 11 kV loss ofsupply(Issue already exists)Rotorua 110 kVIssue can be resolved by reconfiguringRotorua bus in conjunction with supplytransformer replacement.NA NA CustomerspecificRotorua 11 kV and 33 kVloss of supply(Issue already exists)Tarukenga 110 kVIssue can be resolved by reconfiguringRotorua bus in conjunction with supplytransformer replacement.NA NA CustomerspecificTarukenga loss of supply(Issue already exists)Tarukenga 110 kVA second supply transformer at Tarukengawill prevent this loss of supply.To be advised TRK-POW_TFR-DEV-01 CustomerspecificTauranga 11 kV loss ofsupply(Issue already exists)Tauranga 33 kV loss ofsupply(Issue already exists)Tauranga 110 kV Install bus circuit breaker at Tauranga. NA NA CustomerspecificTauranga 110 kV Install bus circuit breaker at Tauranga. NA NA CustomerspecificTe Kaha loss of supply(Issue already exists)Edgecumbe 110 kV orWaiotahi 110 kVInstall bus circuit breaker and reconfigureTe Kaha bus.NA NA CustomerspecificTe Matai loss of supply(Issue already exists)Te Matai 110 kV Install bus circuit breaker at Te Matai. To be advised To be advised Base CapexWaiotahi loss of supply(Issue already exists)Edgecumbe 110 kV orWaiotahi 110 kVInstall bus circuit breaker and reconfigureWaiotahi bus.NA NA Customerspecific2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 379

Appendix A: Grid Reliability ReportRegion Issue affecting n-1 Transmission busoutageOption(s) to address the issueIndicativetiming(June year)Project referencesInvestmenttypeMatahina – G1 generationdisconnection(Issue already exists)Kawerau 110 kVInstall bus circuit breaker and reconfigureMatahina bus.NA NA CustomerspecificMatahina – G2 generationdisconnection(Issue already exists)Edgecumbe 110 kVInstall bus circuit breaker and reconfigureMatahina bus.NA NA CustomerspecificTe Matai–Kaitimakooverloading(Issue already exists)Kaitimako 110kVIn the short term, issue can be managedoperationally.In the long term, issue is resolved byconstructing a new grid exit point atPapamoa.NATo be advisedNAPPM-SUBEST-DEV-01NACustomerspecificOkere–Te Mataioverloading(Issue already exists)Kaitimako 110kVA new interconnecting transformer atKaitimako.2026/27 KMO-POW_TFR-DEV-01 Base CapexCentral NorthIslandDannevirke loss of supply(Issue already exists)Mangamaire loss of supply(Issue already exists)Marton loss of supply(Issue already exists)Woodville 110 kV Install bus circuit breaker at Dannevirke. To be advised To be advised Base CapexMangamaire 110 kV Install bus circuit breaker at Mangamaire. To be advised To be advised Base CapexWanganui 110 kV Install bus zone protection at Wanganui. To be advised To be advised Base CapexMataroa loss of supply(Issue already exists)Mataroa 110 kVIssue can be re resolved by installing:bus circuit breakers, andsupply transformer.To be advisedNATo be advisedNABase CapexCustomerspecificOhakune loss of supply(Issue already exists)Ohakune 110 kVIssue can be re resolved by installing:bus circuit breakers, andsupply transformer.To be advisedNATo be advisedNABase CapexCustomerspecificOngarue loss of supply(Issue already exists)Ongarue 110 kVIssue can be re resolved by installing:bus circuit breakers, andsupply transformer.To be advisedNATo be advisedNABase CapexCustomer-3802013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Appendix A: Grid Reliability ReportRegion Issue affecting n-1 Transmission busoutageOption(s) to address the issueIndicativetiming(June year)Project referencesInvestmenttypespecificTokaanu loss of supply(Issue already exists)Tokaanu 110 kVInstall transformer circuit breaker onTokaanu–T22.NA NA CustomerspecificWaipawa loss of supply(Issue already exists)Woodville loss of supply(Issue already exists)Woodville 110 kV Install bus circuit breakers at Woodville. To be advised To be advised Base CapexWoodville 110 kV Install bus circuit breakers at Woodville. To be advised To be advised Base CapexAratiatia generationdisconnection(Issue already exists)Aratiatia 220 kV orWairakei 220 kVA second Aratiatia–Wairaki circuit. NA NA CustomerspecificNga Awa Puruageneration disconnection(Issue already exists)Nga Awa Purua 220 kVInstall bus circuit breakers at Nga AwaPurua.NA NA CustomerspecificNgatamariki generationdisconnection(Issue already exists)Rangipo generationdisconnection(Issue already exists)Nga Awa Purua 220 kV Install bus circuit breakers Ngatamariki. NA NA CustomerspecificRangipo 220 kV Install bus circuit breakers at Rangipo. NA NA CustomerspecificTe Apiti generationdisconnection(Issue already exists)Woodville 110 kVIssue can be resolved by installing:bus circuit breakers, andsecond 110 kV connection to Te Apiti.To be advisedNATo be advisedNABase CapexCustomerspecificWairakei generationdisconnection(Issue already exists)Wairakei 220 kVInstall bus circuit breakers or reconfigureWairakei bus.NA NA CustomerspecificBunnythorpe–Woodvilleoverloading(Issue already exists)Bunnythorpe 220 kVIssue can be resolved by:upgrading the existing SPS, orreconductoring the110 kV Bunnythorpe–Woodville with higher rated conductors.2015/16-2020/21BPE_WDV-TRAN-EHMT-01Base Capex2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 381

Appendix A: Grid Reliability ReportRegion Issue affecting n-1 Transmission busoutageOption(s) to address the issueIndicativetiming(June year)Project referencesInvestmenttypeCentral North Islandregional low voltage(Issue already exists)Bunnythorpe 220 kVRearranging the bus connections atBunnythorpe and/or installing a fourth220 kV bus coupler will provide n-1 bussecurity.To be advised BPE_BUSC-EHMT-01 Base CapexTaranakiHawera loss of supply(Issue already exists)Hawera 110 kV Upgrade protection at Hawera. To be advised To be advised Base CapexNew Plymouth – Moturoaloss of supply(Issue already exists)New Plymouth 110 kVInstall 110 kV bus circuit breaker at NewPlymouth.To be advised To be advised Base CapexWanganui loss of supply(Issue already exists)Wanganui 110 kV Install bus circuit breakers Wanganui. To be advised To be advised Base CapexWaverley loss of supply(Issue already exists)Waverley 110 kV Issue can be resolved by installing a:bus circuit breakers, andsecond supply transformer.To be advisedNATo be advisedNABase CapexCustomerspecificKapuni generationdisconnection(Issue already exists)Stratford 110 kVUpgrade Kapuni to a ‘double tee’connection.NA NA CustomerspecificPatea generationdisconnection(Issue already exists)Hawera 110 kV Issue can be resolved by a:protection upgrade at Hawera, andsecond feeder to Patea.To be advisedNATo be advisedNABase CapexCustomerspecificHawke’s BayWhareroa generationdisconnection(Issue already exists)Fernhill loss of supply(Issue already exists)Gisborne loss of supply(Issue already exists)Tuai loss of supply(Issue already exists)Hawera 110 kV Issue can be resolved by a:bus reconfiguration, andprotection upgrade at Hawera.To be advised To be advised Base CapexFernhill 110 kV Install bus circuit breaker at Fernhill. To be advised To be advised Base CapexGisborne 110 kV Install bus circuit breaker at Gisborne. NA NA CustomerspecificTuai 110 kV A second supply transformer. NA NA Customerspecific3822013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Appendix A: Grid Reliability ReportRegion Issue affecting n-1 Transmission busoutageOption(s) to address the issueIndicativetiming(June year)Project referencesInvestmenttypeWhirinaki loss of supply(Issue already exists)Whirinaki 220 kV Install bus circuit breaker at Whirinaki. To be advised To be advised Base CapexWhirinaki – G1, G2, G3generation disconnection(Issue already exists)Whirinaki 220 kVIssue can be resolved by installing buscircuit breaker.To be advised To be advised Base CapexRedclyffe 220/110 kVtransformer overloading(Issue already exists)Redclyffe 220 kV orRedclyffe 110 kVIssue can be managed operationally forthe forecast period.To be advised To be advised Base CapexWellingtonCentral Park loss of supply(Issue already exists)Wilton 110 kVConstruct a third Wilton 110 kV bus sectionand additional bus circuit breaker at Wilton.2015/16-2016/17WIL-BUSC-EHMT-01Base CapexHaywards loss of supply(Issue already exists)Haywards 110 kVReplace the transformers with two110/33/11 kV banks will provide bussecurity.2016/17 HAY-POW_TFR-DEV-01 CustomerspecificKaiwharawhara loss ofsupply(Issue already exists)Wilton 110 kVInstall fault limiting reactors and transferload to other grid exit points.NA NA CustomerspecificMasterton loss of supply(Issue already exists)Upper Hutt loss of supply(Issue already exists)Masterton 110 kV Install bus circuit breaker at Masterton. NA NA Base CapexUpper Hutt 110 kV Install bus circuit breaker at Upper Hutt. NA NA Base CapexWest Wind generationdisconnection(Issue already exists)Wilton 110 kVInstall a 110 kV bus and bus circuit breakerand West Wind.2015/16-2016/17WIL-BUSC-EHMT-01CustomerspecificTakapu Road–Wiltonoverloading(Issue already exists)Wilton 110 kV A third Wilton 110 kV bus section. 2015/16-2016/17WIL-BUSC-EHMT-01Base CapexLow transmission andsupply voltage(Issue already exists)Wilton 110 kV A third Wilton 110 kV bus section. 2015/16-2016/17WIL-BUSC-EHMT-01Base CapexWairarapa low voltages Upper Hutt 110 kV Install a bus coupler at Upper Hutt, and 2024/25 UHT-BUSC-EHMT-01 To meet2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 383

Appendix A: Grid Reliability ReportRegion Issue affecting n-1 Transmission busoutageOption(s) to address the issueIndicativetiming(June year)Project referencesInvestmenttype(Issue already exists) install capacitor at Masterton 2024/25 MST-C_BANKS-DEV-01 GRSTo meetGRSWellington 220/110 kVtransformer capacity(Issue already exists)Upper Hutt 110 kVInstall a 5th regional 220/110 kV 250 MVAinterconnecting transformer. Possible sitesare Wilton and Haywards.2015/16-2020/21WIL-BUSC-EHMT-01To meetGRS andcustomerspecificNelson-MarlboroughGolden Bay spur loss ofsupply(Issue already exists)Stoke 66 kV orStoke 110 kVInstall a second Stoke 110/66 kVtransformer and bus circuit breaker.NA NA CustomerspecificBlenheim loss of supply(Issue already exists)Blenheim 110 kV or Stoke110 kVIssue can be resolved by busreconfiguration and/or additional bus circuitbreakers.To be advised To be advised Base CapexMotupipi loss of supply(Issue already exists)Upper Takaka 66 kVInstall a second Stoke 110/66 kVtransformer and bus circuit breaker.NA NA CustomerspecificArgyle generationdisconnection(Issue already exists)Argyle 110 kV andBlenheim 110 kVInstall line circuit breakers at Argyle. To be advised To be advised Base CapexCobb generationdisconnection(Issue already exists)Cobb 66 kV Install bus circuit breakers at Cobb. NA NA CustomerspecificWest CoastWest Coast loss of supply(Issue already exists)Kikiwa 110 kV orInangahua 110 kVReplace Kikiwa–T1 interconnectingtransformer and install bus circuit breakerat Kikiwa.To be advised KIK-POW_TFR-EHMT-01 Base CapexArthur's Pass loss ofsupply(Issue already exists)Arthur's Pass 66 kV,Coleridge 66 kV, or Otira66 kV bus outageIssue can be resolved by installing a:line circuit breakers, andsecond supply transformer.To be advisedNATo be advisedNABase CapexCustomerspecificAtarau loss of supply(Issue already exists)Atarau 110 kV Issue can be resolved by installing a:second feeder, andbus circuit breaker.To be advisedNATo be advisedNABase CapexCustomerspecific3842013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Appendix A: Grid Reliability ReportRegion Issue affecting n-1 Transmission busoutageOption(s) to address the issueIndicativetiming(June year)Project referencesInvestmenttypeCastle Hill loss of supply(Issue already exists)Castle Hill 66 kV,Coleridge 66 kV, orOtira 66 kV bus outageIssue can be resolved by installing a:line circuit breakers, andsecond supply transformer.To be advisedNATo be advisedNABase CapexCustomerspecificDobson loss of supply(Issue already exists)Dobson 66 kV Install a bus circuit breaker at Dobson. To be advised To be advised Base CapexKikiwa loss of supply(Issue already exists)Kikiwa 220 kVInstall fault limiting reactor so that the twoKikiwa transformers can operated inparallel.NA NA CustomerspecificMurchison loss of supply(Issue already exists)Murchison 110 kV Issue can be resolved by installing a:line circuit breakers, andsecond supply transformer.To be advisedNATo be advisedNABase CapexCustomerspecificOtira loss of supply(Issue already exists)Otira 66 kV Issue can be resolved by installing a:line circuit breakers, andsecond supply transformer.To be advisedNATo be advisedNABase CapexCustomerspecificRobertson Street loss ofsupply(Issue already exists)Westport loss of supply(Issue already exists)Inangahua 110 kV Install bus circuit breaker at Inangahua. To be advised To be advised Base CapexInangahua 110 kV Install bus circuit breaker at Inangahua. To be advised To be advised Base CapexCanterburyAshburton loss of supply(Issue already exists)Ashburton 220 kV220/66 kV load: Transpower hascommitted to installing a third transformeron a third bus section.220/33 kV load: issue can be managedoperationally for the forecast period.2014/15NAASB-POW_TFR-DEV-02NACustomerspecificCustomerspecificAshley loss of supply(Issue already exists)Coleridge loss of supply(Issue already exists)Ashley 66 kV Install bus circuit breaker Ashley. To be advised To be advised Base CapexColeridge 66 kV Issue can be resolved by installing a:line circuit breakers, and To be advised To be advised Base Capex2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 385

Appendix A: Grid Reliability ReportRegion Issue affecting n-1 Transmission busoutageOption(s) to address the issueIndicativetiming(June year)Project referencesInvestmenttypesecond supply transformer. NA NA CustomerspecificHororata loss of supply(Issue already exists)Kaiapoi loss of supply(Issue already exists)Hororata 66 kV Issue can be resolved by installing a:Kaiapoi 66 kV orSouthbrook 66 kVline circuit breakers, andreactive support.Issue can be resolved by installing a:bus circuit breaker at Southbrook, andbus circuit breaker at Kaiapoi.To be advised To be advised Base CapexTo be advisedNATo be advisedNABase CapexCustomerspecificSouthbrook loss of supply(Issue already exists)Southbrook 66 kVIssue can be resolved by installing a buscircuit breaker.To be advised To be advised Base CapexWaipara loss of supply(Issue already exists)Waipara 66 kV Issue can be resolved by installing a:bus circuit breakers, andsecond supply transformer and secondfeeder.To be advisedNATo be advisedNABase CapexCustomerspecificColeridge generationdisconnection(Issue already exists)Coleridge 66 kV Issue can be resolved by installing a:line circuit breakers, andsecond supply transformer.To be advisedNATo be advisedNABase CapexCustomerspecificAshburton low voltages(Issue already exists)Ashburton 220 kVProjects to address Upper South Islandvoltage stability will provide the neededadditional reactive support.2018/19 WTKV-REA_PWRS-DEV-01orGRD-BUSG_TRAN-DEV-01Base CapexBromley low voltages(Issue already exists)Bromley 220 kV Reactive support at Bromley. NA BRY-C_BANKS-DEV-01 CustomerspecificIslington area low voltages(Issue already exists)Islington 220 kVProjects to address Upper South Islandvoltage stability will provide the neededadditional reactive support.2018/19 WTKV-REA_PWRS-DEV-01orGRD-BUSG_TRAN-DEV-01Base CapexSouthCanterburyAlbury loss of supply(Issue already exists)Albury 110 kV orTimaru 110 kVInstall line circuit breakers, a secondAlbury–Timaru circuit, and a secondtransformer.NA NA CustomerspecificStudholme loss of supply(Issue already exists)Studholme 110 kV orTimaru 110 kVInstall a bus circuit breaker and reconfigureStudholme bus.To be advised To be advised Base Capex3862013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Appendix A: Grid Reliability ReportRegion Issue affecting n-1 Transmission busoutageOption(s) to address the issueIndicativetiming(June year)Project referencesInvestmenttypeTekapo A loss of supply(Issue already exists)Albury 110 kV orTimaru 110 kVA second circuit to Timaru, via Albury, andsecond supply transformer.NA NA CustomerspecificTemuka loss of supply(Issue already exists)Timaru 110 kVConvert Timaru 110 kV bus to three zonesand additional bus circuit breaker.2013/14-2014/15TIM-BUSC-DEV-01Base CapexTimaru loss of supply(Issue already exists)Timaru 110 kVConvert Timaru 110 kV bus to three zonesand upgrade Timaru supply transformer.2013/14-2014/15TIM-BUSC-DEV-01Base CapexOpuha generationdisconnection(Issue already exists)Albury 110 kV orTimaru 110 kVInstall line circuit breakers, a secondAlbury–Timaru circuit, and a second supplytransformer.NA NA CustomerspecificTekapo A generationdisconnection(Issue already exists)Albury 110 kV orTimaru 110 kVA second circuit to Timaru, via Albury, andsecond transformer.NA NA CustomerspecificOtago-SouthlandBalclutha loss of supply(Issue already exists)Brydone loss of supply(Issue already exists)Edendale loss of supply(Issue already exists)Gore loss of supply(Issue already exists)Balclutha 10 kV Install bus circuit breaker at Balclutha. NA NA CustomerspecificBrydone 110 kV Install bus circuit breaker at Brydone. NA NA CustomerspecificEdendale 110 kV Install bus circuit breaker at Edendale. To be advised To be advised Base CapexGore 110 kV Install bus circuit breaker at Gore. To be advised To be advised Base CapexHalfway Bush 33 kV lossof supply(Issue already exists)Halfway Bush 110 kV orHalfway Bush 220 kVReplace the two 110/33 kV transformerswith one 220/33 kV transformer and closethe 33 kV bus split.2016/17-2025/26HWB-POW_TFR-EHMT-01HWB-BUSG-EHMT-01Base CapexCustomerspecificPalmerston loss of supply(Issue already exists)Halfway Bush 110 kVA second transformer and bus circuitbreaker at Halfway BushNA NA Customerspecific2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 387

Appendix B: Grid Economic Investment ReportAppendix BGrid Economic Investment Report12.115(1) Transpower must publish a grid economic investment report onwhether there are investments that it considers, other than theinvestments identified under clause 12.114 (Investments to meet thegrid reliability standards), could be made in respect of theinterconnection assets.Issues impacting economic operation of the New Zealand electricity system are listed in the table below, together with the projects resolving those issues.Details on both issues and projects are available from Chapters 6-19 of this document.Table B.1: Backbone economic investmentsIssue Projects Indicative timing(June year)Project referencesForecastsubmission date(June years)Wairakei Ring circuittransmission capacityCentral North Islandtransmission capacityKawerau 110 kVgeneration constraintA new 220 kV double circuit transmission line between Wairakei and Whakamaru.Reconductor Wairakei–Ohakuri–Atiamuri circuits, followed by Atiamuri–Whakamaruif required, or a staged development involving:Stage 1: a new 220 kV Wairakei–Atiamuri circuit (bypassing Ohakuri).Stage 2: a second Atiamuri–Whakamaru circuit.Tranche 1, range of options includes:limit power flow on the 110 kV regional networkreconductor Tokaanu–Whakamaru circuits, andthermal upgrade or reconductor Bunnythorpe–Tangiwai–Rangipo circuits.Tranche 2, range of options includes:reconductor Bunnythorpe–Tokaanu circuitsprovide new transmission capacity between Bunnythorpe and Whakamarua new line in the Taranaki area, from Taumarunui to Whakamaru, andLower North Island wide System Protection Scheme.2013/14To be advisedWKM_WRK-TRAN-DEV-01WKM_WRK-TRAN-DEV-02ApprovedTo be advisedTo be advised CNI-TRAN-EHMT-01 To be advisedReplace Kawerau–T12 with a 250 MVA 10% impedance transformer. 2014/15 KAW-POW_TFR-DEV-01 Approved3882013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved.

Appendix B: Grid Economic Investment ReportIssue Projects Indicative timing(June year)Project referencesForecastsubmission date(June years)Taranaki transmissioncapacityTransmission capacitybetween Bunnythorpe andHaywardsRange of options includes:thermal upgrade and/or reconductor the Brunswick–Stratford circuitsreconductor the Huntly–Stratford circuits, anda new line between Taumarunui and Whakamaru.To be advised TRNK-TRAN-EHMT-01 To be advisedReplace the conductor on the 220 kV Bunnythorpe–Haywards–1 and 2 circuits. 2018/19 BPE_HAY-TRAN-EHMT-01 SubmittedInsufficient transmissioncapacity through theWaitaki Valley, andbetween Roxburgh andthe Waitaki ValleyThe project includes:thermally upgrading the 220 kV Cromwell–Twizel–1 & 2 circuitsreconductoring the following 220 kV circuits with duplex conductor:Aviemore–Waitaki–Livingstone circuits.Aviemore–Benmore–1 and 2 circuits.Clyde–Roxburgh–1 and 2 circuits, andLivingstone–Naseby and Naseby–Roxburgh circuitsUpgrade the capacity of the 220 kV Benmore–Twizel–1 circuit.To be advised2014/15To be advised2013/14To be advisedTo be advisedLWSI-TRAN-DEV-01BEN_TWZ-TRAN-EHMT-01ApprovedTo be advisedTransmission capacitybetween North and SouthIslandsHVDC projects includes:Pole 3 - Stage 1 and Stage 2Increase the HVDC line ratingHVDC link expansion Stage 32012/13-2013/14To be advised2020/21HVDC-TRAN-DEV-01HVDC-TRAN-DEV-02HVDC-TRAN-DEV-03ApprovedTo be advised2017/18Table B.2: Regional economic investmentsRegion Issue Project Indicative Timing(June years)Project ReferenceForecastSubmission date(June years)TaranakiStratford–Hawera–Waverley–Wanganui110 kV transmission capacityReplace conductor on the 110 kV circuitsbetween Stratford and Wanganui2014/15 SFD_WGN-TRAN-EHMT-01 Approved2013 Annual Planning Report © Transpower New Zealand Limited 2013. All rights reserved. 389

Appendix C: Fault LevelsAppendix CFault LevelsThe Connection Code contained in Schedule 8 to the Benchmark Agreement requiresTranspower:4.2(g)to publish annually a 10 year forecast of the expected minimum andmaximum fault level at each customer point of service.Calculated fault levels are very dependent on the assumptions used in the calculationand the method of calculation. The calculation of minimum fault levels depends onwhat generation is assumed to be dispatched and what grid assets are out of service.Minimum fault levels have limited meaning unless the assumptions made in thecalculation of the minimum fault level are understood. Minimum fault levels can beused for ensuring the coordination of protection relays between asset owners.Protection coordination has very important consequences for power system securityand safety of people and assets. Accordingly, we are not going to publish minimumfault levels which may be misunderstood and used in a way that threatens securityand safety. We encourage connected parties to talk with us in matters concerningprotection coordination.Table C.2 lists the maximum three-phase fault current for all points of service. TableC.3 lists the maximum single-phase to ground fault current for the 220 kV and 110 kVpoints of service. In both tables, the listed value is the initial RMS symmetrical shortcircuit current ( ) as defined by IEC 60909 2001.The 10 year forecast of maximum fault levels is based on information currently knownby Transpower. The values in the tables should be regarded as being indicative only.We have modelled committed future transmission upgrades and generation projectsusing the best information we have at this time. We know that towards the end of the10 year period, there may be additional transmission upgrades and additionalgeneration required to meet the power and energy requirements of New Zealand.We do not know exactly the nature or location of these future transmission upgradesand new generation. The maximum fault level at a point of service may also changewhere the number of supply transformers are increased or replaced as part of aService Change to meet load growth or provide supply security.Therefore, the maximum short-circuit currents listed should not be relied upon forspecifying short-circuit requirements for new substation equipment. The forecast faultlevels provide an early warning of when plant capability may be exceeded.Accordingly, while Transpower endeavours to forecast fault levels accurately, thelevels may change for a number of reasons and Transpower does not accept liabilityfor other parties reliance on the fault values contained in the forecast. Transpowerencourages asset owners to consult with us for detailed information on maximumfault levels at specific sites relating to new equipment connection.The Connection Code (5.1(h)) puts an obligation on Transpower and the customer toensure its equipment does not cause the maximum short circuit power and currentlimits in Appendix B Table B2 of the Connection Code to be exceeded on or nearby tothe grid. Table C.1 shows the short circuit power and limits in Table B2 of AppendixB of the Connection Code. Note that the fault levels at some buses are already nearor exceed these values.3902013 Annual Planning Report © Transpower New Zealand Limited 2013.All rights reserved.

Appendix C: Fault LevelsTable C.1: Maximum short-circuit power and current limitsNominal voltage(kV)Maximum short-circuit power and current limits(MVA)(kA)220 12,000 31.5110 6,000 31.566 1,800 1650 1,350 1633 1,400 2522 950 2511 475 25We calculated maximum fault levels in Tables C.2 and C.3 using the 2001 IEC 60909method. The values are the initial RMS symmetrical short circuit levels.The fault levels have been calculated using the following basis:All generating units are assumed to be in service.A full representation of the existing transmission grid, directly connectedgeneration and embedded generation above 1 MW known to us. The existingwind farms are assumed to provide only full load current into a fault.Motor loads are not modelled.The breaker time is 0.1 seconds and the fault clearing time is 1 second.The fault impedance is zero ohms.Future committed changes to the power system including transmission upgradesand new generation detailed in this APR. We represented new transmission linesin the model with electrical parameters estimated from the best matches withexisting lines of the same conductor type. We have represented committedgeneration in our power system model with their electrical parameters scaledfrom the latest example which their type is known to us. We based the timing ofthese connections on open discussion with the asset owner, and from thegenerator’s website. The actual commissioning date may vary.Table C.2: Ten year forecast of three-phase maximum fault levels,of service(kA) of each pointGrid exit pointNORTHLANDPoint ofservice2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023Albany ALB0331 20.0 20.5 20.5 20.5 20.5 20.5 20.5 20.5 20.5 20.5 20.5Albany ALB1101 13.9 14.1 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2Bream Bay BRB0331 10.5 10.5 10.5 10.5 10.5 10.5 10.5 10.5 10.5 10.5 10.5Dargaville DAR0111 4.8 4.8 4.8 4.8 4.8 4.8 4.8 4.8 4.8 4.8 4.8Henderson HEN0331 19.5 19.2 19.3 19.3 19.3 19.3 19.3 19.3 19.3 19.3 19.3Hepburn Road HEP0331 22.6 21.8 21.8 21.8 21.8 21.8 21.8 21.8 21.8 21.8 21.8Kensington KEN0331 9.3 9.3 9.3 9.3 9.3 9.3 9.3 9.3 9.3 9.3 9.3Kaikohe KOE1101 3.5 3.4 3.5 3.5 3.5 3.5 3.5 3.5 3.5 3.5 3.5Marsden MDN0142 7.8 7.8 7.8 7.8 7.8 7.8 7.8 7.8 7.8 7.8 7.8Marsden MDN1101 7.8 7.8 7.8 7.8 7.8 7.8 7.8 7.8 7.8 7.8 7.8Maungatapere MPE0331 7.8 7.8 7.8 7.8 7.8 7.8 7.8 7.8 7.8 7.8 7.8Maungaturoto MTO0331 4.5 4.5 4.5 4.5 4.5 4.5 4.5 4.5 4.5 4.5 4.5Silverdale SVL0331 17.7 18.1 18.1 18.1 18.1 18.1 18.1 18.1 18.1 18.1 18.1Wellsford WEL0331 7.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4 7.4 7.42013 Annual Planning Report © Transpower New Zealand Limited 2013.All rights reserved. 391

Appendix C: Fault LevelsGrid exit pointPoint ofservice2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023AUCKLANDBombay BOB0331 9.2 9.1 9.1 9.1 9.1 9.1 9.1 9.1 9.1 9.1 9.1Bombay BOB1102 11.6 11.1 11.1 11.1 11.1 11.1 11.1 11.1 11.1 11.1 11.1Glenbrook GLN0331 16.4 16.2 16.2 16.2 16.2 16.2 16.2 16.2 16.2 16.2 16.2Glenbrook GLN0332 16.4 16.2 16.2 16.2 16.2 16.2 16.2 16.2 16.2 16.2 16.2Meremere MER0331 9.2 9.1 9.1 9.1 9.1 9.1 9.1 9.1 9.1 9.1 9.1Mangere MNG0331 15.8 15.1 15.1 15.1 15.1 15.1 15.1 15.1 15.1 15.1 15.1Mangere MNG1101 22.4 18.3 18.4 18.4 18.4 18.4 18.4 18.4 18.4 18.4 18.4Otahuhu OTA0221 27.0 22.8 23.2 23.2 23.2 23.2 23.2 23.2 23.2 23.2 23.2Otahuhu OTA1101 24.5 19.4 19.5 19.5 19.5 19.5 19.5 19.5 19.5 19.5 19.5Otahuhu B OTC2201 26.1 22.2 22.6 22.6 22.6 22.6 22.6 22.6 22.6 22.6 22.6Pakuranga PAK0331 25.9 25.2 25.3 25.3 25.3 25.3 25.3 25.3 25.3 25.3 25.3Penrose PEN0221 19.9 19.6 19.6 19.6 19.6 19.6 19.6 19.6 19.6 19.6 19.6Penrose PEN0251 22.9 19.8 20.1 20.1 20.1 20.1 20.1 20.1 20.1 20.1 20.1Penrose PEN0331 28.3 27.5 27.6 27.6 27.6 27.6 27.6 27.6 27.6 27.6 27.6Penrose PEN1101 26.9 25.2 25.4 25.4 25.4 25.4 25.4 25.4 25.4 25.4 25.4Mount Roskill ROS0221 22.9 22.2 22.3 22.3 22.3 22.3 22.3 22.3 22.3 22.3 22.3Mount Roskill ROS1101 22.3 19.4 19.5 19.5 19.5 19.5 19.5 19.5 19.5 19.5 19.5Southdown SWN2201 21.7 19.0 19.2 19.2 19.2 19.2 19.2 19.2 19.2 19.2 19.2Takanini TAK0331 18.1 17.8 17.8 17.8 17.8 17.8 17.8 17.8 17.8 17.8 17.8Wiri WIR0331 20.6 19.8 19.8 19.8 19.8 19.8 19.8 19.8 19.8 19.8 19.8WAIKATOArapuni ARI1101 7.8 7.8 7.8 7.8 7.8 7.8 7.8 7.8 7.8 7.8 7.8Atiamuri ATI2201 18.2 18.1 18.1 18.1 18.1 18.1 18.1 18.1 18.1 18.1 18.1Cambridge CBG0111 22.2 22.1 22.2 22.2 22.2 22.2 22.2 22.2 22.2 22.2 22.2Hamilton HAM0111 14.5 14.2 14.3 14.3 14.3 14.3 14.3 14.3 14.3 14.3 14.3Hamilton HAM0331 21.4 21.2 21.3 21.3 21.3 21.3 21.3 21.3 21.3 21.3 21.3Hamilton HAM0552 13.7 13.3 13.5 13.5 13.5 13.5 13.5 13.5 13.5 13.5 13.5Hinuera HIN0331 6.9 6.9 6.9 6.9 6.9 6.9 6.9 6.9 6.9 6.9 6.9Huntly HLY0331 15.1 15.0 15.0 15.0 15.0 15.0 15.0 15.0 15.0 15.0 15.0Huntly HLY0332 15.1 15.0 15.0 15.0 15.0 15.0 15.0 15.0 15.0 15.0 15.0Huntly HLY2201 29.9 28.2 28.5 28.5 28.5 28.5 28.5 28.5 28.5 28.5 28.5Hangatiki HTI0331 4.7 4.7 4.7 4.7 4.7 4.7 4.7 4.7 4.7 4.7 4.7Kinleith KIN0111 13.0 13.0 13.0 13.0 13.0 13.0 13.0 13.0 13.0 13.0 13.0Kinleith KIN0112 32.0 32.1 32.1 32.1 32.1 32.1 32.1 32.1 32.1 32.1 32.1Kinleith KIN0331 4.5 4.5 4.5 4.5 4.5 4.5 4.5 4.5 4.5 4.5 4.5Karapiro KPO1101 7.6 7.5 7.5 7.5 7.5 7.5 7.5 7.5 7.5 7.5 7.5Kopu KPU0661 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7Lichfield LFD1101 5.1 5.1 5.1 5.1 5.1 5.1 5.1 5.1 5.1 5.1 5.1Maraetai MTI0111 34.1 34.1 34.2 34.2 34.2 34.2 34.2 34.2 34.2 34.2 34.2Maraetai MTI2201 22.6 22.1 23.6 23.6 23.6 23.6 23.6 23.6 23.6 23.6 23.6Ohakuri OHK2201 17.7 17.7 17.7 17.7 17.7 17.7 17.7 17.7 17.7 17.7 17.73922013 Annual Planning Report © Transpower New Zealand Limited 2013.All rights reserved.

Appendix C: Fault LevelsGrid exit pointPoint ofservice2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023Ohaaki OKI2201 14.8 14.8 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0Piako PAO1101 6.4 6.3 6.3 6.3 6.3 6.3 6.3 6.3 6.3 6.3 6.3Te Awamutu TMU0111 3.7 3.7 3.7 3.7 3.7 3.7 3.7 3.7 3.7 3.7 3.7Te Awamutu TMU0112 17.3 17.3 17.3 17.3 17.3 17.3 17.3 17.3 17.3 17.3 17.3Te Kowhai TWH0331 21.4 21.3 21.3 21.3 21.3 21.3 21.3 21.3 21.3 21.3 21.3Waihou WHU0331 6.9 6.9 6.9 6.9 6.9 6.9 6.9 6.9 6.9 6.9 6.9Whakamaru WKM2201 28.7 27.9 30.5 30.5 30.5 30.5 30.5 30.5 30.5 30.5 30.5Waikino WKO0331 6.2 6.2 6.2 6.2 6.2 6.2 6.2 6.2 6.2 6.2 6.2Waipapa WPA2201 13.8 13.6 14.1 14.1 14.1 14.1 14.1 14.1 14.1 14.1 14.1Wairakei WRK0331 21.8 21.8 22.1 22.1 22.1 22.1 22.1 22.1 22.1 22.1 22.1Wairakei WRK2201 23.3 23.2 26.9 26.9 26.9 26.9 26.9 26.9 26.9 26.9 26.9BAY OF PLENTYEdgecumbe EDG0331 14.5 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4Kawerau KAW0111 18.6 19.9 19.9 19.9 19.9 19.9 19.9 19.9 19.9 19.9 19.9Kawerau KAW0114 16.2 17.3 17.3 17.3 17.3 17.3 17.3 17.3 17.3 17.3 17.3Kawerau KAW0115 16.2 17.2 17.2 17.2 17.2 17.2 17.2 17.2 17.2 17.2 17.2Kawerau KAW0116 16.8 17.9 17.9 17.9 17.9 17.9 17.9 17.9 17.9 17.9 17.9Kawerau KAW0117 16.6 17.6 17.6 17.6 17.6 17.6 17.6 17.6 17.6 17.6 17.6Kawerau KAW0118 34.6 35.0 35.0 35.0 35.0 35.0 35.0 35.0 35.0 35.0 35.0Kawerau KAW0119 16.8 17.9 17.9 17.9 17.9 17.9 17.9 17.9 17.9 17.9 17.9Kawerau KAW1101 8.7 12.6 12.6 12.6 12.6 12.6 12.6 12.6 12.6 12.6 12.6Kaitimako KMO0331 7.6 7.6 7.6 7.6 7.6 7.6 7.6 7.6 7.6 7.6 7.6Matahina MAT1101 6.6 10.4 10.4 10.4 10.4 10.4 10.4 10.4 10.4 10.4 10.4Mt Maunganui MTM0331 11.1 11.1 11.1 11.1 11.1 11.1 11.1 11.1 11.1 11.1 11.1Owhata OWH0111 5.6 5.7 5.7 5.7 5.7 5.7 5.7 5.7 5.7 5.7 5.7Rotorua ROT0111 17.3 17.3 17.3 17.3 17.3 17.3 17.3 17.3 17.3 17.3 17.3Rotorua ROT0331 8.7 8.8 8.8 8.8 8.8 8.8 8.8 8.8 8.8 8.8 8.8Rotorua ROT1101 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6Tauranga TGA0111 14.3 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4 14.4Tauranga TGA0331 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3Te Kaha TKH0111 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8Te Matai TMI0331 7.5 7.6 7.6 7.6 7.6 7.6 7.6 7.6 7.6 7.6 7.6Tarukenga TRK0111 10.5 10.5 10.5 10.5 10.5 10.5 10.5 10.5 10.5 10.5 10.5Waiotahi WAI0111 8.5 8.6 8.6 8.6 8.6 8.6 8.6 8.6 8.6 8.6 8.6CENTRAL NORTH ISLANDAratiatia ARA2201 18.4 18.4 20.6 20.6 20.6 20.6 20.6 20.6 20.6 20.6 20.6Bunnythorpe BPE0331 15.9 15.9 15.9 15.9 15.9 15.9 15.9 15.9 15.9 15.9 15.9Bunnythorpe BPE0552 12.6 12.6 12.6 12.6 12.6 12.6 12.6 12.6 12.6 12.6 12.6Brunswick BRK0331 9.0 9.0 9.0 9.0 9.0 9.0 9.0 9.0 9.0 9.0 9.0Dannevirke DVK0111 16.3 16.3 16.3 16.3 16.3 16.3 16.3 16.3 16.3 16.3 16.3Linton LTN0331 12.8 12.8 12.8 12.8 12.8 12.8 12.8 12.8 12.8 12.8 12.8Mangamaire MGM0331 4.6 4.6 4.6 4.6 4.6 4.6 4.6 4.6 4.6 4.6 4.62013 Annual Planning Report © Transpower New Zealand Limited 2013.All rights reserved. 393

Appendix C: Fault LevelsGrid exit pointPoint ofservice2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023Mangahao MHO0331 9.1 9.1 9.1 9.1 9.1 9.1 9.1 9.1 9.1 9.1 9.1Marton MTN0331 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6Mataroa MTR0331 3.6 3.5 3.6 3.6 3.6 3.6 3.6 3.6 3.6 3.6 3.6Nga AwaPuruaNAP2201 18.1 18.1 20.0 20.0 20.0 20.0 20.0 20.0 20.0 20.0 20.0National Park NPK0331 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6Ohakune OKN0111 4.7 4.7 4.7 4.7 4.7 4.7 4.7 4.7 4.7 4.7 4.7Ongarue ONG0331 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5Poihipi PPI2201 16.3 16.2 22.8 22.8 22.8 22.8 22.8 22.8 22.8 22.8 22.8Rangipo RPO2201 6.9 6.9 7.0 7.0 7.0 7.0 7.0 7.0 7.0 7.0 7.0Te Mihi THI2201 21.5 22.4 24.3 24.3 24.3 24.3 24.3 24.3 24.3 24.3 24.3Tokaanu TKU0331 3.8 3.8 3.8 3.8 3.8 3.8 3.8 3.8 3.8 3.8 3.8Tokaanu TKU2201 12.0 11.9 12.1 12.1 12.1 12.1 12.1 12.1 12.1 12.1 12.1Tangiwai TNG0111 19.8 19.8 19.8 19.8 19.8 19.8 19.8 19.8 19.8 19.8 19.8Tangiwai TNG0552 5.0 5.0 5.1 5.1 5.1 5.1 5.1 5.1 5.1 5.1 5.1Tararua WindCentralTWC2201 8.7 8.7 8.7 8.7 8.7 8.7 8.7 8.7 8.7 8.7 8.7Woodville WDV1101 7.6 7.6 7.6 7.6 7.6 7.6 7.6 7.6 7.6 7.6 7.6Wanganui WGN0331 6.4 6.4 6.4 6.4 6.4 6.4 6.4 6.4 6.4 6.4 6.4Waipawa WPW0111 4.2 4.2 4.2 4.2 4.2 4.2 4.2 4.2 4.2 4.2 4.2Waipawa WPW0331 4.8 4.8 4.8 4.8 4.8 4.8 4.8 4.8 4.8 4.8 4.8TARANAKICarringtonStreetCST0331 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3Huirangi HUI0331 6.2 6.2 6.2 6.2 6.2 6.2 6.2 6.2 6.2 6.2 6.2Hawera HWA0331 8.2 8.2 8.2 8.2 8.2 8.2 8.2 8.2 8.2 8.2 8.2Hawera HWA0332 4.7 4.7 4.7 4.7 4.7 4.7 4.7 4.7 4.7 4.7 4.7Hawera HWA1101 7.7 7.7 7.7 7.7 7.7 7.7 7.7 7.7 7.7 7.7 7.7Hawera HWA1102 7.7 7.7 7.7 7.7 7.7 7.7 7.7 7.7 7.7 7.7 7.7Kaponga KPA1101 5.7 5.7 5.7 5.7 5.7 5.7 5.7 5.7 5.7 5.7 5.7McKee MKE1101 6.9 6.9 6.9 6.9 6.9 6.9 6.9 6.9 6.9 6.9 6.9Motunui MNI0111 15.9 15.9 15.9 15.9 15.9 15.9 15.9 15.9 15.9 15.9 15.9Motunui MNI0112 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0 16.0New Plymouth NPL0331 10.4 10.4 10.4 10.4 10.4 10.4 10.4 10.4 10.4 10.4 10.4New Plymouth NPL2201 9.0 9.0 9.0 9.0 9.0 9.0 9.0 9.0 9.0 9.0 9.0Opunake OPK0331 4.4 4.4 4.4 4.4 4.4 4.4 4.4 4.4 4.4 4.4 4.4Stratford SFD0331 7.5 7.5 7.5 7.5 7.5 7.5 7.5 7.5 7.5 7.5 7.5Stratford SFD2201 13.3 13.2 13.2 13.2 13.2 13.2 13.2 13.2 13.2 13.2 13.2Taumarunui TMN0552 4.3 4.3 4.3 4.3 4.3 4.3 4.3 4.3 4.3 4.3 4.3Waverley WVY0111 4.5 4.5 4.5 4.5 4.5 4.5 4.5 4.5 4.5 4.5 4.5HAWKE'SBAYFernhill FHL0331 9.2 9.2 9.2 9.2 9.2 9.2 9.2 9.2 9.2 9.2 9.2Gisborne GIS0501 3.6 3.6 3.6 3.6 3.6 3.6 3.6 3.6 3.6 3.6 3.6Redclyffe RDF0331 9.5 9.5 9.6 9.6 9.6 9.6 9.6 9.6 9.6 9.6 9.63942013 Annual Planning Report © Transpower New Zealand Limited 2013.All rights reserved.

Appendix C: Fault LevelsGrid exit pointPoint ofservice2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023Tuai TUI1101 5.8 5.8 5.9 5.9 5.9 5.9 5.9 5.9 5.9 5.9 5.9Whirinaki WHI0111 22.1 22.1 22.2 22.2 22.2 22.2 22.2 22.2 22.2 22.2 22.2Whirinaki WHI0112 22.0 22.0 22.1 22.1 22.1 22.1 22.1 22.1 22.1 22.1 22.1Whirinaki WHI0113 22.5 22.5 22.6 22.6 22.6 22.6 22.6 22.6 22.6 22.6 22.6Whirinaki WHI2201 6.1 6.1 6.3 6.3 6.3 6.3 6.3 6.3 6.3 6.3 6.3Wairoa WRA0111 9.2 9.2 9.2 9.2 9.2 9.2 9.2 9.2 9.2 9.2 9.2Whakatu WTU0331 12.4 12.4 12.5 12.5 12.5 12.5 12.5 12.5 12.5 12.5 12.5WELLINGTONCentral Park CPK0111 7.2 7.2 7.2 7.2 7.2 7.2 7.2 7.2 7.2 7.2 7.2Central Park CPK0331 7.2 7.2 7.2 7.2 7.2 7.2 7.2 7.2 7.2 7.2 7.2Gracefield GFD0331 13.4 13.4 13.4 13.4 13.4 13.4 13.4 13.4 13.4 13.4 13.4Greytown GYT0331 3.8 3.8 3.8 3.8 3.8 3.8 3.8 3.8 3.8 3.8 3.8Haywards HAY0111 18.6 18.5 18.6 18.6 18.6 18.6 18.6 18.6 18.6 18.6 18.6Haywards HAY0331 4.0 4.0 4.0 4.0 4.0 4.0 4.0 4.0 4.0 4.0 4.0Kaiwharawhara KWA0111 8.0 8.0 8.0 8.0 8.0 8.0 8.0 8.0 8.0 8.0 8.0Melling MLG0111 13.6 13.6 13.6 13.6 13.6 13.6 13.6 13.6 13.6 13.6 13.6Melling MLG0331 9.4 9.4 9.4 9.4 9.4 9.4 9.4 9.4 9.4 9.4 9.4Masterton MST0331 8.7 8.7 8.7 8.7 8.7 8.7 8.7 8.7 8.7 8.7 8.7Pauatahanui PNI0331 6.3 6.3 6.3 6.3 6.3 6.3 6.3 6.3 6.3 6.3 6.3Paraparaumu PRM0331 8.0 8.0 8.0 8.0 8.0 8.0 8.0 8.0 8.0 8.0 8.0Takapu Road TKR0331 14.5 14.5 14.5 14.5 14.5 14.5 14.5 14.5 14.5 14.5 14.5Upper Hutt UHT0331 9.6 9.6 9.6 9.6 9.6 9.6 9.6 9.6 9.6 9.6 9.6Wilton WIL0331 13.2 13.2 13.2 13.2 13.2 13.2 13.2 13.2 13.2 13.2 13.2West Wind WWD1101 9.9 9.9 9.9 9.9 9.9 9.9 9.9 9.9 9.9 9.9 9.9West Wind WWD1102 9.9 9.9 9.9 9.9 9.9 9.9 9.9 9.9 9.9 9.9 9.9NELSON-MARLBOROUGHArgyle ARG1101 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7Blenheim BLN0331 6.8 6.8 6.8 6.8 6.8 6.8 6.8 6.8 6.8 6.8 6.8Cobb COB0661 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0Kikiwa KIK0111 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9Motueka MOT0111 7.7 7.7 7.7 7.7 7.7 7.7 7.7 7.7 7.7 7.7 7.7Motupipi MPI0661 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6Stoke STK0331 11.4 11.4 11.7 11.7 11.7 11.7 11.7 11.7 11.7 11.7 11.7WEST COASTArthurs Pass APS0111 2.2 2.2 2.2 2.2 2.2 2.2 2.2 2.2 2.2 2.2 2.2Atarau ATU1101 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5Castle Hill CLH0111 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7Dobson DOB0331 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0Greymouth GYM0661 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5 2.5Hokitika HKK0661 1.7 1.7 1.7 1.7 1.7 1.7 1.7 1.7 1.7 1.7 1.7Kumara KUM0661 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.42013 Annual Planning Report © Transpower New Zealand Limited 2013.All rights reserved. 395

Appendix C: Fault LevelsGrid exit pointPoint ofservice2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023Murchison MCH0111 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6Orowaiti ORO1101 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5Orowaiti ORO1102 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5Otira OTI0111 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6Reefton RFN1101 1.8 1.8 1.8 1.8 1.8 1.8 1.8 1.8 1.8 1.8 1.8Reefton RFN1102 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0Westport WPT0111 8.7 8.7 8.7 8.7 8.7 8.7 8.7 8.7 8.7 8.7 8.7CANTERBURYAddington ADD0111 16.3 16.3 16.3 16.3 16.3 16.3 16.3 16.3 16.3 16.3 16.3Addington ADD0112 15.7 15.7 15.7 15.7 15.7 15.7 15.7 15.7 15.7 15.7 15.7Addington ADD0661 12.4 12.4 12.4 12.4 12.4 12.4 12.4 12.4 12.4 12.4 12.4Ashburton ASB0331 9.8 9.8 9.8 9.8 9.8 9.8 9.8 9.8 9.8 9.8 9.8Ashburton ASB0661 7.9 10.4 10.4 10.4 10.4 10.4 10.4 10.4 10.4 10.4 10.4Ashley ASY0111 8.7 8.7 8.7 8.7 8.7 8.7 8.7 8.7 8.7 8.7 8.7Bromley BRY0111 14.8 15.2 15.2 15.2 15.2 15.2 15.2 15.2 15.2 15.2 15.2Bromley BRY0661 10.9 12.6 12.7 12.7 12.7 12.7 12.7 12.7 12.7 12.7 12.7Coleridge COL0111 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6Coleridge COL0661 4.4 4.4 4.4 4.4 4.4 4.4 4.4 4.4 4.4 4.4 4.4Culverden CUL0331 7.2 7.2 7.2 7.2 7.2 7.2 7.2 7.2 7.2 7.2 7.2Hororata HOR0331 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8Hororata HOR0661 4.6 4.6 4.6 4.6 4.6 4.6 4.6 4.6 4.6 4.6 4.6Islington ISL0331 15.0 15.0 15.0 15.0 15.0 15.0 15.0 15.0 15.0 15.0 15.0Islington ISL0661 17.6 17.6 17.7 17.7 17.7 17.7 17.7 17.7 17.7 17.7 17.7Kaiapoi KAI0111 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1 13.1Middleton MLN0661 12.8 12.8 12.8 12.8 12.8 12.8 12.8 12.8 12.8 12.8 12.8Middleton MLN0662 12.8 12.8 12.8 12.8 12.8 12.8 12.8 12.8 12.8 12.8 12.8Southbrook SBK0331 6.1 6.1 6.1 6.1 6.1 6.2 6.2 6.2 6.2 6.2 6.2Springston SPN0331 7.1 7.1 7.1 7.1 7.1 7.1 7.1 7.1 7.1 7.1 7.1Springston SPN0661 8.3 8.3 8.3 8.3 8.3 8.3 8.3 8.3 8.3 8.3 8.3Waipara WPR0331 1.8 1.8 1.8 1.8 1.8 1.8 1.8 1.8 1.8 1.8 1.8Waipara WPR0661 8.5 8.5 8.6 8.6 8.6 8.6 8.6 8.6 8.6 8.6 8.6SOUTH CANTERBURYAlbury ABY0111 4.5 4.5 4.5 4.5 4.5 4.5 4.5 4.5 4.5 4.5 4.5Aviemore AVI2201 16.0 16.0 16.2 16.2 17.4 17.5 17.5 17.5 17.5 17.5 17.5Bells Pond BPD1101 3.9 3.9 3.9 3.9 3.9 3.9 3.9 3.9 3.9 3.9 3.9Black Point BPT1101 3.2 3.2 3.3 3.3 3.3 3.3 3.3 3.3 3.3 3.3 3.3Oamaru OAM0331 6.0 6.0 6.0 6.0 6.0 6.0 6.0 6.0 6.0 6.0 6.0Studholme STU0111 9.2 9.2 9.2 9.2 9.2 9.2 9.2 9.2 9.2 9.2 9.2Timaru TIM0111 21.8 21.8 21.8 21.8 21.8 21.8 21.8 21.8 21.8 21.8 21.8Tekapo A TKA0111 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7Tekapo A TKA0331 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6Tekapo B TKB2201 12.1 12.1 12.1 12.1 12.1 12.1 12.1 12.1 12.1 12.1 12.13962013 Annual Planning Report © Transpower New Zealand Limited 2013.All rights reserved.

Appendix C: Fault LevelsGrid exit pointPoint ofservice2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023Temuka TMK0331 7.0 7.0 7.0 7.0 7.0 7.0 7.0 7.0 7.0 7.0 7.0Twizel TWZ0331 9.0 9.0 9.0 9.0 9.0 9.0 9.0 9.0 9.0 9.0 9.0Waitaki WTK0111 40.6 40.7 40.7 40.7 40.8 40.8 40.8 40.8 40.8 40.8 40.8Waitaki WTK0331 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8OTAGO-SOUTHLANDBalclutha BAL0331 3.8 3.8 3.6 3.6 3.6 3.6 3.6 3.6 3.6 3.6 3.6Brydone BDE0111 12.7 12.7 14.0 14.0 14.0 14.0 14.0 14.0 14.0 14.1 14.1Benmore BEN2201 19.8 19.9 19.9 19.9 20.3 20.3 20.3 20.3 20.3 20.3 20.3Berwick BWK1101 4.9 4.9 4.8 4.8 4.8 4.8 4.8 4.8 4.8 4.8 4.8Cromwell CML0331 10.5 10.5 10.5 10.5 10.5 10.5 10.5 10.5 10.5 10.5 10.5Clyde CYD0331 10.4 10.4 10.4 10.4 10.4 10.4 10.4 10.4 10.4 10.5 10.5Clyde CYD2201 15.0 15.7 15.7 15.7 15.9 15.9 15.9 15.9 15.9 15.9 15.9Edendale EDN0331 6.2 6.2 6.7 6.7 6.7 6.7 6.7 6.7 6.7 6.8 6.8Frankton FKN0331 7.6 7.6 7.6 7.6 7.6 7.6 7.6 7.6 7.6 7.6 7.6Gore GOR0331 6.2 6.2 8.0 8.0 8.0 8.0 8.0 8.0 8.0 8.1 8.1Halfway Bush HWB0331 16.0 16.1 16.2 16.2 16.2 16.2 16.2 16.2 16.2 16.4 16.4Halfway Bush HWB0332 13.9 14.0 14.1 14.1 14.1 14.1 14.1 14.1 14.1 14.3 14.3Invercargill INV0331 17.4 17.5 17.5 17.5 17.5 17.5 17.5 17.5 17.5 17.7 17.7Manapouri MAN2201 11.5 11.6 11.7 11.7 11.7 11.7 11.7 11.7 11.7 11.9 11.9NorthMakarewaNMA0331 10.5 10.5 10.5 10.5 10.5 10.5 10.5 10.5 10.5 10.6 10.6Naseby NSY0331 7.8 7.8 7.8 7.8 8.0 8.0 8.0 8.0 8.0 8.0 8.0Ohau A OHA2201 18.0 18.0 18.0 18.0 18.1 18.1 18.1 18.1 18.1 18.1 18.1Ohau B OHB2201 19.5 19.5 19.5 19.5 19.7 19.7 19.7 19.7 19.7 19.7 19.7Ohau C OHC2201 17.3 17.4 17.4 17.4 17.5 17.5 17.5 17.5 17.5 17.5 17.5Palmerston PAL0331 1.7 1.7 1.7 1.7 1.7 1.7 1.7 1.7 1.7 1.7 1.7Roxburgh ROX1101 10.5 10.5 10.2 10.2 10.2 10.2 10.2 10.2 10.2 10.2 10.2Roxburgh ROX2201 15.2 15.9 16.0 16.0 16.3 16.3 16.3 16.3 16.3 16.4 16.4South Dunedin SDN0331 17.2 17.3 17.6 17.6 17.6 17.6 17.6 17.6 17.6 17.9 17.9Tiwai TWI2201 8.6 8.7 8.8 8.8 8.8 8.8 8.8 8.8 8.8 9.1 9.12013 Annual Planning Report © Transpower New Zealand Limited 2013.All rights reserved. 397

Appendix C: Fault LevelsTable C.3: Ten year forecast of single-phase maximum fault levels,of service(kA) of each pointGrid exit pointNORTHLANDPoint ofservice2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023Albany ALB0331 3.2 3.2 3.2 3.2 3.2 3.2 3.2 3.2 3.2 3.2 3.2Albany ALB1101 14.8 15.3 15.4 15.4 15.4 15.4 15.4 15.4 15.4 15.4 15.4Bream Bay BRB0331 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0Dargaville DAR0111 5.7 5.7 5.7 5.7 5.7 5.7 5.7 5.7 5.7 5.7 5.7Henderson HEN0331 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1Hepburn Road HEP0331 25.0 24.4 24.4 24.4 24.4 24.4 24.4 24.4 24.4 24.4 24.4Kensington KEN0331 11.2 11.2 11.2 11.2 11.2 11.2 11.2 11.2 11.2 11.2 11.2Kaikohe KOE1101 1.7 1.7 1.7 1.7 1.7 1.7 1.7 1.7 1.7 1.7 1.7Marsden MDN0142 8.8 8.8 8.8 8.8 8.8 8.8 8.8 8.8 8.8 8.8 8.8Marsden MDN1101 8.8 8.8 8.8 8.8 8.8 8.8 8.8 8.8 8.8 8.8 8.8Maungatapere MPE0331 8.8 8.8 8.8 8.8 8.8 8.8 8.8 8.8 8.8 8.8 8.8Maungaturoto MTO0331 4.8 4.8 4.8 4.8 4.8 4.8 4.8 4.8 4.8 4.8 4.8Silverdale SVL0331 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0Wellsford WEL0331 8.4 8.4 8.4 8.4 8.4 8.4 8.4 8.4 8.4 8.4 8.4AUCKLANDBombay BOB0331 10.0 9.9 9.9 9.9 9.9 9.9 9.9 9.9 9.9 9.9 9.9Bombay BOB1102 5.9 5.8 5.8 5.8 5.8 5.8 5.8 5.8 5.8 5.8 5.8Glenbrook GLN0331 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2Glenbrook GLN0332 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2Meremere MER0331 10.0 9.9 9.9 9.9 9.9 9.9 9.9 9.9 9.9 9.9 9.9Mangere MNG0331 17.0 16.4 16.4 16.4 16.4 16.4 16.4 16.4 16.4 16.4 16.4Mangere MNG1101 20.4 17.0 17.1 17.1 17.1 17.1 17.1 17.1 17.1 17.1 17.1Otahuhu OTA0221 32.5 28.3 28.6 28.6 28.6 28.6 28.6 28.6 28.6 28.6 28.6Otahuhu OTA1101 28.0 21.6 21.7 21.7 21.7 21.7 21.7 21.7 21.7 21.7 21.7Otahuhu B OTC2201 30.8 27.1 27.4 27.4 27.4 27.4 27.4 27.4 27.4 27.4 27.4Pakuranga PAK0331 3.6 3.6 3.6 3.6 3.6 3.6 3.6 3.6 3.6 3.6 3.6Penrose PEN0221 29.2 28.8 28.9 28.9 28.9 28.9 28.9 28.9 28.9 28.9 28.9Penrose PEN0251 26.9 24.5 24.8 24.8 24.8 24.8 24.8 24.8 24.8 24.8 24.8Penrose PEN0331 32.3 31.7 31.7 31.7 31.7 31.7 31.7 31.7 31.7 31.7 31.7Penrose PEN1101 29.3 29.2 29.4 29.4 29.4 29.4 29.4 29.4 29.4 29.3 29.3Mount Roskill ROS0221 24.6 24.1 24.1 24.1 24.1 24.1 24.1 24.1 24.1 24.1 24.1Mount Roskill ROS1101 18.2 16.6 16.6 16.6 16.6 16.6 16.6 16.5 16.5 16.5 16.6Southdown SWN2201 22.5 20.5 20.6 20.6 20.6 20.6 20.6 20.6 20.6 20.6 20.6Takanini TAK0331 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1Wiri WIR0331 2.3 2.3 2.3 2.3 2.3 2.3 2.3 2.3 2.3 2.3 2.3WAIKATOArapuni ARI1101 7.5 7.5 7.5 7.5 7.5 7.5 7.5 7.5 7.5 7.5 7.5Atiamuri ATI2201 17.4 17.3 17.4 17.4 17.4 17.4 17.4 17.4 17.4 17.4 17.4Cambridge CBG0111 24.3 24.3 24.3 24.3 24.3 24.3 24.3 24.3 24.3 24.3 24.33982013 Annual Planning Report © Transpower New Zealand Limited 2013.All rights reserved.

Appendix C: Fault LevelsGrid exit pointPoint ofservice2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023Hamilton HAM0111 13.3 13.2 13.2 13.2 13.2 13.2 13.2 13.2 13.2 13.2 13.2Hamilton HAM0331 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1Hamilton HAM0552 12.0 11.8 11.9 11.9 11.9 11.9 11.9 11.9 11.9 11.9 11.9Hinuera HIN0331 8.5 8.5 8.5 8.5 8.5 8.5 8.5 8.5 8.5 8.5 8.5Huntly HLY0331 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1Huntly HLY0332 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1Huntly HLY2201 34.4 33.0 33.3 33.3 33.3 33.3 33.3 33.3 33.3 33.3 33.3Hangatiki HTI0331 5.4 5.4 5.4 5.4 5.4 5.4 5.4 5.4 5.4 5.4 5.4Kinleith KIN0111 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2 14.2Kinleith KIN0112 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0Kinleith KIN0331 5.0 5.0 5.0 5.0 5.0 5.0 5.0 5.0 5.0 5.0 5.0Karapiro KPO1101 8.2 8.2 8.2 8.2 8.2 8.2 8.2 8.2 8.2 8.2 8.2Kopu KPU0661 3.3 3.3 3.3 3.3 3.3 3.3 3.3 3.3 3.3 3.3 3.3Lichfield LFD1101 4.9 4.9 4.9 4.9 4.9 4.9 4.9 4.9 4.9 4.9 4.9Maraetai MTI0111 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0Maraetai MTI2201 22.6 22.4 23.8 23.8 23.8 23.8 23.8 23.8 23.8 23.8 23.8Ohakuri OHK2201 17.2 17.2 17.2 17.2 17.2 17.2 17.2 17.2 17.2 17.2 17.2Ohaaki OKI2201 12.7 12.7 13.4 13.4 13.4 13.4 13.4 13.4 13.4 13.4 13.4Piako PAO1101 3.4 3.4 3.4 3.4 3.4 3.4 3.4 3.4 3.4 3.4 3.4Te Awamutu TMU0111 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8Te Awamutu TMU0112 20.6 20.5 20.5 20.5 20.5 20.5 20.5 20.5 20.5 20.5 20.5Te Kowhai TWH0331 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1Waihou WHU0331 7.9 7.9 7.9 7.9 7.9 7.9 7.9 7.9 7.9 7.9 7.9Whakamaru WKM2201 27.4 27.0 31.0 31.0 31.0 31.0 31.0 31.0 31.0 31.0 31.0Waikino WKO0331 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3Waipapa WPA2201 12.4 12.3 12.7 12.7 12.7 12.7 12.7 12.7 12.7 12.7 12.7Wairakei WRK0331 22.7 22.7 22.9 22.9 22.9 22.9 22.9 22.9 22.9 22.9 22.9Wairakei WRK2201 25.7 25.6 29.1 29.1 29.1 29.1 29.1 29.1 29.1 29.1 29.1BAY OFPLENTYEdgecumbe EDG0331 16.2 16.1 16.1 16.1 16.1 16.1 16.1 16.1 16.1 16.1 16.1Kawerau KAW0111 19.9 21.0 21.0 21.0 21.0 21.0 21.0 21.0 21.0 21.0 21.0Kawerau KAW0114 2.2 2.2 2.2 2.2 2.2 2.2 2.2 2.2 2.2 2.2 2.2Kawerau KAW0115 2.2 2.2 2.2 2.2 2.2 2.2 2.2 2.2 2.2 2.2 2.2Kawerau KAW0116 2.1 2.1 2.1 2.1 2.1 2.1 2.1 2.1 2.1 2.1 2.1Kawerau KAW0117 2.2 2.2 2.2 2.2 2.2 2.2 2.2 2.2 2.2 2.2 2.2Kawerau KAW0118 5.7 5.7 5.7 5.7 5.7 5.7 5.7 5.7 5.7 5.7 5.7Kawerau KAW0119 2.1 2.1 2.1 2.1 2.1 2.1 2.1 2.1 2.1 2.1 2.1Kawerau KAW1101 10.3 14.5 14.5 14.5 14.5 14.5 14.5 14.5 14.5 14.5 14.5Kaitimako KMO0331 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6Matahina MAT1101 6.8 10.4 10.4 10.4 10.4 10.4 10.4 10.4 10.4 10.4 10.4Mt Maunganui MTM0331 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1Owhata OWH0111 4.0 4.0 4.0 4.0 4.0 4.0 4.0 4.0 4.0 4.0 4.0Rotorua ROT0111 19.0 19.1 19.1 19.1 19.1 19.1 19.1 19.1 19.1 19.1 19.12013 Annual Planning Report © Transpower New Zealand Limited 2013.All rights reserved. 399

Appendix C: Fault LevelsGrid exit pointPoint ofservice2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023Rotorua ROT0331 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0Rotorua ROT1101 5.4 5.4 5.4 5.4 5.4 5.4 5.4 5.4 5.4 5.4 5.4Tauranga TGA0111 15.2 15.2 15.2 15.2 15.2 15.2 15.2 15.2 15.2 15.2 15.2Tauranga TGA0331 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5Te Kaha TKH0111 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9Te Matai TMI0331 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2Tarukenga TRK0111 10.8 10.8 10.8 10.8 10.8 10.8 10.8 10.8 10.8 10.8 10.8Waiotahi WAI0111 9.5 9.5 9.5 9.5 9.5 9.5 9.5 9.5 9.5 9.5 9.5CENTRAL NORTH ISLANDAratiatia ARA2201 18.5 18.4 20.1 20.1 20.1 20.1 20.1 20.1 20.1 20.1 20.1Bunnythorpe BPE0331 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0Bunnythorpe BPE0552 12.8 12.8 12.8 12.8 12.8 12.8 12.8 12.8 12.8 12.8 12.8Brunswick BRK0331 9.4 9.4 9.4 9.4 9.4 9.4 9.4 9.4 9.4 9.4 9.4Dannevirke DVK0111 18.2 18.2 18.2 18.2 18.2 18.2 18.2 18.2 18.2 18.2 18.2Linton LTN0331 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2Mangamaire MGM0331 5.1 5.1 5.1 5.1 5.1 5.1 5.1 5.1 5.1 5.1 5.1Mangahao MHO0331 11.1 11.1 11.1 11.1 11.1 11.1 11.1 11.1 11.1 11.1 11.1Marton MTN0331 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3Mataroa MTR0331 4.1 4.1 4.1 4.1 4.1 4.1 4.1 4.1 4.1 4.1 4.1Nga Awa Purua NAP2201 19.0 19.0 20.5 20.5 20.5 20.5 20.5 20.5 20.5 20.5 20.5National Park NPK0331 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0Ohakune OKN0111 5.1 5.1 5.1 5.1 5.1 5.1 5.1 5.1 5.1 5.1 5.1Ongarue ONG0331 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8Poihipi PPI2201 15.4 15.4 22.9 22.9 22.9 22.9 22.9 22.9 22.9 22.9 22.9Rangipo RPO2201 6.7 6.7 6.7 6.7 6.7 6.7 6.7 6.7 6.7 6.7 6.7Te Mihi THI2201 22.8 22.8 25.7 25.7 25.7 25.7 25.7 25.7 25.7 25.7 25.7Tokaanu TKU0331 3.9 3.9 3.9 3.9 3.9 3.9 3.9 3.9 3.9 3.9 3.9Tokaanu TKU2201 11.3 11.3 11.4 11.4 11.4 11.4 11.4 11.4 11.4 11.4 11.4Tangiwai TNG0111 21.2 21.2 21.2 21.2 21.2 21.2 21.2 21.2 21.2 21.2 21.2Tangiwai TNG0552 3.7 3.7 3.7 3.7 3.7 3.7 3.7 3.7 3.7 3.7 3.7Tararua WindCentralTWC2201 8.0 8.0 8.0 8.0 8.0 8.0 8.0 8.0 8.0 8.0 8.0Woodville WDV1101 4.8 4.8 4.8 4.8 4.8 4.8 4.8 4.8 4.8 4.8 4.8Wanganui WGN0331 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3Waipawa WPW0111 4.7 4.7 4.7 4.7 4.7 4.7 4.7 4.7 4.7 4.7 4.7Waipawa WPW0331 5.9 5.9 5.9 5.9 5.9 5.9 5.9 5.9 5.9 5.9 5.9TARANAKICarringtonStreetCST0331 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2Huirangi HUI0331 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5Hawera HWA0331 9.1 9.1 9.1 9.1 9.1 9.1 9.1 9.1 9.1 9.1 9.1Hawera HWA0332 5.0 5.0 5.0 5.0 5.0 5.0 5.0 5.0 5.0 5.0 5.0Hawera HWA1101 7.9 7.9 7.9 7.9 7.9 7.9 7.9 7.9 7.9 7.9 7.9Hawera HWA1102 7.9 7.9 7.9 7.9 7.9 7.9 7.9 7.9 7.9 7.9 7.94002013 Annual Planning Report © Transpower New Zealand Limited 2013.All rights reserved.

Appendix C: Fault LevelsGrid exit pointPoint ofservice2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023Kaponga KPA1101 5.0 5.0 5.0 5.0 5.0 5.0 5.0 5.0 5.0 5.0 5.0McKee MKE1101 8.0 8.0 8.0 8.0 8.0 8.0 8.0 8.0 8.0 8.0 8.0Motunui MNI0111 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5Motunui MNI0112 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5New Plymouth NPL0331 11.3 11.3 11.3 11.3 11.3 11.3 11.3 11.3 11.3 11.3 11.3New Plymouth NPL2201 8.2 8.2 8.2 8.2 8.2 8.2 8.2 8.2 8.2 8.2 8.2Opunake OPK0331 4.8 4.8 4.8 4.8 4.8 4.8 4.8 4.8 4.8 4.8 4.8Stratford SFD0331 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1Stratford SFD2201 15.0 15.0 15.0 15.0 15.0 15.0 15.0 15.0 15.0 15.0 15.0Taumarunui TMN0552 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8Waverley WVY0111 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0HAWKE'S BAYFernhill FHL0331 10.7 10.7 10.7 10.7 10.7 10.7 10.7 10.7 10.7 10.7 10.7Gisborne GIS0501 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4Redclyffe RDF0331 10.9 10.9 11.0 11.0 11.0 11.0 11.0 11.0 11.0 11.0 11.0Tuai TUI1101 7.0 7.0 7.0 7.0 7.0 7.0 7.0 7.0 7.0 7.0 7.0Whirinaki WHI0111 4.2 4.2 4.2 4.2 4.2 4.2 4.2 4.2 4.2 4.2 4.2Whirinaki WHI0112 4.2 4.2 4.2 4.2 4.2 4.2 4.2 4.2 4.2 4.2 4.2Whirinaki WHI0113 4.1 4.1 4.1 4.1 4.1 4.1 4.1 4.1 4.1 4.1 4.1Whirinaki WHI2201 5.4 5.4 5.5 5.5 5.5 5.5 5.5 5.5 5.5 5.5 5.5Wairoa WRA0111 10.1 10.1 10.1 10.1 10.1 10.1 10.1 10.1 10.1 10.1 10.1Whakatu WTU0331 13.9 13.9 14.0 14.0 14.0 14.0 14.0 14.0 14.0 14.0 14.0WELLINGTONCentral Park CPK0111 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2Central Park CPK0331 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2Gracefield GFD0331 14.9 14.9 14.9 14.9 14.9 14.9 14.9 14.9 14.9 14.9 14.9Greytown GYT0331 4.0 4.0 4.0 4.0 4.0 4.0 4.0 4.0 4.0 4.0 4.0Haywards HAY0111 20.6 20.7 20.7 20.7 20.7 20.7 20.7 20.7 20.7 20.7 20.7Haywards HAY0331 3.9 3.9 3.9 3.9 3.9 3.9 3.9 3.9 3.9 3.9 3.9Kaiwharawhara KWA0111 1.3 1.3 1.3 1.3 1.3 1.3 1.3 1.3 1.3 1.3 1.3Melling MLG0111 14.1 14.1 14.1 14.1 14.1 14.1 14.1 14.1 14.1 14.1 14.1Melling MLG0331 10.1 10.1 10.1 10.1 10.1 10.1 10.1 10.1 10.1 10.1 10.1Masterton MST0331 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1Pauatahanui PNI0331 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.6Paraparaumu PRM0331 9.0 9.0 9.0 9.0 9.0 9.0 9.0 9.0 9.0 9.0 9.0Takapu Road TKR0331 15.9 15.9 15.9 15.9 15.9 15.9 15.9 15.9 15.9 15.9 15.9Upper Hutt UHT0331 10.2 10.2 10.2 10.2 10.2 10.2 10.2 10.2 10.2 10.2 10.2Wilton WIL0331 14.3 14.3 14.3 14.3 14.3 14.3 14.3 14.3 14.3 14.3 14.3West Wind WWD1101 7.7 7.7 7.7 7.7 7.7 7.7 7.7 7.7 7.7 7.7 7.7West Wind WWD1102 7.7 7.7 7.7 7.7 7.7 7.7 7.7 7.7 7.7 7.7 7.7NELSON-MARLBOROUGH2013 Annual Planning Report © Transpower New Zealand Limited 2013.All rights reserved. 401

Appendix C: Fault LevelsGrid exit pointPoint ofservice2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023Argyle ARG1101 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6Blenheim BLN0331 1.7 1.7 1.7 1.7 1.7 1.7 1.7 1.7 1.7 1.7 1.7Cobb COB0661 3.4 3.4 3.4 3.4 3.4 3.4 3.4 3.4 3.4 3.4 3.4Kikiwa KIK0111 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0Motueka MOT0111 8.7 8.7 8.7 8.7 8.7 8.7 8.7 8.7 8.7 8.7 8.7Motupipi MPI0661 1.3 1.3 1.3 1.3 1.3 1.3 1.3 1.3 1.3 1.3 1.3Stoke STK0331 0.6 0.6 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2WEST COASTArthurs Pass APS0111 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4Atarau ATU1101 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5Castle Hill CLH0111 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0Dobson DOB0331 3.6 3.6 3.6 3.6 3.6 3.6 3.6 3.6 3.6 3.6 3.6Greymouth GYM0661 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7Hokitika HKK0661 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2Kumara KUM0661 2.3 2.3 2.3 2.3 2.3 2.3 2.3 2.3 2.3 2.3 2.3Murchison MCH0111 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7Orowaiti ORO1101 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2Orowaiti ORO1102 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2Otira OTI0111 1.7 1.7 1.7 1.7 1.7 1.7 1.7 1.7 1.7 1.7 1.7Reefton RFN1101 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5Reefton RFN1102 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0Westport WPT0111 10.5 10.5 10.5 10.5 10.5 10.5 10.5 10.5 10.5 10.5 10.5CANTERBURYAddington ADD0111 17.4 17.4 17.4 17.4 17.4 17.4 17.4 17.4 17.4 17.4 17.4Addington ADD0112 16.7 16.7 16.7 16.7 16.7 16.7 16.7 16.7 16.7 16.7 16.7Addington ADD0661 12.5 12.6 12.6 12.6 12.6 12.6 12.6 12.6 12.6 12.6 12.6Ashburton ASB0331 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9Ashburton ASB0661 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6Ashley ASY0111 9.5 9.5 9.5 9.5 9.5 9.5 9.5 9.5 9.5 9.5 9.5Bromley BRY0111 16.0 16.3 16.3 16.3 16.3 16.3 16.3 16.3 16.3 16.3 16.3Bromley BRY0661 13.2 16.4 16.4 16.4 16.4 16.5 16.5 16.5 16.5 16.5 16.5Coleridge COL0111 1.7 1.7 1.7 1.7 1.7 1.7 1.7 1.7 1.7 1.7 1.7Coleridge COL0661 5.0 5.0 5.0 5.0 5.0 5.0 5.0 5.0 5.0 5.0 5.0Culverden CUL0331 4.9 4.9 4.9 4.9 4.9 4.9 4.9 4.9 4.9 4.9 4.9Hororata HOR0331 3.2 3.2 3.2 3.2 3.2 3.2 3.2 3.2 3.2 3.2 3.2Hororata HOR0661 3.4 3.4 3.4 3.4 3.4 3.4 3.4 3.4 3.4 3.4 3.4Islington ISL0331 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6Islington ISL0661 23.8 23.8 23.8 23.8 23.8 23.9 23.9 23.9 23.9 23.9 23.9Kaiapoi KAI0111 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2Middleton MLN0661 8.8 8.8 8.8 8.8 8.8 8.8 8.8 8.8 8.8 8.8 8.8Middleton MLN0662 8.8 8.8 8.8 8.8 8.8 8.8 8.8 8.8 8.8 8.8 8.8Southbrook SBK0331 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.54022013 Annual Planning Report © Transpower New Zealand Limited 2013.All rights reserved.

Appendix C: Fault LevelsGrid exit pointPoint ofservice2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023Springston SPN0331 8.3 8.3 8.3 8.3 8.3 8.3 8.3 8.3 8.3 8.3 8.3Springston SPN0661 5.1 5.1 5.1 5.1 5.1 5.1 5.1 5.1 5.1 5.1 5.1Waipara WPR0331 1.9 1.9 1.9 1.9 1.9 1.9 1.9 1.9 1.9 1.9 1.9Waipara WPR0661 7.7 7.7 7.7 7.7 7.7 7.7 7.7 7.7 7.7 7.7 7.7SOUTH CANTERBURYAlbury ABY0111 5.2 5.2 5.2 5.2 5.2 5.2 5.2 5.2 5.2 5.2 5.2Aviemore AVI2201 16.9 16.9 17.0 17.0 17.6 17.7 17.7 17.7 17.7 17.7 17.7Bells Pond BPD1101 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6Black Point BPT1101 2.1 2.1 2.2 2.2 2.2 2.2 2.2 2.2 2.2 2.2 2.2Oamaru OAM0331 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3 7.3Studholme STU0111 10.1 10.1 10.1 10.1 10.1 10.1 10.1 10.1 10.1 10.1 10.1Timaru TIM0111 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6Tekapo A TKA0111 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0Tekapo A TKA0331 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0Tekapo B TKB2201 11.8 11.8 11.8 11.8 11.8 11.8 11.8 11.8 11.8 11.8 11.8Temuka TMK0331 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8Twizel TWZ0331 9.2 9.2 9.2 9.2 9.2 9.2 9.2 9.2 9.2 9.2 9.2Waitaki WTK0111 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0Waitaki WTK0331 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8OTAGO-SOUTHLANDBalclutha BAL0331 4.4 4.4 4.2 4.2 4.2 4.2 4.2 4.2 4.2 4.2 4.2Brydone BDE0111 14.1 14.1 15.1 15.1 15.1 15.1 15.1 15.1 15.1 15.2 15.2Benmore BEN2201 22.0 22.0 22.1 22.1 22.2 22.2 22.2 22.2 22.2 22.2 22.2Berwick BWK1101 2.8 2.8 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7Cromwell CML0331 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0Clyde CYD0331 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1Clyde CYD2201 16.4 16.9 16.9 16.9 17.1 17.1 17.1 17.1 17.1 17.1 17.1Edendale EDN0331 7.3 7.3 7.8 7.8 7.8 7.8 7.8 7.8 7.8 7.9 7.9Frankton FKN0331 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2Gore GOR0331 7.4 7.4 9.0 9.0 9.0 9.0 9.0 9.0 9.0 9.1 9.1Halfway Bush HWB0331 19.2 19.2 19.4 19.4 19.4 19.4 19.4 19.4 19.4 19.6 19.6Halfway Bush HWB0332 14.4 14.4 14.6 14.6 14.6 14.6 14.6 14.6 14.6 14.7 14.7Invercargill INV0331 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0Manapouri MAN2201 14.1 14.1 14.2 14.2 14.3 14.3 14.3 14.3 14.3 14.4 14.4NorthMakarewaNMA0331 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2Naseby NSY0331 8.1 8.1 8.1 8.1 8.2 8.2 8.2 8.2 8.2 8.2 8.2Ohau A OHA2201 18.2 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3 18.3Ohau B OHB2201 20.9 20.9 20.9 20.9 21.0 21.0 21.0 21.0 21.0 21.0 21.0Ohau C OHC2201 18.2 18.2 18.2 18.2 18.3 18.3 18.3 18.3 18.3 18.3 18.3Palmerston PAL0331 1.9 1.9 1.9 1.9 1.9 1.9 1.9 1.9 1.9 1.9 1.9Roxburgh ROX1101 11.2 11.3 11.0 11.0 11.0 11.0 11.0 11.0 11.0 11.0 11.0Roxburgh ROX2201 15.4 15.8 15.8 15.8 16.1 16.1 16.1 16.1 16.1 16.2 16.22013 Annual Planning Report © Transpower New Zealand Limited 2013.All rights reserved. 403

Appendix C: Fault LevelsGrid exit pointPoint ofservice2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023South Dunedin SDN0331 16.8 16.8 17.0 17.0 17.1 17.1 17.1 17.1 17.1 17.2 17.2Tiwai TWI2201 8.1 8.1 8.0 8.0 8.1 8.1 8.1 8.1 8.1 8.2 8.24042013 Annual Planning Report © Transpower New Zealand Limited 2013.All rights reserved.

Appendix D: Project CalendarAppendix DProject CalendarTable D.1: Forecast submission dates for projects to the Commerce Commission for the next 2 June years (by quarter)Year Quarter 1 Quarter 2 Quarter 3 Quarter 42012/132013/14 Upper South Island grid upgrade – Stage 2Table D.2: Forecast submission dates for projects to the Commerce Commission post-2013/14YearProject2014/152015/162016/17To be advised HVDC link expansion Stage 3 – Pole 2 capacity upgrade 183Lower North Island transmission reinforcement 184Lower Waitaki transmission development 183Pakuranga–Whakamaru series compensation 183Upper North Island reactive support – post-NIGUP 184Reconductoring projects with enhancement opportunities (to be confirmed)183 Depends on the outcome assessment of benefits – may not proceed.184 Submssion date and project scope dependant on further investigations.2013 Annual Planning Report © Transpower New Zealand Limited 2013.All rights reserved. 405

Appendix D: Project CalendarTable D-3: Forecast commissioning dates and project statusForecastcommissioningyear (June year)ProjectProject statusCostband2013/14 Upgrade protection limits on Mangere supply transformer. Possible AResolve the protection limits on Edendale supply transformers. Possible ARecalibrate metering parameters on Invercargill supply transformers. Possible AResolving the protection constraints on Kopu supply transformers. Possible AResolve the protection limits on Te Awamutu supply transformers. Possible AResolve the 110/33 kV transformers' metering limits and 110/11 kV transformers' protection limit. Possible AClose 110 kV bus at Paraparaumu. Possible AUpgrade bus section and protection limits on Cambridge supply transformers. Committed (customer-specific) AIncreasing the rating of the two existing supply transformers at Te Kowhai. Committed (customer-specific) AReplace Redclyffe supply transformers with two 120 MVA units. Committed (customer-specific) CInstall new 220 kV cables between Pakuranga, Penrose and Albany. Committed GReplace existing Stoke supply transformers with two 120 MVA units. Committed CNorth Auckland and Northland project (NAaN). Committed GIncrease Rotorua 110/11 kV supply transformer capacity (commissioning year: 2013/14-2014/15). Committed BResolve protection limits and branch limiting components on Balclutha supply transformers (commissioning year:2013/14-2014/15).PossibleReplace the Stratford supply transformers with two 40 MVA units (commissioning years:2013/14-2014/15). Committed BALower South Island Reliability projects. The projects include:· Install special protection schemes on the 220 kV and 110 kV network.· Replace interconnecting transformers at Invercargill.· A new 220/110 kV interconnection at Gore.· Install capacitor banks at Balclutha.· Install a series capacitor on one of the North Makarewa–Three Mile Hill circuits (The series capacitor is deferred due toreduced load forecast. The need date will be reviewed in 2015.)Commissioning year: 2013/14-2015/16.Upgrade protection on Takanini supply transformer, and branch limiting component (commissioning years: 2013/14-2016/17).CommittedPossibleEA4062013 Annual Planning Report © Transpower New Zealand Limited 2013.All rights reserved.

Appendix D: Project CalendarForecastcommissioningyear (June year)ProjectProject statusCostbandUpper North Island reactive support – Stage 2 (commissioning year:2013/14-2016/17) Committed FNew grid exit point at Wairau Road. Committed (customer-specific) C2014/15 New substation at Hobson Street. Committed (customer-specific) DInstall a third 220/66 kV transformer at Ashburton. Committed (customer-specific) AInstall capacitors at Motueka. Preferred AReplace the Edendale supply transformers with two higher rated units. Possible BRecalibrate metering parameters on South Dunedin supply transformers. Possible AReplace Studholme supply transformers with higher rated units. Possible BReplace the existing Timaru supply transformers with three 47 MVA units. Committed (customer-specific) CIncrease Waitaki supply transformer’s capacity by adding fans and pumps to solve supply capacity issue. Possible AResolve metering parameter limit on Brunswick supply transformer. Possible AUpgrade protection equipment on Carrington Street supply transformers. Possible AUpgrade the branch limiting components on the Carrington Street supply transformers. Possible AResolve the metering and protection limits Opunake supply transformers. Possible AHawera bus refurbishment. Proposed ANew grid exit point at Putaruru. Possible CReplace 110/33 kV transformers with 120 MVA units. Possible CInstall a third transformer on a third bus section at Ashburton to mitigate Ashburton 220/66 kV loss of load. Committed (customer-specific) CReplace the existing Bunnythorpe interconnecting transformers with higher rated units (commissioning year 2014/15-2016/17).PossibleInstall reactive support at Oamaru (commissioning year 2014/15-2016/18). Possible AInstall capacitors along the Valley Spur or within the distribution network (commissioning year 2014/15-2016/18). Possible AReplace the Waitaki interconnecting transformers with higher rated units. The need will depend on the preferred optionform the Lower Waitaki Valley Reliability investigation (commissioning year 2014/15-2018/19).Proposed2015/16 Upper South Island grid upgrade - Stage 1: a sixth bus coupler at Islington. Committed AInstall a third 220/33 kV supply transformer at Hamilton. Possible ABB2013 Annual Planning Report © Transpower New Zealand Limited 2013.All rights reserved. 407

Appendix D: Project CalendarForecastcommissioningyear (June year)ProjectProject statusCostbandA new 110 kV transmission circuit from Hangatiki to Te Awamutu Possible DSupply Paraparaumu from 220 kV line or install additional supply transformer at Paraparaumu, supplied from Mangahao. Possible DInstall a third Wilton 110 kV bus section (commissioning year: 2015/16-2016/17). Committed TBAInstall a 110 kV bus and bus circuit breaker and West Wind (commissioning year: 2015/16-2016/17). Possible TBAReplace the supply transformers at Waihou with higher rated units (commissioning year: 2015/16-2017/18). Possible BReconductor the Bunnythorpe–Woodville circuits with higher rated conductors, or convert the Bunnythorpe–Woodvillecircuits to 220 kV operation (commissioning year: 2015/16-2020/21).PossibleInstall reactive support at Hawera (commissioning year: 2015/16-2020/21). Possible AReconductoring the110 kV Bunnythorpe–Woodville with higher rated conductor or upgrade the existing SPS(commissioning year: 2015/16-2020/21).Install a 5th regional 220/110 kV 250 MVA interconnecting transformer. Possible sites are Wilton and Haywards(commissioning year: 2015/16-2020/21).Replace the existing supply transformers at Waikino and Waihou with on-load tap changers (commissioning year:2015/16-2022/23).PossiblePossibleProposed2016/17 Upgrade protection limit on Edgecumbe supply transformer Possible AReplace the Kinleith 20 MVA supply transformer with a 40 MVA unit. Possible AReplace the existing Ashley 66/11 kV transformers with two 40 MVA units. Possible AInstall a higher rated supply transformer at Ohakune. Possible AA new grid exit point near Riwaka. Preferred CSplitting Huapai 220 kV bus once the NAaN project is completed. Possible AReplace two 110/33 kV transformer at Halfway Bush with one 220/33 kV 120 MVA unit. Proposed TBAResolve protection limits on Oamaru supply transformers. Possible CConstruct a new Hamilton–Waihou or upgrade existing Hamilton–Piako circuits. Possible C or DReplace existing transformers with two 110/33/11 kV 60 MVA supply transformers. Possible CResolve protection and metering limits on Upper Hutt supply transformer. Proposed AReplacing the transformers with two 110/33/11 kV banks will provide bus security. Possible TBATBATBATBAC4082013 Annual Planning Report © Transpower New Zealand Limited 2013.All rights reserved.

Appendix D: Project CalendarForecastcommissioningyear (June year)ProjectProject statusCostbandReplace the existing Wanganui supply transformers with two 40 MVA units (commissioning year: 2016/17-2017/18). Committed BIncrease the existing transformers capacity. Three options are currently under review (commissioning year: 2016/17-2018/19).PossibleReplace the two 110/33 kV transformers with one 220/33 kV transformer (commissioning year: 2016/17-2025/26). Proposed TBAClose the 33 kV bus split (commissioning year: 2016/17-2025/26). Proposed TBA2017/18 Resolve the metering and protection limits on the Waipawa 110/33 kV transformers. Possible AThermally upgrade, or reconductor part or all of both Gisborne–Tuai circuits. Possible TBAReplace the existing transformers with two 40 MVA units. Possible BAdditional voltage support at Kaitaia or Maungatapere (commissioning year: 2017/18-2018/19). Possible BInstall a second Brunswick supply transformer (commissioning years: 2017/18-2019/20). Possible BInstall a second transformer at (or near) New Plymouth (commissioning year: 2017/18-2022/23). Possible B2018/19 Resolving the protection constraints at Wiri will delay the overload until 2021. Possible AUpper South Island Grid Upgrade - Stage 2: install additional shunt reactive support around Islington and Bromley or busthe existing circuits between Waitaki Valley and Islington where they converge near Orari.PossibleRecalibrate Gisborne supply transformers’ metering parameters. Proposed AResolve protection and metering limits on Maungaturoto supply transformers. Possible AReplace 220/33 kV North Makarewa supply transformers with two 220/66 kV units. Possible TBAInstalling a third supply transformer at Te Kowhai. Possible CInstall a second 220/110 kV, 250 MVA interconnecting transformer in Wellington region. Possible BA new grid exit point at Ashburton. Possible CReplace the existing 30 MVA supply transformer at Fernhill with an 80 MVA unit (commissioning year: 2018/19-2020/21). Possible BTBADReplace the existing Naseby supply transformers with two higher rated units (commissioning year: 2018/19-2020/21). Possible BIncrease Timaru 220/110 kV interconnecting transformer capacity (commissioning year: 2018/19-2020/21). Possible C2019/20 Replace Kawerau–T1 and T2 transformers with higher rated units. Proposed TBAReplace the two Bromley 220/66 kV transformers with two 150 MVA OLTC transformers. Possible B2013 Annual Planning Report © Transpower New Zealand Limited 2013.All rights reserved. 409

Appendix D: Project CalendarForecastcommissioningyear (June year)ProjectProject statusCostband2020/21Establish a new 220/66 kV grid exit point south of Christchurch. Possible CReplace existing Huirangi supply transformers with two 50 MVA units (commissioning year: 2019/20-2021/22). Possible BIn the long term, issue is resolved, by limiting the Wiri peak load to the transformer capacity or replace existingtransformers with higher rated units.PossibleA new grid exit point at Brightwater. Possible CThermally upgrade or reconductor the line Hayward–Melling circuits. Possible TBAUpgrade the Pauatahanui supply transformer capacity. Possible BSupply Paraparaumu load from 220 kV line or reconductor Pauatahanui–Takapu Road circuit section. Possible CImplement the Kawaka bonding project. Possible CAdditional voltage supports at Kaitaia or Maungatapere, system split, or thermally upgrade the Henderson–Wellsfordcircuits.PossibleThermally upgrade the Kikiwa–Stoke 110 kV circuit. Possible AIncrease the supply transformers’ capacity at Waikino (commissioning year: 2020/21-2022/23). Possible B2021/22 In the short term, resolve the constraint on the terminal spans at Otahuhu and Penrose substations. Possible AReconfigure the Otahuhu 110 kV bus to swap the Mangere–Otahuhu–1 and Otahuhu–Roskill–2 circuits on the bus. Possible TBAResolve protection limits and upgrade branch limiting components on Cromwell supply transformers (commissioning year:2021/22-2025/26).2022/23 Upper North Island reactive support – Post-NIGUP Possible EPossibleThermally upgrade the Cromwell–Frankton circuits. Possible TBAResolve protection and metering limits on Tekapo A supply transformer. Possible AThermally upgrade the Inangahua–Murchison –Kikiwa circuit, or a special protection scheme to trip load postcontingency.Install Special protection scheme, or Kinleith 110 kV bus reconfiguration, or reconductor Arapuni–Kinleith–1 circuit(commissioning year: 2022/23-2028/29).2023/24 Resolve metering limits on Marton supply transformers. Possible APossiblePossibleResolve the metering limit on the Woodville 110/11 kV transformers. Possible AResolve protection and circuit breaker limits on Albany supply transformers. Possible ABTBAAAA4102013 Annual Planning Report © Transpower New Zealand Limited 2013.All rights reserved.

Appendix D: Project CalendarForecastcommissioningyear (June year)ProjectProject statusCostband2024/25Replace limiting switchgear on the Henderson–T1 if required. Possible AInstall a 3 rd 220/110 kV transformer at Marsden, and convert the 220 kV and 110 kV buses to three zones. Possible BReplace the existing supply transformers at Kopu with two higher capacity units. Possible BResolve the station equipment constraints on Stoke 220/110 kV interconnecting transformer (commissioning year:2023/24-2028/29).Automatically split the 110 kV network between Henderson and Maungatapere or thermal upgrade the Henderson–Wellsford circuits.PossiblePossibleResolve metering limits on Silverdale supply transformers. Possible AIncrease the protection and metering limits on Frankton–T4 transformer. Possible AIncrease Frankton–T2A and T2B supply transformers’ capacities by adding pumps. Possible AUpgrade Dobson supply transformer protection to defer the issue beyond the forecast period. Possible AInstall a bus coupler at Upper Hutt. Possible TBAInstall capacitor at Masterton Possible TBA2025/26 Install a new 220/110 kV interconnecting transformer at Hamilton. Possible BThere are a number of network developments in Auckland region that are likely to influence the severity and timing of thisissue. Transpower will monitor this issue as these developments take place.2026/27 A new interconnecting transformer at Kaitimako. Possible B2027/28PossibleReplace Halfway Bush 220/33 kV transformer with one 120 MVA unit. Proposed TBAA new interconnecting transformer at Kaitimako will resolve the overloading issue. Possible BInstall additional capacitors, or a special protection scheme to trip load post contingency, or replace Kikiwa–T1 with ahigher rated unit to resolve West Coast low voltage issue.2028/29 Resolve LV cable limit on Gracefield transformer. Possible CTo be advised Install capacitor to resolve the overloading issue at Gisborne Possible APossibleInstall bus circuit breakers and bus reconfiguration. Possible TBAInstall bus circuit breakers at Southdown. Possible TBAMost options to address the Otahuhu-Wiri 110 kV transmission capacity or Wiri supply transformer capacity will alsoaddress this issue.PossibleACTBAATBA2013 Annual Planning Report © Transpower New Zealand Limited 2013.All rights reserved. 411

Appendix D: Project CalendarForecastcommissioningyear (June year)ProjectProject statusCostbandBus reconfiguration at Hamilton. Possible TBANew GXP at Putaruru Possible TBAInstall bus circuit breakers at Kopu. Possible TBAA second Hangatiki–Te Awamutu circuit and install bus circuit breaker at Te Awamutu. Possible TBAWaihou 110 kV bus will need to be substantively rebuilt based on condition assessment in about five years. Transpowerwill investigate upgrading the bus security in conjunction with the rebuild.PossibleInstall bus circuit breaker and bus reconfiguration at Waikino. Possible TBAInstall additional supply transformer at Whakamaru. Possible TBAInstall bus circuit breakers at Atiamuri. Possible TBAIssue can be resolved by installing bus circuit breakers at Karapiro. Possible TBAReconductor Maraetai–Whakamaru circuit and install bus circuit breaker. Possible TBAInstall additional transformer at Mokai. Possible TBAOhakuri bus reconfiguration and additional bus circuit breakers. Possible TBAA second Maraetai–Waipapa circuit. Possible TBAEdgecumbe bus reconfiguration and install bus circuit breakers. Possible TBAReconfigure Kawerau bus. Possible TBAInstall bus circuit breakers at Owhata. Possible TBAReconfigure Rotorua bus in conjunction with supply transformer replacement. Possible TBAInstall bus circuit breaker at Tauranga 11 kV and 33 kV bus. Possible TBAReconfigure Te Kaha bus and install bus circuit breaker. Possible TBAReconfigure Waiotahi bus and install bus circuit breaker. Possible TBAReconfigure Matahina bus and install bus circuit breaker. Possible TBAIssue can be resolved by installing transformer circuit breaker on Tokaanu–T22. Possible TBAIssue can be resolved by a second Aratiatia–Wairaki circuit. Possible TBAInstall bus circuit breakers at Nga Awa Purau. Possible TBATBA4122013 Annual Planning Report © Transpower New Zealand Limited 2013.All rights reserved.

Appendix D: Project CalendarForecastcommissioningyear (June year)ProjectProject statusCostbandInstall bus circuit breakers at Ngatamariki. Possible TBAInstall bus circuit breakers at Rangipo. Possible TBAReconfigure Wairakei bus and install bus circuit breakers. Possible TBAUpgrade Kapuni to a ‘double tee’ connection. To be advised TBAInstall bus circuit breaker at Gisborne. To be advised TBAInstall a second supply transformer at Tuai. To be advised TBAInstall fault limiting reactor at Kaiwharawhara and transfer load to other grid exit points. Possible TBAInstall a second Stoke 110/66 kV transformer and bus circuit breaker. To be advised TBAInstall bus circuit breakers at Cobb. To be advised TBAInstall fault limiting reactor so that the two Kikiwa transformers can operated in parallel. To be advised TBAReactive support at Bromley. Possible TBAInstall line circuit breakers, a second Albury–Timaru circuit, and a second transformer at Albury. To be advised TBAInstall a second circuit to Timaru, via Albury, and second supply transformer at Tekapo A. To be advised TBAInstall line circuit breakers, a second Albury–Timaru circuit, and a second supply transformer at Opuha. To be advised TBAInstall a bus circuit breaker at Balclutha. To be advised TBAInstall bus circuit breaker Brydone. To be advised TBAInstall second transformer and bus circuit breaker at Halfway Bush. To be advised TBAConstruct a new grid exit point at Papamoa. Possible BReplace Otahuhu–T2 & T4 with higher impedance transformers, or upgrade the Otahuhu–Penrose circuit capacity. Possible CLimit the peak load at Otahuhu to the transformer capacity, or add a third supply transformer, or replace with existingtransformers with higher rated units.PossibleBTranspower is investigating several options to resolve Otahuhu–Wiri 110 kV transmission capacity. Options include:• A new cable from Otahuhu connecting to a new 110/33 kV transformer at Wiri.• A new 110/33 kV transformer at Otahuhu and a new 33 kV cable to Wiri• Reconductor Otahuhu–Wiri circuit, or• A new 220/110 kV connection at Bombay and supply Wiri from here and a 110 kV bus at Wiri.PossibleCRe-tune generator excitation systems and/or install power system stabilisers. To be advised TBA2013 Annual Planning Report © Transpower New Zealand Limited 2013.All rights reserved. 413

Appendix D: Project CalendarForecastcommissioningyear (June year)ProjectProject statusCostbandTranspower is investigating several options to resolve Upper South Island transmission capacity. Options include:· A new transmission line to Ashburton or Islington, or· an HVDC tap-off from the existing line north of Christchurch.To be advisedTBAReplace Edgecumbe supply transformers with higher rated units. Possible CThermally upgrade the Rotorua–Tarukenga circuits. Possible AInstall a new supply transformer at Tarukenga. Possible TBAResolve Tauranga 11 kV supply transformers’ low voltage cable limit and protection limit. Possible AReplace the existing transformers with two higher rated units. Possible BInstall a fourth 220/66 kV interconnecting transformer at Islington. Possible BInstall 11 kV capacitors at the Bromley transformer’s tertiary winding. Possible AIncreasing the existing Culverden supply transformers capacity and changing the operating voltage to 220/66 kVtransformers,PossibleTransfer load from Southbrook 33 kV to 66 kV bus by establishing two new 66 kV feeders from Southbrook. Possible TBAInstall either series reactors or reconductoring Bunnythorpe–Mataroa 110 kV circuit. Possible AInstall a second 110/66 kV interconnecting transformer at Stoke. Preferred AInstall a third supply transformer at Henderson Possible BThermally upgrade 110 kV Kaikohe–Maungatapere circuits. Possible TBAReplace the Kensington supply transformers with higher rated units and upgrade the 33 kV switchboard. Possible TBAResolve protection and metering limits on Wellsford supply transformers. Possible AReplace Gore supply transformers with two higher rated units. Possible BClose Halfway Bush 33 kV bus. Possible TBAA new grid exit point near St Andrews. Possible CInstall a second supply transformer at Waitaki to resolve the security issue. Possible ABuilding a 110 kV bus at Bells Pond, connection to the other 110 kV circuit, and a new grid exit point. Possible TBAA new grid exit point at Livingstone (several options are being investigated as part of the Lower Waitaki Valley Reliabilityproject).PossibleInstall a new 120 MVA transformer at Temuka and upgrade 110 kV Timaru–Temuka circuits. Possible B andTBAD4142013 Annual Planning Report © Transpower New Zealand Limited 2013.All rights reserved.

Appendix D: Project CalendarForecastcommissioningyear (June year)ProjectProject statusCostbandCReplace the 30 MVA with a 60 MVA unit at Hinuera. Possible AIncrease Takapu Road supply transformer capacity. Possible BReplace Kikiwa–T1 with 150 MVA unit. Possible BAt Marsden install a 3 rd 220/110 kV transformer, and convert the 220 kV and 110 kV buses to three zones. Possible TBAInstall bus circuit breakers and bus reconfiguration. Possible TBAFor Hangatiki 110 kV bus outage: install bus circuit breaker at Hangatiki.For Arapuni North 110 kV bus outage: issue will be resolved following the replacement of the Tarukenga interconnectingtransformers (Bay of Plenty region) and reconfiguring the Arapuni bus so the two circuits from Hangatiki connect toseparate bus sections.Possible option to resolve Hamilton low voltage includes:· reactive support in the Waikato 110 kV, and· a third 220 kV connection to Hamilton.PossibleTo be advisedTBATBAInstall bus circuit breakers at Mount Maunganui. Possible TBAA second supply transformer at Tarukenga. Possible AInstall bus circuit breaker at Te Matai. To be advised TBAInstall bus circuit breaker at Dannevirke. Possible TBAInstall bus circuit breaker at Mangamaire. Possible TBAInstall bus zone protection at Wanganui. Possible TBAInstalling bus circuit breakers, and supply transformer at Mataroa. Possible TBAInstalling bus circuit breakers, and supply transformer at Ohakune. Possible TBAInstalling bus circuit breakers, and supply transformer at Ongarue. Possible TBAInstall bus circuit breakers at Waipawa. Possible TBAInstall bus circuit breakers at Woodville. Possible TBAInstall bus circuit breakers, and second 110 kV connection to Te Apiti. Possible TBARearranging the bus connections at Bunnythorpe and/or installing a fourth 220 kV bus coupler at Bunnythorpe. Possible TBAUpgrade protection at Hawera. To be advised TBA2013 Annual Planning Report © Transpower New Zealand Limited 2013.All rights reserved. 415

Appendix D: Project CalendarForecastcommissioningyear (June year)ProjectProject statusCostbandInstall 110 kV bus circuit breaker at New Plymouth. To be advised TBAInstall bus circuit breakers at Wanganui. To be advised TBAInstall a bus circuit breakers, and second supply transformer at Waverley. Possible TBAUpgrade protection at Hawera, and a second feeder to Patea. To be advised TBAReconfigure Whareroa bus and upgrade protection at Hawera. To be advised TBAInstall bus circuit breaker at Fernhill. To be advised TBAInstall bus circuit breaker at Whirinaki. To be advised TBAInstall bus circuit breaker at Masterton. Possible TBAInstall bus circuit breaker at Upper Hutt. Possible TBAReconfigure Blenheim bus and/or additional bus circuit breakers. To be advised TBAInstall line circuit breakers Argyle. To be advised TBAReplace Kikiwa–T1 interconnecting transformer and install bus circuit breaker. Possible TBAInstall a line circuit breakers, and second supply transformer at Arthur's Pass. To be advised TBAInstall a second feeder, and bus circuit breaker at Atarau. To be advised TBAInstall a line circuit breakers, and second supply transformer and Castle Hill. To be advised TBAInstall a bus circuit breaker Dobson. To be advised TBAInstall a line circuit breakers, and second supply transformer at Murchison. To be advised TBAInstall a line circuit breakers, and second supply transformer at Otira. To be advised TBAInstall bus circuit breaker at Inangahua. To be advised TBAInstall bus circuit breaker at Ashley. To be advised TBAInstall line circuit breakers, and second supply transformer at Coleridge. Possible TBAInstall line circuit breakers, and reactive support at Hororata. Possible TBAInstall a bus circuit breaker at Southbrook, and a bus circuit breaker at Kaiapoi. Possible TBAInstall a bus circuit breaker at Southbrook. Possible TBAInstall a bus circuit breakers, and second supply transformer and second feeder at Waipara. Possible TBA4162013 Annual Planning Report © Transpower New Zealand Limited 2013.All rights reserved.

Appendix D: Project CalendarForecastcommissioningyear (June year)ProjectProject statusCostbandInstall bus circuit breaker at Coleridge. Possible TBAReconfigure Studholme bus and install bus circuit breaker. To be advised TBAConvert Timaru 110 kV bus to three zones and additional bus circuit breaker. Possible TBAConvert Timaru 110 kV bus to three zones and Timaru supply transformer upgrade. Committed TBAInstall bus circuit breaker at Edendale. To be advised TBAInstall bus circuit breaker at Gore. To be advised TBA2013 Annual Planning Report © Transpower New Zealand Limited 2013.All rights reserved. 417

Appendix E: Investment Approvals ProcessAppendix ETranspower’s Investment Approvals Process(IAP)E.1Purpose of the Investment Approvals ProcessThe Investment Approvals Process (IAP) is the decision-making framework forpreparing investment proposals. It is a robust and replicable process, adaptable tothe range of investment situations that arise: large and small value proposals withmany or few options to investigate. The output is a high quality investment proposalfor approval by the Commerce Commission or a Customer. Transpower’s Board andstakeholders can be confident that the investment and delivery decisions are drivenby a verified need and are efficient, appropriate and defensible.There are two approval routes:Regulatory approval of proposals for investment in interconnection assets allowsTranspower to add the assets to its regulated asset base (RAB) and to recovercosts via the Transmission Pricing Methodology (TPM), andInvestment in connection assets which are paid for by customers are not addedto Transpower’s regulated asset base. The exception to this, which has not yetever occurred, is where investment in connection assets is required to meet GRSand is approved by the Commerce Commission via a Major Capex proposal.E.2IAP FrameworkThe Framework consists of five stages with generic actions occurring through each(outlined in Figure 1). Specific actions are required according to the rules 185 forinvestment in interconnection assets and rules for investment in connection assets,e.g. proposals that require individual Regulator approval (for investment ininterconnection assets) must comply with rules for consultation and methodology foreconomic analysis.NeedOptionsIdentificationOptionsAnalysisProposalTransition toDelivery185 Relevant rules as at March 2012 are those in Part 12 Electricity Industry Participation Code 2010and Capex Input Methodology 2012.4182013 Annual Planning Report © Transpower New Zealand Limited 2013.All rights reserved.

Appendix E: Investment Approvals ProcessOutline of IAP StagesNeedNeeds are identified through Annual Planning Report process, includingconsultation with Customers.Each need is investigated and verified as an investment case.OptionsIdentificationInterconnectionA range of investment options isconsidered, including possible nontransmissionsolutionsConsultation on need, approach,assumptions, long list options; andrequest additional information, throughconsultation document and/orStakeholder forum.The long list options are refined to a setof credible options, using specific criteria(high-level cost, feasibility, GEIP).ConnectionTP produces a High LevelResponse for investment options,taking into account Customerneed.Costs and benefits are assessed under the regulated cost/benefit test (theInvestment Test) with analysis commensurate with the likely investment cost.OptionsAnalysisA short-list of investments options isidentified from economic, technical andfeasibility analysis of credible options.Decision rule for proposed investment isbased on maximum net benefits or leastnet cost (depending on whetherinvestment is to meet the Grid ReliabilityStandards and / or to create net benefitsto the market).Customer decides on preferred optionand signs a contract for detailed studydesign.TP must assess any implications forthe Grid Reliability Standards (GRS)arising from the investment.Both TP and Customers haverequirements under the Codedepending on the GRS assessment.ProposalInvestment option confirmedincluding through feedback fromstakeholders on short list options and/orpreferred option.Investment proposal submitted toCommerce Commission.Investment option confirmedand Transpower and theCustomer enter into anInvestment Contract.Transition toDeliveryThe approved investment enters a detailed design (equipment and placement)stage and approvals processes under the RMA are undertakenConsultation continues within communities affected by ensuing works.2013 Annual Planning Report © Transpower New Zealand Limited 2013.All rights reserved. 419

Appendix F: Grid Support ContractsAppendix FGrid Support ContractsF.1BackgroundFollowing the 2007 - 2008 demand-side participation trials and the consideration ofthe many complex issues and trade-offs involved, Transpower designed a gridsupport contract (GSC) product incorporating feedback from its industry consultationprocess.Transpower has introduced grid support contracts (GSCs) to enable it to contract withproponents of non-transmission options to augment or substitute for grid capacity inspecific circumstances.F.2Use of GSCsGSCs as a risk management toolTranspower has significant concerns over the risk to reliability of supply frominsufficient transmission capacity that could arise from:delayed build of new transmission assets - whether for reasons of regulatoryapproval, obtaining consents under the RMA, acquiring property, or due tocompetition in world markets for transmission assets and expertisehigher demand growth than was forecast at the time of investment decision,which would bring forward the need date, ormajor asset failure - which is a growing concern given the age of Transpower’sasset base.GSCs are designed to provide a useful product as part of a toolbox of approaches tomanaging such risks.GSCs as a transmission deferral toolGSCs may also be used to contract for products that can defer transmissioninvestments where there is genuine option value in deferring an investment decision.Where such option values do not exist, Transpower would not propose using GSCs topush investment to the very edge of modelled ‘just in time’ limits. There are hugeasymmetries of risk, with transmission ‘better a year early than a day late’. Critically,to plan to use GSCs for deferring an investment in this way would remove theiradvantage as an insurance against the delivery risks outlined above.F.3Key parametersKey parameters of Transpower’s GSC product design include the following:GSCs will be specific to transmission capacity problems and offered only forspecific regions and periods when these are occurring or are forecast to occur.Transpower will not pick winners or losers: Transpower will identify a need, apotential provider may propose a commercial solution to the need, andTranspower will decide whether or not to offer a GSC for that proposal.To encourage innovation in non-transmission solutions, GSCs will be open to allnon-transmission options, but with clear qualification and evaluation criteria toensure reliability.To encourage competition in procurement, GSCs will be offered to successfultenders through a full request for proposal (RFP) process: qualification andevaluation criteria will be applied.4202013 Annual Planning Report © Transpower New Zealand Limited 2013.All rights reserved.

Appendix F: Grid Support ContractsGSCs will be contracts for services, not for Transpower ownership. Transpowerwill offer them in its capacity as grid owner. For those GSCs that require to becalled or dispatched, this will be done by the System Operator on behalf of thegrid owner.As cost recovery will be through the transmission pricing methodology (TPM),approval of the GSCs will be required from the Commerce Commission. GSCs willbe offered only as part of major capex investment proposals.F.4Design issuesWe have concerns about some specific issues around GSC design and operation andthe GSC product on offer is intended to minimise these risks. Our main concern ishow to obtain the benefits possible from GSCs without:compromising reliabilitysignificant interference in the wholesale electricity marketsignificant distortions in electricity generation investment incentives, orTranspower becoming relied on for energy as well as transmission capacityprovision.ReliabilityHistorically, the transmission grid was developed to link previously unconnectedregions to provide greater levels of reliability through access to more generationresources. While initially undertaken for energy transport reasons, more recentlyinvestment has been for market efficiency too.Using GSCs to maintain reliability therefore requires them to be highly reliable.It is unrealistic to expect local generation or demand-side response to be able toachieve transmission levels of reliability. Rather, a reliability level of around 99% to99.9% may be achievable, which may be adequate if exposure to these lowerreliability levels is limited to system peaks for limited periods. Using these options itmust be appreciated that reliability may decline, but the options still add value as arisk management tool. Even lower levels of reliability, or prolonged exposure to suchlevels, would in Transpower’s view not be acceptable for the backbone,interconnected grid.A key issue in GSC design and operation is therefore ensuring that appropriatereliability criteria are set for proponents wishing to enter into GSCs.Market distortionA significant issue for our GSC design process is to what extent the use of GSCscould distort existing markets, in particular the wholesale generation investment andoperations market. The wholesale electricity market is a multi-billion dollar perannum market, whereas the GSC market is likely to be in the order of some tens ofmillions per annum at most. Designing and operating GSCs to minimise interferencein the wholesale market is essential.F.5Forms of GSCThe design encompasses three forms of GSC:Demand-side participation (DSP), including non-market generationTranspower has trialled small aggregated DSP in its 2007 Pilot and 2008 Trial. Thesedemonstrated that, under certain conditions, blocks of aggregated small DSP sourcescan be made reliable. Significant issues arose in forecasting the time and size of2013 Annual Planning Report © Transpower New Zealand Limited 2013.All rights reserved. 421

Appendix F: Grid Support Contractsneed sufficiently accurately at the time of call. Transpower is investigatingimprovements to the load forecasting processes and also the criteria for callingDemand Response as a means to address the issues identified at the time of thosetrials. A Demand-side participation GSC may include a variety of Demand Response(DR) resources, including aggregated blocks of multiple small DR resources, blocksmade up of single load, and in principle, non-market generation sources (although thelatter are likely to be part of an aggregated block). Blocks would be called individuallyby the System Operator in accordance with instructions from Transpower as gridowner reflecting the contract terms. Blocks would be expected to deliver thecontracted capacity: their reliability would be a paramount consideration in thedesign, procurement and operation of this form of GSC. Blocks would either becalled ahead of time using a Demand Response Management System (DRMS), or beoperated automatically post-contingency.Voltage supportTranspower will use GSCs for contracting for voltage support over medium to longterm planning horizons. They have in effect replaced the voltage support ancillaryservice contracts over these timeframes. This provides improved integration in gridplanning, as the grid planner can better ‘co-optimise’ real and reactive power issuesand transmission and non-transmission reactive support options, over planninghorizons from technical, good electricity industry practice and economic perspectives.In particular, the grid planner can test and contract for the availability and cost offuture voltage support, rather than simply assume that this will be the eventualoutcome of ancillary service voltage support contracts. Cost allocation inconsequence has changed from zonal under Part 8 of the Electricity IndustryParticipation Code to national under the Part 12 transmission pricing methodology,aligning cost allocation for transmission and non-transmission reactive supportsolutions. The System Operator may still procure contracts of a short-term nature tocover for unanticipated reactive power requirements.Market generationFor market generation, avoiding interference in the operational market is paramount.GSCs will not be offered to define how generators would offer real power into themarket, whether in time, quantity or price. Rather, GSCs will be limited tocontributions to capital or other fixed ‘up front’ costs. In effect, GSCs will be used tobuy certainty over a particular generator’s development path – be it for example intime, equipment or location – to allow transmission to be safely designed around it.Proponents will be required to demonstrate that they are sufficiently committed to beable to deliver and that their contract price is a fair and reasonable reflection of actualcost. GSCs will be offered only to address transmission adequacy issues, and hencenot to address any actual or forecast national shortfalls in generation capacity.F.6Process for offering GSCsAs GSCs are specific to transmission capacity problems, GSCs will be offered only aspart of a reliability investment proposal for assets on the interconnected grid. Thus,GSCs will become a routine part of Transpower’s grid planning process. Where thereis a proponent of a non-transmission option (identified through Transpower’s RFIand/or RFP process) that meets the GSC qualification and evaluation criteria, theoption will become part of the preferred option that is submitted as an investmentproposal under a GUP.The diagram on the next page illustrates how GSCs are integrated into the gridplanning process.4222013 Annual Planning Report © Transpower New Zealand Limited 2013.All rights reserved.

Appendix F: Grid Support ContractsF.7Updates and further informationIn 2011, Transpower released a request for proposal for the procurement of 60 MWof demand-side response in the Upper North Island. No demand response wasprocured through this process, due to the offers being deemed uneconomic as atransmission deferral option for Upper North Island.A key finding from the tender process was that demand response needs to beestablished if it is to be an economic transmission deferral product. Requiringproponents to provide adequate demand response within a condensed timeframe andfor a relatively short contract period only drives prices upward. Reliability demandresponse needs to be established as a sustained programme and not as a reactive“just in time” measure.Transpower has re-scoped the Upper North Island Demand Side Initiatives (UNI DSI)project to investigate whether reliable demand response can be delivered ateconomic cost. The re-scoped project builds on what Transpower learnt during thetender process in 2011. The project includes implementing a pilot which will:test a demand response management system for effective dispatch of demandresponse.assess whether the management system reduces barriers to entry for differenttypes of demand response.discover the economic price points for different types of demand response.determine whether a sustainable demand response programme can beestablished.The implementation of the pilot will be conducted over a number of months, with areview at each stage.It is anticipated that the GSC product will be progressively refined with experience.The design details of the offered product may therefore differ slightly from thoseoutlined above.More information about UNI DSI can be found at:https://www.transpower.co.nz/projects/upper-north-island-reactive-supportproject/upper-north-island-demand-side-initiatives-02013 Annual Planning Report © Transpower New Zealand Limited 2013.All rights reserved. 423

Appendix F: Grid Support ContractsInvestmentApproval ProcessNeedProjectassumptionsRFIOptionsIdentificationTransmission& transmissionalternativesLong-listRFPShort-listOptionsAnalysisConsultationdocumentProposalMCPCC’s noticeof intentionTransition toDeliveryCC’s finaldecisionIntegration of Grid Support Contractsfor transmission alternativesIdentificationAPR withGRR, GEIRLong term plans for thegrid assist potentialproponents oftransmission alternativesto develop conceptIndustry responsesto RFIEvaluate industryresponses to RFIIndustry responsesto RFPEvaluate industryresponses to RFPEvaluationTranspower issues an RFPif there could be practicaltransmission alternatives.Transpower short listsproposals that meetqualification criteria andhave technical, economicand commercial merit.QualificationcriteriaAgree technical andcommercial termsContract signedconditional onCC approvalProcurementIf a short-listedtransmission alternativebecomes the preferredsolution, or is part of thesolution, a conditionalcontract is negotiated.StandardContractApprovalGrid SupportContractTranspower ensures thatcosts can be recoveredunder the Code and underthe Commerce ActQualification criteriaTo ensure reliabilityrequirements, minimise marketdistortion and managecommercial risk to Transpower:CapacityOperating ConditionsReliabilityDegree of CommitmentRange of ServicesPrudential requirementsStandard contractOperating criteriaPerformance and testingProof of complianceInterface with other marketsPenalty provisionsFees and pricing structureOther standard contractualterms4242013 Annual Planning Report © Transpower New Zealand Limited 2013.All rights reserved.

Appendix G: Generation ScenariosAppendix GGeneration ScenariosThis section details the timing, type, location and size of new generators assumed ineach of the generation scenarios.The scenarios range from being renewable to being more thermally oriented.The generation scenarios assume specific points of connection for new modelledgenerators. The choice of connection point is often arbitrary, but required in order toeffectively model future transmission grids. Changes to these connection points maybe necessary when testing proposed transmission investment into a region.G.1Scenario 1: Sustainable PathThe major features of the Sustainable Path scenario are:Carbon charges and gas prices are both very high. As a result, renewable energyproduction exceeds 90% of total generation (on average) from 2020 onwards.Major development of renewable generation takes place in both North and SouthIslands. By 2028, geothermal capacity has reached 1500 MW, wind capacityexceeds 3,100 MW, and 850 MW of new hydro has been constructed.Tidal and wave energy, distributed solar power, and biomass cogeneration alsofeature.Baseload thermal generation is largely phased out, with all four Huntly coal-firedunits, Otahuhu B and Taranaki CC decommissioned by 2025.Thermal peaking plants are required in order to balance intermittent generation,provide dry-year swing, and supply reliable capacity to meet peak demand. By2028, over 1,300 MW of thermal peakers are available.Interruptible load (IL) and price-responsive demand, driven by advancedmetering, time-of-use tariffs, and other initiatives, have an important role to playin balancing intermittent generation and meeting peak demand.2013 Annual Planning Report © Transpower New Zealand Limited 2013.All rights reserved. 425

MWAppendix G: Generation ScenariosThe extent of demand-side management, however, is substantially less than wasassumed in the 2010 Statement of Opportunities (and hence the last APR). Thetotal (firm) demand-side management capacity increases by 350 MW between2012 and 2028.14000Installed capacity by technology - Sustainable path (mds1)12000WindWaveTidal10000SolarCogeneration, otherOpen cycle gas turbine - gasInterruptible load8000Coal, IGCC w ith CCSHydro, schedulableHydro, run of riverHydro, peaking6000Hydro, pumped storageGeothermalPeaker, fast start gas-fired peakerCogeneration, gas-fired4000Peaker, diesel-fired OCGTPrice-responsive load curtailmentCoalCombined cycle gas turbine2000Cogeneration, biomass-fired02012 2014 2016 2018 2020 2022 2024 2026 2028YearProjects and commission dates – Sustainable Path scenarioYear Plant description Technology description CapacityMWSubstation(approx)2013 Huntly coal unit 1 Coal 0 (Decomm.)Huntly2013 Wairakei Geothermal 0 (Decomm.)Wairakei2013 Kawerau Norske Skog Geothermal 25 Kawerau2013 Te Mihi Geothermal 166 Wairakei2013 Remaining part of Wairakei Geothermal 111 Wairakei2014 Ngatamariki Geothermal 80 Ohaaki2014 Mill Creek Wind 60 Wilton2015 Huntly coal unit 2 Coal 0 (Decomm.)Huntly2015 Waitara McKee peaker Peaker, fast start gas-firedpeaker2015 Demand side response 1 NI Price-responsive loadcurtailment2015 Demand side response 1 SI Price-responsive loadcurtailment100 Stratford50 Otahuhu50 Islington2015 Waitahora Wind 175 Linton2015 Castle Hill 1 Wind 200 Linton4262013 Annual Planning Report © Transpower New Zealand Limited 2013.All rights reserved.

Appendix G: Generation ScenariosYear Plant description Technology description CapacityMWSubstation(approx)2015 Mahinerangi stage 2 Wind 164 Halfway Bush2016 Tauhara stage 2 Geothermal 200 Wairakei2016 New IL 1 Interruptible load 50 Otahuhu2016 Demand side response 2 NI Price-responsive loadcurtailment50 Otahuhu2017 Generic geo 1 Geothermal 100 Kawerau2017 Hawea Control Gate Retrofit Hydro, peaking 17 Cromwell2017 South Island peak hydro 2 Hydro, peaking 35 Waitaki2017 Generic solar 1 Solar 50 Otahuhu2018 Generic geo 4 Geothermal 100 Whakamaru2018 Stockton Plateau I Hydro, run of river 30 Westport2018 Diesel fired OCGT 1 Peaker, diesel-fired OCGT 40 Marsden2018 Diesel fired OCGT 10 Peaker, diesel-fired OCGT 40 Kaitimako2018 Diesel fired OCGT 19 Peaker, diesel-fired OCGT 40 Gracefield2019 Taranaki CC Combined cycle gas turbine 0 (Decomm.)Stratford2019 Generic geo 2 Geothermal 100 Ohaaki2019 Generic geo 5 Geothermal 100 Rotorua2019 Diesel fired OCGT 9 Peaker, diesel-fired OCGT 100 Huntly2019 Gas fired OCGT 9 Peaker, fast start gas-firedpeaker160 Huntly2019 Generic solar 3 Solar 50 Islington2019 Taumatatotara Wind 44 Hangatiki2019 Hurleyville Wind 100 Hawera2020 Huntly coal unit 3 Coal 0 (Decomm.)Huntly2020 Otahuhu B Combined cycle gas turbine 0 (Decomm.)Otahuhu2020 North Bank Tunnel Hydro, peaking 280 Waitaki2020 Arnold Hydro, run of river 46 Dobson2020 Diesel fired OCGT 3 Peaker, diesel-fired OCGT 100 Marsden2020 Gas fired OCGT 2 Peaker, fast start gas-firedpeaker2020 Gas fired OCGT 5 Peaker, fast start gas-firedpeaker100 Southdown100 Otahuhu2020 Generic tidal 1 Tidal 200 Wellsford2020 Castle Hill 2 Wind 200 Linton2020 Castle Hill 3 Wind 200 Linton2020 Central Wind Wind 130 Rangipo2021 Generic solar 2 Solar 50 Otahuhu2021 Hauauru ma raki 1 Wind 250 Huntly2022 Marsden Point Refinery Cogeneration, gas-fired 85 Marsden2022 Demand side response 3 NI Price-responsive loadcurtailment50 Gracefield2022 Hawkes Bay Wind Farm Wind 94 Whirinaki2022 Cape Campbell Wind 150 Blenheim2023 Generic run of river 8 Hydro, run of river 50 Wanganui2013 Annual Planning Report © Transpower New Zealand Limited 2013.All rights reserved. 427

Appendix G: Generation ScenariosYear Plant description Technology description CapacityMWSubstation(approx)2023 Diesel fired OCGT 6 Peaker, diesel-fired OCGT 100 Otahuhu2024 Generic run of river 9 Hydro, run of river 50 Tarukenga2024 Generic run of river 10 Hydro, run of river 50 Wairoa2024 Long Gully Wind 12.5 Central Park2024 Waverley Wind 135 Waverley2025 Huntly coal unit 4 Coal 0 (Decomm.)Huntly2025 Biomass Cogen, Kawerau Cogeneration, biomass-fired 31 Kawerau2025 Biomass Cogen, Central Cogeneration, biomass-fired 63 Tangiwai2025 Clutha River Hydro, peaking 200 Roxburgh2025 Kaituna Hydro, run of river 15 Tarukenga2025 Wairau Hydro, run of river 73 Blenheim2025 Diesel fired OCGT 15 Peaker, diesel-fired OCGT 100 Whirinaki2025 Demand side response 12 NI Price-responsive loadcurtailment50 Otahuhu2025 Generic wave 1 Wave 38 Invercargill2026 New IL 2 Interruptible load 50 Otahuhu2026 Demand side response 4 NI Price-responsive loadcurtailment50 Otahuhu2026 Generic solar 4 Solar 50 Stoke2026 Hauauru ma raki 2 Wind 250 Huntly2027 Diesel fired OCGT 12 Peaker, diesel-fired OCGT 100 Kaitemako2027 Generic wave 2 Wave 38 Waimangaroa2027 Slopedown Wind 150 Gore2028 Biomass Cogen, Whirinaki Cogeneration, biomass-fired 63 Whirinaki2028 Demand side response 13 NI Price-responsive loadcurtailment50 Gracefield2028 Kaiwera Downs Wind 240 Nth MakarewaG.2Scenario 2: WindThe key features of the Wind scenario are:Carbon prices and gas prices are both high. As a result, renewable energyproduction exceeds 85% of total generation (on average) from 2018 onwards.By 2020, over 350 MW of new hydro and 2000 MW of new wind generation havebeen added. This is less than assumed in the 2010 Statement of Opportunitiesbut still a substantial amount.There is substantial development of wind generation in the lower North Island,with nearly 1,000 MW added there by 2022. The majority of the wind farms arenow seen as more likely in the North Island.By 2028, wind capacity exceeds 3000 MW, and 950 MW of new hydro has beenconstructed. Geothermal development is slower than in other scenarios, withcapacity maxing out at 1,030 MW.Baseload thermal generation is considerably reduced, with three out of fourHuntly coal-fired units, Taranaki CC and Southdown decommissioned by 2028.Over 1400 MW of thermal peakers are available by 2028. Interruptible load andprice-responsive demand increase by 400 MW over the same period.4282013 Annual Planning Report © Transpower New Zealand Limited 2013.All rights reserved.

MWAppendix G: Generation Scenarios14000Installed capacity by technology - Wind (mds2)12000WindSolar10000Cogeneration, otherOpen cycle gas turbine - gasInterruptible loadCoal, IGCC w ith CCS8000Hydro, schedulableHydro, run of riverHydro, peaking60004000GeothermalPeaker, fast start gas-fired peakerCogeneration, gas-firedPeaker, diesel-fired OCGTPrice-responsive load curtailmentCoalCombined cycle gas turbineCogeneration, biomass-fired200002012 2014 2016 2018 2020 2022 2024 2026 2028YearProjects and commission dates –Wind scenarioYear Plant description Technology description CapacityMWSubstation(approx)2013 Huntly coal unit 1 Coal 0 (Decomm.)Huntly2013 Wairakei Geothermal 0 (Decomm.)Wairakei2013 Kawerau Norske Skog Geothermal 25 Kawerau2013 Te Mihi Geothermal 166 Wairakei2013 Remaining part of Wairakei Geothermal 111 Wairakei2014 Ngatamariki Geothermal 80 Ohaaki2014 Mill Creek Wind 60 Wilton2015 Huntly coal unit 2 Coal 0 (Decomm.)Huntly2015 Waitara McKee peaker Peaker, fast start gas-firedpeaker2015 Gas fired OCGT 9 Peaker, fast start gas-firedpeaker2015 Demand side response 1 NI Price-responsive loadcurtailment2015 Demand side response 1 SI Price-responsive loadcurtailment100 Stratford160 Huntly50 Otahuhu50 Islington2015 Castle Hill 1 Wind 200 Linton2016 Generic geo 4 Geothermal 100 Whakamaru2016 New IL 1 Interruptible load 50 Otahuhu2016 Demand side response 2 NI Price-responsive load 50 Otahuhu2013 Annual Planning Report © Transpower New Zealand Limited 2013.All rights reserved. 429

Appendix G: Generation ScenariosYear Plant description Technology description CapacityMWcurtailmentSubstation(approx)2017 Hawea Control Gate Retrofit Hydro, peaking 17 Cromwell2017 South Island peak hydro 2 Hydro, peaking 35 Waitaki2017 Demand side response 2 SI Price-responsive loadcurtailment50 Islington2017 Hawkes Bay Wind Farm Wind 94 Whirinaki2017 Mahinerangi stage 2 Wind 164 Halfway Bush2018 Southdown Combined cycle gas turbine 0 (Decomm.)Southdown2018 Stockton Plateau I Hydro, run of river 30 Westport2018 Demand side response 3 NI Price-responsive loadcurtailment50 Gracefield2018 Castle Hill 2 Wind 200 Linton2018 Castle Hill 3 Wind 200 Linton2018 Hauauru ma raki 1 Wind 250 Huntly2018 Turitea Wind 180 Linton2019 Taranaki CC Combined cycle gas turbine 0 (Decomm.)Stratford2019 Kaituna Hydro, run of river 15 Tarukenga2019 Rakaia Terrace Hydro, run of river 16 Ashburton2019 Gas fired OCGT 3 Peaker, fast start gas-firedpeaker2019 Gas fired OCGT 8 Peaker, fast start gas-firedpeaker2019 Gas fired OCGT 11 Peaker, fast start gas-firedpeaker160 Southdown100 Huntly100 Stratford2019 Puketoi Wind 175 Linton2019 Taumatatotara Wind 44 Hangatiki2019 Hauauru ma raki 2 Wind 250 Huntly2019 Waverley Wind 135 Waverley2019 Hurleyville Wind 100 Hawera2020 Huntly coal unit 3 Coal 0 (Decomm.)Huntly2020 North Bank Tunnel Hydro, peaking 280 Waitaki2020 Diesel fired OCGT 3 Peaker, diesel-fired OCGT 100 Marsden2020 Diesel fired OCGT 6 Peaker, diesel-fired OCGT 100 Otahuhu2020 Diesel fired OCGT 12 Peaker, diesel-fired OCGT 100 Kaitemako2020 Puketiro Wind 90 Pauatahanui2021 Biomass Cogen, Kawerau Cogeneration, biomass-fired 31 Kawerau2021 Arnold Hydro, run of river 46 Dobson2021 Huntly unit 6 (P40) Open cycle gas turbine - gas 0 (Decomm.)Huntly2022 Generic wind North Isthmus 1 Wind 200 Maungatapere2023 Generic run of river 9 Hydro, run of river 50 Tarukenga2023 Generic run of river 10 Hydro, run of river 50 Wairoa2023 New IL 2 Interruptible load 50 Otahuhu2024 Biomass Cogen, Central Cogeneration, biomass-fired 63 Tangiwai2024 Generic run of river 8 Hydro, run of river 50 Wanganui4302013 Annual Planning Report © Transpower New Zealand Limited 2013.All rights reserved.

Appendix G: Generation ScenariosYear Plant description Technology description CapacityMW2024 Demand side response 4 NI Price-responsive loadcurtailmentSubstation(approx)50 Otahuhu2024 Generic wind Wellington Wind 80 Takapu Road2025 Clutha River Hydro, peaking 200 Roxburgh2025 Wairau Hydro, run of river 73 Blenheim2026 Marsden Point Refinery Cogeneration, gas-fired 85 Marsden2026 Mohikinui Hydro, run of river 85 Inangahua2026 Demand side response 12 NI Price-responsive loadcurtailment50 Otahuhu2026 Generic wind Auckland Wind 40 Glenbrook2027 Gas fired OCGT 5 Peaker, fast start gas-firedpeaker100 Otahuhu2027 Taharoa Wind 54 Hangatiki2028 Biomass Cogen, Whirinaki Cogeneration, biomass-fired 63 Whirinaki2028 Demand side response 13 NI Price-responsive loadcurtailment50 GracefieldG.3Scenario 3: Medium RenewablesThe key features of the Medium Renewables scenario are:Gas prices are lower than in the previous two scenarios, though the volumeavailable is still limited. Carbon prices are moderate.The NZAS aluminium smelter is progressively phased out between 2022 and2027. No new generation build is required over the phase-out period.Baseload thermal generation is considerably reduced, with two out of four Huntlycoal-fired units, Taranaki CC and Southdown decommissioned. However, anefficient new coal-fired power station is constructed in 2022.There is moderate geothermal and wind development, mainly in the North Island.By 2020, geothermal and wind capacity each exceed 1,400 MW. There is littlenew hydro generation.Over 1,400 MW of thermal peakers are available by 2022. The demand sidecontributes relatively little, with interruptible load and price-responsive demandincreasing by just 150 MW over the same period.2013 Annual Planning Report © Transpower New Zealand Limited 2013.All rights reserved. 431

MWAppendix G: Generation Scenarios12000Installed capacity by technology - Medium renewables (mds3)10000WindCogeneration, otherOpen cycle gas turbine - gas8000Interruptible loadHydro, schedulable60004000Hydro, run of riverHydro, peakingHydro, pumped storageGeothermalPeaker, fast start gas-fired peakerCogeneration, gas-firedPeaker, diesel-fired OCGTPrice-responsive load curtailmentCoalCombined cycle gas turbineCogeneration, biomass-fired200002012 2014 2016 2018 2020 2022 2024 2026 2028YearProjects and commission dates – Medium Renewables scenarioYear Plant description TechnologydescriptionCapacityMWSubstation(approx)2013 Huntly coal unit 1 Coal 0 (Decomm.)Huntly2013 Wairakei Geothermal 0 (Decomm.)Wairakei2013 Kawerau Norske Skog Geothermal 25 Kawerau2013 Te Mihi Geothermal 166 Wairakei2014 Ngatamariki Geothermal 80 Ohaaki2014 Demand side response 1 NI Price-responsive loadcurtailment2014 Demand side response 1 SI Price-responsive loadcurtailment50 Otahuhu50 Islington2014 Mill Creek Wind 60 Wilton2015 Waitara McKee peaker Peaker, fast start gasfiredpeaker100 Stratford2015 Puketoi Wind 175 Linton2015 Mahinerangi stage 2 Wind 164 Halfway Bush2016 Tauhara stage 2 Geothermal 200 Wairakei2016 Generic geo 1 Geothermal 100 Kawerau2016 Long Gully Wind 12.5 Central Park2017 Hawea Control Gate Retrofit Hydro, peaking 17 Cromwell2017 South Island peak hydro 2 Hydro, peaking 35 Waitaki2017 New IL 1 Interruptible load 50 Otahuhu4322013 Annual Planning Report © Transpower New Zealand Limited 2013.All rights reserved.

Appendix G: Generation ScenariosYear Plant description TechnologydescriptionCapacityMWSubstation(approx)2017 Hawkes Bay Wind Farm Wind 94 Whirinaki2018 Generic geo 5 Geothermal 100 Rotorua2018 Rakaia Terrace Hydro, run of river 16 Ashburton2019 Southdown Combined cycle gasturbine0 (Decomm.)Southdown2019 Generic geo 2 Geothermal 100 Ohaaki2019 Generic geo 3 Geothermal 100 Wairakei2019 Diesel fired OCGT 16 Peaker, diesel-firedOCGT2020 Taranaki CC Combined cycle gasturbine2020 Diesel fired OCGT 18 Peaker, diesel-firedOCGT2020 Gas fired OCGT 6 Peaker, fast start gasfiredpeaker2020 Gas fired OCGT 12 Peaker, fast start gasfiredpeaker40 New Plymouth0 (Decomm.)Stratford100 New Plymouth160 Otahuhu160 Stratford2020 Turitea Wind 180 Linton2020 Puketiro Wind 90 Pauatahanui2021 Huntly coal unit 2 Coal 0 (Decomm.)Huntly2021 Diesel fired OCGT 12 Peaker, diesel-firedOCGT2021 Gas fired OCGT 3 Peaker, fast start gasfiredpeaker2021 Gas fired OCGT 9 Peaker, fast start gasfiredpeaker100 Kaitemako160 Southdown160 Huntly2022 Marsden Coal Coal 320 Marsden2022 Huntly unit 6 (P40) Open cycle gas turbine- gas0 (Decomm.)Huntly2028 Clutha River Hydro, peaking 200 RoxburghG.4Scenario 4: CoalThe key features of the Coal scenario are:Gas prices are lower than in the Sustainable Path and Wind scenarios, thoughthe volume available is still limited. This is the scenario with the lowest carbonprices.Most existing baseload thermal generation remains online. Taranaki CC isdecommissioned, and one coal-fired Huntly unit follows in 2025.An efficient new coal-fired power station is commissioned in 2022; a second,burning Southland lignite, in 2025 and another lignite plant added 2028.There is also some renewable development. Geothermal capacity climbs to 1,400MW, and 320 MW of new hydro and almost 800 MW of wind are added by 2028.The output of existing hydro generation is curtailed due to difficulties in obtainingwater rights.Over 1,000 MW of thermal peakers are available by 2028 (less than in the morerenewable scenarios). Interruptible load and price-responsive demand increaseby 400 MW over the same period.2013 Annual Planning Report © Transpower New Zealand Limited 2013.All rights reserved. 433

MWAppendix G: Generation ScenariosInstalled capacity by technology - Coal (mds4)1200010000WindCogeneration, otherOpen cycle gas turbine - gasLignite8000Interruptible loadHydro, schedulableHydro, run of riverHydro, peakingHydro, pumped storage6000GeothermalPeaker, fast start gas-fired peakerCogeneration, gas-firedPeaker, diesel-fired OCGT4000Price-responsive load curtailmentCoalCombined cycle gas turbineCogeneration, biomass-fired200002012 2014 2016 2018 2020 2022 2024 2026 2028YearProjects and commission dates – Coal scenarioYear Plant description Technology description CapacityMWSubstation(approx)2013 Huntly coal unit 1 Coal 0 (Decomm.)Huntly2013 Wairakei Geothermal 0 (Decomm.)Wairakei2013 Kawerau Norske Skog Geothermal 25 Kawerau2013 Te Mihi Geothermal 166 Wairakei2014 Ngatamariki Geothermal 80 Ohaaki2014 Demand side response 1 NI Price-responsive loadcurtailment2014 Demand side response 1 SI Price-responsive loadcurtailment50 Otahuhu50 Islington2014 Mill Creek Wind 60 Wilton2015 Waitara McKee peaker Peaker, fast start gas-firedpeaker100 Stratford2015 Waitahora Wind 175 Linton2015 Puketoi Wind 175 Linton2016 Tauhara stage 2 Geothermal 200 Wairakei2017 New IL 1 Interruptible load 50 Otahuhu2017 Demand side response 2 NI Price-responsive loadcurtailment50 Otahuhu2017 Demand side response 2 SI Price-responsive load 50 Islington4342013 Annual Planning Report © Transpower New Zealand Limited 2013.All rights reserved.

Appendix G: Generation ScenariosYear Plant description Technology description CapacityMWcurtailmentSubstation(approx)2018 Generic geo 1 Geothermal 100 Kawerau2018 Generic geo 3 Geothermal 100 Wairakei2018 Demand side response 3 NI Price-responsive loadcurtailment50 Gracefield2019 Castle Hill 3 Wind 200 Linton2020 Marsden Point Refinery Cogeneration, gas-fired 85 Marsden2020 Taranaki CC Combined cycle gas turbine 0 (Decomm.)Stratford2020 Generic geo 4 Geothermal 100 Whakamaru2020 Generic geo 5 Geothermal 100 Rotorua2020 North Bank Tunnel Hydro, peaking 280 Waitaki2020 Gas fired OCGT 12 Peaker, fast start gas-firedpeaker2020 Demand side response 4 NI Price-responsive loadcurtailment160 Stratford50 Otahuhu2020 Central Wind Wind 130 Rangipo2020 Generic wind Auckland Wind 40 Glenbrook2021 Biomass Cogen, Kawerau Cogeneration, biomass-fired 31 Kawerau2021 Stockton Plateau I Hydro, run of river 30 Westport2021 Rakaia Terrace Hydro, run of river 16 Ashburton2021 New IL 2 Interruptible load 50 Otahuhu2021 Long Gully Wind 12.5 Central Park2022 Generic coal 1 Glenbrook Coal 400 Glenbrook2022 Huntly unit 6 (P40) Open cycle gas turbine - gas 0 (Decomm.)Huntly2024 Southdown E105 Open cycle gas turbine - gas 0 (Decomm.)Southdown2024 Gas fired OCGT 6 Peaker, fast start gas-firedpeaker160 Otahuhu2025 Generic lignite 1 Southland Lignite 400 Edendale2026 Gas fired OCGT 9 Peaker, fast start gas-firedpeaker160 Huntly2028 Huntly coal unit 2 Coal 0 (Decomm.)Huntly2028 Generic gas 1 Auckland Combined cycle gas turbine 410 Otahuhu2028 Generic lignite 2 Otago Lignite 400 RoxburghG.5Scenario 5: High Gas DiscoveryThe key features of the High Gas Discovery scenario are:Substantial volumes of natural gas are available at affordable prices. Carbonprices are moderate.All four coal-fired Huntly units are decommissioned by 2020. However, existinggas-fired generators remain online.Efficient new CCGTs are constructed - a 200 MW plant in Taranaki in 2015, a240 MW plant in Northland in 2017, and 400 MW plants in Auckland in 2020 and2025.2013 Annual Planning Report © Transpower New Zealand Limited 2013.All rights reserved. 435

MWAppendix G: Generation ScenariosNew gas-fired peakers are added, with thermal peaking capacity reaching 1,270MW by 2028. There is also new gas-fired cogeneration.There is also some renewable development. Geothermal capacity climbs to 1,200MW, and 550 MW of new wind is added. There is little new hydro generation.Interruptible load and price-responsive demand increase by 200 MW (rather lessthan in the 2010 SOO).Installed capacity by technology - High gas discovery (mds5)1200010000WindCogeneration, otherOpen cycle gas turbine - gas8000Interruptible loadHydro, schedulableHydro, run of riverHydro, peaking6000GeothermalPeaker, fast start gas-fired peakerCogeneration, gas-firedPeaker, diesel-fired OCGT4000Price-responsive load curtailmentCoalCombined cycle gas turbineCogeneration, biomass-fired200002012 2014 2016 2018 2020 2022 2024 2026 2028YearProjects and commission dates – High Gas Discovery scenarioYear Plant description Technology description CapacityMWSubstation(approx)2013 Huntly coal unit 1 Coal 0 (Decomm.)Huntly2013 Wairakei Geothermal 0 (Decomm.)Wairakei2013 Kawerau Norske Skog Geothermal 25 Kawerau2013 Te Mihi Geothermal 165 Wairakei2013 Remaining part of Wairakei Geothermal 110 Wairakei2013 Waitara McKee peaker Peaker, fast start gas-firedpeaker100 MotunuiDeviation2014 Ngatamariki Geothermal 82 Nga Awa Purua2015 Huntly coal unit 2 Coal 0 (Decomm.)Huntly2015 Todd CCGT Combined cycle gas turbine 200 Stratford2015 Arnold Hydro, run of river 46 Dobson2015 Demand side response 1 NI Price-responsive loadcurtailment50 Takapuna2015 Demand side response 1 SI Price-responsive load 50 Bromley4362013 Annual Planning Report © Transpower New Zealand Limited 2013.All rights reserved.

Appendix G: Generation ScenariosYear Plant description Technology description CapacityMWcurtailmentSubstation(approx)2016 Taranaki Cogen Cogeneration, gas-fired 50 Stratford2016 Generic geo 3 Geothermal 100 Wairakei2016 New IL 1 Interruptible load 50 Penrose2017 Rodney CCGT stage 1 Combined cycle gas turbine 240 Huapai2018 Huntly coal unit 3 Coal 0 (Decomm.)Huntly2018 Wairau Hydro, run of river 73 Blenheim2018 Diesel fired OCGT 19 Peaker, diesel-fired OCGT 40 Gracefield2018 Gas fired OCGT 9 Peaker, fast start gas-firedpeaker2018 Gas fired OCGT 12 Peaker, fast start gas-firedpeaker2018 Demand side response 2 SI Price-responsive loadcurtailment160 Huntly160 Stratford50 Islington2020 Huntly coal unit 4 Coal 0 (Decomm.)Huntly2020 Generic gas 1 Auckland Combined cycle gas turbine 410 Otahuhu2020 Generic geo 2 Geothermal 100 Ohaaki2021 Diesel fired OCGT 13 Peaker, diesel-fired OCGT 40 Whirinaki2022 Generic geo 1 Geothermal 100 Kawerau2022 Kaituna Hydro, run of river 15 Tarukenga2023 Gas fired OCGT 3 Peaker, fast start gas-firedpeaker160 Southdown2023 Hauauru ma raki 1 Wind 250 Huntly2023 Generic wind Wellington Wind 80 Takapu Rd2024 Mahinerangi stage 2 Wind 170 Halfway Bush2024 Slopedown Wind 150 Gore2025 Otahuhu C Combined cycle gas turbine 407 Otahuhu2027 Gas fired OCGT 6 Peaker, fast start gas-firedpeaker160 Otahuhu2013 Annual Planning Report © Transpower New Zealand Limited 2013.All rights reserved. 437

MWMWAppendix G: Generation ScenariosG.6Plots of installed capacity for major generation technologiesInstalled capacity of coal and lignite1600Sustainable path (mds1)Wind (mds2)1400Medium renew ables (mds3)Coal (mds4)High gas discovery (mds5)1200100080060040020002012 2014 2016 2018 2020 2022 2024 2026 2028YearInstalled capacity of gasSustainable path (mds1)Wind (mds2)Medium renew ables (mds3)2500Coal (mds4)High gas discovery (mds5)2000150010002012 2014 2016 2018 2020 2022 2024 2026 2028Year4382013 Annual Planning Report © Transpower New Zealand Limited 2013.All rights reserved.

MWMWAppendix G: Generation ScenariosInstalled capacity of geothermal1600Sustainable path (mds1)Wind (mds2)1500Medium renew ables (mds3)Coal (mds4)High gas discovery (mds5)140013001200110010009008007002012 2014 2016 2018 2020 2022 2024 2026 2028YearInstalled capacity of hydro6200Sustainable path (mds1)Wind (mds2)Medium renew ables (mds3)Coal (mds4)6000High gas discovery (mds5)58005600540052002012 2014 2016 2018 2020 2022 2024 2026 2028Year2013 Annual Planning Report © Transpower New Zealand Limited 2013.All rights reserved. 439

MWMWAppendix G: Generation ScenariosInstalled capacity of interruptible load and price-responsive load curtailment700Sustainable path (mds1)Wind (mds2)Medium renew ables (mds3)600Coal (mds4)High gas discovery (mds5)5004003002001002012 2014 2016 2018 2020 2022 2024 2026 2028YearInstalled capacity of thermal peakers1600Sustainable path (mds1)Wind (mds2)Medium renew ables (mds3)Coal (mds4)1400High gas discovery (mds5)120010008006002012 2014 2016 2018 2020 2022 2024 2026 2028Year4402013 Annual Planning Report © Transpower New Zealand Limited 2013.All rights reserved.

MWAppendix G: Generation ScenariosInstalled capacity of wind3000Sustainable path (mds1)Wind (mds2)Medium renew ables (mds3)Coal (mds4)High gas discovery (mds5)25002000150010005002012 2014 2016 2018 2020 2022 2024 2026 2028Year2013 Annual Planning Report © Transpower New Zealand Limited 2013.All rights reserved. 441

Appendix H: Project NamingAppendix HTranspower Project NamingTranspower assigns a unique project reference to each project. This is to assistinternally and externally in ensuring unambiguous project references betweenTranspower and its customers, industry, the Electricity Authority and the wider NewZealand public.All projects are named according to the following convention:LocationIdentifier-AssetCategory-TypeOfWork-UniqueIDLocation + Asset Category + Work Type + Unique IDRegion Site ParentAKLDWAKTBOPEWGTNCHCHetcorExistingStationcodes: +GRDPAOPTRorLine code:ADD_ISLARI_EDGMTI_WKMetcorNIGUNAANSIGUAssetCategories:POW_TFRTRANREA_PWRSREA_PWRCSUBESTBUSECC_BANKSSYN_CONDWork Types:DEVEHMTREPLUnique ID:010203...H.1Location IdentifierThe first block of letters is the location identifier, which can be one of three types:regionsite, ormajor project parent.The region/site codes are largely based on Transpower’s existing site/line specificabbreviations (e.g. OTA for Otahuhu). Where new sites are contemplated, a newabbreviation will be formed (e.g. GRD for Geraldine).Unique codes of four characters will be made for regions or cities where a project isnot sufficiently well defined in location to use a site/line abbreviation (for example,AKLD for Auckland, CHCH for Christchurch).4422013 Annual Planning Report © Transpower New Zealand Limited 2013.All rights reserved.

Appendix H: Project NamingUnique four character codes will also be used for parent projects (e.g. large umbrellaprojects encompassing a number of individual projects). Examples used in the APRinclude:NIGU – North Island Grid UpgradeNAAN – North Auckland and NorthlandHVDC – HVDCUPNI – Upper North IslandH.2Asset CategoryCodes for the asset category are to be based on Transpower’s internal codingpractices. These include:C_BANKS – Capacitor banksSYN_COND – Synchronous CondenserTRAN – TransmissionREA_PWRC – Reactive Power ControllerREA_PWRS – Reactive Power SupportBUSG – BussingPOW_TFR – Power TransformerSUBEST – Substation EstablishmentBUS_SEC – Bus SectionH.3Work TypeCodes for the work type also reflect Transpower’s internal coding. Examples include:DEV – DevelopmentEHMT – EnhancementREPL – ReplacementH.4Unique IDFinally, a unique numeric identifier is added at the end of the code sequence todistinguish projects for which all other parts of the name are identical. This can occurin particular over a ten year forecast period.2013 Annual Planning Report © Transpower New Zealand Limited 2013.All rights reserved. 443

Appendix I: GlossaryAppendix IGlossaryTermAfter DiversityMaximum Demandautomatic underfrequency loadsheddingavailabilitybay (of a station)breaker-and-a-halfstationbusbus coupler circuitbreakerbus sectioncablecapacitor bankcharging current (line)circuit (transmission)(cct)circuit-breakerco-generationcommissionedcommitted projectsconstraintcontingencycontingent eventDescriptionThe peak consumption of energy (averaged over a half-hour period and expressed inWatts) that incorporates the non-simultaneous nature of each point of supply’s load peaktime.The automatic disconnection of customers for severe or prolonged underfrequency. Implemented on relays installed within the distribution network or atTranspower’s substations, customers are tripped in two, nominally, 20% groups.The number of hours per year the network or part thereof is in service. Unavailability isthe opposite of availability (for example, the hours per year the network or part thereof isnot providing service).That part of a substation or power station where a given circuit’s switchgear islocated. According to the type of circuit, a substation or power station may include: feederbays, transformer bays, bus coupler bays, etc.A double-bus substation where, for two circuits, three circuit-breakers are connected inseries between the two buses, the circuits being connected on each side of the centralcircuit-breaker.The common primary conductor of power from a power source to two or more separatecircuits.A circuit-breaker located between two busbars that can both be accessed by the sameexternal circuit. The bus coupler circuit-breaker permits the busbars to be connectedtogether or separated under load or fault conditions.Part of a bus that can be isolated from another part of the same bus.One or more insulated conductors forming a transmission circuit above or below ground.A number of capacitors connected together in series and/or parallel to form the requisitecapacitance and voltage rating for reactive compensation and harmonic filters on theHVAC and HVDC power systems.The current taken by a transmission circuit to energise its conductors due to thecapacitive effect of the circuit.A set of conductors (normally three) plus associated hardware and insulation on atransmission line, which together form a single electrical connection between two or morestations and which, when faulted, is removed automatically from the system (by circuitbreakers)as a single entity.A switching device, capable of making, carrying and breaking currents under normalcircuit conditions and also making, carrying for a specified time and breaking currentsunder specified abnormal conditions, such as those of short circuit.The use of high-pressure steam from a turbo-generator set for an industrial process. Theproduction of electricity is usually secondary to the requirements of the industrial process.The operational state of equipment that has undergone the commissioning process and isbrought under the operational control of a service centre/controller.Refers to actual proposed projects that satisfy a number of criteria indicating that they areextremely likely to proceed in the near future. For example:land has been acquired for construction of the projectplanning consents, construction approvals and licences have been obtainedconstruction has begun, or a firm commencement date has been setcontracts for supply and construction have been finalised, andfinancing arrangements are largely complete.A local limitation in the transmission capacity of the grid required to maintain grid securityor power quality.The uncertainty of an event occurring, and the planning to cover for this. For example, asingle contingency could be:a. in relation to transmission, the unplanned tripping of a single item of equipment, orb. in relation to a fall in frequency, the loss of the largest single block of generation inservice, or the loss of one HVDC pole.Those events for which, in the reasonable opinion of the system operator, resources canbe economically provided to maintain the security of the grid and power quality without the4442013 Annual Planning Report © Transpower New Zealand Limited 2013.All rights reserved.

Appendix I: GlossaryTermcontinuous ratingdecommissioneddemanddemand-sidemanagementdisconnectorDescriptionshedding of demand.The maximum rating to which equipment can be operated continuously.The status of equipment which is permanently disconnected from the power system,made permanently inoperable, and free of any operational identification.A measure of the rate of consumption of electrical energy.Initiatives or mechanisms used to control electricity demand. Examples include ripplecontrols on water heating or contracted shedding of load (demand).A switch that, when in the open position, provides an isolating distance in accordance withspecified requirements.dispatch The process of :distribution (ofelectricity)a. pre-dispatch scheduling to allocate active and reactive power generation, includingadditional ancillary services and reserve, to match expected demand, within thelimitations of the grid and equipmentb. rescheduling to meet forecast demand, andc. issuing instructions based on the schedule and the real-time conditions to manageresources to meet the actual demand.The transfer of electricity between the transmission network and end users through a localnetwork.distribution linedouble circuit lineduplicate protectionelectricity distributorElectricity IndustryAct 2010Electricity IndustryParticipation Codeembedded generatorsend usereventfeederfirm capacityforced outagefrequency (power)frequency excursiongas turbine (GT)generating setAn electric line that is part of a local network.A transmission line carrying two circuits.A protection scheme for a plant item such that any fault on the plant item can be clearedby two independent sets of relays, either of which is able to operate correctly even if theother fails completely.An asset owner whose assets are predominantly for the distribution of electricity tocustomers.The Act setting out the present framework including the Electricity Industry ParticipationCode.The requirements on the electricity industry made pursuant to the Electricity Industry Act2010.Embedded generators are smaller power plants connected to a regional electricity linebusiness’s distribution network (as opposed to the high voltage transmission network).An entity connected to the power system for the primary purpose of consuming electricity.A term identifying undesired or untoward operational happenings, principally:a. accidents (resulting in loss)b. near-misses (which, under slightly different circumstances, could have caused loss)to people, process, equipment, material or the environmentc. a disturbance to the power systemd. a significant change in the state of the gride. equipment defects, andf. fire or intruder alarm operation.A circuit that provides a direct connection to a customer.Power capacity intended to be available at all times during the period covered by aguaranteed commitment to deliver, even under adverse conditions.The automatic or urgent removal from service of an item of equipment.The rate of cyclic change in value of current and voltage, quantified by the internationalstandard term ’Hertz‘ (Hz).A variation of the power system frequency above 50.25 Hz or below 49.75 Hz.A heat engine that uses the energy of expanding gases passing through a multi-stageturbine to create rotational power.A group of rotating machines transforming mechanical or thermal energy into electricity.Note: For the purposes of the operating codes and the output ratings referred to, the set istaken to include the limitations of the energy source, turbine, generator, cable, settransformer and switchgear. [GOSP glossary - IEC 50 (602-02-01)]generationThe electrical energy produced by a generator, a generating station or within a powersystem as a whole.The process of producing electricity.2013 Annual Planning Report © Transpower New Zealand Limited 2013.All rights reserved. 445

Appendix I: GlossaryTermgeneratorgridgrid asset ownergrid assetsgrid exit point (GXP)grid injection pointHVACHVDCin serviceinstantaneous loadintertripislanded operationlife expectancyline [overhead]load controlload sheddingmain protectionmanual load sheddingmaximum continuousrating (MCR)maximum demandMegaVoltAmpere(MVA)n-1, “n”nominal ratingnominal systemDescriptionA person who owns and/or manages one or more generating sets that are physicallyconnected to the grid assets or to a network or to other assets connected to the gridassets.That part of the New Zealand electricity transmission system, the operation of which isundertaken by the grid operator.Transpower New Zealand Limited.At any time, the plant, transmission lines and other facilities, owned or managed by thegrid asset owner, and which are used to interconnect all the points of connection forconnected parties.A point of connection where electricity may flow out of the grid.A point of connection where electricity may flow into the grid.High voltage alternating current.High voltage direct current.The state of equipment that is connected to a source of energy or may be connected to asource of energy by an operating action.The maximum instantaneous current drawn. It consists of continuous, non-continuous andmomentary currents.A protection signalling system whereby a signal initiated at one station trips a circuitbreakerat another station.The condition that arises when a section of the power system is disconnected from andoperating independently of the remainder of the power system.The date where replacement/major refurbishment is necessary.A series of structures carrying overhead one or more transmission circuits.Types of load control include:automatic under frequency load shedding (see MW reserve of a power system)interruptible load (see MW reserve of a power system), andmanual load shedding (see manual load shedding).The forced disconnection of load, in stages. This is either manual (see load control) orautomatic (see MW reserve [of a power system]).Protection equipment (or a system) expected to have priority in initiating either a faultclearance or an action to terminate an abnormal condition in the power system.The forced disconnection of load by an operator/controller.The value assigned to an equipment parameter by the manufacturer, and at which theequipment may be operated for an unlimited period without damage.The peak consumption of energy (averaged over a half-hour period and expressed inwatts) recorded during a given time, for example, a day, week, or year.1000 kVA. The flow of active power is measured in megaWatts (MW). Whencompounded with the flow of reactive power, which is measured in Mvar, the resultant ismeasured in MegaVoltAmperes (MVA).Refers to the planning standard that Transpower generally plans the grid to.The n-1 security level provides supply security to the connected loads under a singlecredible contingency with all the assets that can reasonably be expected in service. Thesingle credible contingencies that are defined in the Rules are:a single transmission circuit interruptionthe failure or removal from operational service of a single generating unitan HVDC link single pole interruptionthe failure or removal from service of a single bus sectiona single interconnecting transformer interruption, andthe failure or removal from service of a single shunt connected reactive component.An ‘’n” security standard means that any outage will trip load. It is often found in smallersupply areas, where just one transmission circuit or supply transformer provides supply.The design rating of the equipment or transmission circuit. For equipment, this is oftenreferred to as the 'nameplate rating'.50 Hertz.4462013 Annual Planning Report © Transpower New Zealand Limited 2013.All rights reserved.

Appendix I: GlossaryTermfrequencynon-continuous loadnormal systemconditionson-load tap-changer(OLTC)outageoverhead lineoverloadpeak demandpeak loadplanned outagepower factorpower flow analysispower systemstabilitypower transformerprotectionreactive powerrelayreliabilityresource consentreturn periodrunback schemesecurityshort circuit ratingshort term ratingsingle-circuit linespur circuitstability limitDescriptionA load that is energised for a portion of the duty cycle greater than one minute. It may befor a set period, and removal may be automatic or by operator action or it may continue tothe end of the duty cycle.The state of the power system when it is operating in accordance with statutoryrequirements as regards quality of supply and within basic design and operationalparameters.Equipment fitted to a power transformer by which the voltage ratio between the windingscan be varied while the transformer is on-load.The state of an item of equipment when it is not available to perform its intended function.An outage may or may not cause an interruption of supply to customers.A transmission line.A load greater than the maximum continuous rating.See maximum demand.The maximum peak load (in amps) that can be expected to be carried within a twelvemonth period on the circuit or by the equipment/component.A deliberate outage scheduled for maintenance purposes.The ratio between active power (expressed in watts, W) and true power (expressed involt-amperes, VA). Can vary between 1 and 0. A load with a low power factor uses morereactive current than a load with a high power factor for the same amount of useful powertransferred.Simulation of the actual power system using computer models, so as to analyse theeffects of changes to inputs (like demand, supply, and asset ratings), and identifyconstraints or other issues that might affect security of supply to a region.The capability of a power system to regain a steady state, characterised by thesynchronous operation of the generators after a disturbance due, for example, to variationof power or impedance.A transformer that primarily changes voltage and current for the efficient conveyance ofelectricity over the circuits connected to it.The equipment provided for detecting abnormal conditions in a power system and theninitiating fault clearance or actuating signals or indications.Energy that flows in the power system between alternators, capacitors, SVCs, etc., andinductive and capacitive equipment such as transmission lines and low power factorloads. It is the product of the voltage and out-of-phase components of the alternatingcurrent and is measured in vars.A device designed to produce predetermined changes in one or more electrical outputcircuits, when certain conditions are fulfilled in the electrical input circuits controlling thedevice.The failure rate. For example, the number of failures per year based on experience over along time period, say 10 years or more.A consent to use land, air or water granted by the local government under the ResourceManagement Act. The consent usually imposes limits on that use.The statistical return period of a weather-related event, load or load effect.An automatic limit on generation or HVDC transfer, which typically would be enabledwhen there is loss of a particular circuit, transformer, signalling or control system.A term used to describe the ability or capacity of a network to provide service after one ormore equipment failures. It can be defined by deterministic planning criteria such as (n),(n-1), (n-2) security contingency. A security contingency of (n-m) at a particular location inthe network means that ‘m’ component failures can be tolerated without loss of service.The three second fault rating of equipment.The maximum rating to which equipment can be operated for a specified duration.A transmission line carrying one circuit.A circuit connected to the transmission system at only one point.The critical value of a given system state variable that cannot be exceeded withoutendangering power system stability.For a power system without a fault, this concept is related to the steady state stability of2013 Annual Planning Report © Transpower New Zealand Limited 2013.All rights reserved. 447

Appendix I: GlossaryTermsteady state stabilitysubstationswitchgearswitchgear groupswitching stationsynchronouscondensersystem frequencysystem normalsystem operatortee (or T) pointtee-offthermalconstraints/limits/capacitiesthermal upgradetransformertransient (in)stabilitytransmissiontransmission circuittransmission linetransmission systemvoltagevoltage collapsevoltage (in)stabilityDescriptionthe system.A power system stability in which disturbances have only small rates of change and smallrelative magnitudes.A building, structure or enclosure incorporating equipment used principally for the controlof the transmission or distribution of electricity.A collective term for switches of all types and their associated equipment, includingcircuit-breakers, disconnectors, and earthing switches.A circuit-breaker and related disconnectors. The relationship is determined by switchgearnumbering.A station existing solely for the purpose of transmission rather than supply.A synchronous machine running without mechanical load and supplying or absorbingreactive power to regulate local voltage.At any instant the value of the frequency of the power in the North Island or South Island.See also Hertz, nominal system frequency, and frequency.The power system is operating in the normal state when:generation meets the demand at 50Hz (±0.2 Hz)voltage requirements are metgrid equipment is operated within design ratings, andreserve margins and the power system configuration provide an adequate level ofoperational security.The person responsible from time to time for the operation of the grid system. The systemoperator is Transpower New Zealand Limited.The point at which a branch transmission circuit is solidly and permanently connected to amain circuit, usually without switchgear. See also tee-off.A branch transmission circuit joining a main circuit and that is protected as part of themain circuit.Refers to the temperature ratings of the assets (lines, generators, transformers)connected to the power system, beyond which the assets cannot securely be operated.The increase in temperature ratings of assets to provide more capacity.A static electric device consisting of a winding or two or more coupled windings whichtransfer power by electromagnetic induction between circuits of the same frequency,usually with changed values of voltage and current.Refers to the response of the power system when it experiences a large disturbance likea line fault or outage of a generator.The conveying of bulk electricity from power stations to points of supply (compared withdistribution).An electrical circuit the primary purpose of which is the transmission of electricity from onegeographical location to another.A series of structures carrying one or more transmission circuits overhead.That part of the power system primarily intended for the conveyance of bulk electricity.The nominal potential difference between conductors or the nominal potential differencebetween a conductor and earth, whichever is applicable.A sudden and large decrease in the voltage of the electrical system.Refers to the power system’s ability to maintain a satisfactory voltage at all buses for anydisturbance, such as a variation in load or an outage of plant.4482013 Annual Planning Report © Transpower New Zealand Limited 2013.All rights reserved.

Appendix J: Grid Exit and Injection PointsAppendix JGrid Exit and Injection PointsTable J-1: North Island Grid Exit and Injection PointsNorth IslandNorth Isthmus Auckland Waikato Bay of Plenty Central North Island Taranaki Hawkes Bay WellingtonAlbany GXP Bombay GXP Cambridge GXP Edgecumbe GXP Bunnythorpe GXP Brunswick GXP Fernhill GXP Central Park GXPBream Bay GXP Glenbrook GXP Hamilton GXP Kaitimako GXP Dannevirke GXP Carrington St GXP Gisborne GXP Gracefield GXPDargaville GXP Hobson Street GXP Hangatiki GXP Kinleith GXP Linton GXP Hawera GXP Redclyffe GXP Greytown GXPHenderson GXP Mangere GXP Hinuera GXP Lichfield GXP Mangamaire GXP Huirangi GXP TokomaruBayGXP Haywards GXPHepburn Road GXP Meremere GXP Kopu GXP Mt Maunganui GXP Marton GXP Motunui GXP Wairoa GXP Kaiwharawhara GXPHuapai GXP Mount Roskill GXP Piako GXP Owhata GXP Mataroa GXP Opunake GXP Whakatu GXP Masterton GXPKensington GXP Pakuranga GXP Putaruru GXP Rotorua GXP National Park GXP Taumarunui GXP Tuai GIP Melling GXPMaungatapere GXP Penrose GXP Te Awamutu GXP Tarukenga GXP Ohakune GXP Wanganui GXP Whirinaki GIP Paraparaumu GXPMaungaturoto GXP Takanini GXP Te Kowhai GXP Tauranga GXP Ongarue GXP Waverley GXP Pauatahanui GXPSilverdale GXP Wiri GXP Waihou GXP Te Kaha GXP Tangiwai GXP Kapuni GIP Takapu Rd GXPWellsford GXP Otahuhu GIP/GXPWairau Road GXP Southdown GIP Huntly GIP/GXPWaikino GXP Te Matai GXP Waipawa GXP NewPlymouthWaiotahi GXP Woodville GXP/GIPMarsden GIP Drury SWI Arapuni GIP Kawerau GIP/GXPAtiamuri GIP Matahina GIP Mangahao GIPKarapiro GIP Nga AwaPuruaGIP Upper Hutt GXPStratford GIP Wilton GXPAratiatia GIP West Wind GIPGIPMaraetai GIP Ngatamariki GIPMokai GIP Ohaaki GIP2013 Annual Planning Report © Transpower New Zealand Limited 2013.All rights reserved. 449

AppendixJ: Grid Exit and Injection PointsNorth IslandNorth Isthmus Auckland Waikato Bay of Plenty Central North Island Taranaki Hawkes Bay WellingtonOhakuri GIP Poihipi GIPWaipapa GIP Rangipo GIPWhakamaru GIP Tararua GIPOhinewai SWI Tokaanu GIPWairakei GIPTable J-2: South Island Grid Exit and Injection PointsSouth IslandNelson/Marlborough West Coast Canterbury South Canterbury Otago/SouthlandArgyle GXP Arthurs Pass GXP Addington GXP Albury GXP Balclutha GXPBlenheim GXP Atarau GXP Ashburton GXP Bells Pond GXP Brydone GXPMotueka GXP Castle Hill GXP Ashley GXP Black Point GXP Cromwell GXPMotupipi GXP Dobson GXP Bromley GXP Oamaru GXP Edendale GXPStoke GXP Greymouth GXP Culverden GXP Studholme GXP Frankton GXPCobb GIP Hokitika GXP Hororata GXP Temuka GXP Gore GXPUpper Takaka SWI Kikiwa GXP Islington GXP Timaru GXP Halfway Bush GXPMurchison GXP Kaiapoi GXP Twizel GXP Invercargill GXPOtira GXP Middleton GXP Aviemore GIP Naseby GXPReefton GXP Southbrook GXP Benmore GIP NorthMakarewaOrowaiti(Robertson Rd)GXPGXP Springston GXP Ohau A GIP Palmerston GXPWestport GXP Waipara GXP Ohau B GIP SouthDunedinGXP4502013 Annual Planning Report © Transpower New Zealand Limited 2013.All rights reserved.

Appendix J: Grid Exit and Injection PointsSouth IslandNelson/Marlborough West Coast Canterbury South Canterbury Otago/SouthlandGXP – Grid Exit PointKumara GIP Coleridge GIP Ohau C GIP Tiwai GXPInangahua SWI Tekapo A GIP Berwick GIPWaimangaroa SWI Tekapo B GIP Clyde GIPWaitaki GIP Manapouri GIPLivingstone SWI Roxburgh GIPThree MileHillSWIGIP– Grid Injection PointSWI – Switching Station2013 Annual Planning Report © Transpower New Zealand Limited 2013.All rights reserved. 451