Annual Planning Report 2012 Complete

INCORPORATING THE GRID RELIABILITY REPORT AND THE GRID ECONOMIC INVESTMENT REPORT 2012ANNUAL PLANNING REPORT

MAR

CH

Foreword

2012 Annual Planning Report © Transpower New Zealand Limited 2012. All rights reserved. i

Foreword to the Annual Planning Report 2012

I am pleased to introduce this seventh Transpower Annual Planning Report (APR).

Transpower is the owner, operator and planner of the National Grid. The National Grid comprises the high voltage electrical transmission system that stretches across both North and South Islands, connecting generation sources to local substations serving rural and urban customers. Importantly, it also facilitates the competitive wholesale electricity market which underpins the pricing of electricity to all New Zealanders.

The APR is one of our initiatives to make our planning processes more transparent for all interested parties. Transpower is adopting an ‘open book’ approach to transmission planning. We think this is appropriate for a regulated entity with such an important role to play in the economic and social wellbeing of New Zealanders.

When we first started publishing the APR in 2006, we were at the start of a significant capital reinvestment programme – a hurdle we needed to climb to ensure New Zealanders continued to enjoy the benefits of a reliable and secure transmission network. Six years later, our capital investments are peaking – all our major projects are targeting completion over the next two years.

For the future, we put our stake in the ground with release of Transmission Tomorrow, It recognises that new build is only part of the answer, and we can and must do more to optimise our investment in the existing network. Already, we are trialling variable line ratings on some core transmission lines, and we’re also promoting the use of demand-side management as a means of deferring transmission investment.

The APR continues to identify issues on the investment horizon that may ultimately require a transmission solution. As in previous years, we have worked to improve the quality and layout of the information provided to be more intuitive for the reader.

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 on demand foreacast and generation possibilities to ensure the APR is the primary grid planning document for the industry.

Dr Patrick Strange

Chief Executive

March 2012

Executive Summary

2012 Annual Planning Report © Transpower New Zealand Limited 2011. All rights reserved. ii

Executive Summary

Background

The 2012 Annual Planning Report (APR) provides information about:

the capabilities of the existing National Grid

demand and generation forecasts for the next 10 to 15 years

the National Grid’s ability to meet future demand and generation needs

the role of the transmission grid in facilitating generation

National Grid investment that may be required to meet future needs for the next 10 to 15 years and beyond, by way of:

grid backbone transmission plans for the main North and South Island transmission corridors, and for the HVDC link, and

thirteen regional plans.

The APR also includes all the requirements of the Grid Reliability Report (GRR) and Grid Economic Investment Report (GEIR) as defined under Part 12, of the Electricity Industry Participation Code, and 10-year forecast of fault levels at each customer point of service under the Benchmark Agreement.

This APR represents information available up to 28 February 2012.

Purpose of the APR

The role of the APR is to signal proposed and possible transmission investments within a 10 to 15 year horizon, so that market participants have a greater degree of information about Transpower’s plans in order to confirm their own.

While the APR is not a regulatory requirement, we appreciate that our operating environment relies on a greater transparency of information about the National Grid, and our plans to operate, maintain and develop it. The APR draws on other publications (like the System Security Forecast) to provide a comprehensive 10 to 15 year forecast of the issues impacting on the National Grid and our plans and possible future paths for development.

The GRR and GEIR are regulatory requirements. We have endeavoured to go well beyond the minimum requirements of the GRR to provide greater transparency of our planning functions and methods.

Overview

The APR aims to provide our view on future grid development needs and augmentation options. In order to allow interested parties to fully evaluate the needs and options, the base data and analytical methods are presented for scrutiny and comment.

The APR takes a national and a regional approach to examine, respectively, the grid backbone and the requirements for each individual region.

Energy and peak demand forecasts

Previous Annual Planning Reports have been based on demand assumptions provided by the Electricity Commission. This year, Transpower has developed a new approach to demand forecasting involving both top down (national/regional) and bottom up (GXP) modelling of peak demand.

Executive Summary

2012 Annual Planning Report © Transpower New Zealand Limited 2012. All rights reserved. iii

The peak demand forecast represents a prudent forecast that equates to a probability of exceedance (POE) of 10%.

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In comparison to last year, this demand forecast shows significantly lower growth. The forecast now shows an average growth rate of 1.7% per annum from 2012 to 2027.

Generation forecasts

We have developed a new set of generation scenarios for use in this work. They are broadly consistent with the scenarios published in the Electricity Commission’s 2010 Statement of Opportunities.

There are five market development scenarios:

Sustainable Path – New Zealand embarks on a path of sustainable electricity development and sectoral emissions reduction.

South Island 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 in both islands with North Island Geothermal playing an important role. Tiwai smelter 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 low over the entire time horizon.

State of the grid

A reliable “fit for purpose” National Grid that meets present consumer needs, and responds to changing demands, is an essential component of a modern society. A robust and capable grid also creates a platform to allow strong competition between generators and retailers, to put downward pressure on prices to the benefit of consumers. The National Grid also continues to provide New Zealanders with access to renewable sources of generation (hydro, wind, geothermal).

Based on present knowledge, we can demonstrate that the projects identified in this report will enable the grid to meet forecast demand and solve the grid related issues predicted to occur over the next 10-15 years.

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1 Further information about the new model is provided in Chapter 4.

5000

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1995 2000 2005 2010 2015 2020 2025

Load (MW) New Zealand Prudent Peak Electricity Demand Forecast

APR 2010 APR 2011 APR 2012 Actual

Executive Summary

2012 Annual Planning Report © Transpower New Zealand Limited 2011. All rights reserved. iv

Key proposed developments

A number of the major projects signalled in previous years are now well underway including the North Island Grid Upgrade project (targeting 2012), North Auckland and Northland Upgrade project (targeting 2013) and the HVDC Pole 3 project (targeting 2013).

In other areas and in the regional networks particularly, smaller upgrade projects providing incremental changes to existing capacity continue to be needed. In these regions, where there is less certainty over future transmission capacity, investment in newer technologies is helping to get the most out of what we have now. Recent projects include New Zealand’s first deployment of series compensation (now approved for the Lower South Island Reliability Project), and deployment of further static synchronous compensators at Penrose and Marsden.

As well as looking at future demand, we also have projects underway to help facilitate the connection of more generation. The replacement Wairakei to Whakamaru C line project to accommodate greater generation in the Wairakei region is expected to break ground shortly. In the South Island, the Clutha to Upper Waitaki Lines project has been recently reviewed. Recognising that generation development has not happened to the extent envisaged, we are holding back on those parts of the project that were generation-enabling only.

Completed projects for 2011

Summary Table 1 lists the projects completed since the 2011 Annual Planning Report.

Summary Table 1: Projects completed since the 2011 Annual Planning Report

Project name

Islington reactive power controller

North Island grid upgrade project:

convert the existing 110 kV Pakuranga substation to 220 kV

convert the existing 110 kV Otahuhu–Pakuranga line to 220 kV

Pakuranga 220/33 kV supply transformer

Bombay 110 kV bus security upgrade

Redclyffe 110 kV bus security upgrade

West Coast Grid Upgrade project:

Inangahua–Reefton 2 circuit extension to Dobson

Dobson interconnecting transformer

Woodville supply transformer replacement and a second supply transformer

Waverley supply transformer replacement

110 kV Hawera–Stratford reconductoring

110 kV Wanganui–Waverley reconductoring

Committed and proposed projects for 2012

Summary Figure 1 and Summary Figure 2 provide a summary of all projects either committed or proposed in this APR

3. Detail around any particular project can be found

in the relevant regional or grid backbone chapter.

2 Transpower is unable to comment on supply side issues (e.g. beyond the grid exit point) other than

through the impact of the generation scenarios. 3 Refer to Chapter 1, Section 1.4 for definitions of “committed” and “proposed”.

Executive Summary

2012 Annual Planning Report © Transpower New Zealand Limited 2012. All rights reserved. v

Summary Figure 1: Transpower’s committed or proposed projects – North Island

Auckland Regional Projects

New 220 kV connection between Pakuranga and Penrose

New cross harbour 220 kV connection between Penrose and Albany

New grid exit point at Hobson Street

New STATCOM at Penrose

Bay of Plenty Regional Projects

Bay of Plenty Interconnection Upgrade including:

converting the Kaitimako to Tarukenga circuits to 220 kV

installing 220 kV interconnecting transformers at Kaitimako

Kawerau 220/110 kV transformer T12 replacement

Tarukenga interconnecting transformer replacement

North Island Grid Backbone Projects

North Island Grid Upgrade Project

construct a new substation at Whakamaru (Whakamaru B) and a transition station at Brownhill

new 220/400 kV double circuit transmission line (partially underground cables) from Whakamaru to Pakuranga

New 220 kV Wairakei–Whakamaru C transmission line

National Auto-Synchronisation Points Project

Bunnythorpe–Haywards 220 kV A and B line conductor replacement

Northland Regional Projects

New STATCOM at Marsden

New grid exit point at Wairau Road

Wellington Regional Projects

Replacement supply transformers at Masterton

Taranaki Regional Projects

Replacement conductor on the 110 kV Stratford–Wanganui transmission line

Replacement conductor on the 110 kV Opunake–Stratford transmission line

Waikato Regional Projects

New grid exit point at Piako

Executive Summary

2012 Annual Planning Report © Transpower New Zealand Limited 2012. All rights reserved. vi

Summary Figure 2: Transpower’s committed or proposed projects – South Island

South Island Grid Backbone Projects

Clutha–Upper Waitaki Lines Project

HVDC Grid Backbone Projects

HVDC Pole 3 Project

HVDC control system replacement

Otago-Southland Regional Projects

Lower South Island Reliability Project including:

new 220/110 kV interconnection at Gore and 220 kV line connecting Gore to the North Makarewa–Three Mile Hill line

replacement transformers at Roxburgh and Invercargill

new capacitors at Balclutha

series compensation at Three Mile Hill

Nelson-Marlborough projects

Replacement supply transformers at Stoke

Canterbury projects

A third 220/66 kV interconnecting transformer at Bromley

Executive Summary

2012 Annual Planning Report © Transpower New Zealand Limited 2012. All rights reserved. vii

Feedback

We will be using this document as a basis for discussions with our customers and other stakeholders by way of regional forums and other meetings. Feedback received 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 how this document might be improved, please address to:

Grid Development

Transpower New Zealand Ltd

PO Box 1021

Wellington

[email protected]

Executive Summary

2012 Annual Planning Report © Transpower New Zealand Limited 2012. All rights reserved. viii

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Table of contents

2012 Annual Planning Report © Transpower New Zealand Limited 2012. All rights reserved. ix

Table of Contents

2012 Annual Planning Report © Transpower New Zealand Limited 2012. All rights reserved. x

1 INTRODUCTION ..............................................................................................................11

2 FACILITATING NEW ZEALAND’S ENERGY FUTURE ..................................................16

3 EXISTING NATIONAL GRID ...........................................................................................23

4 DEMAND ASSUMPTIONS ..............................................................................................31

5 GENERATION ASSUMPTIONS ......................................................................................35

6 GRID BACKBONE ...........................................................................................................40

7 NORTHLAND REGIONAL PLAN ....................................................................................85

8 AUCKLAND REGIONAL PLAN ....................................................................................106

9 WAIKATO REGIONAL PLAN ........................................................................................127

10 BAY OF PLENTY REGIONAL PLAN ............................................................................149

11 CENTRAL NORTH ISLAND REGIONAL PLAN ...........................................................172

12 TARANAKI REGIONAL PLAN ......................................................................................188

13 HAWKE’S BAY REGIONAL PLAN ...............................................................................203

14 WELLINGTON REGIONAL PLAN .................................................................................219

15 NELSON-MARLBOROUGH REGIONAL PLAN ...........................................................237

16 WEST COAST REGIONAL PLAN .................................................................................249

17 CANTERBURY REGIONAL PLAN ................................................................................261

18 SOUTH CANTERBURY REGIONAL PLAN ..................................................................276

19 OTAGO-SOUTHLAND REGIONAL PLAN ....................................................................294

APPENDIX A GRID RELIABILITY REPORT .................................................................314

APPENDIX B GRID ECONOMIC INVESTMENT REPORT ...........................................346

APPENDIX C FAULT LEVELS.......................................................................................348

APPENDIX D PROJECT CALENDAR ...........................................................................362

APPENDIX E TRANSPOWER’S INVESTMENT APPROVALS PROCESS (IAP) ........372

APPENDIX F GRID SUPPORT CONTRACTS ..............................................................374

APPENDIX G GENERATION SCENARIOS ...................................................................379

APPENDIX H TRANSPOWER PROJECT NAMING .....................................................393

APPENDIX I GLOSSARY .............................................................................................395

APPENDIX J GRID EXIT AND INJECTION POINTS ....................................................400

Chapter 1: Introduction

2012 Annual Planning Report © Transpower New Zealand Limited 2012. All rights reserved. 11

1 Introduction

1.1 Purpose of the Annual Planning Report

1.2 The regulatory framework and the APR’s context

1.3 The planning approach

1.4 Project classification

1.5 Project references

1.6 Cost bands

Transpower owns, maintains, operates and develops New Zealand’s high voltage transmission network (the National Grid).

The Annual Planning Report (APR) provides details of potential transmission investment over the next 15 years. This includes:

the forecast of demand and generation at each grid exit point and grid injection point, respectively, over the next 15 years

information about the existing transmission network

anticipated system constraints and issues over the next 15 years

a summary of potential transmission investment to alleviate the anticipated system constraints and issues, and

other issues impacting on transmission investment.

The information in this APR is based on the New Zealand transmission network as at 28 February 2012.

1.1 Purpose of the Annual Planning Report

We produce the APR to:

provide an indication of the National Grid’s ability to meet forecast demand and generation development over the next 15 years

communicate the potential transmission investment required to alleviate anticipated system constraints and issues to industry regulators and interested parties

provide transparency in terms of the current transmission network development options, and

encourage an efficient investment market via the timely disclosure of grid development options.

This APR is based on a full assessment of the forecast transmission issues, and represents our view of how the National Grid can be developed over the next 15 years in order to provide both reliability of supply and a competitive electricity market. To achieve this, the APR:

presents a grid development plan, which includes possible transmission investments based on preliminary assessments only

4 - detailed analysis occurs

when preparing a Major Capex Proposal (MCP) (see Appendix E for more information), and

aims to provide information to enable interested parties to:

understand the transmission network’s ability to supply their needs

provide input into our transmission network development plans

4 This plan does not imply that we have formed a view about a particular transmission investment, or

that a transmission (versus a transmission alternative) investment is the most efficient solution.



identify and evaluate alternative transmission network investments

identify potentially preferred locations for connecting significant load (e.g. heavy industry)

identify locations that may benefit from demand-side initiatives, and

analyse proposed generation investments, such as preferred locations and the ability of the transmission network to accommodate the proposed generation.

This document is produced for the purposes specified above. Any associated cost information represents a high level and provisional estimate only and therefore should not form the basis for investment decisions. Interested parties should confirm the adequacy of these cost estimates for themselves, or contact us for more detailed information.

1.1.1 Document overview

In this APR:

Chapter 2 ‘Facilitating New Zealand’s Energy Future’ provides a high-level description of our long term goal and the challenges in meeting it.

Chapter 3 ‘Existing National Grid provides a description of the National Grid’s existing configuration, including recently completed projects.

Chapter 4 ‘Demand Assumptions’ provides a high-level description of our demand forecast approach and the various demand forecasts it has developed.

Chapter 5 ‘Generation Assumptions’ describes the development and selection of our generation scenarios.

Chapter 6 ‘Grid Backbone’ discusses the grid backbone’s ability to accommodate the forecast demand.

Chapters 7 - 19 ‘Regional Plans’ describe the specific plan for each region’s transmission network.

Appendices A to J contain supporting information including the Grid Reliability Report (Appendix A) and Grid Economic Investment Report (Appendix B).

Each regional plan also provides an overview of the existing regional transmission network and any anticipated security issues.

1.2 The regulatory framework and the APR’s context

Under Part 12 of the Electricity Industry Participation Code, we are required to publish:

a Grid Reliability Report (GRR), which sets out 10-year forecasts of demand at grid exit points and generation at grid injection points, and whether the National Grid can be reasonably expected to meet (n-1) security requirements, and

a Grid Economic Investment Report (GEIR), which identifies economic investments that Transpower considers could be made in respect of the interconnection assets.

The Annual Planning Report (APR) includes both the GRR and GEIR.

1.2.1 The APR’s context

As owner, operator and planner of the National Grid, we publish the APR annually to assist all market participants understand the extent of potential transmission investment requirements well before their inclusion in a formal Major Capex Proposal (MCP) and submission to the Commerce Commission for approval.

A summary of the GRR information can be found in Appendix A. A summary of the GEIR information can be found in Appendix B.



Major Capex Proposals

Investment proposals that are expected to cost more than $5 million must be submitted to the Commerce Commission as a Major Capex Proposal. This process replaces the previous approval process whereby we submitted Grid Upgrade Plans to the Electricity Commission.

System Security Forecast (SSF)

As the System Operator, we also publish the SSF. The SSF assesses the National Grid’s capability to meet demand as required under Part 7 of the Code, and generally covers a shorter term and operational focus. The latest SSF is available from our System Operator website.

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Transmission Code

We have recently published our Transmission Code which codifies more transparently a set of technical planning requirements that we will apply to ensure the National Grid remains resilient and fit for purpose, and consistent with good industry practice. More information on the Transmission Code can be found on our Grid New Zealand website.

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1.3 The planning approach

Our long-term strategic view is outlined in Chapter 2 ‘Facilitating New Zealand’s Energy Future’. Planning is framed by the long-term view to ensure the appropriate selection of investment for the maintenance of a reliable and secure electricity supply, under a range of system and environmental conditions.

1.4 Project classification

The APR refers to a large number of transmission and generation projects both potential and under way. This section explains how we present projects in the APR in the context of their state of completion, regulatory status, identification references and costs.

1.4.1 State of completion

We 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 classifications

Status Definition

Completed Projects that have recently been completed and are commissioned and operating.

Committed Projects that are currently underway for which either:

the investment has obtained regulatory approval, or

Transpower has entered into a new investment contract with a specific customer or customers.

Proposed

Projects that Transpower has proposed, either:

to the Commission via a Major Capex Proposal, or

as part of our Base Capex funding, or

to specific customer or customers for their agreement.

Preferred

Projects for which Transpower has undertaken detailed analysis and identified a preferred transmission or non-transmission solution.

Possible Projects identified as possible options for future grid upgrade, subject to further

5 http://www.systemoperator.co.nz/publications#cs-85812

6 http://www.gridnewzealand.co.nz/transmission-code



Status Definition

analysis.

Base Capex Development projects forecast to cost less than $5 million, or projects that are replacement or refurbishment on existing assets. These proposed projects are funded under approved Base Capex allowance.

Information only Descriptions of issues that are likely to be managed operationally or by customer driven investment. Specific projects are not formulated either because it is too early to do so, or because alternative low-cost options are evident.

1.4.2 Investment purpose

We classify transmission network development projects by their investment purpose, consistent with our capital expenditure regulatory framework, the Capital Expenditure Input Methodology (Capex IM). Table 1-2 lists the development project classifications.

Table 1-2: Regulatory investment type

Investment purpose

Definition

To meet Grid Reliability Standard (core grid/not core grid)

The Grid Reliability Standard (GRS) is an n-1 standard for assets listed on the Core Grid (Schedule 12.3 of Electricity Industry Participation Code).

For all other assets, the GRS is an economic standard which must demonstrate the proposed investment returns benefits greater than the forecast cost of the investment.

To provide net market benefit

Projects that must demonstrate market benefits greater than costs.

Customer-specific Enhancement projects on assets specific to a customer or group of customers which are agreed and paid for under a new investment contract between Transpower and the customer/group of customers.

Minor enhancement Projects that are less than $5 million and are not Customer-specific.

Replacement Replacement projects on assets driven by condition assessment.

All investments greater than $5 million are subject to the Investment Test of the Capex Input Methodology. Base Capex investments greater than $20 million (replacements) must also be based on economic analysis which is consistent with the Investment Test.

1.4.3 Generation proposals

Table 1-3 summarises the generation proposal classifications used throughout the APR.

Table 1-3: Generation proposals classifications

Status Definition Consideration in APR

Committed Projects for which:

land for the project has been acquired

resource consents have been obtained, and

business approval has been obtained.

The project will be:

considered explicitly in Transpower’s assessment of transmission issues and development options, and

described in the main body of the text.

Likely to proceed

Projects for which the following are under way or close to being obtained:

procuring land for the project

application for resource consent, and

business approval.

The project will be considered as:

part of the generation scenarios described in Chapter 5, or

a sensitivity assessment, if it does not fit within any of the generation scenarios described in Chapter 5. In this case, the APR will describe the project in a separate section under the regional plans, including its possible impact on the transmission network and development



Status Definition Consideration in APR

status.

Possible Projects for which the following are in their initial stages or have yet to commence:

procuring land for the project

application for resource consent, and

business approval.

Considered as part of the generation scenarios described in Chapter 5.

1.5 Project references

We apply a unique project reference for each provisional, preferred, proposed or committed project. These references, which feed through our planning, design, build and maintenance operations, should be used when requesting further information from us about any specific project. See Appendix H for more information about how these codes are determined and interpreted.

1.6 Cost bands

Where investment is required to resolve identified issues, an indicative cost has been developed. The indicative costs represent the expected cost (in 2012 dollars) to fully implement 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 uncertainties involved, but for some projects the property costs can significantly impact the overall cost.

Table 1-4 lists the indicative cost bands for transmission network development, reflecting the fact that these are broad estimates only (rather than inaccurate actual dollar figures).

Table 1-4: Indicative cost bands

Identifier Indicative cost band

A Up to $5 million

B $5 - $10 million

C $10 - $20 million

D $20 - $50 million

E $50 - $100 million

F $100 - $300 million

G $300 million plus

Chapter 2: Facilitating New Zealand’s Energy Future


2 Facilitating New Zealand’s Energy Future

2.1 Introduction

2.2 Transmission Tomorrow – a progress report

2.3 Generation and grid compatibility

2.4 When do we invest?

2.1 Introduction

The transmission network is central to the delivery of least cost electricity to New Zealand’s homes and industry. The transmission network enables the economic dispatch of least cost electricity through the electricity market from diverse generation sources. The transmission network also enables a greater range of ancillary services such as frequency keeping, spinning reserve and interruptible load to provide the support needed to keep the network secure.

The requirements placed on the transmission network evolve over time. The assets and operation of the power system of the 1950s is different to today. The requirements of the transmission grid will continue to evolve in ways that we can not foresee today:

the historic link between load growth and GDP may be changing, creating uncertainty over how much electricity use will grow;

the nature of demand for electricity will change, particularly the shape of the demand curve on a daily and annual basis;

how and where electricity is generated will change, both to replace retiring generation and to meet load growth; and;

new technologies will change how electricity is generated, transmitted and used.

We are investing in long-term strategies, platforms and technologies to guide and inform our transmission planning. The future is inherently uncertain. Our planning must reflect this and position us to be able to meet all possible eventualities. This will allow us to make best use of our existing assets and provide better options when new assets are needed. This will reduce the cost and footprint of the grid for future generations while providing a grid that is fit for purpose.

In early 2011, we launched Transmission Tomorrow, which describes the strategies, platforms and technology we use now and will require in the future. Where relevant to the Annual Planning Report, their effect is reflected in Chapter 6 for the grid backbone and Chapters 7-19 for the regional grids.

In this chapter:

Section 2.2 is a progress report on Transmission Tomorrow

Section 2.3 describes emerging and potentially significant interactions between generation technology and the grid.

Section 2.4 concludes with when we invest.

2.2 Transmission Tomorrow – a progress report

Since releasing Transmission Tomorrow, we have made progress on the strategic initiatives. Several initiatives are summarised below.



2.2.1 Variable line ratings - operating assets to ratings

The initiative

Most of our transmission lines are operated to pre-calculated, seasonal ratings. Pre-calculated ratings are design ratings which reflect a least favourable combination of operating conditions (such as ambient temperature and wind) for that season. If the ambient conditions at a point in time are more favourable than assumed for the design ratings, then transmission lines can carry more power than the design rating.

In November 2011 (a month ahead of schedule), we implemented interim variable line ratings (iVLR) on six transmission circuits. The use of iVLR provides the circuits with up to 84 different ratings at different times of day and month in the year. The ambient conditions are determined for a 500 metre grid along the line using historic weather data from NIWA. The ratings are then determined from the maximum design operating conditions and line ground clearances measured from aerial laser surveys.

iVLR provides an average capacity gain for each circuit of between 8% and 16%.

The trial is expected to continue for at least two years, with the experience helping to frame the rollout of variable line ratings across the entire transmission network. We expect to roll out variable line ratings for all lines in conjunction with the next major upgrade of the System Operator’s software tools, within the planning period. The ambient conditions used to calculate these ratings will be based on shorter periods and actual regional data and forecasts.

Operating experience

The following circuits presently have VLR applied:

Clyde–Roxburgh 1 and 2 – part of the 220 kV grid in the Otago-Southland area

Wairakei–Ohakuri and Atiamuri–Ohakuri – part of the 220 kV “Wairakei Ring” northwest of Taupo, and

Otahuhu–Whakamaru 1 and 2 – part of the 220 kV grid into Auckland.

VLR assists in management of the low hydro generation in the Otago-Southland area by increasing the average transmission capacity from the Waitaki Valley to the Otago-Southland area during the time before the capacity of the Clyde–Roxburgh 1 and 2 circuits is increased through the installation of duplex conductors.

The Wairakei Ring area has significant hydro and geothermal generation, with more geothermal generation under construction or planned. VLR allows more flexible dispatch of generation with the existing transmission system, applying downward pressure on energy prices. There is an approved project to increase transmission capacity by building a higher capacity transmission line in the Wairakei ring. VLR on the Wairakei–Ohakuri and Atiamuri–Ohakuri circuits will enable additional capacity and better utilisation of these existing lines. VLR will also further increase the overall transmission capacity through the Wairakei ring.

VLR on the Otahuhu–Whakamaru 1 and 2 circuits is primarily intended to provide increased transmission capacity during maintenance outages of other 220 kV circuits supplying Auckland.

Planning experience

VLR also requires a change in transmission line rating methodology. The change in rating methodology increases the average capacity of a transmission circuit, but may also decrease the rating of some circuits for certain periods during the day and times of the year. The new rating methodology is yet to be applied to transimission circuits that are not part of our iVLR work.



The future full adoption of VLR is not expected to be an issue for the grid backbone, as most circuits gain capacity and the effects of any decrease will be limited to changes in generation dispatch.

VLR may reduce the capacity at certain times of some radial circuits which supply load. Typically, VLR will increase capacity during winter morning and evening peaks, deferring investment to meet those peaks. However, in some cases, the circuit rating may decrease during summer mornings when air temperatures and solar radiation are higher and wind speeds are lower. This could bring forward the the need for investment in transmission or non-transmission options to securely supply the load.

2.2.2 Demand-side response – enabling consumer response

The initiative

Demand-side response is a framework where loads can be reduced (either individually or as part of an aggregated group) to the extent and times required by the grid. The magnitude and duration of any load reduction is to pre-agreed contractual terms.

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 manage outages for maintenance, either maintaining security during the outage or avoiding the need for additional investment to allow maintenance outages.

Progress to date

Upper South Island distribution companies worked with us to collaboratively manage regional demand to reduce system peaks. This initiative has reduced the peak demand in the region by 3 percent, deferring the need for grid upgrades by at least two years.

As part of the Upper North Island Reactive Support Project (see Section 6.4.1) we issued a Request For Proposals for demand-side response. The proposals received were all uneconomic, which was an unexpected result. Part of the problem was the contractual framework and the platform to implement demand-side response.

For demand-side response to be effective and economic, it needs to be established as a sustained programme and not as a reactive “just-in-time” measure. Requiring proponents to provide adequate and verifiable demand-side response within a condensed timeframe and for relatively short contract periods results in prices being driven upwards.

To support the development of demand-side response in New Zealand, we are currently developing a Demand Response Management pilot system, which is planned to be ready for testing in July 2012. Along with a common customer interface, it will assist in the calling and coordination of demand-side response. While initially for the Upper North Island, the technology provides for a platform from which we can support and enable future demand-side initiatives in all parts of New Zealand.

2.2.3 Corridor management of transmission routes – secure long term access to transmission routes

The initiative

National and local policy-makers recognise the need to plan long-term for infrastructure

7. Local authorities are now considering utility corridors in their

long-term plans. This provides a mechanism by which transmission line corridors can be managed so that only compatible developments are built under and adjacent to

7 The 2008 introduction of the National Policy Statement on Electricity Transmission (NPSET) provides increased protection against activities incompatible with transmission lines, such as underbuild.



existing transmission lines. This will preserve our ability to operate, maintain and upgrade our transmission lines

8, which are irreplaceable assets.

Progress to date

As indicated in Transmission Tomorrow, we are developing a companion document for the APR that sets out our long term corridor management strategy for transmission line routes. We focussed our efforts initially on the Auckland region to coincide with our involvement in the development of the Auckland Council’s spatial plan. We will publish the first edition of the companion document later this year.

2.2.4 Voltage support - maximising capability of transmission routes

The initiative

On longer circuits, the full thermal capability of transmission lines cannot be used due to voltage issues. Using reactive compensation to address voltage issues allows lines to operate closer to their thermal rating.

Voltage stability is a significant issue for the Upper North Island and the Upper South Island (refer to Section 6.4.1 and Section 6.6.1 respectively). To address the voltage issues we have static reactive support from switched capacitors and dynamic reactive support from devices such as synchronous condensers, static var compensators (SVCs) and STATCOMS at several substations within an area. Coordinating the reactive devices is not straight forward and must be managed carefully and safely. This requires automatic control via area wide reactive power controllers (RPCs).

Progress to date

Late last year, we commissioned our first area wide RPC, for the Christchurch area. We will also commission a similar area wide RPC for the Auckland area in 2014. This will help the system operator to better manage area wide voltage, eliminating the need for manual switching and thus enabling greater use of reactive compensation and higher loading on lines.

2.2.5 Other initiatives

Resilience of the grid

Grid reliability is inherent in much of what we do; however, maintaining and improving resilience in a more highly loaded grid requires special attention, especially for High Impact Low Probability (HILP) events.

Initiatives in the last year which increase the resilience of the grid include the following:

The protection and control systems at Penrose substation in Auckland are being separated into two different buildings to guard against the loss of all systems at this critical site. This is a low cost improvement as it is being done in conjunction with work required as part of the North Auckland and Northland (NAaN) project.

An investigation is presently underway to improve security of the Wilton 110 kV bus. This bus is the “hub” for the supply to Wellington city. The investigation is being done in conjunction with the need to modify the bus to allow easier and safer maintenance and equipment replacement due to condition assessment.

A HILP study was completed for Islington substation, which is a critical node for supply to the Upper South Island. The study highlighted cost effective investments which improve the resilence of the transmission network to HILP events. These improvements will be included in the Upper South Island Stability

8 About 95% of our line corridors are controlled by the Electricity Act 1992 Part 3. About 5% of our new line corridors are controlled by ownership or easements by Transpower.



major capital proposal (anticipated to be submitted to the Commerce Commission around June this year).

Single phase transformer replacement

We have a long term transformer fleet replacement programme to improve asset performance. We will replace approximately 25 single phase interconnecting bank and supply transformers with modern three phase transformers over a three-year period from July 2012 to June 2015.

This renewal programme will result in a more reliable grid, requiring fewer and shorter outages for maintenance and with fewer faults. The replacement transformers will have higher ratings where capacity issues are identified as part of the APR process.

Integrating generation and transmission

As part of replacing HVDC Pole 1 with the new Pole 3 project, the HVDC controls will also be replaced, which allows greater functionality and flexibility. For example, at present there are separate frequency keeping and reserve markets in the North and South Islands. The replacement HVDC controls will allow a single market.

The new HVDC controls will also enable automatic controls to be added as required in future. For example, this could be to continuously balance North Island wind generation with South Island hydro, or automatically adjusting HVDC transfer in response to outages in the North or South Islands (to the extent that the other island can absorb the change). To make full use of the increased HVDC functionality may also require development of the System Operator’s tools, or rule changes for provision of ancillary services.

The HVDC is a clear example of how the rest of the grid may develop. It uses modern power technology and controls, a market framework, advanced analysis, and sophisticated software tools for the System Operator to maximise the benefit of the electricity system.

2.3 Generation and grid compatibility

Transmission Tomorrow looks forward at how transmission services must develop and Transpower’s role in achieving this. Generation development also has an important role, and this section highlights items that may be significant in future as the generation technology and generation mix change.

There are good reasons why generation technology and the generation mix are changing. They may require changes to how the the generation is integrated into the power system and how it is operated. This is ‘business as usual’, as New Zealand has a long history of integrating and managing new technologies into the power system. Examples include the original and hybrid upgrade of the HVDC link, the introduction of large thermal generating units (Huntly), the first combined cycle gas turbine (in Taranaki), and the the wind farm at Taurarua.

2.3.1 High voltage fault ride-through

New Zealand’s transmission grid is “long and thin”, and parts are heavily loaded with high levels of reactive compensation for voltage support. An inherent characteristic of power systems with increasing levels of reactive compensation is the potential for high Transient Over Voltage (TOV)

9 when there is a sudden reduction in load.

9 TOV is a phenomenon where the voltage jumps to a very high value in the first half cycle following

the sudden reduction in load. The natural response from power system dynamics and fast acting controls then rapidly decreases the TOV to merely a high value over approximately 25 cycles.



High TOV can cause generating units to trip to protect themselves from damage. The tripping of the HVDC link can cause high TOV in the lower North Island (up to Bunnythorpe and Stratford substations, and other substations in the area) which can cause regional generation to trip. This has not been a concern in the past as there was relatively little generation in the Wellington region. The connection of wind farms near Wellington and the proposals for more wind farms in Wellington and the Wairarapa 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 of HVDC transfer but potentially significant generation in the Wellington region. Such a risk is managed through the procurement of sufficient instantaneous reserves to cover the loss of the HVDC link and generation or by reducing HVDC transfer and generation in the Wellington. These measures can have high market costs. High TOV can also be mitigated by investment in transmission assets which will have considerable costs. A more cost effective measure for New Zealand may be to have generation plant located in regions with high TOV being capable of remaining connected during and after the TOV event and providing support during the event to reduce the extent of the high TOV.

2.3.2 Recovery following a fault

Faults are a normal and expected part of operating the power system. Generation plays an important part in assisting the power system in recovering from faults. One type of fault is the loss of generation infeed. This could be caused by the loss of a generating unit, a bus with generating units connected, or transmission circuit(s) carrying power from an area with nett generation export to an area of nett load. The immediate effect following the loss of generation infeed is a fall in frequency. Generation that remains connected to the grid has an important role in arresting frequency fall and restoring frequency.

The System Operator ensures that there are sufficient instantaneous reserves (IR) (partially loaded generating units and interuptible load) available to halt the fall in frequency 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 the North Island, the largest risk is usually the sudden loss of a large thermal generating unit (up to 400 MW).

Other factors such as governor action on generating units and system inertia are also important. Hydro and fossil fuelled generation will automatically use more ‘fuel’ and increase output during falls in frequency as a result of free governor action. System inertia (the ability of the system to resist or slow down the fall in frequency) affects the amount of reserves required. Falls in frequency following the loss of generation are faster with lower system inertia. Halting the fall then requires more fast acting IR.

The changing nature of the generation fleet in the future will affect the amount of required instantaneous reserves:

The displacement of large thermal generating units by renewable generation will tend to reduce the size of the risk of a generating unit trip and hence reduce the required IR over time. However, the IR required to cover the tripping of a bus or transmission circuits may not reduce significantly. The largest individual generating units using renewable ‘fuel’ tend to be smaller compared with the largest generating units which are fossil fuelled (up to about 80 MW (South Island) and 400 MW (North Island)).

Increased amounts of renewable generation with less ability to provide support during falls in frequency will increase the need for instantaneous reserves in the future. Geothermal, wind and in the future marine energy and photovoltaic cannot 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 ‘fuel reserve’ for sustained additional generation to provide instantaneous reserve.



Some forms of renewable generation have less than the hydro or thermal plant which they displace. This reduction in system inertia will increase the need for instantaneous reserves.

Wind and other forms of renewable generation could also provide instantaneous reserves if they ‘spill’ some of their ‘fuel’, so an instantaneous increase in generation output 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 the instantaneous reserve costs. Similarly, wind and other forms of renewable generation can provide “pseudo interia”. This is achieved by allowing the wind turbines 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 other renewable generation sources to provide instantaneous reserves and pseudo interia in future. This is especially likely if enough new geothermal and wind farm generating stations are built so that during low load periods most hydro and fossil fuelled power stations are off.

2.3.3 Balancing generation

The power system must be continuously operated to balance supply and demand for electrical energy. However, wind and some other forms of renewable generation are intermittent or cannot have their outputs readily controlled. This places extra demands on the real-time operation of the power system, as some overseas utilities are experiencing with wind generation supplying close to all overnight load.

One strategy to manage the diverse characteristics of generation is to implement Automatic Generation Control (AGC). AGC, already used outside New Zealand, is a wide-area control to change generation output on a near continuous basis. One use of AGC is to balance the output from variable generation by changing the output from dispatchable generation.

It is also expected that more use will be made of demand-side response to balance generation. This will develop as technology advances and markets mature.

2.4 When do we invest?

The underlying principle for transmission investment in New Zealand is that the transmission investment should provide the best net benefit.

Transmission Tomorrow identified existing and future drivers, including technology, which may or will shape the grid of the future. These technologies increase the options available for enhancing the grid where necessary.

Demand-side response may be particularly useful for reducing the cost of new investment. Many projects are commissioned ‘early’ to account for the year-to-year variability in peak load growth and the risk of project delays. Demand-side response has the potential to cover this uncertainty, allowing new investment to be deferred for a 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 additional investment to allow maintenance outages.

It is important that we maintain options like using demand-side response to deal with the unexpected. Transmission planning is often said to be about minimising the mistakes from being wrong about the future. Developing our options whether by way of technology, future corridor protection or demand-side initiatives will help ensure that tomorrow’s consumers will have a fit-for-purpose transmission grid at the least possible cost.

Chapter 3: Existing National Grid


3 Existing National Grid

3.1 Introduction

3.2 Load and generation

3.1 Introduction

This chapter provides an overview of New Zealand’s existing National Grid as at 28 February 2012 with respect to load and generation. New Zealand’s National Grid consists of the:

HVAC transmission network, and

an inter-island HVDC link.

3.1.1 The AC transmission network

New 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 full length 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 the introduction of the 220 kV grid from the 1950s onwards. The 110 kV system is now primarily used for transmission to some regions that do not have 220 kV, or for sub-transmission to substations within a region.

Figure 3-1 and Figure 3-2 show maps of the transmission network for both the North and South Islands.



Figure 3-1: New Zealand’s North Island transmission network



Figure 3-2: New Zealand’s South Island transmission network



3.1.2 The HVDC Link

The HVDC link connects the North and South Island transmission networks.

This bi-directional link runs from Benmore, in the South Island, where there is an AC/DC converter station. There is a 534 km transmission line between Benmore and Fighting Bay (Marlborough), a 40 km submarine cable between Fighting Bay and Oteranga Bay across the Cook Strait, and a further 37 km transmission line into Haywards substation north of Wellington. At Haywards substation, there is another AC/DC converter station.

HVDC power flow is predominantly from the South Island to the North Island. Power flow is from north to south when it is necessary to conserve South Island hydro resources as part of an efficient generation process, or to supply South Island demand 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 conversion technology. An older technology (mercury arc valve) pole (Pole 1), operating at 270 kV, was stood down in September 2007, with half being totally decommissioned, and the remaining half pole to operate on a limited basis.

10 We are also mid-way

through construction of a $672 million project to replace Pole 1 by 2012 with a new pole (the HVDC Inter-island Link Project).

Table 3-1 lists the pole capacities for converting power from AC to DC and from DC to AC for both poles. Total pole capacity equates to the total capacity of the link.

Table 3-1: Converter ratings and pole capacities

Pole Commissioned Converter type Transmission capacity

Operation

Pole 1 (half pole) 1965 Mercury arc valves 270 MW1 Available for limited

peak operation only

Pole 2 1991 Thyristor valves 700 MW2

Full

Total possible transmission capacity 970 MW

Notes:

1. In December 2007, Transpower announced it would decommission half of Pole 1, after standing down the full Pole 1 in September 2007.

2. In November 2007, Transpower reconfigured the three operational undersea cables of the HVDC link to increase the capacity of the south to north transfer of Pole 2 to 700 MW.

3.1.3 Transmission network asset profile

Table 3-2 provides a summary of the transmission network’s assets.

Table 3-2: Transmission network assets

Asset description Detail

Length of HVAC and HVDC transmission line 11,730 route km

Number of substations (including HVDC) 178

HVAC transmission line voltages 220, 110, 66, 50 kV

HVDC transmission line voltages 350, 270 kV

HVDC link capacity 700 MW1

10

The remaining half of Pole 1 is available under limited conditions: for normal operation, in response to Grid emergencies, and for testing. The conditions include north transfer between 130 MW and 200 MW, with automatic controls unavailable (except frequency modulation). Other conditions include a limit on the number of starts, minimum operating time per start and cumulative operating time.



Asset description Detail

Capacitor banks 69

Transformers (banks) 360

Synchronous condensers 10

Static Var Compensators/STATCOMS 4

Notes:

1. Pole 1 was stood down from operation in September 2007. One half of this Pole will be made available for limited use to supply peak load periods. Approximately 270 MW additional will be made available by this action.

3.1.4 Recently completed transmission upgrade projects

Table 3-3 lists the transmission upgrade projects completed since the last Annual Planning Report (31 March 2011).

Table 3-3: Projects completed since the 2011 Annual Planning Report

Project name

Islington reactive power controller

North Island Grid Upgrade project:

convert the existing 110 kV Pakuranga substation to 220 kV

convert the existing 110 kV Otahuhu–Pakuranga line to 220 kV

Pakuranga 220/33 kV supply transformer

Bombay 110 kV bus security upgrade

Redclyffe 110 kV bus security upgrade

West Coast Grid Upgrade project:

Inangahua–Reefton 2 circuit extension to Dobson

Dobson interconnecting transformer

Woodville supply transformer replacement and a second supply transformer

Waverley supply transformer replacement

110 kV Hawera–Stratford reconductoring

110 kV Wanganui–Waverley reconductoring

Table 3-4 lists the transmission upgrade projects that have commenced but are not yet commissioned.

Table 3-4: Projects commenced (not yet commissioned)

Project name Expected completion date

North Island Grid Upgrade project – new 220/400 kV double circuit transmission line (partially underground cables) from Whakamaru to Pakuranga

2012

Bay of Plenty Interconnection Upgrade project including:

New 220/110 kV transformers at Kaitimako

Converting the Hairini–Tarukenga line to 220 kV operation

2012

2012

110 kV Hawera–Waverley reconductoring 2012

North Auckland and Northland grid upgrade project including:

new 220 kV underground cable between Pakuranga and Penrose

new 220 kV underground cable between Penrose and Albany

2013

2013

Replacement of 220 kV Wairakei–Whakamaru transmission line 2013

HVDC Pole 3

Stage 1

Stage 2

2012

2014

Upper North Island Dynamic Reactive Support Project 2013-14



Project name Expected completion date

Lower South Island Reliability Project 2012-17

Clutha–Upper Waitaki Lines Project1 2013-TBC

Masterton supply transformer replacement 2012

Tarukenga interconnecting transformer replacement 2013

A third 220/66 kV transformer at Bromley 2013

Opunake–Stratford A reconductoring 2013

New grid exit point at Piako 2013

New grid exit point at Hobson Street 2013

New grid exit point at Wairau Road 2013

Stoke supply transformer replacement 2014

Notes

1. Some components of this project will be subject to review by June 2013

3.2 Load and generation

New Zealand’s transmission network is regarded as narrow and longitudinal, with areas of demand (load) commonly some distance from the areas of significant generation. Consequently, the transmission network is essential in complementing generation to bring the power to where it is needed.

A particular feature of the National Grid, and a key benefit for a sustainable New Zealand, is its ability to provide New Zealanders with access to renewable generation. Typically, the remote areas of generation connected by the National Grid are renewable (e.g. hydro in the Waitaki Valley, wind in the Tararuas, and hydro and geothermal in the Central North Island).

Figure 3-3 shows a simplified map of load, generation, and the transmission network’s grid backbone. For more information see Chapter 4 for the demand assumptions, Chapter 5 for the generation assumptions and Chapter 6 for the transmission backbone.



Figure 3-3: Load, Generation and the Grid Backbone

Many 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, delivering power from the hydro generation in the South Island to the North Island through the HVDC link, which also balances demand between the islands. North to south transfers have been occurring for longer periods in recent years. They occur more frequently during dry years where hydro generators in the South Island try to conserve 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 generation embedded within these networks). Demand has been flat over the last 7 years particularly when compared with the strong growth seen in earlier decades. In recent years demand has been affected by the ongoing impacts of the global recession, the winter savings campaign in 2007, a reduction in demand at Tiwai Aluminium Smelter in 2008 and the impact of the Christchurch earthquakes.



Figure 3-4: New Zealand energy use for last seven years

Chapter 4: Demand Assumptions


4 Demand assumptions

4.1 Introduction

4.2 Energy use versus peak demand

4.3 Peak demand forecast methodology

4.4 Comparison with the 2010 and 2011 APR demand forecast

4.1 Introduction

This chapter provides an overview of the grid exit point demand forecasts used in the planning studies for this report.

Consideration of the National Grid’s future adequacy requires a view of future electricity demand. In line with international Good Electricity Industry Practice (GEIP) and to ensure the timely construction of new transmission, we use a prudent demand forecast for our planning.

For this publication of the Annual Planning Report we have employed a new approach to derive our forecasts. The new approach takes account of more recent information and builds on the work of the now disestablished Electricity Commission. We consulted on our new approach in May 2011 and relevant discussion and documentation can be found at http://www.gridnewzealand.co.nz/project-inputs.

Our prudent peak forecasts can be interpreted as representing a 10% probability of exceedance (POE) forecast for the first 5 years of the forecast period (until 2017). In other words, until 2017 one would expect actual demand to exceed the forecast in one year out of ten. Post 2017 we assume an expected (or mean) rate of growth such that the probability of exceedance increases over time. We consider this is an appropriate basis on which to conduct our planning.

Both the Annual Planning Report (APR) and Grid Reliability Report (GRR) require a grid adequacy assessment at the grid exit point level.

This is in accordance with Rule 12.76, Part 12 of the Electricity Industry Participation Code, which states:

Part 12 Grid reliability reporting

12.76 Transpower to publish grid reliability report

12.76(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 10 years

12.76(1)(b) a forecast of supply at each grid injection point over the next 10 years

12.76(1)(c) whether the power system is reasonably expected to meet the N-1 criterion, including in particular whether the power system would be in a secure state at each grid exit point, at all times over the next 10 year, and

12.76(1)(d) proposals for addressing any matters identified in accordance with rule 12.76(1)(c).

12.76(2) Transpower must publish a grid reliability report no later than 2 years after the date on which it published the

http://www.gridnewzealand.co.nz/project-inputs



previous grid reliability report, or such other date as determined by the Electricity Authority.

12.76(3) If there is a material change in the forecast demand at a grid exit point or in the forecast supply at a grid injection point in the period to which the most recent grid reliability report relates, Transpower must publish a revised grid reliability report as soon as reasonably practicable after the material change.

Appendix A contains the detailed prudent peak load forecasts by region and grid exit point.

4.2 Energy use versus peak demand

The demand for electrical energy in New Zealand varies from month-to-month, day-to-day, and from hour-to-hour. For example, residentially, much more energy is consumed between the hours of 7:00 – 9:00 am and 5:00 – 8:00 pm than at other times of the day, due to heavier domestic appliance use. The demand at peak times of the day can 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 use

Because electricity cannot be stored practically in the quantities required, meeting electricity 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 as consumption over time, in MWh. Transmission planning requires an analysis of the transmission network’s adequacy in terms of meeting a forecast of peak demand, rather than energy.

4.3 Peak demand forecast methodology

Our new approach to demand forecasting uses both top-down modelling of national and regional peak and energy demand, and bottom-up modelling of grid exit point

Typical Daily Load Profile

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peak demand. The top-down models employ a suite of models and use Monte Carlo techniques to randomly vary components of the models to assess the variability that can be expected in future peak demand. More details are available at http://www.gridnewzealand.co.nz/project-inputs.

At grid exit point level we have employed simpler regression techniques on historical grid exit point demand data to project expected and prudent peaks. We have also sought customer views on grid exit point demand and in many cases modified our forecasts to include specific load information from our customers. See the relevant region’s chapter for more information about specific amendments (Chapters 7-19).

Our forecasting structure also allows us to project each grid exit point contribution to regional and island peak demand. These will typically be less than grid exit point peak demand and are calibrated to sum to the regional and island peak demands produced by our top-down models.

4.3.1 Customer consultation

We believe customers are best placed to provide information about future demand in their transmission networks. To this end, we issued a prudent forecast for comment to our customers in August 2011, inviting comments and adjustments where applicable. Around 25 responses were received. Additional comments had been obtained in 2010 during the consultation for the 2011 APR forecast (thirty two responses were received). We have endeavoured, where reasonable and practical, to incorporate this feedback.

We are committed to further consultation with customers with regard to our peak load forecasts and we welcome ongoing dialogue on the nature and timing of changes to grid exit point demand.

4.4 Comparison with the 2010 and 2011 APR demand forecast

Figure 4-2 shows a comparison of the 2012 APR peak demand forecasts with those from the previous two years.

Figure 4-2: Comparison of 2012 APR prudent peak demand forecast with two previous APRs

At a national level, the 2012 prudent forecast is significantly lower than the 2011 and 2010 forecasts. Our 2012 forecast starts at a lower level, which mostly results from the lower growth seen from 2006 but is also influenced by changes in our forecast

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1995 2000 2005 2010 2015 2020 2025

Load (MW) New Zealand Prudent Peak Electricity Demand Forecast

SOO 2010 APR 2010 APR 2011 APR 2012 Actual

http://www.gridnewzealand.co.nz/project-inputs



methodology. The forecast now grows at an average rate of 1.7% per annum from 2012 to 2027.

The demand seen in recent years has been affected by a range of factors. The first part of 2008 was affected by dry weather, resulting in higher market prices and a conservation campaign, which both reduced demand. In 2009, demand was low compared with 2006 and 2007 due in part to reduced Tiwai production. Later, the financial crisis reduced economic activity affecting commercial/industrial demand. This impact has continued into 2009 and 2010.

In 2011, we have seen a higher national peak recorded. This occurred during the unusual polar weather event that affected the whole country in mid-August. Heavy snow fell over much of the country and numerous new August low temperature extremes were observed driving higher household heating demand. At a regional level there are also differences in our prudent forecasts when compared to last year. See the relevant regions’ chapters for more information.

Chapter 5: Generation Assumptions


5 Generation assumptions

5.1 Introduction

5.2 Generation capacity assumptions

5.3 Use of the generation capacity assumptions

5.1 Introduction

This chapter sets out the planning assumptions used to forecast future electricity generation at each grid injection point.

Transpower undertakes grid planning to ensure that:

electricity demand is met reliably

the generation investment market is efficient for all market participants, and

the energy market is competitive for all consumers.

As a result, consideration of the National Grid’s future adequacy requires a view of not only future electricity demand – a requirement of both the Annual Planning Report (APR) and the Grid Reliability Report (GRR) – but also future electricity generation at each grid injection point.

Future generation will comprise a mix of existing generation (adjusted for decommissioning), new committed generation, and other potential generation developments. The uncertainty surrounding future generation requires the consideration of several possible generation scenarios.

We have considered five scenarios that are essentially an updated version of the scenarios in the Electricity Commission’s 2010 Statement of Opportunities (SOO).

5.2 Generation capacity assumptions

Generation capacity assumptions derive from a combination of:

existing grid connected generation, (assumed to be available, at its existing capacity, 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 publicly notified capacity, for the duration of the planning period from commissioning and includes expansions of existing grid-connected generation)

committed decommissioned generation, (existing generation that we have been notified will be decommissioned, which is excluded from its publicly notified decommissioning date, for the balance of the planning period), and

new generation forecasts, (forecast new generation, which is included from the assumed commissioning date, at assumed capacities, for the duration of the planning period from commissioning. Decommissioning may occur as well).

5.2.1 Existing grid connected generation

Table 5-1 lists the operating capacities of existing grid-connected generation. Installed capacities may differ in some cases.



Table 5-1: Existing grid-connected generation

Generation plant Region Type Operating capacity in MW

Grid injection point

Glenbrook1 Auckland Cogen 74 Glenbrook

Otahuhu B Auckland Gas - CCGT 380 Otahuhu

Southdown Auckland Cogen 170 Southdown

Kawerau Bay of Plenty Geothermal 105 Kawerau

Kinleith Bay of Plenty Cogen 28 Kinleith

Matahina Bay of Plenty Hydro 72 Matahina

Wheao/Flaxy Bay of Plenty Hydro 24 Rotorua

Aratiatia Central North Island Hydro 78 Aratiatia

Mangahao Central North Island Hydro 37 Mangahao

Ohaaki Central North Island Geothermal 46 Ohaaki

Poihipi Central North Island Geothermal 51 Poihipi

Rangipo Central North Island Hydro 120 Rangipo

Tararua III2 Central North Island Wind 93 Bunnythorpe

Te Apiti Central North Island Wind 90 Woodville

Tokaanu Central North Island Hydro 240 Tokaanu

Wairakei Central North Island Geothermal 161 Wairakei

Nga Awa Purua Central North Island Geothermal 140 Nga Awa Purua

Kaitawa Hawkes Bay Hydro 36 Tuai

Piripaua Hawkes Bay Hydro 42 Tuai

Tuai Hawkes Bay Hydro 60 Tuai

Whirinaki Hawkes Bay Diesel 155 Whirinaki

Kapuni Taranaki Cogen 25 Kapuni

Kiwi Dairy Taranaki Cogen 70 Hawera

Patea Taranaki Hydro 31 Hawera

Taranaki CC Taranaki Gas - CCGT 385 Stratford

Stratford Peaker Taranaki Gas - CCGT 200 Stratford

Arapuni Waikato Hydro 197 Arapuni

Atiamuri Waikato Hydro 84 Atiamuri

Huntly Waikato Coal 1000 Huntly

Huntly e3P Waikato Gas - CCGT 385 Huntly

Huntly P40 Waikato Gas - OCGT 50 Huntly

Karapiro Waikato Hydro 90 Karapiro

Maraetai Waikato Hydro 360 Maraetai

Mokai Waikato Geothermal 112 Whakamaru

Ohakuri Waikato Hydro 112 Ohakuri

Waipapa Waikato Hydro 51 Maraetai

Whakamaru Waikato Hydro 100 Whakamaru

West Wind Wellington Wind 143 West Wind

Argyle/Wairau Nelson/Marlborough Hydro 11 Argyle

Cobb Nelson/Marlborough Hydro 32 Cobb

Coleridge Canterbury Hydro 45 Coleridge

Aviemore South Canterbury Hydro 220 Aviemore





Benmore South Canterbury Hydro 540 Benmore

Ohau A South Canterbury Hydro 264 Ohau A

Ohau B South Canterbury Hydro 212 Ohau B

Ohau C South Canterbury Hydro 212 Ohau C

Tekapo A South Canterbury Hydro 25 Tekapo A

Tekapo B South Canterbury Hydro 160 Tekapo B

Waitaki South Canterbury Hydro 105 Waitaki

Clyde Otago/Southland Hydro 432 Clyde

Manapouri Otago/Southland Hydro 840 Manapouri

Roxburgh Otago/Southland Hydro 320 Roxburgh

Waipori3 Otago/Southland Hydro 84 Halfway Bush

1. Another 38 MW cogen unit at the location is embedded generation.

2. Tararua stages I and II are both embedded generation.

3. Partly embedded.

5.2.2 Committed new generation

Committed projects are those which are reasonably likely to proceed and where the following are satisfied:

all necessary resource and construction consents have been obtained

construction has commenced, or a firm date set

arrangements for securing the required land are in place

supply and construction contracts have been executed, and

financing arrangements are in place.

Table 5-2 lists committed grid-connected generation projects.

Table 5-2: Committed new generation



Waitara McKee peaker Taranaki Gas-fired OCGT 100 Motunui Deviation

Kawerau Norske Skog Bay of Plenty Geothermal 25 Kawerau

Ngatamariki Central North Island Geothermal 82 Nga Awa Purua

Te Mihi Central North Island Geothermal 166 Te Mihi

5.2.3 Decommissioned generation

Generation forecasts must also account for decommissioned generation. There has been no decommissioning of generation in 2011.

5.2.4 New generation forecasts

This year’s APR uses a new set of scenarios, which are an updated version of the scenarios in the Electricity Commission’s 2010 Statement of Opportunities (SOO).

What are generation scenarios?

Generation scenarios represent possible future generation outcomes, resulting from making 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 Path

Scenario 2: South Island Wind

Scenario 3: Medium Renewables

Scenario 4: Coal

Scenario 5: High Gas Discovery

Scenario 1 – Sustainable Path

New Zealand embarks on a path of sustainable electricity development and sectoral emissions reduction. Major development of renewable generation takes place in both the North and South Islands – mainly hydro, geothermal, and wind, but tidal and wave energy, solar power and biomass cogeneration also feature. Renewable energy production exceeds 90% of total generation from 2020 onwards. Baseload thermal generation is largely phased out, but new thermal peakers are required. The demand side also has an important role to play in balancing intermittent generation and

meeting peak demand.

Scenario 2 – South Island Wind

There is extensive wind and hydro generation development, with a focus on the South Island and lower North Island. Geothermal resources in the central North Island are developed more slowly than in the other scenarios. Renewable energy production exceeds 85% of total generation (on average) from 2020 onwards. Baseload thermal generation is considerably reduced, but there is substantial investment in thermal peaking generation and demand-side participation.

Scenario 3 – Medium Renewables

A ‘middle-of-the-road’ scenario. There is moderate geothermal and wind development, mainly in the North Island, but little new hydro generation. Baseload thermal generation is considerably reduced, but new thermal peakers are required. The demand side contributes less than in the other scenarios. The NZAS aluminium smelter is progressively phased out between 2022 and 2027 – no new generation build is required over the phase-out period.

Scenario 4 – Coal

This is the scenario with the lowest carbon prices, which makes investment in new coal-fired power stations economic. An efficient new coal-fired power station is commissioned in 2022; a second, burning Southland lignite, in 2025. Most existing baseload thermal generation remains online. There is also some renewable development – but some existing hydro schemes have to reduce their output, owing to difficulty in securing water rights. Intermittent generation is supported by thermal peaking generation and demand-side response.

Scenario 5 – High Gas Discovery

Major new gas discoveries keep gas prices low over the entire time horizon. Some existing 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, a 240 MW CCGT in Northland in 2017, and 400 MW CCGTs in Auckland in 2020 and 2025. New gas-fired peakers and gas cogeneration are also constructed. There is some geothermal and wind development but little new hydro generation.

Scenario development approach

The Electricity Commission’s scenarios from the 2010 SOO were produced using the Generation Expansion Model (GEM), which creates a least cost schedule of new



generation capacity required to meet forecast demand. See the Electricity Authority’s website for more information about GEM.

11

The new scenarios described in this document are based on the 2010 SOO scenarios and have been produced using a similar version of GEM with many of the same input assumptions (including capital and maintenance costs, fuel costs and carbon prices).

Transpower revised some assumptions to bring the scenarios up to date with current information, and to reflect our views about plausible generation and demand-side development. Key changes include:

updating the lists of existing, committed and potential generation

using the APR 2012 demand forecast (as described in Chapter 4)

relaxing the GEM security constraints (the original constraints tended to produce scenarios with an implausibly high amount of North Island peaking capacity)

setting exchange rates to what we would regard as a plausible long-term average

reviewing the potential contribution of demand-side alternatives to managing system peaks

reviewing 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 diversity of outcomes in some regions (which is important for assessing the range of possible transmission flows).

While we attempted to incorporate the most up to date information about future generation projects, new information is always coming to light. For example, at the time of constructing these scenarios it was understood Meridian Energy were still pursuing resource consents for their Project Hayes wind project, and it was considered plausible that stage 1 of this project could be built by 2017, as in Scenario 2. Since this date Meridian has announced it is withdrawing its application for resource consents such that this now appears very unlikely. While we acknowledge aspects of the scenarios may change we believe the scenarios are still appropriate for identifying issues on the grid that may require further investigation.

5.3 Use of the generation capacity assumptions

5.3.1 Use of generation scenarios in the APR

The generation scenarios are used to assess the effect of generation on the National Grid backbone. The generation output is varied to test the transmission capability. Issues that have already been noted are considered again to determine what effect, if any, the forecast generation will have.

5.3.2 Grid Injection Point injection forecast assumptions

Grid Injection Point injection forecasts, (required for the GRR), are based on each generator’s operating capacity. For the purposes of assessing local grid injection point adequacy, we base our assessment on ensuring there is adequate transmission capacity to fully dispatch each generator rather than making assumptions about how much each generator may actually generate in the future.

11

http://www.ea.govt.nz/industry/modelling/in-house-models/gem/

http://www.ea.govt.nz/industry/modelling/in-house-models/gem/

Chapter 6: Grid Backbone


6 Grid backbone

6.1 Introduction

6.2 Changes since the 2011 Annual Planning Report

6.3 North Island grid backbone overview

6.4 North Island grid backbone issues and project options

6.5 South Island grid backbone overview

6.6 South Island grid backbone issues and project options

6.7 HVDC link overview

6.8 HVDC link issues and project options

6.1 Introduction

This chapter describes the adequacy of New Zealand’s grid backbone to meet forecast demand and anticipated generation development, approved development plans, and further development options for the next 15 years.

The grid backbone (see Chapter 3 for more information) provides the connection between the regions. The regions are described in Chapters 7 to 19.

Prudent transmission network planning considers a range of generation scenarios to meet the forecast growth in demand (see Chapters 4 and 5 for more information) to determine the development option and timing for grid upgrades.

Transmission needs for the grid backbone are identified after the commissioning of committed projects. The identification of transmission needs is indicative only, based on a limited number of load and generation dispatch scenarios, along with the impact of future new generation scenarios. They indicate the possible need for a fuller investigation within the forecast period, with the timing and scope of the investigation determined by new generation developments and demand growth.

The resolving projects to meet the transmission needs are an indicative list only, being possible solutions that will be subject to the Investment Test. They will be developed through the grid planning process as investments to meet the Grid Reliability Standard and/or to provide net market benefit.

For the North Island, the existing and possible future grid backbones are described in Section 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 in Section 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 by Pole 3 in 2012/13.


Table 6-1 lists the specific issues and projects that are either new or no longer relevant within the forecast period when compared to last year's report.

Table 6-1: Changes since 2011

Issues/projects Change

No new issues or projects completed since 2011 No change



6.3 North Island grid backbone overview

6.3.1 Existing North Island transmission configuration

The North Island grid backbone comprises the:

220 kV circuits from Wellington to Auckland located along the Central North Island corridor

220 kV Wairakei Ring circuits (220 kV circuits between Wairakei and Whakamaru) connecting the major hydro and geothermal generation in the Central North Island to the transmission network, and

220 kV circuits from Bunnythorpe to Huntly through Stratford connecting Taranaki generation to the transmission network.

Power flows either north or south on the inter-island HVDC link, depending on the time of day or year. During daylight periods and normal rainfall patterns in the South Island, power tends to flow north. In non-peak periods (late evenings and early mornings) 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.



Figure 6-1: North Island grid backbone schematic

Otahuhu

Takanini

Glenbrook

Huntly

Hamilton

Te Kowhai

Whakamaru

Atiamuri

Poihipi

Wairakei

Rangipo

Tokaanu

Tangiwai

Linton

Bunnythorpe

Haywards

Wilton

Brunswick

Stratford

Taumarunui

Ohakuri

Ohinewai

220 kV SUBSTATION BUS

KEY

220 kV CIRCUIT

GENERATOR

CAPACITOR

TEE POINT

Drury



6.3.2 Future North Island grid backbone

Figure 6-2 and Figure 6-3 provide an indication of the North Island transmission backbone development in the medium term (the next 15 years), and longer term (beyond 2027), respectively.

We are building a new double-circuit transmission link from Whakamaru to Auckland, and a new double-circuit transmission line between Wairakei and Whakamaru.

We have submitted an Investment Proposal to the Commerce Commission to replace conductor on the existing 220 kV transmission lines between Bunnythorpe and Haywards. A consequence of the replacement will be to increase 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 Taranaki region and a new line to Whakamaru.

In the longer term, we may increase the transmission capacity through the North Island by increasing the operating voltage on the new overhead transmission line into Auckland to 400 kV. Ultimately we may build a new transmission line connecting Bunnythorpe, Whakamaru, and Auckland, but this is highly dependent on future load and generation growth, and the viability of alternatives.

We will also be looking to provide substation diversity at some critical transmission nodes and strengthen resilience to high impact low probability events.

Voltage stability in the Upper North Island is an ongoing issue. We will continue to study the additional reactive support requirements to maintain Upper North Island voltage stability as regional load continues to grow.



Figure 6-2: Indicative North Island grid backbone schematic to 2027

Otahuhu

Takanini

Glenbrook

Ohinewai

Huntly

Hamilton

Te Kowhai

Taumarunui

Whakamaru B

Atiamuri

Ohakuri

Poihipi

Wairakei

Rangipo

Tokaanu

Tangiwai

Brunswick

Stratford

Linton

Bunnythorpe

Haywards

Wilton

Pakuranga

* new double circuit transmission line constructed for

400 kV operation but initially operated at 220 kV.

*

Brownhill

Drury

Whakamaru A

NEW ASSETS

UPGRADED ASSETS

KEY

Te Mihi



Figure 6-3: Longer term indicative North Island grid backbone schematic

Otahuhu

Takanini

Glenbrook

OhinewaiHuntly

Hamilton

Te Kowhai

Taumarunui

Whakamaru B

Atiamuri

Ohakuri

Poihipi Wairakei

Rangipo

Tokaanu

Tangiwai

Brunswick

Stratford

Linton

Bunnythorpe

Haywards

Wilton

Pakuranga

Brownhill

400 kV

Drury

Whakamaru A

NEW ASSETS

UPGRADED ASSETS

KEY

220 kV

400 kV

Although this diagram shows a few

possible development paths for the

future North Island grid backbone

transmission system, it is not intended

to indicate a preference. Any option

will be finalised closer to the date that

transmission reinforcement is needed.

* Another possible option is a new

HVDC link into Auckland.

** New grid exit point(s) south of

Otahuhu, possibly:

- north of Drury, and/or

- at Brownhill Road by extending the

220 kV bus.

***

400 kV

**

Te Mihi

6.4 North Island grid backbone issues and project options

The North Island grid backbone comprises five areas indicated in Figure 6-4. Table 6-2 summarises issues involving the grid backbone for the next 15 years. For more information about a particular issue, refer to the listed section number in Table 6-2.



Figure 6-4: North Island grid backbone area

Upper North

Island area

Wairakei Ring area

Central North

Island area

Taranaki area

Wellington area

Table 6-2: Grid backbone transmission issues

Section number

Issue

6.4.1 Upper North Island voltage stability

6.4.2 Transmission capacity into Auckland and Northland

6.4.3 Wairakei Ring transmission capacity

6.4.4 Taranaki transmission capacity

6.4.5 Central North Island transmission capacity

6.4.6 Wellington area transmission capacity

6.4.1 Upper North Island voltage stability

Overview

The Upper North Island covers the geographical area north of Huntly, including Glenbrook, Takanini, Auckland, and the North Isthmus.

The transmission capability to supply the Upper North Island load is limited by voltage stability, which in turn is influenced by:

generation in Auckland and at Huntly

the reactive power losses due to the transmission system within the Upper North Island

the reactive power losses due to the transmission system supplying the Upper North Island area, and

the reactive power demand due to the composition of the load in the area (in particular the proportion and type of motor load).

There are several generator and circuit contingencies that can cause voltage control problems. The worst contingencies include the loss of the:



Otahuhu combined-cycle gas turbine generator

Huntly E3P generator (Unit 5)

220 kV Huntly–Otahuhu 2 circuit, or

220 kV Drury–Huntly 1 circuit.

The Upper North Island load includes a significant proportion of motor load. The behaviour of this load during and following faults influences the regional transmission voltage performance. During a severe fault, motors will decelerate and some can stall. The motors will then draw large currents which in turn delay the voltage recovery after a fault. We have identified that voltage recovery is most at risk in late summer between mid-January and mid-March, when the greatest amount of motor load is connected.

Reactive losses on heavily loaded transmission lines are significant, especially following a circuit tripping when the loading of parallel circuits increases.

The Upper North Island has an enduring need for voltage support because of its reliance on long transmission lines from the south for much of its power. Investment is required every two or three years for voltage support in the Upper North Island. Some component of reactive power support in the Auckland region must be dynamic to avoid the need for shunt capacitor switching after a transmission or generator contingency. The dynamic reactive support may be provided by generators, synchronous condensers, static var compensators (SVCs) or static synchronous compensators (STATCOMs).

Approved projects

Investments in previous years include an SVC at Albany, binary switched capacitors at Kaitaia, ten capacitor banks totalling 600 Mvar at four substations

12, and a

short-term contract for reactive support from condensers at Otahuhu13

. Six capacitors are, or soon will be, decommissioned

14 based on condition assessment.

We have installed power system monitoring equipment to improve our understanding of the Upper North Island power system, specifically load composition and response to transient events.

Projects approved in 2010 by the Electricity Commission under Part F of the Electricity Governance Rules include:

a STATCOM at Penrose, scheduled for commissioning in 2013

two STATCOMs at Marsden, scheduled for commissioning in 2014

a Reactive Power Controller (RPC) to co-ordinate the various dynamic and static devices in the Upper North Island. This work is scheduled to begin in 2012, for commissioning in 2014/2015, and

demand-side participation.

We issued a Request For Proposals for demand-side participation, but the proposals received were all uneconomic. This was an unexpected result, and the demand-side participation framework is being further developed to unlock its potential (see Section 2.2 for more information).

Other approved projects also have a beneficial effect on voltage stability in the Upper North Island by reducing the reactive power losses in the transmission system.

12

Capacitors installed in previous years are: Albany 1 x 100 Mvar, Hepburn Road 3 x 50 Mvar, Penrose 4 x 50 Mvar, Otahuhu 2 x 100 Mvar.

13 The condensers belong to Contact Energy, and were once operated as gas turbine generators, The

contract for the condensers expires in 2013 and will not be renewed, as it is more economic to install other reactive support such as STATCOMs.

14 Capacitors that are, or soon will be, decommissioned are: Albany 2 x 30 Mvar, Henderson

1 x 30 Mvar, and Otahuhu 3 x 30 Mvar.



The North Auckland and Northland (NAaN) project that increases the transmission capacity in the Auckland and Northland regions (see Chapter 7, Section 7.8.4 for more information).

The North Island Grid Upgrade (NIGU) project that increases the transmission capacity into the Auckland and Northland regions (see Section 6.4.2 for more information).

Even with these approved projects, voltage stability will be an ongoing issue.

Resolving projects

We have commenced an investigation to determine the amount of additional reactive support required to relieve the Upper North Island voltage stability issue beyond the completion of the NAaN and NIGU projects.

Additional reactive support will be required about every two-three years. This will be a mixture of capacitors and dynamic support such as STATCOMs. The benefits of advancing series compensation on the new transmission link between Whakamaru and Pakuranga will be evaluated also.

The project cost falls within band E. This is a possible investment project to meet the Grid Reliability Standard and we anticipate seeking approval from the Commission in the second half of 2012.

6.4.2 Transmission capacity into Auckland and Northland

Overview

Power transfer to the Upper North Island is dependent on:

the generation from Huntly, and the transmission capacity between Huntly and Otahuhu, and

generation from Whakamaru and south of Whakamaru, and the transmission capacity between Whakamaru and Otahuhu.

For the existing system, issues that may arise during periods of high demand and low generation in the Auckland area include:

an outage of a Huntly–Otahuhu circuit may overload the other Huntly–Otahuhu circuit.

an outage of a Huntly–Ohinewai circuit may overload the other Huntly–Ohinewai circuit.

the two 220 kV Otahuhu–Whakamaru circuits may overload during a contingency.

an outage of the Hamilton–Whakamaru circuit may overload the two 110 kV Arapuni–Hamilton regional circuits.

an outage of the Hamilton–Ohinewai circuit may cause low voltage at the Hamilton 220 kV bus.

Approved projects

The above issues will be addressed by the North Island Grid Upgrade (NIGU). NIGU includes a number of projects which will:

increase the power transfer capacity into Auckland

reduce the loading on the existing 220 kV Otahuhu–Whakamaru and Huntly–Otahuhu circuits, and

reduce the reactive support needed in the Upper North Island (see Section 6.4.1).



As part of NIGU, we have just completed conversion of the existing 110 kV Pakuranga substation to 220 kV, and the existing Otahuhu–Pakuranga line from 110 kV to 220 kV operation

15.

The remaining NIGU projects include:

a new substation, Whakamaru B (near the existing Whakamaru substation) and a transition station at Brownhill

a double-circuit overhead transmission line approximately 190 km from Whakamaru B substation to a transition station at Brownhill, which will:

initially operate at 220 kV, and

be capable of 400 kV operation in future.

two 220 kV underground cables from the transition station at Brownhill to Pakuranga substation, rated at 851/890 MVA summer/winter per cable circuit.

After the commissioning of the NIGU projects, eight 220 kV circuits from the south will primarily supply the Upper North Island, with three diverse routes, comprising:

two circuits from Huntly to Otahuhu (the western path)

four circuits from Whakamaru to Otahuhu (the central path), and

two circuits from Whakamaru to Pakuranga (the eastern path).

There are also two circuits between Huntly and Ohinewai connecting the western and central paths.

There is a 220 kV connection between Otahuhu and Pakuranga within the Auckland region. The North Auckland and Northland (NAaN) project makes use of the transmission capacity and diversity provided by Pakuranga to increase the capacity and security within the Auckland and Northland regions (see Chapter 7, Section 7.8.4).

The Auckland region is also connected by two smaller 110 kV regional circuits from Arapuni via Hamilton, Bombay, and Wiri to Otahuhu, though their contribution is minor compared to the 220 kV circuits.

Figure 6-5 shows the grid backbone circuits supplying the Upper North Island area.

15

The Otahuhu–Pakuranga line was constructed at 220 kV, but operated initially at 110 kV.



Figure 6-5: 220 kV Upper North Island grid backbone circuits

Otahuhu

Takanini

Glenbrook

Huntly

Hamilton

Whakamaru A

Ohinewai

Drury

Circuit Summer/Winter

rating

Drury–Huntly 1 694/764 MVA

Drury–Glenbrook 1 and 2 694/762 MVA

Drury–Takanini–Otahuhu 1 1123/1200 MVA

Huntly–Ohinewai 1 and 2 694/764 MVA

Huntly–Takanini 2 694/764 MVA

Hamilton–Ohinewai 1 615/671 MVA

Hamilton–Whakamaru 1 615/671 MVA

Ohinewai–Otahuhu 1 and 2 615/671 MVA

Ohinewai–Whakamaru 1 615/671 MVA

Otahuhu–Whakamaru 1 and 2 293/323 MVA

Otahuhu–Takanini 2 678/724 MVA

Pakuranga–Whakamaru North 1 and 2 851/890 MVA

Whakamaru B

Pakuranga

Brownhill

* new double circuit

transmission line constructed

for 400 kV operation but

initially operated at 220 kV.

*

The following sections assess the transmission capability of the circuits into the Auckland and Northland regions following the committed NIGU projects. The assessment is based on representative system conditions, to determine how different generation development scenarios interact with the 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 Northland region during a normal demand period:

normal summer’s day load in the North Island (approximately 85% of summer peak load)

no thermal generation in Auckland and Northland in service

low renewable generation in Auckland and Northland, and

medium to high generation elsewhere.

The circuits into the Auckland and Northland regions have sufficient capacity during a normal demand period and low generation in the Auckland and Northland regions for the duration of the forecast period.

System condition 2 (peak demand)

This system condition tests a high demand period in the Auckland and Northland regions along with the outage of the biggest generator:

island peak load in the North Island

high generation in the North Island

the biggest generator in Auckland is out of service, i.e. Otahuhu C or Huntly E3P, and



all other thermal generation in Auckland, Northland and Huntly16

is in service.

Through this it was identified that the 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.

Impact of generation scenarios

The five generation scenarios described in Chapter 5 have the following impacts on the circuits into Auckland and Northland.

For system condition 1, all the generation scenarios have minimal impact within the forecast period.

For system condition 2, a low Hamilton bus voltage is seen towards the end of the forecast period in generation scenarios 1 (‘sustainable path’) and 2 (‘South Island wind’). This is because compared to the other generation scenarios, a lower amount of generation is commissioned in the Northland, Auckland and Waikato regions in these scenarios.

Outages

An outage of one of the circuits into Auckland and an outage of the biggest generator in Auckland still maintains n-1 security into Auckland and Northland.

Resolving projects

We will investigate options to resolve the Hamilton bus voltage issue closer to the time it occurs (see Chapter 9, Section 9.9.2 for more information).

Beyond 15 years, the double-circuit line from Whakamaru B to Brownhill will be converted from 220 kV to its construction voltage of 400 kV. This will also require:

220/400 kV transformers and associated works at Whakamaru B substation to interconnect with the existing 220 kV system

a switchyard in the vicinity of the transition station at Brownhill with 220/400 kV transformers and associated works

220 kV underground cables to the Otahuhu substation, and

extensions to the Otahuhu switchyard(s).

6.4.3 Wairakei Ring transmission capacity

Overview

The Wairakei Ring circuits:

connect the major hydro and geothermal generation stations in the North Island to the grid backbone, and

supply the Bay of Plenty region from Atiamuri and Ohakuri.

In addition, a new geothermal power station is being built at Te Mihi, and a number of other generation stations which connect directly or indirectly to the Wairakei Ring are in the planning or consent stage.

For the existing system, as this generation develops, an outage of one of the Wairakei Ring circuits may begin to constrain north power flows. Specifically, an outage of the:

Whakamaru–Poihipi–Wairakei circuit may overload the Wairakei–Ohakuri–Atiamuri circuits

16

At Huntly, all generator units are in service except E3P is placed out of service for the study. In the 5 generation scenarios, there are new generation connected at Huntly and some units are decommissioned. It ranges from 630 MW to 1,295 MW in 2027 across the 5 generation scenarios.



Wairakei–Ohakuri–Atiamuri circuits may overload the Whakamaru–Poihipi–Wairakei circuit.

Approved projects

To address the above issues, we are building a 220 kV double-circuit line between Wairakei and Whakamaru, to replace the existing single-circuit Wairakei–Whakamaru B line. The line is scheduled for commissioning in 2013, and will increase the power flow capacity through the Wairakei Ring.

Figure 6-6 shows the grid backbone circuits in the Wairakei Ring area after the commissioning of the Wairakei Ring project.

Figure 6-6: 220 kV Wairakei Ring circuits

Atiamuri

PoihipiWairakei

Ohakuri


rating

Ohakuri–Wairakei 1 333/358 MVA

Atiamuri–Ohakuri 1 333/358 MVA

Atiamuri–Whakamaru 1 333/358 MVA

Wairakei–Whakamaru 1 903/994 MVA

Wairakei–Te Mihi–Whakamaru 1 903/994 MVA

Te Mihi

Whakamaru A

Whakamaru B

The following sections assess the Wairakei Ring transmission capability following the committed Wairakei to Whakamaru Replacement Line Project. The assessment is based on representative system conditions, to determine how different generation development scenarios interact with the Wairakei Ring.

System condition 1 (north flow)

This system condition tests power flowing north through the circuits in the Wairakei Ring towards the Upper North Island:


high geothermal generation in the Wairakei Ring area

medium to high generation (including peakers) elsewhere to balance generation with demand, and

HVDC north transfer between 380 MW and, but not exceeding, 1,400 MW.

The following issues were identified:

The Atiamuri–Ohakuri and Ohakuri–Wairakei circuits may overload for an outage of either the new Te Mihi–Whakamaru or Wairakei–Whakamaru circuits.

High generation at Kawerau and low demand in the Bay of Plenty may cause higher circuit loading on the Atiamuri–Ohakuri circuit especially during high north flow through the Wairakei Ring circuits. In this scenario, the Atiamuri–Ohakuri circuit may also 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 Wairakei Ring towards the Wellington region and the South Island via the HVDC link:



low North Island load (approximately 45% of peak load)


medium to low generation elsewhere, and

HVDC south transfer but not exceeding 950 MW.

The Wairakei Ring circuits have sufficient capacity for south power flows for the duration of the forecast period. However, there may be transmission constraints south 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 Bay of Plenty region during high demand and medium generation in that region:

island peak load in North Island


medium generation in the Bay of Plenty region with the biggest generator in the region out of service (Kawerau geothermal generator is out of service).


HVDC north transfer but not exceeding 1,400 MW.

The following circuits may overload for this system condition.

The Ohakuri–Wairakei circuit overloads for an outage of the Atiamuri–Whakamaru, Te Mihi–Whakamaru or Wairakei–Whakamaru circuits.

The Atiamuri–Ohakuri circuit overloads for an outage of the Atiamuri–Whakamaru, Te Mihi–Whakamaru or Wairakei–Whakamaru circuits.

The Atiamuri–Whakamaru circuit overloads for an outage of the Ohakuri–Wairakei circuit.


The five generation scenarios described in Chapter 5 have the following impacts on the circuits in the Wairakei Ring.

For system condition 1 (north power flow through the Wairakei Ring circuits to supply the Upper North Island), only generation scenarios 1 (‘sustainable path’) and 3 (‘medium renewables’) have a significant impact. These generation scenarios have the lowest net increase in the Upper North Island generation compared to the other generation scenarios. Therefore, there are higher levels of power flow through the Wairakei Ring to supply the Upper North Island load, which may overload the Atiamuri–Ohakuri and Ohakuri–Wairakei circuits.

Generation scenario 1 (‘sustainable path’) has the highest net increase in generation in the Bay of Plenty region compared to the other generation scenarios. High generation and low demand in the Bay of Plenty region may cause the Atiamuri–Ohakuri circuit to overload in a contingent event.

For system condition 2 (south power flow through the Wairakei Ring circuits), all the generation scenarios have minimal impact on the Wairakei Ring circuits within the forecast period.

For system condition 3 (east power flow through the Wairakei Ring), generation scenarios 2 (‘South Island wind’) and 5 (‘high gas discovery’) have the highest impact on circuits supplying the Bay of Plenty region. These generation scenarios have the lowest net increase in generation in the Bay of Plenty region. Therefore, there are higher levels of power flow through the Wairakei Ring to supply the Bay of Plenty, which may overload the Wairakei–Ohakuri–Atiamuri–Whakamaru circuits.



Outages

The main connection to the Bay of Plenty region is through the Wairakei–Ohakuri and Atiamuri–Whakamaru circuits. An outage of either of these circuits puts the whole Bay of Plenty region on n security.

All outages within the Wairakei Ring may also cause generation constraints, which require replacement generation in other areas such as the Auckland region.

Resolving projects

During peak demand periods in the Bay of Plenty region, generation must run in the region to prevent overloading of the Wairakei–Ohakuri–Atiamuri–Whakamaru circuits. Historically, generation in the Bay of Plenty region has been available during peak periods, and we expect this will continue in the short term. However, in the longer term, the region’s dependence on local hydro generation may expose it to insufficient transmission 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 term

reconductoring the Wairakei–Ohakuri–Atiamuri circuits, followed by the Atiamuri–Whakamaru circuit, if required, or

a new 220 kV Wairakei–Atiamuri circuit (bypassing Ohakuri), followed by a second Atiamuri–Whakamaru circuit, if required.

The Wairakei–Ohakuri–Atiamuri–Whakamaru circuits have already been thermally upgraded, and a further thermal upgrade is not technically feasible. A second Wairakei–Atiamuri circuit is one option which keeps the Bay of Plenty region on n-1 security during outages of the Wairakei–Ohakuri or Atiamuri–Whakamaru circuits. It is unlikely that security to the Bay of Plenty during outages will by itself provide sufficient benefit to justify the second circuit.

We will monitor the generation developments in the Wairakei Ring area and the Bay of Plenty region, to determine if a transmission upgrade investigation is required.

6.4.4 Taranaki transmission capacity

Overview

Taranaki generation is connected to the North Island grid backbone via Stratford with two 220 kV circuits north to Huntly and two circuits south to Bunnythorpe.

Figure 6-7 shows the grid backbone circuits for the Taranaki area between Bunnythorpe and Huntly.



Figure 6-7: 220 kV circuits between Bunnythorpe and Huntly

Huntly

Te Kowhai

Bunnythorpe

Brunswick

Stratford

Taumarunui


rating

Bunnythorpe–Brunswick 1 and 2 695/712 MVA1

Brunswick–Stratford 1 and 3 239/292 MVA

Brunswick–Stratford 2 232/287 MVA

Huntly–Stratford 1 354/354 MVA1

Stratford–Taumarunui 1 (from Stratford) 455/455 MVA2

Stratford–Taumarunui 1 (from Taumarunui) 343/343 MVA2

Taumarunui–Te Kowhai 1 469/492 MVA

Huntly–Te Kowhai 1 (from Huntly) 301/301 MVA2

Huntly–Te Kowhai (from Te Kowhai) 469/492 MVA2

1. 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 to

protection settings.

Approved projects

There are no approved grid backbone projects in the Taranaki area.

The following sections assess the Taranaki transmission capability following the committed upgrades in the North Island. The assessment is based on representative system conditions, to determine how different generation development scenarios interact with the circuits out of Taranaki.


This system condition tests power flowing north through the circuits between Stratford and Huntly to Auckland and Northland:


high generation in Taranaki

the biggest generator in Auckland is out of service i.e. Otahuhu C

medium to high generation elsewhere to balance generation with demand, and

HVDC north transfer varies between 380 MW and 1,400 MW depending on generation and demand in the North Island.

For this system condition, an outage of one of the Huntly–Stratford circuits may cause the other circuit to overload especially during high Taranaki generation and low Auckland generation. Also, an outage of one of the Huntly–Stratford circuits may lead to dynamic and transient instability during high Taranaki generation.



For high levels of generation in the Taranaki area, power also flows to Bunnythorpe before flowing north through the Central North Island grid backbone

17.


This system condition tests power flowing mainly south through the circuits between Stratford and Bunnythorpe to the HVDC link:


high generation in Taranaki

medium to low generation elsewhere to balance generation with demand, and

HVDC varies between 120 MW north transfer and 950 MW south transfer depending on generation and demand in the North Island.

For this system condition, an outage of one of the Brunswick–Stratford circuits may overload the remaining two Brunswick–Stratford circuits

18 and the parallel 110 kV

circuits between Stratford and Bunnythorpe.

The 110 kV circuits that overload are mainly the Hawera–Stratford and Wanganui–Waverly circuits, which have been upgraded to a higher rated conductor but the ratings are still limited by substation equipment.


The five generation scenarios described in Chapter 5 have the following impacts on the circuits out of Taranaki.

For system condition 1 (north power flow from Stratford to Huntly), generation scenario 3 (‘medium renewables’) has the highest impact at the end of the forecast period, as it has the lowest net increase in generation in the Auckland and Northland area compared to the other generation scenarios. The significant overloads on the Huntly–Stratford circuits are dependent on:

Auckland and Northland load

Auckland and Northland generation, and

Taranaki generation.

For system condition 2 (south power flow from Stratford to Bunnythorpe), all the generation scenarios have minimal impact within the forecast period on the Taranaki transmission capacity except for generation scenario 5 (‘high gas discovery’). Generation scenarios 1 to 4 include the decommissioning of the Taranaki combined-cycle gas turbine while generation scenario 5 does not. This scenario has a net increase of up to 460 MW of new gas-fired peakers and combined-cycle gas turbines.

Outages

An outage of any of the circuits out of Taranaki i.e. between Stratford and Huntly or between Stratford and Bunnythorpe, may cause generation constraints, which require replacement generation in other areas.

Resolving projects

To prevent overloads on the circuits out of Taranaki during HVDC north and south flow, the Taranaki generation can be constrained. Alternatively, transmission solutions could include:

17

Central North Island 220 kV circuits such as Tokaanu–Whakamaru may overload during high Taranaki generation and HVDC north flow. See Section 6.4.5 for more information about this issue.

18 Central North Island 220 kV circuits such as Bunnythorpe–Tokaanu and Bunnythorpe–Tangiwai may

overload before the Brunswick–Stratford circuits overload for high HVDC south flow. See Section 6.4.5 for more information about this issue.



thermally upgrade and/or reconductor the Brunswick–Stratford circuits

reconductor the Huntly–Stratford circuits19

, or

a new transmission line between Taumarunui and Whakamaru.

To resolve the overloads on the 110 kV circuits, Wanganui and Waverly substation equipment is committed for upgrade to allow a higher rating on the 110 kV Hawera–Stratford and Wanganui–Waverly circuits. Upgrade of the Hawera substation equipment is still being investigated and is part of a separate project.

Also, re-tuning of the generator excitation systems and/or installation of power system stabilisers can enhance transient and dynamic stability to transfer power out of Taranaki between Stratford and Huntly.

6.4.5 Central North Island transmission capacity

Overview

The circuits between Bunnythorpe and Whakamaru/Wairakei comprise the:

two Bunnythorpe–Tokaanu–Whakamaru circuits, and

Bunnythorpe–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 circuits

Whakamaru A

Rangipo

Tangiwai

Bunnythorpe

Tokaanu


rating

Bunnythorpe–Tokaanu 1 and 2 307/335 MVA

Bunnythorpe–Tangiwai 1 239/291 MVA

Rangipo–Tangiwai 1 239/291 MVA

Rangipo–Wairakei 364/396 MVA

Tokaanu–Whakamaru 1 and 2 307/335 MVA

Wairakei

Approved projects

There are no grid backbone approved projects in the Central North Island area.

The following sections assess the transmission capability of the Central North Island grid backbone following the committed upgrades in the North Island. The assessment is based on representative system conditions, to determine how different generation development scenarios interact with the circuits in the Central North Island.

19

The Huntly–Stratford circuits have a maximum operating temperature of 120°C, which is the maximum practical operating temperature. Therefore, a thermal upgrade is not possible.




This system condition tests power flowing north through the circuits in the Central North Island towards Whakamaru or Wairakei:


high renewable generation including wind, wave, tidal, and solar


HVDC north transfer varies between 50 MW and 1,400 MW depending on North Island generation and demand.

For high generation in the Taranaki area, some of the Taranaki generation flows into Bunnythorpe. This can cause an overload on the Central North Island circuits.


A Tokaanu–Whakamaru circuit may overload for an outage of the other Tokaanu–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 other Bunnythorpe–Tokaanu circuit, any section of the Bunnythorpe–Tangiwai–Rangipo–Wairakei circuit, or one of the circuits between Stratford and Huntly.

The Bunnythorpe–Tangiwai–Rangipo–Wairakei circuits may overload for an outage of one of the Bunnythorpe–Tokaanu–Whakamaru circuits or one of the circuits between Stratford and Huntly.

There is a regional 110 kV single circuit between Bunnythorpe and Arapuni (via Mataroa, Ohakune, and Ongarue) which may also overload and constrain north transfer.


This system condition tests power flowing south through the circuits in the Central North Island towards Bunnythorpe:


low renewable generation including wind, wave, tidal, and solar


low to medium generation elsewhere to balance generation with demand, and

HVDC south transfer varies between 580 MW and 950 MW depending on North Island generation and demand.


A Bunnythorpe–Tokaanu circuit may overload for an outage of the other Bunnythorpe–Tokaanu circuit or any section of the Bunnythorpe–Tangiwai–Rangipo–Wairakei circuit.

A Tokaanu–Whakamaru circuit may overload for an outage of the other Tokaanu–Whakamaru circuit, any section of the Bunnythorpe–Tangiwai–Rangipo–Wairakei circuits, or one of the circuits between Stratford and Huntly.

The Bunnythorpe–Tangiwai–Rangipo–Wairakei circuit may overload for outages of a Bunnythorpe–Tokaanu–Whakamaru circuit or one of the circuits between Stratford and Huntly.

There is also low voltage at Bunnythorpe, Tangiwai, and Tokaanu for high HVDC south transfer and low generation in the Lower North Island.

The regional 110 kV circuit between Bunnythorpe and Arapuni (via Mataroa, Ohakune, and Ongarue) may also overload and constrain HVDC south transfer.




The five generation scenarios described in Chapter 5 have the following impacts on the Central North Island circuits.

For system condition 1 (north power flow from Bunnythorpe to Whakamaru/Wairakei), generation scenario 3 (‘medium renewables’) has the highest impact on the circuits in the Central North Island, as it has the lowest net increase in generation in the Auckland and Northland area compared to the other generation scenarios.

For system condition 2 (south power flow from Whakamaru/Wairakei to Bunnythorpe), generation scenarios 4 (‘coal’) and 5 (‘high gas discovery’) have the highest impact on the circuits in the Central North Island, as they have the lowest net increase in generation in the Wellington area. With a lower amount of new generation in the Wellington area, more power is required to flow through the circuits between Whakamaru/Wairakei and Bunnythorpe to supply the demand in the Wellington area and the South Island via the HVDC link. Low voltage at Bunnythorpe, Tangiwai, and Tokaanu only occurs for generation scenario 4, which has the lowest net increase in generation in the Lower North Island.

Outages

An outage of any of the Central North Island circuits may cause generation constraints, which require replacement generation in other areas.

Resolving projects

For the circuits between Whakamaru and Bunnythorpe, the requirement to upgrade is largely dictated by generation development in the area. The upgrade options can be separated into two tranches depending on the amount of new generation.

In tranche 1, the range of options includes:

limit the power flow on 110 kV regional network between Mataroa and Ohakune through a Special Protection Scheme (SPS), series reactor, phase shifting transformer or a permanent system split (putting four regional grid exit points on n security)

reconductor the Tokaanu–Whakamaru circuits, and

thermally upgrade or reconductor the Bunnythorpe–Tangiwai–Rangipo circuit.

Tranche 1 options may enable up to 500 MW of new generation 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 for tranche 1. The range of options includes:

reconductor the Bunnythorpe–Tokaanu circuits

provide new transmission capacity between Bunnythorpe and Whakamaru:

reuse the existing 220 kV single circuit line route between Bunnythorpe and Wairakei for a replacement double-circuit

a new double-circuit 220 kV or 400 kV circuit between Bunnythorpe and Whakamaru, or

HVDC light between Bunnythorpe and Whakamaru.

a new line in the Taranaki area, from Taumarunui to Whakamaru (to divert power flow from the Central North Island grid backbone), and

Lower North Island-wide System Protection Scheme to enable new generation.

The details and range of options in tranche 2 are still being investigated.



We will monitor generation developments in the Central North Island area, to determine the level of transmission upgrades required including the need for reactive devices to alleviate the low voltage issues.

6.4.6 Wellington area transmission capacity

Overview

The 220 kV circuits in the Wellington area between Bunnythorpe and Wellington comprise:

two circuits connecting directly between Haywards and Bunnythorpe

one Haywards–Linton–Bunnythorpe circuit, with Tararua Wind Central connected off the Linton–Bunnythorpe section of the circuit, and

one 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 area

Bunnythorpe


rating

Bunnythorpe–Haywards 1 and 2 307/335 MVA

Bunnythorpe–Linton–Wilton 1 694/764 MVA

Bunnythorpe–Tararua Wind Central–Linton 1 694/764 MVA

Haywards–Linton 1 694/762 MVA

Haywards–Wilton 1 694/739 MVA

Linton

Haywards

Wilton

Approved projects

There are no approved grid backbone projects for the Wellington area.

We submitted an Investment Proposal to the Commerce Commission in December 2011 to reconductor the two direct Bunnythorpe–Haywards circuits because of condition assessment. The replacement conductor will also provide a small increase in the circuits’ rating (from 307/335 MVA to 355/370 MVA). A decision from the Commerce Commission is expected in the second quarter of 2012.

The project cost falls within band F and construction is expected to be completed by the fourth quarter of 2018.

The following sections assess the Wellington area’s transmission capability following the committed upgrades in the North Island. The assessment is based on representative system conditions, to determine how different generation development scenarios 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 Wellington area towards Bunnythorpe:


high renewable generation including wind, wave, tidal, and solar




HVDC north transfer varies between 50 MW and 1,400 MW depending on North Island generation and demand.


The two Bunnythorpe–Haywards circuits may overload for outages of the Haywards–Linton–Bunnythorpe circuit (with Tararua Wind Central tee connected) or the Wilton–Linton–Bunnythorpe circuit.

The Linton–Bunnythorpe circuit (with Tararua Wind Central tee connected) may overload for outages of the Haywards–Wilton circuit or the Wilton–Linton–Bunnythorpe circuit.

The Haywards–Linton circuit may overload for an outage of the Linton– Bunnythorpe circuit (with Tararua Wind Central tee connected) under certain generation scenarios.

The Wilton–Linton–Bunnythorpe circuit may overload for an outage of the Haywards–Wilton circuit under certain generation scenarios.

System condition 2 (HVDC south flow)

This system condition tests power flowing south through the circuits in the Wellington area towards Haywards and Wilton:


low renewable generation including wind, wave, tidal, and solar


medium to low generation elsewhere, and

HVDC south varies between 580 MW and 950 MW depending on North Island generation and demand.

For this system condition, the two Bunnythorpe–Haywards circuits may overload for outages of the Haywards–Linton–Bunnythorpe circuit (with Tararua Wind Central tee connected) or the Wilton–Linton–Bunnythorpe circuit.

Some regional 110 kV circuits may also overload and constrain HVDC south transfer. These are the circuit between Bunnythorpe and Arapuni (via Mataroa, Ohakune, and Ongarue) and the two Bunnythorpe–Woodville circuits.

There are also voltage issues for the loss of a 220 kV circuit between Bunnythorpe and Wellington during high HVDC south transfer and low generation in the Wellington area.


The five generation scenarios described in Chapter 5 have the following impacts on the circuits in the Wellington area.

For system condition 1 (north power flow from Wellington to Bunnythorpe), generation scenario 3 (‘medium renewables’) has the highest impact on the circuits in the Wellington area, as it has the lowest net increase in generation in the Auckland and Northland area compared to the other generation scenarios. Generation scenarios 1 (‘sustainable path’) and 2 (‘South Island wind’) have high wind generation at the Linton bus and may cause the Haywards–Linton circuit to overload for outages of the Linton–Bunnythorpe circuit, Haywards–Wilton circuit or the Wilton–Linton–Bunnythorpe circuit. The Wilton–Linton–Bunnythorpe circuits may also overload due to high generation at the Linton bus for an outage of the Haywards–Wilton circuit.

For system condition 2 (south power flow from Bunnythorpe to Wellington), generation scenarios 4 (‘coal’) and 5 (‘high gas discovery’) have the highest impact on the circuits in the Wellington area, as they have the lowest net increase in generation in the Wellington area. With a lower amount of new generation in Wellington, more power is required to flow through the circuits between Bunnythorpe



and Wellington to supply Wellington area demand and the South Island via the HVDC link. Low voltages at Bunnythorpe and Linton occur only in generation scenario 4, which has the lowest net increase in generation in the Wellington area.

Outages

An outage of any of the 220 kV circuits in the Wellington area during HVDC north or south flow may cause generation constraints, which require replacement generation in other areas.

Resolving projects

For the two direct circuits between Bunnythorpe and Haywards, we believe that it is uneconomic to increase their rating to increase the transmission capacity (other than the small increase in rating following reconductoring – refer to Approved projects above). However, a higher amount of power transfer between Bunnythorpe and Haywards is possible with a Special Protection Scheme (SPS). The SPS will automatically reduce the power flowing on the HVDC link (after Pole 3 is commissioned) if the two direct Bunnythorpe–Haywards circuits overload, subject to other constraints within the power system. We will monitor the level of constraint caused by these circuits to determine when an investigation to implement an SPS is required.

The overloads on the two circuits between Bunnythorpe and Linton are driven by the amount of generation connected at Linton. We will monitor the amount of generation being connected at Linton to determine if a transmission upgrade investigation is required.

For the two regional 110 kV Bunnythorpe–Woodville circuits, we have a committed project to install an SPS to increase south flow transmission capacity. We will monitor new generation connections to determine if an investigation to re-conductor the circuits to a higher rating is required.

There is significant potential wind generation in the Wairarapa. One option to connect this generation is to build a new 220 kV transmission line from the Wairarapa to Bunnythorpe or Linton.



6.5 South Island grid backbone overview

6.5.1 Existing South Island transmission configuration

The South Island grid backbone comprises 220 kV circuits with:

three circuits from Islington to Kikiwa

four circuits from Twizel and Livingstone in the Waitaki Valley area to Islington

circuits within the Waitaki Valley, between Twizel and Livingstone, which connect six large hydro power stations and the HVDC link

three circuits from Roxburgh to Twizel and Livingstone in the Waitaki Valley area, and

four circuits from Roxburgh to Invercargill/North Makarewa (two via Three Mile Hill) and nine circuits within the Southland area.

Power flows either north or south on the inter-island HVDC link, depending on the time of day or year. During daylight periods, power tends to flow north to meet peak demand. However, during light load periods, power can flow south to conserve the level 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.



Figure 6-10: South Island grid backbone schematic

220 kV

220 kV SUBSTATION BUS

KEY

220 kV CIRCUIT

STATIC VAR COMPENSATOR

Kikiwa

Islington

Bromley

Ashburton

Livingstone

Naseby

Tekapo B

Twizel

Ohau A

Ohau B

Ohau C

Benmore Waitaki

Aviemore

Cromwell

Waipara

Culverden

Clyde

Roxburgh

Invercargill

Tiwai

Manapouri

North Makarewa GENERATOR

SVC-9

CAPACITOR

SVC

Three Mile Hill

Timaru

SVC-3

STC-2

STATIC SYNCHRONOUS COMPENSATORSTC



6.5.2 Future South Island grid backbone

Figure 6-10 and Figure 6-11 provide an indication of the South Island transmission backbone development in the medium term (the next 15 years), and longer term (beyond 2027), respectively.

We will install an additional bus coupler circuit breaker at Islington, to improve voltage stability for the Upper South Island following a bus fault and to increase security.

Further investments in the Upper South Island to maintain voltage stability to meet load growth will also be required. Presently we are consulting on two options:

increasing the dynamic reactive support at and around the Islington 220 kV bus, and

bussing all four 220 kV circuits into the Upper South Island at Geraldine.

In the longer term, further upgrades for the Upper South Island may be required for voltage stability or thermal capacity reasons. Options include:

extending the 220 kV grid from Kikiwa to Inangahua in the West Coast region20

, to improve voltage stability

bussing all three circuits north of Islington with an HVDC tap-off near Waipara, and

a second Islington–Twizel circuit providing a fifth circuit into the Upper South Island.

The Upper South Island voltage stability is an ongoing issue. We will continue to study the additional reactive support requirements to maintain Upper South Island voltage stability as regional load continues to grow.

Within the Waitaki Valley area, there is an approved project to increase the transmission capacity of the Aviemore–Waitaki–Livingstone circuits. There is also an approved project to increase the capacity of the Aviemore–Benmore circuits, which will be reviewed in 2013 to optimise its implementation date.

Between Roxburgh and the Waitaki Valley, there is an approved project to increase the transmission capacity of the Roxburgh–Clyde circuits. There is also an approved project to increase the capacity of the other circuits, which will be reviewed in 2013 to optimise an implementation date.

For the area below Roxburgh, the 110 kV regional network limits the capacity of the 220 kV grid backbone. There is an approved project to remove this regional grid constraint. There is also an approved project to further increase the grid backbone capacity by installing a series capacitor on the North Makarewa–Three Mile Hill circuit, which will be reviewed in 2013 to optimise an implementation date.

We will also look to provide substation diversity at critical transmission nodes to strengthen resilience for high impact low probability events.

20

There is a 220 kV double-circuit transmission line between Inangahua and Kikiwa, which at present has a circuit on one side only and is operated at 110 kV.



Figure 6-11: Indicative South Island grid backbone schematic to 2027

Kikiwa

Waipara

Culverden

Bromley

Ashburton

Tekapo B

Twizel

Ohau A

Ohau B

Ohau C

Benmore

Aviemore

Waitaki

LivingstoneNaseby

Cromwell

Clyde

Roxburgh

Invercargill

Tiwai

North Makarewa

Manapouri

Geraldine

Islington SVC*

*

* Although this diagram shows new

dynamic and static reactive supports

installed at Islington, and a new

switching station at Geraldine, this is

indicative only as options are still

being investigated.

NEW ASSETS

UPGRADED ASSETS

KEY

Three Mile Hill220 kV

Gore

SVC-9SVC-3

STC-2

*Timaru



Figure 6-12: Longer term indicative South Island grid backbone schematic

Kikiwa

Waipara

Culverden

Bromley

Ashburton

Tekapo B

Twizel

Ohau A

Ohau B

Ohau C

Benmore

Aviemore

Waitaki

Livingstone

Naseby

Cromwell

Clyde

Roxburgh

Invercargill

Tiwai

North Makarewa

Manapouri

Geraldine

Islington SVC

NEW ASSETS

UPGRADED ASSETS

KEY

Inangahua

STC

SVC

* Although this diagram shows a few development paths

for the future South Island grid backbone transmission

system, it is not intended to indicate a preference. Option

will be finalised closer to the date that transmission

reinforcement is needed.

Haywards

*

*350 kV

*

Three Mile Hill

Gore

STC-2

SVC-9SVC-3

*

Timaru

6.6 South Island grid backbone issues and project options

The South Island grid backbone comprises four areas indicated in Figure 6-13. Table 6-3 summarises issues involving the South Island grid backbone for the next 15 years. For more information about a particular issue, refer to the listed section number.



Table 6-3: South Island grid backbone transmission issues

Section number

Issue

6.6.1 Upper South Island voltage stability

6.6.2 Upper South Island transmission capacity

6.6.3 Transmission capacity north of Roxburgh and within the Waitaki Valley

6.6.4 Transmission capacity south of Roxburgh

Figure 6-13: South Island grid backbone area

Upper South

Island area

Waitaki Valley area

North of Roxburgh area

South of Roxburgh area

Southland area

6.6.1 Upper South Island voltage stability

Overview

Most of the Upper South Island load is supplied through four 220 kV circuits from the Waitaki Valley. The Upper South Island area has relatively little generation compared with load. The generation is connected to the regional grid or embedded within the distribution networks.

The transmission capacity to supply the Upper South Island is limited by voltage stability. Voltage stability within this area is influenced by:

the reactive power losses due to the transmission system within the area

the reactive power demand due to load composition in the area (in particular the proportion and type of motor load), and

generation in the area

Reactive support for the Upper South Island is provided by:

synchronous condensers and SVCs at Islington

a STATCOM at Kikiwa, and

capacitor banks at Islington on the grid backbone and, within the regional grids capacitor banks at Islington, Bromley, Southbrook, Blenheim, Stoke, Greymouth, and Hokitika.



The contingencies which may cause a voltage stability issue are:

from winter 2016, an outage of an Islington bus section which disconnects a number of transmission elements

21, increasing the reactive power that will be

absorbed by the remaining in-service circuits and transformers

from winter 2017, an outage of the Islington–Tekapo B circuit, and

from 2017, an outage of an Ashburton bus section.

Approved projects

We regularly invest in grid upgrades to raise the voltage stability limit, to match load growth. Recent investments include a second SVC at Islington and a STATCOM at Kikiwa. Most recently, we installed a Reactive Power Controller (RPC) at Islington to co-ordinate various dynamic and static devices in the Upper South Island.

We intend to install an additional bus coupler circuit breaker at Islington to address Upper South Island voltage stability up to 2017.

Voltage stability will be an ongoing issue which will require regular investments to match load growth.


The five generation scenarios described in Chapter 5 have the following impacts on the Upper South Island backbone grid.

All generation scenarios have new generation or demand side reduction within the Upper South Island. This will improve voltage stability, which may defer or replace the need for transmission investment. Generation scenarios 1 (‘sustainable path’), 2 (‘South Island wind’) and 3 (‘medium renewables’) have the highest amount of new generation. Generation scenarios 4 (‘coal’) and 5 (‘high gas discovery’) have the least new generation over the next five years, and would be insufficient to defer transmission investment.

Outages

An outage of a circuit or other transmission element for maintenance will increase the reactive power losses of the transmission system. This requires maintenance to be scheduled for a low load period, load reduction, generation to be constrained on, and/or additional investment in reactive support.

Resolving projects

We will install a sixth bus coupler at Islington to create an additional bus zone to minimise the equipment tripping following a bus fault, and so improve voltage stability.

We have also commenced an investigation to determine the amount of additional reactive support required in the next tranche of investments to relieve the Upper South Island voltage stability issue. Transmission options include:

a combination of static and dynamic reactive support around Islington and Bromley, and/or

sectionalising the 220 kV circuits from the Waitaki Valley to Islington by bussing them at a new switching station near Geraldine; this also requires a short section of new transmission line to bring all circuits to Geraldine.

In the longer-term, transmission options include:

about 350 Mvar of additional reactive support may be required by 2027, and

21

The critical Islington bus section outage disconnects: Islington–Tekapo B, Islington–Waipara–Culverden–Kikiwa 2, a capacitor bank, and T7 (220/66 kV transformer).



reinforcing 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 capacity

Overview

Power transfer to the Upper South Island is through four 220 kV circuits from the Waitaki Valley.

The Islington 220 kV bus is a single major node, supplying a large proportion of the load 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 a significant or total loss of supply, either with all equipment in service or during maintenance outages.

Approved projects

There are no approved grid backbone projects in the Upper South Island area for transmission capacity.

System condition (north flow)

The Upper South Island has relatively little generation compared with the load, even at minimum load. Therefore, power always flows from the Waitaki Valley northwards.

The n-1 transmission (thermal) limit for the Upper South Island area is forecast to bind towards the end or just beyond the forecast period (2027).


The five generation scenarios described in chapter 5 all have new generation north of Islington, or demand response to reduce peak demand. More generation or demand response defers the onset of the n-1 transmission limit.

Outages

“Outage windows” are required so a circuit can be taken out of service for maintenance while managing the grid to provide n-1 security. The number and duration of outage windows available for maintenance depends on the load, load management, and generation within the area. It is possible that insufficient outage windows will be available within the forecast period to enable the required maintenance, or for upgrading circuits.

Resolving projects

Options to address the n-1 transmission capacity towards the end of the forecast period include:

an HVDC tap-off from the existing HVDC line north of Christchurch

a new transmission line to Ashburton or Islington.

These resolving projects may need to be brought forward a few years to ensure there are enough opportunities to take equipment out of service for maintenance.

We will monitor the loading on the Upper South Island circuits to determine when a transmission upgrade investigation is required.



6.6.3 Transmission capacity north of Roxburgh and within the Waitaki Valley

Overview

Two sub-areas make up the grid backbone in the area: within the Waitaki Valley, and from Roxburgh to the Waitaki Valley.

The grid backbone within the Waitaki Valley connects:

the Upper South Island area, at Twizel and Livingstone

the Waitaki Valley hydro generators22

at six substations

the inter-island HVDC link at Benmore, and

the transmission system to Roxburgh, from Twizel and Livingstone.

The direction and amount of power flowing through the circuits within the Waitaki Valley depends on the load in the Upper South Island, the generation in the area, the amount and direction of HVDC transfer, and the net Otago-Southland load.

The grid backbone from Roxburgh to the Waitaki Valley provides through-transmission to the Otago/Southland area. The direction of the power flow may be north 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 generation at Clyde and, to a lesser extent, by the load off-take at Cromwell and Naseby.

Approved projects

The Clutha–Upper Waitaki Lines Project (CUWLP) is an approved suite of projects23

to increase transmission capacity for:

low generation in the Otago-Southland area, which causes high ‘south’ power flows from within the Waitaki Valley to Roxburgh, and

high generation in the Otago-Southland area, which causes high ‘north’ power flows from Roxburgh to the Waitaki Valley.

The first tranche of projects is to increase the transmission capacity to address high south power flows. We will:

duplex the Clyde–Roxburgh 1 and 2 circuits in 2013, and

duplex the Aviemore–Waitaki–Livingstone circuits in 2014.

Duplexing these circuits approximately doubles the south transmission thermal capacity

24 to export power from the Waitaki Valley to Roxburgh, (from 250-280 MW to

560-590 MW)25

. There is no significant change in the north transmission thermal capacity.

The second tranche of projects is to:

duplex the Roxburgh–Naseby–Livingstone circuits

duplex the Aviemore–Benmore 1 and 2 circuits, and

thermally upgrade Cromwell–Twizel 1 and 2 circuits.

22

The six hydro power stations that connect to the grid backbone in the Waitaki Valley are: Ohau A, Ohau B, Ohau C, Benmore, Aviemore, Waitaki.

23 The Clutha–Upper Waitaki Lines Project (CUWLP) was previously referred to as the Lower South

Island Renewables Grid Upgrade Project, approved by the Electricity Commission in August 2010. 24

The increase in south transmission capacity occurs only after all the referenced circuits are duplexed; there is no significant increase in south transmission capacity with only some of the circuits duplexed.

25 The amount of power that can be exported from the Waitaki Valley to Roxburgh varies with

generation, 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 in the Roxburgh–Waitaki Valley area.



The primary benefit of the second tranche of projects is to increase the north transmission thermal capacity. When there is high generation in the Otago-Southland area, and at Roxburgh and Clyde, power is exported to the Upper South Island area and/or the HVDC link at Benmore. The increase in transmission thermal capacity is progressive, with increased transmission capacity available at the completion of each upgrade. The north transmission thermal capacity increases from its existing level of 200-590 MW to 790-1,260 MW

26 once all the upgrades are completed.

The justification for increasing the north transmission thermal capacity is twofold, to:

enable full output from existing generators at Clyde, Roxburgh and the Otago/Southland area, and

enable new generation projects in the Otago/Southland area. We will review the second tranche of projects in 2013, to optimise the timing of the upgrades.

The second tranche also significantly increases the south transmission thermal capacity, to 560–590 MW. However, it is expected that most of this south transmission capacity will not be required.

Figure 6-14 shows the circuits in the Waitaki Valley after the upgrades.

Figure 6-14: 220 kV circuits between Roxburgh and Twizel after CUWLP upgrade

LivingstoneNaseby

Twizel

Ohau B

Ohau C Benmore

Waitaki

Aviemore

Cromwell

Clyde

Roxburgh


rating

Aviemore–Benmore 1 and 2 609/671 MVA1

Aviemore–Waitaki 1 609/671 MVA

Livingstone–Waitaki 1 609/671 MVA

Livingstone–Naseby 1 609/671 MVA1

Naseby–Roxburgh 1 609/671 MVA1

Clyde–Cromwell–Twizel 1 and 2 561/617 MVA1

Clyde–Roxburgh 1 and 2 347/382 MVA

Benmore–Twizel 1 404/493 MVA

Benmore–Ohau B 1 561/617 MVA

Ohau B–Twizel 3 694/760 MVA

Benmore–Ohau C 2 561/617 MVA

Ohau C–Twizel 4 694/764 MVA

1The timing to upgrade these circuits will be reviewed in 2013. The summer/winter rating for these circuits prior to upgrade is:

202/246 MVA for Aviemore–Benmore 1 and 2,

Roxburgh–Naseby–Livingstone 1, and

385/470 MVA for Cromwell–Twizel 1 and 2.

The following sections assess the transmission capability following the CUWLP upgrade. The assessment is based on representative system conditions, to determine how different generation development scenarios interact with the Waitaki Valley area.


This system condition tests power flowing from the Lower South Island to the upgraded HVDC link:

maximum South Island generation

26

The amount of power that can be sent from Roxburgh to the Waitaki Valley varies with generation and load. The large range for north transmission capacity is mainly due to the effect of generation at 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.



off peak South Island load (approximately 62% of island peak)

maximum HVDC north transfer of 1,400 MW

There were no issues with transmission capacity for north flow for the forecast period.


This system condition tests power flowing south of Roxburgh/Clyde during a period of extremely low southern generation fully utilising the upgraded HVDC links south flow capacity. To avoid overloading the grid backbone (after the CUWLP projects are completed):

in 2018, a minimum total of about 362 MW of generation is required at Manapouri, Roxburgh and Clyde power stations

in 2027, a minimum total of about 670 MW is required at Manapouri, Roxburgh and Clyde power stations.


The five generation scenarios described in Chapter 5 have the following impacts on the circuits within the Waitaki Valley area.

There were no issues with transmission capacity for north flow for all generation scenarios.

High levels of power flow south towards Roxburgh, with high levels of HVDC south flow, overloaded the Benmore–Twizel circuit.

As noted in the previous section for system condition 2 (south flow), minimum levels of generation are required south of Roxburgh/Clyde. Any new generation south of Roxburgh increases the options for providing the minimum generation requirements, assisting in the management of the power system.

Outages

The transmission capacity is reduced during outages, which may require generation in the Waitaki Valley or Lower South Island area to be constrained.

Resolving projects

For very high power flows from the Waitaki Valley to the Lower South Island, the Benmore–Twizel circuit capacity will need to be increased. Transmission solutions to prevent overloading of the Benmore–Twizel circuit include

27:

variable line ratings to alleviate some overloads in the short term, and

thermally upgrading and/or reconductoring the Benmore–Twizel circuit.

We will monitor the loading of the Benmore–Twizel circuit to determine if a transmission upgrade investigation is required.

Any further increase in south transmission capacity beyond that provided by the suite of projects provided by CUWLP will require a new transmission line. We will monitor the load and minimum generation levels required to determine if a new line investigation is required. The present load forecasts do not indicate the need for a new transmission line.

27

We believe that only a relatively small increase in the rating of the Benmore–Twizel circuit is required (about 20%), and that reconductoring the circuit is not required.



6.6.4 Transmission capacity south of Roxburgh

Overview

The grid backbone south of Roxburgh is primarily a six circuit “triangle” between Roxburgh, Three Mile Hill and Invercargill/North Makarewa. There are also nine circuits connecting Invercargill, North Makarewa, Manapouri and Tiwai.

There is a low capacity 110 kV regional network which operates in parallel with the grid 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 by the large hydro generator at Manapouri and the large load at Tiwai.

Presently, the main concern for the grid backbone in this area is the transmission capacity supplying the regional load when Manapouri generation is low and Southland demand is high. An outage of one of the two Invercargill–Roxburgh circuits may result in:

overloading of the other Invercargill–Roxburgh circuit

low voltages in Southland, and

overloading of the regional 110 kV network between Gore and Roxburgh and the Roxburgh 220/110 kV transformer (see Chapter 19 for more information).

These issues are presently managed by constraining on minimum levels of generation and voltage support at Manapouri.

Figure 6-15 shows the 220 kV grid backbone circuits south of Roxburgh.

Figure 6-15: Grid backbone circuits south of Roxburgh

Invercargill

Tiwai

Manapouri

North Makarewa

Three

Mile Hill

Roxburgh Circuit Summer/Winter

rating

Invercargill–Roxburgh 1 and 2 347/382 MVA

Invercargill–Manapouri 2 311/380 MVA

Invercargill–North Makarewa 1 404/457 MVA1

Manapouri–North Makarewa 1, 2 and 3 311/380 MVA

Invercargill–Tiwai 1 and 2 385/457 MVA2

North Makarewa–Tiwai 1 and 2 385/470 MVA

Roxburgh–Three Mile Hill 1 and 2 385/470 MVA

North Makarewa–Three Mile Hill 1 and 2 347/382 MVA

1. The winter rating is presently limited by a substation component

limit; with this limit resolved, the winter rating will be 493 MVA.

2. The winter rating is presently limited by a substation component

limit; with this limit resolved, the winter rating will be 470 MVA.

Gore

Approved projects

The Lower South Island Reliability Grid Upgrade Plan is a suite of projects to increase the grid backbone transmission capacity for power flow south from Roxburgh.

Projects to remove the constraint on the grid backbone caused by the regional 110 kV grid include (see Chapter 19 for more information):

replacing the Roxburgh 220/110 kV transformer with a higher rated transformer in November 2012 (this will slightly ease, but not remove, the existing constraints), and

providing a 220/110 kV connection at Gore, and reconfigure the 110 kV network in 2014 (this will provide a measureable increase in south transmission capacity).

There is also an approved project to further increase the south transmission capacity by installing a series capacitor on one of the two North Makarewa–Three Mile Hill



circuits. The timing for this series capacitor will be reviewed in 2013, to optimise the timing of the upgrade.


This system condition tests power flowing north to Roxburgh:

maximum South Island generation

off peak South Island load (approximately 62% of island peak)

maximum HVDC north transfer of 1,400 MW

There are no issues with the transmission capacity south of Roxburgh during north power flow for the forecast period.


This system condition tests power flowing south of Roxburgh during periods of low generation, particularly at Manapouri. To avoid overloading of the grid backbone (after the Lower South Island Reliability upgrades are completed) requires increased minimum generation in the Southland area as the load in the area increases. In 2027, approximately 350 MW of generation is required (principally from Manapouri) to avoid overloading of the grid backbone circuits supplying the Southland load.

Impact of Generation scenarios

The five generation scenarios described in Chapter 5 have the following impacts on the circuits south of Roxburgh.

Generation scenario 4 (‘coal’) connects new generation at North Makarewa (240 MW wind in 2018, 400 MW peak thermal in 2025). This will cause the Invercargill–North Makarewa circuit to overload, even with all circuits in service.

Connecting new generation to a North Makarewa–Gore–Three Mile Hill circuit may cause the circuit to overload.

There are no other grid backbone issues with additional generation (although all generation scenarios have 110 kV regional grid issues, see Chapter 19).

Any additional generation will assist in managing the power system during periods of low generation.

Outages

The transmission capacity is reduced during outages, which will constrain the minimum and maximum generation in the Otago-Southland area.

Resolving projects

The above issues are emerging late in the forecast period.

Transmission solutions to prevent overloading of the Invercargill–North Makarewa circuit include a combination of:

reconfiguring the grid by bussing the Invercargill–Manapouri circuit at North Makarewa

thermally upgrading the Invercargill–North Makarewa circuit(s), possibly combined with variable line ratings, and/or

reconductoring the Invercargill–North Makarewa circuits.

Transmission solutions to prevent overloading of the North Makarewa–Gore–Three Mile Hill circuit include:

a protection scheme to automatically reduce generation if the circuit overloads



a thermal upgrade of the circuits, combined with variable line rating and/or

a reconductor of (part of) the circuit.

Any further increase in south transmission capacity following completion of the Lower South Island Reliability projects will require a new transmission line. The present load 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 to 75 Mvar

28

additional capacitors

operating Manapouri generators at 0 MW to provide voltage support.

28

The two existing 50 Mvar capacitors at North Makarewa are designed to be easily upgraded to 75 Mvar.



6.7 HVDC link overview

The 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 hydro generation capacity, which may be important for the North Island in peak winter periods. For the South Island, the HVDC link provides access to the North Island’s gas 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 would be needed. In addition, the HVDC link is essential for the electricity market as it allows generators in the North and South Islands to compete, putting downward pressure on prices and minimising the need to invest in expensive new generating stations. The HVDC link also plays an important part in allowing renewable energy sources to be managed between the two islands.

6.7.1 Existing HVDC link configuration

Figure 6-16 shows a simplified schematic of the existing HVDC link, which comprises:

a mercury arc converter (Pole 1), with a converter station at Benmore in the South Island and Haywards in the North Island

a thyristor converter (Pole 2), with a converter station at Benmore in the South Island and Haywards in the North Island

protection and control systems at Benmore and Haywards

a 350 kV bipolar transmission line, 534 km long from Benmore to Fighting Bay on the shore of Cook Strait in the South Island and 37 km long from Haywards to Oteranga Bay on the shore of Cook Strait in the North Island

three 350 kV undersea 40 km cables, with cable terminal stations at Fighting Bay and Oteranga Bay, and

a land electrode at Bog Roy near Benmore in the South Island and a shore electrode at Te Hikowhenua near Haywards in the North Island.

Figure 6-16: Existing HVDC link

BENMORE

220 kV

HAYWARDS

220 kV

Cable 6

Cable 4

Pole 2

(existing thyristor

Converters 700 MW)

535 km DC line

section – South

Island

35 km DC line

section

North Island

40 km Cook Strait

Cables

+ 270 kV

- 350 kV

Cable 5

HAYWARDS

110 kV

C7

BENMORE

16 kV

Ground (Earth/Sea) Return Current mode

F4

79.3 Mvar

79.3 Mvar

F3

F3

F4

106.3 Mvar

106.3 Mvar

C1

60 Mvar

T1

C4C335 Mvar

each

T5

C2 60 Mvar

T2

40 Mvar

R5

40 Mvar

R1T2

50.5 Mvar

F1

F2

47.5 Mvar

47.5 Mvar

C9

C10Pole 1 assets

Pole 2 assets

VG3

VG4

P1B

VG2

VG1

P1A

F1

C8

6.7.2 Future HVDC link configuration

Figure 6-17 shows a simplified schematic of the HVDC link as it will be following the completion of the Pole 3 project in 2012/13. The Pole 3 project will replace the Pole 1 mercury arc converters with new converters similar to the existing Pole 2 converters, and connected to the 220 kV buses at Haywards and Benmore. The work includes:



new thyristor based converters at Benmore and Haywards, including the associated converter transformers and DC smoothing reactors

new 220 kV AC filters at Benmore and Haywards

replacement of the existing 110 kV AC filters at Haywards

refurbishment of all synchronous condensers at Haywards and new 110/11 kV transformers for four of the condensers, and

replacement of HVDC protection and controls.

Figure 6-17: Pole 2/Pole 3 HVDC link

BENMORE

220kV HAYWARDS

220kV

Pole 2

existing

Thyristor

converters

(700 MW)

535 km DC

line section

South Island 40 km Cook Strait

Cables

+ 350 kV

- 350 kV

HAYWARDS

110kV

C7

F3

F4

79.3 Mvar

79.3 Mvar

Stage 1 – 1000 MW

Existing

Stage 2 – 1200 MW

F3

F4

106. 3 Mvar

106. 3 Mvar

C7-C10

65 Mvar

each

Cable 6

Cable 4

Cable 5

35 km DC line

section North

Island

Pole 3

Thyristor

converters

(700 MW) New 220 kV

Filter/s

C1

60 Mvar

T1

40 Mvar

R1

C4C335 Mvar

each

T5

C2 60 Mvar

T2

40 Mvar

R5

C8

C9

C10

New

5th/7

th

Filter/s

New 220 kV Filter/s

New Statcom

Figure 6-18 shows a simplified diagram for a possible further expansion of the HVDC link to 1,400 MW north capacity following completion of the Pole 3 project. This would involve the installation of:

one additional submarine cable

additional filters at both Benmore and Haywards, and

additional dynamic reactive support at Haywards.

Figure 6-18: Possible future HVDC link

BENMORE

220kV HAYWARDS

220kV

Pole 2

Thyristor

converters

(700 MW)

535 km DC

line section

South Island 40 km Cook Strait

Cables

+ 350 kV

- 350 kV

HAYWARDS

110kV

C7

F3

F4

79.3 Mvar

79.3 Mvar

Existing after

completion of Stage 2

F3

F4

106. 3 Mvar

106. 3 Mvar

C7-C10

65 Mvar

each

Cable 6

Cable 4

Cable 5

35 km DC line

section North

Island

Pole 3

Thyristor

converters

(700 MW) 220 kV

Filter/s

C1

60 Mvar

T1

40 Mvar

R1

C4C335 Mvar

each

T5

C2 60 Mvar

T2

40 Mvar

R5

C8

C9

C10

5th/7

th

Filter/s

220 kV Filter/s

Statcom

Stage 3 – 1400 MW

New 220 kV

Filter/s

New 220 kV Filter/s

New Statcom

Cable 7



6.8 HVDC link issues and project options

6.8.1 HVDC link capacity

In 1992, the HVDC link capacity was 1,240 MW, with a Pole 1 capacity of 640 MW and a Pole 2 capacity of 700 MW.

The HVDC link capacity is now significantly lower. Pole 1 is available for only limited operation, including north transfer only of between 130 MW and 200 MW. 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 the reserve cover available, which significantly reduces the maximum practical transfer limit.

It is economic to restore the HVDC link capacity.

The Pole 3 project, to replace Pole 1, will provide an HVDC link capacity of 1,000 MW (north and south power flow), with a possible increase to 1,200 MW in 2014. It will not always be possible to use the full capacity of the HVDC link. Power transfer between the North and South Islands may be limited by the availability of instantaneous reserves and the capacity of the North and South Island 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 to replace Pole 1 is completed in 2012/13.

6.8.2 State of existing equipment

Pole 1

Pole 1 was commissioned in 1965. Half of the original Pole 1 was decommissioned in December 2009.

The remaining half of Pole 1 is available under limited conditions: for normal operation, in response to Grid emergencies, and for testing. The conditions include north transfer between 130 MW and 200 MW, with automatic controls unavailable (except frequency modulation). Other conditions include a limit on the number of starts, minimum operating time per start and cumulative operating time

29.

When Pole 1 is not operating, HVDC bipole operation is not available. Without bipole 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, and

ground (sea/earth) return current.

With regard to the reserve cover required, in bipole operation should one pole fail then the remaining pole can increase its power transfer, which provides some self cover. This could be partial or full load cover depending on pre-fault power flow of the remaining pole. There is no 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, the normal link transfer is dependent on the reserve cover available. This significantly reduces the practical transfer limit at most times.

Also, a planned or unplanned outage under monopolar operation decouples the two islands, reducing the generation available to both islands and introducing price separation (or reduced competition).

29

For further details of the HVDC Pole 1 offer, see http://www.transpower.co.nz/grid-owner-notices.



With regard to ground (sea/earth) return current, in monopolar operation all of the HVDC current flows in the ground.

30 To date, we have not had any problems with

ground return current, other than wear on the sea/earth electrodes.

The effect of the restricted operating conditions for Pole 1 highlights the need for its replacement.

Pole 2

Pole 2 was commissioned in 1991, with a design life of 35 years for the main circuit equipment, although most of the equipment is expected to last longer. Some main circuit equipment is also common to Pole 1 and Pole 2 (neutral bus and electrode line equipment), which was also installed in the early 1990s.

The nominal rating of Pole 2 is 560 MW, with a continuous overload of 700 MW. The continuous overload has proved very beneficial for limiting reserve requirements and managing emergency conditions.

HVDC controls

All the HVDC Pole 1 and bipole controls and protections date from when Pole 2 was installed in the early 1990’s. These digital control systems face obsolescence because the lifetime of control systems (about 15-20 years) is shorter than that of the main circuit equipment, thus requiring at least one full replacement within the lifetime of the HVDC converter equipment.

HVDC transmission lines

The transmission line was originally built for +/- 250 kV 1200 A operation (600 MW bipole operation). During the hybrid link upgrade, the line was re-insulated to operate at 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.

Most of the conductor on the line in the North Island is nearing the end of its serviceable life, based on condition assessment. Most of the conductor in the South Island is expected to have a remaining service life of several decades.

About 100 of the 1,530 towers in the South Island need to be replaced to correct a number of conductor clearance and tower strength issues as part of the line maintenance work.

HVDC submarine cables

Three cables (each rated 500 MW at 350 kV) were installed as part of the Hybrid DC link upgrade project in the early 1990s.

Between 1991 and 2004, the three cables had performed well with no major issues or failures. In October 2004, a cable failed and was out of service for six months while repairs were carried out. It was fortunate that this fault was in shallow water in Oteranga Bay so it could be repaired using a locally available barge, with sufficient time to mobilise a repair before the limited weather window in February/March ended.

While the cause of failure is difficult to establish, and the balance of probabilities indicates that it is likely to be a localised problem, it is also possible that there is a latent design weakness or manufacturing defect which could result in another fault in the cable, or even one of the other cables.

30

In balanced bipole operation, the dc current in both poles is equal and opposite (within an accuracy of about 4 amps). Thus the current in one Pole returns through the other Pole, and the 4 amps of unbalanced current flows in the ground (sea/earth) electrode.



There is a Cable Protection Zone (CPZ) to exclude external activities which might damage the cables. These cables are also under constant marine patrol preventing fishing and trawling activities within the CPZ. Regular Remote Operated Vehicle (ROV) surveys are also undertaken to monitor the external condition of the cable and the environmental factors affecting the cables.

The cables’ design and the CPZ help ensure the cables will achieve their 40 year design life. However, sea conditions and seabed movement makes Cook Strait one of the most aggressive locations for submarine cables in the world. The abrasion-corrosion conditions in Cook Strait are understood and mechanical deterioration is likely to be the determinant factor in determining the life expectancy of the cables.

HVDC electrodes

A bipolar HVDC link operating with balanced current in both poles has only a small amount of residual ground current. In unbalanced bipolar operation, or in monopolar operation, a return current path needs to be provided.

The return current path is via the earth (ground), which requires a land electrode at Bog Roy, for Benmore, and a shore electrode at Te Hikowhenua, for Haywards station. These electrodes are designed for continuous operation at 2000 amps. This corresponds to 700 MW monopolar operation at 350 kV DC. It is capable of operating at 2400 A for intermittent (few hours at a time) operation.

Monopolar operation depends on the availability and integrity of the electrodes to ensure safe operation of the link. The long term impact of operating in continuous monopolar operation at high power levels is not readily available. Since the partial decommissioning and restricted operation of Pole 1, monopolar operation of the HVDC link has been its normal operating mode. We and our contractors carry out regular maintenance work to ensure the integrity of these electrodes, and the electrodes remain within their design limits.

Synchronous condensers

There are eight synchronous condensers at Haywards, providing reactive support and improving system strength to enable stable operation of the HVDC link. The number of synchronous condensers that need to be in service depends on the HVDC bipole power transfer, if all other system conditions are equal.

Four condensers are connected to the tertiary windings of the 220/110/11 kV interconnecting transformers. Two condensers are connected through recently installed new 110/11 kV transformers. The other two condensers are connected to the tertiary windings of the Pole 1 converter transformers. The Pole 1 transformers are nearing the end of their reliable economic life.

The condensers were installed between 1955 and 1965 and are of very robust design and construction. Good international practice is for major overhaul and invasive maintenance 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 nearing the end of its reliable economic life.

6.8.3 Approved HVDC link projects (Stage 1 and 2)

The HVDC Pole 3 project is an approved project, presently under construction, to increase the HVDC link capacity (refer to Section 6.8.1) and address equipment issues (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, and

Stage 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 connection and commissioning of Pole 3 has the potential to significantly affect the operation of the power system and the electricity market. An industry group has been established to coordinate outage and 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 current rating of 2000 A, to give a 700 MW converter. The upper limit on the voltage is set by the existing line design and cable ratings. The maximum nominal current is limited by the 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 system reserve requirements.

HVDC transfer north up to 1,000 MW in balanced 500/500 MW bipole operation is possible.

Only three cables are available, which limits the self cover of the HVDC for a pole trip:

Pole 3 will have two cables connected, so the short-term 1,000 MW capacity of Pole 3 is matched by the 1,000 MW cable capacity, but may be limited by the steady-state 700 MW rating of the transmission line. Pole 3 will provide a minimum 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 be limited by the 500 MW rating of the cable. Pole 2 will provide cover up to 500 MW for a failure of Pole 3.

As discussed in Section 6.8.1, the south transfer capability is limited by the capacity of the AC network in the North and South Islands, and varies significantly with the system demand in the Wellington region because of the AC system limitation. The HVDC controls will apply a maximum south transfer limit of 750 MW to represent this AC system limitation with all equipment in service and at a time of minimum system demand. The south transfer capability will reduce below this value as the demand increases (and during equipment outages).

110 kV filters at Haywards

The 110 kV connected filters at Haywards, installed as part of the original HVDC Link in the mid 1960s, will be replaced by 5

th/7

th harmonic filters.

Synchronous condensers at Haywards

The eight existing condensers will be retained and refurbished. The two condensers that are connected to the Pole 1 mercury arc valve converter transformers will be reconnected to the 110 kV busbars with new transformers after Pole 1 is decommissioned.

Pole 2 and Bipole protection and control

The Pole 2 and Bipole control systems will be replaced with identical technology to that of new Pole 3. The Pole 2 valve firing controls will be replaced as part of the new Pole 2 control system, and will interface to the existing valve based electronics (which will be retained) at the thyristors.

The new control system will be very flexible. It will monitor and control the HVDC transfer to manage system conditions at Haywards and Benmore and on the AC network at Haywards. The flexibility of the new control system will provide options to modify it, allowing the AC network to operate above the n-1 limit by relying on the HVDC control system to prevent post-contingency overloads.



Haywards STATCOM (Stage 2 – 1,200 MW)

In addition to the existing synchronous condensers, additional dynamic reactive power 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 stability

limit excessive transient or temporary overvoltage (TOV) following a bipole trip.

A STATCOM with a substantial overload rating will provide the necessary dynamic reactive support for HVDC capacity of 1,200 MW. The STATCOM has a nominal rating of +60/-60 Mvar and a short-term rating which is expected to be a minimum of +100/-180 Mvar.

HVDC north transfer up to 1,200 MW is possible with unbalanced 700/500 MW operation of Pole 3/Pole 2.

Only three cables are available, which limits the self-cover of the HVDC for a pole trip as described for Stage 1.

As for Stage 1, the south transfer capability is limited by the capacity of the AC network 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 with all equipment in service and at a time of minimum system demand. The increase from 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 rating

Each of the poles on the HVDC line has a steady state rating of 700 MW, whereas Pole 3 will have a minimum short-term rating of 1,000 MW for 30 minutes. The short-term rating of the line depends on its pre-contingency loading and ambient air temperature. At times, the full short-term rating of Pole 3 may be restricted by the rating of the line.

6.8.4 Further HVDC developments

HVDC link expansion to 1,400 MW

Following the Pole 3 project, the HVDC Link can be further expanded to 1,400 MW north transfer capacity with the installation of:

one additional submarine cable

additional filters at both Benmore and Haywards, and

additional dynamic reactive support at Haywards.

Figure 6-18 (in Section 6.7.2) shows a simplified diagram for this possible upgrade.

The HVDC controls will limit the maximum south transfer to 950 MW with all equipment in service and at a time of minimum system demand. The increase from Stage 2 is due to the additional reactive support at Haywards. The south transfer capability will reduce below this value as the demand increases (and during equipment outages)

When planning for the additional cable, the condition and risks associated with the existing cables will also be reviewed and the need for a spare (fifth) cable will be assessed.

The timing for this possible upgrade will be assessed following completion of the Pole 3 project. The earliest anticipated date for expansion to 1,400 MW is presently 2017 and we anticipate seeking approval from the Commission in 2014. This would be a major capex proposal and our project reference is HVDC-TRAN-DEV-03.



We anticipate that a capacity increase to 1,400 MW will provide sufficient capacity to enable diversity of generation in the North and South Islands for the foreseeable future.

HVDC line rating

The HVDC line’s capacity could be increased to allow the unconstrained use of the converters’ short-term overload rating for all operating conditions. We will monitor the use of the HVDC link to determine if and when an investigation for an upgrade of the HVDC line may be required. This is a possible major capex proposal and we anticipate seeking approval for this project at a date to be advised. Our project reference is HVDC-TRAN-DEV-02.

Chapter 7: Northland Region


7 Northland Regional Plan

7.1 Regional overview

7.2 Northland transmission system

7.3 Northland demand

7.4 Northland generation

7.5 Northland significant maintenance work

7.6 Future Northland projects summary and transmission configuration


7.8 Northland transmission capability

7.9 Other regional items of interest

7.10 Northland generation proposals and opportunities


This chapter details the Northland regional transmission plan. We base this regional plan on an assessment of available data, and welcome feedback to improve its value to all stakeholders.

Figure 7-1: Northland region



The Northland region load includes greater Auckland loads such as Henderson and Albany, a major industrial load at Bream Bay, and loads at smaller regional centres to the north.

We have assessed the Northland region’s transmission needs over the next 15 years while considering longer-term development opportunities. Specifically, the transmission network needs to be flexible to respond to a range of future service and technology possibilities, taking into consideration:

the existing transmission network

forecast demand

forecast generation

equipment replacement based on condition assessment, and

possible technological development.

7.2 Northland transmission system

This section highlights the state of the Northland regional transmission network. The existing transmission network is set out geographically in Figure 7-1 and schematically in Figure 7-2.

Figure 7-2: Northland transmission schematic

110kV CIRCUIT

50kV CIRCUIT

SUBSTATION BUS

TRANSFORMER

KEY

220kV CIRCUIT

LOAD

CAPACITOR

OtahuhuAUCKLAND

220 kV

220 kV

220 kV

110 kV

Mount Roskill

110 kV

110 kV50 kV

50 kV

33 kV

33 kV

33 kV

11 kV

33 kV

110 kV

33 kV

33 kV

220 kV

Southdown

33 kV

220 kV 110 kV

110 kV

33 kV

VECTOR

WAIRAU ROAD

Kaikohe

Maungatapere

Dargaville

Kensington

Bream Bay

Marsden

Silverdale

Albany

Hepburn Road

Henderson

Huapai

SVC

SVC STATIC VAR

COMPENSATOR

BONDED CIRCUIT

110 kV

33 kV

Kaitaia

110 kVMaungaturoto

110 kV

33 kV

Wellsford

Lines company assets



7.2.1 Transmission into the region

The Northland region is supplied through Auckland by a 220 kV double-circuit line from Otahuhu, with Southdown power station connected into one of these circuits just north of Otahuhu, and a 110 kV double-circuit line from Mount Roskill.

The Northland region’s generation capacity is well short of the local demand. Most of the region’s power requirements must be imported into the region through Auckland.

We have committed to a major project to improve security of supply into the Northland region. The North Auckland and Northland (NAaN) project (see Chapter 8 for more information) includes a 220 kV cable from Pakuranga to Penrose and on to Albany. This will approximately double the n-1 capacity into Northland, and will take a different route across Auckland from the existing 220 kV circuits. When required, a second 220 kV cable will be installed along a similar cable route.

7.2.2 Transmission within the region

Transmission within the Northland region consists of three sub-regions.

The first sub-region consists of five substations31

within the Auckland city area. The substations are connected through high capacity 220 kV circuits or relatively high capacity 110 kV circuits. There are six capacitor banks

32 and a static var

compensator (SVC) for voltage support.

The second sub-region is the high capacity 220 kV double-circuit line from Huapai to Marsden and Bream Bay. Two static synchronous compensators (STATCOMs) are being installed at Marsden for voltage support.

The third sub-region is around Maungatapere, supplied mainly through the 110 kV double-circuit Marsden–Maungatapere line. There is also a low capacity backup double circuit Henderson–Maungatapere line, with substations at Wellsford and Maungaturoto. From Maungatapere there is a 110 kV double-circuit line to Kensington and a 110 kV double-circuit line to Kaikohe. There are also two 50 kV single-circuit Maungatapere–Dargaville lines. At present, voltage support for the sub-region is provided by capacitors at Kaitaia and, within the distribution, at Kaikohe.

There are five 220/110 kV interconnecting transformers: two at Henderson, one at Albany, and two at Marsden.

7.2.3 Additional voltage support

The sub-region around Maungatapere will require additional voltage support in both the short and long term. Technically, the most effective voltage support solution is to over-compensate the system by installing additional capacitors at Kaitaia, so reactive power flows from Kaitaia to Kaikohe and Maungatapere.

If additional voltage support is installed at Maungatapere, then higher capacity equipment must be installed to achieve the same voltage set point. This may require STATCOMs or similar technology rather than lower cost capacitors.

7.2.4 Longer-term development path

The North Auckland and Northland (NAaN) project is expected to secure transmission into Northland well beyond the 15-year forecast period. In the longer term, an additional 220 kV circuit will be required to retain adequate security. This is likely to be a second cable between Penrose and Albany.

31

The five lower sub-region substations are Henderson, Huapai, Albany, Silverdale and Hepburn Road.

32 A 30 Mvar capacitor bank, connected to the 11 kV tertiary of the Henderson T1 220/110 kV

transformer, will soon be decommissioned.



No new transmission lines are expected to be required from the North Isthmus to Northland to provide additional transmission capacity. At most, one of the two 220 kV circuits from Huapai to Bream Bay and Marsden may need to be reconductored from simplex to duplex (the other circuit is already duplex), and the two 110 kV Henderson–Maungatapere circuits may also need to be reconductored.

A new transmission line will be required if an increase in security is required at some time in the future, particularly if security needs to be maintained during maintenance outages.

7.3 Northland demand

The after diversity maximum demand (ADMD) for the Northland region is forecast to grow on average by 2.2% annually over the next 15 years, from 908 MW in 2012 to 1,254 MW by 2027. This is higher than the national average demand growth of 1.7% annually.

Figure 7-3 shows a comparison of the 2011 and 2012 forecast 15-year maximum demand (after diversity

33) for the Northland region. The forecasts are derived using

historical data, and modified to account for customer information, where appropriate. The power factor at each grid exit point is also derived from historical data, and is used to calculate the real power capacity for power transformer and transmission line. See Chapter 4 for more information about demand forecasting.

Figure 7-3: Northland region after diversity maximum demand forecast

Table 7-1 lists forecast peak demand (prudent growth) for each grid exit point for the forecast period, as required for the Grid Reliability Report.

33

The after diversity maximum demand (ADMD) for the region will be less than the sum of the individual grid exit point peak demands, as it takes into account the fact that the peak demand does not occur simultaneously at all the grid exit points in the region.

600

700

800

900

1000

1100

1200

1300

1997 1999 2001 2003 2005 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027

Load (MW)

Northland

2011 APR Forecast

2012 APR Forecast

Actual Peak



Table 7-1: Forecast annual peak demand (MW) at Northland grid exit points to 2027

Grid exit point Power factor

Peak demand (MW)

Next 5 years 5-15 years out

2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Albany 33 kV 0.99 160 165 170 175 180 186 197 207 215 224 231

Albany 110 kV (Wairau Rd)

1

0.99 160 165 170 175 180 186 197 207 215 224 231

Bream Bay2 0.95 45 46 46 47 48 49 52 53 55 56 57

Dargaville 0.97 13 13 14 14 14 14 15 16 16 16 17

Henderson3 0.99 130 134 138 142 146 151 160 168 175 182 187

Hepburn Road 0.99 165 170 175 180 186 191 203 213 222 231 238

Kensington4 0.99 70 71 73 74 75 77 79 82 84 87 90

Maungatapere 33 kV

0.96 54 55 56 57 59 60 62 65 67 70 72

Kaikohe5 0.97 63 65 66 68 70 71 75 78 81 84 86

Maungaturoto 0.99 18 18 18 19 19 19 20 21 21 22 23

Silverdale 0.99 80 82 85 87 90 93 98 103 108 112 115

Wellsford 0.99 35 36 37 38 39 40 42 43 45 47 49

1. A new grid exit point at Wairau Road is planned for commissioning in 2013. This will take some load from the Albany 110 kV grid exit point, although the exact split is not known.

2. The customer advised there are some major step increases proposed at Bream Bay that should be included in the prudent forecast. In particular, 2 MW additional load included in 2019.

3. The customer advised that their forecast is lower than Transpower’s forecast.

4. The customer advised of load transfers between Kensington and Maungatapere. These affect the observed peaks with the amount varying year-on-year.

5. Kaikohe is supplied on two 110 kV feeders from Maungatapere. In previous years, the APR provided separate load forecasts for Kaikohe and Kaitaia; these are now combined in a single load forecast for Kaikohe.

7.4 Northland generation

The Northland region’s generation capacity is approximately 54 MW, well short of the local demand. Proposals for new generation in the Northland region have been announced, but as yet are not committed (see Section 7.10 for more information).

Table 7-2 lists the generation forecast for each grid injection point for the forecast period, as required for the Grid Reliability Report. This includes all known and committed generation stations including those embedded within the relevant local lines company’s network (Vector, Northpower or Top Energy).

34

Table 7-2: Forecast annual generation capacity (MW) at Northland grid injection points to 2027 (including existing and committed generation)

Grid injection point (location if embedded)

Generation capacity (MW)


2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Albany (Rosedale1) 3 3 3 3 3 3 3 3 3 3 3

Bream Bay (Marsden Diesel)

9 9 9 9 9 9 9 9 9 9 9

Kaikohe (Ngawha) 27 27 27 27 27 27 27 27 27 27 27

34

Only generators with a capacity greater than 1 MW are listed. Generation capacity is rounded to the nearest megawatt.






2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Maungatapere (Wairua)

5 5 5 5 5 5 5 5 5 5 5

Silverdale (Redvale) 10 10 10 10 10 10 10 10 10 10 10

1. Rosedale generation is limited to approximately 1 MW due to insufficient gas at the site. This amount is not expected to rise significantly within the next few years.

7.5 Northland significant maintenance work

Our capital project and maintenance works are integrated to enable system issues to be resolved if possible when assets are replaced or refurbished. Table 7-3 lists the significant maintenance-related work

35 proposed for the Northland region for the next

15 years that may significantly impact related system issues or connected parties.

Table 7-3: Proposed significant maintenance work

Description Tentative year

Related system issues

Albany 220/110/11 kV interconnecting transformer expected end-of-life

2022-2024 The appropriate replacement option will be considered and carried out in conjunction with the Henderson interconnecting transformers replacement.

Albany 33 kV outdoor to indoor conversion

2020-2023 Albany supply transformer n-1 capacity is limited by transformer branch component limits. The work to remove these limits will be coordinated with the 33 kV outdoor to indoor conversion work. See Section 7.8.9 for more information.

Henderson 220/110/11 kV interconnecting transformers expected end-of-life

2023-2025 The appropriate replacement option will be considered and carried out in conjunction with the Albany interconnecting transformer replacement.

Henderson 33 kV outdoor to indoor conversion

2014-2016 Henderson supply transformer n-1 capacity is limited by transformer branch component limits. The work to remove these limits will be coordinated with the 33 kV outdoor to indoor conversion work. See Section 7.8.13 for more information.

Hepburn Road 33 kV outdoor to indoor conversion

2014-2016 No system issues are identified within the forecast period.

Kensington supply transformer expected end-of-life

2027-2029 The forecast load at Kensington already exceeds the Kensington transformer n-1 capacity. See Section 7.8.15 for information.

Maungatapere 110/50 kV transformers expected end-of-life

2012-2014 The forecast load at Dargaville already exceeds the Maungatapere transformer n-1 capacity. See Section 7.8.11 for more information.

Maungatapere 110/33 kV transformers expected end-of-life, and 33 kV outdoor to indoor conversion

2018-2020

2022-2025

The forecast load at Maungatapere already exceeds the transformer n-1 capacity. See Section 7.8.16 for more information.

Maungaturoto 33 kV outdoor to indoor conversion


Wellsford supply transformers expected end-of-life

2015-2017 The forecast load at Wellsford already exceeds the transformer n-1 capacity. See Section 7.8.19 for more information.

35

This may include replacement of the asset due to its condition assessment.



7.6 Future Northland projects summary and transmission configuration

Table 7-4 lists projects to be carried out in the Northland region within the next 15 years.

Figure 7-4 shows the possible configuration of Northland transmission in 2027, with new assets, upgraded assets, and assets undergoing significant maintenance within the forecast period.

Table 7-4: Projects in the Northland region up to 2027

Site Projects Status

Albany Replace interconnecting transformer. Resolve supply transformers’ protection and circuit breaker limits. Convert 33 kV outdoor switchgear to an indoor switchboard.

Base Capex Possible Base Capex

Albany– Wairau Road–Hobson Street–Penrose

Construct a new 220 kV underground cable link. Committed

Bream Bay Resolve supply transformer protection limits. Base Capex

Dargaville Use the 15 MVA short-term capacity of the supply transformers. Increase the supply transformers thermal capacity by adding fans and pumps.

Possible Possible

Henderson Replace switchgear on the interconnecting transformers. Replace interconnecting transformers. Install a new 220/33 kV supply transformer Convert 33 kV outdoor switchgear to an indoor switchboard.

Base Capex Base Capex Possible Base Capex

Henderson–Wellsford

Install a special protection scheme to automatically split the system. Possible

Hepburn Road Convert 33 kV outdoor switchgear to an indoor switchboard. Base Capex

Huapai Split the Huapai 220 kV bus. Possible

Kaikohe–Maungatapere

Thermal upgrade the circuits. Possible

Kaitaia Install a second 20 Mvar binary switched capacitor bank. Possible

Kensington Replace supply transformers with higher-rated units. Upgrade 33 kV switchboard.

Possible Base Capex

Kensington–Maungatapere

Resolve protection limits on the Kensington–Maungatauere circuits. Base Capex

Marsden Install two new STATCOMs. Replace interconnecting transformers with higher-rated units.

Committed Possible

Maungatapere Replace 110/50 kV supply transformers with two higher-rated units. Replace 110/33 kV supply transformers. Convert 33 kV outdoor switchgear to an indoor switchboard.

Base Capex Base Capex Base Capex

Maungaturoto Convert 33 kV outdoor switchgear to an indoor switchboard. Resolve supply transformers’ protection and metering limits.

Base Capex Base Capex

Silverdale Recalibrate supply transformers’ metering parameters. Base Capex

Wellsford Replace existing 110/33 kV supply transformers. Base Capex

Wairau Road Construct a new grid exit point. Committed



Figure 7-4: Possible Northland transmission configuration in 2027

Otahuhu

AUCKLAND

220 kV

220 kV

110 kV

220 kV

110 kV

Mount Roskill

110 kV

110 kV

110 kV

110 kV50 kV

50 kV

33 kV

33 kV

33 kV

33 kV

33 kV

33 kV

11 kV

33 kV

110 kV

33 kV

33kV

220 kV

Southdown

33 kV

220 kV 110 kV

110 kV

33 kV

VECTOR

WAIRAU ROAD

SVC

Penrose

Kaitaia

Kaikohe

Kensington

Maungatapere

Dargaville

Bream Bay

Marsden

Maungaturoto

Wellsford

Silverdale

Albany

AUCKLANDHepburn Road

Henderson

Huapai

WAIRAU ROAD220 kV

KEY

STC

33 kV

NEW ASSETS

UPGRADED ASSETS

ASSETS SCHEDULED

FOR REPLACEMENT

* MINOR UPGRADE

*

**

*

*

*



Table 7-5 lists the specific issues that are either new or no longer relevant within the forecast period when compared to last year's report.


Issues Change

Albany supply transformer capacity New issue.

Bream Bay supply transformer capacity New issue.

Dargaville supply transformer capacity New issue.

Henderson–Wellsford 110 kV transmission capacity New issue.

Kaikohe supply transformer capacity Kaitaia transmission security Kaitaia supply transformer capacity

Removed. These assets have been transferred to Top Energy.

Marsden interconnection transformer capacity New issue.

Maungaturoto supply transformer capacity New issue.

Silverdale supply transformer capacity New issue.

7.8 Northland transmission capability

Table 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.



Table 7-6: Northland region transmission issues

Section number

Issue

Regional

7.8.1 Henderson interconnecting transformer capacity

7.8.2 Henderson–Wellsford transmission capacity

7.8.3 Marsden interconnecting transformer capacity

7.8.4 North Auckland and the Northland region transmission capacity

7.8.5 North of Henderson transmission capacity

7.8.6 North of Huapai transmission security

7.8.7 North of Marsden low voltage

7.8.8 Upper North Island voltage instability for grid backbone contingencies

Site by grid exit point

7.8.9 Albany supply transformer capacity

7.8.10 Bream Bay supply transformer capacity

7.8.11 Dargaville transmission security

7.8.12 Dargaville supply transformer capacity

7.8.13 Henderson supply transformer capacity

7.8.14 Kaikohe–Maungatapere 110 kV transmission capacity

7.8.15 Kensington transmission security and supply transformer capacity

7.8.16 Maungatapere supply transformer capacity

7.8.17 Maungaturoto supply transformer capacity

7.8.18 Silverdale supply transformer capacity

7.8.19 Wellsford supply transformer capacity

7.8.1 Henderson interconnecting transformer capacity

Project reference: HEN-POW_TFR_DIS-EHMT-01

Project status/purpose: Base Capex, minor enhancement

Indicative timing: 2023

Indicative cost band: A

Issue

There are two 220/110 kV interconnecting transformers at Henderson, providing:

a total nominal installed capacity of 400 MVA, and

n-1 capacity of 229/229 MVA36

(summer/winter).

Switchgear on the Henderson T1 transformer restricts its n-1 capacity to 229 MVA. Loading on these transformers may exceed their n-1 capacity during peak load from 2014.

In addition, Vector is able to transfer approximately 90 MW of load from Penrose to Mount Roskill. If this occurs during peak load periods, the load on the Henderson interconnecting transformers will exceed their n-1 capacity.

36

The transformers’ capacity is limited by switchgear; with this limit resolved, the n-1 capacity will be 254/270 MVA (summer/winter).



Solution

Commissioning of the NAaN project, scheduled for completion in 2013, will delay the issue to 2023.

If required, we will replace the limiting switchgear on the Henderson interconnecting transformers 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-of-life within the forecast period. The appropriate replacement option will be considered and carried out in conjunction with the Albany interconnecting transformer replacement (see Section 7.5).

7.8.2 Henderson–Wellsford transmission capacity

Project reference: HEN_MPE-TRAN-EHMT-01

Project status/purpose: Possible, to meet the Grid Reliability Standard (not core grid)


Indicative cost band: To be advised

Issue

There are two 110 kV circuits between Henderson and Wellsford, each rated at 55/68 MVA (summer/winter). An outage of one Henderson–Wellsford circuit will cause the other circuit to exceed its n-1 capacity from 2024.

Solution

The most likely solution will be to split the 110 kV network between Henderson and Maungatapere to remove the overload. Another possible option is to thermally upgrade the Henderson–Wellsford circuits. The options to resolve the issue will be investigated closer to the need date.

7.8.3 Marsden interconnecting transformer capacity

Project reference: MDN-POW_TFR-DEV-01

Project status/purpose: Possible, to meet the Grid Reliability Standard (core grid)


Indicative cost band: New interconnecting transformer: B

Issue

There are two 220/110 kV interconnecting transformers at Marsden, providing:


n-1 capacity of 180/188 MVA (summer/winter).

Loading on these transformers may exceed their n-1 capacity during peak load from 2023.

Solution

The Marsden site is developed to install a third 220/110 kV transformer, and convert the 220 kV and 110 kV buses to three zones.

7.8.4 North Auckland and the Northland region transmission capacity

Project context: NAaN

Project reference: ALB_PAK-TRAN-DEV-01

Project status/purpose: Committed, to meet the Grid Reliability Standard (core grid)



Indicative timing: Q4 2013

Indicative cost band: G

Issue

Two 220 kV Henderson–Otahuhu circuits supply the Northland region’s load, with the parallel 110 kV Otahuhu–Roskill–Hepburn–Henderson circuits supplying Mount Roskill from both the north and south under normal grid configuration. The 220 kV circuit capacities are limited by station equipment at Henderson to 915 MVA per circuit. The conductor rating of each circuit is 938/984 MVA (summer/winter).

An outage of a Henderson–Otahuhu circuit may cause the Henderson–Southdown circuit to exceed its branch rating by winter 2017.

A double-circuit outage of the 220 kV Henderson–Otahuhu line will result in a significantly lower capacity for supplying the North Auckland and Northland load, via the 110 kV transmission network.

Solution

We are committed to implementing the NAaN project in 2013 (see Chapter 8 for more information). This will ensure loading on the 220 kV Henderson–Otahuhu circuits remains within the n-1 capacity, and improve reliability of supply to the Northland region.

7.8.5 North of Henderson transmission capacity

Project status/purpose: This issue is for information only

Issue

The 220 kV Henderson–Huapai 1 circuit is rated at 457/457 MVA37

(summer/winter). An outage of the parallel 220 kV Albany–Henderson 3 circuit may cause the 220 kV Henderson–Huapai 1 circuit to exceed its branch rating during peak winter load periods.

The present system allows transfer of the Liverpool Street load through Vector’s network to Mount Roskill, if required. This will increase the loading on the Henderson–Huapai 1 circuit.

Solution

Completion of the NAaN project in 2013 provides a second 220 kV connection into Albany from the south, resolving the capacity issue in the long term.

7.8.6 North of Huapai transmission security

Project reference: HPI-BUSC-DEV-01




Issue

The Huapai switching station comprises three circuit breakers:

one on each of the 220 kV circuits connecting Marsden and Bream Bay, and

37

The capacity of this circuit is limited by substation equipment at Henderson; with this limit resolved, the capacity will be 666/740 MVA (summer/winter).



a shared circuit breaker for the two incoming 220 kV circuits from Albany and Henderson.

If the shared circuit breaker fails to trip following a fault, both the incoming circuits will trip, leaving the entire load north of Huapai supplied by the low capacity 110 kV Henderson–Maungatapere circuits. This will result in significant load shedding.

Solution

Splitting the Huapai bus once the NAaN project is completed (see Chapter 8) will resolve this issue.

7.8.7 North of Marsden low voltage

Project reference: MDN-C_BANKS-DEV-01

Project status/purpose: Possible, to meet the Grid Reliability Standard (not core grid) and/or customer-specific

Indicative timing: To be advised


Issue

Increasing load lowers the voltage in the Northland region. An outage of:

the 220 kV Huapai–Marsden circuit from 2013 will cause low voltages at the Marsden and Bream Bay 220 kV buses and at the Maungatapere, Dargaville, Kaikohe, and Kaitaia supply buses.

one of the 110 kV Marsden–Maungatapere circuits will cause low voltages at Maungatapere, Kaikohe, and Dargaville from 2013.

one of the 110 kV Kaikohe–Maungatapere circuits will cause low voltages at Kaikohe from 2013.

Solution

The low voltage issues due to the loss of a 220 kV circuit will be solved by installing two STATCOMs at Marsden, with commissioning scheduled for 2014 (see Chapter 8, Section 8.8.1). This will resolve the low voltage issue for the forecast period and beyond.

The low voltage issue due to the loss of a 110 kV circuit can be resolved as a transmission investment by installing reactive support at Kaitaia and/or Maungatapere, or as a non-transmission alternative by installing capacitors at Kaikohe. The reactive support is most effective if installed at Kaitaia to avoid low voltages at all other substations. Greater amounts of reactive support are required if the reactive support is solely at Kaikohe or Maungatapere.

Addressing the low voltage issue due to the loss of a 110 kV circuit involves a trade-off between operating at a lower than normal voltage, transmission investment in reactive support, and investment within the distribution network (non-transmission alternatives). Options include

38:

operating at a low voltage (for example, 0.9 p.u. at the Kaitaia 110 kV bus), and following a circuit outage, automatically switching in the existing binary switched capacitors at Kaitaia

operating within the standard voltage range by switching in the Kaitaia capacitors, and accepting a 20% voltage drop should the Kaitaia capacitors trip

38

The figures given in the options list are with the existing 4 x 5 Mvar of capacitors at Kaikohe, within Top Energy’s network. Other figures apply if the capacitors are not available.



at Kaitaia, installing 20 Mvar of binary switched capacitors (a duplicate of the existing binary switched capacitor bank at Kaitaia), so the voltage is always within the standard range, or

at Maungatapere, installing 60 Mvar by 2018 and 80 Mvar by 2022, so the voltage is always within the standard range.

Capacitor-based reactive support at Maungatapere will require many small capacitor banks to limit the voltage step when switching the capacitors. This may result in an unrealistic capacitor bank installation, requiring a STATCOM instead.

Installing capacitors at Kaitaia will result in a leading power factor at the Transpower and Top Energy boundary following asset transfer.

Addressing the low voltage issues due to 110 kV circuit outages will also address the low voltage issues due to 220 kV circuit outages beyond 2018.

7.8.8 Upper North Island voltage instability for grid backbone contingencies

Project status/purpose: See Chapter 6, Sections 6.4.1 and 6.4.2

Issue

As demand in the Auckland and Northland regions grows, voltage stability margins will deteriorate to the point where there are several generators and circuit contingencies on the grid backbone that can cause voltage control problems within the Northland region (see Chapter 6, Sections 6.4.1 and 6.4.2, for more information).

Solution

We have proposed and committed to a number of projects to solve the issues identified. These are detailed under the North Island Grid Backbone Issues and Project Options (see Chapter 6, Sections 6.4.1 and 6.4.2 for more information).

7.8.9 Albany supply transformer capacity

Project reference: ALB-POW_TFR_EHMT-01




Issue

Three 220/33 kV transformers (two rated at 100 MVA and one at 120 MVA) supply Albany’s load, providing:



(summer/winter).

The peak load at Albany is forecast to exceed the transformers’ n-1 winter capacity by approximately 1 MW in 2023, increasing to approximately 16 MW in 2027 (see Table 7-7).

Table 7-7: Albany supply transformer overload forecast

Grid exit point

Power factor

Transformer overload (MW)


2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Albany 0.99 0 0 0 0 0 0 0 0 1 9 16

39

The transformers’ capacity is limited by a protection limit; with this limit resolved, the n-1 capacity will be 244/258 MVA (summer/winter).



Solution

We will convert the Albany 33 kV outdoor switchgear to an indoor switchboard within the next 5-10 years. This will resolve the transformers’ protection and circuit breaker limits until 2027. Future investment will be customer driven.

7.8.10 Bream Bay supply transformer capacity

Project reference: BRB-POW_TFR_PTN-EHMT-01




Issue

Two 220/33 kV transformers supply Bream Bay’s load, providing:



(summer/winter).

The peak load at Bream Bay is forecast to exceed the transformers’ n-1 summer capacity by approximately 1 MW in 2021, increasing to approximately 4 MW in 2027 (see Table 7-7).

Table 7-8: Bream Bay supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Bream Bay 0.95 0 0 0 0 0 0 0 1 2 3 4

Solution

Increasing the transformers’ protection limits will resolve the overload issue beyond the forecast period.

7.8.11 Dargaville transmission security

Project reference: MPE-POW_TFR-REPL-01

Project status/purpose: Base Capex, replacement

Indicative timing: 2012-2014

Indicative cost band: B

Issue

Two 110/50 kV transformers (rated at 10 MVA and 30 MVA) at Maungatapere connected to two 50 kV circuits supply Dargaville’s load. These transformers provide:



The total load on the Maungatapere transformers equals the Dargaville load plus transmission line losses. The peak load at Dargaville already exceeds the transformers’ n-1 summer capacity by 2 MW, and the overload is forecast to increase to approximately 6 MW in 2027.

40

The transformers’ capacity is limited by protection limits; with this limit resolved, the n-1 capacity will be 108/108 MVA (summer/winter).



Solution

Both 110/50 kV transformers at Maungatapere have an expected end-of-life within the next five years. Two 20 or 25 MVA replacement transformers will have sufficient capacity for the forecast period and beyond. We will discuss with Northpower the details of the timing and capacity for the replacement transformers.

7.8.12 Dargaville supply transformer capacity

Project reference: DAR-POW-TFR-EHMT-01

Project status/purpose: Possible, customer-specific


Indicative cost band: Add fans and/or pumps: A

Issue

Two 50/11 kV transformers supply Dargaville’s load, providing:



The peak load at Dargaville is forecast to exceed the transformers’ n-1 summer capacity by approximately 1 MW in 2012, increasing to approximately 5 MW in 2027 (see Table 7-9).

Table 7-9: Dargaville supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Dargaville 0.97 1 2 2 2 2 3 3 4 4 5 5

Solution

We will discuss future supply options with Northpower. Possible options include:

using the transformers’ 15 MVA short term n-1 capacity

using operational measures to manage the peak load within the transformers’ n-1 capacity, and

increasing the transformers’ thermal capacity by adding fans and/or pumps.

Future investment will be customer driven.

7.8.13 Henderson supply transformer capacity

Project reference: HEN-POW_TFR-EHMT-01




Issue

Two 220/33 kV transformers supply Henderson’s load, providing:



(summer/winter).

41

The transformers’ capacity is limited by a bus section, circuit breaker and disconnector; with these limits resolved, the n-1 capacity will be 146/153 MVA (summer/winter).



The peak load at Henderson is forecast to exceed the transformers’ n-1 winter capacity by approximately 2 MW in 2012, increasing to approximately 59 MW in 2027 (see Table 7-10).

Table 7-10: Henderson supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Henderson 0.99 2 6 10 14 18 23 32 40 47 54 59

Solution

We will also convert the Henderson 33 kV outdoor switchgear to an indoor switchboard within 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 Hepburn Road, providing an operational solution when the issue arises. A longer-term option is to install a third supply transformer.

7.8.14 Kaikohe–Maungatapere 110 kV transmission capacity

Project reference: KOE_MPE-TRAN-EHMT-01




Issue

Two 110 kV Kaikohe–Maungatapere circuits supply Kaikohe, with onward transmission to Kaitaia. The two circuits provide:

a total nominal installed capacity of 141/155 MVA (summer/winter), and


The combined peak load of Kaikohe and Kaitaia is forecast to exceed the transmission n-1 capacity from 2014 when Ngawha is not generating.

Solution

The Ngawha generation station is embedded behind the Kaikohe supply bus. With Ngawha generating 10 MW, the issue can be delayed until 2019. If Ngawha is generating nearer its peak of 25 MW, the issue can be delayed to the end of the forecast period.

The issue may also be managed operationally by Top Energy limiting the net peak load to the circuit’s capacity. A possible longer-term option is to thermally upgrade the Kaikohe–Maungatapere circuits.


7.8.15 Kensington transmission security and supply transformer capacity

Project reference: KEN-SUB-EHMT-01






Issue

Two 110 kV circuits supply Kensington’s load, providing:



(summer/winter).

There is no 110 kV bus at Kensington. Each circuit operates in series with a 110/33 kV transformer. A fault on either the transmission circuit or transformer will cause both the circuit and transformer to be out of service.

Two 110/33 kV transformers supply Kensington’s load, providing:



An outage of one Kensington–Maungatapere circuit and a supply transformer will cause:

the other circuit to exceed its winter branch rating from 2012, and

the other supply transformer to exceed its n-1 winter capacity by approximately 12 MW in 2012, increasing to approximately 32 MW in 2027 (see Table 7-11).

Table 7-11: Kensington supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Kensington 0.99 12 13 14 16 17 18 21 24 26 29 32

Solution

Northpower can transfer significant load within its network from Kensington to Maungatapere following a line and a transformer failure and does not consider a project necessary at this time.

In the longer term, developments to resolve this issue include:

an upgrade of the Kensington grid exit point, including supply transformers and the 33 kV switchboard, and

resolving the protection limits on the Kensington–Maungatapere circuits.

In addition, the Kensington supply transformers have an expected end-of-life within the forecast period. Future investment will be customer driven.

7.8.16 Maungatapere supply transformer capacity


Issue

Two 110/33 kV transformers supply Maungatapere’s load, providing:



Maungatapere’s summer demand peaks are approaching its winter peaks. The peak load at Maungatapere is forecast to exceed the transformers’ n-1 summer capacity by approximately 20 MW in 2012, increasing to approximately 39 MW in 2027 (see Table 7-12).

42

The circuits’ capacity is limited by the protection; with this limit resolved, the n-1 capacity will be 152/152 MVA (summer/winter).



Table 7-12: Maungatapere supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Maungatapere 0.96 20 21 23 24 25 26 29 31 34 36 39

Northpower can transfer significant load within its network between Maungatapere and Kensington following a transformer failure. This effectively makes Maungatapere and Kensington a single load when considering supply transformer capacity.

Solution

Load growth at Maungatapere is expected to be limited by Northpower, which advises that it intends to permanently shift load from this grid exit point to Kensington in approximately 2016 to avoid the need to upgrade. The Maungatapere 110/33 kV transformers have an expected end-of-life within the next 5-10 years.

7.8.17 Maungaturoto supply transformer capacity

Project reference: MTO-POW_TFR_PTN-EHMT-01




Issue

Two 110/33 kV transformers supply Maungaturoto’s load, providing:



(summer/winter).

The peak load at Maungaturoto is forecast to exceed the transformers’ n-1 winter capacity by 1 MW in 2019, increasing to approximately 3 MW in 2027 (see Table 7-13).

Table 7-13: Maungaturoto supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Maungaturoto 0.99 0 0 0 0 0 0 1 1 2 3 3

Solution

We will convert the Maungaturoto 33 kV outdoor switchyard to an indoor switchboard within the next 5-10 years. Protection and metering limits will be resolved at the same time. This will solve the supply transformer capacity issue for the forecast period and beyond.

7.8.18 Silverdale supply transformer capacity

Project reference: SVL-POW_TFR_PTN-EHMT-01




43

The transformers’ capacity is limited by protection and metering limits; with these limits resolved, the n-1 capacity will be 31/33 MVA (summer/winter).



Issue

Two 110/33 kV transformers supply Silverdale’s load, providing:



(summer/winter).

The peak load at Silverdale is forecast to exceed the transformers’ n-1 winter capacity by approximately 1 MW in 2023, increasing to approximately 9 MW in 2027 (see Table 7-14).

Table 7-14: Silverdale supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Silverdale 0.99 0 0 0 0 0 0 0 0 1 6 9

Solution

Recalibrating the metering parameters resolves the issue for the forecast period and beyond.

7.8.19 Wellsford supply transformer capacity

Project reference: WEL-POW_TFR-EHMT-01




Issue

Two 110/33 kV transformers supply Wellsford’s load, providing:



(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 2027 (see Table 7-15). Both existing transformers are made up of three single-phase units, with no spare unit on site.

Table 7-15: Wellsford supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Wellsford 0.99 7 8 9 9 10 11 13 15 17 18 20

Solution

In the short term, we are investigating resolving the protection and metering limits to enable use of the transformers’ full capacity. This will increase the n-1 capacity to 37/39 MVA (summer/winter), deferring the issue for two years.

44

The transformers’ capacity is limited by a metering limit, followed by a cable limit (120 MVA); with these limits resolved, the n-1 capacity will be 126/132 MVA (summer/winter).

45 The transformers’ capacity is limited by protection equipment and metering limits; with these limits

resolved, the n-1 capacity will be 37/39 MVA (summer/winter).



Both 110/33 kV transformers at Wellsford have an expected end-of-life within the next five years. We will discuss with Vector the rating and timing for the replacement transformers.


There are no other items of interest identified to date beyond those set out in Section 7.8. See Section 7.10 for more information about specific generation proposals relevant to this region.

7.10 Northland generation proposals and opportunities

This section details relevant regional issues for selected generation proposals under investigation by developers and in the public domain, or other generation opportunities.

The maximum generation that can be connected depends on several factors and usually falls within a range. Generation developers should consult with us at an early stage of their investigations to discuss connection issues. See our website for more information about connecting generation.

46

7.10.1 Maximum regional generation

The following maximum generation estimates assume a light North Island load profile and that existing generation is high (Ngawha generating 25 MW).

For generation connected at the Maungatapere 110 kV bus, the maximum generation that can be injected under n-1 is approximately 270 MW. The constraint is due to one Marsden interconnector when the other interconnector is out of service.

For generation connected at the Huapai 220 kV bus, the maximum generation that can be injected under n-1 is approximately 560 MW. The constraint is due to the Henderson–Huapai 1 circuit overloading when Albany–Huapai 1 is out of service. This may increase to 750 MW if a substation equipment constraint on this circuit is removed.

7.10.2 Generation injection at Kaikohe and Maungatapere

Kaikohe

In addition to Ngawha generation, the combined generation injection at Kaikohe and Kaitaia is limited to approximately 70 MW by the rating of the two 110 kV Kaikohe–Maungatapere circuits. Thermally upgrading the circuits will allow approximately 100 MW of generation, while replacing the conductor will allow approximately 140 MW of generation.

The generation limits above can be increased to approximately 150 MW, 200 MW and 280 MW, respectively, if the additional generation is connected directly to the Kaikohe bus and automatically tripped if a Kaikohe–Maungatapere circuit trips.

Other parts of the transmission network may also limit the maximum level of generation.

Maungatapere

Generation of approximately 300-350 MW can be connected directly or indirectly at Maungatapere. This includes generation at Kaitaia, Kaikohe, and Dargaville and, for some system configurations, generation connected to the 110 kV Henderson–Maungatapere line (see also Section 7.10.3). Higher levels of generation may be

46

http://www.transpower.co.nz/connecting-new-generation.



possible by replacing some equipment at substations, upgrading the Marsden interconnection capacity, and thermally upgrading the Henderson–Maungatapere line.

7.10.3 Generation connected to the 110 kV Henderson–Maungatapere line

There is a 110 kV double-circuit line from Henderson to Wellsford, Maungaturoto, and Maungatapere. Each circuit is rated at 56/68 MVA. Generation up to a total of approximately 200 MW can be connected, provided a system split is put in place with half the generation transmitted towards Maungatapere and half towards Henderson. In addition, if one circuit is out of service, the generation must be automatically reduced to match the capacity of the remaining circuit.

The two circuits can be thermally upgraded to allow approximately 300 MW of generation, or have replacement conductors to allow even greater generation. Generation transmitted towards Maungatapere forms part of the generation injection limit into Maungatapere (see Section 7.10.2 for more information).

7.10.4 Generation connected to the 220 kV Huapai–Marsden line

There is a 220 kV double-circuit line from Huapai (north of Auckland) to Marsden and Bream Bay (in Northland), which is the main connection to the Northland region. One circuit is predominantly a simplex conductor and the other is a duplex conductor, with ratings of 333/370 MVA and 666/740 MVA

47, 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 depending on which circuit the generation connects into, with the simplex Bream Bay–Huapai conductor being the limiting component. New generation elsewhere in the Northland region will reduce this limit.

47

The actual circuit rating is presently limited to 457 MVA due to some substation equipment, which is relatively easy and inexpensive to replace in the context of generation connection. Therefore, the limit is ignored in the context of this discussion.

Chapter 8: Auckland Region


8 Auckland Regional Plan


8.2 Auckland transmission system

8.3 Auckland demand

8.4 Auckland generation

8.5 Auckland significant maintenance work

8.6 Future Auckland projects summary and transmission configuration


8.8 Auckland transmission capability


8.10 Auckland generation proposals and opportunities


This chapter details the Auckland regional transmission plan. We base this regional plan on an assessment of available data, and welcome feedback to improve its value to all stakeholders.

Figure 8-1: Auckland Region



The Auckland region has some of the highest load densities in New Zealand, coupled with relatively low levels of local generation.

We have assessed the Auckland region’s transmission needs over the next 15 years while considering longer-term development opportunities. Specifically, the transmission network needs to be flexible to respond to a range of future service and technology possibilities, taking into consideration:


forecast demand

forecast generation



8.2 Auckland transmission system

This section highlights the state of the Auckland regional transmission network. The existing transmission network is set out geographically in Figure 8-1 and schematically in Figure 8-2.

Figure 8-2: Auckland transmission schematic

110 kV

22 kV

220 kV

220 kV

33 kV

110 kV33 kV

VECTOR CBD

110 kV33 kV

VECTOR CBD

220 kV

220 kV

Henderson

NORTHLAND

110 kV

220 kV

110kV CIRCUIT

SUBSTATION BUS

TRANSFORMER

TEE POINT

KEY

220kV CIRCUIT

LOAD

CAPACITOR

33 kV

110 kV

Hamilton

WAIKATO

Huntly

WAIKATO

Whakamaru

Hepburn Road

110 kV

33 kV

BONDED CIRCUIT

220 kV

220 kV

33 kV

33 kV

22 kV

Mount Roskill

Southdown

Penrose

Pakuranga

Otahuhu

Wiri

Bombay

Glenbrook

Takanini

Mangere

Ohinewai

SYNCHRONOUS CONDENSER

22 kV

SC

SC

SC

GENERATOR

UNDERGROUND CABLE

Arapuni

220 kV

Drury

Otahuhu

Combined

Cycle

110 kV



8.2.1 Transmission into/through the region

As approximately 70% of the Auckland and Northland regions’ peak electricity demand is supplied by generation located south of Bombay, transmission is necessary to keep the energy flowing into Auckland and through to North Auckland and the Northland region.

There are three major projects and a series of small projects that we are progressing to ensure that the Auckland region has secure transmission as demand continues to grow.

Broader project descriptions that provide a context for the issues identified in later sections include the:

North Island Grid Upgrade (NIGU) project

North Auckland and Northland (NAaN) grid upgrade project, and

Upper North Island Reactive Support (UNIRS) project.

North Island Grid Upgrade (NIGU) project

This committed project includes building a new transmission link into the Pakuranga substation from the south, operating the existing Otahuhu–Pakuranga line at its design voltage of 220 kV (previously operating at 110 kV), and providing additional reactive support for the area to maintain voltages in the Auckland and Northland regions (see Chapter 6, Sections 6.3.2 and 6.4.2).

This project:

provides additional transmission capacity into the Auckland region (see Section 6.4.2)

provides diversity for transmission from the south into the Auckland region (all existing 220 kV transmission circuits terminate into Otahuhu), and

converts Pakuranga from 110 kV to 220 kV, which reduces the load on the 110 kV system supplying the eastern side of the Auckland region, including Penrose.

North Auckland and Northland (NAaN) grid upgrade project

This committed project adds new transmission capacity between the Pakuranga, Penrose, and Albany substations. It also enables the building of new grid exit points at Hobson Street (Auckland CBD) and Wairau Road (North Shore). The NAaN project reinforces transmission in the Auckland region and across into the Northland region. The 220 kV circuit from Pakuranga to Penrose will:

increase capacity to the Penrose 220 kV bus by adding a third 220 kV circuit alongside the existing 220 kV Otahuhu–Penrose double-circuit line, and

build on the NIGU project by increasing the diversity for transmission from the south into the Auckland region, as there will be 220 kV transmission from Pakuranga to Otahuhu and Penrose.

The 220 kV circuit from Penrose to Albany will:

increase capacity to the Northland region (including the North Isthmus) by adding a third 220 kV circuit from Otahuhu to Henderson

build on the NIGU project by increasing the diversity for transmission from the south into the Northland region (including the North Isthmus), as there will be 220 kV transmission from Pakuranga, through Penrose, to Albany

provide capacity and security to Vector’s Hobson Street and Wairau Road substations through a 220 kV connection to the Albany–Penrose circuit, and

enable Vector to redistribute load from existing grid exit points, particularly the Albany 33 kV and 110 kV (Wairau Road) loads and Auckland CBD loads.



Upper North Island Reactive Support (UNIRS) project

The purpose of this project is to relieve voltage stability issues associated with an outage of major generators and/or circuits supplying the Upper North Island area (see Chapter 6). It includes installing dynamic reactive support at Penrose and Marsden.

8.2.2 Transmission and distribution network within the region

The Auckland transmission network consists of three layers: the 220 kV network, the 110 kV network, and the 110 kV distribution system belonging to the local lines company, Vector.

220 kV transmission network

The 220 kV network supplies Otahuhu from the south, via a double-circuit line from Huntly, a double-circuit line from Whakamaru via Ohinewai, and two single-circuit lines from Whakamaru.

At Otahuhu the 220 kV network splits into two with one network supplying Penrose via a double-circuit line, and the other network supplying the Northland region (including the North Isthmus) via a second double-circuit line to Henderson.

The commissioning of a new 220 kV substation at Otahuhu (physically separated from the existing switchyard) provides physical diversity, making the power supply more resilient for rare but high-impact disturbances.

110 kV transmission network

The 110 kV transmission network is split into two parts.

One half of the 110 kV network is a backup supply to Penrose, in parallel with the 220 kV Otahuhu–Penrose double circuit line, with 220/110 kV interconnectors at Otahuhu and Penrose. The 110 kV system also connects to the Waikato region by a Bombay–Wiri–Otahuhu double-circuit line, with power flow generally south out of Otahuhu.

The other half of the 110 kV network supplies Mangere and Mount Roskill in a double-circuit ring, extending from Mount Roskill through a double-circuit 110 kV connection 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 double-circuit line. Power flow is generally into Mount Roskill on all circuits, from both Otahuhu and the Northland region.

110 kV distribution system

Vector’s 110 kV distribution system connects from Penrose to Mount Roskill via Vector’s Liverpool Street substation, and is normally split between Mount Roskill and Liverpool Street. However, it is often used to transfer the Liverpool Street load (up to 90 MW) between the Penrose and Mount Roskill substations.

8.2.3 Reactive power

To improve the network voltage and voltage stability, static capacitors are installed at the Otahuhu, Penrose, and Bombay substations. Condensers at Otahuhu provide dynamic reactive power under contract.


We have identified a longer-term development path to address issues involving transmission into, within and through the Auckland region, the details of which will be revisited when the need arises. The timing of the transmission investments depends on the net load of the Auckland and Northland regions. New generation in the region



or demand-side response may defer transmission investment. Similarly, regional generation retirement or increased demand will bring forward the need for transmission investment.

Possible future upgrades include, but are not limited to the following:

Installation of series compensation on the 220 kV Pakuranga–Whakamaru circuits to improve load sharing with the other 220 kV circuits. Ultimately, the Brownhill–Whakamaru section of the Pakuranga–Whakamaru circuits will be upgraded to operate at 400 kV, by installing 400/220 kV transformers at Brownhill and Whakamaru.

Increasing the transfer capacity into Auckland by building a switching station at Brownhill and cable circuits from Brownhill to Otahuhu.

Possibly increasing the capacity of the 110 kV circuits between Arapuni and Otahuhu via thermal upgrades or re-conductoring with higher-capacity conductors.

Transmission reinforcement within the Auckland region via additional cables between Pakuranga, Penrose, and Mount Roskill.

Transmission reinforcement into the Northland region via a second cable between Penrose and Albany.

Additional static and dynamic reactive power support approximately every 2 to 3 years to ensure power system voltage stability, and sufficient reserves are maintained to cover the worst transmission contingency. The series compensation on the 220 kV Pakuranga–Whakamaru circuits may be brought forward because of its positive contribution to voltage stability and reduction in transmission 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 the existing lines.

The development of the Auckland spatial plan (particularly in the South Auckland area) will have a large influence on future options for increasing transmission capacity into Auckland.

Figure 8-3 provides an indication of the possible transmission development within and through Auckland in the longer term (beyond 2027).



Figure 8-3: Indicative Auckland and Northland region schematic beyond 2027

110 kV

220 kV

220 kV

110 kV

220 kV

Henderson

NORTHLAND

220 kV

110 kV

WAIKATO

Whakamaru

Hepburn Road

110 kV

NORTHLANDAlbany / Wairau Road

Mount

Hobson

Street220 kV

Penrose

SouthdownPakuranga

Otahuhu

Wiri

Bombay

Hamilton

Brownhill220 kV

220 kV

Otahuhu

Combined

Cycle

110 kVMangere

Ohinewai Arapuni

NEW ASSETS

UPGRADED ASSETS

KEY

110 kV

400 kV

110 kV

Roskill

WhakamaruTakanini

Huntly

VECTOR CBD NETWORK

MVAR

MVAR

MV

AR

220 kV

110 kV

8.3 Auckland demand

The after diversity maximum demand (ADMD) for the Auckland region is forecast to grow on average by 2.1% annually over the next 15 years, from 1,530 MW in 2012 to 2,078 MW by 2027. This is higher than the national average demand growth of 1.7% annually.


48) for the Auckland region. The forecasts are derived using


48




Figure 8-4: Auckland region after diversity maximum demand forecast


Table 8-1: Forecast annual peak demand (MW) at Auckland grid exit points to 2027


Peak demand (MW)


2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Bombay 33 kV1 0.98 25 26 26 27 14 14 14 0 0 0 0

Bombay 110 kV1 1.00 51 52 53 54 69 70 73 90 93 96 98

Glenbrook 33 kV 1.00 32 33 33 34 35 35 37 38 39 40 41

Glenbrook NZ Steel

0.99 116 116 120 120 120 120 120 120 120 120 120

Hobson Street2, 3

0.97 0 0 126 130 134 137 144 150 155 161 164

Mangere 33 kV 0.94 115 119 122 126 129 133 141 149 155 161 166

Mangere 110 kV 0.87 55 55 55 55 55 55 55 55 55 55 55

Meremere4 0.95 14 14 15 15 0 0 0 0 0 0 0

Mt Roskill 22 kV 0.98 130 134 138 142 146 151 160 168 175 182 187

Mt Roskill 110 kV – Kingsland

0.97 66 68 70 72 74 76 80 83 86 89 91

Otahuhu 0.99 66 69 71 73 75 77 82 86 91 95 100

Pakuranga 0.98 163 167 171 174 178 182 189 196 203 210 218

Penrose 22 kV 0.96 50 52 53 55 56 58 62 65 67 70 72

Penrose 33 kV 0.98 300 309 318 328 338 348 369 388 403 420 432

Penrose 110 kV - Liverpool Street

3

0.97 238 246 126 130 134 137 144 150 155 161 164

Penrose 110 kV - Quay Street

5

NA 0 0 0 0 0 0 0 0 0 0 0

Takanini6 0.99 125 129 133 137 141 145 154 162 168 175 180

Wiri 0.99 82 85 87 90 92 95 101 106 110 115 118

600

800

1000

1200

1400

1600

1800

2000

2200

1997 1999 2001 2003 2005 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027

Load (MW)

Auckland

2011 APR Forecast

2012 APR Forecast

Actual Peak




Peak demand (MW)


2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

1. The customer advised that approximately half of the load will shift from Bombay 33 kV to Bombay 110 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 2013/2014. Some of the Penrose–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 being considered.

4. The customer advised that the load at Meremere will be shifted to Huntly (in the Waikato region) in 2016.

5. The Penrose 110 kV–Quay Street load has been transferred to Penrose–Liverpool Street and the Penrose–Quay Street circuits decommissioned.

6. The customer advised that their forecast is lower than Transpower’s forecast.

8.4 Auckland generation

The Auckland region’s generation capacity is approximately 681 MW.

Table 8-2 lists the generation forecast for each grid injection point for the forecast period, as required for the Grid Reliability Report. This includes all known and committed generation stations including those embedded within the relevant local lines company’s network (Vector or Counties Power).

49

No new generation is known to be committed in the Auckland region for the forecast period.

Table 8-2: Forecast annual generation capacity (MW) at Auckland grid injection points to 2027 (including existing and committed generation)




2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Glenbrook1 112 112 112 112 112 112 112 112 112 112 112

Mangere (Watercare Mangere)

7 7 7 7 7 7 7 7 7 7 7

Otahuhu B CCGT

380 380 380 380 380 380 380 380 380 380 380

Otahuhu (Greenmount Landfill)

5 5 5 5 5 5 5 5 5 5 5

Penrose (Auckland Hospital)

4 4 4 4 4 4 4 4 4 4 4

Southdown CCGT 170 170 170 170 170 170 170 170 170 170 170

Takanini (Whitford Landfill)

3 3 3 3 3 3 3 3 3 3 3

1. This is a 38 MW embedded generating unit with a continuous output rating of approximately 25 MW.

8.5 Auckland significant maintenance work


50 proposed for the Auckland region for the next


49

Only generators with capacity greater than 1 MW are listed. Generation capacity is rounded to the nearest megawatt.

50 This may include replacement of the asset due to its condition assessment.






Bombay supply transformers expected end-of-life, and 33 kV outdoor to indoor conversion

2018-2020 2016-2018

Bombay supply transformer capacities are sufficient for the forecast period. The customer may relinquish 33 kV supply from Bombay within 10-20 years.

Mangere 33 kV outdoor to indoor conversion

2014-2016 The forecast load will exceed the transformer n-1 capacity from 2012. The n-1 capacity is limited by protection limit. If appropriate, the work to resolve this limit will be coordinated with the 33 kV outdoor to indoor conversion work. See Section 8.8.5 for more information.

Mount Roskill supply transformer T3 expected end-of-life, and 22 kV outdoor to indoor conversion

2015-2019 The Mount Roskill load is forecast to exceed the transformer n-1 capacity from 2012. The n-1 capacity is limited by a few branch components initially, and then the transformers need a capacity upgrade by 2020 to meet n-1 capacity. See Section 8.8.6 for more information.

Otahuhu interconnecting transformer expected end-of-life

2019-2021 The options to replace the transformers must be coordinated with the:

Penrose T10 interconnecting transformer replacement – see Section 8.8.3 for more information

Otahuhu–Wiri transmission capacity issue – see Section 8.8.8 for more information, and

Otahuhu–Penrose 110 kV transmission capacity issue – see Section 8.8.10

Otahuhu supply transformers expected end-of-life

2021-2023 The Otahuhu load already exceeds the transformers’ n-1 capacity. See Section 8.8.7 for more information.

Penrose T10 interconnecting transformer expected end-of-life

2017-2019 This work will be coordinated with the Otahuhu interconnecting transformer replacement. See Section 8.8.3 for more information.

Penrose supply transformers expected end-of-life, and 33 kV outdoor to indoor conversion

2026-2028 2012-2014

A spare transformer enables us to manage the existing three supply transformers for the next 15 years. See 8.8.11 for more information

Takanini 33 kV outdoor to indoor conversion

2014-2016 Takanini supply transformer n-1 capacity is limited by a few transformer branch component limits. If appropriate, the work to resolve these limits will be coordinated with the 33 kV outdoor to indoor conversion work. See Section 8.8.12 for more information.

Wiri supply transformer expected end-of-life and 33 kV outdoor to indoor conversion

2014-2017 The Wiri load is forecast to exceed the transformer n-1 capacity by 2019. See Section 0 for more information.

8.6 Future Auckland projects summary and transmission configuration

Table 8-4 lists projects to be carried out in the Auckland region within the next 15 years.

Figure 8-5 shows the possible configuration of Auckland transmission in 2027, with new assets, upgraded assets, and assets undergoing significant maintenance within the forecast period.

Table 8-4: Projects in the Auckland region up to 2027


Albany–Penrose 220 kV cables between Albany and Penrose. Committed

Brownhill –Whakamaru

400 kV capable double-circuit transmission line. Committed

Brownhill–Pakuranga

220 kV cables between Brownhill and Pakuranga. Committed

Bombay Replace 110/33 kV supply transformers. Base Capex




Convert 33 kV outdoor switchgear to an indoor switchboard. Base Capex

Hobson Street New substation at Hobson Street. Committed

Mangere Resolve supply transformer protection limits. Convert 33 kV outdoor switchgear to an indoor switchboard.


Mount Roskill Upgrade supply transformer branch limiting components. Replace Mount Roskill T3 supply transformer. Convert 22 kV outdoor switchgear to an indoor switchboard.

Possible Base Capex Base Capex

Otahuhu Replace Otahuhu T2/T4 interconnecting transformers. Replace 220/22 kV supply transformers. Install a new 220/22 kV supply transformer.

Base Capex Base Capex Possible

Otahuhu–Wiri Increase transmission capacity to Wiri. Possible

Otahuhu–Penrose

Increase the circuit’s capacity. Possible

Pakuranga–Penrose

Install 220 kV cable between Pakuranga and Penrose. Committed

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.

Committed Base Capex Base Capex Base Capex

Takanini Upgrade supply transformer branch limiting components. Convert 33 kV outdoor switchgear to an indoor switchboard.

Possible Base Capex

Wiri Resolve supply transformer’s protection limits. New or upgrade the existing supply transformers’ capacity. Convert 33 kV outdoor switchgear to an indoor switchboard.

Base Capex Possible Base Capex



Figure 8-5: Possible Auckland transmission configuration in 2027

110 kV22 kV

220 kV

220 kV

33 kV

110 kV33 kV

VECTOR CBD

VECTOR CBD

220 kV

Henderson

NORTHLAND

220 kV

33 kV

110 kV

WAIKATO

Whakamaru

Hepburn Road

110 kV

220 kV33 kV

NORTHLANDAlbany / Wairau Road

Mount Roskill

Hobson

Street220 kV

Penrose

SouthdownPakuranga

Otahuhu

Wiri

Bombay

Hamilton

Brownhill220 kV

WhakamaruHuntly

WAIKATO

Glenbrook

Takanini

220 kV33 kV

220 kV

Otahuhu

Combined

Cycle

110 kV33 kV

Mangere

220 kV

Drury

Ohinewai Arapuni

110

kV22 k

V

33 kV

VECTOR CBD

110 kV

STC

22 kV

110 kV

KEY

NEW ASSETS

UPGRADED ASSETS

ASSETS SCHEDULED

FOR MAINTENANCE

* MINOR UPGRADE

*

*

*




Issues Change

Pakuranga supply transformer capacity Removed. Project to install a third transformer completed.

Otahuhu–Penrose 110 kV transmission capacity New issue.

Bombay transmission security Removed. Project to install a 110 kV bus coupler completed.

8.8 Auckland transmission capability

Table 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.



Table 8-6: Auckland region transmission issues

Section number

Issue

Regional

8.8.1 Auckland region voltage quality

8.8.2 North Auckland and Northland regional transmission security

8.8.3 Otahuhu interconnecting transformer capacity


8.8.4 Hobson Street supply security

8.8.5 Mangere supply transformer capacity

8.8.6 Mount Roskill supply transformer capacity

8.8.7 Otahuhu supply transformer capacity

8.8.8 Otahuhu–Wiri 110 kV transmission capacity

8.8.9 Penrose 220 kV transmission security

8.8.10 Otahuhu–Penrose 110 kV transmission

8.8.11 Penrose 33 kV supply transformer capacity

8.8.12 Takanini supply transformer capacity

8.8.13 Wiri supply transformer capacity

8.8.14 Wiri Tee transmission capacity

8.8.1 Auckland region voltage quality

Project context: UNIRS – Chapter 6, See Section 6.4.1 (UNIRS)

Issue

As demand in the Auckland and Northland regions grows, regional voltages may deteriorate to a point where the outage of a 220 kV circuit may cause voltage collapse.

Generation located in the Auckland and Northland regions is insufficient to meet reactive demand. Reactive power from non-generation sources such as shunt capacitors, series capacitors, static synchronous compensators (STATCOM), static var compensators (SVC) and condensers is required to ensure the maintenance of acceptable voltage levels and quality.

Solution

We have a number of projects underway to improve Auckland voltage, including a STATCOM at Penrose and a STATCOM at Marsden. Despite these projects, Auckland voltage stability is an ongoing issue requiring continual study as the Auckland and Northland regional loads grow.

8.8.2 North Auckland and Northland regional transmission security


Project reference: ALB_PAK-TRAN-DEV-01

Project status/purpose: Committed, to meet Grid Reliability Standard (core grid)


Indicative cost band: G

Issue

There are three issues with respect to Auckland transmission security.



North Auckland and Northland supply can be maintained with n-1 security until winter 2016. From that date, further transmission reinforcement or a transmission alternative will be required.

North Auckland and Northland load is supplied by a single 220 kV double-circuit overhead 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 and 2013, respectively.

Solution

We have committed to install a 220 kV underground cable link between the Pakuranga, Penrose and Albany substations, which:

provides security of supply for the North Auckland and Northland beyond 2016

improves transmission diversity into the North Auckland and Northland, and

connects to new grid exit points at Hobson Street and Wairau Road.

The link will provide a capacity of approximately 790 MVA (winter). As the cable link will have significantly lower impedance than the parallel 220 kV overhead transmission circuits between Otahuhu, Henderson, and Albany, more power will flow through the cable than in the parallel circuits. A series reactor in the cable circuit is included to balance the power flow between the parallel routes.

8.8.3 Otahuhu interconnecting transformer capacity


Issue

The Otahuhu 110 kV bus is normally operated split with two separate buses to give better 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 the 110 kV bus section with circuits to Bombay, Penrose and Wiri 110 kV substations, providing:



One pair (T3 and T5, rated at 250 MVA each) supplies the 110 kV bus section with circuits to the Mangere and Mount Roskill 110 kV substations, providing:



Otahuhu T2 and T4 are effectively in parallel with the Penrose T6 and T10 interconnecting transformers through the Otahuhu–Penrose transmission system.

Toward the end of the forecast period, the T2 transformer may exceed its post-contingency capacity at peak load times for an outage of the T4 transformer.

Solution

The recent conversion of Pakuranga from 110 kV to 220 kV reduced the load on Otahuhu T2 and T4, and Penrose T6 and T10 transformers. These transformers now have sufficient capacity until the Auckland CBD load reaches approximately 300 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 the interconnecting transformers at Otahuhu and Penrose.



Additionally, the Otahuhu T2, T4 and Penrose T10 interconnecting transformers have an expected end-of-life within the forecast period. We will investigate the number and ratings for the replacement interconnecting transformers.

8.8.4 Hobson Street supply security


Project reference: HOB-SUBEST-DEV-01

Project status/purpose: Committed, customer-specific


Indicative cost band: D (including an initial 250 MVA 220/110 kV transformer)

Issue

Vector has indicated that to ensure security of supply, it requires reinforcement of its Hobson Street substation by 2014.

Solution

A new 220/110 kV grid exit point will be built at Hobson Street connecting to the new Albany–Penrose cable (see Section 8.8.2). This will also allow Vector to transfer some load from the Penrose 110 kV grid exit point.

8.8.5 Mangere supply transformer capacity

Project reference: MNG-POW_TFR_PTN-01




Issue

Two 110/33 kV transformers supply Mangere’s load, providing:



(summer/winter).

The peak load at Mangere is forecast to exceed the transformers’ n-1 winter capacity by 5 MW in 2012, increasing to approximately 56 MW in 2027 (see Table 8-7).

Table 8-7: Mangere supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Mangere 0.94 5 9 12 16 20 24 32 39 45 51 56

Solution

We will discuss options with Vector. Possible solutions include:

resolving the protection limit of the transformers which will solve the overload issue until 2018, or

limiting the peak load to the transformer capacity, with future load growth transferred to other grid exit points.

Future development options to increase transformer capacity for this grid exit point will be customer driven.

51

The transformers’ capacity is limited by a protection equipment limit; with this limit resolved, the n-1 capacity will be 138/144 MVA (summer/winter).



In addition, we also plan to convert the Mangere 33 kV outdoor switchgear to an indoor switchboard within the next five years.

8.8.6 Mount Roskill supply transformer capacity

Project reference: ROS-POW_TFR-EHMT-01




Issue

Three 110/22 kV transformers (one rated at 50 MVA and two at 70 MVA each) supply Mount Roskill’s load, providing:



(summer/winter).

The peak load at Mount Roskill is forecast to exceed the transformers’ n-1 winter capacity by 1 MW in 2012, increasing to 58 MW in 2027 (see Table 8-8).

Table 8-8: Mount Roskill supply transformer overload forecast

Grid exit point

Power factor


Next 5 years 5-15 Years out

2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Mount Roskill 0.98 1 5 9 13 17 21 31 39 46 53 58

Solution

We will investigate removing the transformers’ circuit breaker and protection relay constraints. This will increase the n-1 capacity to 145/152 MVA (summer/winter), which is sufficient to delay the issue for several years.

The Mount Roskill T3 supply transformer has an expected end-of-life within the forecast period. In addition, we also plan to convert the 22 kV outdoor switchyard to an 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 point will be customer driven.

8.8.7 Otahuhu supply transformer capacity

Project reference: OTA-POW_TFR-EHMT-01

Project status/purpose: New transformer: possible, customer-specific



Issue

Two 220/22 kV transformers supply Otahuhu’s load, providing:



(summer/winter).

52

The transformer’s capacity is limited by a circuit breaker limit on the 50 MVA transformer and relay limits on the 70 MVA transformers; with auxiliary equipment limits resolved, the n-1 capacity will be 145/152 MVA (summer/winter).

53 The 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).



The peak load at Otahuhu is forecast to exceed the n-1 winter capacity by 9 MW in 2012, increasing to approximately 42 MW in 2027 (see Table 8-9).

Table 8-9: Otahuhu supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Otahuhu 0.99 9 11 13 16 18 20 24 29 33 38 42

Solution

Upgrading the LV cable and removing the bushing constraints on the supply transformers 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 growth transferred to other grid exit points

adding a third supply transformer, and

replacing the two existing supply transformers with higher-rated units.

Both supply transformers have an expected end-of-life within the forecast period. We will discuss the ratings and timing for the replacement transformers with Vector. Further development options to increase transformer capacity for this grid exit point will be customer driven.

8.8.8 Otahuhu–Wiri 110 kV transmission capacity

Project reference: OTA_WIR-TRAN-DEV-01

Project status/purpose: Possible, to meet the Grid Reliability Standard (core grid) and/or customer-specific


Indicative cost band: D

Issue

Two 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), and

Otahuhu–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 the remaining circuit during summer peak load periods from approximately 2012. This will occur during periods of high Auckland generation and low Waikato generation.

Solution

We are investigating several options. In the short-term, Vector can limit Wiri load with future load growth transferred to other grid exit points. Possible longer-term options are:

a new 110 kV cable from Otahuhu connecting to a new 110/33 kV supply transformer at Wiri

a new 110/33kV transformer at Otahuhu and a new 33 kV cable connected into Wiri

reconductoring the 110 kV Otahuhu–Wiri circuits with higher capacity conductor, or

a new 220/110 kV connection at Bombay substation on the Huntly–Otahuhu circuit (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).

8.8.9 Penrose 220 kV transmission security

Project context: NIGU and UNIRS See Section 6.4.2 (NIGU project) and Section 8.8.2 (NAaN)

Issue

The two 220 kV Otahuhu–Penrose circuits are rated at 469/492 MVA (summer/winter). During peak demand periods, an outage of one Otahuhu–Penrose circuit may cause the other circuit to exceed the conductor rating from 2013.

Solution

In the short term, the loading on the 220 kV Otahuhu–Penrose circuits may be reduced following an outage by taking the low impedance Penrose 220/110 kV transformer (T10) out of service.

54 This transfers some of the load to the 110 kV

Otahuhu–Penrose 2 circuit. This solution is sufficient until 2014.

We are committed to installing a 220 kV Pakuranga–Penrose cable circuit as part of the NAaN project, scheduled for completion in 2013 (see Section 8.8.2). This will address the issue until approximately 2027 or beyond, when a second 220 kV Pakuranga–Penrose circuit will be required.

8.8.10 Otahuhu–Penrose 110 kV transmission capacity

Project reference: OTA_PEN-TRAN-DEV-01

Project status/purpose: Possible, to meet Grid Relilability Standard (not core grid)



Issue

The 110 kV Otahuhu–Penrose circuit is rated at 177/195 MVA (summer/winter). After commissioning of the NIGU project, an outage of the Penrose 220/110 kV transformer (T10) will cause the 110 kV Otahuhu–Penrose circuit to overload from 2020.

Solution

The Otahuhu–Penrose 110 kV circuit is limited by the terminal spans at Otahuhu and Penrose 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 higher impedance transformers

thermally upgrading the circuit to a higher temperature, or

replacing the circuit with a higher capacity conductor.

8.8.11 Penrose 33 kV supply transformer capacity


54

The two existing Penrose 220/110 kV interconnecting transformers are 200 MVA 5% impedance and 250 MVA 15% impedance units. By switching the 5% impedance transformer out of service, the higher impedance unit will balance the power flow between the remaining 220 kV and the existing 110 kV circuits.



Issue

Three 220/33 kV transformers (two rated at 200 MVA and one at 160 MVA) supply Penrose’s load, providing:



The peak load at Penrose is forecast to exceed the transformers’ n-1 winter capacity by approximately 28 MW in 2012, increasing to approximately 183 MW in 2027 (see Table 8-10).

Table 8-10: Penrose supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Penrose 0.98 28 39 50 61 72 84 109 131 149 168 183

Solution

We 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, with future load growth transferred to other grid exit points.

We have installed a fourth 220/33 kV supply transformer. This is a system spare transformer to enable us to manage outages on the existing three supply transformers for the next 15 years (in particular, allowing the existing T9 transformer to undergo extensive preventative maintenance). The firm capacity will not increase, because only three of the four transformers can be in service to maintain fault levels within the equipment ratings.

Additionally, we also plan to convert the Penrose 33 kV outdoor switchyard to an indoor switchboard within the forecast period.

8.8.12 Takanini supply transformer capacity

Project reference: Upgrade protection: TAK-POW_TFR-EHMT-01

Upgrade circuit breaker and busbar: TAK-SUBEST-EHMT-01

Project status/purpose: Upgrade protection: Base Capex, minor enhancement Upgrade circuit breaker and busbar: possible, customer-specific


Indicative cost band: Upgrade protection: A Upgrade circuit breaker and busbar: A

Issue

Two 220/33 kV transformers supply Takanini’s load, providing:


n-1 capacity limit of 126/126 MVA55

(summer/winter).

The peak load at Takanini is forecast to exceed the transformers’ n-1 winter capacity by 6 MW in 2012, increasing to approximately 61 MW in 2027 (see Table 8-11).

55

The 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 be 188/198 MVA (summer/winter).



Table 8-11: Takanini supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Takanini 0.99 6 10 14 18 22 26 35 43 49 56 61

Solution

If the protection equipment, circuit breaker, and busbar limits are resolved, the transformers’ thermal capacity will be sufficient until the second half of the forecast period.

In addition, the Takanini 33 kV outdoor switchyard will be converted into an indoor switchboard within the next five years. If appropriate, we will upgrade the transformer branch limiting components in conjunction with the conversion work.

Vector has advised that they expect to keep peak load within the transformers’ n-1 capacity for several years. Further development options to increase the transformer capacity for this grid exit point will be customer driven.

8.8.13 Wiri supply transformer capacity

Project reference: Upgrade protection: WIR-POW_TFR_PTN-EHMT-01 Upgrade transformer capacity: WIR-POW_TFR-EHMT-01

Project status/purpose: Upgrade protection: Base Capex, minor enhancement Upgrade transformer capacity: possible, customer-specific

Indicative timing: Upgrade protection: 2019 Upgrade transformer capacity: 2021

Indicative cost band: Upgrade protection: A Upgrade transformer capacity: B

Issue

Two 110/33 kV transformers supply Wiri’s load, providing:


n-1 capacity limit of 106/106 MVA56

(summer/winter).

The peak load at Wiri will exceed the transformers’ summer n-1 capacity by approximately 2 MW in 2019, increasing to approximately 20 MW in 2027 (see Table 8-12).

Table 8-12: Wiri supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Wiri 0.99 0 0 0 0 0 0 2 7 12 16 20

Solution

Resolving the protection equipment limits will delay the overload until 2020. We will discuss future supply options with Vector, including:

limiting peak load to the firm transformer capacity (i.e. 106/106 MVA), with future load growth transferred to other grid exit points, and/or

replacing the existing transformers with two 120 MVA units, or

installing a third supply transformer.

56

The transformers’ capacity is limited by protection equipment limit; with this limit resolved, the n-1 capacity will be 109/115 MVA (summer/winter).



The solution to the Otahuhu–Wiri transmission capacity issue may also address the Wiri supply transformer capacity issue (see Section 8.8.8).

The Wiri single phase supply transformers have an expected end-of-life within the next five years. In addition, we also plan to conver the Wiri 33 kV outdoor switchyard to an indoor switchboard within the next five years.

We will discuss with Vector the number, rating, and timing of the transformer replacement in conjunction with the transformer upgrade and 33 kV outdoor to indoor switchyard conversion work.

Any future transformer upgrade will be customer driven.

8.8.14 Wiri Tee transmission capacity


Issue

Wiri is connected to the Bombay–Wiri–Otahuhu circuits through the Wiri Tee circuit sections, each rated at 92/101 MVA (summer/winter).

The peak load at Wiri already exceeds the circuits’ n-1 summer capacity.

Solution

This issue arises along with the Otahuhu–Wiri circuit issue (see Section 8.8.8). It is expected to be resolved with that issue. Although the Wiri Tee section is only approximately 90 m in length, it crosses over a motorway, which is expected to complicate an otherwise a relatively minor project to increase this circuit section’s capacity.



8.10 Auckland generation proposals and opportunities


The maximum generation that can be connected at any substation depends on several factors and usually falls within a range. Generation developers should consult with us at an early stage of their investigations to discuss connection issues. See our website for more information about connecting generation.

57


The Auckland region has some of the highest load densities in New Zealand, coupled with relatively low levels of local generation, and so there is no practical limit to the maximum generation that can be connected within the region. However, there will be limits on the maximum generation that can be connected at a substation or along an existing line due to the rating of the existing circuits.

57




8.10.2 Auckland generation issues

There are numerous inter-related issues with supplying the load within the Auckland region, as discussed earlier in this chapter. In addition, the increase in fault level due to generators will be an issue for some parts of the transmission and/or distribution systems.

Therefore, depending on its connection point, new generation within the Auckland region may assist in addressing an issue, make it worse, have no effect, or may require specific additional transmission investment to enable connection. Fault-level issues may also preclude new generation connection in some locations.

Chapter 9: Waikato Region


9 Waikato Regional Plan


9.2 Waikato transmission system

9.3 Waikato demand

9.4 Waikato generation

9.5 Waikato significant maintenance work

9.6 Future Waikato projects summary and transmission configuration


9.8 Waikato transmission capability


9.10 Waikato generation proposals and opportunities


This chapter details the Waikato regional transmission plan. We base this regional plan on an assessment of available data, and welcome feedback to improve its value to all stakeholders.

Figure 9-1: Waikato region



The Waikato region comprises two distinct transmission networks, 110 kV and 220 kV, of which the 220 kV network forms part of the grid backbone. The 220 kV circuits enter the region from Stratford, Tokaanu, and Wairakei. The 110 kV circuits enter the region from Kinleith to Arapuni, and from Ongarue to Hangatiki. The northern boundary is crossed by the:

220 kV circuits from Huntly, Ohinewai, and Whakamaru, and

110 kV circuits from Hamilton and Arapuni.

We have assessed the Waikato region’s transmission needs over the next 15 years while considering longer-term development opportunities. Specifically, the transmission network needs to be flexible to respond to a range of future service and technology possibilities, taking into consideration:


forecast demand

forecast generation



9.2 Waikato transmission system

This section highlights the state of the Waikato regional transmission network. The existing transmission network is set out geographically in Figure 9-1 and schematically in Figure 9-2.

Figure 9-2: Waikato transmission schematic

110kV CIRCUIT

SUBSTATION BUS

TRANSFORMER

TEE POINT

KEY

220kV CIRCUIT

LOAD

CAPACITOR

110 kV

AUCKLAND

220 kV

220 kV

Atiamuri

220 kV

Taumarunui

Poihipi

220 kV

Tokaanu

CENTRAL NORTH ISLAND

Kinleith

Ongarue

220 kV

220 kV

110 kV

110 kV

Otahuhu Bombay

110 kV

110 kV

110 kV

Stratford

110 kV

33 kV

33 kV

11 kV110 kV

110 kV33 kV

33 kV33 kV

66 kV

GENERATOR

11 kV

33 kV

Huntly

OtahuhuKopu

Waikino

Waihou

Hinuera

Cambridge

Karapiro

Arapuni

BAY OF PLENTY

Waipapa

Maraetai

Whakamaru

220 kV

Ohakuri

220 kV

Tarukenga

Wairakei


Hangatiki

Te Awamutu

Te Kowhai

Hamilton

DruryAUCKLAND

TARANAKI


Ohinewai

33 kV

Kawerau

11 kV




This region contributes a significant portion of the total North Island generation and exceeds local demand. Surplus generation is exported over the 220 kV transmission network to the rest of the country. The 220 kV transmission network has enough capacity to provide n-1 security to the local load indefinitely.

The committed 400 kV-capable transmission line58

between Whakamaru and Pakuranga (Auckland) will reduce loading on the 220 kV and 110 kV circuits within the Waikato region.


The 110 kV transmission network within the region predominantly supplies and connects the rest of the Waikato region, including most of the regional load and some regional generation.

Transmission system issues

The 110 kV transmission network predominantly comprises low capacity circuits. This results in capacity and supply security issues for some outages. It also results in generation restrictions, particularly at Arapuni, even with all circuits in service. We have a number of investigations planned or underway to address these issues.

Maintenance security issues

The 220/110 kV interconnection at Hamilton supplies most of the load in the Waikato region. The outage of a 220 kV circuit to Hamilton or a 220/110 kV interconnecting transformer 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 full or partial n-1 security.


We are presently working on a Waikato regional development strategy. This project focuses on resolving short and long-term issues in the region, including the:

Waikato 110 kV transmission network (the 110 kV circuits that operate in parallel with the grid backbone between Tarukenga and Bombay)

110 kV Thames Valley spur, and

Hamilton interconnecting transformer capacity and maintenance security.

Additionally, in order to meet high load growth in the Tauranga area, one option is a transmission connection between Waihou and a new grid exit point north of Tauranga. This may involve converting parts of the Thames Valley spur to 220 kV.

The following are possible developments in the grid backbone through the Waikato region:

installing series capacitors on the 220 kV Brownhill–Whakamaru circuits (likely within the forecast period)

converting the 220 kV Brownhill–Whakamaru circuits to 400 kV operation by installing 400/220 kV interconnecting transformers at Brownhill and Whakamaru (likely beyond the forecast period).

9.3 Waikato demand

The after diversity maximum demand (ADMD) for the Waikato region is forecast to grow on average by 1.8% annually over the next 15 years, from 511 MW in 2012 to

58

Part of the North Island Grid Upgrade (NIGU) project, see Chapter 6 for more information.



668 MW by 2027. This is higher than the national average demand growth of 1.7% annually.


59) for the Waikato region. The forecasts are derived using


Figure 9-3: Waikato region after diversity maximum demand forecast

Table 9-1 lists forecasts peak demand (prudent growth) for each grid exit point for the forecast period, as required for the Grid Reliability Report.

Table 9-1: Forecast annual peak demand (MW) at Waikato grid exit points to 2027


Peak demand (MW)


2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Cambridge1 0.98 38 39 39 40 40 41 42 43 45 46 47

Hamilton 11 kV 1.00 47 48 49 25 0 0 0 0 0 0 0

Hamilton 33 kV2 0.99 148 151 154 182 212 216 225 234 241 249 256

Hamilton NZR 0.80 8 8 8 8 8 8 8 8 8 8 8

Hangatiki 0.88 30 31 31 32 33 33 35 36 37 38 39

Hinuera3 0.95 47 48 42 43 44 45 47 49 51 52 54

Huntly4 0.99 25 25 26 26 42 43 44 45 47 48 49

Kopu -0.99 50 52 53 55 56 58 62 65 67 70 72

Piako5 0.98 0 28 28 29 30 31 33 35 36 38 39

Putaruru3 0.95 0 0 7 8 8 8 8 9 9 9 10

Te Kowhai2 0.97 105 110 112 117 120 122 127 131 135 139 141

Te Awamutu1 0.98 37 37 38 39 39 40 41 43 44 46 48

59


300

350

400

450

500

550

600

650

700

750

800

1997 1999 2001 2003 2005 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027

Load (MW) Waikato

2011 APR Forecast

2012 APR Forecast

Actual Peak




Peak demand (MW)


2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Waihou5 0.96 67 41 43 44 45 47 49 52 54 56 58

Waikino 1.00 41 42 44 45 46 48 50 53 55 57 59

Whakamaru 1.00 11 11 11 11 12 12 12 13 13 14 14

1. The customer provided this forecast.

2. The forecast is distorted by frequent and regular load shifting between Hamilton and Te Kowhai.

3. Some load will be shifted from Hinuera to a proposed new grid exit point at Putaruru in 2014.

4. An industrial load increase of 5 MW is expected at Huntly in 2012.

5. Some load will be shifted from Waihou to a new grid exit point at Piako.

9.4 Waikato generation

The Waikato region’s generation capacity is 2,662 MW.

Table 9-2 lists the generation forecast for each grid injection point for the forecast period, as required for the Grid Reliability Report. This includes all known and committed generation stations including those embedded within the relevant local lines company’s network (Waipa Networks, WEL Networks, The Lines Company or Powerco).

60

Table 9-2: Forecast annual generation capacity (MW) at Waikato grid injection points to 2027 (including existing and committed generation)




2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Arapuni 197 197 197 197 197 197 197 197 197 197 197

Atiamuri 84 84 84 84 84 84 84 84 84 84 84

Huntly 1448 1448 1448 1448 1448 1448 1448 1448 1448 1448 1448

Karapiro 90 90 90 90 90 90 90 90 90 90 90

Maraetai 360 360 360 360 360 360 360 360 360 360 360

Mokai 112 112 112 112 112 112 112 112 112 112 112

Ohakuri 112 112 112 112 112 112 112 112 112 112 112

Te Kowhai (Te Rapa) 44 44 44 44 44 44 44 44 44 44 44

Te Kowhai (Te Uku) 64 64 64 64 64 64 64 64 64 64 64

Waipapa 51 51 51 51 51 51 51 51 51 51 51

Whakamaru 100 100 100 100 100 100 100 100 100 100 100

9.5 Waikato significant maintenance work


61 proposed for the Waikato region for the next


60






Description Tentative year Related system issues

Cambridge 11 kV switchgear replacement

2013 Upgrading the 11 kV switchgear will improve the Cambridge supply transformer n-1 capacity issue. See Section 9.8.6 for more information.

Hamilton T5 supply transformer expected end-of-life

2022-2024 A significant increase in supply transformer capacity is required within the forecast period. Increasing the capacity of T5 will reduce the transformer overload. See Section 9.8.7 for more information.

Hangatiki T1 and T2 supply transformers’ expected end-of-life

2013-2015 Upgrading the transformers’ capacity is one of the possible options to resolve the transformer overload issue. See Section 9.8.8 for more information.

Hinuera T1 and T2 supply transformers’ expected end-of-life

2022-2029 Upgrading the capacity of T1 is one of the possible options (following construction of Putaruru) to resolve the transformer loading issue. See Section 9.8.9 for more information.

Waihou supply transformers’ expected end-of-life, 33 kV outdoor to indoor conversion, and 110 kV substation rebuild

2022-2027

2013-2015

Upgrading the transformers’ capacity is one of the possible options (following construction of Piako) to resolve the transformer overloading issue. See Section 9.8.15 for more information.

The replacement transformer with on-load tap changing capability will improve the voltage profile at Waihou. See Section 9.8.5 for more information.

Waikino supply transformers’ expected end-of-life, and 33 kV outdoor to indoor conversion

2018-2022

Upgrading the transformers’ capacity is one of the possible options to resolve transformer overloading issue. See Section 9.8.16 for more information.

The replacement transformer with on-load tap changing capability will improve the voltage profile at Waikino. See Section 9.8.5 for more information.

9.6 Future Waikato projects summary and transmission configuration

Table 9-4 lists projects to be carried out in the Waikato region within the next 15 years.

Figure 9-4 shows the possible configuration of Waikato transmission in 2027, with new assets, upgraded assets, and assets undergoing significant maintenance within the forecast period.

Table 9-4: Projects in the Waikato region up to 2027


Arapuni Reconfigure 110 kV bus. Committed

Arapuni–Kinleith Increase the line capacity by reconductoring/thermal upgrading. Possible

Cambridge Replace 11 kV switchgear. Committed

Hamilton Install a new 220/110 kV interconnecting transformer. Install a new 220/33 kV supply transformer.

Possible Possible

Hamilton–Waihou Increase the line capacity by building a new 110 kV Hamilton–Waihou circuit or upgrade 110 kV Hamilton–Waihou circuits.

Possible

Hangatiki Replace 110/33 kV supply transformers Base Capex

Hinuera Upgrade the 110/33 kV 30 MVA supply transformer capacity. Possible

Karapiro Upgrade 110 kV switchyard. Base Capex

Kopu Resolve supply transformer protection limits. Base Capex

Piako New grid exit point. Committed

Putaruru New grid exit point. Possible

Te Awamutu New transmission circuit either from Hangatiki or Karapiro. Resolve supply transformer protection limits.

Possible Base Capex

Te Kowhai Install radiators and fans on the existing supply transformers. Committed




Install a new 220/33 kV supply transformer. Possible

Waihou Rebuild 110 kV structure. Replace 110/33 kV supply transformers. Convert 33 kV outdoor switchgear to an indoor switchboard. Install new capacitors.

Base Capex Base Capex Base Capex Possible

Waikino Install new capacitors. Replace supply transformers. Convert 33 kV outdoor switchgear to an indoor switchboard.


Figure 9-4: Possible Waikato transmission configuration in 2027

`

KEY

110 kV

AUCKLANDOtahuhu

220 kV

220 kV

220 kV

Taumarunui

Poihipi/Wairakei

220 kV

Tokaanu


Kinleith

Ongarue

220 kV

220 kV

110 kV

110 kV

Otahuhu Bombay

110 kV

110 kV

110 kV

Stratford

110 kV

33 kV

33 kV

11 kV

110 kV

110 kV33 kV

33 kV

33 kV

Kopu

33 kV

110 kV

Brownhill

66 kV

Waikino

Waihou

Piako

Hinuera

Cambridge

Karapiro

Arapuni

Putaruru

BAY OF PLENTYAtiamuri

220 kV

Ohakuri

220 kV

Tarukenga

Wairakei

AUCKLAND

Whakamaru

Hangatiki

Te Awamutu

Te Kowhai

Maraetai

Waipapa

Hamilton

Huntly

33 kVOhinewai

220 kV

Drury

(1) the transmission backbone section identifies two

development paths for the lower North Island:

- upgrade existing lines, and/or

- new transmission line

Although this diagram shows upgrading of existing

lines, it is not intended to indicate a preference as

both options are still being investigated.

TARANAKI

Kawerau

Wairakei

Whakamaru North

11 kV

NEW ASSETS

UPGRADED ASSETS

ASSETS SCHEDULED

FOR REPLACEMENT

* MINOR UPGRADE

*

*

(1)




Issues Change

Bombay–Hamilton and Arapuni–Bombay 110 kV transmission capacity

Issue removed. Loading on these circuits is managed with Arapuni constraints or a bus split.

Te Awamutu supply transformer capacity New issue.



9.8 Waikato transmission capability

Table 9-6 summarises issues involving the Waikato region for the next 15 years. For more information about a particular issue, refer to the listed section number.

Table 9-6: Waikato regional transmission issues

Section number

Issue

Regional

9.8.1 Arapuni–Hamilton 110 kV transmission capacity

9.8.2 Arapuni–Kinleith 110 kV transmission capacity

9.8.3 Hamilton interconnecting transformer capacity

9.8.4 Hamilton–Waihou 110 kV transmission capacity

9.8.5 Waihou–Waikino–Kopu spur low voltage


9.8.6 Cambridge supply transformer capacity

9.8.7 Hamilton supply transformer capacity

9.8.8 Hangatiki supply transformer capacity

9.8.9 Hinuera supply transformer capacity

9.8.10 Hinuera transmission security

9.8.11 Kopu supply transformer capacity

9.8.12 Maraetai–Whakamaru transmission capacity

9.8.13 Te Awamutu supply transformer capacity

9.8.14 Te Awamutu transmission security

9.8.15 Waihou supply transformer capacity

9.8.16 Waikino supply transformer capacity

9.8.1 Arapuni–Hamilton 110 kV transmission capacity


Issue

The two 110 kV Arapuni–Hamilton circuits are each rated at 51/62 MVA (summer/winter).

The 110 kV bus is currently permanently split with two bus sections:

Arapuni G1-4 generators, Arapuni–Bombay, Arapuni–Hamilton 1 and 2, Arapuni–Hangatiki, and the Arapuni–Ongarue circuits on one bus (north bus)

Arapuni–Kinleith 1 and 2 circuits on the other bus (south bus), and

Arapuni G5-8 are selectable between the two bus sections.

Cost benefit analysis showed that it is economic to permanently split the bus until the new Pakuranga–Whakamaru line

62 is commissioned. This analysis will be revisited

prior to the commissioning of the new line to decide the operational strategy in the future.

With the Arapuni bus split open:

62

This is a new 220/400 kV double-circuit transmission line, and forms part of the North Island Grid Upgrade (NIGU) project.



Arapuni north bus generation may be constrained pre-contingency to manage the loading on the Arapuni–Hamilton circuits for an outage of the Arapuni–Hamilton circuit

the Arapuni runback is enabled on Arapuni G1-4 to reduce generation if an Arapuni–Hamilton circuit overloads.

With the Arapuni bus split closed, and following the commissioning of the Pakuranga–Whakamaru line:

Arapuni generation may be constrained pre-contingency to manage the loading on the Arapuni–Hamilton circuits for an outage of the Arapuni–Hamilton or Hamilton–Whakamaru circuit.

the Arapuni runback is enabled on Arapuni G1-4 to reduce generation if an Arapuni–Hamilton circuit overloads.

The worst case conditions are during:

summer, when Huntly generation is sometimes restricted due to high river temperatures, and

high hydro inflow periods, when renewable generation south of Whakamaru is dispatched ahead of thermal generation in the upper North Island.

Solution

The Arapuni bus split is currently implemented by connecting three 110 kV circuits directly to the 110 kV bus. This is not a long-term solution, as it restricts maintenance access to those circuits. An investigation is underway to determine a longer-term strategy for the Arapuni bus split.

A number of projects that are presently being implemented or considered as solutions to other issues will also relieve the loading on the 110 kV Arapuni–Hamilton circuits. These other projects include the NIGU project, the Tarukenga interconnecting transformer replacement and the new Putaruru grid exit point (see Section 9.8.10 for more information).

An investigation into longer-term options to resolve this issue is ongoing. However, a preliminary assessment of the Investment Test indicates that reconductoring the 110 kV circuits to remove the overload may not be economic. A condition assessment shows that the existing conductor will not require replacement within the forecast period.

9.8.2 Arapuni–Kinleith 110 kV transmission capacity

Project reference: ARI_KIN-TRAN-EHMT-01




Issue

There are two 110 kV Arapuni–Kinleith circuits (1 and 2), rated at 57/70 MVA and 63/77 MVA (summer/winter), respectively. There is a possibility of a new grid exit point (Putaruru) being single tee-connected part way along Arapuni–Kinleith circuit 2 in 2013

63 (see Section 9.8.10 for more information).

Loading on the 110 kV Arapuni–Kinleith circuits may exceed their n-1 capacity under certain operating conditions.

With the Arapuni bus split open, factors contributing to this overload include:

the summer ratings period, and

63

Putaruru load is expected to be approximately 7 MW from 2014.



full 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 high pulp and paper plant production periods)

high generation at Arapuni

high Huntly and Auckland-area generation, and

high south power flow (for example, HVDC south power flow).

Additionally, the 110 kV circuits between Kinleith and Lichfield are often opened to prevent overloading during some outages in the Bay of Plenty region. The Kinleith load is then supplied by the two 110 kV Arapuni–Kinleith circuits and generation at Kinleith. For some system conditions the load at Kinleith may be on n security when the system is split.

Peak load at Kinleith is approximately 95 MW (offset by up to 40 MW of on-site generation) and is forecast to remain steady. The net Kinleith load rarely exceeds 75 MW. The typical daily peaks are between 55 MW and 65 MW.

Solution

In the short term, loading on Arapuni–Kinleith circuits is managed by:

opening Arapuni bus split, and

restricting Arapuni south bus generation during summer ratings.

Following the commissioning of the Pakuranga–Whakamaru double-circuit line and the 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 during south power flow include:

special protection schemes, or

reconfiguration of the Kinleith 110 kV bus.

In the longer term, possible options to increase the capacity of the Arapuni–Kinleith circuits include:

reconductoring Arapuni–Kinleith 1

reconductoring the Arapuni–Putaruru line section, and

thermally upgrading the Kinleith–Putaruru line section.

Acquisition of property easements may be required for reconductoring work in some cases.

9.8.3 Hamilton interconnecting transformer capacity

Project reference: HAM-POW_TFR-DEV-01



Indicative cost band: New interconnecting transformer: B New substation: C

Issue

Two three-phase interconnecting transformers at Hamilton supply much of the Waikato 110 kV transmission network load, as well as a small proportion of the Auckland and Bay of Plenty 110 kV loads under certain load flow conditions. These transformers provide:





(summer/winter).

During low 110 kV generation in Waikato (Arapuni and Karapiro generation) and high Waikato demand, the load on the Hamilton interconnecting transformers may exceed their n-1 capacity. This overloading issue worsens:

with low Upper North Island generation, and

after completion of the Tarukenga interconnecting transformer replacement project (see Chapter 10, Section 10.9.4).

Solution

In the short term, we anticipate this issue will be managed operationally with generation rescheduling and load management.

However, with low upper North Island generation and/or higher load growth there may not be enough Waikato 110 kV generation to manage this issue towards the end of the forecast period.

Developments being considered or underway, such as the NIGU project, will reduce loading on the Hamilton interconnecting transformers. We are also discussing options for the long-term supply of Hamilton City with WEL Networks (see Section 9.8.7). If the existing 110/11 kV load at Hamilton is moved to the 33 kV bus, the loading on the Hamilton transformers will decrease.

Two of the options that Transpower is considering for upgrading the 220/110 kV Hamilton interconnecting transformers (when required) include a new 200 MVA transformer:

in parallel with the existing transformers, or

at a new substation, connected to the intersection of the 220 kV Otahuhu–Whakamaru 3 circuit and the 110 kV Hamilton–Waihou circuits.

The second option improves security during maintenance outages of the 220 kV circuits supplying Hamilton, and forms the connection point for a third circuit to Waihou (instead of a Hamilton connection, see Section 9.8.4 for more information).

9.8.4 Hamilton–Waihou 110 kV transmission capacity

Project reference: HAM_WHU-TRAN-DEV-01



Indicative cost band: Third Hamilton–Waihou circuit: D Reconductoring Hamilton–Waihou circuit: C

Issue

Two 110 kV Hamilton–Waihou circuits supply the ‘Valley Spur’ (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 2011 peaks of approximately 114 MW and 127 MW, respectively.

The peak load in the Valley Spur is forecast to exceed the circuits’ n-1 summer capacity by approximately 1 MW in 2016, increasing to approximately 40 MW in 2027 (See Table 9-7).

64

The transformers’ capacity is limited by protection equipment; with this limit resolved, the n-1 capacity will be 248/259 MVA (summer/winter).



Table 9-7: Valley Spur circuit overload forecast

Grid exit point Circuit overload (MW)


2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Valley Spur 0 0 0 0 1 5 14 22 28 35 40

The transmission loading is further exacerbated by the low voltage along the spur (see Section 9.8.5 for more information).

Solution

Together with Powerco, we have investigated connecting a new grid exit point to these circuits at Piako, part-way between Hamilton and Waihou (see Section 9.8.15 for more information). Approximately 40% of the Waihou load will be shifted to Piako, and consequently the circuit overloading issue will only occur between Hamilton and Piako.

We will investigate the installation of capacitors to relieve the Valley Spur low voltage issues (see Section 9.8.5 for more information). This provides an interim solution to the Hamilton–Waihou circuits’ capacity issue, delaying the need for further transmission reinforcement by approximately one year.

In the short term, the overload can be managed operationally.

We will also investigate longer-term additional investment, other than installing capacitors along the Valley Spur. Possible options include:

constructing a third 110 kV Hamilton–Waihou circuit of a similar capacity to the existing circuits, or

upgrading the existing 110 kV Hamilton–Waihou circuits to increase their summer capacity.

The timing and choice of the capacity reinforcement option will be influenced by load growth and developments within Powerco’s network, such as load transfer from the Valley Spur to Hinuera grid exit point.

Depending on the solution, we may need to purchase easements for either a new line or for some parts of an upgraded line.

9.8.5 Waihou–Waikino–Kopu spur low voltage

Project reference: VLYS-REA_PWS-DEV-01


Indicative timing: New capacitors: 2014-2017 Supply transformer replacement: 2013-2015

Indicative cost band: New capacitors: A Waihou supply transformer replacement: B Waikino supply transformer replacement: A

Issue

Supply bus voltages at the Waihou and Waikino grid exit points are forecast to fall below 0.95 pu following an outage of one 110 kV Hamilton–Waihou circuit. In addition, the step voltage change for such an outage will exceed 5%. Both grid exit points have supply transformers with off-load tap changers.

Solution

We are investigating options to maintain voltage at the Waihou and Waikino buses. Possible options include:



installing two 20 Mvar capacitors (along the Valley Spur or within Powerco’s network), which will also defer Valley Spur investment (see Section 9.8.4 for more information), or

replacing the existing transformers at Waikino and Waihou, which are due for replacement in the next 10 years, with on-load tap changing transformers, and installing a lesser number of capacitors.

Property issues may arise if there is a need to expand the substation to accommodate the new capacitors.

9.8.6 Cambridge supply transformer capacity

Project reference: CBG-SUBEST-EHMT-01

Project status/purpose: Committed, minor enhancement and customer-specific



Issue

Two 110/11 kV transformers supply Cambridge’s load, providing:


n-1 capacity of 38/3865

MVA (summer/winter).

The peak load at Cambridge is forecast to exceed the transformers’ n-1 winter capacity by approximately 3 MW in 2012, increasing to approximately 12 MW in 2027 (see Table 9-8).

Table 9-8: Cambridge supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Cambridge 0.98 3 4 5 5 5 6 8 8 10 11 12

Solution

The Cambridge 11 kV switchgear is currently being replaced. This will resolve the bus and protection limits, providing sufficient capacity until 2023 when the transformers’ n-1 winter capacity will be exceeded by approximately 1 MW. This overload will increase to approximately 2 MW in 2027. We will discuss the options to increase the supply transformers’ n-1 capacity with Waipa Networks closer to this time.

9.8.7 Hamilton supply transformer capacity

Project reference: HAM-SUBEST-DEV-01


Indicative timing: New supply transformer at Hamilton: 2015 New supply transformer at Te Kowhai: 2018

Indicative cost band: Cost for one new supply transformer: A (at Hamilton), C (at Te Kowhai)

Issue

Hamilton has both an 11 kV and a 33 kV supply bus. In 2015, the 11 kV supply will be decommissioned and the load transferred to the 33 kV.

Two 110/11 kV transformers supply Hamilton’s 11 kV load, providing:

65

The transformers’ capacity is limited by the 11 kV bus and protection limits; with these limits resolved, the n-1 capacity will be 45/47 MVA (summer/winter).






The peak load at Hamilton 11 kV is forecast to exceed the transformers’ n-1 winter capacity by approximately 10 MW in 2012, increasing to approximately 13 MW in 2014 (see Table 9-9).

Two 220/33 kV transformers supply Hamilton’s 33 kV load, providing:



The peak load at Hamilton 33 kV is forecast to exceed the transformers’ n-1 winter capacity by approximately 34 MW in 2012, increasing to approximately 68 MW in 2015. When the 11 kV supply bus is decommissioned and the load is transferred to the 33 kV bus, the 220/33 kV transformer overload forecast increases to approximately 141 MW in 2027 (see Table 9-9). This large overload is partly due to load shifting from Te Kowhai to Hamilton to manage distribution company loads.

Table 9-9: Hamilton supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Hamilton 11 kV 1.00 10 12 13 0 0 0 0 0 0 0 0

Hamilton 33 kV 0.99 34 37 40 68 97 102 111 119 127 135 141

WEL Networks is capable of significant load shifting between Hamilton and Te Kowhai, so the combined load is compared with the total supply transformer capacity at both grid exit points.

Four 220/33 kV transformers at Hamilton and Te Kowhai supply the total Hamilton city 33 kV load, providing:



The total load is forecast to be 220 MW in 2012, increasing to 354 MW by 2027. The total supply transformer capacity will not be exceeded until approximately 2026.

Solution

An interim solution is to transfer load to the Te Kowhai grid exit point. Table 9-9 shows that significant load transfers will be required by 2027. As a longer-term solution, we are investigating a range of options with WEL networks that include:

increasing the rating of the two existing supply transformers at Te Kowhai (a committed project, see Section 9.9.4)

installing a third 220/33 kV supply transformer at Hamilton, and

installing a third 220/33 kV supply transformer at Te Kowhai (see Section 9.9.4).

In addition, Hamilton T5 transformer has an expected end-of-life in the next 10-15 years. We will discuss with WEL Networks the appropriate rating and timing for the replacement transformer.

9.8.8 Hangatiki supply transformer capacity

Project reference: HTI-POW_TFR-REPL-01


66

The transformers’ capacity is limited by the 11 kV transformer branch component; with this limit resolved, the n-1 capacity will be 48/51 MVA (summer/winter).





Issue

Two 110/33 kV transformers supply Hangatiki’s load, providing:



Hangatiki winter and summer load peaks are similar. The peak load at Hangatiki is forecast to exceed the transformers’ n-1 summer capacity by approximately 13 MW in 2012, increasing to approximately 20 MW in 2027 (see Table 9-10).

Table 9-10: Hangatiki supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Hangatiki 0.88 13 14 14 15 15 16 17 18 19 20 20

Solution

The Hangatiki transformers are made up of single-phase units, with a non-contracted spare available on site. There is a possibility of new embedded generation in this area that may reduce peak transformer loading.

We are discussing longer-term options with The Lines Company, such as replacing the existing transformers with two 40 MVA supply transformers.

In addition, all the Hangatiki supply transformers have an expected end-of-life within the next five years. Future investment will be customer driven.

9.8.9 Hinuera supply transformer capacity

Project reference: New grid exit point: PTR-SUBEST-DEV-01 Transformer replacement: HIN-POW_TFR-EHMT-01


Indicative timing: New grid exit point: 2014 Transformer replacement: to be advised

Indicative cost band: New grid exit point: C Transformer replacement: A

Issue

Two 110/33 kV transformers (rated at 30 MVA and 50 MVA) supply Hinuera’s load, providing:



The peak load at Hinuera is forecast to exceed the transformers’ n-1 winter capacity by approximately 13 MW in 2012. The overload will decrease in 2014 if Putaruru is completed. The transformers’ n-1 winter capacity will be exceeded by approximately 8 MW in 2014, increasing to approximately 20 MW in 2027 (see Table 9-11).



Table 9-11: Hinuera supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Hinuera 0.95 13 14 8 8 9 10 12 14 16 18 20

Hinuera (no Putaruru)

0.95 13 14 15 16 17 18 21 23 25 28 30

Solution

Powerco is planning to increase transmission security in the Hinuera area with a new grid exit point near Putaruru, which will be connected to the existing 110 kV Arapuni–Kinleith circuit 2 (see also Section 9.8.10). This new grid exit point will reduce Hinuera load by approximately 15% by 2027, but will not resolve the Hinuera supply transformer overload issue.

We will discuss with Powerco the options to relieve this issue, one of which is to replace the 30 MVA transformer with a 60 MVA unit. This will provide n-1 security of supply beyond the forecast period

67. In the short term, load may be transferred within

the Powerco network from Hinuera to Waihou to resolve this issue. Any future investment or transformer upgrade will be customer driven.

9.8.10 Hinuera transmission security

Project reference: PTR-SUBEST-DEV-01



Indicative cost band: C

Issue

A single 110 kV circuit from Karapiro supplies Hinuera’s load, providing:

a capacity of 63/77 MVA (summer/winter), and

no n-1 security (given there is only one supplying circuit).

Peak load in the Hinuera area is forecast to be 47 MW in 2012, increasing to 54 MW in 2027.

Solution

Powerco is considering increasing transmission security to Hinuera’s load with a new grid exit point near Putaruru (connected to the existing 110 kV Arapuni–Kinleith circuit 2). 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 remainder secured by backfeeding within the local lines distribution system from Putaruru or Waihou.

9.8.11 Kopu supply transformer capacity

Project reference: KPU-POW_TFR_PTN-EHMT-01




67

The 50 MVA transformer’s capacity is limited by 33 kV metering; this limit will bind from 2021 if it is not resolved.



Issue

Two 110/66 kV transformers supply Kopu’s load, providing:



(summer/winter).

The peak load at Kopu is forecast to exceed the transformers’ n-1 capacity by approximately 9 MW in 2012, increasing to approximately 31 MW in 2027 (see Table 9-12).

Table 9-12: Kopu supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Kopu -0.99 9 11 12 14 15 17 21 24 26 29 31

Solution

Resolving the protection limit will increase the transformers’ n-1 capacity to 64/67 MVA (summer/winter), providing sufficient capacity until 2018. Following the protection upgrade, the peak load at Kopu is forecast to exceed the transformers’ n-1 winter capacity by approximately 1 MW in 2018. This overload will increase to approximately 13 MW in 2027. We will discuss options to increase the supply transformers’ n-1 capacity with Powerco closer to this time. Alternatives may include:

replacing the existing transformers with higher capacity units, or

converting some 66 kV feeders to 110 kV operation.

9.8.12 Maraetai–Whakamaru transmission capacity


Issue

The 220 kV Maraetai–Whakamaru 1 and 2 circuits are each rated at 202/246 MVA (summer/winter). These circuits carry the entire generation output of the Waipapa and Maraetai generation stations to Whakamaru.

The generation stations’ combined capacity is 411 MW. If there is an outage of one of the Maraetai–Whakamaru circuits, generation is restricted to approximately 50% of full capacity in summer and 60% of full capacity in winter.

Solution

In case of a contingency, a generation runback scheme is in place to reduce generation to the available capacity of the remaining circuit. This situation has been considered satisfactory since the generation was first installed, and there are no plans to make transmission network changes at this stage.

9.8.13 Te Awamutu supply transformer capacity

Project reference: TMU-POW_TFR_PTN-EHMT-01




68




Issue

Two 110/11 kV transformers supply Te Awamutu’s load, providing:



(summer/winter).

The peak load at Te Awamutu is forecast to exceed the transformers’ n-1 capacity by approximately 1 MW in 2015, increasing to approximately 10 MW in 2027 (see Table 9-13).

Table 9-13: Te Awamutu supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Te Awamutu 0.98 0 0 0 1 1 2 3 5 6 8 10

Solution

Resolving the protection limit will increase the transformers’ n-1 capacity to 52/54 MVA (summer/winter), providing sufficient capacity for the forecast period and beyond.

9.8.14 Te Awamutu transmission security

Project reference: HTI_TMU-TRAN-DEV-01




Issue

A single 110 kV circuit from Karapiro supplies Te Awamutu’s load, providing:

a capacity of 63/77 MVA (summer/winter), and

no n-1 security (given there is only one supplying circuit).

Te Awamutu’s peak load is forecast to be 38 MW in 2012, increasing to 46 MW in 2027.

Solution

We have investigated and discussed several options with Waipa Networks for providing n-1 security to Te Awamutu, which include:

a new 110 kV circuit from Hangatiki to Te Awamutu, or

a second 110 kV circuit from Karapiro to Te Awamutu.

Waipa Networks may construct a new 110 kV circuit from Hangatiki to Te Awamutu, to be operated by Transpower.

9.8.15 Waihou supply transformer capacity

Project reference: New grid exit point: PAO-SUBEST-DEV-01 Transformer replacement: WHU-POW_TFR-REPL-01

Project status/purpose: New grid exit point: committed, customer-specific Transformer replacement: Base Capex, replacement

Indicative timing: New grid exit point: 2012-2013 Transformer replacement: 2022-2027

69




Indicative cost band: New grid exit point: C Transformer replacement: B

Issue

Three 110/33 kV transformers supply Waihou’s load, providing:



Waihou winter and summer peak loads are similar. The peak load at Waihou is forecast to exceed the transformers’ n-1 summer capacity by approximately 26 MW in 2012. The overload will decrease when Piako is completed, increasing to approximately 17 MW in 2027 (see Table 9-14).

Table 9-14: Waihou supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Waihou 0.96 26 1 2 3 5 6 9 11 13 15 17

Following a supply transformer contingency (for example, a unit failure), restoration of full capacity can be achieved by:

shifting load to other grid exit points, and

swapping a transformer unit with an on-site spare unit, taking up to 14 hours to complete.

Solution

Powerco is planning to increase transmission security to Waihou with a new grid exit point at Piako. Piako will connect to the existing 110 kV Hamilton–Waihou circuits and reduce Waihou peak load by approximately 40% by 2027.

This will not resolve the Waihou supply transformer overload issue. A likely long-term solution is to replace the existing transformers with higher-rated transformers. These transformers have an expected end-of-life within the next 10-15 years. We will discuss with Powerco the appropriate number, rating, and timing for the replacement transformers.

In addition, we will convert the 33 kV outdoor switchyard to an indoor switchboard within the next five years.

9.8.16 Waikino supply transformer capacity

Project reference: WKO-POW_TFR-EHMT-01




Issue

Two 110/33 kV transformers supply Waikino’s load, providing:



The peak load at Waikino is forecast to exceed the transformers’ n-1 summer capacity by approximately 5 MW in 2012, increasing to approximately 23 MW in 2027 (see Table 9-15).



Table 9-15: Waikino supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Waikino 1.00 5 6 7 8 10 11 14 17 19 21 23

Solution

In the short term, operational measures can be used to manage this issue. We will discuss with Powerco the options to increase the supply transformers’ n-1 capacity.

In addition, the existing supply transformers at Waikino will approach their expected end-of-life within the next 5-10 years, and conversion of the existing 33 kV switchgear from outdoor to an indoor switchboard is planned for around the same time.


9.9.1 Cambridge spur capacity

Project statuspurpose: This issue is for information only

Issue

The Cambridge Spur comprises three loads (at Cambridge, Te Awamutu, and Hinuera), which are offset by Karapiro generation. There are two 110 kV circuits supplying this spur, each with a capacity of 57/70 MVA (summer/winter).

The summer peak load on this spur is approaching the winter peak load, and the combined load on the Cambridge Spur in summer 2011 was approximately 100 MW. This is forecast to increase to approximately 128 MW by 2027. To avoid exceeding the n-1 capacity of the Hamilton–Cambridge–Karapiro circuits during peak summer load periods, Karapiro’s minimum generation will need to be approximately 47 MW in 2012. However, the minimum Karapiro generation will decrease to 42 MW following the commissioning of Putaruru in 2014, increasing to 62 MW in 2027.

Solution

Karapiro generation is generally reliable and has a capacity of 90 MW. It typically operates at 40 MW during low load periods and 80-90 MW during daytime peaks. Hinuera load will decrease when the new Putaruru grid exit point is commissioned in 2014. However, with continued load growth and periods of low water inflows, there will eventually be insufficient available generation to avoid exceeding the Hamilton–Cambridge–Karapiro circuits’ n-1 capacity (requiring a circuit upgrade).

The proposed Hangatiki–Te Awamutu 110 kV circuit will also impact the loading on these circuits (see Section 9.8.14). Depending on the generation and load pattern in the region, the flows on the Cambridge spur may increase or decrease.

We will investigate options to alleviate the overload.

9.9.2 Hamilton low voltage


Issue

The Hamilton 220 kV bus will have low voltage (below 0.9 pu) from 2019 for the following system conditions:

high load periods



loss of the 220 kV Hamilton–Ohinewai circuit, and

low Waikato 110 kV generation.

Solution

We will investigate options to resolve this issue closer to the time it occurs. Some of the options include:

reactive support in the Waikato 110 kV transmission network, and

a third 220 kV connection to Hamilton (see Section 9.9.3).

9.9.3 Hamilton transmission security during maintenance


Issue

When either a 220 kV Hamilton–Whakamaru circuit or a 220 kV Hamilton–Ohinewai circuit or Hamilton 220/110 kV interconnection is out for maintenance, the 110 kV system is split from the 220 kV system, placing a considerable part of the Waikato region on n security.

Solution

It may be economic to provide full or partial n-1 security during maintenance. We are considering options that include a:

new 200 MVA 220/110 kV transformer at a new substation, connected to the intersection of the 220 kV Otahuhu–Whakamaru 3 circuit and the 110 kV Hamilton–Waihou circuits, or

third 220 kV circuit into Hamilton, and/or

third interconnecting transformer in parallel with the existing transformers.

9.9.4 Te Kowhai substation developments

Project reference: TWH-POW_TFR-EHMT-01

Project status/purpose: Supply transformer upgrade: committed, customer-specific New supply transformer: possible, customer-specific

Indicative timing: Supply transformer upgrade: 2012 New supply transformer 2018

Indicative cost band: Supply transformer upgrade: A New supply transformer: C

Issue

Two 220/33 kV transformers supply Te Kowhai’s load, providing:



There are also two embedded generators (Te Uku and Te Rapa) at Te Kowhai. The net load in 2011 ranged from an injection of approximately 70 MW to an off take of approximately 85 MW.

Solution

The distribution network is capable of substantial load shifting between Te Kowhai and Hamilton. The supply capacity at Hamilton is highly constrained (see Section 9.8.7). Following discussions with WEL Networks, to enable additional load transfer to Te Kowhai from Hamilton, we are:

increasing the rating of the two existing supply transformers by installing radiators and fans in 2012, increasing the n-1 capacity to 132 MVA, and



proposing to install a third 120 MVA 220/33 kV supply transformer at Te Kowhai by around 2018.

9.10 Waikato generation proposals and opportunities



70

9.10.1 Hauauru Ma Raki wind station

The proposed Hauauru Ma Raki wind generation station (also referred to as the Waikato wind station) may generate up to 540 MW, and will connect to the 220 kV double-circuit transmission line between Huntly and Drury.

If it is necessary to cater for a generation scenario with maximum wind generation and maximum Huntly generation (assuming sustained low hydro generation), then it may be necessary to reconductor the two 220 kV Huntly–Ohinewai circuits, and thermally upgrade the two 220 kV circuits between the wind station connection and Drury.

9.10.2 Hangatiki generation

There are prospects to connect up to approximately 40 MW of generation at Hangatiki. 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 and generation scenarios, the following upgrades will be required:

runback schemes at Arapuni and/or Hangatiki.

reconductoring the 110 kV Arapuni–Hamilton circuits.

For example, during 2012 winter peak loads, with combined Huntly, Otahuhu, and Southdown generation of 1,525 MW and Arapuni generation of 180 MW, any generation at Hangatiki will cause the Arapuni–Hamilton circuits to overload.

In addition, any new generation on the 110 kV transmission network in the Waikato region will add to the 110 kV Bombay–Hamilton and 110 kV Arapuni–Kinleith loading (see Section 9.8.2). Options to enable this level of generation include generation runback schemes, generation re-scheduling, and possibly reconductoring the Bombay–Hamilton circuit. Possible overloading of the two 110 kV Arapuni–Kinleith circuits may need to be addressed, but this may be required irrespective of additional generation at Hangatiki.

70


Chapter 10: Bay of Plenty Region


10 Bay of Plenty Regional Plan


10.2 Bay of Plenty transmission system

10.3 Bay of Plenty demand

10.4 Bay of Plenty generation

10.5 Bay of Plenty significant maintenance work

10.6 Future Bay of Plenty projects summary and transmission configuration


10.8 Bay of Plenty transmission capability


10.10 Bay of Plenty generation proposals and opportunities


This chapter details the Bay of Plenty regional transmission plan. We base this regional plan on an assessment of available data, and welcome feedback to improve its value to all stakeholders.

Figure 10-1: Bay of Plenty region



The Bay of Plenty region includes a mix of significant and growing provincial cities (Mount Maunganui, Tauranga, and Rotorua) together with smaller, less active rural localities (Waiotahi and 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 15 years while considering longer-term development opportunities. Specifically, the transmission network needs to be flexible to respond to a range of future service and technology possibilities, taking into consideration:


forecast demand

forecast generation



10.2 Bay of Plenty transmission system

This section highlights the state of the Bay of Plenty regional transmission network. The existing transmission network is set out geographically in Figure 10-1 and schematically in Figure 10-2.

Figure 10-2: Bay of Plenty transmission schematic

110kV CIRCUIT

50kV CIRCUIT

SUBSTATION BUS

TRANSFORMER

TEE POINT

KEY

220kV CIRCUIT

LOAD

CAPACITOR

110 kV

110 kV

110 kV

110 kV

220 kV

220 kV

11 kV

110 kV

110 kV

110 kV110 kV

220 kV

11 kV

11 kV

11 kV

(TASMAN)

33 kV

110 kV 50 kV

11 kV 33 kV

33 kV

33 kV

11 kV

Mount Maunganui

Te MataiEdgecumbe

Waiotahi

Kawerau

Matahina

Owhata

Rotorua

Tarukenga

Lichfield

Ohakuri

WAIKATO

11 kV

Atiamuri

110 kV

Kaitimako

Okere

Aniwhenua

Wheao

110 kV

GENERATOR

110 kV

11 kV

Kinleith

WAIKATO

Arapuni

33 kV

11 kV

Te Kaha

110 kV

33 kV

11 kV

Tauranga


Bay of Plenty generation is lower than maximum local demand, with the deficit imported through the National Grid during peak load conditions, and any surplus exported during light load conditions.

The 220 kV Whakamaru–Atiamuri and Ohakuri–Wairakei circuits connect the region to the rest of the National Grid. The region will be on n security whenever one circuit is out of service for maintenance. These circuits’ capacities are expected to be adequate to supply the regional load in the short term. We will monitor the generation developments in the region and the Wairakei Ring area to determine if a transmission upgrade is required. See Chapter 6, section 6.4.3 for more information.



There is also a low capacity 110 kV Tarukenga–Kinleith–Arapuni connection. This connection is presently split at Arapuni to prevent it overloading.


The transmission network in the Bay of Plenty region comprises 220 kV and 110 kV circuits with interconnecting transformers located at Tarukenga, Edgecumbe, and Kawerau. The Edgecumbe interconnecting transformers are not normally in service. There is also a single 50 kV circuit between Waiotahi and Te Kaha.

The Bay of Plenty load is predominantly supplied through the 220 kV Whakamaru–Atiamuri and Ohakuri–Wairakei circuits, with lower capacity 110 kV circuits through Kinleith. Reactive power support is provided by 25 Mvar capacitors at Tauranga and Mount Maunganui.

Within the region, we will be converting the 110 kV transmission network between Tarukenga and Kaitimako

71 to 220 kV to provide greater capacity into Mount

Maunganui and Tauranga. This will resolve other system issues such as the overloading of a Tarukenga interconnecting transformer and the overloading of a 110 kV Okere–Te Matai circuit.

We are also discussing with Powerco and Unison options to increase the:

capacity into and around Rotorua which may involve line upgrades between Tarukenga and Rotorua, and/or new supply transformers at Rotorua and Owhata, and

supply security by building a new grid exit point at Papamoa to alleviate load growth at Mount Maunganui and Te Matai.

Generation and interruptible load connected directly or indirectly to the Kawerau 110 kV bus must sometimes be constrained to prevent overloading of the 220/110 kV transformers. There is a total of 236 MW installed generation capacity at Kawerau (Aniwhenua, Kawerau Geothermal, and Matahina).


No firm options have been developed for the Bay of Plenty region beyond the planning period. However, long-term planning for recent projects has indicated the following 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 Tauranga to the existing Waihou substation in the Waikato region. This may be required to meet long-term load growth in the fast-growing Tauranga area, and improve security during maintenance outages.

There is the potential for significant additional geothermal generation in the eastern Bay of Plenty region, around Kawerau. If significant generation eventuates, then a staged transmission capacity upgrade will be required (see Section 10.10.1 for more information).

71

The line between Tarukenga and Kaitimako is built at 220 kV but operated at 110 kV.



10.3 Bay of Plenty demand

The after diversity maximum demand (ADMD) for the Bay of Plenty region is forecast to grow on average by 1.2% annually over the next 15 years, from 581 MW in 2012 to 689 MW by 2027. This is lower than the national average demand growth of 1.7% annually.


72) for the Bay of Plenty region. The forecasts are derived

using historical data, and modified to account for customer information, where appropriate. The power factor at each grid exit point is also derived from historical data, and is used to calculate the real power capacity for power transformer and transmission line. See Chapter 4 for more information about demand forecasting.

Figure 10-3: Bay of Plenty region after diversity maximum demand forecast


Table 10-1: Forecast annual peak demand (MW) at Bay of Plenty grid exit points to 2027


Peak demand (MW)


2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Edgecumbe 0.96 65 67 70 72 75 77 83 88 92 96 99

Kaitimako1 0.98 22 27 34 35 36 37 39 41 43 45 47

Kawerau Horizon 0.98 21 21 22 23 23 24 25 26 27 28 29

Kawerau T6-T9 1.00 90 90 90 90 90 90 90 90 90 90 90

Kawerau T11/ T14 0.98 85 85 85 85 85 85 85 85 85 85 85

Kinleith 11 kV -0.94 85 85 85 85 85 85 85 85 85 85 85

Kinleith 33 kV 0.98 28 29 29 30 30 31 32 33 34 35 36

Lichfield 0.95 9 9 9 9 9 9 9 9 9 9 9

72


300

350

400

450

500

550

600

650

700

750

800

1997 1999 2001 2003 2005 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027

Load (MW) Bay of Plenty

2011 APR Forecast

2012 APR Forecast

Actual Peak




Peak demand (MW)


2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Mt Maunganui 33 kV

2

0.98 72 74 76 74 76 79 84 88 92 96 99

Owhata 0.99 16 16 17 17 17 18 18 19 20 20 21

Papamoa2 0.98 0 0 0 10 10 10 10 10 10 10 10

Rotorua 11 kV 0.97 35 35 36 36 36 36 37 38 38 39 39

Rotorua 33 kV 0.97 42 42 43 43 43 44 44 45 46 47 47

Tauranga 11 kV1 0.99 30 31 26 27 28 28 30 31 32 34 35

Tauranga 33 kV 0.95 88 91 93 96 99 102 108 114 118 123 127

Tarukenga 11 kV 1.00 12 12 12 13 13 13 13 14 14 14 15

Te Kaha 0.97 2 2 2 2 2 2 2 2 3 3 3

Te Matai2 0.96 33 34 35 31 32 33 35 37 39 41 42

Waiotahi 0.98 10 10 11 11 11 11 12 12 13 13 14

1. The customer advises that 5 MW of load will be shifted from Tauranga 11 kV to Kaitimako in 2014.

2. The customer advises that some 5 MW from Mt Maunganui and 5MW from Te Matai may be shifted to the new Papamoa East grid exit point in 2015.

10.4 Bay of Plenty generation

The Bay of Plenty region’s generation capacity is approximately 393 MW.

Kaimai is a run of river scheme that varies between 14 MW and 42 MW, injecting into the Tauranga 33 kV bus. Typically, 14 MW is the minimum generation available from the scheme, which is used to offset peak grid exit point loads, but only if sufficient water is available.

Table 10-2 lists the generation forecast for each grid injection point for the forecast period, as required for the Grid Reliability Report. This includes all known and committed generation stations including those embedded within the relevant local lines company’s network (Horizon, Unison, or Powerco).

73

Table 10-2: Forecast annual generation capacity (MW) at Bay of Plenty grid injection points to 2027 (including existing and committed generation)




2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Aniwhenua 25 25 25 25 25 25 25 25 25 25 25

Edgecumbe (Bay Milk)

10 10 10 10 10 10 10 10 10 10 10

Kawerau (BOPE) 6 6 6 6 6 6 6 6 6 6 6

Kawerau (TPP) 37 37 37 37 37 37 37 37 37 37 37

Kawerau - KAG 105 105 105 105 105 105 105 105 105 105 105

Kawerau (KA24) 9 9 9 9 9 9 9 9 9 9 9

Kawerau (Norske Skog) 25 25 25 25 25 25 25 25 25 25 25

Kinleith 28 28 28 28 28 28 28 28 28 28 28

Matahina 72 72 72 72 72 72 72 72 72 72 72

Mount Maunganui (Ballance Agri)

7 7 7 7 7 7 7 7 7 7 7

73







2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Rotorua (Fletcher Forests)

3 3 3 3 3 3 3 3 3 3 3

Rotorua (Wheao, Flaxy, Kaingaroa)

24 24 24 24 24 24 24 24 24 24 24

Tauranga (Kaimai) 42 42 42 42 42 42 42 42 42 42 42

10.5 Bay of Plenty significant maintenance work


74 proposed for the Bay of Plenty region for the

next 15 years that may significantly impact related system issues or connected parties.



Edgecumbe supply transformers expected end-of-life, and Edgecumbe 33 kV outdoor to indoor conversion

2027-2029

2012-2014

The forecast load will exceed the transformers’ n-1 capacity from 2013. See Section 10.8.4 for more information.

Edgecumbe interconnecting transformers expected end-of-life

2024-2026 The Edgecumbe interconnecting transformers are normally open to reduce generation constraints at Kawerau. See Section 10.10.1 for more information.

Kawerau 110/11 kV supply transformers expected end-of-life, and 11 kV switchgear replacement

2018-2020 Replacing these transformers will affect the 11 kV fault level. See Section 10.10.1 for more information.

All Kinleith 110/11 kV supply transformers expected end-of-life, and 11 kV indoor switchboard replacement


Kinleith T4 supply transformer expected end-of-life

2016-2021 Changing the transformer’s vector group will enable T4 and T5 to operate in parallel. This is one option to provide n-1 security to the 33 kV bus. See Section 10.8.7 for more information.

Owhata supply transformers expected end-of-life, and 11 kV switchgear replacement

2016-2018 2027-2029

Upgrading the transformer’s capacity will resolve the transformer overloading issue. See Section 10.8.10 for more information.

Rotorua110/11 kV supply transformers expected end-of-life

2013-2015 Upgrading the transformer’s capacity will resolve the transformer overloading issue. See Section 10.8.11 for more information.

Tarukenga interconnecting transformers replacement

2013 Committed system development will relieve constraints on 110 kV transmission network between Tarukenga and Arapuni. See Section 10.9.4 for more information.

Te Kaha substation redevelopment 2012-2013 No system issues are identified within the forecast period.

Te Matai T1 supply transformer expected end-of-life

2025-2027 Upgrading the transformer capacity will resolve the transformer overload issue. See Section 10.8.16 for more information.

Waiotahi 110/11 kV supply transformers expected end-of-life

2019-2021 Upgrading the transformer’s capacity will resolve the transformer overloading issue. See Section 10.8.17 for more information.

74




10.6 Future Bay of Plenty projects summary and transmission configuration

Table 10-4 lists projects to be carried out in the Bay of Plenty region within the next 15 years.

Figure 10-4 shows the possible configuration of Bay of Plenty transmission in 2027, with new assets, upgraded assets, and assets undergoing significant maintenance within the forecast period.

Table 10-4: Projects in the Bay of Plenty region up to 2027


Edgecumbe Increase supply transformer protection settings – interim solution. Replace supply transformers with higher-rated units. Replace interconnecting transformers. Convert 33 kV outdoor switchgear to an indoor switchboard.

Base Capex Possible Base Capex Base Capex

Kawerau Increase 220/110 kV transformer capacity. Replace 110/11 kV T1 and T2 supply transformers. Replace 11 kV switchgear.

Proposed Base Capex Base Capex

Kaitimako Install a new 220 kV bus, new two 150 MVA interconnecting transformers, and thermally upgrade and convert Kaitimako–Tarukenga to 220 kV operations. Install a third interconnecting transformer.

Committed Possible

Kinleith Replace 110/11 kV supply transformer. Replace 11 kV indoor switchboard. Replace 110/33 kV T4 supply transformer. Replace 110/33 kV T5 supply transformer with higher-rated unit.


Owhata Replace 110/11 kV supply transformers. Replace 11 kV switchgear.


Papamoa New grid exit point. Possible

Rotorua–Tarukenga

Thermal upgrade the circuit. Possible

Rotorua Replace 110/11 kV supply transformers. Base Capex

Tarukenga Replace 220/110 kV interconnecting transformers. Committed

Tauranga Upgrade 110/11 kV transformers’ branch limiting components Possible

Te Kaha Substation re-development. Base Capex

Te Matai Replace 40 MVA supply transformer. Base Capex

Waiotahi Replace 110/11 kV supply transformer. Base Capex



Figure 10-4: Possible Bay of Plenty transmission configuration in 2027

110 kV110 kV

110 kV

110 kV

110 kV

110 kV

220 kV

220kV

11 kV

11 kV

110 kV

110 kV

110 kV

220 kV

11 kV

11 kV

11 kV

(TASMAN)

110 kV 50 kV

33 kV

33 kV

11 kV

33 kV

11 kV

110 kV

11 kV

Ohakuri

WAIKATO

Atiamuri

Kinleith

WAIKATO

Arapuni

Lichfield

Owhata

Tarukenga

Kaitimako110 kV

Te Matai

Tauranga

Mount Maunganui

Edgecumbe

Waiotahi

Te Kaha

Kawerau

Matahina

11 kV

220 kV33 kV

33 kV

Papamoa

110 kV

Okere

33 kVAniwhenua

110 kV

11 kV 33 kV

Rotorua

Wheao

KEY

NEW ASSETS

UPGRADED ASSETS

ASSETS SCHEDULED

FOR REPLACEMENT

* MINOR UPGRADE

*




Issues Change

Mount Maunganui supply transformer capacity New issue.

10.8 Bay of Plenty transmission capability

Table 10-6 summarises issues involving 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 issues

Section number

Issue

Regional

10.8.1 Kawerau 110 kV generation constraint

10.8.2 Tarukenga interconnecting transformer capacity

10.8.3 Tauranga and Mount Maunganui transmission security


10.8.4 Edgecumbe supply transformer capacity

10.8.5 Kaitimako supply security

10.8.6 Kinleith–Tarukenga 110 kV transmission capacity

10.8.7 Kinleith 110/33 kV supply transformer capacity

10.8.8 Mount Maunganui supply transformer capacity

10.8.9 Okere–Te Matai 110 kV transmission capacity



Section number

Issue

10.8.10 Owhata supply transformer capacity

10.8.11 Rotorua supply transformer capacity

10.8.12 Rotorua transmission security

10.8.13 Tarukenga supply security

10.8.14 Tauranga 11 kV supply transformer capacity


10.8.16 Te Matai supply transformer capacity

10.8.17 Waiotahi supply transformer capacity

10.8.18 Waiotahi and Te Kaha supply security

10.8.1 Kawerau 110 kV generation constraint

Project reference: 110 kV reconfiguration: EDG_MAT-TRAN-DEV-01 Interconnecting transformer: KAW-POW_TFR-DEV-01

Project status/purpose: Proposed, to provide net market benefit

Indicative timing: 110 kV reconfiguration: 2012 Interconnecting transformer: 2014

Indicative cost band: 110 kV reconfiguration: A Interconnecting transformer: B

Issue

Generation at Aniwhenua, Matahina, KAG, embedded generation within Horizon’s distribution network and within the Norske-Skog mill connects to the Kawerau 110 kV bus. The Kawerau 110 kV bus is connected to the rest of the system through:

Kawerau 220/110 kV transformer T12 (100 MVA, 20% impedance)

Kawerau 220/110 kV transformer T13 (100 MVA, 10% impedance), and

low capacity 110 kV circuits (Kawerau–Edgecumbe 1 and 2, each rated at 48/59 MVA, in series with Edgecumbe–Owhata rated at 57/69 MVA).

There is an existing constraint for exporting generation from the Kawerau 110 kV bus under the following situations.

High generation and low demand at Kawerau.

An under frequency event for a Huntly generation trip or loss of the HVDC requiring increased generation and tripping interruptible load.

An outage of a 110 kV Edgecumbe–Kawerau circuit or the 220/110 kV interconnecting transformer.

Norske Skog is commissioning a 25 MW generator in December 2012, connected to the Kawerau 110 kV bus. This will increase the occurrences of generation constraints at Kawerau.

Solution

A grid upgrade proposal75

has been submitted for Commerce Commission approval to replace the Kawerau T12 transformer

76 with a 250 MVA 10% impedance

transformer. If approved, the project is expected to be completed in 2014.

This will relieve existing generation constraints and allow for a small increase in future generation connections at the Kawerau 110 kV bus.

75

http://www.gridnewzealand.co.nz/n4751.html 76

The Kawerau 220/110 kV T12 transformer is 100 MVA, 20% impedance.



We will not be able to replace a transformer before 2014 due to the lead time to procure and install the transformer. As part of our grid upgrade proposal, we will implement an interim grid reconfiguration to relieve constraints until we commission the new transformer. The interim measure is to connect the Kawerau–Matahina 2 circuit directly to the Edgecumbe–Kawerau 2 circuit, bypassing Kawerau to create a single circuit between Matahina and Edgecumbe, and splitting the Matahina bus. The Edgecumbe–Kawerau 1 circuit is open during this period (see Figure 10-5).

Figure 10-5 : Grid reconfiguration to shift one Matahina generator to Edgecumbe

110 kV

110 kV

110 kV

220 kV

220 kV

110 kV

11 kV

11 kV

11 kV

(TASMAN)

33 kV

11 kV

Te Matai Edgecumbe

Waiotahi

Kawerau

Matahina G1

Owhata

Tarukenga

Ohakuri

WAIKATO

Okere

Aniwhenua

110 kV

Matahina G2

110kV CIRCUIT

SUBSTATION BUS

TRANSFORMER

TEE POINT

KEY

220kV CIRCUIT

LOAD

GENERATOR

10.8.2 Tarukenga interconnecting transformer capacity

Project reference: 220/110 kV interconnection: KMO_TRK-TRAN-EHMT-01 Interconnecting transformer: KMO-POW_TFR-DEV-01

Project status/purpose: 220/110 kV interconnection: committed, to meet the Grid Reliability Standard (core grid) Interconnecting transformer: possible, to meet the Grid Reliability Standard (core grid)

Indicative timing: 220/110 kV interconnection: Q4 2012 Interconnecting transformer: 2017

Indicative cost band: 220/110 kV interconnection: D Interconnecting transformer: B

Issue

Two 220/110 kV interconnecting transformers at Tarukenga supply over half of the Bay of Plenty region, including the Tauranga, Mount Maunganui, and Rotorua grid exit points. They provide:



An outage of one interconnecting transformer may cause the other to exceed its n-1 capacity. Operational measures can be taken, such as requiring increased output from embedded hydro generation (assuming water is available) and load restrictions.



Solution

We have a committed project to establish a 220/110 kV interconnection at Kaitimako, so the load at Tauranga and Mount Maunganui is removed from the Tarukenga interconnecting transformer.

The new 220/110 kV interconnection at Kaitimako involves:

thermally upgrading the Kaitimako–Tarukenga circuits and changing the operating voltage from 110 kV to 220 kV

77, and

installing two new 220/110 kV, 150 MVA interconnecting transformers at Kaitimako.

This will also resolve the issue involving overloading of the 110 kV Okere–Te Matai (see Section 10.8.9) beyond the forecast period.

The n-1 capacity of the new interconnection at Kaitimako (due to be commissioned at the end of 2012) is sufficient until 2017. The proposed new grid exit point at Papamoa (see Section 10.9.1) will further defer the Kaitimato interconnecting transformers overload issue until 2018. Operational measures, such as requiring increased output from embedded hydro generation (assuming water is available) and load restrictions, may defer the overload for another few years. In the longer-term, a third interconnecting transformer is likely to be required at Kaitimako.

10.8.3 Tauranga and Mount Maunganui transmission security

Project reference: PPM-SUBEST-DEV-01




Issue

Tauranga and Mount Maunganui are supplied from Kaitimako through the following 110 kV circuits (see Figure 10-6):

Kaitimako–Tauranga 1, rated at 96/105 MVA (summer/winter)

Kaitimako–Mount Maunganui 1, rated at 63/77 MVA (summer/winter), and

a shared Kaitimako–Tauranga–Mount Maunganui 2 circuit with the following ratings.

Kaitimako–Poike section 96/105 MVA (summer/winter).

Poike–Tauranga section 96/105 MVA (summer/winter).

Poike–Mount Maunganui 63/77 MVA (summer/winter).

77

The Kaitimako–Tarukenga circuits are constructed at 220 kV, but operated at 110 kV.



Figure 10-6: Kaitimako grid configuration

110 kV

110 kV

Mount Maunganui

Te Matai

Tarukenga

110 kV

Kaitimako

Okere

Tauranga

110 kV 110 kV

110 kV

110 kV

Edgecumbe

Owhata

Poike

For Tauranga and Mount Maunganui security, an outage of the Kaitimako–Tauranga 1 circuit during peak load periods will cause the Kaitimako–Poike circuit section to overload from 2013. This assumes Kaimai (Tauranga) is generating 14 MW.

In addition, an outage of a Kaitimako–Mount Maunganui circuit or a Mount Maunganui–Poike circuit section will overload the other circuit from 2017.

For Tauranga, an outage of the Kaitimako–Tauranga circuit or the Poike–Tauranga circuit section will overload the other circuit from 2020.

Solution

The overloading of the Kaitimako–Poike circuit section is addressed by an existing special protection scheme, which will reconfigure the Kaitimako–Tauranga–Mount Maunganui 2 circuit at Tauranga or Mount Maunganui to remove the overload. This addresses the issue only until the load at Mount Maunganui and Tauranga exceeds the rating of the Kaitimako–Mount Maunganui (2017) and Kaitimako–Tauranga circuits (2020).

We will discuss options to address the Tauranga security issue with Powerco, which include:

transferring more load from Tauranga to the new Kaitimako grid exit point, and

short-term operational measures to limit the Tauranga load and/or constrain-on generation at Kaimai.


The Mount Maunganui security issue is addressed by:

transferring load from Mount Maunganui to a proposed new Papamoa grid exit point (see Section 10.9.1), and

operational measures (if required in the short term) to limit the Mount Maunganui load.

Land will need to be acquired for the new grid exit point at Papamoa.



10.8.4 Edgecumbe supply transformer capacity

Project reference: Upgrade protection: EDG-POW_TFR_PTN-EHMT-01 Upgrade transformer: EDG-POW_TFR-EHMT-01

Project status/purpose: Upgrade protection: Base Capex, minor enhancement Upgrade transformer: possible, customer-specific

Indicative timing: Upgrade protection: 2013 Upgrade transformer: to be advised

Indicative cost band: Upgrade protection: A Upgrade transformer: C

Issue

Two 220/33 kV transformers supply Edgecumbe’s load, providing:



(summer/winter).

The peak load at Edgecumbe is forecast to exceed the transformers’ n-1 winter capacity by approximately 9 MW in 2012, increasing to approximately 43 MW in 2027 (see Table 10-7).

Table 10-7: Edgecumbe supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Edgecumbe 0.96 9 11 14 16 19 21 27 31 35 40 43

Solution

Resolving the protection limit will delay the overload issue until 2013. We will discuss with Horizon Energy future supply options, which involve:

limiting the load or transferring some load to another grid exit point in the short term, and

replacing the existing transformers with higher-rated units in the long term.

We will also convert the Edgecumbe 33 kV outdoor switchgear to an indoor switchboard within the next five years, and raise the protection limit in conjunction with the conversion work.

In addition, the two supply transformers will approach their expected end-of-life at the end of the forecast period. Any future transformer upgrade will be customer driven.

10.8.5 Kaitimako supply security


Issue

A single 110/33 kV, 75 MVA transformer supplies load at Kaitimako resulting in no n-1 security. Some of the 33 kV Tauranga load will be shifted to Kaitimako, which is forecast to grow to 47 MW by 2027 (see also Section 10.8.3).

Solution

The lack of n-1 security can be managed operationally by transferring load to Tauranga.

78

The transformers’ capacity is limited by protection settings; with this limit resolved, the n-1 capacity will be 62/67 MVA (summer/winter).



10.8.6 Kinleith–Tarukenga 110 kV transmission capacity


The 110 kV Kinleith–Tarukenga 1 and 2 circuits are rated at 51/62 MVA and 63/77 MVA (summer/winter), respectively. These circuits may overload during low Arapuni and/or Upper North Island generation, if either of the following circuits is out of service:

220 kV Hamilton–Whakamaru, or

110 kV Kinleith–Lichfield–Tarukenga.

Solution

This issue is managed with the Arapuni bus split and generation limits at Arapuni. This issue will be alleviated by the following committed projects.

The North Island Grid Upgrade.

The Wairakei–Whakamaru C line.

The Tarukenga interconnecting transformer replacement.

These measures will relieve but not eliminate the constraints on the Kinleith–Taruekenga circuits. Operational measures can be used to manage the constraints for the forecast period and beyond.

10.8.7 Kinleith 110/33 kV supply transformer capacity

Project reference: KIN-POW_TFR-EHMT-01




Issue

Two 110/33 kV transformers (rated at 20 MVA and 30 MVA) supply Kinleith’s 33 kV load, providing:



These supply transformers cannot be connected to the 33 kV bus at the same time, due to different vector groups.

The peak 33 kV load at Kinleith is forecast to exceed the transformers’ n-1 winter capacity by approximately 4 MW in 2012, increasing to approximately 12 MW in 2027 (see Table 10-8).

Table 10-8: Kinleith 33 kV supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Kinleith 33 kV 0.98 4 4 5 5 6 7 8 9 10 11 12

Solution

We are discussing options with Powerco and Carter Holt Harvey. One possible option 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 five years. The appropriate rating and vector group for the replacement transformer will also be considered, in conjunction with the replacement work. Any future transformer upgrade will be customer driven.



10.8.8 Mount Maunganui supply transformer capacity


Issue

Two 110/33 kV transformers supply Mount Maunganui’s load, providing:




The peak load at Mount Maunganui is forecast to exceed the transformers’ n-1 winter capacity by approximately 4 MW in 2019, increasing to approximately 19 MW in 2027 (see Table 10-9).

Table 10-9: Mount Maunganui supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Mount Maunganui

0.98 0 0 0 0 0 0 4 9 12 16 19

Solution

The transmission capacity into Mount Maunganui is limited to approximately 75 MW by the rating of the Kaitimako–Mount Maunganui circuit (see Section 10.8.3). This constraint will be addressed by transferring load from Mount Maunganui to a proposed new grid exit point at Papamoa (see Section 10.9.1 for more information).

10.8.9 Okere–Te Matai 110 kV transmission capacity


Issue

The Western Bay of Plenty area of Kaitimako, Mount Maunganui, Tauranga and Te Matai are supplied via three 110 kV circuits:

two 110 kV Kaitimako–Tarukenga circuits, and

one 110 kV Okere–Te Matai–Kaitimako circuit.

During periods of high demand, an outage of one Kaitimako–Tarukenga circuit can overload the Okere–Te Matai circuit. The establishment of a new grid exit point at Papamoa (see Section 10.9.1 for more information) will increase the loading on the Okere–Te Matai circuit.

Solution

The committed project to increase the operating voltage of the Kaitimako–Tarukenga circuits from 110 kV to 220 kV (see Section 10.8.2 for more information) will alleviate the overloading issue on the Okere–Te Matai circuit until 2023. With a third interconnecting transformer at Kaitimako the overloading will be alleviated for the forecast period and beyond.

10.8.10 Owhata supply transformer capacity

Project reference: OWH-POW_TFR-EHMT-01


79

The transformers’ capacity is limited by the protection limit; with this limit resolved, the n-1 capacity will be 87/98 MVA (summer/winter).





Issue

Two 110/11 kV transformers supply Owhata’s load, providing:



The peak load at Owhata is forecast to exceed the transformers’ n-1 winter capacity by approximately 5 MW in 2012, increasing to approximately 9 MW in 2027 (see Table 10-10).

Table 10-10: Owhata supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Owhata 0.99 5 5 5 6 6 7 7 8 8 9 9

Solution

Presently, operational measures can be taken to prevent transformer overloads in the event of a transformer failure.

In the short term, Unison has a number of smart grid projects underway to increase load shifting between Owhata and Rotorua. Shifting load from Rotorua to Owhata will also reduce loading on the 110 kV Rotorua–Tarukenga circuits (see Section 10.8.12).

Unison is reconfiguring its distribution system, and discussing options with us (see Section 10.9.5). Unison plans to add a 33 kV connection point at Owhata within the forecast period. Three options to replace the existing transformers are being considered for longer-term supply at Owhata, which involve:

two higher-rated 110/11 kV transformers followed by two 110/33 kV transformers

two 110/33/11 kV transformers, or

one 110/33 kV, one 110/11 kV and one 33/11 kV transformer.

Additionally, the 110/11 kV supply transformers at Owhata will approach their expected end-of-life within the next 5-10 years. We are discussing with Unison the rating and timing for these replacement transformers.

We do not anticipate any property issues, as the transformer replacement work can be carried out within the existing substation boundary.

10.8.11 Rotorua supply transformer capacity

Project reference: ROT-POW_TFR-EHMT-01




Issue

Two 110/11 kV transformers supply Rotorua’s 11 kV load, providing:





The peak load at Rotorua is forecast to exceed the transformers’ n-1 winter capacity by approximately 10 MW in 2012, increasing to approximately 14 MW in 2027 (see Table 10-11).

Table 10-11: Rotorua supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Rotorua 0.97 10 10 11 11 11 11 12 13 13 14 14

There are also two 110/33 kV supply transformers supplying the 33 kV load at Rotorua providing:

a total nominal capacity of 120 MVA, and



The Rotorua 33 kV peak load is not forecast to exceed the 110/33 kV transformers’ capacity for the duration of the forecast period.

Solution

We are discussing future supply options with Unison (see Section 10.9.5), which includes increasing the 110/11 kV supply transformer capacities.

Unison also advises that:

load can be transferred within its network to Tarukenga and Owhata following a 110/11 kV transformer failure, and

it is investigating options to transfer some of the existing 11 kV load to the 33 kV bus and Owhata.

In addition, the 110/11 kV supply transformers at Rotorua are approaching their expected end-of-life within the next five years.

We do not anticipate any property issues, as the transformer replacement work can be carried out within the existing substation boundary.

10.8.12 Rotorua transmission security

Project reference: ROT_TRK-TRAN-EHMT-01




Issue

The 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 some of the Rotorua load is connected to the 110 kV Rotorua–Tarukenga 2 circuit, and

majority of Rotorua’s load is supplied from the 110 kV Rotorua–Tarukenga 1 circuit.

Outage of the 110 kV Rotorua–Tarukenga 2 circuit:

results in the loss of Wheao generation, and

overloads the remaining 110 kV Rotorua–Tarukenga 1 circuit (as it supplies all Rotorua’s load).

80

The transformers’ capacity is limited by the protection limit; with this limit resolved, the n-1 capacity will be 68/71 MVA (summer/winter).



Outage of the 110 kV Rotorua–Tarukenga 1 circuit results in a loss of supply to the entire Rotorua 11 kV load.

Solution

We are discussing with Unison (the local lines company) and Trustpower (owner of the embedded generation connecting at Rotorua) future supply options, which include:

in the short term, transferring load within Unison’s network to Tarukenga and Owhata to reduce the Rotorua load to within the capacity of the 110 kV Rotorua–Tarukenga circuits, and/or

in the long term, thermally upgrading the existing 110 kV Rotorua–Tarukenga circuits to 90/100 MVA (summer/winter), which may require easements over some parts of the line.

Unison is considering moving a substantial amount of load from Rotorua to Owhata, which may defer the 110 kV Rotorua–Tarukenga circuit upgrades. Reducing the 11 kV load and reconfiguring the Rotorua 110 kV bus will prevent the total loss of supply for the 11 kV load. Future investment will be customer driven.

10.8.13 Tarukenga supply security


Issue

A single 110/11 kV, 20 MVA supply transformer supplies Tarukenga’s load resulting in no n-1 security. Tarukenga’s peak load is forecast to grow to 15 MW by 2027.

Unison can backfeed this load from the Rotorua 11 kV bus if required.

Solution

The lack of n-1 security can be managed operationally.



Issue

Two 110/11 kV transformers supply Tauranga’s 11 kV load, providing:



(summer/winter).

The peak load on the Tauranga 11 kV bus is forecast to:

exceed the transformers’ n-1 winter capacity by approximately 3 MW in 2012

not exceed the transformers’ n-1 winter capacity from 2014 to 2016 following 5 MW of load shifting to Kaitimako in 2014, and

exceed the transformers’ n-1 winter capacity by approximately 8 MW in 2027 (see Table 10-12).

81

The transformers’ capacity is limited by low voltage cables, protection limits, and the series reactors; with these limits resolved, the n-1 capacity will be 45/45 MVA (summer/winter).



Table 10-12: Tauranga 11 kV supply transformer overload forecast




2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Tauranga 11 kV 0.99 3 3 0 0 0 1 2 4 5 6 8

Solution

A 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 limit82

will provide sufficient n-1 capacity to meet the load growth within the forecast period.




Issue

Two 110/33 kV transformers (rated at 120 MVA and 90 MVA) supply Tauranga’s 33 kV load, providing:




The peak load on the Tauranga 33 kV bus is forecast to exceed the transformers’ n-1 winter capacity by approximately 1 MW in 2017, increasing to approximately 20 MW in 2027 (see Table 10-13). This overload forecast assumes that there is at least 14 MW of Kaimai (Tauranga) generation.

Table 10-13: Tauranga 33 kV supply transformer overload forecast




2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Tauranga 33 kV 0.95 0 0 0 0 0 1 6 10 13 17 20

Solution

The branch limits on the 120 MVA supply transformer are temporary. Those limits will be removed on completion of the 33 kV indoor switchboard project, ensuring the Tauranga 33 kV load has n-1 capacity for the forecast period and beyond.

10.8.16 Te Matai supply transformer capacity


Issue

Two 110/33 kV transformers (rated at 30 MVA and 40 MVA) supply Te Matai’s load, providing:


82

Resolving the low voltage cables and protection limits will increase the n-1 capacity to 40/40 MVA (summer/winter), which is the limit of the series reactors. This is sufficient to meet the load within the forecast period.

83 The 120 MVA transformers’ capacity is limited by low voltage switchgear; with this limit resolved, the

n-1 capacity will be 75/75 MVA (summer/winter) which is the LV cable limit.




The peak load at Te Matai is forecast to

exceed the transformers’ n-1 winter capacity by approximately 1 MW in 2014

not exceed the transformers’ n-1 winter capacity from 2015 to 2018 following 5 MW of load shifting to the proposed new grid exit point at Papamoa, and

exceed the transformers’ n-1 winter capacity by approximately 8 MW in 2027 (see Table 10-14).

Table 10-14: Te Matai supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Te Matai 0.96 0 0 1 0 0 0 1 3 5 6 8

Solution

Powerco can transfer some more of its load to a new grid exit point at Papamoa (see also Section 10.9.1) ensuring Te Matai has n-1 security for the forecast period and beyond.

In addition, the Te Matai 30 MVA supply transformer will approach its expected end-of-life at the end of the forecast period. We will discuss with Powerco the timing and rating of the replacement transformer. Future investment will be customer driven.

10.8.17 Waiotahi supply transformer capacity

Project status/purpsoe: This issue is for information only

Issue

Two 110/11 kV transformers supply Waiotahi’s load, providing:



The transformers also supply Te Kaha’s load via an 11/50 kV step-up transformer at Waiotahi. The combined peak load at Waiotahi is forecast to exceed the transformers’ n-1 winter capacity by approximately 1 MW in 2012, increasing to 6 MW in 2027 (see Table 10-15).

Table 10-15: Waiotahi supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Waiotahi (and Te Kaha)

0.98 1 2 2 2 2 3 3 4 4 5 6

Solution

We will discuss with Horizon Energy options to increase the transformer capacity. Additionally, the 110/11 kV supply transformers at Waiotahi will approach their expected end-of-life within the next 5-10 years. We will discuss with Horizon Energy the rating and timing for these replacement transformers.

We do not anticipate any property issues as the transformer replacement work can be carried out within the existing substation boundary.




10.8.18 Waiotahi and Te Kaha supply security


Issue

Waiotahi and Te Kaha are supplied by one transmission circuit (a 110 kV circuit to Waiotahi and a 50 kV circuit to Te Kaha) resulting in no n-1 security.

Both loads are supplied from the Edgecumbe 110 kV bus via the single Edgecumbe–Waiotahi circuit, with the:

Waiotahi 11 kV load supplied through two 10 MVA transformers, and

Te Kaha 11 kV load supplied through one:

3 MVA 11/50 kV step up transformer at Waiotahi

50 kV Te Kaha–Waiotahi circuit, and

2.25 MVA 50/11 kV transformer at Te Kaha.

Solution

The lack of n-1 security can be managed operationally.


10.9.1 Papamoa grid exit point

We are discussing with Powerco the establishment of a new grid exit point at Papamoa, connected to the 110 kV Kaitimako–Te Matai circuit. The new grid exit point is to cater for load growth, which is predominantly supplied from Mount Maunganui (see also Section 10.8.3). It will also allow some load to be transferred from Te Matai (see also Section 10.8.16).

Papamoa will increase the loading on the 110 kV Tarukenga–Okere–Te Matai–Kaitimako circuits. This will bring forward the need to upgrade these circuits, but does not create significant new issues. This issue does not arise within the forecast period once the new 220/110 kV interconnection at Kaitimako is commissioned.

10.9.2 Kawerau–Matahina 110 kV transmission capacity

The 110 kV Kawerau–Matahina line comprises two circuits each rated at 88/98 MVA (summer/winter). This line carries the entire generation output of the Matahina and Aniwhenua generation stations to Kawerau.

The generation stations’ combined capacity is 97 MW. Given the outage of one of the Kawerau–Matahina circuits, generation can be managed operationally. Some of Aniwhenua’s generation is used to supply the Galatea system that is configured as an embedded network behind Matahina.

During a contingency, generation at Matahina and Aniwhenua can be restricted to the remaining circuit’s available capacity. This situation is considered satisfactory, and there are no plans to make transmission network changes at this stage.

10.9.3 Kaitimako transmission security

Kaitimako is supplied by (see Figure 10-6):

two direct circuits, Kaitimako–Tarukenga 1 and 2, and

one indirect circuit, Tarukenga–Okere–Te Matai–Kaitimako.

Kaitimako also supplies Mount Maunganui and Tauranga (see Section 10.8.3).



Following the outage of any of the Kaitimako–Tarukenga circuits during peak load periods, it may not be possible to ensure circuit ratings and bus voltages stay within their required limits should there be another outage. In this case, a system split is required to mitigate the constraints. This situation still applies even after the conversion of the Kaitimako–Tarukenga circuits from 110 kV to 220 kV operation (see Section 10.8.2).

10.9.4 Tarukenga interconnecting transformer replacement

The Tarukenga interconnecting transformers require replacement due to their condition. We are replacing the existing 200 MVA 5% and 3.6% impedance transformers with two 150 MVA 15% impedance transformers.

The transformer capacity reduction is possible because the Western Bay of Plenty is being transferred to 220 kV by the Kaitimako–Tarukenga circuits’ upgrade to 220 kV operation (see Section 10.8.2). The increase in impedance helps to reduce the through-transmission in the 110 kV transmission network towards Kinleith (see Section 10.8.6).

10.9.5 Rotorua area development plan

We are working with Unison to develop a long-term plan for supplying load in the Rotorua area. The plan will determine the most economic combination of long-term solutions to the following issues.

Owhata supply transformer capacity (see Section 10.8.10)

Rotorua supply transformer capacity (see Section 10.8.11)

Rotorua supply transmission security (see Section 10.8.12)

Tarukenga supply security (see Section 10.8.13).

10.10 Bay of Plenty generation proposals and opportunities



84

10.10.1 Generation connection at Kawerau

The existing constraints on 110 kV generation are discussed in Section 10.8.1. There are also a number of other future generation connection proposals at Kawerau, as the area has significant geothermal resources. If these generation connections eventuate, then the likely system developments will involve:

replacing the Kawerau T13 transformer (220/110 kV, 100 MVA) with a 250 MVA transformer

splitting the 110 kV Kawerau–Edgecumbe circuits, and

replacing the Edgecumbe 220/110 kV transformers and returning them to service.

In addition, increased generation at Kawerau may increase the 11 kV supply bus and distribution system fault levels sufficiently to exceed their fault-level capacities. This particularly applies if new generation is connected directly to the supply bus, and may also be an issue if the generation is embedded within the distribution system. This

84




may require the replacement of the existing supply transformers with higher-impedance transformers and/or replacement of the existing 11 kV switchboard.

We are currently in discussions with Horizon Energy regarding the 11 kV fault level issue. The 11 kV switchboard and the 110/11 kV supply transformers at Kawerau are due for replacement within the next 10 years (see Section 10.5). We will consider options to reduce the 11 kV fault level when the equipment is due for replacement.

10.10.2 Generation connection to the Okere–Te Matai circuit

Some generation prospects exist close to the 110 kV Okere–Te Matai circuit, or close to Okere on one of the other circuits passing through the area. These circuits can become highly loaded for some circuit outages when there is high demand. Under these conditions, the generation may need to be reduced or switched off.

The committed project to increase the operating voltage of the Kaitimako–Tarukenga circuits (see Section 10.8.2) will reduce the extent and duration of this issue.

Chapter 11: Central North Island Region


11 Central North Island Regional Plan


11.2 Central North Island transmission system

11.3 Central North Island demand

11.4 Central North Island generation

11.5 Central North Island significant maintenance work

11.6 Future Central North Island projects and transmission configuration


11.8 Central North Island transmission capability


11.10 Central North Island generation proposals and opportunities


This chapter details the Central North Island regional transmission plan. We base this regional plan on an assessment of available data, and welcome feedback to improve its value to all stakeholders.

Figure 11-1: Central North Island region



The Central North Island region includes a mix of small to large sized towns together with the large load at Palmerston North and environs (supplied from Bunnythorpe and Linton). There is also a large industrial load at Tangiwai.

We have assessed the Central North Island region’s transmission needs over the next 15 years while considering longer-term development opportunities. Specifically, the transmission network needs to be flexible to respond to a range of future service and technology possibilities, taking into consideration:


forecast demand

forecast generation



11.2 Central North Island transmission system

This section highlights the state of the Central North Island regional transmission network. The existing transmission network is set out geographically in Figure 11-1 and schematically in Figure 11-2.

Figure 11-2: Central North Island transmission schematic

110 kV

Paraparaumu

110 kV

220 kV

Haywards Wilton

220 kV

220 kV

220 kV

110 kV

110 kV

110 kV110kV CIRCUIT

33kV CIRCUIT

SUBSTATION BUS

TRANSFORMER

TEE POINT

KEY

220kV CIRCUIT

LOAD

CAPACITOR

110 kV

110 kV

110 kV

110 kV

110 kV

110 kV

33 kV

33 kV

55 kV

(NZR)

33 kV

11 kV

11 kV

33 kV

11 kV

55kV

(NZR)

33 kV

33 kV

33 kV

11 kV

33 kV

Brunswick

Ongarue

TARANAKI

Wanganui

Marton

WAIKATO

Hangatiki Whakamaru

HAWKES BAY

Fernhill

National Park

Ohakune

Mataroa

Bunnythorpe

Linton

Mangahao

WELLINGTON WELLINGTON

Masterton

Mangamaire

33 kV

Woodville

Dannevirke

Waipawa

RangipoTokaanu

Tangiwai

220 kV

220 kV

RedclyffeWhirinaki

Wairakei

Aratiatia

Poihipi

220 kV

33 kV

WAIKATO

Tararua

11 kV

220 kV

Ohaaki11 kV

33 kV

Purua

GENERATOR

Nga Awa

Te Apiti

Ohakuri


The Central North Island region comprises 220 kV and 110 kV transmission circuits with interconnecting transformers located at Bunnythorpe. All the 220 kV circuits form part of the grid backbone. The 110 kV transmission network is mainly supplied through the 220/110 kV interconnecting transformers at Bunnythorpe, plus low capacity connections to other regions.



The Central North Island region is a main corridor for 220 kV transmission circuits through the North Island. The 220 kV transmission system connects Bunnythorpe from 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. The direction of power flow through the region, north or south, is set by generation and loads outside the region.

Most of the Central North Island’s generation capacity is connected to the 220 kV and is significantly in excess of the local demand. Surplus generation is exported over the National Grid to other demand centres.


The 110 kV transmission system within the Central North Island region mainly consists of low-capacity circuits. The transmission system may impose constraints under certain operating conditions. Operational measures taken to ensure the 110 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 following 110 kV circuits:

Bunnythorpe–Woodville

those between Bunnythorpe and Arapuni (Waikato region), and

those between Bunnythorpe and Stratford (Taranaki region).


Longer-term development plans are being formed as part of the Lower North Island investigation.

The transmission development in this region will largely depend on the magnitude and location of future generation, and the commissioning of new generation in the region may bring forward the need for transmission investment. Possible upgrades include duplexing the existing 220 kV lines, and rebuilding some of the 110 kV lines for 220 kV operation.

11.3 Central North Island demand

The after diversity maximum demand (ADMD) for the Central North Island region is forecast to grow on average by 1.1% annually over the next 15 years, from 347 MW in 2012 to 408 MW by 2027. This is lower than the national average demand growth of 1.7% annually.


85) for the Central North Island region. The forecasts are

derived using historical data, and modified to account for customer information, where appropriate. The power factor at each grid exit point is also derived from historical data, and is used to calculate the real power capacity for power transformer and transmission line. See Chapter 4 for more information about demand forecasting.

85




Figure 11-3: Central North Island region after diversity maximum demand forecast


Table 11-1: Forecast annual peak demand (MW) at Central North Island grid exit points to 2027


Peak demand (MW)


2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Bunnythorpe 33 kV

0.98 110 112 114 117 119 121 126 131 135 139 142

Bunnythorpe NZR

0.80 8 8 8 8 8 8 8 8 8 8 8

Dannevirke 0.97 15 15 16 16 16 17 17 18 19 19 19

Linton 0.99 75 77 78 80 81 83 86 89 92 95 97

Mangamaire 0.97 12 12 13 13 13 13 14 14 15 15 16

Mangahao 0.97 39 40 41 41 42 43 45 46 48 49 50

Marton 0.98 16 16 17 17 17 18 18 19 20 20 21

Mataroa 0.98 8 8 8 9 9 9 9 10 10 10 10

National Park 0.97 8 8 8 8 8 8 8 9 9 9 9

Ohaaki 0.96 6 6 6 6 6 6 7 7 7 7 7

Ohakune1 0.98 11 11 9 10 10 10 11 11 12 12 13

Ongarue 0.98 11 11 11 11 11 11 11 12 12 12 12

Tokaanu 0.99 11 11 11 11 11 11 12 12 12 13 13

Tangiwai 11 kV1 0.99 44 44 47 47 48 48 49 50 51 52 53

Tangiwai NZR 0.80 10 10 10 10 10 10 10 10 10 10 10

Woodville 0.98 4 4 4 4 5 5 5 5 5 5 6

Waipawa 0.96 22 23 23 24 24 25 26 27 27 28 29

Wairakei 0.90 50 51 52 53 54 55 57 60 61 63 64

1. The customer advised a 2 MW load shift from Ohakune to Tangiwai 11 kV planned for 2014.

200

250

300

350

400

450

500

1997 1999 2001 2003 2005 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027

Load (MW) Central North Island

2011 APR Forecast

2012 APR Forecast

Actual Peak



11.4 Central North Island generation

The Central North Island’s generation capacity is 1,252 MW, increasing to 1,528 MW after the commissioning of Ngatamariki and Te Mihi geothermal power plants. This generation contributes a significant portion of the total North Island generation and exceeds local demand. Surplus generation is exported over the National Grid to other demand centres.

Table 11-2 lists the generation forecast for each grid injection point for the forecast period, as required for the Grid Reliability Report. This includes all known and committed generation stations including those embedded within the relevant local lines company’s network (Powerco, The Lines Company, Scanpower, Centralines, Electra).

86

Table 11-2: Forecast annual generation capacity (MW) at Central North Island grid injection points to 2027 (including existing and committed generation)




2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Aratiatia 78 78 78 78 78 78 78 78 78 78 78

Bunnythorpe (Tararua Wind Stage 2)

36 36 36 36 36 36 36 36 36 36 36

Linton (Tararua Wind Stage 1)

32 32 32 32 32 32 32 32 32 32 32

Linton (Totara Road) 1 1 1 1 1 1 1 1 1 1 1

Mangahao 37 37 37 37 37 37 37 37 37 37 37

Nga Awa Purua 140 140 140 140 140 140 140 140 140 140 140

Nga Awa Purua - Ngatamariki

0 82 82 82 82 82 82 82 82 82 82

Ohaaki 46 46 46 46 46 46 46 46 46 46 46

Ongarue (Mokauiti, Kuratau and Wairere Falls)

13 13 13 13 13 13 13 13 13 13 13

Poihipi 51 51 51 51 51 51 51 51 51 51 51

Rangipo 120 120 120 120 120 120 120 120 120 120 120

Tararua Wind Central (Tararua Stage 3)

93 93 93 93 93 93 93 93 93 93 93

Tararua Wind Central (Te Rere Hau)

49 49 49 49 49 49 49 49 49 49 49

Te Mihi 0 0 166 166 166 166 166 166 166 166 166

Tokaanu 240 240 240 240 240 240 240 240 240 240 240

Wairakei1 161 161 109 109 109 109 109 109 109 109 109

Wairakei (Hinemaiaia) 7 7 7 7 7 7 7 7 7 7 7

Wairakei (Rotokawa) 35 35 35 35 35 35 35 35 35 35 35

Wairakei (Te Huka) 23 23 23 23 23 23 23 23 23 23 23

Woodville - Te Apiti 90 90 90 90 90 90 90 90 90 90 90

1. Contact has indicated that Wairakei generation will eventually be phased out by 2026.

86




11.5 Central North Island significant maintenance work


87 proposed for the Central North Island region

for the next 15 years that may significantly impact related system issues or connected parties.




Bunnythorpe interconnecting transformers expected end-of-life

2014-2016 The options for the replacement transformers are under investigation. See Section 11.8.1 for more information.

Bunnythorpe 33 kV outdoor to indoor conversion


Linton 33 kV outdoor to indoor conversion

2017-2019 The forecast load at Linton will exceed the transformers’ capacity from 2015. See Section 11.8.5 for more information.

Mangahao supply transformers expected end-of-life, and 33 kV outdoor to indoor conversion

2020-2022

2014-2016

Managing Mangahao generation can reduce the transformer’s loading. See Section 11.8.6 for more information.

Marton supply transformers expected end-of-life

2023-2026 The forecast load will exceed the transformers’ capacity from 2023. See Section 11.8.7 for more information.

Mataroa supply transformer expected end-of-life

2016-2018 No n-1 security at Mataroa. See Section 11.8.8 for more information.

National Park supply transformer expected end-of-life

2013-2015 No n-1 security at National Park. See Section 11.8.9 for more information.

Ohakune supply transformer expected end-of-life

2012-2014 The discussion on options to increase the supply security and transformer capacity is underway. See Section 11.8.10 for more information.

Ongarue 33kV supply transformer expected end-of-life, and Ongarue 33 kV outdoor to indoor conversion

2025-2026

2017-2019

No n-1 security at Ongarue. See Section 11.8.11 for more information.

Wairakei supply transformers expected end-of-life


11.6 Future Central North Island projects and transmission configuration

Table 11-4 lists projects to be carried out in the Central North Island region within the next 15 years.

Figure 11-4 shows the possible configuration of Central North Island transmission in 2027, with new assets, upgraded assets, and assets undergoing significant maintenance within the forecast period.

Table 11-4: Projects in the Central North Island region up to 2027


Bunnythorpe Replace existing interconnecting transformers with two 150 MVA units. Convert 33 kV outdoor switchgear to an indoor switchboard.


Bunnythorpe–Haywards Bunnythorpe–Haywards A and B reconductoring. Preferred

Bunnythorpe–Mataroa Install series reactor or phase shifting transformer. Possible

Bunnythorpe–Woodville Install special protection scheme, or reconductor Possible

87





Bunnythorpe–Woodville circuit or convert the circuit’s operating voltage.

Linton Convert 33 kV outdoor switchgear to an indoor switchboard. Base Capex

Mangahao Replace supply transformers. Convert 33 kV outdoor switchgear to an indoor switchboard.


Marton Resolve supply transformers’ metering and protection limits. Replace supply transformers.


Mataroa Replace supply transformer. Base Capex

National Park Replace supply transformer. Base Capex

Ohakune Replace supply transformer. Base Capex

Ongarue Replace supply transformer. Convert 33 kV outdoor switchgear to an indoor switchboard.


Tangiwai Replace 11 kV switchgear. Base Capex

Haywards–Bunnythorpe–Tokaanu–Whakamaru

Increase the transmission circuit capacities. Possible

Waipawa Resolve supply transformers’ metering and protection limits. Base Capex

Wairakei Replace supply transformers. Base Capex

Wairakei–Whakamaru Build a new 220 kV double circuit transmission line and dismantle the existing 220 kV Wairakei–Whakamaru B single circuit transmission line.

Committed

Figure 11-4: Possible Central North Island transmission configuration in 2027

110 kV

220 kV

Haywards Wilton

220 kV

220 kV

220 kV

110 kV

110 kV

110 kV

110 kV

110 kV

110 kV

33 kV

55 kV

(NZR)

33 kV

11 kV

11 kV

55kV

(NZR)

33 kV

33 kV

33 kV

11 kV

33 kV

Brunswick

Ongarue

TARANAKI

Wanganui

Marton

WAIKATOHangatiki Whakamaru

HAWKES BAY

National Park

Ohakune

Mataroa

Bunnythorpe

Linton

Mangahao

WELLINGTON WELLINGTON

Masterton

Woodville

Rangipo

Tokaanu

Tangiwai

220 kV220 kV

RedclyffeWhirinaki

Ohakuri

Wairakei

Aratiatia

Poihipi

220 kV

(1) The transmission backbone section

identifies two possible development

paths for the lower North Island:

- upgrade the existing lines, and


Although this diagram shows upgrading

of the existing lines, it is not intended to

indicate a preference as both options

are still being investigated.

33 kV

WAIKATO

Tararua

220 kV

Ohaaki

11 kV

33 kVNga Awa

110 kV

110 kV

11 kV

33 kV

Fernhill

Dannevirke

Waipawa

11 kV

110 kV

Mangamaire

33 kV

110 kV

Paraparaumu

33 kV

Purua

Te Apiti

KEY

NEW ASSETS

UPGRADED ASSETS

ASSETS SCHEDULED

FOR REPLACEMENT

* MINOR UPGRADE

*

*

(1)

Ngatamariki

Te Mihi

(1)






Issues Change

Linton supply transformer capacity New issue.

Marton supply transformer capacity New issue.

Ohaaki supply security Removed. These assets have been transferred to Unison.

Waipawa supply transformer capacity New issue.

Woodville supply security Removed. Project to replace 4.5 MVA transformer with two 10 MVA transformers completed.

11.8 Central North Island transmission capability

Table 11-6 summarises issues involving the Central North Island region for the next 15 years. For more information about a particular issue, refer to the listed section number.

Table 11-6: Central North Island region transmission issues

Section number

Issue

Regional

11.8.1 Bunnythorpe interconnecting transformer capacity

11.8.2 Bunnythorpe–Mataroa 110 kV transmission capacity

11.8.3 Bunnythorpe–Woodville 110 kV transmission capacity


11.8.4 Bunnythorpe supply transformer capacity

11.8.5 Linton supply transformer capacity

11.8.6 Mangahao supply transformer capacity

11.8.7 Marton supply transformer capacity

11.8.8 Mataroa supply transformer security

11.8.9 National Park transmission and supply transformer security

11.8.10 Ohakune supply transformer security and capacity

11.8.11 Ongarue supply transformer security

11.8.12 Tokaanu supply transformer security

11.8.13 Waipawa supply transformer capacity and security

11.8.1 Bunnythorpe interconnecting transformer capacity

Project reference: BPE-POW_TFR-EHMT-01

Project status/purpose: Possible, to meet the Grid Reliability Standard (core grid).



Issue

There are three interconnecting transformers at Bunnythorpe, each rated at 50 MVA, providing:



Loading on the Bunnythorpe interconnecting transformers may exceed their n-1 capacity for high Central North Island and Wellington loads, coupled with low local generation in Wellington.



Solution

This issue can be managed operationally by constraining-on Mangahao generation.

The Bunnythorpe interconnecting transformers have an expected end-of-life within the forecast period. They will be replaced by two 150 MVA transformers.

11.8.2 Bunnythorpe–Mataroa 110 kV transmission capacity

Project reference: BPE_MTR–TRAN-EHMT-01

Project status/purpose: Possible, to meet the Grid Reliability Standard (not core grid). This project is part of the lower North Island transmission capacity investigation and we anticipate seeking approval from the Commerce Commission in 2013



Issue

The Bunnythorpe–Mataroa single circuit is rated at 57/70 MVA (summer/winter). This circuit can overload for some generation dispatch patterns such as high HVDC north power flow, high wind generation in the lower North Island, low Arapuni generation, and an outage of a 220 kV Bunnythorpe–Tokaanu, Tokaanu–Whakamaru or Rangipo–Wairakei circuit.

Solution

This 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.

Longer-term options to reduce the power flow along the Bunnythorpe–Mataroa circuit include installing a:

series reactor, or

phase shifting transformer.

11.8.3 Bunnythorpe–Woodville 110 kV transmission capacity

Project reference: BPE_WDV-TRAN-EHMT-01

Project status/purpose: Possible, to meet the Grid Reliability Standard (not core grid). This project is part of the lower North Island transmission capacity investigation, and we anticipate seeking approval from the Commerce Commission in 2013

Indicative timing: Special protection scheme: 2013 Circuit reconductoring/convert circuit’s operating voltage: 2015-2020

Indicative cost band: Special protection scheme: A Circuit reconductoring/convert circuit’s operating voltage: to be advised

Issue

The Bunnythorpe–Woodville circuits are rated at 57/70 MVA (summer/winter). An outage of one circuit causes the other circuit to overload during high south flow. The loading on these circuits depends on the HVDC transfer direction and level, Te Apiti generation levels and the load in Wellington, Dannevirke, and Waipawa.

Solution

This issue can be resolved operationally by:

restricting HVDC south power flow, and/or

restricting Te Apiti generation, or

opening either the 110 kV Mangamaire–Woodville circuit or the Mangamaire–Masterton circuit, leaving Mangamaire on n security.



Longer-term options include:

installing a special protection scheme to automatically open the Mangamaire–Woodville circuit following an outage

reconductoring the 110 kV Bunnythorpe–Woodville circuits with a higher-rated conductor, or

converting the Bunnythorpe–Woodville circuits to 220 kV operation.

11.8.4 Bunnythorpe supply transformer capacity


Issue

Two 220/33 kV transformers supply Bunnythorpe’s load, providing:



(summer/winter).

The peak load at Bunnythorpe is forecast to exceed the transformers’ n-1 winter capacity by approximately 7 MW in 2012, increasing to approximately 39 MW in 2027 (see Table 11-7). Tararua wind generation (Stage 2) is connected to the Bunnythorpe 33 kV bus, and the forecast assumes minimum generation of 7 MW coincident with the peak load.

Table 11-7: Bunnythorpe supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Bunnythorpe 0.98 7 10 12 14 17 19 24 28 32 36 39

Solution

Increasing the transformers’ cable limit will not solve the overload issue. Powerco can transfer load within the distribution system to Linton following a contingency. This operational measure is considered adequate for at least the next 5-10 years.

We will also discuss with Powerco converting the Bunnythorpe 33 kV outdoor switchyard to an indoor switchboard. Future investment will be customer driven.

11.8.5 Linton supply transformer capacity


Issue

Two 110/33 kV transformers (rated at 60 MVA and 100 MVA) supply Linton’s load, providing:



The peak load at Linton is forecast to exceed the transformers’ n-1 winter capacity by approximately 2 MW in 2015, increasing to approximately 19 MW in 2027 (see Table 11-8). Tararua wind generation (Stage 1) is connected to the Linton 33 kV bus, and the forecast assumes minimum generation of 7 MW coincident with the peak load.

88

The transformers’ capacity is limited by cable ratings; with this limit resolved, the n-1 capacity will be 101/106 MVA (summer/winter).



Table 11-8: Linton supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Linton 0.99 0 0 0 2 4 5 9 12 14 17 19

Solution

Linton normally has two 100 MVA transformers, but one failed and has been temporarily replaced with a 60 MVA transformer. The issue will be addressed by procuring a replacement transformer.

We will also discuss with Powerco converting the Linton 33 kV outdoor switchyard to an indoor switchboard. Future investment will be customer driven.

11.8.6 Mangahao supply transformer capacity


Issue

Two 110/33 kV transformers supply Mangahao’s load, providing:



The peak load at Mangahao is forecast to exceed the transformers’ n-1 winter capacity by approximately 4 MW in 2012, increasing to approximately 15 MW in 2027 (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 forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Mangahao 0.97 4 5 6 7 7 8 10 12 13 14 15

Solution

If Mangahao generates at 13 MW or more, this issue could be delayed beyond the forecast period. The supply transformer overload is managed operationally as Mangahao generation is usually available during peak load periods.

We will also convert the Mangahao 33 kV outdoor switchgear to an indoor switchboard within the next five years. In addition, both Mangahao supply transformers will approach their expected end-of-life within the next 5-10 years. We will discuss with Electra and Todd Energy the timing and options for these works. Future investment will be customer driven.

11.8.7 Marton supply transformer capacity

Project reference: MTN-POW_TFR-EHMT-01




Two 110/33 kV transformers (rated at 20 MVA and 30 MVA) supply Marton’s 33 kV load, providing:





(summer/winter).

The peak load at Marton is forecast to exceed the transformers’ n-1 winter capacity by approximately 1 MW in 2023, increasing to approximately 2 MW in 2027 (see Table 11-10).

Table 11-10: Marton supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Marton 0.98 0 0 0 0 0 0 0 0 1 1 2

Solution

Resolving the metering equipment limit will solve the transformers’ n-1 capacity issue within the forecast period.

In addition, both Marton supply transformers will approach their expected end-of-life within the forecast period. We will discuss with Powerco the rating and timing for the replacement transformers. Future investment will be customer driven.

11.8.8 Mataroa supply transformer security


Issue

The load at Mataroa is supplied by a single 110/33 kV, 30 MVA supply transformer comprising three single-phase units, resulting in no n-1 security.

Solution

A spare on-site unit may be able to provide backup following a unit failure, with replacement taking 8-14 hours. However, this is an uncontracted spare, which may not be available when needed. Powerco considers the lack of n-1 security can be resolved operationally for the forecast period.

The Mataroa supply transformer is approaching its expected end-of-life within the next five years. We will discuss with Powerco the future supply options at Mataroa. Future investment will be customer driven.

11.8.9 National Park transmission and supply transformer security


Issue

The load at National Park is supplied through a single 110 kV transmission circuit and a single 110/33 kV, 10 MVA supply transformer comprising three single-phase units, resulting in no n-1 security.

Solution

A spare on-site unit provides backup following a unit failure, with replacement taking 8-14 hours. Some load can also be backfed through The Lines Company distribution

89

The transformers’ capacity is limited by metering equipment, followed by LV bushing limit (24 MWA) and protection limit (25 MVA); with these limits resolved, the n-1 capacity will be 26/27 MVA (summer/winter).



system. The Lines Company considers the lack of n-1 security can be resolved operationally for the forecast period.

The National Park supply transformer is approaching its expected end-of-life within the next five years. We are discussing future supply options with The Lines Company to increase supply security. Future investment will be customer driven.

11.8.10 Ohakune supply transformer security and capacity

Project reference: TNG-SUBEST-DEV-01


Indicative timing: 2013, subject to agreement with The Lines Company


Issue

The load at Ohakune is supplied by a single 110/11 kV, 10 MVA supply transformer comprising three single-phase units (currently with one on-site spare). This means Ohakune has no n-1 security, although the spare on-site unit provides backup following a unit failure (with replacement taking 8-14 hours).

The peak load at Ohakune is forecast to exceed the transformer’s continuous capacity by approximately 2 MW in 2012, increasing to approximately 5 MW in 2027 (see Table 11-11).

Table 11-11: Ohakune supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Ohakune 0.98 2 2 2 2 3 3 3 4 4 5 5

Solution

The local lines companies, Powerco and The Lines Company, have not requested a higher security level at Ohakune. We are discussing option with The Lines Company to transfer some of its load at Ohakune to Tangiwai grid exit point, via a new feeder at Tangiwai.

In addition, the Ohakune supply transformer is approaching its expected end-of-life within the next five years. We will discuss the timing for the replacement transformer with the local lines companies. Future investment will be customer driven.

11.8.11 Ongarue supply transformer security


Issue

The load at Ongarue is supplied by a single 110/33 kV, 20 MVA supply transformer comprising three single-phase units, resulting in no n-1 security.

Solution

Most load can be backfed through The Lines Company’s distribution system. The Lines Company considers the lack of n-1 security can be resolved operationally for the forecast period.

We will also convert the Ongarue 33 kV outdoor switchgear to an indoor switchboard within the next 5-10 years. Also the Ongarue supply transformer will approach its expected end-of-life towards the end of the forecast period. We will discuss with The



Lines Company the timing of the switchgear conversion work and transformer replacement options. Future investment will be customer driven.

11.8.12 Tokaanu supply transformer security


Issue

The 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-load transformer will result in a loss of supply until the other transformer is manually switched into service.

Solution

The Lines Company considers the lack of n-1 security can be resolved operationally for the forecast period. Future investment will be customer driven.

11.8.13 Waipawa supply transformer capacity and security

Project reference: WPW-POW_TFR_PTN-EHMT-01




Issue

Waipawa has loads at 33 kV and 11 kV. Two 110/33 kV transformers (rated at 20 MVA and 30 MVA) supply Waipawa’s load, providing:



(summer/winter).

The peak load at Waipawa is forecast to exceed the transformers’ n-1 winter capacity by approximately 1 MW in 2015, increasing to approximately 6 MW in 2027 (see Table 11-12).

Table 11-12: Waipawa supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Waipawa 0.96 0 0 0 1 1 2 3 3 4 5 6

A single 33/11 kV, 10 MVA transformer supplies Waipawa’s 11 kV load, resulting in no n-1 security.

Solution

Resolving the 110/33 kV transformers’ metering and protection limits will delay the transformers’ capacity issue for a few years. We will discuss with Centralines the future supply options for Waipawa.

Centralines considers the lack of n-1 security for Waipawa’s 11 kV load can be resolved operationally within the forecast period. Future investment will be customer driven.

90

The transformers’ capacity is limited by a metering limit, followed by protection and transformer bushing (27 MVA) limits; with these limits resolved, the n-1 capacity will be 29/30 MVA (summer/winter).




There are no other items of interest identified to date beyond those set out in Section 11.8. See Section 11.10 for specific generation proposals relevant to this region.

11.10 Central North Island generation proposals and opportunities



91

11.10.1 Additional geothermal generation

There are a number of planned and proposed geothermal generation developments in the region connecting into or near the Wairakei Ring. The Ngatamariki geothermal power station is under construction and will connect to the Nga Awa Purua switchyard. A new geothermal power station is being built at Te Mihi and will be connected to a new switchyard located at or near the tee point of the existing 220 kV Wairakei–Poihipi–Whakamaru circuit.

We have committed to replacing the existing Wairakei–Poihipi–Whakamaru 1 circuit with a new overhead double-circuit line between Wairakei and Whakamaru. This will increase the power flow capacity through the Wairakei Ring (see Chapter 6, Section 6.4.3, for more information).

11.10.2 Tauhara geothermal station

Tauhara will connect into a 220 kV circuit from Wairakei to the Hawkes Bay region. Maungaharuru wind generation station (formally known as Titiokura, and Hawke’s Bay wind stations) in the Hawkes Bay region will also connect to the same circuit (see Chapter 13, Section 13.10.2), 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 both 220 kV circuits from Wairakei to the Hawkes Bay region, and a thermal upgrade of the circuits between Wairakei and Tauhara.

11.10.3 Additional wind generation connection to the 220 kV circuits between Bunnythorpe and Wellington

There are several investigations and proposals for wind station connections to the 220 kV double-circuit line between Bunnythorpe, Linton, and Wellington, which could occur at Linton or at new connection points along the line.

This is a high-capacity line and the effect of some additional generation on transmission capacity between Bunnythorpe and Wellington will be a small net percentage increase or decrease in transfer capacity, depending on the direction of power flow. A total of approximately 830 MW maximum generation injection into both the Bunnythorpe–Tararua Wind Central–Linton and Bunnythorpe–Linton 220 kV circuits will not cause system issues.

91




The wind generation resource under investigation is so large, however, that it is unlikely to be economical to connect it all to these 220 kV circuits because of transmission constraints.

11.10.4 Additional generation connected to the 110 kV buses

There are several possible wind generation station sites close to the 110 kV transmission circuits that run from Mangamaire to Woodville, Dannevirke, and Waipawa.

At times, the existing 90 MW Te Apiti wind station, which connects at Woodville, uses all the available transmission capacity, even with the use of generation runback schemes. Any new generation connected to the 110 kV transmission circuits may occasionally cause generation constraints. The capacity on the existing 110 kV Masterton–Mangamaire–Woodville and Bunnythorpe–Woodville circuits enables the connection of approximately 79 MW of additional generation. Higher levels of generation may require new lines.

11.10.5 Puketoi ranges

There are several prospective wind generation stations in the Puketoi ranges, with a combined capacity of many hundreds of megawatts. The closest network is the 110 kV transmission network (see Section 11.10.4), which is not nearby. If wind generation is developed in this area, then a single new transmission line may possibly connect all the wind stations to the National Grid at Bunnythorpe.

Generation from the Puketoi ranges can also connect along the 220 kV double-circuit line from Bunnythorpe to Wellington. However, care is required to ensure that the total generation from the Puketoi ranges, plus other generation along the 220 kV Bunnythorpe–Wellington line, does not become too high (see Section 11.10.3). It is also possible that some of the 110 kV lines may be rationalised as part of this work.

Chapter 12: Taranaki Region


12 Taranaki Regional Plan


12.2 Taranaki transmission system

12.3 Taranaki demand

12.4 Taranaki generation

12.5 Taranaki significant maintenance work

12.6 Future Taranaki projects summary and transmission configuration


12.8 Taranaki transmission capability


12.10 Taranaki generation proposals and opportunities


This chapter details the Taranaki regional transmission plan. We base this regional plan on an assessment of available data, and welcome feedback to improve its value to all stakeholders.

Figure 12-1: Taranaki region



The Taranaki region includes a mix of medium sized and small grid exit points, and industrial loads.

We have assessed the Taranaki region’s transmission needs over the next 15 years while considering longer-term development opportunities. Specifically, the transmission network needs to be flexible to respond to a range of future service and technology possibilities, taking into consideration:


forecast demand

forecast generation



12.2 Taranaki transmission system

This section highlights the state of the Taranaki regional transmission network. The existing transmission network is set out geographically in Figure 12-1 and schematically in Figure 12-2.

Figure 12-2: Taranaki transmission schematic

110 kV

110 kV

110 kV

110 kV

110 kV

110 kV

110 kV

110 kV

220 kV

220 kV


33 kV

110 kV

11 kV

Patea Whareroa

33 kV

33 kV33 kV

33 kV

33 kV

110kV CIRCUIT

SUBSTATION BUS

TRANSFORMER

TEE POINT

KEY

220kV CIRCUIT

LOAD

CAPACITOR

Marton/Bunnythorpe

New

Plymouth

Carrington Street Huirangi

Motunui

Opunake

Kapuni

Stratford

Hawera

Waverley33 kV

Wanganui

110 kV

220 kV

33 kV

BrunswickBunnythorpe

55 kV

220 kV

Taumarunui

WaikatoHuntly Te Kowhai

GENERATOR

SERIES REACTOR

WITH A BYPASSED

SWITCH


200 MWPeakers

TaranakiCombined

Cycle

Kupe

33 kV33 kV

12.2.1 Transmission through the region

The Taranaki region connects to the National Grid through 220 kV circuits that run north to Huntly and south-east to Bunnythorpe. Under normal operation, generation exceeds 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 kV line. Power transfer south of Stratford can be constrained by the parallel 110 kV circuits under certain operating conditions.



We have committed to reconductoring the 110 kV circuits between Stratford and Wanganui with a higher-rated conductor to maximise the through flow on the 220 kV circuits.


The 220 kV Taranaki transmission network forms part of the grid backbone. The parallel 110 kV transmission network within the region has both capacity and voltage issues under certain operating conditions.

We currently have a number of projects proposed or underway to improve supply reliability and support demand growth in the Taranaki region. These projects include replacing old single phase transformers and resolving the overloading issues on the 110 kV transmission network. Due to corrosion, we have also committed to replacing the old 110 kV Opunake–Stratford conductor with a modern equivalent.


No significant new transmission is expected to be required in the Taranaki region. New generation connection may require nearby circuits to be thermally upgraded or reconductored for additional capacity to export the generation.

High levels of new generation, such as two or more additional combined cycle gas turbines may require additional transmission circuits in and adjacent to the Taranaki region to transfer generation out of the region.

12.3 Taranaki demand

The after diversity maximum demand (ADMD) for the Taranaki region is forecast to grow on average by 1.0% annually over the next 15 years, from 222 MW in 2012 to 258 MW by 2027. This is lower than the national average demand growth of 1.7% annually.


92) for the Taranaki region. The forecasts are derived using


92

The after diversity maximum demand (ADMD) for the region will be less than the sum of the individual GXP peak demands, as it takes into account the fact that the peak demand does not occur simultaneously at all the GXPs in the region.



Figure 12-3: Taranaki region after diversity maximum demand forecast

Figure 12-1 lists forecast peak demand (prudent growth) at each grid exit point for the forecast period, as required for the Grid Reliability Report.

Table 12-1: Forecast annual peak demand (MW) at Taranaki grid exit points to 2027


Peak demand (MW)


2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Brunswick 0.94 43 44 45 46 47 48 49 51 53 54 55

Carrington Street

1

0.95 62 63 65 66 67 69 71 74 76 78 80

Huirangi1 0.91 28 29 29 30 30 31 32 33 34 35 36

Hawera 0.93 32 33 33 34 35 35 35 38 39 40 41

Hawera (Kupe) 1.00 12 12 12 12 12 12 12 12 12 12 12

Motunui 0.92 9 9 9 9 9 9 9 9 9 9 9

Moturoa 0.99 22 23 23 24 25 25 27 28 29 30 32

Opunake 0.91 11 11 11 12 12 12 13 13 14 14 14

Stratford 33 kV 0.92 31 32 32 32 33 33 34 35 36 37 38

Stratford 220 kV 1.00 11 11 11 12 12 12 13 13 14 14 14

Taumarunui 0.83 11 11 11 11 11 11 11 11 11 11 11

Wanganui 0.94 50 51 52 53 54 55 57 60 61 63 64

Waverley 0.92 4 4 4 4 4 4 4 4 5 5 5

1. Load shifting between Carrington Street and Huirangi affects both peak forecasts.

12.4 Taranaki generation

The Taranaki region’s generation capacity is 733 MW, increasing to 833 MW after the commissioning of the Todd Energy 100 MW McKee Power Plant. The region imports

100

150

200

250

300

350

400

1997 1999 2001 2003 2005 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027

Load (MW)

Taranaki

2011 APR Forecast

2012 APR Forecast

Actual Peak



and exports power to the National Grid depending on the level of dispatched thermal generation.

Table 12-2 lists the generation forecast at each grid injection point for the forecast period, as required for the Grid Reliability Report. This includes all known and committed generation stations including those embedded within the relevant local lines company’s network (Powerco).

93

Table 12-2: Forecast annual generation capacity (MW) at Taranaki grid injection points to 2027 (including existing and committed generation)




2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Carrington St (Mangorei) 5 5 5 5 5 5 5 5 5 5 5

Hawera - Kiwi Dairy (Whareroa)

70 70 70 70 70 70 70 70 70 70 70

Hawera – Patea

31 31 31 31 31 31 31 31 31 31 31

Hawera (Patearoa) 2 2 2 2 2 2 2 2 2 2 2

Huirangi (Mangahewa) 9 9 9 9 9 9 9 9 9 9 9

Huirangi (Motukawa) 5 5 5 5 5 5 5 5 5 5 5

Kapuni 25 25 25 25 25 25 25 25 25 25 25

Motunui Deviation (MPP) 0 100 100 100 100 100 100 100 100 100 100

Stratford 385 385 385 385 385 385 385 385 385 385 385

Stratford peaking plant 200 200 200 200 200 200 200 200 200 200 200

Stratford (Stratford Austral Pacific)

1 1 1 1 1 1 1 1 1 1 1

12.5 Taranaki significant maintenance work


94 proposed for the Taranaki region for the next

15 years that might significantly impact related system issues or connected parties.




Brunswick supply transformer expected end-of-life

2017-2019 No n-1 security at Brunswick. Future investment will be customer driven. See Section 12.8.3 for more information.

Hawera 110 kV rebuild, and 33 kV outdoor to indoor conversion

2012-2014 The work involves rationalising the 110 kV bus to ease maintenance outages and increasing the 110 kV bus rating. The new rating will match the new Stratford and Waverley circuits.

Hawera supply transformers expected end-of-life

2027-2030 The forecast load will exceed the supply transformer’s n-1 thermal capacity from 2014. See Section 12.8.7 for more information.

Huirangi supply transformers expected end-of-life

2019-2021 The forecast load at Huirangi already exceeds transformer n-1 capacity. See Section 12.8.7 for more information.

Motunui 11 kV switchgear replacement


93 Only generators with a capacity greater than 1 MW are listed. Generation capacity is rounded to the

nearest megawatt. 94






New Plymouth interconnecting transformer expected end-of-life

2020-2022 There are system issues associated with an outage of the New Plymouth interconnecting transformer. See Section 12.8.1 for more information.

Opunake–Stratford A reconductoring


Stratford interconnecting transformer expected end-of-life

2023-2025 The interconnecting transformer will exceed its n-1 capacity under certain operating conditions. See Section 12.8.1 for more information.

Stratford supply transformer expected end-of-life

2013-2015 The forecast load of Stratford already exceeds the transformer n-1 capacity. See Section 12.8.10 for more information.

Wanganui supply transformers expected end-of-life

2013-2015 The forecast load of Wanganui already exceeds the transformer n-1 capacity. See Section 12.8.11 for more information.

12.6 Future Taranaki projects summary and transmission configuration

Table 12-4 lists projects to be carried out in the Taranaki region within the next 15 years.

Figure 12-4 shows the possible configuration of Taranaki transmission in 2027, with new assets, upgraded assets, and assets undergoing significant maintenance within the forecast period.

Table 12-4: Projects in the Taranaki region up to 2027


Brunswick Replace supply transformer. Install a second supply transformer.

Base Capex Possible

Brunswick–Stratford Upgrade circuit’s capacity. Possible

Carrington Street Upgrade supply transformer branch limiting components. Base Capex

Carrington Street–Stratford

Increase circuit’s capacity by thermally upgrading the terminal spans near Carrington Street.

Possible

Hawera 110 kV bus rebuild. Convert 33 kV outdoor switchgear to an indoor switchboard. Replace supply transformers.


Huirangi Replace supply transformers with higher-rated units. Base Capex

New Plymouth Replace interconnecting transformer. Install a second interconnecting transformer.

Base Capex Possible

Opunake–Stratford Reconductor Opunake–Stratford A line. Committed

Hawera–Waverley Reconductor Hawera–Waverley line. Committed

Stratford Replace interconnecting transformer. Replace supply transformers with higher-rated units.


Wanganui Replace supply transformers with higher-rated units. Base Capex



Figure 12-4: Possible Taranaki transmission configuration in 2027

110 kV

110 kV

110 kV

110 kV

110 kV

110 kV

110 kV

110 kV

220 kV

220 kV

33 kV

110 kV

33 kV

11 kV

33 kV

33 kV33 kV

33 kV

33 kV


Marton/Bunnythorpe

33 kV

Wanganui

110 kV

220 kV

33 kV

BrunswickCENTRAL NORTH ISLAND

Bunnythorpe

New Plymouth

Carrington Street Huirangi

Motunui

Stratford

Taranaki

Patea Whareroa

Hawera

Waverley

Kapuni

Opunake

Taumarunui

Waikato

Huntly

Kupe

33 kV

200 MWPeakers

KEY

CombinedCycle

55 kV

220 kV

Te Kowhai

McKee Power

Project

NEW ASSETS

UPGRADED ASSETS

ASSETS SCHEDULED

FOR REPLACEMENT

* MINOR UPGRADE

*




Issues Change

Hawera supply transformer capacity New issue.

Opunake supply transformer capacity New Issue.

12.8 Taranaki transmission capability

Table 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 issues

Section number

Issue

Regional

12.8.1 North Taranaki transmission capacity and low voltage issues

12.8.2 Stratford–Hawera–Waverley–Wanganui 110 kV transmission capacity


12.8.3 Brunswick supply security

12.8.4 Carrington Street supply transformer capacity

12.8.5 Hawera voltage quality

12.8.6 Hawera (Kupe) supply security

12.8.7 Hawera supply transformer capacity

12.8.8 Huirangi supply transformer capacity



Section number

Issue

12.8.9 Opunake supply transformer capacity

12.8.10 Stratford supply transformer capacity

12.8.11 Wanganui supply transformer capacity

12.8.12 Waverley supply security

12.8.1 North Taranaki transmission capacity and low voltage issues

Project reference: TRNK-TRAN-EHMT-01

Project status/purpose: Stratford interconnecting transformer capacity: possible, to meet the Grid Reliability Standard (core grid) Replace Carrington Street–Stratford circuits’ terminal span equipment: Base Capex, minor enhancement Upgrade Huirangi transformer: possible, customer-specific


Indicative cost band: New interconnecting transformer: B Reconfigure 220 kV to 110 kV transmission: to be advised Replace Carrington Street–Stratford circuits’ terminal span equipment: A Upgrade Huirangi transformer: B

Issue

The 220/110 kV, 100 MVA interconnecting transformer at Stratford operates in parallel with the 220/110 kV, 200 MVA interconnecting transformer at New Plymouth to supply Taranaki’s load. The Stratford transformer also assists with through transmission on the 110 kV transmission network between Bunnythorpe and Stratford.

The Stratford and New Plymouth transformers provide:



An outage of the New Plymouth interconnecting transformer may cause:

the Stratford interconnecting transformer to exceed its n-1 capacity (the loading on this interconnecting transformer depends on the 110 kV Taranaki generation)

the Carrington Street–Stratford circuit to exceed its thermal capacity, and

low voltage at the Huirangi 33 kV supply bus.

Solution

Possible solutions include:

installing a second 220/110 kV interconnecting transformer at (or near) New Plymouth, and we anticipate land acquisition is required for the second transformer

operating the 220 kV New Plymouth–Stratford circuits at 110 kV, decommissioning the New Plymouth 220/110kV interconnection and raising the Stratford interconnection capacity to 250 MVA

constraining-on generation in the 110 kV network to reduce loading and retain voltage quality

upgrading the thermal capacity of the Carington Street terminating spans of the Carrington Street–Stratford circuits, and

replacing the Huirangi supply transformers with transformers with on load tap changers.

In addition, the interconnecting transformers at New Plymouth and Stratford have an expected end-of-life within the forecast period. We will investigate the rating and



timing of the replacement transformers and possible alternate transmission configuration.

12.8.2 Stratford–Hawera–Waverley–Wanganui 110 kV transmission capacity

Project reference: SFD_WGN-TRAN-EHMT-01

Project status/purpose: Committed, to provide net market benefit



Issue

There are several issues with respect to the capacity of the 110 kV Stratford–Hawera–Waverley–Wanganui circuits.

Circuit capacities sometimes constrain high south power flow for an outage of a parallel 220 kV circuit between Stratford and Bunnythorpe. A series reactor and an automatic bus splitting scheme have been installed at Hawera. These raise, but do not eliminate, the constraint level.

Circuit capacities may constrain generation, for high generation from Taranaki coupled with high or low generation at Whareroa and Patea.

An outage of the 110 kV Hawera–Stratford circuit may overload the 110 kV Wanganui–Waverley circuit during high net Hawera load (when Patea and Whareroa are not generating). This may require load shedding at Hawera to relieve the overloading.

Solution

During an outage of a 220 kV circuit between Stratford and Bunnythorpe, an automatic protection scheme will remove post-contingency overloads on the 110 kV Hawera–Waverley circuit by splitting the Hawera 110 kV bus. Patea and the 33 kV load will be connected only to the Hawera–Stratford circuit. Whareroa and Kupe will be connected only to the 110 kV Hawera–Waverley circuit.

We have completed reconductoring the Hawera–Stratford and Wanganui–Waverley sections

95 and committed to reconductoring the Hawera–Waverley section by the end

of 2012, after which the series reactor at Hawera will be decommissioned.

12.8.3 Brunswick supply security

Project reference: BRK-POW_TRF-DEV-01




Issue

A single 220/33 kV, 50 MVA96

transformer bank supplies load at Brunswick resulting in no n-1 security.

There is a non-contracted on-site spare transformer, allowing possible replacement within 8-14 hours following a unit failure (if the spare unit is available). Some load may need to be curtailed during this transformer outage period, as there is only limited capacity within the Powerco network to transfer load.

95

The Hawera–Stratford and Wanganui–Waverley circuits’ capacities are limited by station equipment at Hawera of 76/76 MVA (summer/winter) and Wanganui of 78/78 MVA (summer/winter), respectively.

96 The transformer’s meter accuracy limit of 39 MVA prevents the full nominal installed capacity being

available.



Solution

We are discussing future supply options with Powerco, one of which is to install a second supply transformer to provide n-1 security. 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 the replacement transformers. Future investment will be customer driven.

12.8.4 Carrington Street supply transformer capacity

Project reference: Upgrade protection: CST-POW_TFR_PTN-EHMT-01 Upgrade branch components: CST-POW_TFR-EHMT-01

Project status/purpose: Upgrade protection: Base Capex, minor enhancement Upgrade branch components: possible, customer-specific


Indicative cost band: Upgrade protection: A Upgrade branch components: A

Issue

Two 110/33 kV transformers supply Carrington Street’s load, providing:



(summer/winter).

The peak load at Carrington Street is forecast to exceed the n-1 winter capacity by 1 MW in 2012, increasing to approximately 18 MW in 2027 (see Table 12-7).

Table 12-7: Carrington Street supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Carrington Street

0.95 1 2 3 4 6 7 10 12 15 17 18

Solution

Upgrading the protection equipment, 33 kV bus section, circuit breakers, disconnectors, and current transformers to at least 109 MVA will resolve the issue for the forecast period and beyond. Future investment will be customer driven.

12.8.5 Hawera voltage quality

Project reference: HWA-REAC-SUP-DEV-01

Project status/purpose: Possible, to meet the Grid Reliaility Standard (not core grid)



Issue

An outage of the 110 kV Hawera–Stratford circuit can result in low voltage and voltage drops greater than 5% when there is no local generation available at Hawera. When this occurs, Hawera is supplied from a 143 km spur line from Bunnythorpe. As the spur load grows, the voltage quality issues progressively arise at Waverley, and Wanganui.

97

The transformers’ capacity is limited by a relay, followed by LV bus section and disconnector (69 MVA) limits, and circuit breaker (71 MVA) limits; with these limits resolved, the n-1 capacity will be 104/109 MVA (summer/winter).



Patea (32 MW) and Whareroa (50 MW) inject into the Hawera 110 kV bus, but have difficulty providing voltage support.

Solution

We are presently investigating options for resolving the low voltage issues at Hawera, which include:

obtaining greater reactive support from the generators

installing under-voltage load shedding capability, and

installing reactive support at Hawera.

12.8.6 Hawera (Kupe) supply security


Issue

A single 110/33 kV, 30 MVA supply transformer supplies the Origin Energy Resources Kupe load, resulting in no n-1 security.

The load can be transferred to the other supply transformers at Hawera by closing the 33 kV bus coupler for maintenance outages, and after a transformer trips.

Solution

The load is fixed industrial, supplied by a dedicated transformer that meets the customer’s requirements.

12.8.7 Hawera supply transformer capacity


Issue

Two 110/33 kV transformers supply Hawera’s load, providing:

a total installed capacity of 60 MVA, and



The peak load at Hawera is forecast to exceed the transformers’ n-1 summer capacity by 1 MW in 2016, increasing to approximately 9 MW in 2027 (see Table 12-8).

Table 12-8: Hawera supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Hawera 0.93 0 1 2 2 3 4 5 6 7 9 9

Solution

The interim solution is to close the 33 kV bus coupler and supply the Powerco load from the single Kupe supply transformer.

A possible longer-term option is to replace the existing transformers with two 50 MVA units.

98

The transformers’ capacity is limited by 33 kV bus section limit; with this limit resolved, the n-1 capacity will be 37/39 MVA (summer/winter).



Both Hawera supply transformers have an expected end-of-life at the end of the forecast period. We will discuss with Powerco the appropriate rating and timing for the replacement transformers. Future investment will be customer driven.

12.8.8 Huirangi supply transformer capacity

Project reference: HUI-POW_TFR-REPL-01




Issue

Two 110/33 kV transformers supply Huirangi’s load, providing:

a total installed capacity of 40 MVA, and


The peak load at Huirangi is forecast to exceed the transformers’ n-1 summer capacity by 6 MW in 2012, increasing to approximately 13 MW in 2027 (see Table 12-9).

Table 12-9: Huirangi supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Huirangi 0.91 6 6 7 7 8 8 9 10 11 12 13

Solution

The interim solution is for Powerco to control the Bell Block load shift from Carrington Street to Huirangi.

The longer-term option is to replace the existing transformers with two 50 MVA units and reconfigure the distribution system.

Both Huirangi supply transformers have an expected end-of-life within the next 5-10 years. We are in discussions with Powerco to obtain the appropriate rating and timing for the replacement transformers. Future investment will be customer driven.

12.8.9 Opunake supply transformer capacity

Project reference: OPK_POW-TFR-EHMT-01




Issue

Two 110/33 kV transformers supply Opunake’s load, providing:



(summer/winter).

The peak load at Opunake is forecast to exceed the winter n-1 capacity by 1 MW in 2019, increasing to approximately 3 MW in 2027 (see Table 12-10).

99

The transformers’ capacity is limited by metering limit; with this limit resolved, the n-1 capacity will be 38/40 MVA (summer/winter).



Table 12-10: Opunake supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Opunake 0.91 0 0 0 0 0 0 1 1 2 2 3

Solution

Resolving the metering and protection limits will provide sufficient n-1 capacity for the forecast period and beyond.

12.8.10 Stratford supply transformer capacity

Project reference: SFD_POW-TFR-REPL-01




Issue

Two 110/33 kV transformers supply Stratford’s load, providing:



(summer/winter).

The peak load at Stratford already exceeds the transformers’ n-1 summer capacity and the overload is forecast to increase to approximately 17 MW by 2027 (see Table 12-11).

Table 12-11: Stratford supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Stratford 0.92 11 11 11 12 12 13 14 15 16 17 17

Solution

The existing supply transformers are approaching their expected end-of-life within the next five years. We are discussing with Powerco the appropriate rating and timing for the replacement transformers. A longer-term solution involves replacing the existing transformers with two 40 MVA units.

12.8.11 Wanganui supply transformer capacity

Project reference: WGN_POW-TFR-REPL-01




Issue

There are two 110/33 kV transformers (20 MVA and 30 MVA) at Wanganui, providing:



(summer/winter).

100

The transformers’ winter capacity is limited by the cable rating; with this limit resolved, the n-1 capacity will be 25 MVA.



There is a single 50 MVA 220/33kV transformer at Brunswick. Both the Wanganui and Brunswick grid exit points supply Wanganui Township, providing:


n-1 capacity of 59 MVA102

(summer/winter).

The aggregate peak load at Wanganui and Brunswick already exceeds the transformers’ n-1 winter capacity and the overload is forecast to increase to approximately 27 MW in 2027 (see Table 12-12).

Table 12-12: Wanganui town supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Wanganui 0.94 10 11 12 14 15 16 19 21 23 26 27

Solution

We are discussing future supply options with Powerco. Options include:

replacing the two Wanganui transformers with two 80 MVA units

adding 110 kV feeders from Wanganui, or

installing a second transformer at Brunswick.

All supply transformers at Wanganui are approaching their expected end-of-life within the next five years. We will discuss with Powerco the rating and timing of replacement transformers. Future investment will be customer driven.

12.8.12 Waverley supply security


Issue

A single 110/11 kV, 10 MVA transformer supplies load at Waverley resulting in no n-1 security.

Solution

There is an on-site spare transformer, allowing replacement within 8-14 hours following a unit failure. Powerco considers the issue can be resolved operationally for the forecast period. Any future investment will be customer driven.


There are no other items of interest identified to date beyond those set out in Section 12.8. See Section 12.10 for information about generation proposals relevant to this region.

12.10 Taranaki generation proposals and opportunities

This section details relevant regional issues for selected generation proposals under investigation by developers and in the public domain, or other generation opportunities.The maximum generation that can be connected at any substation

101

The transformers’ capacity is limited by the transformer bushing; with this limit resolved, the n-1 capacity will be 27/28 MVA (summer/winter).

102 Brunswick supply transformer is taken out of service. The Wanganui supply transformers’ n-1 capacity is limited by branch limiting components. With these limits resolved, the n-1 capacity will be 64/68 MVA (summer/winter).



depends on several factors and usually falls within a range. Generation developers should consult with us at an early stage of their investigations to discuss connection issues. See our website for more information about connecting generation.

103


For generation connections at the Stratford 220 kV bus, the maximum generation that can be injected under n-1 is approximately 800-1,200 MW. This includes the existing and newly commissioned 200 MW generators. Generation injection into the Stratford 220 kV bus depends on the direction of HVDC power flows and system constraints around the Wairakei ring.

Generation stability issues will also need to be addressed (see Chapter 6, Section 6.4.4).

12.10.2 Waverley wind station

There is a potential for wind generation near Waverley. Connection options include the nearby 110 kV Hawera–Wanganui circuit, or the three nearby 220 kV Brunswick–Stratford circuits.

We have committed to upgrading the 110 kV Stratford–Wanganui circuits (see Section 12.8.2). After the upgrade, approximately 100-150 MW of generation can be connected.

The three 220 kV Brunswick–Stratford circuits are part of the grid backbone connecting Taranaki to the rest of the National Grid. The loading on these three circuits is approximately equal, which maximises their transfer capacity. In order to maintain the existing transfer capacity, a large wind station will need to be connected to all three circuits, or the capacity of one or more of the circuits will need to be increased.

12.10.3 Additional generation at other locations

There are no issues with connecting new generation at the New Plymouth 220 kV bus (other than stability issues). The maximum generation injection into the New Plymouth 110 kV bus at n-1 security is approximately 450 MW under light load conditions. Any generation injecting into this bus will play a significant role in regulating the 110 kV bus voltages in the northern part of the Taranaki region.

Exploration for more gas inshore and offshore continues in the Taranaki region and has a potential for further gas generation development. Depending on the size of new generation, connection to the 220 kV and few 110 kV lines in the northern Taranaki area might be possible without a major line capacity upgrade.

Due to environmental corrosion, we have committed to reconductoring the Opunake–Stratford circuit with a new AAAC conductor. The existing rating has been maintained which has sufficient capacity for approximately 50 MW of new generation on a secure double circuit.

103


Chapter 13: Hawke’s Bay Region


13 Hawke’s Bay Regional Plan


13.2 Hawke’s Bay transmission system

13.3 Hawke’s Bay demand

13.4 Hawke’s Bay generation

13.5 Hawke’s Bay significant maintenance work

13.6 Future Hawke’s Bay projects summary and transmission configuration


13.8 Hawke’s Bay transmission capability


13.10 Hawke’s Bay generation proposals and opportunities


This chapter details the Hawke’s Bay regional transmission plan. We base this regional plan on an assessment of available data, and welcome feedback to improve its value to all stakeholders.

Figure 13-1: Hawke’s Bay region



The Hawke’s Bay region load includes a mix of significant provincial cities (Napier, Hastings and Gisborne), heavy industry (the Panpac Mill), and smaller rural service centres (Wairoa and Havelock North).

We have assessed the Hawke’s Bay region’s transmission needs over the next 15 years while considering longer-term development opportunities. Specifically, the transmission network needs to be flexible to respond to a range of future service and technology possibilities, taking into consideration:


forecast demand

forecast generation



13.2 Hawke’s Bay transmission system

This section highlights the state of the Hawke’s Bay regional transmission network. The existing transmission network is set out geographically in Figure 13-1 and schematically in Figure 13-2.

Figure 13-2: Hawke’s Bay transmission schematic

220 kV

110 kV

220 kV

110 kV

110kV CIRCUIT

SUBSTATION BUS

TRANSFORMER

TEE POINT

KEY

220kV CIRCUIT

LOAD

CAPACITOR

33 kV

33 kV

220 kV

11 kV

BONDED CIRCUIT

33 kV


Wairakei

Tokomaru Bay

Gisborne

110 kV

50 kV

Wairoa110 kV

Tuai110 kV

Redclyffe

Whakatu

Fernhill


Waipawa

GENERATOR

Whirinaki

11 kV

11 kV




Transmission into the region is via two 220 kV circuits from Wairakei that supply the Whirinaki and Whakatu loads directly, and via two 220/110 kV interconnecting transformers at Redclyffe.

Two 110 kV circuits also connect Fernhill to Waipawa in the south and are normally open at Waipawa.


220/110 kV interconnection

The majority of the region’s load is supplied via the 220/110 kV transformers at Redclyffe. The transformer capacity may need to be increased as load grows, and/or new generation is connected to the 110 kV transmission network.

110 kV circuits

Transmission within the Hawke’s Bay region is predominantly at 110 kV. The two circuits supplying Gisborne may require a rating increase within the forecast period. For new generation or load connections beyond that forecast in this APR, some of the 110 kV lines may require capacity upgrade.


The two 220 kV circuits from Wairakei are expected to be adequate for the next 30-40 years of regional load growth. Additional reactive support will be required over this period, and the region will be on n security whenever one circuit is out of service for maintenance.

The two 220 kV circuits may need to be thermally upgraded to export power from the region during low load periods if there is a large increase in new generation. A new 220 kV line from the Bunnythorpe area to the Hawke’s Bay region may be considered if an increase in security is required.

We expect the development of new generation in the Hawke’s Bay region to drive the need for system upgrades.

13.3 Hawke’s Bay demand

The after diversity maximum demand (ADMD) for the Hawke’s Bay region is forecast to grow on average by 1.0% annually over the next 15 years, from 320 MW in 2012 to 369 MW by 2027. This is lower than the national average demand growth of 1.7% annually.


104) for the Hawke’s Bay region. The forecasts are derived


104




Figure 13-3: Hawke’s Bay region after diversity maximum demand forecast

Table 13-1 lists forecast peak demand (prudent growth) at each grid exit point for the forecast period, as required for the Grid Reliability Report.

Table 13-1: Forecast annual peak demand (MW) at Hawke’s Bay grid exit points to 2027


Peak demand (MW)


2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Fernhill 0.95 60 61 62 63 64 5 67 68 70 72 73

Gisborne 0.98 49 50 51 53 54 55 58 61 63 65 67

Redclyffe 0.97 70 76 77 78 79 80 83 85 87 89 90

Tuai 0.98 1 1 1 1 1 1 1 1 1 1 1

Wairoa 0.90 10 10 10 11 11 11 11 12 12 13 13

Whirinaki 1.00 82 82 82 82 82 82 82 82 82 82 82

Whakatu 0.96 95 96 98 99 101 102 105 108 111 114 116

13.4 Hawke’s Bay generation

The Hawke’s Bay region’s generation capacity is 325 MW, of which up to 170 MW105

is normally available.

Generation from Tuai, Kaitawa, and Piripaua hydro generation stations are collectively referred to as the Waikaremoana Hydro Scheme, and connect to the Tuai 110 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 kV transmission network.

105

The Whirinaki generation station is for emergency dispatch during dry year conditions or as otherwise determined by the Electricity Authority. Therefore, this generator is not counted as part of the region’s normal generation.

200

220

240

260

280

300

320

340

360

380

400

1997 1999 2001 2003 2005 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027

Load (MW) Hawkes Bay

2011 APR Forecast

2012 APR Forecast

Actual Peak



Table 13-2 lists the generation forecast at each grid injection point for the forecast period, as required for the Grid Reliability Report. This includes all known and committed generation stations including those embedded within the relevant local lines company’s network (Unison or Eastland Networks).

106

Table 13-2: Forecast annual generation capacity (MW) at Hawke’s Bay grid injection points to 2027 (including existing and committed generation)




2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Gisborne1

4 4 4 4 4 4 4 4 4 4 4

Gisborne (Matawai) 2 2 2 2 2 2 2 2 2 2 2

Kaitawa 36 36 36 36 36 36 36 36 36 36 36

Piripaua 42 42 42 42 42 42 42 42 42 42 42

Redclyffe (Ravensdown)

8 8 8 8 8 8 8 8 8 8 8

Tuai 60 60 60 60 60 60 60 60 60 60 60

Wairoa (Waihi) 5 5 5 5 5 5 5 5 5 5 5

Whirinaki 155 155 155 155 155 155 155 155 155 155 155

Whirinaki (Pan Pac) 13 13 13 13 13 13 13 13 13 13 13

1. Mobile diesel units are situated in the Gisborne and Tokomaru Bay areas.

13.5 Hawke’s Bay significant maintenance work


107 proposed for the Hawke’s Bay region for the





Fernhill supply transformers expected end-of-life, and 33 kV outdoor to indoor conversion

2018-2020 2012-2014

The forecast load at Fernhill already exceeds the transformer n-1 winter capacity. See Section 13.8.5 for more information.

Tuai supply transformer expected end-of-life

2012-2014 No n-1 security at Tuai. Future investment will be customer driven. See Section 13.8.9 for more information.

Wairoa supply transformers expected end-of-life

2015-2017 The forecast load at Wairoa may exceed transformer n-1 summer capacity for low load power factor. See 13.8.10 for more information.

Whakatu 33 kV outdoor to Indoor conversion


Whirinaki 11 kV Bus B and C switchboard replacement


13.6 Future Hawke’s Bay projects summary and transmission configuration

Table 13-4 lists the projects to be carried out in the Hawke’s Bay region within the next 15 years.

106





Figure 13-4 shows the possible configuration of Hawke’s Bay transmission in 2027, with new assets, upgraded assets, and assets undergoing significant maintenance within the forecast period.

Table 13-4: Projects in the Hawkes Bay region up to 2027


Fernhill Replace supply transformers. Convert 33 kV outdoor switchgear to an indoor switchboard.


Gisborne–Tuai Upgrade Gisborne–Tuai conductor capacity. Possible

Gisborne Recalibrate supply transformers’ metering parameters. New 110 kV capacitor bank.

Base Capex Possible

Redclyffe Replace supply transformers with two 120 MVA units. Committed

Tuai Replace supply transformer. Base Capex

Wairoa Replace supply transformers. Base Capex

Whakatu Convert 33 kV outdoor switchgear to an indoor switchboard. Base Capex

Whirinaki Replace 11 kV Bus B and C switchboards. Base Capex

Figure 13-4: Possible Hawke’s Bay transmission configuration in 2027

220 kV

110 kV

220 kV

110 kV

33 kV

33 kV

11 kV

33 kV


Wairakei

Tokomaru Bay

Gisborne

110 kV

50 kV

Wairoa110 kV

110 kV

Redclyffe

Whakatu

Fernhill


Waipawa

220 kV

Whirinaki

11 kV

KEY

Tuai11 kV

NEW ASSETS

UPGRADED ASSETS

ASSETS SCHEDULED

FOR REPLACEMENT

* MINOR UPGRADE

*






Issues Change

Gisborne supply capacity New issue.

Redclyffe 110 kV transmission security Removed. Project to install Redclyffe 110 kV bus coupler and protection upgrade completed.

Whakatu supply transformer capacity New Issue.

13.8 Hawke’s Bay transmission capability

Table 13-6 summarises the issues involving the Hawke’s Bay region for the next 15 years. For more information about a particular issue, refer to the listed section number.

Table 13-6: Hawke’s Bay region transmission issues

Section number

Issue

Regional

13.8.1 Hawke’s Bay voltage quality

13.8.2 Fernhill–Redclyffe 110 kV transmission capacity

13.8.3 Redclyffe–Tuai 110 kV transmission capacity

13.8.4 Redclyffe interconnecting transformer capacity


13.8.5 Fernhill supply transformer capacity

13.8.6 Gisborne 110 kV voltage quality

13.8.7 Gisborne supply capacity

13.8.8 Redclyffe supply transformer capacity

13.8.9 Tuai supply security

13.8.10 Wairoa supply transformer capacity

13.8.11 Whakatu supply transformer capacity

13.8.1 Hawke’s Bay voltage quality


Issue

The Hawke’s Bay transmission network is primarily supplied from the 220 kV Redclyffe bus, which is in turn supplied from the grid backbone by two 220 kV circuits from Wairakei. The 138 MW Waikaremoana hydro scheme connects to the 110 kV network, which also supplies the region’s load.

The loss of a 220 kV circuit at high load and minimal Waikaremoana generation can result in low voltages at the:

110 kV bus at Gisborne, and the issue progressively arises at other high voltage buses as load increases, and

supply buses at Fernhill and Redclyffe, which do not have on-load tap changers

Solution

The low voltage risk is managed operationally by constraining-on generators at Waikaremoana so that the generators’ reactive support is available. As the Hawke’s Bay load increases, a 220 kV circuit outage will require more Waikaremoana generators to be in service for reactive support.



We are in discussions with Unison about the supply transformer replacement108

at Fernhill and Redclyffe. Replacing these transformers with on-load tap changing transformers 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 capacity


Issue

There 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 flows from Redclyffe to Tuai via the 110 kV:

Redclyffe–Tuai circuits, and

Fernhill–Redclyffe circuits and Fernhill–Tuai circuit (as per the blue load arrows in Figure 13-5).

In these situations, an outage of one Fernhill–Redclyffe circuit can overload the other circuit.

Figure 13-5: Power flow from Redclyffe to Tuai during high load and low Tuai generation

Gisborne

110 kV

Tuai

110 kV

110 kVWairoa

Redclyffe

220 kV

110 kV

Fernhill 110 kV

Solution

Options to relieve a remaining Fernhill–Redclyffe circuit from overloading include:

constraining-on the Waikaremoana hydro generation with a minimum value that controls the Fernhill–Redclyffe circuit power flows. Minimum generation for the 2012 winter peak is approximately 19 MW, increasing to approximately 52 MW in 2027.

unbonding the 110 kV Fernhill–Tuai circuits. This increases the impedance of the Redclyffe–Fernhill–Tuai path and reduces the power flow through the Fernhill–Redclyffe circuits. This option does not eliminate the requirement to constrain-on Waikaremoana generation but does reduce the level of minimum generation.

108

The supply transformers at Fernhill and Redclyffe have an expected end-of-life within the next 10 years and are scheduled for replacement within the next 5-10 years.



The initial application of the Investment Test indicates that the project to unbond the Fernhill–Tuai circuit is not economically beneficial within the forecast period. The estimated generation and demand growth in the region shows that this option is more likely to have an economic benefit beyond the forecast period.

13.8.3 Redclyffe–Tuai 110 kV transmission capacity


Issue

There are two 110kV Redclyffe–Tuai circuits, each rated at 57/70 MVA (summer/winter). During periods of low load and high Tuai generation, power flows from Tuai to Redclyffe (as per the blue load arrows in Figure 13-6) via the 110 kV:

Redclyffe–Tuai circuits, and

Fernhill–Tuai circuit.

In these situations, an outage of the Fernhill–Tuai circuit can overload both Redclyffe–Tuai circuits.

Figure 13-6: Power flow from Tuai to Redclyffe during low load and high Tuai generation

Gisborne

110 kV

Tuai

110 kV

110 kV

Wairoa

Redclyffe

220 kV

110 kV

Fernhill 110 kV

Solution

The 110 kV Redclyffe–Tuai circuit constraints are managed operationally by limiting the maximum Waikaremoana hydro scheme generation.

We consider the issue can be resolved operationally for the forecast period.

13.8.4 Redclyffe interconnecting transformer capacity


Issue

Two 220/110 kV interconnecting transformers at Redclyffe supply the majority of the Hawke’s Bay load (except the load at Whirinaki and Whakatu, which is supplied from the 220 kV transmission system). The transformers provide:



a nominal installed capacity of 160 MVA, and


An outage of either interconnecting transformer will overload the remaining transformer during periods of:

high load and minimal Waikaremoana generation, or

low load and high Waikaremoana generation.

The peak 110 kV load is forecast to exceed the transformers’ n-1 winter capacity by approximately 34 MW in 2012, increasing to approximately 67 MW in 2027 (see Table 13-7). The forecast assumes minimal Waikaremoana generation of 12 MW.

Table 13-7: Redclyffe 220/110 kV transformer overload forecast

Grid exit point Transformer overload (MW)


2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Redclyffe 34 37 38 42 45 47 52 57 61 64 67

Solution

The overload is presently managed operationally by transferring load (within Unison’s network) from the 110 kV transmission network to the 220 kV transmission network, and by constraining-on generation at Waikaremoana. As the Hawke’s Bay load continues to grow, more Waikaremoana generation will need to be constrained-on more frequently during an outage of an interconnecting transformer at Redclyffe.

The application of the Investment Test shows that installing a third 220/110 kV transformer or replacing the existing transformers with higher-rated units is uneconomic at present. The transformer loading can be managed operationally.

13.8.5 Fernhill supply transformer capacity

Project reference: FHL-POW_TFR-REPL-01




Issue

Two 110/33 kV transformers (rated at 30 MVA and 50 MVA) supply Fernhill’s load, providing:



(summer/winter).

The peak load at Fernhill already exceeds the transformers’ n-1 winter capacity by approximately 29 MW, and the overload is forecast to increase to approximately 42 MW in 2027 (see Table 13-8).

Table 13-8: Fernhill supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Fernhill 0.95 29 29 30 31 32 33 35 37 39 40 42

109

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).



Solution

The short-term operational solution is load transfer within the Unison network following a transformer outage.

We have discussed with Unison the possible longer-term solutions, which include replacing the 30 MVA transformer with an 80 MVA transformer.

Both the existing single-phase supply transformers at Fernhill will approach their expected end-of-life within the next 5-10 years. In addition, we also plan to convert the Fernhill 33 kV outdoor switchgear to an indoor switchboard within the next five years.

We will discuss with Unison the future supply options as well as the coordination of the transformer capacity upgrade with the transformer replacement work.

13.8.6 Gisborne 110 kV voltage quality


Issue

The Gisborne 110 kV bus voltage can fall below 99 kV when either one of the Gisborne–Tuai 1 or 2 circuits is out of service, especially during high load, low generation periods.

Solution

The short-term operational solutions are:

for planned outages, dispatch the Waikaremoana hydro station to raise the local 110 kV bus voltage to 116 kV (this is not a preferred long-term solution as it limits the maximum active power generation), or

raise the 110 kV voltage at Redclyffe.

A possible longer-term option includes installing additional 10 to 20 Mvar capacitors at Gisborne.

13.8.7 Gisborne supply capacity

Project reference: Line capacity: GIS_TUI-TRAN-EHMT-01 Transformer capacity: GIS-POW_TFR-EHMT-01

Project status/purpose: Line capacity: possible, customer-specific Transformer capacity: Base Capex, minor enhancement

Indicative timing: Line capacity: 2015 Transformer capacity: 2023

Indicative cost band: Line capacity: to be advised Transformer capacity: A

Issue

The Gisborne load is supplied by:

two 110 kV circuits, each rated at 48/59 MVA (summer/winter) from Tuai, and

two 110/50 kV transformers, providing:


n-1 capacity of 63/63 MVA110 (summer/winter).

The peak load at Gisborne is forecast to exceed the:

110

The transformers’ capacity is limited by the metering equipment; with these limits resolved, the n-1 capacity will be 73/77 MVA (summer/winter).



circuits’ n-1 capacity from 2015, and

transformers’ n-1 winter capacity by 2 MW in 2023, increasing to approximately 6 MW in 2027 (see Table 13-9).

Table 13-9: Gisborne supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Gisborne 0.98 0 0 0 0 0 0 0 0 2 4 6

Solution

A short-term solution is to manage the load at Gisborne to within the circuits’ or supply transformers’ n-1 capacity.

A possible longer-term solution includes:

thermally upgrade, or reconductor part or all of both Gisborne–Tuai circuits, and

recalibrating the supply transformers’ metering parameters, which will resolve the overloading issue for the forecast period and beyond.

13.8.8 Redclyffe supply transformer capacity

Project reference: RDF-POW_TFR-EHMT-01




Issue

Two 110/33 kV transformers (rated at 40 MVA and 50 MVA) supply Redclyffe’s load, providing:



(summer/winter).

The peak load at Redclyffe already exceeds the transformers’ n-1 winter capacity by approximately 27 MW, and the overload is forecast to increase to approximately 47 MW in 2027 (see Table 13-10).

Table 13-10: Redclyffe supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Redclyffe 0.97 27 33 34 35 36 37 40 42 44 46 47

Solution

We have entered into an agreement with Unison to replace the existing transformers with two 120 MVA transformers that will provide a secure supply within the forecast period and beyond.

13.8.9 Tuai supply security


111

The transformers’ capacity is limited by LV circuit breaker and disconnector limits, followed by protection and LV bushing limits of 48 MVA; with these limits resolved, the n-1 capacity will be 49/53 MVA (summer/winter).



Issue

A single 110/11 kV, 2.2 MVA transformer supplies load at Tuai, resulting in no n-1 security. This transformer is also approaching its expected end-of-life within the next five years.

Solution

The lack of n-1 security can be managed operationally. However, we will discuss with Eastland Network Limited the options for increasing security and coordinating outages to minimise supply interruptions when replacing this transformer.

13.8.10 Wairoa supply transformer capacity


Issue

Two 110/11 kV transformers supply Wairoa‘s load, providing:



An outage of one transformer will cause the remaining transformer to exceed its n-1 summer capacity by 1 MW in 2015, increasing to 3 MW in 2027 (see Table 13-11).

Table 13-11: Wairoa supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Wairoa 0.90 0 0 0 1 1 1 1 2 2 2 3

Solution

Eastland Network Limited can manage the issue operationally.

Both Wairoa supply transformers are approaching their expected end-of-life within the next five years. We will discuss with Eastland Network the appropriate timing and capacity for the replacement transformers.


13.8.11 Whakatu supply transformer capacity


Issue

Two 220/33 kV transformers supply Whakatu‘s load, providing:



An outage of one transformer will cause the remaining transformer to exceed its n-1 winter capacity by 3 MW in 2021, increasing to 11 MW in 2027 (see



Table 13-12).



Table 13-12: Whakatu supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Whakatu 0.96 0 0 0 0 0 0 0 3 6 9 11

Solution

Unison can shift load between the Whakatu and Fernhill grid exit points.

In addition, we are planning to convert the Whakatu 33 kV outdoor switchgear to an indoor switchboard within the next five years.

Any future investment will be customer driven.



13.10 Hawke’s Bay generation proposals and opportunities



112


All generation in excess of the load is exported from the Hawke’s Bay region over the 220 kV double-circuit line from Redclyffe to Wairakei. Each circuit is rated at 478/583 MVA (summer/winter, subject to replacing some substation equipment), and there is scope for thermally upgrading the circuits to approximately 690/760 MVA (summer/winter). Additional reactive power sources such as capacitors may be required as these circuits are relatively long (137 kilometres), and they absorb reactive power when highly loaded.

Generation connected to grid exit points on the 110 kV network in the Hawke’s Bay region is exported via the Redclyffe interconnecting transformers. Each interconnecting 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, and assume existing generation is high (Waikaremoana is generating 139 MW).

For generation connected at the Redclyffe 220 kV bus, the maximum generation that can be injected under n-1 is approximately 500 MW, or approximately 550 MW if the 220 kV circuit protection constraints are removed. The constraint is due to an overload of the 220 kV Redclyffe–Wairakei circuit when the 220 kV Whirinaki–Wairakei circuit is out of service.

For generation connected at the Redclyffe 110 kV bus, the maximum generation that can be injected under n-1 is approximately 30 MW. The constraint is due to an

112




overload of the Redclyffe interconnecting transformer when the other interconnecting transformer is out of service.

13.10.2 Titiokura and Hawke’s Bay wind stations, and Tauhara geothermal station

Maungaharuru wind generation station (formerly known as Titiokura, and Hawke’s Bay wind farms) is approximately 27 km from Whirinaki, with a capacity of up to approximately 330 MW. A 220 kV double-circuit line traverses the site, and is the main supply to the Hawke’s Bay area from Wairakei.

The proposed Tauhara geothermal power station in the Central North Island region also connects to one of the 220 kV circuits to Wairakei. There are no issues with connecting the wind and geothermal generation into the same 220 kV circuits to Wairakei (see Chapter 11, Section 11.10.2).

13.10.3 Additional generation connected to the 110 kV network

There are a number of potential wind and hydro generation prospects that may connect into one or more of the 110 kV circuits in the region.

The impact new generation has on circuit loading depends on the connection’s location and configuration. For some connection locations and configurations, altering the hydro generation at Tuai removes the circuit overloads, although this may adversely impact the energy market. To increase transmission capacity, the circuits will need to be reconductored and/or the Fernhill–Tuai circuit unbonded.

The Redclyffe 220/110 kV interconnecting transformer capacity may also need to be increased to avoid overloading when there is high generation and low load, as power flows from the 110 kV transmission network into the 220 kV transmission network.

Chapter 14: Wellington Region


14 Wellington Regional Plan


14.2 Wellington transmission system

14.3 Wellington demand

14.4 Wellington generation

14.5 Wellington significant maintenance work

14.6 Future Wellington projects summary and transmission configuration


14.8 Wellington transmission capability


14.10 Wellington generation proposals and opportunities


This chapter details the Wellington regional transmission plan. We base this regional plan on an assessment of available data, and welcome feedback to improve its value to all stakeholders.

Figure 14-1: Wellington region



The Wellington region is the major load centre (comprising both residential and central business district loads) of the southern North Island. Other than the main cities making up the greater Wellington region, the area also covers the rural service centres, particularly in the Wairarapa.

We have assessed the Wellington region’s transmission needs over the next 15 years while considering longer-term development opportunities. Specifically, the transmission network needs to be flexible to respond to a range of future service and technology possibilities, taking into consideration:


forecast demand

forecast generation



14.2 Wellington transmission system

This section highlights the state of the Wellington regional transmission network. The existing transmission network is set out geographically in

Figure 14-1 and schematically in Figure 14-2.

Figure 14-2: Wellington transmission schematic

220 kV

220 kV

110 kV

110 kV

110 kV

110 kV

110 kV

110 kV110 kV

110 kV

110kV CIRCUIT

SUBSTATION BUS

TRANSFORMER

TEE POINT

KEY

220kV CIRCUIT

LOAD

CAPACITOR33 kV

33 kV

11 kV

11 kV

UNDERGROUND CABLE

33 kV

33 kV

33 kV11 kV

33 kV

33 kV

33 kV

33 kV

3 WDG TRANSFORMER

SYNCH CONDENSOR

REACTOR

HVDC

110 kV

Masterton

CENTRAL NORTH ISLANDMangamaire

Greytown

Upper Hutt

Haywards

Gracefield

Melling

Central Park

Wilton

Kaiwharawhara

Takapu

Road

Pauatahanui

Paraparaumu


BunnythorpeMangahao

11 kV

33 kV

West Wind

33 kV

SC

SCSC

SC

SC

SC SC SC SC

HVDC LINKHVDC


The Wellington region is connected to the rest of the National Grid through 220 kV circuits from Bunnythorpe and the HVDC inter-island link. It is a main corridor for through transmission between the North and South Islands. The loading of the



circuits in the main corridor depends largely on HVDC power flow from the South Island, and generation from the Central North Island.

The North Island terminal of the HVDC link is at Haywards. The HVDC link can transfer up to 666 MW to the South Island (this value highly depends on the load and generation in the Wellington region), and receive up to 700 MW from the South Island (with a 200 MW emergency capacity with pole 1B). We are carrying out a project to replace Pole 1 of the inter-island HVDC link with a new pole in 2012. The new pole (Pole 3), together with the existing Pole 2, will increase the capacity of the overall HVDC link to 1,000 MW from 2012, and 1,200 MW from 2014. Once Pole 3 is built, Pole 1 will be 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.


The region has some of the higher load densities in the North Island, coupled with relatively low levels of local generation.

Transmission within the Wellington region comprises:

220 kV circuits entering the region from Bunnythorpe

110 kV circuits entering the region from Mangamaire

HVDC link supporting the 220 kV transmission network at Haywards, and

interconnecting transformers located at Haywards and Wilton.

The 2012 Wellington regional plan considers the transmission network from December 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.


It is expected that no new major transmission lines will be required into the Wellington region. However, reconductoring of some existing lines for increased capacity may be required, 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 may be required for increased security to Wellington city, if this is shown to be economically justified.

In addition, there will be incremental upgrades within existing substations to increase security of supply within the region, particularly to Wellington city.

14.3 Wellington demand

The after diversity maximum demand (ADMD) for the Wellington region is forecast to grow on average by 1.4% annually over the next 15 years, from 756 MW in 2012 to 934 MW by 2027. This is lower than the national average demand growth of 1.7% annually.


113) for the Wellington region. The forecasts are derived using

historical data, and modified to account for customer information, where appropriate. The power factor at each grid exit point is also derived from historical data, and is

113




used to calculate the real power capacity for power transformer and transmission line. See Chapter 4 for more information about demand forecasting.

Figure 14-3: Wellington region after diversity maximum demand forecast

Table 14-1 lists the peak demand forecast (prudent growth) at each grid exit point for the forecast period, as required for the Grid Reliability Report.

Table 14-1: Forecast annual peak demand (MW) for Wellington grid exit points to 2027


Peak demand (MW)


2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Central Park 11 kV 0.98 27 33 33 34 34 35 36 37 38 39 40

Central Park 33 kV 0.98 175 174 177 181 184 188 196 203 209 216 220

Gracefield 0.98 60 61 62 64 65 66 69 71 74 76 77

Greytown1 0.93 16 17 17 17 18 18 19 20 20 21 21

Haywards 11 kV 0.99 23 24 24 24 25 25 26 27 28 29 30

Haywards 33 kV 0.98 20 20 21 21 22 22 23 24 25 25 26

Kaiwharawhara 0.97 43 44 45 46 47 48 50 52 53 55 56

Masterton1 0.97 51 52 53 54 55 56 59 61 63 64 66

Melling 11 kV 0.98 30 31 31 32 33 33 35 36 37 38 39

Melling 33 kV 0.99 50 51 52 53 54 55 57 60 61 63 64

Pauatahanui 0.98 23 24 24 25 25 26 26 27 28 29 30

Paraparaumu 0.98 68 69 70 71 71 72 74 76 77 79 81

Takapu Road 0.99 103 105 107 110 112 114 119 123 128 132 137

Upper Hutt 0.99 37 37 38 38 39 40 41 42 43 44 45

Wilton 0.99 65 66 68 69 70 72 75 77 80 82 84

1. Customer expects strong growth in demand at the Greytown and Masterton grid exit points.

200

300

400

500

600

700

800

900

1000

1997 1999 2001 2003 2005 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027

Load (MW)

Wellington

2011 APR Forecast

2012 APR Forecast

Actual Peak



14.4 Wellington generation

The Wellington region’s generation capacity is 165 MW, which is much lower than the local load. Most of the generation capacity is from wind stations, the largest being West Wind at 143 MW.

Table 14-2 lists the generation forecast for each grid injection point for the forecast period, as required for the Grid Reliability Report. This includes all known and committed generation stations, including those embedded within the relevant local lines company’s network (Wellington Electricity Lines Limited, Powerco, and Electra).

114

No new generation is known to be committed in the Wellington region for the forecast period.

Table 14-2: Forecast annual generation capacity (MW) for Wellington grid injection points to 2027 (including existing and committed generation)




2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Central Park (Southern Landfill)

1 1 1 1 1 1 1 1 1 1 1

Central Park (Wellington Hospital)

8 8 8 8 8 8 8 8 8 8 8

Greytown (Hau Nui) 9 9 9 9 9 9 9 9 9 9 9

Masterton (Kourarau A and B)

1 1 1 1 1 1 1 1 1 1 1

Haywards (Silverstream)

3 3 3 3 3 3 3 3 3 3 3

West Wind 143 143 143 143 143 143 143 143 143 143 143

HVDC – Haywards 220 kV

1 HVDC

North Transfer 1000 1000 1200 1200 1200 1200 1200 1200 1200 1200 1200

1. The fourth cable may be installed after 2017 as an additional stage in the HVDC development, increasing the HVDC link capacity to 1,400 MW.

14.5 Wellington significant maintenance work


115 proposed for the Wellington region for the




Central Park 110/33 kV supply transformers expected end-of-life

2012-2014

The option to replace or to extend the existing transformers’ operational lives is under investigation. See Section 14.8.2 for more information.

Central Park–Wilton 2 and 3 circuits reconductoring

2018-2019

Maintenance work. See Section 14.9.1 for more information.

Gracefield 33 kV switchgear replacement


114






Greytown 33 kV outdoor to indoor conversion

2019-2021

Resolving the metering and protection limits will solve the transformers’ n-1 capacity issue for the forecast period. See Section 14.8.3 for more information.

Haywards supply transformers expected end-of-life, and 33 kV outdoor to indoor conversion

2013-2015

2015-2017

The forecast loads connected at 33 kV and 11 kV buses will exceed the transformers’ capacity from 2012. See Section 14.8.4 for more information.

Mangahao–Paraparaumu circuits reconductoring

2017-2018 Permanent system split at Paraparaumu. See Section14.8.8 for more information.

Masterton supply transformers expected end-of-life

2011-2013 A project is underway to replace the transformers with two higher-rated units. See Section 14.8.6 for more information.

Melling 110/33 kV supply transformers expected end-of-life

2020-2023

The forecast load will exceed the transformer’s n-1 capacity from 2022 (assuming the metering limit is resolved). See Section 14.8.7 for more information.

Pauatahanui supply transformer T1 expected end-of-life

2019-2020 The forecast load will exceed the transformers' n-1 capacity from 2012. See Section 14.8.9 for more information.

Takapu Road outdoor to indoor conversion

2012-2014 Resolving the protection and metering limits will solve the transformers’ n-1 capacity until 2014. See Section 14.8.10 for more information.

Upper Hutt supply transformers expected end-of-life, and 33 kV outdoor to indoor conversion

2027-2028

2013-2015

Resolving the protection and metering limits will solve the transformer’s n-1 capacity for the forecast period. See Section 14.8.11 for more information.

Wilton 110 kV bus rationalisation, and 33 kV outdoor to indoor conversion

2012-2014 2013-2015

See Section 14.8.12 for more information.

14.6 Future Wellington projects summary and transmission configuration

Table 14-4 lists projects to be carried out in the Wellington region within the next 15 years.

Figure 14-4 shows the possible configuration of Wellington transmission in 2027, with new assets, upgraded assets, and assets undergoing significant maintenance within the forecast period.

Table 14-4: Projects in the Wellington region up to 2027


Central Park Replace 110/33 kV supply transformers. Base Capex

Central Park–Wilton

Reconductor Central Park–Wilton 2 and 3 circuits. Base Capex

Gracefield Replace 33 kV switchgear. Base Capex

Greytown Increase metering and protection limits on the supply transformers. Convert 33 kV outdoor switchgear to an indoor switchboard.


Haywards HVDC Pole 3. Replace all Haywards supply transformers with two 110/33/11 kV units.

Committed Base Capex

Mangahao–Paraparaumu

Reconductor Mangahao–Paraparaumu circuits. Base Capex

Masterton Replace existing supply transformer with two higher-rated units. Committed

Melling Increase metering and protection limits on the 110/33 kV and 110/11 kV supply transformers, respectively. Replace 110/33 kV supply transformer.


Paraparaumu Install capacitors on the Paraparaumu 33 kV bus, an additional supply transformer(s) at Paraparaumu, or a new grid exit point.

Possible

Pauatahanui Replace supply transformer T1. Base Capex




Takapu Road Resolve protection and metering limits on the supply transformers. Convert 33 kV outdoor switchgear to an indoor switchboard. Replace existing supply transformers with higher-rated units.

Base Capex Base Capex Possible

Upper Hutt Resolve protection and metering limits on the supply transformers Replace supply transformer. Convert 33 kV outdoor switchgear to an indoor switchboard.


Wilton 110 kV bus rationalisation. Convert 33 kV outdoor switchgear to an indoor switchboard. Resolve protection limits on the supply transformers Install a new 220/110 kV interconnecting transformer.


Figure 14-4: Possible Wellington transmission configuration in 2027

220 kV

220 kV

110 kV

110 kV

110 kV

110 kV

110 kV

110 kV

110 kV

110 kV

33 kV

33 kV

11 kV

11 kV

33 kV

33 kV

33 kV

11 kV

33 kV

33 kV

33 kV

33 kV

110 kV

Masterton

CENTRAL NORTH ISLANDMangamaire

Greytown

Upper Hutt

Haywards

Gracefield

Melling

Central Park

Wilton

Kaiwharawhara

Takapu

Road

Pauatahanui

Paraparaumu


Bunnythorpe

Mangahao

11 kV

33 kV

(1) The transmission backbone section identifies two

possible development paths for the lower North Island:

- upgrade existing lines, and


Although this diagram shows upgrading of the existing

lines, it is not intended to indicate a preference as both

options are still being investigated.

West Wind

110 kV

33 kV

(2) Although this diagram shows the new Wellington

interconnecting transformer at Wilton, it is not

intended to indicate a preference as various options

are still being investigated.

KEY

(2)

Otaki

HVDC

SCSC

SC SC SC SC

SC SC

STC STC

HVDC

33 kV

NEW ASSETS

UPGRADED ASSETS

ASSETS SCHEDULED

FOR REPLACEMENT

* MINOR UPGRADE

*

*

*

*

(1)




Issue Change

Greytown supply transformer capacity New issue.

Haywards–Melling transmission capacity New issue.



14.8 Wellington transmission capability

Table 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 issues

Section number

Issue

Regional

14.8.1 Wellington regional transmission security


14.8.2 Central Park supply transformer capacity

14.8.3 Greytown supply transformer capacity

14.8.4 Haywards supply transformer capacity and security

14.8.5 Kaiwharawhara supply capacity and security

14.8.6 Masterton supply transformer capacity

14.8.7 Melling supply capacity

14.8.8 Paraparaumu transmission security and supply transformer capacity

14.8.9 Pauatahanui supply transformer capacity

14.8.10 Takapu Road supply transformer capacity

14.8.11 Upper Hutt supply transformer capacity

14.8.12 Wilton supply transformer capacity

14.8.1 Wellington regional transmission security

Project reference: WIL-POW_TFR-DEV-03




Issue

The Wellington 110 kV transmission network is predominantly supplied by 220/110 kV interconnecting transformers, with three transformers at Haywards and one transformer at Wilton.

The three Haywards transformers have:



The Wilton transformer has:


n-1 capacity of 293/306 MVA (summer/winter)

The loading of these interconnecting transformers depends on the Wellington 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 the outage of the Wilton interconnecting transformer. In this case, the Haywards interconnecting transformers will exceed their n-1 winter capacity from approximately 2015 (depending on Wellington load, HVDC transfer magnitude, and direction).



Solution

We are investigating options for a new 250 MVA transformer in the Wellington transmission network.

14.8.2 Central Park supply transformer capacity

Project reference: CPK-POW_TFR-DEV-01




Issue

Three 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:



(summer/winter).

The peak load at Central Park for the combined 33 kV and 11 kV load is forecast to exceed the transformers’ n-1 winter capacity by approximately 2 MW in 2015, increasing to approximately 45 MW in 2027 (see Table 14-7)

Two 33/11 kV transformers supply Central Park’s 11 kV load, providing:



(summer/winter).

The peak load at Central Park 11 kV is forecast to exceed the transformers’ n-1 winter capacity by approximately 3 MW in 2013, increasing to approximately 10 MW in 2027 (see Table 14-7).

Table 14-7: Central Park supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Central Park 110/33 kV

0.98 0 0 0 2 6 11 19 27 34 41 45

Central Park 33/11 kV

0.98 0 3 4 4 5 5 6 7 8 9 10

Solution

Possible solutions include the following.

For the 110/33 kV supply transformer capacity issue:

resolving the LV cable limit (will solve the issue until 2016)

replacing the transformers with higher capacity units (see later), and

limiting the load to within the capacity of the transformers.

For the 33/11 kV supply transformer capacity issue:

operationally managing the transformer overload (resolving the transformers’ protection limit will not solve the transformer overload issue),

116

The transformers’ capacity is limited by the LV cable; with this limit resolved, the n-1 capacity will be 217/228 MVA (summer/winter).

117 The transformers’ capacity is limited by the LV protection equipment; with this limit resolved, the n-1 capacity will be 29/30 MVA (summer/winter).



The two 100 MVA supply transformers at Central Park are approaching their expected end-of-life within the next five years. Options include extending the transformers’ lives or replacing them with 120 MVA units. While 120 MVA units will increase the supply capacity, on their own they will not resolve the capacity issue in the long term.

We will discuss future supply options with Wellington Electricity. Future investment will be customer driven.

14.8.3 Greytown supply transformer capacity

Project reference: GYT-POW_TFR-EHMT-01




Issue

Two 110/33 kV transformers supply Greytown’s load, providing:



(summer/winter).

The peak load at Greytown is forecast to exceed the transformers’ n-1 summer capacity by approximately 1 MW in 2016, increasing to approximately 4 MW in 2027 (see Table 14-8).

Table 14-8: Greytown supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Greytown 0.93 0 0 0 0 1 1 2 2 3 4 4

Solution

Recalibrating the metering will solve the overload issue until 2021, and resolving the protection limit will solve the transformers’ n-1 capacity issue within the forecast period.

In addition, we also plan to convert the Greytown 33 kV outdoor switchgear to an indoor switchboard within the next 5-10 years.

14.8.4 Haywards supply transformer capacity and security

Project reference: HAY-POW_TFR-DEV-01




Issue

The 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 in no n-1 security. This load can be back fed through the Wellington Electricity network.

118

The transformers’ capacity is limited by metering equipment, followed by protection equipment (23 MVA), and tap changer (24 MVA) limits; with these limits resolved, the n-1 capacity will be 26/27 MVA (summer/winter).



The Haywards 33 kV peak load is forecast to exceed the transformer’s capacity by approximately 1 MW in 2012, increasing to approximately 7 MW in 2027 (see Table 14-9).

One 110/11 kV, 20 MVA transformer supplies the load at the 11 kV bus resulting in no n-1 security. Wellington Electricity can backfeed some load through their network, and the Haywards local service transformer.

The Haywards 11 kV peak load is forecast to exceed the transformer’s capacity by approximately 3 MW in 2012, increasing to approximately 10 MW in 2027 (see Table 14-9).

Table 14-9: Haywards supply transformer overload forecast




2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Haywards 33 kV 0.98 1 1 2 2 2 3 4 5 5 6 7

Haywards 11 kV 0.99 3 4 4 5 5 6 7 8 9 9 10

Solution

We are discussing future supply options with Wellington Electricity. The short-term solution is to manage the load operationally. A possible long-term option is to replace the supply transformers with two new 110/33/11 kV, 60 MVA transformers, providing n-1 security to both the 11 kV and 33 kV buses.

Both supply transformers at Haywards are approaching their expected end-of-life within the next five years. We will discuss the appropriate rating and timing of the replacement transformers with Wellington Electricity.

14.8.5 Kaiwharawhara supply capacity and security

Project status/purpose: This is for information only

Issue

The Kaiwharawhara load is supplied by119

:

two 110 kV circuits, each rated at 56/66 MVA120

(summer/winter) from Wilton, and

two 110/11 kV supply transformers, providing:



(summer/winter).

Kaiwharawhara peak load occurs during the summer period. The Kaiwharawhara substation is configured with no 110 kV bus (each transformer is connected to one 110 kV circuit only in a transformer-feeder arrangement) and is operated with a split 11 kV bus. Tripping either one of the transformer feeders will result in a loss of supply 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 10 MW in 2012, increasing to approximately 22 MW in 2027 (see Table 14-10), and

119

The permanent arrangement for Kaiwharawhara is described. There is a temporary, higher capacity transformer at Kaiwharawhara, which does not affect the total load that can be supplied from Kaiwharawhara.

120 The Kaiwharawhara–Wilton circuits are limited by the cable rating; with this limit resolved, the n-1 capacity will be 56/68 MVA (summer/winter).

121 The transformers’ capacity is limited by the 11 kV circuit breaker owned by the local distribution company; with this limit resolved, the n-1 capacity will be 42/44 MVA (summer/winter).



circuits’ n-1 summer capacity from 2017.

Table 14-10: Kaiwharawhara supply transformer overload forecast




2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Kaiwharawhara 0.97 10 11 12 12 13 14 16 18 20 21 22

Solution

Wellington Electricity considers the issue can be managed operationally by transferring excess load to other grid exit points through the distribution network. Future investment will be customer driven.

14.8.6 Masterton supply transformer capacity

Project reference: MST-POW_TFR-DEV-01




Issue

Two 110/33 kV transformers supply Masterton’s load, providing:



(summer/winter).

The peak load at Masterton is forecast to exceed the transformers’ n-1 winter capacity by approximately 17 MW in 2012, increasing to approximately 32 MW in 2027 (see Table 14-11).

Table 14-11: Masterton supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Masterton 0.97 17 18 19 20 22 23 25 27 29 31 32

Solution

We have entered into an agreement with Powerco to replace the existing transformers with two 60 MVA units. These will provide n-1 security at Masterton for the forecast period and beyond.

If a transformer failure occurs before commissioning of the new units, Powerco can transfer some load as an interim operational measure.

14.8.7 Melling supply capacity

Project reference: Circuit capacity upgrade: HAY_MLG-TRAN-EHMT-01 Resolve protection and metering limits: MLG-POW_TFR-EHMT-01

Project status/purpose: Circuit capacity upgrade: possible, customer-specific Resolve protection and metering limits: Base Capex, minor enhancement

Indicative timing: Circuit capacity upgrade: 2023 Resolve protection and metering limits: 2012

Indicative cost band: Circuit capacity upgrade: to be advised Resolve protection and metering limits: A

122

The transformers’ capacity is limited by transformer bushings; with this limit resolved, the n-1 capacity will be 37/40 MVA (summer/winter).



Issue

The Melling load is supplied by:

two 110 kV circuits, each rated at 95/101 MVA (summer/winter) from Haywards.

two 110/33 kV transformers supplying Melling’s 33 kV load, providing:



(summer/winter).

two 110/11 kV transformers supplying Melling’s 11 kV load, providing:



(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 winter capacity from 2023

the 33 kV load is forecast to exceed the transformers’ n-1 winter capacity by 2 MW in 2012, increasing to approximately 16 MW in 2027 (see Table 14-12), and

the 11 kV load is forecast to exceed the transformers’ n-1 winter capacity by 2 MW in 2012, increasing to approximately 11 MW in 2027 (see Table 14-12).

Table 14-12: Hayward–Melling circuit and Melling supply transformer overload forecast

Circuits/Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Hayward–Melling N/A 0 0 0 0 0 0 0 0 1 4 6

Melling 33 kV 0.99 2 3 4 5 6 7 9 11 13 15 16

Melling 11 kV 0.98 2 3 3 4 5 5 7 8 9 10 11

Solution

Possible solutions include the following.

For the 110 kV circuit capacity, use the short-term rating for the circuit, thermally upgrade the circuits, or reconductor the line.

For the 110/33 kV supply transformer capacity, resolving the metering limit will solve the transformers’ n-1 winter capacity issue until 2022.

For the 110/11 kV supply transformer capacity, resolving the protection limit will solve 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 at Melling to the supply transformers’ and circuit’s capacity. A possible longer-term solution is to develop the distribution network to limit the load within the capacity of the circuits and transformers.

In addition, both Melling 110/33 kV supply transformers have an expected end-of-life within the next 5-10 years. We will discuss the appropriate rating and timing for the replacement transformers with Wellington Electricity. Future investment will be customer driven.

123

The transformers’ capacity is limited by metering equipment; with this limit resolved, the n-1 capacity will be 64/67 MVA (summer/winter).

124 The transformers’ capacity is limited by HV protection equipment; with this limit resolved, the n-1 capacity will be 32/34 MVA (summer/winter).



14.8.8 Paraparaumu transmission security and supply transformer capacity

Project reference: PRM-POW_TFR-DEV-01

Project status/purpose: Possible, to meet the Grid Reliability Standard (not core grid) and customer-specific

Indicative timing: New capacitors: 2013 A third supply transformer or new grid exit point: 2015

Indicative cost band: New capacitors: A A third supply transformer: B A new grid exit point: C

Issue

The Paraparaumu load is supplied by:

two 110 kV circuits, each rated at 95/105 MVA (summer/winter), from Takapu Road via Pauatahanui to Paraparaumu

two 110 kV circuits, each rated at 49/60 MVA (summer/winter), from Mangahao to Paraparaumu, and

two 110/33 kV supply transformers, providing:



A system split is permanently in place north of Paraparaumu. This prevents the 110 kV circuits becoming a parallel path to the 220 kV Bunnythorpe–Haywards circuits and consequently constraining those circuits. Paraparaumu substation is also configured with a split 110 kV bus.

The issues at Paraparaumu involve the following:

Paraparaumu’s forecast peak load will exceed the supply transformers’ n-1 winter capacity by approximately 4 MW in 2012, increasing to approximately 17 MW in 2027 (see Table 14-13).

An outage of one Paraparaumu–Pauatahanui–Takapu Road circuit will cause the remaining circuit to:

exceed the n-1 capacity of the Paraparaumu–Pauatahanui circuit section from 2012, and

exceed the n-1 capacity of the Pauatahanui–Takapu Road circuit section from 2015.

Table 14-13: Paraparaumu supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Paraparaumu 0.98 4 5 5 6 7 8 10 11 13 15 17

Solution

The Paraparaumu peak load occurs for only a short period each day during winter evenings. Possible interim solutions include:

post-contingency load reduction, or

operating the supply transformers at their short-term thermal ratings over the short peak period, and/or

installing capacitors at the Paraparaumu 33 kV bus.

Possible long-term solutions include:

an additional supply transformer (or transformers) at Paraparaumu, supplied from the Mangahao–Paraparaumu circuits, so the Paraparaumu load is divided into two grid exit points, or



a new grid exit point near Paraparaumu (Otaki) supplied from the Mangahao–Paraparaumu circuits. Some of the load at Paraparaumu can be transferred to the new grid exit point.

An additional supply transformer (or transformers) and/or a new grid exit point will allow some load to be supplied from the south via Pauatahanui from Takapu Road, while the rest is supplied from the north via Mangahao from Bunnythorpe. Following some contingencies during periods of high load, it will be necessary to transfer load from the ‘north’ to the ‘south’ infeed to prevent some circuit overloading.

Property issues are not anticipated for the new capacitors and/or additional supply transformers at Paraparaumu because the existing substation has sufficient room to accommodate the new equipment. However, designated land will be required for the new grid exit point near Paraparaumu.

We are discussing future supply options with Electra. Future investment will be customer driven.

14.8.9 Pauatahanui supply transformer capacity

Project status/purpose: This is for information only

Issue

Two 110/33 kV transformers supply Pauatahanui’s load, providing:



The peak load at Pauatahanui is forecast to exceed the transformers’ n-1 winter capacity by approximately 1 MW in 2012, increasing to approximately 8 MW in 2027 (see Table 14-14).

Table 14-14: Pauatahanui supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Pauatahanui 0.98 1 1 2 2 3 3 4 5 6 7 8

Solution

One supply transformer at Pauatahanui will approach its expected end-of-life within the next 5-10 years. We will discuss future supply options with Wellington Electricity. Future investment will be customer driven.

14.8.10 Takapu Road supply transformer capacity

Project reference: Increase protection and metering limits: TKR- POW_TFR-EHMT-01 Upgrade transformer’s capacity: TKR-POW_TFR-DEV-01

Project status/purpose: Increase protection and metering limits: Base Capex, minor enhancement Upgrade transformer’s capacity: possible, customer-specific

Indicative timing: Increase protection and metering limits: Q4 2012 Upgrade transformer’s capacity: to be advised

Indicative cost band: Increase protection and metering limits: A Upgrade transformer’s capacity: B

Issue

Two 110/33 kV transformers supply Takapu Road’s load, providing:





(summer/winter).

The peak load at Takapu Road is forecast to exceed the transformers’ n-1 winter capacity by approximately 17 MW in 2012, increasing to approximately 51 MW in 2027 (see Table 14-15)

Table 14-15: Takapu Road supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Takapu Road 0.99 17 19 22 24 26 28 33 38 42 47 51

Solution

Resolving the protection and metering equipment limits will solve the overload issue until 2014. We will discuss future options with Wellington Electricity. In the short term, we will manage the load operationally. Possible longer-term options include:

replacing the existing supply transformers with two 120 MVA units and limit the load growth to the transformers’ n-1 capacity

installing a third supply transformer, and

transferring load to another grid exit point.


In addition, we also plan to convert the Takapu Road 33 kV outdoor switchgear to an indoor switchboard within the next five years.

14.8.11 Upper Hutt supply transformer capacity

Project reference: UHT- POW_TFR-EHMT-01




Issue

Two 110/33 kV transformers supply Upper Hutt’s load, providing:



(summer/winter).

The peak load at Upper Hutt is forecast to exceed the transformers’ n-1 winter capacity by approximately 1 MW in 2012, increasing to approximately 9 MW in 2027 (see Table 14-16).

Table 14-16: Upper Hutt supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Upper Hutt 0.99 1 1 2 2 3 3 5 6 7 8 9

125

The transformers’ capacity is limited by protection, followed by metering equipment (110 MVA) limits; with these limits resolved, the n-1 capacity will be 111/116 MVA (summer/winter).

126 The transformers’ capacity is limited by protection equipment, followed by the metering (41MVA) limits; with these limits resolved, the n-1 capacity will be 51/54 MVA (summer/winter).



Solution

Resolving the protection equipment limit and recalibrating the metering parameters will provide sufficient n-1 capacity for the forecast period.

In addition, the Upper Hutt 33 kV outdoor switchgear will be converted to an indoor switchboard within the next five years. Also, both the supply transformers have an expected end-of-life at the end of the forecast period. We will discuss the rating and timing for these replacement transformers with Wellington Electricity. Future investment will be customer driven.

14.8.12 Wilton supply transformer capacity

Project reference: WIL- POW_TFR-EHMT-01




Issue

Two 220/33 kV transformers supply Wilton’s load, providing:



(summer/winter).

The peak load at Wilton is forecast to exceed the transformers’ n-1 winter capacity by approximately 1 MW in 2023, increasing to approximately 5 MW in 2027 (see Table 14-17).

Table 14-17: Wilton supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Wilton 0.99 0 0 0 0 0 0 0 0 1 3 5

Solution

Resolving the protection equipment limit will provide sufficient n-1 capacity for the forecast period.

In addition, the Wilton 33 kV outdoor switchgear will be converted to an indoor switchboard within the next five years. We will also investigate the options to rationalise the Wilton 110 kV bus for better maintenance safety and increased Wilton supply security.


14.9.1 Central Park supply security during maintenance

There 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 loss of one transformer connected in series with the circuit.

Wellington Electricity has indicated concern over a lack of supply security at Central Park. When a circuit is taken out of service for maintenance, a loss of another circuit during high load periods will cause the third supply transformer to overload and trip, resulting in a total loss of supply.

127

The transformers’ capacity is limited by protection, followed by cable (112 MVA) limits; with these limits resolved, the n-1 capacity will be 116/121 MVA (summer/winter).



This issue is being addressed in the short term by installing a 110/33 kV special protection scheme at Central Park to automatically shed load. This issue can be addressed in the long term by installing a 110 kV bus at Central Park.

14.10 Wellington generation proposals and opportunities



128

See also Chapter 11, Section 11.10.3 for more information about connecting wind generation in the Bunnythorpe/Wellington region.

14.10.1 Generation connection options - general

Most of the transmission network in the region is used to supply load rather than connect generation. In general, there are no issues with connecting up to several hundred megawatts of generation to these circuits. Higher generation levels reverse the power flow direction, and approach the circuits’ ratings. As a result, depending on where 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.

14.10.2 Puketiro wind station

This proposed wind generation station can connect to the 220 kV circuits between Bunnythorpe and Haywards/Wilton. There are no regional transmission capacity issues with connecting this generation, although the capacity of the grid backbone may sometimes limit generation.

14.10.3 Long Gully wind station

A wind generation station at Long Gully embedded within the 33 kV distribution system at Central Park will not cause any connection issues.

14.10.4 Generation connection to the 110 kV network in the Wairarapa area

There is a 110 kV double-circuit line from Haywards to Upper Hutt, Greytown, and Masterton, and a single-circuit line from Masterton to Mangamaire and Woodville (in the Central North Island region).

The amount of generation that can be installed depends on its location along the 110 kV line, and any line upgrades. Approximately 230 MW of generation can connect at Masterton under normal operating conditions. Other generation locations and upgrade options may result in maximum generation levels ranging from approximately 0 (zero)-230 MW.

128


Chapter 15: Nelson-Marlborough Region


15 Nelson-Marlborough Regional Plan


15.2 Nelson-Marlborough transmission system

15.3 Nelson-Marlborough demand

15.4 Nelson-Marlborough generation

15.5 Nelson-Marlborough significant maintenance work

15.6 Future Nelson-Marlborough projects summary and transmission configuration


15.8 Nelson-Marlborough transmission capability


15.10 Nelson-Marlborough generation proposals and opportunities


This chapter details the Nelson-Marlborough regional transmission plan. We base this regional plan on an assessment of available data, and welcome feedback to improve its value to all stakeholders.

Figure 15-1: Nelson-Marlborough region



The Nelson-Marlborough region includes a mix of significant and growing provincial cities (Nelson, and Blenheim) together with smaller rural service centres.

We have assessed the Nelson-Marlborough region’s transmission needs over the next 15 years while considering longer-term development opportunities. Specifically, the transmission network needs to be flexible to respond to a range of future service and technology possibilities, taking into consideration:


forecast demand

forecast generation



15.2 Nelson-Marlborough transmission system

This section highlights the state of the Nelson-Marlborough regional transmission network. The existing transmission network is set out geographically in Figure 15-1 and schematically in Figure 15-2.

Figure 15-2: Nelson-Marlborough transmission schematic

Upper Takaka

Cobb

WEST COAST

110 kV

220 kV

Argyle

110 kV

Stoke

110kV CIRCUIT

66kV CIRCUIT

SUBSTATION BUS

TRANSFORMER

KEY

220kV CIRCUIT

33 kV

33 kV

33 kV

LOAD

CAPACITOR

3 WDG TRANSFORMER

REACTOR

GENERATOR

66 kVMotupipi

66 kV

66 kV

Blenheim

110 kV

Kikiwa

66 kV

Kikiwa

Motueka

11 kV

66 kV


The Nelson-Marlborough region is connected to the rest of the National Grid via 220 kV circuits from the Waitaki Valley with significant load off-take in the South Canterbury and Canterbury regions. Therefore, supply to the Nelson-Marlborough region is affected by transmission capacity from the Waitaki Valley.

The region is predominantly supplied by three 220 kV circuits between the Islington and Kikiwa substations, with some generation from the hydro power stations connected at Cobb (which is strategic to the Golden Bay spur) and Argyle.


The transmission within the region comprises:

220 kV circuits from Kikiwa to Stoke

parallel 110 kV circuits forming a ‘triangle’ between Kikiwa, Stoke, and Blenheim



220/110 kV and 110/66 kV interconnecting transformers at Stoke, and

a 66 kV transmission spur supplying the Golden Bay area.

The reactive power support in this region is provided from the 60 Mvar capacitors at Stoke and 20.4 Mvar capacitors at Blenheim.


The two existing 220 kV Kikiwa–Stoke circuits have enough capacity to provide n-1 security within the region for the next 20-30 years.

As the Nelson-Marlborough region relies on generation several hundred kilometres away, there will be an on-going need for investment in reactive support (such as the STATCOM at Kikiwa and additional capacitors) to support the voltage.

The 110 kV Blenheim–Argyle–Kikiwa line may need upgrading if there is more than one significant new generator connected along the line, at Blenheim or embedded behind the Blenheim grid exit point.

Increased 220/110 kV interconnecting transformer capacity will be required beyond the forecast period at Kikiwa and/or Stoke. The capacity of the 110 kV Kikiwa–Stoke circuit may also need to be increased as this circuit is an important connection between 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 Stoke to Motueka to 110 kV. This conversion does not need to be investigated until approximately 2020, with possible implementation in approximately 2025.

15.3 Nelson-Marlborough demand

The after diversity maximum demand (ADMD) for the Nelson-Marlborough region is forecast to grow on average by 1.4% annually over the next 15 years, from 243 MW in 2012 to 298 MW by 2027. This is lower than the national average demand growth of 1.7% annually.


129) for the Nelson-Marlborough region. The forecasts are


129




Figure 15-3: Nelson-Marlborough region after diversity maximum demand forecast

Table 15-1 lists the peak demand forecast (prudent growth) for each grid exit point for the forecast period, as required for the Grid Reliability Report.

Table 15-1: Forecast annual peak demand (MW) at Nelson-Marlborough grid exit points to 2027


Peak demand (MW)


2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Blenheim 0.98 80 82 84 86 88 90 94 98 102 106 110

Motueka 0.98 20 21 21 21 22 22 22 23 24 24 25

Motupipi 0.95 8 8 9 9 9 9 10 10 10 10 11

Stoke1 1.00 144 147 149 152 155 158 164 169 175 181 186

1. Additional 4 MW load allowed at Stoke from 2012 for any migration of load from Canterbury due to the earthquakes.

15.4 Nelson-Marlborough generation

The Nelson-Marlborough region’s generation capacity is 56 MW, which is lower than local demand, requiring power to be imported through the National Grid.

Table 15-2 lists the generation forecast for each grid injection point for the forecast period, as required for the Grid Reliability Report. This includes all known generation stations, including those embedded within the relevant local lines company’s network (Network Tasman or Marlborough Lines).

130

No new generation is known to be committed in the Nelson-Marlborough region for the forecast period.

130


100

120

140

160

180

200

220

240

260

280

300

1997 1999 2001 2003 2005 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027

Load (MW) Nelson-Marlborough

2011 APR Forecast

2012 APR Forecast

Actual Peak



Table 15-2: Forecast annual generation capacity (MW) at Nelson-Marlborough grid injection points to 2027 (including existing and committed generation)




2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Argyle - Branch River Scheme

11 11 11 11 11 11 11 11 11 11 11

Cobb 32 32 32 32 32 32 32 32 32 32 32

Blenheim (Lulworth Wind)

1 1 1 1 1 1 1 1 1 1 1

Blenheim (Marlborough Lines Diesel)

9 9 9 9 9 9 9 9 9 9 9

Blenheim (Waihopai) 3 3 3 3 3 3 3 3 3 3 3

Motupipi (Onekaka) 1 1 1 1 1 1 1 1 1 1 1

15.5 Nelson-Marlborough significant maintenance work

Our capital project and maintenance works are integrated to enable system issues to be resolved if possible when assets are replaced or refurbished. Table 15-3 lists the significant maintenance related work

131 proposed for the Nelson-Marlborough region

for the next 15 years that may significantly impact related system issues or connected parties.



Blenheim supply transformers expected end-of-life

2018-2020 The option to replace or extend transformer life is under investigation.

Blenheim 33 kV capacitor banks replacement

2015-2017 See Chapter 6 for information about the Upper South Island voltage issue. The rating of replacement capacitors is yet to be determined.

Stoke 11 kV capacitor bank replacement

2014-2016 See Chapter 6 for information about the Upper South Island voltage issue. The rating of replacement capacitors is yet to be determined.

Stoke 110/66 kV interconnecting transformer expected end-of-life

2019-2021 Upgrading the transformer’s capacity is one of the possible options to resolve the transformer overloading issue. See Section 15.8.2 for more information

Stoke supply transformers expected end-of-life, and 33 kV outdoor to indoor conversion

2012-2014 The supply transformer replacement work is currently underway. See Section 15.8.7 for more information.

15.6 Future Nelson-Marlborough projects summary and transmission configuration

Table 15-4 lists projects to be carried out in the Nelson-Marlborough region within the next 15 years.

Figure 15-4 shows the possible configuration of Nelson-Marlborough transmission in 2027, with new assets, upgraded assets, and assets undergoing significant maintenance within the forecast period.

131




Table 15-4: Projects in the Nelson-Marlborough region up to 2027


Blenheim Replace supply transformers. Replace 33 kV capacitor banks.


Brightwater New grid exit point. Possible

Motueka Upgrade supply transformer branch limiting components. New capacitors.

Base Capex Possible

Motueka-Stoke Upgrade conductor capacities. Possible

Motupipi New capacitor. Possible

Riwaka New grid exit point. Preferred

Stoke New 110/66 kV interconnecting transformer. Replace 110/66 kV interconnecting transformer. Replace 220/33 kV supply transformers with two higher-rated units. Convert 33 kV outdoor switchgear to an indoor switchboard. Replace 11 kV capacitor banks.

Preferred Base Capex Committed Base Capex Base Capex

Figure 15-4: Possible Nelson-Marlborough transmission configuration in 2027

66 kV

66 kV110 kV

220 kV

110 kV

110 kV

66 kV

NEW ASSETS 33 kV

33 kV

33 kV

Motupipi

66 kV

Upper Takaka

Cobb

Stoke

Blenheim

Argyle Kikiwa

WEST COASTKikiwa

220 kV

33 kV

Riwaka66 kV 33 kV

Brightwater

Motueka

11 kV

66 kV

UPGRADED ASSETS

ASSETS SCHEDULED

FOR REPLACEMENT

KEY

*

* MINOR UPGRADE



Table 15-5: Changes Since 2011

Issues Change

Stoke 220/110 kV interconnecting transformer capacity New issue.

Kikiwa–Stoke 110 kV transmission capacity New issue.

15.8 Nelson-Marlborough transmission capability

Table 15-6 summarises issues involving the Nelson-Marlborough region for the next 15 years. For more information about a particular issue, refer to the listed section number.



Table 15-6: Nelson-Marlborough region transmission issues

Section number

Issue

Regional

15.8.1 Stoke 220/110 kV interconnecting transformer capacity



15.8.3 Cobb–Motueka 66 kV transmission capacity

15.8.4 Motueka supply transformer capacity

15.8.5 Motupipi single supply security

15.8.6 Kikiwa–Stoke 110 kV transmission capacity

15.8.7 Stoke supply transformer capacity


Project reference: STK-POW_TFR-DEV-01

Project status/purpose: Resolving station equipment limits: Base Capex, minor enhancement



Issue

A single 220/110 kV interconnecting transformer at Stoke provides a 110 kV interconnection to the Nelson-Marlborough region. This transformer has:




The Stoke 220/110 kV transformer is effectively operating in parallel with the 150 MVA interconnecting transformer at Kikiwa. An outage of the Kikiwa transformer results in the Stoke transformer supplying the Nelson-Marlborough and West Coast regions

133 and may cause the Stoke transformer to overload. The loading on the

Stoke transformer depends on the generation in the Nelson-Marlborough and West Coast regions.

Solution

In the short term, this issue will be managed operationally via generation rescheduling and load management. Removing station equipment constraints on the interconnecting 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.


Project reference: STK-POW_TFR-EHMT-02

Project status/purpose: Preferred, customer-specific



132

The transformer’s capacity is limited by 110 kV disconnectors; with this limit resolved, the n-1 capacity will be 180/188 MVA (summer/winter).

133 The normal operating arrangement is only Kikiwa T2 (150 MVA) provides a 110 kV interconnection to the West Coast region, and Kikiwa T1 (50 MVA) supplies the local 11 kV load.



Issue

The Golden Bay loads at the Motueka and Motupipi grid exit points are supplied by:

a single 23 MVA 110/66/11 kV transformer at Stoke, and

the Cobb generation station.

With no Cobb generation, the peak load at Golden Bay is forecast to exceed the Stoke transformer’s continuous rating by approximately 5 MW in 2012, increasing to approximately 11 MW in 2027 (see Table 15-7).

Table 15-7: Stoke 110/66 kV transformer overload forecast

Grid exit point

Power factor


Next 5 years 5-15 Years out

2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Golden Bay 0.98 5 5 6 6 7 7 8 9 10 11 11

Solution

The short-term operational solution requires Cobb to generate at a minimum output to avoid overloading the Stoke transformer.

We are discussing longer-term solutions with Network Tasman and Trustpower. The preferred option is to install a 40 MVA transformer in parallel with the existing interconnecting 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 raise property issues as the existing substation has sufficient room to accommodate the new transformer.


15.8.3 Cobb–Motueka 66 kV transmission capacity


Issue

The 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), and

Cobb–Upper Takaka 1 circuit rated at 29/35 MVA (summer/winter).

An outage of one of the Cobb–Motueka 2, Motueka–Upper Takaka 1 or Cobb–Upper Takaka 1 circuits will limit the Cobb generation station’s output.

Solution

The issue is managed operationally with an automatic generation runback scheme to constrain Cobb generation to match the remaining circuit’s rating. This is considered adequate and future investment will be customer driven.

15.8.4 Motueka supply transformer capacity

Project reference: Upgrade protection: MOT-POW_TFR_PTN-EHMT-01

New capacitors: MOT-C_BANKS-DEV-01 New grid exit point: MOT-SUBEST-DEV-01

Project status/purpose: Upgrade protection: Base Capex, minor enhancement

New capacitors and grid exit point: preferred, customer-specific

Indicative timing: Upgrade protection: 2012



New capacitors: 2013 New grid exit point: 2016

Indicative cost band: Upgrade new capacitor: A New grid exit point: C

Issue

Two 66/11 kV transformers supply Motueka’s load, providing:



(summer/winter).

The peak load at Motueka is forecast to exceed the transformers’ n-1 winter capacity by approximately 2 MW in 2012, increasing to approximately 7 MW in 2027 (see Table 15-8).

Table 15-8: Motueka supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Motueka 0.98 2 2 3 3 3 4 4 5 5 6 7

Solution

We have discussed future supply options with Network Tasman. We will raise the protection limit to provide a short-term solution. The preferred long-term development option involves:

installing capacitors at Motueka, which extends the transformer’s real power capacity, and

establishing a new grid exit point near Riwaka, connecting to the 66 kV Stoke–Upper Takaka lines.

Installing new capacitor banks does not raise new property issues as the existing substation has sufficient room to accommodate the new equipment. Network Tasman has designated land for the new Riwaka grid exit point.

15.8.5 Motupipi single supply security


Issue

Motupipi is supplied by a single 66 kV circuit from Upper Takaka, which means it has no n-1 security. The forecast load growth at Motupipi will not exceed the present circuit rating for the forecast period and beyond.

Motupipi’s point of connection is the 66 kV line termination, so the loading of the supply transformer rests with the customer.

Solution

The lack of n-1 security can be managed operationally. However, we will discuss options for increasing security with Network Tasman. Future investment will be customer driven.

134

The transformers’ capacity is limited by protection limit, followed 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).



15.8.6 Kikiwa–Stoke 110 kV transmission capacity

Project reference: KIK_STK-TRAN-EHMT-01


Indicative timing: Beyond 2020


Issue

There are two 110 kV circuits connecting the Nelson-Marlborough and West Coast regions:

Kikiwa–Stoke 3 circuit rated at 56/68 MVA (summer/winter), and

Kikiwa–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 kV circuits. The Kikiwa–Stoke 3 circuit may overload when Nelson-Marlborough region load is high coupled with low local generation.

Solution

This issue can be managed operationally by constraining generation levels at Cobb and Argyle. A longer-term solution is to thermally upgrade the Kikiwa–Stoke 110 kV circuit.

15.8.7 Stoke supply transformer capacity

Project reference: Replace transformer: STK-POW_TFR-EHMT-01

New grid exit point: STK-SUBEST-DEV-01

Project status/purpose: Replace transformer: committed, replacement New grid exit point: possible, customer-specific

Indicative timing: Replace transformer: 2012-2014 New grid exit point: 2015

Indicative cost band: Replace transformer: C New grid exit point: C

Issue

Three 220/33 kV transformers supply Stoke’s load, providing:



(summer/winter).

The peak load at Stoke already exceeds the transformers’ n-1 winter capacity, and the overload is forecast to increase to approximately 76 MW in 2027 (see Table 15-9).

Table 15-9: Stoke supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Stoke 1.00 33 36 39 42 45 48 53 59 65 70 76

Solution

The supply transformers are made up of single-phase units with a contracted on-site spare, allowing replacement within 8-14 hours following a unit failure.

135




We are replacing the existing transformers with two 120 MVA units with a post contingency rating of 143 MVA, which gives an additional 29 MVA n-1 capacity. The transformer 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 kV Kikiwa–Stoke circuits. Network Tasman has designated land for a new grid exit point.

The existing single-phase supply transformers at Stoke are approaching their end-of-life within the next five years. We also plan to convert the Stoke 33 kV outdoor switchgear to an indoor switchboard. The replacement of these transformers and the 33 kV outdoor to indoor conversion will be coordinated.


15.9.1 Golden Bay voltage quality and transmission security

Project reference: New capacitor: MOT-C_BANKS-DEV-01 Upgrade conductor: STK_UTK-TRAN-EHMT-01



Indicative cost band: New capacitor: A Upgrade conductor: to be advised

Issue

Two 66 kV circuits connect Cobb generation to the transmission grid. Disconnection of Cobb generation from the grid during a planned maintenance outage of the Cobb–Upper Takaka 1 circuit and loss of the Cobb–Motueka–Stoke 2 circuit, causes low voltage and transmission security issues at Golden Bay.

Solution

Possible development options include:

installing capacitors at Motueka and/or Motupipi for voltage support, and reducing voltage step post contingency, or

upgrading the limiting conductor on the Stoke–Upper Takaka A and B lines.

Installation of capacitor banks at Motueka will also help to extend the Motueka supply transformers’ n-1 real power capacity for the forecast period and beyond (see Section 15.8.4).

15.10 Nelson-Marlborough generation proposals and opportunities



136


Maximum generation estimates assume a light South Island load profile, and that high generation in the Nelson-Marlborough region (with Cobb generating 27 MW).

136




For generation connected at the Stoke 220 kV bus, the maximum generation that can be injected under n-1 is approximately 380 MW. The constraint is due to the 220 kV Kikiwa–Stoke circuit overloading when the other circuit is out of service.

Generation up to approximately 150 MW can be connected at the Blenheim 110 kV bus, or to the two 110 kV Blenheim–Stoke circuits. Higher levels of generation (approximately 170 MW generation injection under n-1) requires a protection upgrade on the Blenheim–Stoke 1 circuit. Further increases require a thermal upgrade of the 110 kV Blenheim–Argyle–Kikiwa circuit.

15.10.2 Generation on the Blenheim–Argyle–Kikiwa circuit

Blenheim–Argyle–Kikiwa is a single 110 kV circuit rated at 56/68 MVA. The maximum generation that can be connected to this circuit depends on the location of the connection. With all circuits in service, approximately 50 MW can be connected, in addition to the existing generation injected at Argyle. Generation levels above this will need to be embedded within the Marlborough Lines network. Generation restrictions may also be needed for some outages. Alternatively, increasing the rating of the circuit is also technically possible.

15.10.3 Generation connection to the 66 kV network

The existing Cobb hydro generation station is already connected to the 66 kV transmission network, and its output must occasionally be constrained if a circuit is out of service or to prevent overloading of the Stoke 110/66 kV transformer.

Approximately 10 MW of additional generation can be connected if controls are installed to automatically reduce generation for some outages, and the Stoke 110/66 kV transformer capacity is increased. The 66 kV transmission lines have a variety of conductor types and ratings. Thermally upgrading or replacing the sections with the lowest capacities allows an additional 15-30 MW of generation before the remaining sections require upgrading.

Chapter 16: West Coast Region


16 West Coast Regional Plan


16.2 West Coast transmission system

16.3 West Coast demand

16.4 West Coast generation

16.5 West Coast significant maintenance work

16.6 Future West Coast projects summary and transmission configuration


16.8 West Coast transmission capability


16.10 West Coast generation proposals and opportunities


This chapter details the West Coast regional transmission plan. We base this regional plan on an assessment of available data, and welcome feedback to improve its value to all stakeholders.

Figure 16-1: West Coast region



The West Coast region includes a mix of provincial towns (Dobson, Greymouth, Hokitika), and smaller, lower-growth rural localities.

We have assessed the West Coast region’s transmission needs over the next 15 years while considering longer-term development opportunities. Specifically, the transmission network needs to be flexible to respond to a range of future service and technology possibilities, taking into consideration:


forecast demand

forecast generation



16.2 West Coast transmission system

This section highlights the state of the West Coast regional transmission network. The existing transmission network is set out geographically in Figure 16-1 and schematically in Figure 16-2.

Figure 16-2: West Coast transmission schematic


The West Coast region is connected to the National Grid via a 220/110 kV interconnection at Kikiwa and two 66 kV circuits from Coleridge. The 220/110 kV interconnection at Kikiwa is effectively operating in parallel with the transformer at Stoke.



The regional generation is lower than the regional demand. Most of the regional load is supplied from remote generation in the Waitaki Valley, with significant load off-take in the South Canterbury and Canterbury regions.


The transmission within the region:

comprises 110 kV and 66 kV transmission circuits, with two 110/66 kV interconnecting transformers at Dobson

connects to the rest of the National Grid through two 220/110 kV interconnecting transformers at Kikiwa (one on standby) and two 66 kV circuits at Coleridge, and

derives reactive support from a STATCOM at Kikiwa and capacitor banks at Greymouth and Hokitika.

Most of the assets at Orowaiti, Reefton, Atarau, Greymouth, and Hokitika are owned by the associated local lines company (Westpower or Buller Network).

The West Coast load is mostly supplied from the northern infeed, with power flowing through the region via the:

110 kV circuits from Kikiwa to Dobson via Inangahua, and

110 kV spur from Inangahua to Westport via Orowaiti.

The second 110 kV Inangahua–Reefton–Dobson circuit and a new interconnecting transformer at Dobson were recently commissioned to reinforce the 110 kV transmission network from the northern infeed.

Some loads are fed from the south via low capacity 66 kV circuits from Coleridge, which also provide significant support to the region.


The 220/110 kV interconnection at Kikiwa is effectively operating in parallel with the transformer at Stoke. In the longer term, transformer capacity needs to be increased at Kikiwa and/or Stoke to meet load growth and transmission security requirements to the West Coast region.

Possible transmission reinforcement via a third 110 kV circuit connecting between Kikiwa and Inangahua, additional reactive support, 66 kV transmission reconfiguration (Kawhaka bonding), and Dobson–Greymouth capacity upgrades may be required to support the load growth and transmission security in the West Coast region in the longer term.

The above system developments may also be required for generation developments. If there is a significant increase in generation, then some of the circuits between Kikiwa and Inangahua may need to be operated at 220 kV.

16.3 West Coast demand

The after diversity maximum demand (ADMD) for the West Coast region is forecast to grow on average by 2.7% annually over the next 15 years, from 70 MW in 2012 to 104 MW by 2027. This is higher than the national average demand growth of 1.7% annually.


137) for the West Coast region. The forecasts are derived

using historical data, and modified to account for customer information, where

137

The after diversity maximum demand (ADMD) for the region will be less than the sum of the individual grid exit points peak demands, as it takes into account the fact that the peak demand does not occur simultaneously at all the grid exit points in the region.



appropriate. The power factor at each grid exit point is also derived from historical data, and is used to calculate the real power capacity for power transformer and transmission line. See Chapter 4 for more information about demand forecasting.

Figure 16-3: West Coast region after diversity maximum demand forecast

Table 16-1 lists forecast peak demand (prudent growth) for each grid exit point in the West 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 2027

Grid exit point

Power factor

Peak demand (MW)


2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Arthur’s Pass 0.99 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5

Atarau1 1.00 1.0 11.0 11.0 11.0 11.0 11.0 11.0 11.0 11.0 11.0 11.0

Castle Hill 1.00 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9

Dobson2 0.98 16.0 16.3 16.6 20.9 21.2 21.5 26.1 26.6 27.2 27.7 28.0

Greymouth 0.98 15.0 15.3 15.6 15.9 16.2 16.6 17.2 17.8 18.4 18.9 19.3

Hokitika3 0.98 16.8 17.0 19.8 20.0 20.3 20.5 21.0 21.5 21.9 22.4 22.7

Kikiwa 0.99 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0

Kumara 0.95 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0

Murchison 0.99 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0

Orowaiti4 1.00 11.0 19.2 19.3 19.5 19.7 19.9 20.2 20.5 20.9 21.2 21.4

Otira 0.78 0.9 0.9 0.9 0.9 0.9 1.9 1.9 1.9 1.9 1.9 1.9

Reefton 0.99 11.0 11.2 11.4 11.7 11.9 12.1 12.6 13.1 13.5 13.9 14.2

Westport 0.96 10.2 10.3 10.5 10.6 10.8 10.9 11.3 11.6 11.9 12.2 12.4

1. The customer advised of a possible load increase in 2013.

2. The customer advised of a possible load increase in 2015 and 2019.

3. The customer advised of a possible load increase in 2014.

4. The customer advised of a possible new load in 2013.

0

20

40

60

80

100

120

140

1997 1999 2001 2003 2005 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027

Load (MW) West Coast

2011 APR Forecast

2012 APR Forecast

Actual Peak



16.4 West Coast generation

The West Coast region’s generation capacity is 20 MW, which is lower than the local demand and the deficit is imported through the National Grid.

Table 16-2 lists the generation forecast for each grid injection point in the West Coast region for the forecast period, as required for the Grid Reliability Report. This includes all known generation stations including those embedded within the relevant local lines company’s network (Westpower, Buller Networks, Network Tasman, or Orion)

138.

Kumara does not have significant water storage but is expected to supply a minimum of 2 MW during summer peaks. The construction of the 6 MW Amethyst hydro project is currently underway and is expected to be operational by 2013.

Table 16-2: Forecast annual generation capacity (MW) at West Coast grid injection points to 2027 (including existing and committed generation)




2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Dobson (Arnold) 3 3 3 3 3 3 3 3 3 3 3

Hokitika (Amethyst)

0 6 6 6 6 6 6 6 6 6 6

Hokitika (McKays Creek)

1 1 1 1 1 1 1 1 1 1 1

Hokitika (Wahapo-Okarito Forks)

3 3 3 3 3 3 3 3 3 3 3

Kumara (Kumara and Dillmans)

1

10 10 10 10 10 10 10 10 10 10 10

Kumara (Hokitika Diesel)

3 3 3 3 3 3 3 3 3 3 3

1. Kumara and Dillmans share the same water and are offered into the market as a single 10 MW generator.

16.5 West Coast significant maintenance work


139 proposed for the West Coast region for the




Arthur’s Pass supply transformer expected end-of-life

2013-2015 No n-1 security at Arthur’s Pass. Future investment will be customer-driven. See Section 16.8.2 for more information.

Castle Hill supply transformer expected end-of-life

2012-2014 No n-1 security at Castle Hill. Future investment will be customer-driven. See Section 16.8.5 for more information.

Murchison supply transformer expected end-of-life

2016-2018 No n-1 security at Murchison. Future investment will be customer-driven. See Section 16.8.7 for more information.

138





16.6 Future West Coast projects summary and transmission configuration

Table 16-4 lists projects to be carried out in the West Coast region within the next 15 years.

Figure 16-4 shows the possible configuration of West Coast transmission in 2027, with new assets, upgraded assets and assets undergoing significant maintenance within the forecast period.

Table 16-4: Projects in the West Coast region up to 2027


Arthur’s Pass Replace supply transformer. Base Capex

Castle Hill Replace supply transformer. Base Capex

Dobson Resolve protection limits on the supply transformers. Replace supply transformers with higher-rated units. Install new capacitors.

Base Capex Possible Possible

Inangahua–Murchison–Kikiwa

Increase the line thermal capacity. Possible

Kikiwa Replace Kikiwa T1 with a higher-rated unit. Possible

Murchison Replace supply transformer. Base Capex

Figure 16-4: Possible West Coast transmission configuration in 2027

66 kV

66 kV

66 kV

66 kV

66 kV

110 kV

11 kV

110 kV

66 kV66 kV

NELSON - MARLBOROUGH

CANTERBURY

33 kV

Stoke

11 kV

110 kV

11 kV

110 kV

220 kV

CANTERBURY

Islington

StokeArgyle

110 kV

Kikiwa

Murchison

Inangahua

Waimangaroa

OrowaitiWestport

Dobson

Atarau33 kV

Reefton

11 kV

Kumara

Otira

Arthur’s Pass

Castle Hill

Coleridge

11 kVSTC

110 kV

Greymouth

Hokitika

11 kV

*

NEW ASSETS

UPGRADED ASSETS

ASSETS SCHEDULED

FOR REPLACEMENT

KEY

* MINOR UPGRADE






Issues Change

West Coast 110 kV and 66 kV transmission security

Removed. This is no longer an issue with the commissioning of Hokitika capacitors and the second Dobson–Reefton circuit.

Kikiwa interconnecting transformer capcity New issue.

West Coast low voltage New issue.

Hokitika transmission capacity New issue.

16.8 West Coast transmission capability

Table 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.

Table 16-6: West Coast region transmission issues

Section number

Issue

Regional

16.8.1 Inangahua–Murchison–Kikiwa transmission capacity

16.8.2 Kikiwa interconnecting transformer capacity

16.8.3 West Coast low voltage


16.8.4 Arthur’s Pass transmission and supply security

16.8.5 Castle Hill transmission and supply security

16.8.6 Dobson supply transformer capacity

16.8.7 Hokitika transmission capacity

16.8.8 Murchison transmission and supply security

16.8.9 Otira supply security

16.8.1 Inangahua–Murchison–Kikiwa transmission capacity

Project context: Modelled project in the West Coast Grid Upgrade Plan (approved in July 2008). Commission cost recovery approval has not yet been sought.

Project reference: IGH_KIK-TRAN-EHMT-01



Indicative cost band: Thermal upgrade: A Special protection scheme: To be advised

Issue

There are two parallel 110 kV circuits between Inangahua and Kikiwa, which include the:

110 kV Inangahua–Murchison–Kikiwa circuit, rated at 56/68 MVA (summer/winter), and

110 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 from approximately 2017, and

low voltage at the West Coast 110 kV bus from approximately 2021 (see Section 16.8.3 for more information).



Solution

Possible options to resolve the transmission capacity issue include:

thermally upgrading the 110 kV Inangahua–Murchison–Kikiwa circuit, or

a 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 that this option has no overall economic benefit. We are investigating other options to resolve this issue.

See 16.8.3 for possible options to resolve the low voltage issue.

Easements may be required for some parts of the thermal upgrade project.

16.8.2 Kikiwa interconnecting transformer capacity


Issue

There are two 220/110 kV interconnecting transformers at Kikiwa, T1 and T2 rated at 50 MVA and 150 MVA, respectively. The normal operating arrangement is to have Kikiwa T1 supply the local 11 kV load only and Kikiwa T2 provide a 110 kV interconnection to the West Coast region. Kikiwa T2 also operates in parallel with a 150 MVA interconnecting transformer at Stoke (Nelson-Marlborough region) due to the 110 kV network connections between them.

The loss of one 150 MVA interconnecting transformer at Stoke will cause the Kikiwa interconnecting transformer to overload under certain conditions, including a combination of:

regional peak loads, and

low generation in the West Coast and Nelson-Marlborough regions.

Solution

This issue can be managed operationally by Cobb and Kumara generation within the forecast period. Transpower will work with the generators to manage this constraint.

A possible longer-term option is to replace Kikiwa T1 with a higher-rated transformer and operate in parallel with Kikiwa T2 and the interconnecting transformer at Stoke.

16.8.3 West Coast low voltage

Project reference: WCST-REA_SUP-DEV-01



Indicative cost band: New capacitors: A Special protection scheme: To be advised

Issue

Low voltage will occur at the Atarau 110 kV bus following an outage of a:

110 kV Inangahua–Kikiwa 2 circuit from 2021, or

Kikiwa T2 interconnecting transformer from 2024.

The low voltage issue progressively arises at other buses with increasing load in the West Coast region.



Solution

We are investigating options to mitigate the low voltage issues. A local voltage quality agreement may be appropriate in the short term for 110 kV voltages. Possible transmission solutions include:

installing new capacitors at West Coast

a special protection scheme to shed load post contingency, and

replacing Kikiwa T1 with a higher-rated transformer and operate in parallel with the Kikiwa T2 interconnecting transformer (this option also resolves the Kikiwa interconnecting transformer capacity issue described in Section 16.8.2).

16.8.4 Arthur’s Pass transmission and supply security


Issue

The two circuits supplying Arthur’s Pass do not have circuit breakers at Arthur’s Pass. A fault on either circuit will cause a loss of supply to Arthur’s Pass, resulting in no n-1 security.

Additionally, a single 66/11 kV, 3 MVA transformer supplies load at Arthur’s Pass resulting in no n-1 security. This transformer is also approaching its expected end-of-life within the next five years.

Solution

The lack of n-1 security can be managed operationally. There is a non-contracted on-site spare transformer, allowing possible replacement within 8-14 hours following a unit failure (if the spare unit is available). However, we will discuss options with Orion for increasing security and coordinating outages to minimise supply interruptions when replacing this transformer.

16.8.5 Castle Hill transmission and supply security


Issue

The two circuits supplying Castle Hill do not have line protection to clear faults. A fault on either circuit will cause a loss of supply to Castle Hill, resulting in no n-1 security.

Additionally, a single 66/11 kV, 3.75 MVA transformer supplies load at Castle Hill resulting in no n-1 security. This transformer is also approaching its expected end-of-life within the next five years.

Solution

The lack of n-1 security can be managed operationally. There is a non-contracted on-site spare transformer, allowing possible replacement within 8 to 14 hours following a unit failure (if the spare unit is available). However, we will discuss with Orion options for increasing security and coordinating outages to minimise supply interruptions when replacing this transformer.

16.8.6 Dobson supply transformer capacity

Project reference: Upgrade protection: DOB-POW_TFR_PTN-EHMT-01 Upgrade transformer capacity: DOB-POW_TFR-EHMT-01

Project status/purpose: Upgrade protection: Base Capex, minor enhancement Upgrade transformer capacity: possible, customer-specific



Indicative timing: Upgrade protection: 2014 Upgrade transformer capacity: 2015-2017

Indicative cost band: Upgrade protection: A Upgrade transformer capacity: B

Issue

Two 66/33 kV transformers supply Dobson’s load, providing:



(summer/winter).

The peak load at Dobson is forecast to exceed the transformers’ n-1 winter capacity by approximately 1 MW in 2014, increasing to approximately 12 MW in 2027 (see Table 16-7). This forecast makes the assumption that Arnold generation is 3 MW. If Arnolad generation decreases, the issue may arise earlier.

Table 16-7: Dobson supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Dobson 0.98 0 0 1 5 5 6 10 11 11 12 12

Solution

Resolving the transformers’ protection and LV cable limits will provide sufficient n-1 capacity until 2018. We will look into raising the protection limits which will resolve the overload issue until 2015.

Possible longer-term options include increasing the embedded generation at Dobson which we are discussing with Westpower and Trustpower. Operational measures or replacing the existing supply transformers with two 40 MVA units are also possible longer-term options.


16.8.7 Hokitika transmission capacity


Issue

Two circuits supply the Hokitika grid exit point:

Hokitika–Kumara rated at 27/32 MVA (summer/winter), and

Hokitika–Otira rated at 27/32 MVA (summer/winter)

An outage of one circuit will cause the other to exceed its thermal capacity when Kumara generation is low.

The 66 kV line from Coleridge to Kumara is predominantly strung with a copper conductor, and therefore cannot be thermally upgraded.

Solution

This issue can be managed operationally by Kumara generation within the forecast period.

140

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).



Transpower is also investigating an option to upgrade the 66 kV transmission network by bonding the copper circuits around Hokitika and Kumara, resulting in two higher-capacity circuits to Hokitika.

16.8.8 Murchison transmission and supply security


Issue

The two circuits supplying Murchison do not have any circuit breakers at Murchison. A fault on either circuit will cause a loss of Murchison’s supply resulting in no n-1 security.

There is a short loss of supply whenever the circuits supplying Murchison are switched for maintenance.

Additionally, a single 110/11 kV, 5 MVA transformer supplies load at Murchison resulting in no n-1 security. This transformer has an expected end-of-life within the forecast period.

Solution

The lack of n-1 security can be managed operationally. We are investigating options to mitigate loss of supply to Murchison during switching for line maintenance. We will also discuss options with Network Tasman for increasing security and coordinating outages to minimise supply interruptions when replacing the Murchison supply transformer.

16.8.9 Otira supply security


Issue

A single 66/11 kV, 2.5 MVA transformer supplies load at Otira resulting in no n-1 security. Load growth is not forecast to exceed the transformer rating within the forecast period.

Solution

There is a non-contracted on-site spare transformer, allowing possible replacement within 8-14 hours following a unit failure (if the spare unit is available). The lack of n-1 security can be managed operationally.



16.10 West Coast generation proposals and opportunities


The maximum generation that can be connected depends on several factors and usually falls within a range. Generation developers should consult with us at an early



stage of their investigations to discuss connection issues. See our website for more information about connecting generation.

141


Maximum generation estimates assume a South Island light load profile and that the generation in the West Coast region is high (with Kumara generating 10 MW).

For generation connected at the Kikiwa 220 kV bus, the maximum generation that can be injected under n-1 is approximately 800 MW. The constraint is the Islington–Kikiwa 3 circuit when either one of the other two circuits connecting Islington and Kikiwa is out of service.

The estimate for maximum generation injection at the Kikiwa 110 kV bus and the Inangahua 110 kV bus assumes West Coast load of 53 MW, and the maximum generation that can be injected under n and n-1 is approximately:

285 MW and 135 MW, respectively, at the Kikiwa 110 kV bus, with the constraint being due to the Kikiwa interconnecting transformer overloading, and 110 kV Kikiwa–Stoke circuit overloading when the Kikiwa interconnecting transformer is out of service.

165 MW and 95 MW, respectively, at the Inangahua 110 kV bus, with the constraint being due to the 110 kV Inangahua–Murchison–Kikiwa 1 circuit overloading under an n condition, and under an n-1 condition when the other Inangahua–Kikiwa 2 circuit is out of service.

Depending on the point of connection, generation connection on the West Coast 66 kV transmission network may be constrained by several low capacity 66 kV circuits.

16.10.2 Generation connected to the Waimangaroa 110 kV bus

Two circuits connect Waimangaroa to Inangahua and the rest of the National Grid. The Inangahua–Waimangaroa 1 circuit is rated at 101/111 MVA (summer/winter), and has a higher rating than the Inangahua–Waimangaroa 2 circuit, which is rated at 56/68 (summer/winter). There is also a lower rating circuit connecting between Inangahua and Kikiwa.

Depending on the amount of generation connected at the Waimangaroa 110 kV bus, it may be necessary to:

join the Waimangaroa 110 kV bus

install a special protection scheme to allow unconstrained generation injection, and/or

increase the circuit capacity between Waimangaroa, Inangahua, and Kikiwa.

141


http://www.transpower.co.nz/connecting

Chapter 17: Canterbury Region


17 Canterbury Regional Plan


17.2 Canterbury transmission system

17.3 Canterbury demand

17.4 Canterbury generation

17.5 Canterbury significant maintenance work

17.6 Future Canterbury projects summary and transmission configuration


17.8 Canterbury transmission capability


17.10 Canterbury generation proposals and opportunities


This chapter details the Canterbury regional transmission plan. We base this regional plan on an assessment of available data, and welcome feedback to improve its value to all stakeholders.

Figure 17-1: Canterbury region



The Canterbury region load includes Christchurch together with smaller rural localities.

We have assessed the Canterbury region’s transmission needs over the next 15 years while considering longer-term development opportunities. Specifically, the transmission network needs to be flexible to respond to a range of future service and technology possibilities, taking into consideration:


forecast demand

forecast generation



17.2 Canterbury transmission system

This section highlights the state of the Canterbury regional transmission network. The existing transmission network is set out geographically in Figure 17-1 and schematically in Figure 17-2.

Figure 17-2: Canterbury transmission schematic

66kV CIRCUIT

SUBSTATION BUS

TRANSFORMER

TEE POINT

KEY

220kV CIRCUIT

LOAD

CAPACITOR

3 WDG TRANSFORMER

REACTOR

66 kV

SOUTH CANTERBURY

66 kV

220 kV

33 kV

WEST COAST

66 kV

220 kV

66 kV

66 kV

66 kV

66 kV

66 kV

66 kV

66 kV

66 kV

NELSON - MARLBOURGH

66 kV

Twizel33 kV

11 kV

11 kV

Tekapo B

Livingstone

11 kV

11 kV 33 kV

Kikiwa

33 kV

33 kV

33 kV

33 kV

11 kV

66 kV

Otira Castle Hill

Kikiwa

Culverden

Kaikoura

Waipara

Ashley

Southbrook

Kaiapoi

PapanuiAddington

Islington

Bromley

Springston

Hororata

Coleridge

220 kV

33 kV

66 kV

Ashburton

11 kV

Middleton

66 kV

11 kV

GENERATOR

STATIC VAR COMPENSATORsvc

SVC

SV

C

SC SYNCHRONOUS CONDENSER

SC

SC


1 June 2012


1 May 2012


The 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 electricity demand is supplied by generation located in the South Canterbury region, transmission is necessary to keep power flowing into and through the region to the top of the South Island.




From the Waitaki Valley, the region is supplied by four 220 kV transmission circuits, three from Twizel and one from Livingstone. The transmission network within this region comprises 220 kV and 66 kV transmission circuits, with 220 kV to 66 kV interconnections at Islington, Bromley, Culverden

142, and Waipara.

There are eight 220/66 kV interconnecting transformers: two at Bromley, three at Islington, two at Waipara, and one at Culverden.

Reactive support for the region (and grid backbone) is provided by:

synchronous condensers, static var compensators, and capacitor banks at Islington

capacitor banks at Bromley, and

a single 33 Mvar capacitor at Southbrook.

We have a number of projects planned or underway to support demand growth and supply security in the Canterbury region.

We have improved the dynamic voltage support and reactive power management in the region, and the upper South Island by installing a new static var compensator (SVC) at Islington, and a reactive power controller in the Christchurch area.


We are investigating transmission capacity enhancement and future reactive support requirements in the Canterbury and Upper South Island to increase both thermal constraints and voltage stability limits. This is to ensure that the Canterbury has secure transmission into and through the region, as demand continues to grow.

Beyond the next 30 years, new transmission capacity may be required into the Canterbury region. The new capacity may be provided by a new 220 kV line, HVDC tap-off or the refurbishment of the existing lines. New generation in the Upper South Island or demand-side response may defer transmission investment.

17.3 Canterbury demand

The after diversity maximum demand (ADMD) for the Canterbury region is forecast to grow on average by 2.0% annually over the next 15 years, from 817 MW in 2012 to 1,103 MW by 2027. This is higher than the national average demand growth of 1.7% annually. The Christchurch earthquakes during 2011 caused a 10-15% reduction in peak demand. The extreme snow storm during the winter of 2011 masked the reduction in demand, and winter load in 2012 is expected to be down given normal winter conditions. When the Christchurch earthquake recovery plan becomes clearer our forecast will be adjusted accordingly.


143) for the Canterbury region. The forecasts are derived using


142

At Culverden, the 220 kV to 66 kV interconnection is done in two stages, via:

two 220/33 kV transformers, stepping down the voltage to supply the local load, and

one 33/66 kV transformer stepping the voltage back up to 66 kV to supply Kaikoura. 143




Figure 17-3: Canterbury region after diversity maximum demand forecast


Table 17-1: Forecast annual peak demand (MW) at Canterbury grid exit points to 2027


Peak demand (MW)


2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Addington 11 kV -11 0.99 35 37 38 40 41 41 42 35 36 37 38

Addington 11 kV -21 0.99 25 26 27 28 28 29 29 24 25 26 26

Addington 66 kV1 0.99 133 138 142 145 148 150 149 136 139 143 146

Ashburton 33 kV2 0.92 55 56 29 29 30 15 16 8 9 9 9

Ashburton 66 kV2 0.92 133 137 149 154 158 167 176 187 194 201 207

Ashley3 0.87 12 12 13 22 23 23 24 25 26 27 28

Bromley 11 kV 0.99 56 58 60 61 62 63 61 63 65 67 69

Bromley 66 kV1 1.00 171 183 188 194 198 199 209 294 301 308 315

Coleridge 0.99 1 1 1 1 1 1 1 1 1 1 1

Culverden 33 kV4 0.97 21 21 22 25 26 27 28 29 30 31 32

Culverden 66 kV 0.99 10 10 10 11 11 11 12 12 12 13 13

Hororata 33 kV5 0.95 31 25 25 25 26 19 19 20 20 21 21

Hororata 66 kV5 0.96 27 42 32 32 36 44 44 45 46 46 47

Islington 33 kV 0.97 73 75 76 78 79 81 84 87 89 92 94

Islington 66 kV6 0.99 128 129 135 152 154 156 159 162 165 168 171

Islington 66 kV – Papanui

1

0.99 113 112 112 113 114 115 118 82 83 84 86

Kaiapoi 0.99 29 29 30 30 31 32 33 34 35 36 37

Middleton 0.97 30 31 31 32 33 33 35 36 37 38 39

Southbrook3,7

0.95 43 45 46 39 40 41 43 45 47 49 51

Springston 33 kV5 0.99 43 34 34 36 38 33 34 35 36 37 38

400

500

600

700

800

900

1000

1100

1200

1997 1999 2001 2003 2005 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027

Load (MW)

Canterbury

2011 APR Forecast

2012 APR Forecast

Actual Peak




Peak demand (MW)


2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Springston 66 kV5 0.99 21 32 48 49 50 58 61 64 66 69 72

Waipara 33 kV8 0.96 13 13 14 14 14 22 23 23 24 24 24

Waipara 66 kV 0.97 12 13 13 13 13 14 14 15 15 16 16

1. The customer has indicated load shifts planned for 2020 from Addington 11 kV, Addington 66 kV, Papanui 11 kV and Papanui 66 kV to Bromley 66 kV.

2. This forecast includes allowance for strong growth including some migration of load from Christchurch, load switching between Ashburton 33 kV and Ashburton 66 kV and a staged migration from Ashburton 33 kV over 2014 to 2021.

3. Ashley load will increase from 2015, with the addition load transferred from Southbrook.

4. The customer indicates an expected irrigation load increase in 2015.

5. The customer provided this forecast.

6. The customer advised the step change to Islington 66 kV in 2015 is due to the creation of a new zone sub "Waimakariri" which will pick up some load from Papanui 11 kV and Islington 33 kV.



17.4 Canterbury generation

The Canterbury region’s generation capacity is 79 MW, which is lower than local demand 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 forecast period, as required for the Grid Reliability Report. This includes all known and committed generation stations including those embedded within the relevant local lines company’s network (Electricity Ashburton, Orion or Mainpower).

144

No new generation is known to be committed in the Canterbury region for the forecast period.

Table 17-2: Forecast annual generation capacity (MW) at Canterbury grid injection points to 2027 (including existing and committed generation)




2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Ashburton (Highbank) 25 25 25 25 25 25 25 25 25 25 25

Ashburton (Montalto) 2 2 2 2 2 2 2 2 2 2 2

Bromley (City Waste) 3 3 3 3 3 3 3 3 3 3 3

Bromley (QE2 diesel) 4 4 4 4 4 4 4 4 4 4 4

Coleridge 45 45 45 45 45 45 45 45 45 45 45

17.5 Canterbury significant maintenance work

Our capital project and maintenance works are integrated to enable system issues to be resolved if possible when assets are replaced or refurbished.

Table 17-3 lists the significant maintenance-related work145

proposed for the Canterbury region that may significantly impact related system issues or connected parties over the next 15 years.

144







Addington 11 kV switchboard No.2 replacement Addington supply transformers expected end-of-life

2012-2014

2023-2024

Orion is planning reconfiguring its 11 kV distribution system, which will be co-ordinated with the switchboard replacement. See Section 17.9.4 for more information.

Ashley supply transformers expected end-of-life

2016-2018 The forecast load at Ashley exceeds the transformers’ n-1 capacity from 2012. See Section 17.8.3 for more information.

Bromley 220/66 kV transformers expected end-of-life

2018-2020 The forecast load at Bromley exceeds the transformers’ n-1 capacity from 2012. See Section 17.8.4 for more information.

Bromley 66/11 kV transformer’s expected end-of-life

2022-2024

No system issues are identified within the forecast period.

Bromley 11 kV reactor decommission


Hororata 33 kV outdoor to indoor conversion


Islington T3 and T7 interconnecting transformers expected-end-of-life

Islington 33 kV outdoor to indoor conversion

2022-2023

2017-2019

The peak load is forecast to exceed the transformers’ n-1 capacity from 2019. See Section 17.8.1 for more information.

Kaiapoi 11 KV switchgear replacement


Springston 33 kV outdoor to indoor conversion


Waipara 33 kV outdoor to indoor conversion


17.6 Future Canterbury projects summary and transmission configuration

Table 17-4 lists projects to be carried out in the Canterbury region within the next 15 years.

Figure 17-4 shows the possible configuration of Canterbury transmission in 2027, with new assets, upgraded assets, and assets undergoing significant maintenance within the forecast period.

Table 17-4: Projects in the Canterbury region up to 2027


Addington Replace 11 kV switchboard No.2. Replace T5, T6, and T7 supply transformers.


Ashburton Install new 220/66 kV supply transformer. Preferred

Ashley Replace existing supply transformers with higher-rated units. Base Capex

Bromley Install new 220/66 kV transformer. Replace existing 220/66 kV transformers. Replace existing 66/11 kV supply transformers. Dismantle 11 kV reactor.

Committed Base Capex Base Capex Base Capex

Culverden Replace 220/33 kV transformers with higher-rated 220/66 kV transformers.

Possible

Hororata Convert 33 kV outdoor switchgear to an indoor switchboard. Base Capex

Islington Install new 220/66 kV interconnecting transformer. Replace existing 220/66 kV interconnecting transformers. Convert 33 kV outdoor switchgear to an indoor switchboard.


Kaiapoi Replace 11 kV switchgear Base Capex

Southbrook Resolve supply transformers’ branch component limits. Possible




Install two new 66 kV feeders. Possible

Springston Convert 33 kV outdoor switchgear to an indoor switchboard. New 220/66 kV grid exit point.

Base Capex Possible

Waipara Convert 33 kV outdoor switchgear to an indoor switchboard. Base Capex

Figure 17-4: Possible Canterbury transmission configuration in 2027

66 kV

SOUTH CANTERBURY

220 kV

33 kV

WEST COAST

66 kV

220 kV

66 kV

66 kV

66 kV

66 kV

66 kV

66 kV

NELSON - MARLBOURGH

Twizel33 kV

Tekapo B

Livingstone

11 kV

11 kV 33 kV

33 kV

66 kV

33 kV

11 kV

66 kV

Otira Castle Hill

Kikiwa Kikiwa

220 kV

33 kV

33 kV

Culverden

Waipara

Ashley

Southbrook

Kaiapoi

BromleyIslington

Springston

Ashburton

66 kV

Hororata

Coleridge 66 kV

11 kV

Addington

11 kV

Middleton

66 kV

11 kV

KEY

SVCS

VC

NEW ASSETS

UPGRADED ASSETS

ASSETS SCHEDULED

FOR REPLACEMENT

* MINOR UPGRADE

*




Issues Change

Ashley supply transformer capacity New issue.

Culverden supply transformer capacity New issue.

Hororata supply transformer capacity New issue.

Kaikoura supply security and transformer capacity Removed. These assets will be transferred to Mainpower on 1 May 2012.

17.8 Canterbury transmission capability

Table 17-6 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 17-6: Canterbury region transmission issues

Section number

Issue

Regional

17.8.1 Islington 220/66 kV transformer capacity


17.8.2 Ashburton 220/66 kV supply transformer capacity

17.8.3 Ashley supply transformer capacity

17.8.4 Bromley 220/66 kV transformer capacity and voltage quality

17.8.5 Coleridge supply transformer security

17.8.6 Culverden supply transformer capacity

17.8.7 Hororata supply transformer capacity and voltage quality

17.8.8 Southbrook supply transformer capacity

17.8.9 Springston transmission capacity

17.8.10 Waipara supply transformer security

17.8.1 Islington 220/66 kV transformer capacity

Project reference: ISL-POW_TFR-DEV-01

Project status/purpose: New 220/66 kV grid exit point: possible, customer specific A fourth 220/66 kV transformer: to meet the Grid Reliability Standard (core grid)

Indicative timing: New 220/66 kV grid exit point: about 2020 A fourth 220/66 kV transformer: to be advised

Indicative cost band: New 220/66 kV grid exit point: C A fourth 220/66 kV transformer: B

Issue

Three 220/66 kV interconnecting transformers at Islington supply the loads for North Canterbury, Christchurch, and Springston, providing:



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 is 13 MW.

Solution

A staged development plan was developed in discussion with Orion. The plan’s first stage increases the 220/66 kV transformer capacity at Bromley, and transfers load from Islington to Bromley in 2019 (see Section 17.8.4). Additional longer-term development options being investigated include:

establishing a new 220/66 kV grid exit point south of Christchurch (see Section 17.9.2), which will also resolve the Springston transmission line capacity issue (see Section 17.8.9)

146.

installing a fourth 220/66 kV interconnecting transformer at Islington. This does not raise new property issues, as the existing substation has sufficient room to accommodate a new transformer. However, installing a new transformer will increase the fault level at Islington, downstream substations, and associated supply buses, which would then need resolution.

146

Acquisition of substation land is required for establishing a new 220/66 kV southern grid exit point.



17.8.2 Ashburton 220/66 kV supply transformer capacity

Project reference: New 220/66 kV transformer: ASB-POW_TFR-DEV-02 New grid exit point: ASB-SUBEST-DEV-01

Project status/purpose: New 220/66 kV transformer: preferred, customer-specific New grid exit point: possible, customer-specific

Indicative timing: New 220/66 kV transformer: 2015 New grid exit point: approximately 2020

Indicative cost band: New 220/66 kV transformer: A New grid exit point: to be advised

Issue

Two 220/66 kV transformers supply Ashburton’s 66 kV load, providing:



The Ashburton 66 kV bus is connected to embedded generation at Highbank and Montalto, 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 the transformers’ n-1 summer capacity by approximately 11 MW in 2012, increasing to approximately 84 MW in 2027 (see Table 17-7).

Table 17-7: Ashburton 220/66 kV supply transformer overload forecast




2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Ashburton (66 kV) 0.92 11 14 27 31 35 44 53 64 71 78 84

Solution

The preferred option is to install a third 220/66 kV, 120 MVA supply transformer. This will address the transformers’ n-1 capacity issue. As an interim measure, the load can be secured by transferring load to the Ashburton 33 kV transmission network and/or utilising the embedded generation.

In the longer term, load will be transferred to a new grid exit point (see Section 17.9.1).

17.8.3 Ashley supply transformer capacity

Project reference: ASY-POW_TFR-DEV-01




Issue

Two 66/11 kV transformers supply Ashley’s load, providing:



The peak load at Ashley is forecast to exceed the transformers’ n-1 winter capacity by approximately 2 MW in 2012, increasing to approximately 18 MW in 2027 (see Table 17-8).



Table 17-8: Ashley supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Ashely 0.87 2 3 3 12 13 14 15 16 16 17 18

Solution

The existing supply transformers are approaching their expected end-of-life within the next five years. We are discussing with Mainpower the appropriate rating and timing for the replacement transformers. A longer-term solution involves replacing the existing transformers with two 40 MVA units.

17.8.4 Bromley 220/66 kV transformer capacity and voltage quality

Project reference: BRY-POW_TFR-DEV-01



Indicative cost band: B (cost band for one transformer)

Issue

Two 220/66 kV transformers supply Bromley’s 66 kV and 11 kV loads, providing:



The load on the transformers is radially connected, enabling them to be analysed as supply transformers.

The peak load at Bromley is forecast to exceed the transformers’ n-1 winter capacity by approximately 80 MW in 2012, increasing to approximately 229 MW in 2027 (see Table 17-9).

Orion advises that some load from Papanui and Addington will be shifted to Bromley in 2020. This will adversely affect the voltage quality at the Bromley 220 kV and 66 kV buses for an outage of the 220 kV Bromley–Islington circuit from 2020.

Table 17-9: Bromley interconnecting transformer overload forecast




2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Bromley (66 kV) 1.00 80 93 99 106 111 113 121 203 211 220 229

Solution

Following discussions with Orion, a new 220/66 kV transformer with on-load tap changer is being installed in parallel with the two existing transformers. This will be followed by replacing the two existing transformers with higher rated units in 2019.

Both Bromley transformers have an expected end-of-life within the next 5-10 years. Installing capacitors at the Bromley transformer’s tertiary winding will resolve the low voltage issue.

Installing a new 220/66 kV transformer and capacitors does not raise any property issues, as the existing substation has sufficient room to accommodate the new equipment.



17.8.5 Coleridge supply transformer security


Issue

A single 66/11 kV, 2.5 MVA three phase supply transformer supplies the load at Coleridge, resulting in no n-1 security.

Solution

There is an off-site spare transformer that can take several days to install. Orion accepts this level of security. Future investment will be customer driven.

17.8.6 Culverden supply transformer capacity

Project reference: CUL-POW_TFR-DEV-01




Issue

Two 220/33 kV transformers supply the load at Culverden and Kaikoura, providing:



The peak load at Culverden and Kaikoura is forecast to exceed the supply transformers’ n-1 summer capacity by approximately 1 MW in 2014, increasing to approximately 12 MW in 2027 (see Table 17-10).

Table 17-10: Culverden supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Culverden 0.97 0 0 1 4 5 6 7 9 10 11 12

Solution

We are discussing options with Mainpower. Operational measures are expected to be sufficient in the short term. Longer-term options include replacing the existing supply transformers with higher capacity units and changing the operating voltage to 220/66 kV. Future investment will be customer driven.

17.8.7 Hororata supply transformer capacity and voltage quality


Issue

Hororata is supplied from:

Islington by two 66 kV Hororata–Islington circuits, each rated at 59/62 MVA (summer/winter), and

Coleridge and the West Coast by two 66 kV Coleridge–Hororata circuits, each rated at 30/37 MVA (summer/winter).

With low Coleridge generation (three of the five machines out of service), the summer n-1 capacity of the 66 kV Hororata–Islington circuits is limited to 56 MW to avoid low voltages at the Hororata 66 kV bus.



Two 66/33 kV transformers supply Hororata 33 kV load, providing:

a total nominal capacity of 34 MVA, and


(summer/winter).

Hororata’s load peaks in summer. The peak load at Hororata 33 kV is forecast to exceed the transformers’ n-1 summer capacity by approximately 11 MW in 2012 (see Table 17-11).

Table 17-11: Hororata supply transformer overload forecast




2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Hororata (33 kV) 0.95 11 5 5 5 6 0 0 0 0 1 1

Solution

There is a low voltage intertrip scheme installed at Hororata to manage the Hororata voltage quality constraint in the short term. We have discussed the supply options for the ‘Plains’ area (supplied from Springston and Hororata) with Orion.

The supply transformer capacity issue can be managed operationally in the short term by shifting load to Hororata 66 kV bus. In the longer term, Orion will shift load from the 33 kV to the 66 kV, which will remove the overload issue.


17.8.8 Southbrook supply transformer capacity

Project reference: SBK-TRAN-DEV-01




Issue

Two 66/33 kV transformers supply Southbrook’s load, providing:



(summer/winter).

Southbrook’s load peaks in summer. The peak load at Southbrook is forecast to exceed the transformers’ n-1 summer capacity by approximately 1 MW in 2013. The overload will decrease when Mainpower transfers some load from the Southbrook 33 kV bus to the 66 kV bus. However, the Southbrook load will exceed the transformers’ n-1 summer capacity again by approximately 2 MW in 2021, increasing to approximately 8 MW in 2027 (see Table 17-12).

Table 17-12: Southbrook supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Southbrook 0.95 0 1 2 0 0 0 0 2 4 6 8

147

The transformers’ capacity is limited by bus section rating; with this limit resolved, the n-1 capacity will be 23/24 MVA (summer/winter).

148 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 will be 55/57 MVA (summer/winter).



Solution

The issue can be managed operationally. Alternatively, resolving all transformers’ branch component limits will solve the overloading issue until 2027. Mainpower intends to transfer some load from the Southbrook 33 kV bus to 66 kV. This can be achieved by establishing two new 66 kV feeders from Southbrook. We are discussing the options with Mainpower. Future investment will be customer driven.

17.8.9 Springston transmission capacity


Issue

Two 66 kV Islington–Springston circuits supply Springston’s load, providing:



Springston’s load peaks in summer. The peak load at Springston is forecast to exceed the circuits’ n-1 summer capacity from 2012.

Solution

In the short term, Orion can transfer load between Springston and Hororata following a contingency.

Longer-term solutions include the following:

during 2011, Orion installed new 66 kV capacity in the area from Islington, which will relieve the loading on the existing circuits in the short term; (they intend to progressively extend the 66 kV capacity in the area to reduce load on Springston over the next 10 years), and

a new 220/66 kV grid exit point south of Christchurch to remove load from Springston (see Section 17.9.2).

In addition, we also plan to convert Springston 33 kV outdoor switchyard to an indoor switchboard within the next 5-10 years.

17.8.10 Waipara supply transformer security


Issue

A single 66/33 kV, 16 MVA transformer supplies load at Waipara resulting in no n-1 security.

Solution

Mainpower is capable of transferring load from their 33 kV to their 66 kV network, and has indicated it will continue with the present level of security. Future investment will be customer driven.


17.9.1 New Ashburton grid exit point

We are investigating a second Ashburton grid exit point to supply the distribution load to the west of Ashburton. The connection configuration for the new grid exit point is via two transformer feeders connected to the 220 kV Islington–Livingstone and



Islington–Tekapo B circuits. The new grid exit point will be required in about 4-10 years time.

17.9.2 New southern grid exit point for Orion

We are investigating one or two new 220/66 kV grid exit points for Orion south of Christchurch. The new grid exit point may connect to the 220 kV Islington–Livingstone circuit, the Islington–Tekapo B circuit, or both. The new grid exit point(s) will be required by about 2020.

17.9.3 Decommissioning of Bromley 30 Mvar reactor

Bromley has a 30 Mvar reactor connected to the tertiary of the T5 220/66/11 kV transformer. It is used to prevent high 220 kV voltages throughout the South Island during light load conditions. Following the commissioning of the second Islington SVC and the Kikiwa STATCOM, the reactor will be decommissioned in 2011.

17.9.4 Decommissioning two Addington 66/11 kV transformers

Orion is planning a staged development of their 11 kV distribution system supplied from 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 will remain. The other three transformers (T5, T6, and T7) are made up of single-phase units, and are scheduled for replacement by approximately 2023. Following discussions with Orion, the intention is to decommission T5 in approximately 2013 and decommission T6 and T7 in approximately 2019. The Addington 11 kV load will be limited to within the capacity of the two remaining transformers (n-1 capacity of 39/40 MVA summer/winter).

In addition, the Addington 11 kV No. 2 indoor switchboard is scheduled for replacement in approximately 2012. The configuration of the replacement switchboard will be compatible with the longer-term site developments.

17.9.5 Fonterra load connection at Hororata

Fonterra has constructed a new 5.5 MW dairy processing plant at Darfield in 2011/12, and planning for an additional 6 MW expansion in 2013. Further upgrades may be required in the future. The existing plant is connected to the Orion 33 kV sub-transmission network supplied from Hororata 33 kV bus.

This step load will adversely affect the voltage quality at Hororata. We are discussing options with Orion to increase the security of supply and resolve the low voltage issue at Hororata.

17.10 Canterbury generation proposals and opportunities



149

149





The 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 practical limit to the maximum generation that can be connected within the region. However, there will be limits on the maximum generation that can be connected at a substation or along an existing line due to the rating of the existing circuits.

17.10.2 Mount Cass wind station

There is a proposal to install a 60 MW (approximately) wind station at Mount Cass, which can be connected to the Waipara 66 kV bus without any restrictions when all transmission assets are in service. Generation greater than 60 MW will require automatic controls to limit generation following some outages, to prevent circuits from overloading.

17.10.3 Inland Canterbury wind sites

Wind maps show that inland Canterbury has good wind resources for wind generation, but most of the area is distant from significant transmission.

There are two 66 kV Islington–Hororata circuits rated at 60/63 MVA, and two Hororata–Coleridge circuits rated at 30/37 MVA (reconductoring a section of which increases this rating to 48/53 MVA). It is possible to connect over 100 MW of generation if connected directly to the Hororata 66 kV bus or up to approximately the rating 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 maximum generation depends on the location of the connection point, and the number of circuits it is connected to.

There is some spare capacity south of Christchurch to connect generation into the 220 kV Islington–Livingstone circuit. The primary purpose of this circuit is to supply loads in and north of Christchurch. Connecting too much generation to this circuit will overload it, and reduce the amount of load that can be supplied in and north of Christchurch. Approximately 400 MW can be connected (more if the circuit section from the Rangitata River to Islington is thermally upgraded).

Chapter 18: South Canterbury Region


18 South Canterbury Regional Plan


18.2 South Canterbury transmission system

18.3 South Canterbury demand

18.4 South Canterbury generation

18.5 South Canterbury significant maintenance work

18.6 Future South Canterbury projects summary and transmission configuration


18.8 South Canterbury transmission capability


18.10 South Canterbury generation proposals and opportunities


This chapter details the South Canterbury regional transmission plan. We base this regional plan on an assessment of available data, and welcome feedback to improve its value to all stakeholders.

Figure 18-1: South Canterbury region



The South Canterbury region includes Timaru and Oamaru (both predominantly service centres for the surrounding region) and agricultural industries (Bells Point, Black Point, Studholme, Temuka, and Waitaki).

We have assessed the South Canterbury region’s transmission needs over the next 15 years while considering longer-term development opportunities. Specifically, the transmission network needs to be flexible to respond to a range of future service and technology possibilities, taking into consideration:


forecast demand

forecast generation



18.2 South Canterbury transmission system

This section highlights the state of the South Canterbury regional transmission network. The existing transmission network is set out geographically in Figure 18-1 and schematically in Figure 18-2.

Figure 18-2: South Canterbury transmission schematic

110 kV

CANTERBURY

220 kV

OTAGO - SOUTHLAND

110 kV

110 kV

110 kV

110 kV

110 kV

220 kV

220 kV220 kV

220 kV

220 kV

220 kV

220 kV

220 kV

Cromwell Naseby33 kV

11 kV

11 kV

11 kV

11 kV220 kV

Islington

Ashburton

33 kV

33 kV

33 kV

110kV CIRCUIT

SUBSTATION BUS

TRANSFORMER

TEE POINT

KEY

220kV CIRCUIT

LOAD

CAPACITOR

33 kV

11 kV

110 kV

Temuka

Studholme

Oamaru

Timaru

Livingstone

Tekapo A

Albury

Tekapo B

Ohau A

Twizel

Ohau B

Ohau C WaitakiBlack Point

Benmore

Aviemore

GENERATOR

110 kVBells Pond

* Note: Studholme split is

closed during peak dairy

season (October-April)

Glenavy




Several major 220 kV lines serve the South Canterbury region, connecting it to Christchurch and the upper South Island to the north, and the Otago Southland region to the south.

This region contributes a major portion of the generation in the South Island, feeding the 220 kV transmission network from the Tekapo, Ohau, and Waitaki Valley generation stations. Peak load in the region (approximately 150 MW in 2011) is approximately 10% of the region’s generation capacity, so the need for transmission capacity into the region is driven by generation export requirements, and the need to transfer power from the lower South Island to the upper South Island.


The South Canterbury regional transmission network comprises 220 kV and 110 kV transmission circuits, with interconnecting transformers at Timaru and Waitaki. All significant loads in the South Canterbury region are supplied via the 110 kV transmission network running up the east coast from Oamaru to Temuka.

The 110 kV transmission network is normally split at Studholme, but this split is closed 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 transformer banks supplying Timaru, Albury, Tekapo A and Temuka, and

Waitaki 220/110 kV interconnecting transformer banks supplying Studholme, Bells Pond, Black Point, and Oamaru.

Up to 25 MW of generation is injected directly into the 110 kV transmission network from Tekapo A.

Much of the 110 kV transmission network is reaching its capacity, as are the interconnecting transformers at Timaru. This is mainly due to growth associated with the dairy industry, and irrigation in particular.

We have a number of investigations and projects planned or underway to support the demand growth and supply security in the South Canterbury region. These include:

the Lower Waitaki Reliability project, upgrading supply security to the area between the Waitaki, Oamaru and Studholme grid exit points, and

supply security upgrades at Timaru and Temuka.


The investigations underway include long-term development plans for the area. This is likely to include new 220 kV connections to offload the highly loaded 110 kV transmission network.

Some demand response may be appropriate to allow the economic connection of large rural loads such as irrigation.

18.3 South Canterbury demand

The after diversity maximum demand (ADMD) for the South Canterbury region is forecast to grow on average by 3.4% annually over the next 15 years, from 194 MW in 2012 to 303 MW by 2027. This is higher than the national average demand growth of 1.7% annually.




150) for the South Canterbury region. The forecasts are


Figure 18-3: South Canterbury region after diversity maximum demand forecast


Table 18-1: Forecast annual peak demand (MW) at South Canterbury grid exit points to 2027


Peak demand (MW)


2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Albury 0.91 4 4 4 4 4 4 5 5 5 5 5

Bells Pond1 0.95 8 8 17 17 17 17 17 17 17 17 17

Black Point1 0.92 12 20 21 22 23 23 24 24 24 24 24

Oamaru1 0.92 44 46 62 65 68 69 73 75 77 78 80

St Andrews1 0.95 0 0 0 0 0 35 45 45 45 45 45

Studholme1 0.94 17 18 25 26 28 33 36 38 38 39 39

Tekapo A 1.00 6 6 6 7 7 7 8 9 9 9 9

Temuka 0.96 65 68 70 73 75 78 87 92 97 102 106

Timaru2 0.96 71 72 81 81 82 82 83 84 85 86 87

Twizel 1.00 6 6 6 6 7 7 7 7 7 8 8

Waitaki3 0.95 7 7 7 11 11 11 17 17 22 22 23

1. The customer and Covec (an independent consultant) provided the new load forecast. The forecast includes major new irrigation and manufacturing loads.

150


0

50

100

150

200

250

300

350

400

1997 1999 2001 2003 2005 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027

Load (MW) South Canterbury

2011 APR Forecast

2012 APR Forecast

Actual Peak




Peak demand (MW)


2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

2. The forecast includes step-change information provided by the customer.

3. The customer indicates an expected irrigation load increase in 2015, 2019, and 2023.

18.4 South Canterbury generation

The South Canterbury region’s generation capacity is 1,746 MW. This represents a major portion of total South Island generation and significantly exceeds local demand. Surplus generation is exported via the National Grid to other demand centres in the South Island, and via the HVDC link to the North Island.

Table 18-2 lists the generation forecast for each grid injection point in the South Canterbury region for the forecast period, as required for the Grid Reliability Report. This includes all known and committed generation stations including those embedded within the relevant local lines company’s network (either Network Waitaki or Alpine Energy).

151

No new generation is known to be committed in the South Canterbury region for the forecast period.

Table 18-2: Forecast annual generation capacity (MW) at South Canterbury grid injection points to 2027 (including existing and committed generation)




2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Albury (Opuha) 8 8 8 8 8 8 8 8 8 8 8

Aviemore 220 220 220 220 220 220 220 220 220 220 220

Benmore 540 540 540 540 540 540 540 540 540 540 540

Ohau A 264 264 264 264 264 264 264 264 264 264 264

Ohau B 212 212 212 212 212 212 212 212 212 212 212

Ohau C 212 212 212 212 212 212 212 212 212 212 212

Tekapo A 25 25 25 25 25 25 25 25 25 25 25

Tekapo B 160 160 160 160 160 160 160 160 160 160 160

Waitaki 105 105 105 105 105 105 105 105 105 105 105

18.5 South Canterbury significant maintenance work


152 proposed for the South Canterbury region for

the next 15 years that may significantly impact related system issues or connected parties.




Albury supply transformer expected end-of-life

2016-2018 No n-1 security at Albury. Future investment will be customer driven. See Section 18.8.5 for more information.

151







Studholme supply transformer expected end-of-life

2014-2016 Load at Studholme exceeds the supply transformers’ n-1 capacity. See Section 18.8.11 for more information.

Studholme 11 kV switchboard replacement

2014-2016 The switchboard needs to be replaced with new supply transformers.

Timaru 110 kV bus rationalisation and bus protection upgrade

2012-2015 The 110 kV rationalisation and protection work needs to be coordinated with the supply and interconnecting transformer development work at Timaru. See Sections 18.8.2 and 18.8.14 for more information.

Timaru supply transformers T2 and T3 expected end-of-life

2017-2019 The load at Timaru exceeds the supply transformers’ n-1 capacity. See Section 18.8.14 for more information.

Twizel 33 kV outdoor to indoor conversion


Waitaki interconnecting transformers expected end-of-life

2015-2019 The options to replace the interconnecting transformers are related to the Lower Waitaki Valley Reliability project. See Sections 18.8.1 and 18.8.4 for more information.

18.6 Future South Canterbury projects summary and transmission configuration

Table 18-4 lists projects to be carried out in the South Canterbury region within the next 15 years.

Figure 18-4 shows the possible configuration of South Canterbury transmission in 2027, with new assets, upgraded assets, and assets undergoing significant maintenance within the forecast period.

Table 18-4: Projects in the South Canterbury region up to 2027


Albury Replace supply transformer. Base Capex

Benmore–Twizel Upgrade circuit thermal capacity (see Chapter 6, Section 6.6.3 for more information).

Possible

Geraldine New switching station (see Chapter 6, Section 6.6.1 for more information).

Possible

Oamaru Upgrade supply transformer branch limiting components. Possible

Studholme Replace existing supply transformers with higher-rated units. Replace 11 kV switchboard.

Possible Base Capex

St Andrews New grid exit point. Possible

Tekapo A Resolve protection limits on 11/33 kV supply transformer. Base Capex

Temuka–Timaru Upgrade circuit thermal capacity. Possible

Temuka Install a new supply transformer. Possible

Timaru Install a 110 kV bus coupler and upgrade 110 kV bus protection. Rationalise 110 kV bus. Install additional interconnecting transformer(s). Upgrade supply transformer capacity.

Possible Base Capex Possible Possible

Twizel Convert 33 kV outdoor switchgear to indoor. Base Capex

Waitaki Replace interconnecting transformers. Install a second 11/33 kV supply transformer. Upgrade 11/33 kV supply transformer.

Base Capex Possible Possible

Clutha-Upper Waitaki Line Project

Replace the following circuits with duplex conductor:

220 kV Aviemore–Benmore 1 and 2 circuits.

220 kV Aviemore–Waitaki–Livingstone 1 circuits.

220 kV Livingstone–Naseby–Roxburgh 1 circuits.

220 kV Clyde–Roxburgh 1 and 2 circuits (Otago-Southland region).

Committed




Thermal upgrade the 220 kV Cromwell–Twizel 1 and 2 circuits.

(See Chapter 6, Section 6.6.3 for more information).

Lower Waitaki Valley Reliability Project

Possible options include the following.

Build a new 110 kV line between Livingstone and Oamaru,

Build a new 110 kV Glenavy switching station.

Reconductor/thermally upgrade the 110 kV circuits between Waitaki, Oamaru and Timaru.

Install capacitors at Oamaru.

Possible

Figure 18-4: Possible South Canterbury transmission configuration in 2027

110 kV

CANTERBURY

220 kV

OTAGO - SOUTHLAND

110 kV

110 kV

110 kV

110 kV

110 kV

220 kV

220 kV220 kV

220 kV

220 kV

220 kV

220 kV

220 kV

Cromwell Naseby

33 kV

11 kV

11 kV

11 kV 220 kV

Islington

Ashburton

33 kV

33 kV

33 kV

33 kV

11 kV110 kV

Temuka

Studholme

Oamaru

Tekapo A

Albury

Tekapo B

Ohau A

Twizel

Ohau B

Ohau CWaitaki

Black Point

Benmore

Aviemore

Livingstone

Geraldine

110 kV

11 kV

Timaru

220 kV

St Andrews220 kV

11 kV

Bells Pond

Glenavy

110 kV

110 kV

** This diagram shows several

possible upgrade paths for the

South Canterbury region.

KEY

NEW ASSETS

UPGRADED ASSETS

ASSETS SCHEDULED

FOR REPLACEMENT

* MINOR UPGRADE

*

*

**

**

**




Issues Change

Albury supply transformer capacity. New issue.

Tekapo A transformer capacity New issue.



18.8 South Canterbury transmission capability

Table 18-6 summarises issues involving the South Canterbury region for the next 15 years. For more information about a particular issue, refer to the listed section number.

Table 18-6: South Canterbury region transmission issues

Section number

Issue

Regional

18.8.1 Oamaru–Waitaki voltage quality and transmission security

18.8.2 Timaru interconnecting transformer capacity

18.8.3 Timaru 110 kV transmission security

18.8.4 Waitaki 220/110 kV interconnecting transformer capacity


18.8.5 Albury single supply security and supply transformer capacity

18.8.6 Albury and Tekapo A transmission security

18.8.7 Bells Pond single supply security

18.8.8 Black Point single supply security

18.8.9 Oamaru supply transformer capacity

18.8.10 Studholme single supply security

18.8.11 Studholme supply transformer capacity

18.8.12 Tekapo A supply security and supply transformer capacity

18.8.13 Temuka transmission security and supply transformer capacity

18.8.14 Timaru supply transformer capacity

18.8.15 Waitaki single supply security and supply transformer capacity

18.8.1 Oamaru–Waitaki voltage quality and transmission security

Project context: Lower Waitaki Valley Reliability

Project reference: Reactive support: OAM-C_BANKS-DEV-01 Upgrade transmission capacity: LWTK-TRAN-DEV-01

Project status/purpose: Reactive support: possible, customer-specific Upgrade transmission capacity: possible, to meet the Grid Reliability Standard (not core grid)

Indicative timing: Reactive support: Between 2012 and 2017 Upgrade transmission capacity: post 2012

Indicative cost band: Reactive support: A Upgrade transmission capacity: C

Issue

Two 110 kV circuits from Waitaki supply the Oamaru, Black Point, Bells Pond, and Studholme grid exit points, which include the:

Oamaru–Black Point–Waitaki 1 circuit (which supplies Black Point via a tee connection), and

Oamaru–Studholme–Bells Pond–Waitaki 2 circuit (which supplies the Bells Pond and Studholme loads from tee connections).

The underlying load growth forecast for this area is considerably higher than the national average. The growth is mainly due to irrigation and dairy industry. There is also a possible major new industrial load at Oamaru.



Voltage

The load at these four grid exit points peaks in summer. The voltage at the Oamaru 110 kV bus can fall below 0.9 pu with the loss of the:

Oamaru–Black Point–Waitaki circuit, or

Oamaru–Studholme–Bells Pond–Waitaki circuit.

There is also a voltage quality issue with a large voltage step immediately following the outage of either circuit. There are no steady state voltage problems at Oamaru 33 kV, due to the range of the supply transformer on-load tap changers.

In the medium-term, there are voltage stability issues. These may occur from:

2014 if the large industrial load connects at Oamaru, or

2017 with underlying Oamaru load growth but no additional step load at Oamaru.

Overloading

Thermal overloads occur by:

summer 2012 on one Glenavy–Oamaru circuit section following an outage of the parallel circuit

summer 2012 on the Bells Pond–Waitaki section during an outage of the Oamaru–Black Point–Waitaki circuit or any of the Twizel–Timaru–Ashburton circuits, and

summer 2012 on the Black Point–Waitaki section during an outage of the Oamaru–Studholme–Bells Pond–Waitaki circuit.

Solution

We are investigating a range of short-term options. The solution may include one or more of the following:

load management at the Oamaru and Waitaki Valley grid exit points

implementing system splits

installing reactive support at Oamaru

post-contingency load shedding at Oamaru, and

implementing variable line ratings.

Having a Wider Voltage Agreement at 110 kV buses may be appropriate in the short term. In the medium term, the voltage issues at Oamaru can be resolved by installing approximately 30 Mvar of reactive support at Oamaru. This also provides approximately 7 MW additional capacity on the Glenavy–Oamaru circuits.

We are discussing the preferred options with the local lines companies (Network Waitaki and Alpine Energy).

Additional reactive support will be required in the longer-term, however, the reactive support’s size and the location will depend on the development undertaken to resolve the capacity issue. A range of long-term options is being investigated to resolve the capacity issue, including:

establishing a new switching station at Glenavy

reconductoring and thermally upgrading the existing 110 kV circuits, and/or

building a new 110 kV Livingstone–Oamaru line, or

a new grid exit point supplying load in the Ngapara area west of Oamaru.

A major driver of the transmission upgrade is the possible major new industrial load at Oamaru. We do not expect to propose major upgrades in the short-term, unless this load becomes committed.



Easements may be required for the line upgrade work, and will be required for any new lines.

18.8.2 Timaru interconnecting transformer capacity

Project reference: Load shifting: See Section 18.8.14 Interconnecting transformer capacity: TIM-POW_TFR-EHMT-02

Project status/purpose: Load shifting: See Section 18.8.14 Interconnecting transformer capacity: possible, to meet the Grid Reliability Standard (not core grid). We anticipate seeking approval from the Commerce Commission in third quarter of 2012.

Indicative timing: Interconnecting transformer capacity: to be advised

Indicative cost band: Interconnecting transformer capacity: C

Issue

Two 220/110 kV interconnecting transformers at Timaru supply the loads at Timaru, Temuka, Albury and Tekapo A, providing:



(summer/winter).

An outage of one transformer may cause the other transformer to exceed its n-1 capacity from 2012, if Tekapo A is not generating. In addition, some development options for the Lower Waitaki Valley area may increase the loading on these transformers, one of which is supplying Studholme from Timaru instead of Waitaki (see Sections 18.8.1 and 18.8.10).

Solution

The options to address this issue include one or more of the following:

peak load management or load shedding

110 kV reactive support to reduce reactive power flow through the Timaru interconnecting transformers

shifting the Timaru supply bus load from the 110 kV to the 220 kV side of the Timaru interconnecting transformers (see also Section 18.8.14), and

increasing installed capacity using one of several possible configurations of the existing and new interconnecting transformers.

18.8.3 Timaru 110 kV transmission security

Project reference: TIM-BUSC-DEV-01




Issue

The Timaru 110 kV bus supplies the entire loads at Timaru and Temuka, and connects directly to Albury and Tekapo A via a single 110 kV circuit. At present, a 110 kV bus fault at Timaru will cause a total loss of supply to substations at Timaru and Temuka, disconnect Tekapo A and Albury from the Grid, and possibly cause an outage at Studholme (depending on the status of the Studholme split).

Solution

We will investigate the economic benefit of installing a 110 kV bus coupler at Timaru, to provide n-1 protection for 110 kV bus faults.

153

The transformers’ winter capacity is limited by protection equipment; with this limit resolved, the n-1 capacity will be 122/127 MVA (summer/winter).



18.8.4 Waitaki 220/110 kV interconnecting transformer capacity

Project reference: WTK-POW_TFR-REPL-01




Issue

Two 220/110 kV interconnecting transformers (T23 and T24) at Waitaki supply the Waitaki 110 kV loads at Black Point, Bells Pond, Oamaru, and Studholme, providing:



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). These transformers have a higher capacity than the circuits they supply, so they are not the first constraint. However, under some upgrade scenarios the capacity of the 110 kV Waitaki–Oamaru circuits (as well as the load placed on them) will exceed the interconnecting transformers’ n-1 capacity.

In addition, the tap changers on these transformers are unable to be operated due to their condition. This exacerbates voltage issues on the Lower Waitaki 110 kV transmission system (see Section 18.8.1).

Solution

These transformers have an expected end-of-life within the next 10 years. The need to increase the interconnection capacity in conjunction with the necessary maintenance work will depend on the preferred option from the Lower Waitaki Valley Reliability investigation (see Section 18.8.1).

18.8.5 Albury single supply security and supply transformer capacity


Issue

A single 110/11 kV, 5 MVA transformer supplies load at Albury resulting in no n-1 security.

In addition, Albury is connected to embedded generation at Opuha, which may export power to the National Grid during periods of low demand.

The peak load at Albury is forecast to exceed the transformer’s summer capacity by approximately 1 MW in 2023, only increasing slightly until 2027 (see Table 18-7).

Table 18-7: Albury supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Albury 0.91 0 0 0 0 0 0 0 0 1 1 1

Solution

Alpine Energy can supply Albury’s load from Timaru after a short loss of supply, and considers the issue can be managed operationally for the forecast period. Future investment will be customer driven.



An additional consideration is that this supply transformer has an expected end-of-life within the next 10 years. We will discuss options with Alpine Energy for increasing supply security and coordinating outages to minimise supply interruptions when replacing this transformer.

18.8.6 Albury and Tekapo A transmission security


Issue

A single 110 kV Tekapo A–Albury–Timaru circuit connects Tekapo A, Albury, and Opuha to the National Grid. If the circuit trips, demand located at Albury and Tekapo A will lose supply, and generation located at Tekapo A and Opuha will disconnect from the National Grid.

Solution

Albury and Tekapo A demand may be restored by local Opuha and Tekapo A generation. Alpine Energy considers the issue can be managed operationally for the forecast period. Future investment will be customer driven.

18.8.7 Bells Pond single supply security

Project reference: BPD-BUSC-DEV-01




Issue

Bells Pond has a single 110 kV circuit connected to an Oamaru–Waitaki circuit, resulting in no n-1 security.

Solution

Alpine Energy has requested a higher security level. We are discussing possible options with Alpine Energy, which include:

building a 110 kV bus at Bells Pond

connection to the other 110 kV Oamaru–Waitaki circuit, and

a new grid exit point connected to the Islington–Livingstone circuit.

18.8.8 Black Point single supply security


Issue

Black Point has a single 110 kV circuit connected to an Oamaru–Waitaki circuit, resulting in no n-1 security.

Solution

Network Waitaki has not requested a higher security level and there are currently no plans to increase supply security at this grid exit point. Future investment will be customer driven.

18.8.9 Oamaru supply transformer capacity

Project reference: OAM-POW_TFR-EHMT-01






Issue

Two 110/33 kV transformers supply Oamaru’s load, providing:



(summer/winter).

The peak load at Oamaru is forecast to exceed the transformers’ n-1 summer capacity by approximately 12 MW in 2014, increasing to approximately 30 MW in 2027 (see Table 18-8).

Table 18-8: Oamaru supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Oamaru 0.92 0 0 12 15 18 19 23 25 27 28 30

Solution

The 110 kV circuits supplying these transformers have a lower capacity than the transformers (see Section 18.8.1). Therefore, the transformers are not the first constraint on Oamaru load.

Resolving the protection limits will provide sufficient n-1 capacity until 2016. Future investment will be customer driven.

18.8.10 Studholme single supply security

Project status/purpose: See Section 18.8.1 for more information

Issue

The Studholme–Timaru circuit is split during the off-peak dairy 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 from Waitaki 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. This results in approximately 25 seconds loss of supply at Studholme before the switching occurs.

However, a brief loss of supply to the local dairy factory at Studholme can cause significant 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 overloading issues on the Waitaki–Bells Pond section of the Oamaru–Studholme–Bells Pond–Waitaki circuit. We expect to be unable to close the split during peak summer load periods from 2014.

Solution

We are investigating options to increase supply security at Studholme. The long-term solution will be part of the Lower Waitaki Reliability project (see Section 18.8.1).

154

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).



18.8.11 Studholme supply transformer capacity

Project reference: STU-POW_TFR-EHMT-01


Indicative timing: Upgrade transformer capacity: 2014 (subject to Alpine Energy agreement) New grid exit point: to be advised

Indicative cost band: Upgrade transformer capacity: B New grid exit point: C

Issue

Two 110/11 kV transformers supply Studholme’s load, providing:



The peak load at Studholme already exceeds the transformers’ n-1 summer capacity, and the overload is forecast to increase to approximately 74 MW in 2027 (see Table 18-9). However, part of this increase is due to a single load from a proposed irrigation scheme in 2017. This may be supplied from a new grid exit point in the area north of Studholme.

Table 18-9: Studholme supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Studholme 0.94 7 8 15 16 17 58 71 73 73 74 74

Studholme has an unusual 110 kV bus arrangement, where the two transformers have no dedicated 110 kV circuit breakers. This means that both supply transformers will be tripped to clear a transformer fault, causing a loss of supply at Studholme. Supply can be restored after the faulted transformer is disconnected.

Solution

We are discussing possible solutions with Alpine Energy, which include:

replacing the existing transformers with higher-rated units, and

building a new grid exit point north of Studholme near St Andrews (if the new irrigation load is committed) on the 220 kV Islington–Livingstone circuit, and transferring some of the Studholme load.

Acquisition of substation land will be required for establishing a new grid exit point.

An additional consideration is that both Studholme supply transformers are approaching their expected end-of-life within the next five years. If an agreement to proceed with the transformer upgrade has not been made prior to the need for replacement, we will discuss the transformer capacity upgrade project with Alpine Energy in conjunction with the replacement work.

18.8.12 Tekapo A supply security and supply transformer capacity


Issue

A single 110/11 kV, 35 MVA transformer in series with a single 11/33 kV, 10 MVA155

transformer supplies load at Tekapo resulting in no n-1 security.

155

The transformer’s protection limit of 7 MVA and metering equipment limit of 8 MVA prevent the full nominal installed capacity being available.



The peak load at Tekapo A is forecast to exceed the transformer’s winter capacity by approximately 1 MW in 2019, increasing to approximately 2 MW in 2027 (see Table 18-10).

Table 18-10: Tekapo A supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Tekapo A 1.00 0 0 0 0 0 0 1 1 2 2 2

Solution

Alpine Energy considers the issue can be managed operationally for the forecast period. Resolving the protection limits will provide sufficient capacity for the duration of the forecast period. Future investment will be customer driven.

18.8.13 Temuka transmission security and supply transformer capacity

Project reference: Additional transformer: TMK-POW_TFR-DEV-02 Upgrade circuit capacity: TIM_TMK-TRAN-EHMT-01



Indicative cost band: Additional transformer: B Upgrade circuit capacity: B

Issue

Two 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 thermal capacity from 2012 during summer peak demand periods. Also, there is no 110 kV bus at Temuka. Therefore, a circuit outage will also result in the loss of the 110/33 kV supply transformer connected to this circuit.

At Temuka, two 110/33 kV transformers supply the 33 kV load, providing:



The peak load at Temuka is forecast to exceed the transformers’ n-1 summer capacity by approximately 12 MW in 2012, increasing to approximately 53 MW in 2027 (see Table 18-11).

Table 18-11: Temuka supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Temuka 0.96 12 14 16 19 21 24 33 38 43 48 53

Solution

We are discussing options with Alpine Energy. A long-term solution involves:

paralleling the existing transformers and installing a new 120 MVA transformer, and

upgrading the 110 kV circuits between Timaru and Temuka, or

a new connection to the 220 kV Islington–Waitaki circuits, west of Temuka.



The addition of a new transformer will not raise new property issues as it can be implemented within the existing substation boundary. However, upgrading the capacity 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 the Clandeboye dairy factory, which accounts for more than half the demand at this grid exit point.

18.8.14 Timaru supply transformer capacity

Project reference: TIM-POW_TFR-EHMT-01




Issue

Three 110/11 kV transformers supply Timaru’s load, providing:

a total nominal installed capacity of 77 MVA (one 27 MVA and two 25 MVA), and


The peak load at Timaru already exceeds the transformers’ n-1 winter capacity, and the overload is forecast to increase to approximately 34 MW in 2027 (see Table 18-12).

Table 18-12: Timaru supply transformer forecast overload

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Timaru 0.96 18 19 28 28 29 29 30 31 32 33 34

There is a non-contracted spare transformer unit on site, allowing possible replacement 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.

Solution

We are discussing the options with Alpine Energy, including:

replacing the existing three 110/11 kV supply transformers with three 40 MVA units, and

installing two 220/33 kV, 120 MVA supply transformers and a new 33 kV switchboard, and retaining some or all of the 110/11 kV transformers. The solution will also affect the loading on the Timaru interconnecting transformers (see Section 18.8.2), and these two issues need to be resolved together.

An additional consideration is that Timaru supply transformers have an expected end-of-life within the next 5-10 years. We will discuss options with Alpine Energy for increasing supply security at Timaru.

No property issues are anticipated, as it is likely that either option can be implemented within the existing substation boundary.

18.8.15 Waitaki single supply security and supply transformer capacity

Project reference: WTK-POW_TFR-EHMT-01


Indicative timing: Install a second supply transformer: to be advised Increase transformer capacity by adding fans and pumps: 2014

Indicative cost band: Install a second supply transformer: A



Increase transformer capacity by adding fans and pumps: A

Issue

A single 11/33 kV, 5.5 MVA transformer supplies load at Waitaki resulting in no n-1 security.

Network Waitaki can supply some of the Waitaki load from Twizel after a short loss of supply. However, the peak Waitaki load is forecast to exceed the continuous supply transformer capacity by approximately 2 MW in 2012, increasing to approximately 18 MW in 2027 (see Table 18-13). Network Waitaki has requested options for security and capacity enhancements.

Table 18-13: Waitaki supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Waitaki 0.95 2 2 2 6 6 7 12 12 17 18 18

Solution

We are investigating options with Network Waitaki to increase capacity and security of supply in the area.

A possible solution to increase the security of supply involves installing a second supply transformer.

Possible options to resolve the capacity issues include:

transferring 2 MW of load to another grid exit point, delaying the issue until 2014, or

increasing the capacity of the supply transformer.



18.10 South Canterbury generation proposals and opportunities



156

18.10.1 North Bank project

The proposed North Bank hydro project, located on the north bank of the Waitaki River, consists of two hydro generation stations with total generation capacity of approximately 265 MW.

The proposed connection option is one generation station connecting to the 110 kV Glenavy–Waitaki ‘A’ line, and the other generation station connecting to the 220 kV

156




Roxburgh–Islington ‘A’ line. It is likely that the Lower Waitaki Valley grid upgrade plan may have some effect on the generation dispatch for the power station connecting to the 110 kV line. At times, depending on the connection configuration, some generation may be constrained post-contingency. The generation connection configuration is yet to be finalised.

18.10.2 Wind generation

There are no issues with connecting wind or other generation at existing substations within the Waitaki Valley at 220 kV.

Connecting too much generation to one of the four circuits to Christchurch may cause it to overload and reduce the total amount of load that can be supplied across all four circuits.

The maximum generation that can be connected varies with the point of connection and the circuit. Connections close to the Waitaki Valley enable the most generation, approximately equal to the circuit rating. The best case location and circuit will enable 400-700 MW of generation. The worst case location and circuit will not support the dispatch of generation.

Unless the 110 kV Tekapo A–Albury–Timaru circuit is upgraded, there is limited opportunity to connect new generation because of the existing generation at Tekapo A, and the Opuha generation embedded at Albury.

The other 110 kV circuits in the South Canterbury region can support generation connections up to or slightly higher than the circuit rating.

Chapter 19: Otago-Southland Region


19 Otago-Southland Regional Plan


19.2 Otago-Southland transmission system

19.3 Otago-Southland demand

19.4 Otago-Southland generation

19.5 Otago-Southland significant maintenance work

19.6 Future Otago-Southland projects summary and transmission configuration


19.8 Otago-Southland transmission capability


19.10 Otago-Southland generation proposals and opportunities


This chapter details the Otago-Southland regional transmission plan. We base this regional plan on an assessment of available data, and welcome feedback to improve its value to all stakeholders.

Figure 19-1: Otago-Southland region



The Otago-Southland region includes a mix of significant provincial cities (Dunedin and Invercargill) together with smaller rural localities (Queenstown and Wanaka), and the largest electricity consumer in New Zealand, Tiwai Point Aluminium Smelter.

We have assessed the Otago-Southland region’s transmission needs over the next 15 years while considering longer-term development opportunities. Specifically, the transmission network needs to be flexible to respond to a range of future service and technology possibilities, taking into consideration:


forecast demand

forecast generation



19.2 Otago-Southland transmission system

This section highlights the state of the Otago-Southland regional transmission network. The existing transmission network is set out geographically in Figure 19-1 and schematically in Figure 19-2.

Figure 19-2: Otago-Southland transmission schematic

SOUTH CANTERBURY

110 kV

110 kV

220 kV

220 kV

220 kV

220 kV

220 kV

220 kV

220 kV

220 kV

220 kV

SOUTH CANTERBURY

220 kV

220 kV

110 kV

110 kV

110 kV

110 kV

110 kV

110 kV

Twizel

33 kV

Livingstone

33 kV

33 kV

33 kV

33 kV

33 kV

33 kV

33 kV

110 kV 11 kV

33 kV

33 kV

33 kV

110kV CIRCUIT

SUBSTATION BUS

TRANSFORMER

TEE POINT

KEY

220kV CIRCUIT

LOAD

CAPACITOR

Cromwell

33 kV

Frankton

Clyde

Naseby

Roxburgh

Palmerston

Halfway BushThree

Mile Hill

South Dunedin

Berwick

Balclutha

Gore

Brydone

Edendale

Invercargill

Tiwai

North Makarewa

Manapouri

GENERATOR

3 WDG TRANSFORMER

33kV CIRCUIT


There are issues with the transmission capacity to transfer power into or out of the Otago-Southland region.

When Otago-Southland generation is high, transmission capacity from Roxburgh may constrain generation dispatch within the region for some outages. With low Otago-Southland generation, the transmission capacity of the circuits from Twizel and



Livingstone to Roxburgh may exceed their thermal ratings to supply the deficit power to the region.

Under the Clutha-Upper Waitaki Lines Project (formerly known as Lower South Island Facilitating Renewables), we have committed to upgrading the Clyde–Roxburgh and Aviemore–Waitaki–Livingstone circuits by 2014. By mid 2013, we will review the timing for the delivery of the remaining sections, namely:

reconductoring the Livingstone–Naseby–Roxburgh, Aviemore–Benmore circuits, and

thermally upgrading the Cromwell–Twizel circuits.

See Chapter 6, Section 6.6.3 for more information.


The transmission within the Otago-Southland region comprises 220 kV and 110 kV transmission circuits with interconnecting transformers located at Cromwell, Halfway Bush, Roxburgh and Invercargill.

Capacitors are installed at North Makarewa to improve the system voltage and voltage stability performance. There are also capacitors on the supply bus at Brydone 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 North Makarewa substations, is predominantly supplied from Manapouri, or via the 220 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 interconnecting transformers at Halfway Bush, Roxburgh, and Invercargill.

The Central Otago area represents load supplied from Cromwell and Frankton via the Cromwell interconnecting transformers.

The 110 kV transmission network within the Otago-Southland region predominantly comprises low-capacity circuits supplying the smaller centres within the region. Both capacity and voltage issues arise during outages. In addition, most of the transformers connected to the 110 kV transmission network are older, single-phase units, with an expected end-of-life within the next 20 years.

We have committed to implementing the Lower South Island Reliability Project to increase the capacity of the 110 kV and 220 kV transmission network within the region. It addresses existing issues and provides the foundation for future upgrades when required. The project includes a new 220/110 kV interconnection at the Gore substation, replacing the Roxburgh 220/110 kV transformer with a higher rated unit, and a series capacitor on a North Makarewa–Three Mile Hill circuit. See Chapter 6, Section 6.6.4 for more information.


The Lower South Island Reliability Project addresses existing issues and provides the foundation for future upgrades when required, which will potentially include additional reactive support and increased line compensation.

19.3 Otago-Southland demand

The after diversity maximum demand (ADMD) for the Otago-Southland region is forecast to grow on average by 0.8% annually over the next 15 years, from 1,107 MW



in 2012 to 1,247 MW by 2027. This is lower than the national average demand growth of 1.7% annually.


157) for the Otago-Southland region. The forecasts are derived


Figure 19-3: Otago-Southland region after diversity maximum demand forecast

Table 19-1: lists forecast peak demand (prudent growth) for each grid exit point for the forecast period, as required for the Grid Reliability Report.

Table 19-1: Forecast annual peak demand (MW) at Otago-Southland grid exit points to 2027


Peak demand (MW)


2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Balclutha 0.97 31 31 32 32 33 34 35 36 37 39 39

Brydone1 0.79 12 12 12 12 12 12 12 12 12 12 12

Cromwell 1.00 34 35 37 38 40 41 44 46 49 52 54

Clyde 0.95 11 11 11 12 12 12 13 13 14 14 14

Edendale1 0.98 31 32 33 34 38 39 41 44 46 48 50

Frankton 0.99 57 58 60 62 64 65 69 72 75 79 82

Gore1 0.97 34 40 61 62 82 83 84 86 87 88 89

Halfway Bush -1 0.99 120 121 123 109 111 112 116 119 121 124 126

157


800

900

1000

1100

1200

1300

1400

1500

1997 1999 2001 2003 2005 2007 2009 2011 2013 2015 2017 2019 2021 2023 2025 2027

Load (MW)

Otago-Southland

2011 APR Forecast

2012 APR Forecast

Actual Peak




Peak demand (MW)


2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Halfway Bush -2 0.99 111 113 114 115 117 118 121 124 126 129 131

Invercargill 0.99 103 105 108 110 112 114 118 123 127 131 136

Naseby 1.00 33 34 35 35 36 37 38 40 41 42 43

North Makarewa 0.99 57 58 59 61 62 63 66 68 70 72 73

Palmerston 0.97 10 10 10 11 11 11 12 12 12 13 13

South Dunedin 0.99 77 78 79 96 97 98 100 102 104 107 109

Tiwai 0.97 640 640 640 645 650 655 665 675 685 690 690

1. Step-change information identified through customer discussions and from the Covec (an independent consultant) forecast study prior to publishing the 2011 Annual Planning Report. The forecast includes potential major new manufacturing loads.

19.4 Otago-Southland generation

The Otago-Southland region’s generation capacity is 1,831 MW.158

This generation usually contributes a major portion of the total South Island generation and exceeds local demand. Surplus generation is exported over the National Grid to other demand centres in the South Island.

Table 19-2 lists the generation forecast for each grid injection point for the forecast period, as required for the Grid Reliability Report. This includes all known and committed generation stations, including those embedded within the relevant local lines company’s network (PowerNet, OtagoNet, or Aurora).

159

Table 19-2: Forecast annual generation capacity (MW) at Otago-Southland grid injection points to 2027 (including existing and committed generation)




2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Clyde

432 432 432 432 432 432 432 432 432 432 432

Manapouri 840 840 840 840 840 840 840 840 840 840 840

Roxburgh

320 320 320 320 320 320 320 320 320 320 320

Balclutha (Mt. Stuart) 8 8 8 8 8 8 8 8 8 8 8

Berwick/Halfway Bush (Waipori and Mahinerangi)

84 36

84 36

84 36

84 36

84 36

84 36

84 36

84 36

84 36

84 36

84 36

Clyde (Fraser) 3 3 3 3 3 3 3 3 3 3 3

Clyde (Horseshoe Bend hydro and wind)

4 2

4 2

4 2

4 2

4 2

4 2

4 2

4 2

4 2

4 2

4 2

Clyde (Talla Burn) 3 3 3 3 3 3 3 3 3 3 3

Clyde (Teviot and Kowhai)

11 2

11 2

11 2

11 2

11 2

11 2

11 2

11 2

11 2

11 2

11 2

Cromwell (Roaring Meg)

4 4 4 4 4 4 4 4 4 4 4

Frankton (Wye Creek) 1 1 1 1 1 1 1 1 1 1 1

Halfway Bush (Deep Stream)

5 5 5 5 5 5 5 5 5 5 5

158

This excludes the resource consent applications for the Clyde and Roxburgh generation station capacity increases.

159 Only generators with a capacity greater than 1 MW are listed. Generation capacity is rounded to the nearest megawatt.






2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Naseby (Falls Dam) 1 1 1 1 1 1 1 1 1 1 1

Naseby (Paerau) 10 10 10 10 10 10 10 10 10 10 10

North Makarewa (Monowai)

7 7 7 7 7 7 7 7 7 7 7

North Makarewa (White Hills)

58 58 58 58 58 58 58 58 58 58 58

19.5 Otago-Southland significant maintenance work


160 proposed for the Otago-Southland region for

the next 15 years that may significantly impact related system issues or connected parties.




Balclutha 33 kV outdoor to indoor conversion

2013-2015 Addition of capacitors incorporated into the Lower South Island reliability Project will be installed at the same time. See Section 19.8.1 for more information.

Edendale 110/33 kV supply transformers expected end-of-life

2027-2029 The forecast load at Edendale exceeds the transformer n-1 capacity from 2013. See Section 19.8.5 for more information.

Gore 110/33 kV supply transformers expected end-of-life, and 33 kV outdoor to indoor conversion

2025-2027

2016-2018

We will investigate the timing and rating of the replacement transformers. See Section 19.8.7 for more information.

Halfway Bush interconnecting transformer expected end-of-life

2014-2016 This work will be coordinated with the replacement of the supply transformers to minimize outages.

Halfway Bush 110/33 kV supply transformer expected end-of-life 33 kV outdoor to indoor conversion 220/33 kV supply transformer expected end-of-life

2015-2017

2016-2017

2024-2026

The Halfway Bush load already exceeds the transformer’s n-1 capacity. The overloading issue is currently managed operationally. This work will be coordinated with the replacement of the interconnecting transformers. See Section 19.8.8 for more information.

Invercargill interconnecting transformer expected end-of-life

2013-2015 The transformer replacement is incorporated into the Lower South Island Reliability Project. See Section 19.8.1 for more information.

North Makarewa 220 kV capacitor bank replacement

2020-2022 Increasing the rating of the capacitor banks will be investigated as part of the replacement. See Section 19.8.1 for more information.

Naseby 220/33 kV supply transformers replacement and 33 kV outdoor to indoor conversion

2018-2020 The forecast load at Naseby exceeds the transformer n-1 capacity from 2014. We will investigate the timing and rating of the replacement transformers. See Section 19.8.10 for more information.

Palmerston supply transformer expected end-of-life, and 33 kV outdoor to indoor conversion

2016-2018 No n-1 security at Palmerston. Discussion about future supply security at Palmerston is currently underway. See Section 19.8.12 for more information.

Roxburgh interconnecting transformer replacement

2012-2015 We have committed to replace this transformer with a higher-rated unit as part of the Lower South Island Reliability Project. See Section 19.8.2 for more information.

160






South Dunedin 220/33 kV supply transformer expected end-of-life, and 33 kV outdoor to indoor conversion

2024-2026

2014-2015

Resolving the metering and protection limits will solve the transformers’ n-1 capacity issue for the forecast period. See Section 19.8.14 for more information.

19.6 Future Otago-Southland projects summary and transmission configuration

Table 19-4 lists projects to be carried out in the Otago-Southland region within the next 15 years.

Figure 19-4 shows the possible configuration of Otago-Southland transmission in 2027, with new assets, upgraded assets, and assets undergoing significant maintenance within the forecast period.

Table 19-4: Projects in the Otago-Southland region up to 2027


Balclutha Upgrade supply transformer branch limiting components. Convert 33 kV outdoor switchgear to an indoor switchboard. Install 33 kV capacitors.

Base Capex Base Capex Committed

Clyde–Roxburgh Increase 220 kV circuit capacities by duplexing the lines connecting Clyde and Roxburgh.

Committed

Cromwell Upgrade supply transformer branch limiting components. Base Capex

Cromwell–Frankton

Thermally upgrade the circuits. Possible

Cromwell–Twizel Increase 220 kV circuit capacities by thermally upgrade the lines connecting Cromwell and Twizel.

Committed

Edendale Upgrade cable on the supply transformers. Resolve protection and replace supply transformers.

Possible Base Capex

Frankton Upgrade supply transformer branch limiting components. Increase supply transformer capacities by adding pumps.

Base Capex Possible

Gore Install two 220/110 kV interconnecting transformers. Replace supply transformers. Convert 33 kV outdoor switchgear to an indoor switchboard.

Committed Base Capex Base Capex

Halfway Bush Replace two 110/33 kV supply transformers with one 220/33 kV unit. Replace 220/33 kV supply transformer. Replace 220/110 kV interconnecting transformer. Convert 33 kV outdoor switchgear to an indoor switchboard.

Base Capex Base Capex Base Capex Base Capex

Invercargill Replace 220/110 kV transformer with a higher-rated unit. Upgrade supply transformer metering equipment.

Possible Base Capex

Livingstone–Naseby

Increase the 220 kV circuit capacity by duplexing the line connecting Livingstone and Naseby.

Committed

Naseby–Roxburgh

Increase the 220 kV circuit capacity by duplexing the line connecting Naseby and Roxburgh.

Committed

Naseby Replace supply transformers. Convert 33 kV outdoor switchgear to an indoor switchboard.


North Makarewa–Three Mile Hill

Install series capacitor on one of the North Makarewa–Three Mile Hill circuits.

Committed

North Makarewa Replace shunt capacitors. Replace 220/33 kV transformers with 220/66 kV units.

Base Capex Possible

Palmerston Replace supply transformer. Convert 33 kV outdoor switchgear to an indoor switchboard.


Roxburgh Replace 220/110 kV transformer with a higher-rated unit. Committed

South Dunedin Upgrade supply transformer metering equipment. Replace 220/33 kV T1 supply transformer. Convert 33 kV outdoor switchgear to an indoor switchboard.




Figure 19-4: Possible Otago-Southland transmission configuration in 2027

SOUTH CANTERBURY

110 kV

110 kV

220 kV

220 kV

220 kV

220 kV

220 kV

220 kV

220 kV

220 kV

220 kV

SOUTH CANTERBURY

220 kV

220 kV

110 kV

110 kV

110kV

110 kV

110 kV

110 kV

33 kV

Livingstone

33 kV

33 kV

33 kV

33 kV

33 kV

33 kV

33 kV

110 kV 11 kV

33 kV

66 kV

Naseby

Clyde

Roxburgh

Palmerston

Halfway BushThree

Mile Hill

South Dunedin

Berwick

Balclutha

Gore

Brydone

Edendale

Invercargill

Tiwai

North Makarewa

Manapouri

110 kV

Twizel

33 kV

Cromwell

33 kV

Frankton

NEW ASSETS

UPGRADED ASSETS

ASSETS SCHEDULED

FOR REPLACEMENT

KEY

* MINOR UPGRADE

*

*

*

*

*

*



Table 19-5: Changes Since 2011

Issues Change

Balclutha supply transformer capacity New issue.

Naseby supply transformer capacity New issue.

Palmerston supply transformer capacity New issue.

19.8 Otago-Southland transmission capability

Table 19-6 summarises issues involving the Otago-Southland region for the next 15 years. For more information about a particular issue, refer to the listed section number.

Table 19-6: Otago-Southland region transmission issues

Section number

Issue

Regional

19.8.1 Southland transmission capacity and low voltage

19.8.2 Roxburgh interconnecting transformer capacity


19.8.3 Balclutha supply transformer capacity



Section number

Issue

19.8.4 Cromwell supply transformer capacity

19.8.5 Edendale supply transformer capacity

19.8.6 Frankton transmission and supply security

19.8.7 Gore supply transformer capacity

19.8.8 Halfway Bush supply transformer capacity

19.8.9 Invercargill supply transformer capacity

19.8.10 Naseby supply transformer capacity

19.8.11 North Makarewa supply transformer capacity

19.8.12 Palmerston supply security and supply transformer capacity

19.8.13 Palmerston transmission security

19.8.14 South Dunedin supply transformer capacity

19.8.15 Waipori transmission security

19.8.1 Southland transmission capacity and low voltage

Project context: Lower South Island Reliability

Project reference: STLD-TRAN-EHMT-01

Project status/purpose: Committed, to meet the Grid Reliability Standard (core grid)


Indicative cost band: E

Issue

The 220 kV Southland transmission network forms a geographical triangle linking the substations at Roxburgh, Halfway Bush and Invercargill. At each corner of this triangle, 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 the times when Manapouri generation is low, the 220 kV network may also overload.

Overloading

Some of the Southland 110 kV circuits and/or interconnecting transformers may overload for an outage of:

some of the Southland 110 kV circuits

one of the 220 kV Invercargill–Roxburgh circuits, or

one of the 220 kV Roxburgh–Three Mile Hill circuits.

A 220 kV Invercargill–Roxburgh circuit may also overload for an outage of the parallel circuit.

The severity of these overloads depends on Roxburgh, Manapouri, and Waipori generation at the time of the outage.

Low voltages

An outage of some of the Southland transmission circuits or interconnecting transformers 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 low voltage at Balclutha and Gore.

Solution

The overloading issues can be managed operationally by regulating the amount of generation at Manapouri, Waipori and Roxburgh. The extent to which generation may need to be regulated will depend on the generation dispatched in the South Island at the time. In addition, some load can be transferred from the Halfway Bush 110 kV bus to the 220 kV bus, and some low voltage problems can be resolved using the existing transformer off-load tap changers.

We have committed to implementing the Lower South Island Reliability Project to increase the transmission capacity between Roxburgh and Invercargill. The development plans include the following.

Install Special Protection Schemes to allow sufficient build time.

Replace the existing Roxburgh 220/110 kV interconnecting transformer with a 150 MVA unit (see also Section 19.8.2).

Replace the existing Invercargill 220/110 kV interconnecting transformer with a 100 MVA unit.

Install shunt capacitors for reactive support at Balclutha.

Install a new 220/110 kV interconnection point comprising two 220/110 kV transformers at Gore, and a two kilometre 220 kV double-circuit line connected from the Gore substation to the 220 kV North Makarewa–Three Mile Hill line.

Install a series capacitor on one of the North Makarewa–Three Mile Hill circuits.

161

19.8.2 Roxburgh interconnecting transformer capacity

Project context: This project forms part of Lower South Island Reliability Project. See Section 19.8.1

Issue

The loading on the 220/110 kV interconnecting transformer at Roxburgh mainly depends on generation levels at the Roxburgh 110 kV bus, and the load supplied by the Southland 110 kV transmission network.

During low generation on the Roxburgh 110 kV bus, the Roxburgh interconnecting transformer may overload with an outage of:

the 220/110 kV interconnecting transformer at Halfway Bush

the 110 kV Balclutha–Berwick circuit

one of the 220 kV Invercargill–Roxburgh circuits, or

one of the 220 kV Roxburgh–Three Mile Hill circuits.

The Roxburgh interconnecting transformer may also overload following an outage for some instances of high generation on the Roxburgh 110 kV bus.

Solution

The interim solution is to operationally manage the loading on the interconnecting transformer by regulating the generation on the Roxburgh 110 kV bus to prevent the interconnecting transformer’s overload. The extent of the interconnecting transformer overload depends on the generation dispatched in the South Island at the time.

161

We are reviewing the appropriate timing of the series capacitor. A decision is expected by the end of 2012 with tentative commissioning by 2016.



We have committed to replace the Roxburgh interconnecting transformer with a 150 MVA unit. This longer-term solution forms part of the Lower South Island Reliability Project.

19.8.3 Balclutha supply transformer capacity

Project reference: BAL-POW_TFR_PTN-EHMT-01

Project status/purpose: Upgrade protection: Base Capex, minor enhancement



Issue

Two 110/33 kV transformers supply Balclutha’s load, providing:



(summer/winter).

The peak load at Balclutha is forecast to exceed the transformers’ n-1 winter capacity by approximately 3 MW in 2012, increasing to approximately 11 MW in 2027 (see Table 19-7).

Table 19-7: Balclutha supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Balclutha 0.97 3 3 4 4 5 6 7 8 9 10 11

Solution

The overloading issues can be managed operationally, but we will study the possibility of resolving the protection limit, which will solve the issue until 2014. The installation of new capacitors at 33 kV (as part of the Lower South Island Reliability Project) will release some additional capacity. This work is planned for 2013-2015 in coordination with the 33 kV outdoor switchgear to an indoor switchboard conversion, which could remove some of the other transformer branch limiting components.

19.8.4 Cromwell supply transformer capacity

Project reference: CML-POW_TFR-EHMT-01




Issue

Two 220/110/33 kV transformers (rated at 73 MVA163

and 50 MVA) supply Cromwell’s 33 kV loads, with:



(summer/winter).

162

The transformer’s 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).

163 This is a bank of two transformers connected in parallel, and operated as a single unit, with the 33 kV transformer windings providing a combined nominal installed capacity of 73 MVA.

164 The transformer’s capacity is limited by the protection limit, followed by the current transformer, 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).



The peak load at Cromwell is forecast to exceed the transformers’ n-1 winter capacity by approximately 3 MW in 2019, increasing to approximately 13 MW in 2027 (see Table 19-8).

Table 19-8: Cromwell supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Cromwell 1.0 0 0 0 0 0 0 3 5 8 11 13

Solution

Resolving the protection limit will provide sufficient n-1 capacity until 2020. Upgrading other transformer branch limiting components will resolve the issue for the forecast period and beyond. Future investment will be customer driven.

19.8.5 Edendale supply transformer capacity

Project reference: Upgrade protection and transformer capacity: EDN-POW_TFR-EHMT-01 Upgrade cable: EDN-POW_TFR-EHMT-01

Project status/purpose: Upgrade protection/transformer capacity: Base Capex, minor enhancement/replacement Upgrade cable: possible, customer-specific

Indicative timing: Upgrade cable and protection: 2012 Upgrade transformer capacity: 2017

Indicative cost band: Upgrade cable and protection: A Upgrade transformer capacity: B

Issue

Two 110/33 kV transformers supply Edendale’s load, providing:



(summer/winter).

The peak load at Edendale is forecast to exceed the n-1 winter capacity by approximately 1 MW in 2013, increasing to approximately 17 MW in 2027 (see Table 19-9).

Table 19-9: Edendale supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Edendale 0.98 0 1 2 3 4 5 8 10 12 15 17

Solution

Resolving the cable and protection limits will provide sufficient n-1 capacity until 2017. We will discuss future supply options with PowerNet, including:

operational management by transferring or limiting the load to within the capability of the supply transformer, or

replacing the existing transformers with two higher-rated units.

In addition, both supply transformers at Edendale have an expected end-of-life at the end of the forecast period. We will discuss the rating and timing for the replacement transformers with PowerNet. Future investment will be customer driven.

165

The transformers’ capacity is limited by the cable and protection limit; with these limits resolved, the n-1 capacity will be 34/36 MVA (summer/winter).



19.8.6 Frankton transmission and supply security

Project reference: Upgrade protection and metering: FKN-POW_TFR-EHMT-01 Upgrade line thermal capacity: CML_FKN-TRAN-EHMT-01 Upgrade transformer capacity: FKN-POW_TFR-EHMT-02

Project status/purpose: Upgrade protection and metering: Base Capex, minor enhancement Upgrade line and transformer capacities: possible, customer-specific

Indicative timing: Upgrade line thermal capacity: 2019 Upgrade protection and metering, and transformer capacity: 2022

Indicative cost band: Upgrade line thermal capacity: to be advised Upgrade protection and metering: A Upgrade transformer capacity: A

Issue

Two 110 kV Cromwell–Frankton circuits supply Frankton’s load, providing:



(summer/winter).

Two 110/33 kV transformers (rated at 66 MVA167

and 85 MVA) supply Frankton’s load, providing:



(summer/winter).

There is no 110 kV bus at Frankton. A fault on either a circuit or Frankton supply transformer will cause both the circuit and supply transformer to be taken out of service.

The peak load at Frankton is forecast to exceed the circuits’ n-1 winter thermal capacity from approximately 2019, and the transformers’ n-1 winter capacity by approximately 1 MW in 2023, increasing to approximately 8 MW in 2027 (see Table 19-10).

Table 19-10: Frankton supply transformer and Cromwell–Frankton circuit overload forecast


Transformer/circuit overload (MW)


2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Frankton supply transformer

0.99 0 0 0 0 0 0 0 0 1 4 8

Cromwell–Frankton circuits

0.99 0 0 0 0 0 0 2 5 8 12 15

Solution

We will discuss future supply options with Aurora closer to the time the issue arises. Possible options are:

thermally upgrading the Cromwell–Frankton circuits

resolving the protection limit and recalibrating metering parameters on the newly commissioned transformer at Frankton, and

increasing the thermal capacity of the two older supply transformers by adding pumps.

166

The circuits’ capacity is limited by a line trap; with this limit resolved, the n-1 capacity will be 63/77 MVA (summer/winter).

167 This is a bank of two transformers connected in parallel, and operated as a single unit, providing a total nominal installed capacity of 66 MVA.

168 The transformer’s capacity is limited by the protection limit, followed by the metering (82 MVA) and LV cable (90 MVA) limits; with these limits resolved, the n-1 capacity will be 113/119 MVA (summer/winter).



Easements on some small parts of the line may be required for the thermal upgrade work.


19.8.7 Gore supply transformer capacity

Project reference: GOR-POW_TFR-REPL-01



Indicative cost band: Replace transformers with higher-rated units: A

Issue

Two 110/33 kV transformers supply Gore’s load, providing:



The peak load at Gore is forecast to exceed the transformers’ n-1 winter capacity by approximately 19 MW in 2014, increasing to approximately 47 MW in 2027 (see Table 19-11).

Table 19-11: Gore supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Gore 0.97 0 0 19 20 40 41 42 44 45 46 47

Solution

We will discuss future supply options with PowerNet, including:

load projections and developments in the area

managing the load to within the capability of the existing transformers, or


In addition, we also plan to convert the Gore 33 kV outdoor switchgear to an indoor switchboard within the next five years.

The solutions do not raise property issues as the existing substation has sufficient room to accommodate the transformers and an indoor switchboard.

19.8.8 Halfway Bush supply transformer capacity

Project reference: HWB-POW_TFR-REPL-01




Issue

Three transformers supply Halfway Bush’s 33 kV load, comprising:

two 110/33 kV transformers, each with nominal capacity of 50 MVA, and n-1 capacity of 54/57 MVA (summer/winter), and

one 220/33 kV transformer, with a nominal capacity of 100 MVA, and n-1 capacity of 112/112 MVA

169 (summer/winter).

169

The transformers’ capacity is limited by a protection limit; with this limit resolved, the n-1 capacity will be 124/131 MVA (summer/winter).



We operate the 33 kV bus split with:

both 110/33 kV transformers connected in parallel supplying one bus section, and

the 220/33 kV transformer supplying the other bus section, resulting in no continuous n-1 supply security.

The 33 kV bus split can be closed during an outage of any one of the three supply transformers supplying the 33 kV load. This provides an n-1 capacity of 107/114 MVA (summer/winter) for an outage of the 220/33 kV transformer.

The peak load at Halfway Bush is forecast to exceed the transformers’ n-1 winter capacity by approximately 17 MW in 2012, increasing to approximately 25 MW in 2027 (see Table 19-12).

Table 19-12: Halfway Bush supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Halfway Bush -1 & -2

0.99 17 19 20 7 8 10 13 17 20 23 25

The Halfway Bush supply transformer loading may be reduced by:

transferring load between the Halfway Bush 110 kV and 220 kV buses with the 33 kV bus split, and/or

increasing the output from Waipori generation injecting into the Halfway Bush 33 kV bus, and/or

transferring up to 5 MW via Aurora’s distribution network to South Dunedin.

Solution

We are investigating closing the 33 kV bus permanently. This requires the 33 kV fault level, load sharing between the transformers, and the 33 kV bus voltage set-point and voltage 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 MVA supply transformers with a single 220/33 kV, 120 MVA supply transformer by 2017. The old 220/33 kV, 100 MVA supply transformer will be replaced with a 120 MVA unit by 2025. Converting the 33 kV outdoor switchgear to an indoor switchboard is also scheduled to be carried out within the next five years, and we are co-ordinating this with some of Aurora’s feeder rationalization projects.


19.8.9 Invercargill supply transformer capacity

Project reference: INV-POW_TFR-EHMT-01




Issue

Two 220/33 kV transformers supply Invercargill’s load, providing:


n-1 capacity of 105/105MVA170

(summer/winter).

170

The transformers’ capacity is limited by metering equipment; with this limit resolved, the n-1 capacity will be 155/162 MVA (summer/winter).



The peak load at Invercargill is forecast to exceed the transformers’ n-1 winter capacity by approximately 2 MW in 2013, increasing to approximately 33 MW in 2027 (see Table 19-13).

Table 19-13: Invercargill supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Invercargill 0.99 0 2 5 7 9 11 16 20 24 29 33

Solution

Recalibrating the metering parameters at Invercargill will solve the issue within the forecast period.

19.8.10 Naseby supply transformer capacity

Project reference: NSY-POW_TFR_EHMT-01




Issue

Two 220/33 kV transformers supply Naseby’s load, providing:



The peak load at Naseby is forecast to exceed the transformers’ n-1 summer capacity by approximately 1 MW in 2014, increasing to approximately 9 MW in 2027 (see Table 19-14).

Table 19-14: Naseby supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Naseby 1.0 0 0 1 1 2 3 4 6 7 8 9

Solution

We will discuss future supply options with PowerNet, which include:

managing the load to within the capability of the existing transformers, or


In addition, both transformers are scheduled for replacement within the next 5-10 years and converting the 33 kV outdoor switchgear to an indoor switchboard is also scheduled to be carried out at around the same time. We will discuss the rating and timing for the replacement transformers with PowerNet, and co-ordinate the outdoor to indoor conversion project with the replacement work.


19.8.11 North Makarewa supply transformer capacity

Project reference: NMA-POW_TFR-EHMT-01






Issue

Two 220/33 kV transformers supply North Makarewa’s load, providing:



(summer/winter).

The peak load at North Makarewa is forecast to exceed the transformers’ n-1 winter capacity by approximately 3 MW in 2021, increasing to approximately 8 MW in 2027 (see Table 19-15).

Table 19-15: North Makarewa supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

North Makarewa

0.99 0 0 0 0 0 0 0 3 5 7 8

Solution

We have discussed future supply options with PowerNet and they intend to replace the two existing 220/33 kV supply transformers with new 220/66 kV units by 2019.


19.8.12 Palmerston supply security and supply transformer capacity


Issue

A single 110/33 kV, 10 MVA supply transformer comprising three single-phase units supplies the load at Palmerston, resulting in no n-1 security. This transformer also has an expected end-of-life within the next five years.

The peak load at Palmerston is forecast to exceed the transformer’s capacity by approximately 1 MW in 2012, increasing to approximately 4 MW in 2027 (see Table 19-16).

Table 19-16: Palmerston supply transformer overload forecast

Grid exit point

Power factor



2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

Palmerston 0.97 1 1 1 1 1 2 2 3 3 3 4

Solution

There is a non-contracted spare on-site unit providing backup after a unit failure, with replacement taking 8-14 hours. A limited amount of load can also be back-fed through the OtagoNet transmission network.

We are discussing future development options with OtagoNet. Converting the transmission to Palmerston to 33 kV (see Section 19.8.13) avoids the need to replace the Palmerston 110/33 kV supply transformer and improves the security of supply.


171

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).



19.8.13 Palmerston transmission security


Issue

Two 110 kV circuits supply Palmerston’s load, which include the:

Halfway Bush–Palmerston 1 circuit, and

Halfway Bush–Palmerston 2 circuit.

Neither circuit has a circuit breaker at Palmerston, preventing the two circuits from normally operating in parallel. The Halfway Bush–Palmerston 2 circuit is normally open and the loss of the Halfway Bush–Palmerston 1 circuit will result in a short loss of supply to Palmerston until the other circuit can be put into service. Consequently, Palmerston has no continuous n-1 supply security.

Solution

The issue can be managed operationally. One possible option is to operate both circuits at 33 kV, and reconfigure the distribution network to provide continuous n-1 security at Palmerston.


19.8.14 South Dunedin supply transformer capacity

Project reference: SDN-POW_TFR-EHMT-01




Issue

Two 220/33 kV transformers supply South Dunedin’s load, providing:



(summer/winter).

The peak load at South Dunedin is forecast to exceed the transformers’ n-1 winter capacity by approximately 16 MW in 2015, increasing to approximately 30 MW in 2027 (see Table 19-17).

Table 19-17: South Dunedin supply transformer overload forecast




2012 2013 2014 2015 2016 2017 2019 2021 2023 2025 2027

South Dunedin 0.99 0 0 0 16 17 18 20 23 25 27 30

Solution

Recalibrating the metering parameters at South Dunedin resolves the issue within the forecast period.

In addition:

the South Dunedin 33 kV outdoor switchyard will be converted to an indoor switchboard within the next five years. If appropriate, we will resolve the metering limits during the conversion work.

172

The transformers’ capacity is limited by metering equipment, followed by the protection limit of 110 MVA; with these limits resolved, the n-1 capacity will be 132/139 MVA (summer/winter).



The South Dunedin T1 supply transformer has an expected end-of-life in the next 10-15 years. We will discuss the rating and timing for the replacement transformer with Aurora.

19.8.15 Waipori transmission security


Issue

Waipori generation injects into the Berwick 110 kV bus. The 110 kV Balclutha–Berwick and Berwick–Halfway Bush circuits presently have no line protection at the Berwick end, and both circuits will trip in the event of a line fault. This will disconnect Waipori generation from the National Grid, resulting in no n-1 connection security.

Solution

Trustpower has not requested a higher security level and there are no plans to increase supply security at this grid injection point. Future investment will be customer driven. If n-1 connection security is eventually required, then line protection, together with the associated 110 kV current transformers and a voltage transformer at Berwick, will need to be installed.



19.10 Otago-Southland generation proposals and opportunities

This section details relevant regional issues for selected generation proposals that are under investigation by developers and in the public domain, or other generation opportunities.


173


Otago-Southland is a generation-rich region. Surplus generation export is constrained by the 220 kV Naseby–Roxburgh–Livingstone circuit ratings. At times, existing generation needs to be constrained under light load conditions to avoid overloading of the 220 kV Naseby–Roxburgh–Livingstone circuit under both normal operating conditions and during contingent events (see Chapter 6 for more information).

We have committed to implementing the Clutha-Upper Waitaki Lines Project to reinforce the Twizel and Livingstone circuits to Roxburgh. This in turn increases the generation export capability to the region, which enables new generation connections.

173




19.10.2 Mahinerangi wind station

Expansion of the Mahinerangi wind generation station beyond stage 1 can be accommodated on the National Grid via the two 110 kV Halfway Bush–Roxburgh circuits.

Only relatively minor upgrades within the Otago-Southland region are required to enable the connection of over 200 MW of Mahinerangi generation. Potential upgrades include increasing the Roxburgh 220/110 kV transformer capacity (an approved project that is part of the Lower South Island Reliability Project), a thermal upgrade of part of the two 110 kV Roxburgh–Halfway Bush circuits, and increasing the Halfway Bush 220/110 kV transformer capacity. Some or all of these upgrades may not be required, depending on the staged development of the wind station, load growth, and the economic level of trade-off between Mahinerangi generation, Waipori, and generation connections to the Roxburgh 110 kV bus.

19.10.3 Edendale–Gore wind stations

There are a number of wind generation prospects in the area to the south-east of the line between Edendale and Gore.

One option is to connect wind generation to the relatively low capacity 110 kV single-circuit line that runs between the Invercargill and Halfway Bush substations, which connects through the Edendale, Brydone, and Gore substations. This 110 kV line cannot be thermally upgraded. Approximately 100-120 MW of wind generation can be connected at a substation (or less if at a new connection point along the line), but will 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-circuit North Makarewa–Three Mile Hill line. Approximately 350 MW of generation can be connected, but parts of the line will need to be thermally upgraded.

Appendix A: Grid Reliability Report


Appendix A Grid reliability report

A.1 Ten year forecast of demand at each grid exit point



12.76(1)(a) a forecast of demand at each grid exit point over the next ten years

The table below provides a forecast of demand at each grid exit point. These can also be viewed within the respective regional plans in Chapters 7-19.

Table A.1: Ten year forecast of demand at each grid exit point

Prudent peak demand (MW) forecast

2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022

NORTHLAND

Albany 33 kV 160 165 170 175 180 186 191 197 203 207 211

Albany 110 kV (Wairau Road)

160 165 170 175 180 186 191 197 203 207 211

Bream Bay 45 46 46 47 48 49 49 52 53 53 54

Dargaville 13 13 14 14 14 14 15 15 15 16 16

Henderson 130 134 138 142 146 151 155 160 165 168 171

Hepburn Road 165 170 175 180 186 191 197 203 209 213 218

Kensington 70 71 73 74 75 77 78 79 80 82 83

Maungatapere 33 kV 54 55 56 57 59 60 61 62 64 65 66

Maungatapere 110 kV 63 65 66 68 70 71 73 75 77 78 80

Maungaturoto 18 18 18 19 19 19 20 20 20 21 21

Silverdale 80 82 85 87 90 93 96 98 101 103 105

Wellsford 35 36 37 38 39 40 41 42 43 43 44

Region peak 910 937 959 982 1010 1036 1060 1079 1107 1122 1144

Region demand at island peak

886 914 931 938 963 988 1005 1015 1033 1046 1061

AUCKLAND

Bombay 33 kV 25 26 26 27 14 14 14 14 0 0 0

Bombay 110 kV 51 52 53 54 69 70 72 73 89 90 92

Glenbrook 33 kV 32 33 33 34 35 35 36 37 38 38 39

Glenbrook NZ Steel 116 116 120 120 120 120 120 120 120 120 120

Hobson Street 0 0 126 130 134 137 141 144 148 150 153

Mangere 33 kV 115 119 122 126 129 133 137 141 146 149 152

Mangere 110 kV 55 55 55 55 55 55 55 55 55 55 55

Meremere 14 14 15 15 0 0 0 0 0 0 0

Mt Roskill 22 kV 130 134 138 142 146 151 155 160 165 168 171

Mt Roskill 110 kV – Kingsland

66 68 70 72 74 76 78 80 82 83 84

Otahuhu 66 69 71 73 75 77 80 82 84 86 89




2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022

Pakuranga 163 167 171 174 178 182 185 189 192 196 200

Penrose 22 kV 50 52 53 55 56 58 60 62 63 65 66

Penrose 33 kV 300 309 318 328 338 348 358 369 380 388 395

Penrose 110 kV - Liverpool Street

238 246 126 130 134 137 141 144 148 150 153

Penrose 110 kV - Quay Street

0 0 0 0 0 0 0 0 0 0 0

Takanini 125 129 133 137 141 145 149 154 158 162 165

Wiri 82 85 87 90 92 95 98 101 104 106 108

Region peak 1535 1569 1605 1637 1680 1723 1762 1787 1819 1849 1878


1429 1468 1499 1515 1540 1576 1605 1623 1653 1674 1697

WAIKATO

Cambridge 38 39 39 40 40 41 42 42 43 43 38

Hamilton 11 kV 47 48 49 25 0 0 0 0 0 0 0

Hamilton 33 kV 148 151 154 182 212 216 221 225 230 234 238

Hamilton NZR 8 8 8 8 8 8 8 8 8 8 8

Hangatiki 30 31 31 32 33 33 34 35 35 36 36

Hinuera 47 48 42 43 44 45 46 47 48 49 50

Huntly 25 25 26 26 42 43 43 44 45 45 46

Kopu 50 52 53 55 56 58 60 62 63 65 66

Piako 0 28 28 29 30 31 32 33 34 35 35

Putaruru 0 0 7 8 8 8 8 8 8 9 9

Te Kowhai 105 110 112 117 120 122 124 127 129 131 133

Te Awamutu 37 37 38 39 39 40 41 41 42 43 44

Waihou 67 41 43 44 45 47 48 49 51 52 53

Waikino 41 42 44 45 46 48 49 50 52 53 54

Whakamaru 11 11 11 11 12 12 12 12 13 13 13

Region peak 501 521 535 545 549 568 580 586 600 605 614


454 467 478 487 513 526 538 548 561 570 580

BAY OF PLENTY

Edgecumbe 65 67 70 72 75 77 80 83 86 88 90

Kaitimako 22 27 34 35 36 37 38 39 41 41 42

Kawerau Horizon 21 21 22 23 23 24 24 25 26 26 26

Kawerau T6-T9 90 90 90 90 90 90 90 90 90 90 90

Kawerau T11/ T14 85 85 85 85 85 85 85 85 85 85 85

Kinleith 11 kV 85 85 85 85 85 85 85 85 85 85 85

Kinleith 33 kV 28 29 29 30 30 31 32 32 33 33 34

Lichfield 9 9 9 9 9 9 9 9 9 9 9

Mt Maunganui 33 kV 72 74 76 74 76 79 81 84 86 88 90

Owhata 16 16 17 17 17 18 18 18 19 19 19

Papamoa 0 0 0 10 10 10 10 10 10 10 10




2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022

Rotorua 11 kV 35 35 36 36 36 36 37 37 37 38 38

Rotorua 33 kV 42 42 43 43 43 44 44 44 45 45 46

Tauranga 11 kV 30 31 26 27 28 28 29 30 30 31 32

Tauranga 33 kV 88 91 93 96 99 102 105 108 112 114 116

Tarukenga 11 kV 12 12 12 13 13 13 13 13 14 14 14

Te Kaha 2 2 2 2 2 2 2 2 2 2 2

Te Matai 33 34 35 31 32 33 34 35 36 37 38

Waiotahi 10 10 11 11 11 11 12 12 12 12 13

Region peak 564 573 579 580 590 605 613 619 630 636 642


552 554 564 573 585 598 608 618 629 623 629


Bunnythorpe 33 kV 110 112 114 117 119 121 124 126 129 131 133

Bunnythorpe NZR 8 8 8 8 8 8 8 8 8 8 8

Dannevirke 15 15 16 16 16 17 17 17 18 18 18

Linton 75 77 78 80 81 83 85 86 88 89 91

Mangamaire 12 12 13 13 13 13 14 14 14 14 15

Mangahao 39 40 41 41 42 43 44 45 46 46 47

Marton 16 16 17 17 17 18 18 18 19 19 19

Mataroa 8 8 8 9 9 9 9 9 9 10 10

National Park 8 8 8 8 8 8 8 8 8 9 9

Ohaaki 6 6 6 6 6 6 6 7 7 7 7

Ohakune 11 11 9 10 10 10 10 11 11 11 11

Ongarue 11 11 11 11 11 11 11 11 12 12 12

Tokaanu 11 11 11 11 11 11 12 12 12 12 12

Tangiwai 11 kV 44 44 47 47 48 48 49 49 50 50 51

Tangiwai NZR 10 10 10 10 10 10 10 10 10 10 10

Woodville 4 4 4 4 5 5 5 5 5 5 5

Waipawa 22 23 23 24 24 25 25 26 26 27 27

Wairakei 50 51 52 53 54 55 56 57 59 60 60

Region peak 334 342 348 352 357 360 364 365 365 370 371


286 298 305 307 317 328 334 337 345 349 355

TARANAKI

Brunswick 43 44 45 46 47 48 48 49 50 51 52

Carrington Street 62 63 65 66 67 69 70 71 73 74 75

Huirangi 28 29 29 30 30 31 32 32 33 33 34

Hawera 32 33 33 34 35 35 36 37 38 38 39

Hawera (Kupe) 12 12 12 12 12 12 12 12 12 12 12

Motunui 9 9 9 9 9 9 9 9 9 9 9

Moturoa 22 23 23 24 25 25 26 27 27 28 28

Opunake 11 11 11 12 12 12 12 13 13 13 13

Stratford 33 kV 31 32 32 32 33 33 34 34 35 35 36




2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022

Stratford 220 kV 11 11 11 12 12 12 12 13 13 13 13

Taumarunui 11 11 11 11 11 11 11 11 11 11 11

Wanganui 50 51 52 53 54 55 56 57 59 60 60

Waverley 4 4 4 4 4 4 4 4 4 4 5

Region peak 218 223 227 229 232 236 239 240 242 243 245


214 218 222 224 228 232 234 235 237 238 240

HAWKE’S BAY

Fernhill 60 61 62 63 64 65 66 67 68 68 69

Gisborne 49 50 52 53 54 55 57 58 60 61 62

Redclyffe 70 76 77 78 79 80 82 83 84 85 86

Tuai 1 1 1 1 1 1 1 1 1 1 1

Wairoa 10 10 10 11 11 11 11 12 12 12 12

Whirinaki 82 82 82 82 82 82 82 82 82 82 82

Whakatu 95 96 98 99 101 102 104 105 107 108 110

Region peak 318 322 327 330 333 339 343 346 351 354 356


284 293 297 299 306 314 319 321 326 329 334

WELLINGTON

Central Park 11 kV 27 33 33 34 34 35 35 36 37 37 38

Central Park 33 kV 175 174 177 181 184 188 192 196 200 203 206

Gracefield 60 61 62 64 65 66 68 69 70 71 72

Greytown 16 17 17 17 18 18 19 19 19 20 20

Haywards 11 kV 23 24 24 24 25 25 26 26 27 27 28

Haywards 33 kV 20 20 21 21 22 22 23 23 23 24 24

Kaiwharawhara 43 44 45 46 47 48 49 50 51 52 52

Masterton 51 52 53 54 55 56 57 59 60 61 62

Melling 11 kV 30 31 31 32 33 33 34 35 35 36 36

Melling 33 kV 50 51 52 53 54 55 56 57 59 60 60

Pauatahanui 23 24 24 25 25 26 26 26 27 27 28

Paraparaumu 68 69 70 71 71 72 73 74 75 76 77

Takapu Road 103 105 107 110 112 114 116 119 121 123 125

Upper Hutt 37 37 38 38 39 40 40 41 41 42 42

Wilton 65 66 68 69 70 72 73 75 76 77 79

Region peak 755 768 783 799 809 821 833 841 856 865 874


707 730 743 748 768 788 802 808 823 832 844

NELSON-MARLBOROUGH

Blenheim 80 82 84 86 88 90 92 94 96 98 100

Motueka 20 21 21 21 22 22 22 22 23 23 23

Motupipi 8 8 9 9 9 9 9 10 10 10 10

Stoke 144 147 149 152 155 158 161 164 166 169 172




2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022

Region peak 244 248 254 258 260 266 268 270 272 275 278


210 214 217 221 226 229 231 234 233 236 239

WEST COAST

Arthur’s Pass 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5

Atarau 1.0 11.0 11.0 11.0 11.0 11.0 11.0 11.0 11.0 11.0 11.0

Castle Hill 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9

Dobson 16.0 16.3 16.6 20.9 21.2 21.5 25.8 26.1 26.4 26.6 26.9

Greymouth 15.0 15.3 15.6 15.9 16.2 16.6 16.9 17.2 17.6 17.8 18.1

Hokitika 16.8 17.0 19.8 20.0 20.3 20.5 20.8 21.0 21.3 21.5 21.7

Kikiwa 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0

Kumara 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0

Murchison 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0

Orowaiti 11.0 19.2 19.3 19.5 19.7 19.9 20.0 20.2 20.4 20.5 20.7

Otira 0.9 0.9 0.9 0.9 0.9 1.9 1.9 1.9 1.9 1.9 1.9

Reefton 11.0 11.2 11.4 11.7 11.9 12.1 12.4 12.6 12.9 13.1 13.3

Westport 10.2 10.3 10.5 10.6 10.8 10.9 11.1 11.3 11.4 11.6 11.7

Region peak 62 67 73 76 78 80 82 84 86 88 90


47 59 57 61 62 63 67 68 68 69 69

CANTERBURY

Addington 11 kV -1 35 37 38 40 41 41 42 42 35 35 36

Addington 11 kV -2 25 26 27 28 28 29 29 29 24 24 25

Addington 66 kV 133 138 142 145 148 150 152 149 135 136 138

Ashburton 33 kV 55 56 29 29 30 15 16 16 8 8 9

Ashburton 66 kV 133 137 149 154 158 167 171 176 184 187 190

Ashley 12 12 13 22 23 23 24 24 25 25 26

Bromley 11 kV 56 58 60 61 62 63 61 61 62 63 64

Bromley 66 kV 171 183 188 194 198 199 203 209 291 294 297

Coleridge 1 1 1 1 1 1 1 1 1 1 1

Culverden 33 kV 21 21 22 25 26 27 27 28 29 29 29

Culverden 66 kV 10 10 10 11 11 11 11 12 12 12 12

Hororata 33 kV 31 25 25 25 26 19 19 19 20 20 20

Hororata 66 kV 27 42 32 32 36 44 44 44 45 45 46

Islington 33 kV 73 75 76 78 79 81 82 84 86 87 88

Islington 66 kV 128 129 135 152 154 156 158 159 161 162 164

Islington 66 kV - Papanui 113 112 112 113 114 115 117 118 81 82 82

Kaiapoi 29 29 30 30 31 32 32 33 33 34 34

Middleton 30 31 31 32 33 33 34 35 35 36 36

Southbrook 43 45 46 39 40 41 42 43 44 45 46

Springston 33 kV 43 34 34 36 38 33 34 34 35 35 36

Springston 66 kV 21 32 48 49 50 58 60 61 63 64 65




2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022

Waipara 33 kV 13 13 14 14 14 22 22 23 23 23 23

Waipara 66 kV 12 13 13 13 13 14 14 14 15 15 15

Region peak 808 837 860 887 917 941 958 976 995 1010 1023


792 821 848 864 882 894 907 924 953 966 978

SOUTH CANTERBURY

Albury 4 4 4 4 4 4 5 5 5 5 5

Bells Pond 8 8 17 17 17 17 17 17 17 17 17

Black Point 12 20 21 22 23 23 24 24 24 24 24

Oamaru 44 46 62 65 68 69 71 73 75 75 76

St Andrews 0 0 0 0 0 35 45 45 45 45 45

Studholme 17 18 25 26 28 33 34 36 37 38 38

Tekapo A 6 6 6 7 7 7 8 8 8 9 9

Temuka 65 68 70 73 75 78 85 87 90 92 94

Timaru 71 72 81 81 82 82 83 83 84 84 85

Twizel 6 6 6 6 7 7 7 7 7 7 7

Waitaki 7 7 7 11 11 11 12 17 17 17 17

Region peak 190 199 213 227 233 261 277 292 298 301 305


138 146 172 176 179 197 205 208 210 212 213

OTAGO-SOUTHLAND

Balclutha 31 31 32 32 33 34 34 35 36 36 37

Brydone 12 12 12 12 12 12 12 12 12 12 12

Cromwell 34 35 37 38 40 41 42 44 45 46 48

Clyde 11 11 11 12 12 12 12 13 13 13 13

Edendale 31 32 33 34 38 39 40 41 43 44 45

Frankton 57 58 60 62 64 65 67 69 70 72 74

Gore 34 40 61 62 82 83 84 84 85 86 86

Halfway Bush -1 120 121 123 109 111 112 114 116 117 119 120

Halfway Bush -2 111 113 114 115 117 118 119 121 122 124 125

Invercargill 103 105 108 110 112 114 116 118 121 123 125

Naseby 33 34 35 35 36 37 38 38 39 40 40

North Makarewa 57 58 59 61 62 63 64 66 67 68 69

Palmerston 10 10 10 11 11 11 11 12 12 12 12

South Dunedin 77 78 79 96 97 98 99 100 101 102 103

Tiwai 640 640 640 645 650 655 660 665 670 675 680

Region peak 1107 1114 1129 1142 1152 1165 1178 1190 1201 1209 1216


1057 1069 1090 1106 1139 1151 1162 1175 1176 1190 1201



A.2 Ten year forecast of supply at each grid injection point



12.76(1)(b) a forecast of supply at each grid injection point over the next ten years

The table below provides a forecast of supply at each grid injection point. These can also be viewed within the respective regional plans in Chapters 7-19.

Table A.2: Ten year forecast of generation capacity at each grid injection point


2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022

NORTHLAND

Albany (Rosedale) 3 3 3 3 3 3 3 3 3 3 3

Kaikohe (Ngawha) 27 27 27 27 27 27 27 27 27 27 27

Maungatapere (Wairua) 5 5 5 5 5 5 5 5 5 5 5

Silverdale (Redvale) 10 10 10 10 10 10 10 10 10 10 10

AUCKLAND

Glenbrook 112 112 112 112 112 112 112 112 112 112 112

Mangere (Watercare Mangere)

7 7 7 7 7 7 7 7 7 7 7

Otahuhu B CCGT

380 380 380 380 380 380 380 380 380 380 380

Otahuhu (Greenmount Landfill)

5 5 5 5 5 5 5 5 5 5 5

Penrose (Auckland Hospital)

4 4 4 4 4 4 4 4 4 4 4

Southdown CCGT 170 170 170 170 170 170 170 170 170 170 170

Takanini (Whitford Landfill) 3 3 3 3 3 3 3 3 3 3 3

WAIKATO

Arapuni 197 197 197 197 197 197 197 197 197 197 197

Atiamuri 84 84 84 84 84 84 84 84 84 84 84

Huntly 1448 1448 1448 1448 1448 1448 1448 1448 1448 1448 1448

Karapiro 90 90 90 90 90 90 90 90 90 90 90

Maraetai 360 360 360 360 360 360 360 360 360 360 360

Mokai 112 112 112 112 112 112 112 112 112 112 112

Ohakuri 112 112 112 112 112 112 112 112 112 112 112

Te Kowhai (Te Rapa) 44 44 44 44 44 44 44 44 44 44 44

Te Kowhai (Te Uku) 64 64 64 64 64 64 64 64 64 64 64

Waipapa 51 51 51 51 51 51 51 51 51 51 51

Whakamaru 100 100 100 100 100 100 100 100 100 100 100

BAY OF PLENTY

Aniwhenua 25 25 25 25 25 25 25 25 25 25 25




2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022

Edgecumbe (Bay Milk) 10 10 10 10 10 10 10 10 10 10 10

Kawerau (BOPE) 6 6 6 6 6 6 6 6 6 6 6

Kawerau (TPP) 37 37 37 37 37 37 37 37 37 37 37

Kawerau - KAG 105 105 105 105 105 105 105 105 105 105 105

Kawerau (KA24) 9 9 9 9 9 9 9 9 9 9 9

Kawerau (Norske Skog) 25 25 25 25 25 25 25 25 25 25 25

Kinleith 28 28 28 28 28 28 28 28 28 28 28

Matahina 72 72 72 72 72 72 72 72 72 72 72

Mount Maunganui (Ballance Agri)

7 7 7 7 7 7 7 7 7 7 7

Rotorua (Fletcher Forests) 3 3 3 3 3 3 3 3 3 3 3

Rotorua (Wheao, Flaxy, Kaingaroa)

24 24 24 24 24 24 24 24 24 24 24

Tauranga (Kaimai) 42 42 42 42 42 42 42 42 42 42 42


Aratiatia 78 78 78 78 78 78 78 78 78 78 78

Bunnythorpe (Tararua Wind Stage 2)

36 36 36 36 36 36 36 36 36 36 36

Linton (Tararua Wind Stage 1)

32 32 32 32 32 32 32 32 32 32 32

Linton (Totara Road) 1 1 1 1 1 1 1 1 1 1 1

Mangahao 37 37 37 37 37 37 37 37 37 37 37

Nga Awa Purua 140 140 140 140 140 140 140 140 140 140 140

Nga Awa Purua - Ngatamariki

0 110 110 110 110 110 110 110 110 110 110

Ohaaki 46 46 46 46 46 46 46 46 46 46 46

Ongarue (Mokauiti, Kuratau and Wairere Falls)

13 13 13 13 13 13 13 13 13 13 13

Poihipi 51 51 51 51 51 51 51 51 51 51 51

Rangipo 120 120 120 120 120 120 120 120 120 120 120

Tararua Wind Central (Tararua Stage 3)

93 93 93 93 93 93 93 93 93 93 93

Tararua Wind Central (Te Rere Hau)

49 49 49 49 49 49 49 49 49 49 49

Te Mihi 0 0 166 166 166 166 166 166 166 166 166

Tokaanu 240 240 240 240 240 240 240 240 240 240 240

Wairakei 161 161 109 109 109 109 109 109 109 109 109

Wairakei (Hinemaiaia) 7 7 7 7 7 7 7 7 7 7 7

Wairakei (Rotokawa) 35 35 35 35 35 35 35 35 35 35 35

Wairakei (Te Huka) 23 23 23 23 23 23 23 23 23 23 23

Woodville - Te Apiti 90 90 90 90 90 90 90 90 90 90 90

TARANAKI

Carrington St (Mangorei) 5 5 5 5 5 5 5 5 5 5 5

Hawera - Kiwi Dairy (Whareroa)

70 70 70 70 70 70 70 70 70 70 70




2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022

Hawera – Patea

31 31 31 31 31 31 31 31 31 31 31

Hawera (Patearoa) 2 2 2 2 2 2 2 2 2 2 2

Huirangi (Mangahewa) 9 9 9 9 9 9 9 9 9 9 9

Huirangi (Motukawa) 5 5 5 5 5 5 5 5 5 5 5

Kapuni 25 25 25 25 25 25 25 25 25 25 25

Motunui Deviation (MPP) 0 100 100 100 100 100 100 100 100 100 100

Stratford 385 385 385 385 385 385 385 385 385 385 385

Stratford peaking plant 200 200 200 200 200 200 200 200 200 200 200

Stratford (Stratford Austral Pacific)

1 1 1 1 1 1 1 1 1 1 1

HAWKES BAY

Gisborne

4 4 4 4 4 4 4 4 4 4 4

Gisborne (Matawai) 2 2 2 2 2 2 2 2 2 2 2

Kaitawa 36 36 36 36 36 36 36 36 36 36 36

Piripaua 42 42 42 42 42 42 42 42 42 42 42

Redclyffe (Ravensdown) 8 8 8 8 8 8 8 8 8 8 8

Tuai 60 60 60 60 60 60 60 60 60 60 60

Wairoa (Waihi) 5 5 5 5 5 5 5 5 5 5 5

Whirinaki 155 155 155 155 155 155 155 155 155 155 155

Whirinaki (Pan Pac) 13 13 13 13 13 13 13 13 13 13 13

WELLINGTON

Central Park (Southern Landfill)

1 1 1 1 1 1 1 1 1 1 1

Central Park (Wellington Hospital)

8 8 8 8 8 8 8 8 8 8 8

Greytown (Hau Nui) 9 9 9 9 9 9 9 9 9 9 9

Masterton (Kourarau A and B)

1 1 1 1 1 1 1 1 1 1 1

Haywards (Silverstream) 3 3 3 3 3 3 3 3 3 3 3

West Wind 143 143 143 143 143 143 143 143 143 143 143

NELSON-MARLBOROUGH

Argyle - Branch River Scheme

11 11 11 11 11 11 11 11 11 11 11

Cobb 32 32 32 32 32 32 32 32 32 32 32

Blenheim (Lulworth Wind) 1 1 1 1 1 1 1 1 1 1 1

Blenheim (Marlborough Lines Diesel)

9 9 9 9 9 9 9 9 9 9 9

Blenheim (Waihopai) 3 3 3 3 3 3 3 3 3 3 3

Motupipi (Onekaka) 1 1 1 1 1 1 1 1 1 1 1

WEST COAST

Dobson (Arnold) 3 3 3 3 3 3 3 3 3 3 3

Hokitika (Amethyst) 0 6 6 6 6 6 6 6 6 6 6




2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022

Hokitika (McKays Creek) 1 1 1 1 1 1 1 1 1 1 1

Hokitika (Wahapo-Okarito Forks)

3 3 3 3 3 3 3 3 3 3 3

Kumara (Kumara and Dillmans)

10 10 10 10 10 10 10 10 10 10 10

Kumara (Hokitika Diesel) 3 3 3 3 3 3 3 3 3 3 3

CANTERBURY

Ashburton (Highbank) 25 25 25 25 25 25 25 25 25 25 25

Ashburton (Montalto) 2 2 2 2 2 2 2 2 2 2 2

Bromley (City Waste) 3 3 3 3 3 3 3 3 3 3 3

Coleridge 45 45 45 45 45 45 45 45 45 45 45

SOUTH CANTERBURY

Albury (Opuha) 8 8 8 8 8 8 8 8 8 8 8

Aviemore 220 220 220 220 220 220 220 220 220 220 220

Benmore 540 540 540 540 540 540 540 540 540 540 540

Ohau A 264 264 264 264 264 264 264 264 264 264 264

Ohau B 212 212 212 212 212 212 212 212 212 212 212

Ohau C 212 212 212 212 212 212 212 212 212 212 212

Tekapo A 25 25 25 25 25 25 25 25 25 25 25

Tekapo B 160 160 160 160 160 160 160 160 160 160 160

Waitaki 105 105 105 105 105 105 105 105 105 105 105

OTAGO-SOUTHLAND

Clyde

432 432 432 432 432 432 432 432 432 432 432

Manapouri 840 840 840 840 840 840 840 840 840 840 840

Roxburgh

320 320 320 320 320 320 320 320 320 320 320

Balclutha (Mt. Stuart) 8 8 8 8 8 8 8 8 8 8 8

Berwick/Halfway Bush (Waipori and Mahinerangi)

84 36

84 36

84 36

84 36

84 36

84 36

84 36

84 36

84 36

84 36

84 36

Clyde (Fraser) 3 3 3 3 3 3 3 3 3 3 3

Clyde (Horseshoe Bend hydro and wind)

4

2

4

2

4

2

4

2

4

2

4

2

4

2

4

2

4

2

4

2

4

2

Clyde (Talla Burn) 3 3 3 3 3 3 3 3 3 3 3

Clyde (Teviot and Kowhai) 11 2

11 2

11 2

11 2

11 2

11 2

11 2

11 2

11 2

11 2

11 2

Cromwell (Roaring Meg) 4 4 4 4 4 4 4 4 4 4 4

Frankton (Wye Creek) 1 1 1 1 1 1 1 1 1 1 1

Halfway Bush (Deep Stream)

5 5 5 5 5 5 5 5 5 5 5

Naseby (Falls Dam) 1 1 1 1 1 1 1 1 1 1 1

Naseby (Paerau) 10 10 10 10 10 10 10 10 10 10 10

North Makarewa (Monowai) 7 7 7 7 7 7 7 7 7 7 7

North Makarewa (White Hills Wind Farm)

58 58 58 58 58 58 58 58 58 58 58



A.3 Issues impacting on N-1 supply



12.76(1)(c) whether the power system is reasonably expected to meet the N-1 criterion, including in particular whether the power system would be in a secure state at each grid exit point, at all times over the next ten years.

12.76(1)(d) proposals for addressing any matters identified in accordance with rule 12.76(1)(c).

The issues impacting n-1 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 A.3: Backbone issues and resolving projects

Issue affecting n-1 Projects Indicative timing (June year)

Project references Investment proposal to CC (Forecast June years)

Investment purpose

Upper North Island voltage stability

Upper North Island reactive support – Stage 2 Upper North Island reactive support – Post-NIGUP

2011/12-2014/15 To be advised

UPNI-REA_SUP-DEV-02 UPNI-REA_SUP-DEV-03

Approved Q2 2012/13

To meet GRS To meet GRS

Upper North Island transmission capacity

A new 220/400 kV double-circuit transmission line from Pakuranga to Whakamaru.

See Chapter 6 for more information.

2011/12 NIGU-TRAN-DEV-01

Approved To meet GRS

Taranaki transmission capacity

Re-tune generator excitation systems and/or install power system stabilisers.

To be advised TRNK-GEN_PSS-DEV-01 NA Minor enhancement

Upper South Island voltage stability

Stage 1 – a sixth bus coupler at Islington.

Stage 2 - Install additional shunt reactive support around Islington and Bromley, or bus the existing circuits between Waitaki Valley and Islington where they converge near Geraldine.


2015/16

2016/17

ISL-BUS_SEC-EHMT-01

WTKV-REA_PWRS-DEV-01 GRD-BUSG_TRAN-DEV-01

Q2 2012/13

Q2 2013/14

To meet GRS

To meet GRS

Upper South Island transmission capacity

Options include:

an HVDC tap-off from the existing line north of Christchurch, and

a new transmission line to Ashburton or Islington.


To be advised

UPSI-TRAN-DEV-01

To be advised

To meet GRS

Transmission capacity south of Roxburgh

The projects include:

Install special protection schemes on the 220 kV and 110 kV network.

Replace interconnecting transformers at Roxburgh and 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.


2012/13-2014/15 LWSI-TRAN-EHMT-01 Approved To meet GRS



A.4: Regional issues and resolving projects

Region Issue affecting n-1 Projects Indicative timing (June year)


Investment purpose

Northland Henderson interconnecting transformer capacity

(Issue arises from 2023)

New grid exit point at Wairau Road.

Replace limiting switchgear on the Henderson T1 if required.

2013/14

2023/24

WRR-SUBEST-DEV-01

HEN-POW_TFR_DIS-EHMT-01

NA

NA

Customer-specific

Minor enhancement

Henderson–Wellsford transmission capacity


Automatic split the 110 kV network between Henderson and Maungatapere or thermal upgrade the Henderson–Wellsford circuits.

2024/25 HEN-MPE-TRAN-EHMT-01 To be advised To meet GRS

Marsden interconnecting transformer capacity


Install a 3rd 220/110 kV transformer, and

convert the 220 kV and 110 kV buses to three zones.

2023/24 MDN-POW_TFR-DEV-01 To be advised To meet GRS

North Auckland and the Northland region transmission capacity

North Auckland and Northland project (NAaN).

Q2 2013/14 ALB_PAK-TRAN-DEV-01 Approved To meet GRS

North of Henderson transmission capacity

(Issue already exists)

North Auckland and Northland project (NAaN) provides a 2

nd 220 kV connections

into Albany from the south.

NA NA NA NA

North of Huapai transmission security


Splitting Huapai 220 kV bus once the NAaN project is complete.

Q2 2013/14 HPI-BUSC-DEV-01 NA Minor enhancement

North of Marsden low voltage


Additional voltage support at Kaitaia or Maungatepere.

To be advised MDN-C_BANKS-DEV-01 NA To meet GRS and/or customer-specific

Upper North Island voltage instability for grid backbone contingencies

Upper North Island reactive support (see Chapter 6).

See backbone See backbone See backbone See backbone

Albany supply transformer capacity


Resolve protection and circuit breaker limits.

2023/24 ALB-POW_TFR_EHMT-01 NA Minor enhancement

Bream Bay supply Resolve protection limits. 2021/22 BRB-POW_TFR_PTN-EHMT-01 NA Minor enhancement





Investment purpose

transformer capacity


Dargaville transmission security


Transpower will discuss the timing and capacity of the Maungatapere supply transformers replacement with Northpower.

2012/13-2014/15

MPE-POW_TFR-EHMT-01 NA Replacement

Dargaville supply transformer capacity


Issue can be managed operationally, followed by adding fans and/or pumps.

2013/14 DAR-POW-TFR-EHMT-01 NA Customer-specific

Henderson supply transformer capacity


Issue can be managed operationally. Longer term solution is to install a third supply transformer.

To be advised HEN-POW_TFR-EHMT-01 NA Customer-specific

Kaikohe–Maungatapere 110 kV transmission capacity


Issue can be managed operationally. Longer term solution is to thermal upgrade 110 kV Kaikohe–Maungatapere circuits.

To be advised KOE_MPE-TRAN-EHMT-01 NA Customer-specific

Kensington transmission security and supply transformer capacity

(Supply transformer capacity issue already exists, transmission security issue arrises from 2016)

Issue can be managed operationally. Longer term solution is to replace supply transformers and upgrade the 33 kV switchboard, and upgrade branch limiting components on the Kensington–Maungatapere circuits.

NA To be advised

NA KEN-SUB-EHMT-01

NA NA

NA Customer-specific

Maungatapere supply transformer capacity

Issue can be managed operationally.


NA NA NA NA

Maungaturoto supply transformer capacity


Resolve the protection and metering limits. 2019/20 MTO-POW_TFR_PTN-EHMT-01 NA Minor enhancement

Silverdale supply transformer capacity


Resolve the metering limits. 2023/24 SVL-POW_TFR_PTN-EHMT-01 NA Minor enhancement

Wellsford supply transformer capacity

Transpower is investigation removing the protection limit.

2012/13 WEL-POW_TFR-EHMT-01 NA Minor enhancement





Investment purpose


Auckland Auckland region voltage quality

Upper North Island Reactive Support and North Island Grid Upgrade (see Chapter 6).

See backbone See backbone See backbone To meet GRS

North Auckland and Northland regional transmission security

Install new 220 kV cables between Pakuranga, Penrose and Albany.

Q2 2013/14 ALB_PAK-TRAN-DEV-01 Approved To meet GRS

Otahuhu interconnecting transformer capacity

Issue can be managed operationally. NA NA NA NA

Hobson Street supply security


New substation at Hobson Street. 2013/14 HOB-SUBEST-DEV-01 NA Customer-specific

Mangere supply transformer capacity


Limit the peak load to the transformer capacity and/or increase the transformer protection limits which will resolve the issue until 2018.

Q4 2011/12 MNG-POW_TFR_PTN-01 NA Minor enhancement

Mount Roskill supply transformer capacity


Remove the circuit breaker and protection limits will resolve the issue until 2019.

2014/15 ROS-POW_TFR-EHMT-01 NA Customer-specific

Otahuhu supply transformer capacity


Limit the peak load to the transformer capacity, or add a third supply transformer, or replace with existing transformers with higher-rated units.

To be advised OTA-POW_TFR-EHMT-01 NA Customer-specific

Otahuhu–Wiri 110 kV transmission capacity


Several options being investigated, they are:

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.

A new 220/110 kV connection at Bombay and supply Wiri from here and a 110 kV bus at Wiri.

To be advised OTA_WIR-TRAN-DEV-01 NA To be advised

Penrose 220 kV transmission security

The issue will be managed operationally before the commissioning of a new 220 kV

2013/14 PAK_PEN-TRAN-DEV-01 Approved To meet GRS





Investment purpose

(Issue already exists) cable connecting Pakuranga and Penrose.

Otahuhu–Penrose 110 kV transmission capacity


Resolve the constraint on the terminal spans at Otahuhu and Penrose substations. Longer-term solutions include replace Otahuhu T2 & T4 with higher impedance transformers, or upgrade the Otahuhu–Penrose circuit capacity.

2020/21 To be advised

OTA_PEN-TRAN-EHMT-01 OTA_PEN-TRAN-DEV-01

NA To be advised

Minor enhancement To meet GRS

Penrose 33 kV supply transformer capacity


Limit the peak load to the transformer capacity.

NA NA NA NA

Takanini supply transformer capacity


Remove protection constraints will delay the overload until 2014. Upgrade the circuit breaker and busbar rating will resolve the issue within the forecast period.

2012/13 2014/15

TAK-POW_TFR-EHMT-01 TAK-SUBEST-EHMT-01

NA NA

Minor enhancement Customer-specific

Wiri supply transformer capacity


Remove protection constraints will delay the overload until 2020. Longer term options will be limit the peak load to the transformer capacity or replace existing transformers with higher-rated units.

2019/20 2020/21

WIR-POW_TFR_PTN-EHMT-01 WIR-POW_TFR-EHMT-01

NA NA


Wiri Tee transmission capacity


Likely to be resolved by Otahuhu–Wiri solution.

To be advised OTA_WIR-TRAN-DEV-01 NA To be advised

Waikato Arapuni–Hamilton 110 kV transmission capacity


Issue can be managed operationally.

NA NA NA NA

Arapuni–Kinleith 110 kV transmission capacity


Possible short-term options are:

System splits

Special protection scheme, or

Kinleith 110 kV bus reconfiguration

2020/21-2026/27

ARI_KIN-TRAN-EHMT-01 2012/13 To meet GRS

Hamilton interconnecting transformer capacity


Issue can be managed operationally in the short-term. The longer term option is to install a new

NA 2025/26

NA HAM-POW_TFR-DEV-01

NA To be advised

NA To meet GRS





Investment purpose

interconnecting transformer.

Hamilton–Waihou 110 kV transmission capacity


Issue can be managed operationally in the short-term. Longer term options are to construct a new Hamilton–Waihou or upgrade existing Hamilton–Waihou circuits.

NA 2016/17

NA HAM_WHU-TRAN-DEV-01

NA NA

Customer-specific Customer-specific

Waihou–Waikino–Kopu spur low voltage


Install capacitors, either on the grid or within the distribution network, or install supply transformers with onload tap changers.

2014/15-2016/17 2013/14-2014/15

VLYS-REA_PWS-DEV-01 2014/15 To meet GRS

Cambridge supply transformer capacity


Upgrade bus section and protection limits. 2012/13-2013/14

CBG-SUBEST-EHMT-01 NA Customer-specific

Hamilton supply transformer capacity


Increase the rating of the two existing Te Kowhai transformer by installing radiators and fans and transfer load to Te Kowhai. Longer term options are to install a third 220/33 kV supply transformer at Hamilton or at Te Kowhai.

2012/13 2017/18

TWH-POW_TFR-EHMT-01 HAM-SUBEST-DEV-01

NA NA


Hangatiki supply transformer capacity


Contracted spare unit on site. Longer-term options are replace existing transformers with two 40 MVA units.

2014-15 HTI-POW_TFR-REPL-01 NA Replacement

Hinuera supply transformer capacity


New grid exit point at Putaruru, and replace the 30 MVA with a 60 MVA unit.


PTR-SUBEST-DEV-01 HIN-POW_TFR-EHMT-01

NA NA


Hinuera transmission security


New grid exit point at Putaruru. 2014/15 PTR-SUBEST-DEV-01 NA Customer-specific

Kopu supply transformer capacity


Reomove the protection constraints will resolve the issue until 2018.

Q2 2012/13 KPU-POW_TFR_PTN-EHMT-01 NA Minor enhancement

Maraetai–Whakamaru Issue can be managed operationally by an NA NA NA NA





Investment purpose

transmission capacity


existing generation runback scheme.

Te Awamutu supply transformer capacity


Resolve the protection limits. 2015/16 TMU-POW_TFR_PTN-EHMT-01 NA Minor enhancement

Te Awamutu transmission security


A second transmission circuit either from Hangatiki or Karapiro.

2014/15 HTI_TMU-TRAN-DEV-01 NA Customer-specific

Waihou supply transformer capacity


New grid exit point at Piako, and replace the supply transformers with higher-rated units.

2012/13 2022/23-2026/27

PAO-SUBEST-DEV-01 WHU-POW_TFR-REPL-01

NA NA

Customer-specific replacement

Waikino supply transformer capacity


Issue can be managed operationally. Longer-term option includes increase the supply transformers’ capacity.

NA 2020/21

NA WKO-POW_TFR- REPL-01

NA NA

NA replacement

Bay of Plenty Tarukenga interconnecting transformer capacity

Thermally upgrade the Kaitimako–Tarukenga circuits and change the operating voltage from 110 kV to 220 kV and install two 220/110 kV, 150 MVA transformers at Kaitimako. A third 220/110 kV interconnecting transformer at Kaitimako.

Q2 2012/13 2017/18

KMO_TRK-TRAN-EHMT-01 KMO-POW_TFR-DEV-01

Approved To be advised

To meed GRS To meed GRS

Tauranga and Mount Maunganui transmission security

(Issue arises from 2013 and from 2018)

New grid exit point at Papamoa. To be advised PPM-SUBEST-DEV-01 NA

Customer-specific

Edgecumbe supply transformer capacity


Upgrade protection limit, and replace transformers with higher-rated units.


EDG-POW_TFR_PTN-EHMT-01 EDG-POW_TFR-EHMT-01

NA NA


Kaitimako supply security







Investment purpose

Kinleith–Tarukenga 110 kV transmission capacity



Kinleith 110/33 kV supply transformer capacity


Replace the 20 MVA supply transformer with a 40 MVA unit.

2015/16 KIN-POW_TFR-EHMT-01 NA Customer-specific

Mount Maunganui supply transformer capacity



Okere–Te Matai 110 kV transmission capacity


Thermally upgrading the Kaitimako–Tarukenga circuits and changing the operating voltage from 110 kV to 220 kV and install two 220/110 kV, 150 MVA transformers at Kaitimako will alleviate the issue until 2023.

Q2 2012/13 KMO_TRK-TRAN-EHMT-01 Approved To meet GRS

Owhata supply transformer capacity


Increase the existing transformers capacity. Three options are currently under reviewed.

2014/15 OWH-POW_TFR-EHMT-01 NA Customer-specific

Rotorua supply transformer capacity


Increase 110/11 kV supply transformer capacity or transfer some 11 kV load to the 33 kV bus and Owhata.

2013/14-2014/15

ROT-POW_TFR-EHMT-01 NA Customer-specific

Rotorua transmission security


Issue can be managed operationally in the short-term. In the longer term, thermally upgrade the Rotorua–Tarukenga circuits.

NA 2014/15

NA ROT_TRK-TRAN-EHMT-01

NA NA


Tarukenga supply security



Tauranga 11 kV supply transformer capacity



Tauranga 33 kV supply The transformer capacity issue will be NA NA NA NA





Investment purpose



resolved when the limiting component on the supply transformer is removed on completion of the 33 kV indoor switchboard project.

Te Matai supply transformer capacity

(Issue arises in 2014, the from 2019)


Waiotahi supply transformer capacity


Replace the existing transformers with two higher-rated units.

2019/20 WAI-POW_TFR-REPL-01 NA Replacement

Waiotahi and Te Kaha supply security



Central North Island

Bunnythorpe interconnecting transformer capacity

(Issue aready exists)

Issue can be managed operationally in the short-term. In the longer term, replace the existing transformers with higher-rated units.

2014/15-2016/17

BPE-POW_TFR-EHMT-01 To be advised To meet GRS

Bunnythorpe–Mataroa 110 kV transmission capacity


Short-term, the issue can be resolved by managing HVDC north power flow or increasing Arapuni generation, or opening the Arapuni–Ongarue circuit. Longer term, to install either series reactors or phase shifting transformers.

NA To be advised

NA BPE_MTR-TRAN-EHMT-01

NA 2013/14

NA To meet GRS

Bunnythorpe–Woodville 110 kV transmission capacity


Short-term, the issue can be managed operationally. Longer-term, install an SPS to automatically open the Mangamaire–Woodville circuit, reconductor the Bunnythorpe–Woodville circuits with higher-rated conductors, or convert the Bunnythorpe–Woodville circuits to 220 kV operation.

NA 2013/14 2015/16-2020/21

NA BPE_WDV-TRAN-EHMT-01

NA 2013/14

NA To meet GRS

Bunnythorpe supply transformer capacity







Investment purpose

Linton supply transformer capacity



Mangahao supply transformer capacity



Marton supply transformer capacity


Resolve metering limits.

2023/24 MTN-POW_TFR-EHMT-01 NA Minor enhancement

Mataroa supply security



National Park transmission and supply transformer security



Ohakune supply transformer security and capacity


A new feeder from Tangiwai. 2012/2013 TNG-SUBEST-DEV-01 NA Customer-specific

Ongarue supply transformer security



Tokaanu supply transformer security



Waipawa supply capacity and security

(Security issue already exists, and capacity issue arises from 2015)

Resolve the metering and protection limits on the 110/33 kV transformers.

Issue can be managed operationally for lack of n-1 security for 11 kV load.

2015/16

NA

WPW-POW_TFR_PTN-EHMT-01

NA

NA

NA

Minor enhancement

NA

Taranaki North Taranaki transmission capacity and low voltage

Possible options are: 2015/16- TRNK-TRAN-EHMT-01 To be advised To meet GRS





Investment purpose

issues


A second transformer at New Plymouth.

Convert 220 kV New Plymouth–Stratford circuits to 110 kV operation.

Constraining on generation.

Upgrade terminating spans capacity on the Carrington Street–Stratford circuits

Replace Huirangi supply transformers with transformers with on load tap changers.

2020/21

Brunswick supply security


Add a second transformer.

2017/18 BRK-POW_TFR-DEV-01 NA Customer-specific

Carrington Street supply transformer capacity


Upgrade protection equipment, and upgrade the LV bus section, disconnectors and current transformers.

2012/13 CST-POW_TFR_PTN-EHMT-01 CST-POW_TFR-EHMT-01

NA NA


Hawera voltage quality


Install reactive support at Hawera, or contract for aditional reactive support, or install under-voltage load shedding capability.

2015/16-2020/21

HWA-C_BANKS-DEV-01 To be advised To meet GRS

Hawera (Kupe) supply security



Hawera supply transformer capacity


Issue can be managed operationally in the short-term. Longer term option is to replace the existing transformers with two 50 MVA units.

NA NA NA NA

Huirangi supply transformer capacity


Issue can be managed operationally in the short-term. Longer term option is to replace existing supply transformers with two 50 MVA units.

NA 2018/2019

NA HUI-POW_TFR-REPL-01

NA NA

NA Replacement

Opunake supply transformer capacity


Resolve the metering and protection limits. 2019/20 OPK_POW-TFR-EHMT-01 NA Minor enhancement

Stratford supply transformer capacity

Replace the supply transformers with two 40 MVA units.

2012/13-2014/15

SFD-POW_TFR-REPL-01 NA Replacement





Investment purpose


Wanganui supply transformer capacity


Possible options are:

Replace existing transformers with two 80 MVA units.

New 110 kV feeders from Wanganui.

Install new supply transformer at Brunswick.

2013/14-2015/16

WGN-POW_TFR-REPL-01 NA Replacement

Waverly supply security



Hawkes Bay Hawke’s Bay voltage quality



Fernhill–Redclyffe 110 kV transmission capacity



Redclyffe–Tuai 110 kV transmission capacity



Redclyffe interconnecting transformer capacity


Issue can be managed operationally by transfer load from the 110 kV network to the 220 kV network and constraining-on generation at Waikaremoana.

NA NA NA NA

Fernhill supply transformer capacity


Replace the 30 MVA with an 80 MVA unit. 2018/19 FHL-POW_TFR-REPL-01 NA Replacement

Gisborne 110 kV voltage quality

Issue can be managed operationally. Longer term option is to install new capacitors at Gisborne.

To be advised To be advised To be advised To meet GRS

Gisborne supply capacity


Thermally upgrade, or reconductor part or all of both Gisborne–Tuai circuits, and recalibrate Gisborne supply transformers’

2015/16 2023/24

GIS_TUI-TRAN-EHMT-01 GIS-POW_TFR-EHMT-01

NA NA

Customer-specific Minor enhancement





Investment purpose

metering parameters.

Redclyffe supply transformer capacity


Replace supply transformers with two 120 MVA units.

Q1 2013/14 RDF-POW_TFR-EHMT-01 NA Customer-specific

Tuai supply security



Wairoa supply transformer capacity



Whakatu supply transformer capacity



Wellington Wellington regional transmission security


Install a second 250 MVA interconnecting transformer.

2015/16-2020/21

WIL-POW_TFR-DEV-03 To be advised To meet GRS

Central Park supply transformer capacity

(110/33 kV transformer capacity issue arises from 2015)

(33/11 kV transformer capcity issue arises from 2013)

Replace 110/33 kV transformers with 120 MVA units or to extend the transformers’ lives.

33/11 kV transformer overload issue can be managed operationally.

2012/13-2013/14

CPK-POW_TFR-DEV-01 NA Replacement

Greytown supply transformer capacity


Resolve metering and protection limits.

2016/17 GYT-POW_TFR-EHMT-01 NA Minor enhancement

Haywards supply transformer capacity and security


Replace with two 110/33/11 kV 60 MVA supply transformers.

2013/2014 HAY-POW_TFR-DEV-01 NA Replacement

Kaiwharawhara transmission Issue can be managed operationally. NA NA NA NA





Investment purpose

and supply security, and supply transformer capacity


Masterton supply transformer capacity


Replace existing transformers with two 60 MVA units.

2012/13 MST-POW_TFR-DEV-01 NA Customer-specific

Melling supply capacity

(Hayward–Melling circuit capacity issue arises from 2023)

(110/33 kV and 110/11 kV transformer capacity issues arise from 2012)

Hayward–Melling: use the short term rating for the circuit, thermally upgrade the circuits, or reconductor the line.

110/33 kV: recalibrate the metering will defer the issue until 2022.

110/11 kV: resolve HV protection limit will defer the issue until 2014. Transpower will discuss future supply options with Wellington Electricity.

2023/24

2011/12

HAY_MLG-TRAN-EHMT-01

MLG-POW_TFR-EHMT-01

NA

NA

Customer-specific

Minor enhancement

Paraparaumu transmission security and supply transformer capacity


Interim, post-contingency load reduction, use supply transformer’s short-term thermal ratings, or install capacitors on the Paraparaumu 33 kV bus. Long term, additional supply transformer or a new grid exit point.

2012/13 2014/15

PRM-C_BANKS-DEV-01 PRM-POW_TFR-DEV-01

To be advised NA

To meet GRS Customer-specific

Pauatahanui supply transformer capacity


Options will be discussed with Wellington Electricity.

To be advised To be advised NA Customer-specific

Takapu Road supply transformer capacity


Resolve protection and metering limits will defer the issue until 2014. Long term option is to increase the supply transformer capacity.

Q2 2012/13 To be advised

TKR-POW_TFR-EHMT-01 TKR-POW_TFR-DEV-01

NA NA


Upper Hutt supply transformer capacity


Resolve protection and metering limits. Q2 2013/14 UHT-POW_TFR-EHMT-01 NA Minor enhancement

Wilton supply transformer capacity

Resolve protection limits. 2023/24 WIL-POW_TFR-EHMT-01 NA Minor enhancement





Investment purpose


Nelson-Marlborough

Stoke 220/10 kV interconnecting transformer capacity


Resolve the station equipment constraints, and managed operationally via generation rescheduling and load management.

2020/21 STK-POW_TFR-DEV-01 NA Minor enhancement

Stoke 110/66 kV interconnecting transformer capacity


Install a second interconnecting transformer. To be advised STK-POW_TFR-EHMT-02 NA Customer-specific

Cobb–Motueka 66 kV transmission capacity


Issue can be managed operationally using an automatic generation runback scheme.

NA NA NA NA

Motueka supply transformer capacity


Resolve the protection limits, followed by install capacitors at Motueka, and establish a new grid exit point near Riwaka.

2012/13 2013/14 2016/17

MOT-POW_TFR-EHMT-01 MOT-C_BANKS-DEV-01 MOT-SUBEST-DEV-01

NA NA NA

Minor enhancement Customer-specific Customer-specific

Motupipi single supply security



Kikiwa–Stoke 110 kV transmission capacity


Issue can be managed operationally. Longer term option is to thermally upgrade the Kikiwa–Stoke 110 kV circuit.

Beyond 2020/21

KIK_STK-TRAN-EHMT-01 To be advised To meet GRS

Stoke supply transformer capacity


Replace existing supply transformers with two 120 MVA units, followed by establish a new grid exit point at Brightwater.

2012/13-2013/14 2015/16

STK-POW_TFR-EHMT-01 STK-SUBEST-DEV-01

NA NA


West Coast Inangahua–Murchison–Kikiwa transmission capacity


Thermal upgrade the Inangahua–Murchison –Kikiwa circuit, or a special protection scheme to trip load post contingency.

2017/18 IGH_KIK-TRAN-EHMT-01 To be advised To meet GRS

Kikiwa interconnecting transformer capacity


West Coast low voltage Install additional capacitors, or a special protection scheme to trip load post

2020/21 WCST-REA_SUP-DEV-01 To be advised To meet GRS





Investment purpose

(Issue arises from 2021) contingency, or replace Kikiwa T1 with a higher-rated unit.

Arthur’s Pass transmission and supply security



Castle Hill transmission and supply security



Dobson supply transformer capacity

Upgrade protection will defer the issue until 2015. Longer term options are operational measures or replace the existing transformers with higher-rated units.

Q4 2013/14 2015/16-2017/18

DOB-POW_TFR_PTN-EHMT-01 DOB-POW_TFR-EHMT-01

NA NA


Hokitika transmission capacity

Issue can be managed operationally. Longer term option is to implement the Kawaka bonding project.

NA NA NA NA

Murchison transmission and supply security



Otira supply security



Canterbury Islington 220/66 kV transformer capacity

(Issue arises in 2019)

Options include:

establish a new 220/66 kV grid exit point south of Christchurch, and

install a fourth 220/66 kV interconnecting transformer at Islington.

2020/21

To be advised

ISL-POW_TFR-DEV-01 To be advised To be advised

Ashburton supply transformer capacity


Install a third 220/66 kV transformer. 2014/15 ASB-POW_TFR-DEV-02 NA Customer-specific

Ashley supply transformer capacity

Replace the existing 66/11 kV transformers with two 40 MVA units.

2015/16 ASY-POW_TFR-REPL-01 NA Replacement





Investment purpose

Bromley 220/66 kV transformer capacity and voltage quality


Install one 220/66 kV transformer, then a second and third transformer at later date.

2012/13-2013/14

BRY-POW_TFR-DEV-01 NA Customer-specific

Coleridge supply transformer security



Culverden supply transformer capacity


Issue can be managed operationally in the short term. Longer term options include increasing the existing supply transformers capacity and changing the operating voltage to 220/66 kV transformers,

To be advised CUL-POW_TFR-DEV-01 NA Customer-specific

Hororata supply transformer capacity and voltage quality



Southbrook supply transformer capacity


Transfer load from 33 kV to 66 kV bus by establishing two new 66 kV feeders from Southbrook.

To be advised SBK-TRAN-DEV-01 NA Customer-specific

Springston transmission security


Short-term: transfer load to Hororata. Long-term: shift load via distribution network or establish a new 220/66 kV grid exit point south of Christchurch.

NA To be advised

NA To be advised

NA NA


Waipara single supply security



South Canterbury

Oamaru–Waitaki voltage quality and transmission security

(Issue arises from summer 2012)

Upgrade transmission capacity (several options are being investigated). Install reactive support at Oamaru.

Post 2012/13 2012/13-2017/18

LWTK-TRAN-DEV-01 OAM-C_BANKS-DEV-01

To be advised NA

To meet GRS Customer-specific

Timaru interconnecting Increase interconnecting transformer To be advised TIM-POW_TFR-EHMT-02 Q1 2012/13 To meet GRS





Investment purpose


(Issue alreadt exists)

capacity.

Timaru 110 kV transmission security


Install a 110 kV bus coupler. 2013/14 TIM-BUSC-DEV-01 To be advised To meet GRS

Waitaki 220/110 kV interconnecting transformer capacity


The need to increase the interconnection capacity will depend on the preferred option form the Lower Waitaki Valley Reliability investigation.

2014/15-2018/19

WTK-POW_TFR-REPL-01 NA Replacement

Albury single supply security and supply transformer capacity



Albury and Tekapo A transmission security



Bells Pond single supply security


Possible options include building a 110 kV bus at Bells Pond, connection to the other 110 kV circuit, and a new grid exit point.

To be advised BPD-BUSC-DEV-01 NA Customer-specific

Black Point single supply security



Oamaru supply transformer capacity


Resolve protection limits. 2013/14 OAM-POW_TFR-EHMT-01 NA Minor enhancement

Studholme single supply security


The long term solution will be part of the Lower Waitaki reliability project.

see above see above see above see above

Studholme supply Replace with higher-rated units, and 2014/15 STU-POW_TFR-EHMT-01 NA Customer-specific





Investment purpose



transfer load to a new grid exit point. To be advised To be advised NA Customer-specific

Tekapo A supply security and supply transformer capacity


Resolve protection and metering limits. 2019/20 NA NA Minor enhancement

Temuka transmission security and supply transformer capacity


Install a new 120 MVA transformer, upgrade the 110 kV Timaru–Temuka circuits, or a new connection to the 220 kV Islington–Waitaki circuits, west of Temuka.

To be advised TMK-POW_TFR-DEV-02 TIM_TMK-TRAN-EHMT-01


Timaru supply transformer capacity


Replace the existing transformers with three 40 MVA units, or install two 220/33 kV transformers, new 33 kV switchboard and transfer some loads from 11 kV to 33 kV.

2014/15 TIM-POW_TFR-EHMT-01 NA Customer-specific

Waitaki single supply security and supply transformer capacity


Install a second supply transformer to resolve supply security issue. Transfer load within lines company’s network, or increase supply transformer’s capacity by adding fans and pumps to solve supply capacity issue.

To be advised 2013/14

WTK-POW_TFR-EHMT-01 NA Customer-specific

Otago-Southland

Southland transmission capacity and low voltage

Projects include:

An SPS to delay large investment and to allow sufficient build time.

Replace Roxburgh and Invercargill interconnecting transformers with higher- capacity units.

Install shunt capacitors at Balclutha.

Install a new 220/110 kV interconnection at Gore.

Install a series capacitor on one of the North Makarewa–Three Mill Hill circuit.

2011/12-2014/15

STLD-TRAN-EHMT-01 Approved To meet GRS

Roxburgh interconnecting Part of Lower South Island Reliability project. See above See above See above See above





Investment purpose


Balclutha supply transformer capacity


Resolve protection limits will defer the issue until 2014. New capacitors (part of the Lower South Island Reliability project) will relief some additional capacity.

2012/13-2013/14

BAL-POW_TFR_EHMT-01 NA Minor enhancement

Cromwell supply transformer capacity


Resolve protection limits will defer the issue until 2020.

2019/20 CML-POW_TFR-EHMT-01 NA Minor enhancement

Edendale supply transformer capacity


Limit the load within the capability of the supply transformer, or resolve the cable and protection limits will defer the issue until 2017 and replace the supply transformers with two higher-rated units.

NA 2012/13

NA EDN-POW_TFR-EHMT-01

NA NA


Frankton transmission and supply security


Thermally upgrade the Cromwell–Frankton circuits, and increase the protection and metering limits on Frankton T4 transformer, and increase Frankton T2A & T2B supply transformers’ capacities by adding pumps.

2019/20 2022/23 2022/23

CML_FKN-TRAN-EHMT-01 FKN-POW_TFR-EHMT-01 FKN-POW_TFR-EHMT-02

NA NA NA

Customer-specific Minor enhancement Customer-specific

Gore supply transformer capacity


Replace with two higher-rated units. 2014/15 GOR-POW_TFR-REPL-01 NA Replacement

Halfway Bush supply transformer capacity


Replace two 110/33 kV transformer with one 220/33 kV 120 MVA unit, and replace 220/33 kV transformer with one 120 MVA unit.

2017/18 2025/26

HWB-POW_TFR-REPL-01 NA Replacement

Invercargill supply transformer capacity


Recalibrate metering parameters. 2012/13 INV-POW_TFR-EHMT-01 NA Minor enhancement

Naseby supply transformer capacity


Issue can be managed operationally, or replace the existing transformers with two higher-rated units.

2014/15-2019/20

NSY-POW_TFR_EHMT-01 NA Customer-specific





Investment purpose

North Makarewa supply transformer capacity


Replace 220/33 kV transformers with two 220/66 kV units.

2018/19 NMA-POW_TFR-EHMT-01 NA Customer-specific

Palmerston single supply security



Palmerston transmission security



South Dunedin supply transformer capacity


Recalibrate metering parameters 2014/15 SDN-POW_TFR-EHMT-01 NA Minor enhancement

Waipori transmission security



Appendix B: Grid Economic Investment Report


Appendix B Grid Economic Investment Report

12.115(1) Transpower must publish a grid economic investment report on whether there are investments that it considers, other than the investments identified under clause 12.114 (Investmens to meet the grid reliability standards), could be made in respect of the interconnection 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 investments

Issue Projects Indicative timing (June year)

Project references Forecast submission date (June years)

Wairakei Ring circuit transmission capacity

A new 220 kV double circuit transmission line between Wairakei and Whakamaru. 2013/14 WKM_WRK-TRAN-DEV-01 Approved

Central North Island transmission capacity

Tranche 1, range of options includes:

limit power flow on the 110 kV regional network reconductor Tokaanu–Whakamaru circuits, and thermal upgrade or reconductor Bunnythorpe–Tangiwai–Rangipo circuits.

Tranche 2, range of options includes:

reconductor Bunnythorpe–Tokaanu circuits provide new transmission capacity between Bunnythorpe and Whakamaru a new line in the Taranaki area, from Taumarunui to Whakamaru, and Lower North Island wide System Protection Scheme.

Install reactive support.

To be advised

CNI-TRAN-EHMT-01 2013/14

Kawerau 110 kV generation constraint

Replace Kawerau T12 with a 250 MVA 10% impedance transformer. Interim solution is 110 kV grid reconfigurations.

2013/14 2012/13-2013/14

KAW-POW_TFR-DEV-01 EDG_MAT-TRAN-DEV-01

Submitted

Taranaki transmission capacity

Range of options includes:

thermal upgrade and/or reconductor the Brunswick–Stratford circuits

To be advised

TRNK-TRAN-EHMT-01

To be advised

Appendix B: Grid Economic Investment Report


Issue Projects Indicative timing (June year)

Project references Forecast submission date (June years)

reconductor the Huntly–Stratford circuits, and a new line between Taumarunui and Whakamaru.

Transmission capacity between Bunnythorpe and Haywards

Replace the conductor on the 220 kV Bunnythorpe–Haywards 1 and 2 circuits. 2012/13-2018/19 BPE_HAY-TRAN-EHMT-01 Submitted

Insufficient transmission capacity through the Waitaki Valley, and between Roxburgh and the Waitaki Valley

The project includes:

thermally upgrading the 220 kV Cromwell–Twizel 1 & 2 circuits reconductoring the following 220 kV circuits with duplex conductor:

Aviemore–Waitaki–Livingstone circuits.

Aviemore–Benmore 1 and 2 circuits.

Clyde–Roxburgh 1 and 2 circuits, and

Livingstone–Naseby and Naseby–Roxburgh circuits

Upgrade the capacity of the 220 kV Benmore–Twizel 1 circuit.

To be advised

2014/15 To be advised 2013/14 To be advised

To be advised

LWSI-TRAN-DEV-01

BEN_TWZ-TRAN-EHMT-01

Approved

To be advised

Transmission capacity between North and South Islands

HVDC projects includes:

Pole 3 - Stage 1 and Stage 2 Increase the HVDC line rating HVDC link expansion Stage 3

2012/13-2013/14 To be advised 2017/18

HVDC-TRAN-DEV-01 HVDC-TRAN-DEV-02 HVDC-TRAN-DEV-03

Approved To be advised 2014/15

Table B.2: Regional economic investments

Region Issue Project Indicative Timing (June years)

Project Reference Forecast Submission date (June years)

Taranaki Stratford–Hawera–Waverly–Wanganui 110 kV transmission capacity

Replace conductor on the 110 kV circuits between Stratford and Wanganui

Q2 2012/13 SFD_WGN-TRAN-EHMT-01 Approved

Appendix C: Fault Levels

2012 Annual Planning Report © Transpower New Zealand Limited 2012.All rights reserved. 348

Appendix C Fault Levels

The Connection Code contained in Schedule 8 to the Benchmark Agreement requires Transpower:

4.2(g) to publish annually a 10 year forecast of the expected minimum and maximum fault level at each customer point of service.

Calculated fault levels are very dependent on the assumptions used in the calculation and the method of calculation. The calculation of minimum fault levels depends on what 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 the calculation of the minimum fault level are understood. Minimum fault levels can be used for ensuring the coordination of protection relays between asset owners.

Protection coordination has very important consequences for power system security and safety of people and assets. Accordingly, we are not going to publish minimum fault levels which may be misunderstood and used in a way that threatens security and safety. We encourage connected parties to talk with us in matters concerning protection coordination.

Table C.2 lists the maximum three-phase fault current for all points of service. Table C.3 lists the maximum single-phase to ground fault current for the 220 kV and 110 kV points of service. In both tables, the listed value is the initial RMS symmetrical short circuit current ( ) as defined by IEC 60909 2001.

The 10 year forecast of maximum fault levels is based on information currently known by Transpower. The values in the tables should be regarded as being indicative only. We have modelled committed future transmission upgrades and generation projects using the best information we have at this time. We know that towards the end of the 10 year period, there may be additional transmission upgrades and additional generation required to meet the power and energy requirements of New Zealand. We do not know exactly the nature or location of these future transmission upgrades and new generation. The maximum fault level at a point of service may also change where the number of supply transformers are increased or replaced as part of a Service Change to meet load growth or provide supply security.

Therefore, the maximum short-circuit currents listed should not be relied upon for specifying short-circuit requirements for new substation equipment. The forecast fault levels provide an early warning of when plant capability may be exceeded. Accordingly, while Transpower endeavours to forecast fault levels accurately, the levels may change for a number of reasons and Transpower does not accept liability for other parties reliance on the fault values contained in the forecast. Transpower encourages asset owners to consult with us for detailed information on maximum fault levels at specific sites relating to new equipment connection.

The Connection Code (5.1(h)) puts an obligation on Transpower and the customer to ensure its equipment does not cause the maximum short circuit power and current limits in Appendix B Table B2 of the Connection Code to be exceeded on or nearby to the grid. Table C.1 shows the short circuit power and limits in Table B2 of Appendix B of the Connection Code. Note that the fault levels at some buses are already near or exceed these values.



Table C.1: Maximum short-circuit power and current limits

Nominal voltage (kV)

Maximum short-circuit power and current limits (MVA) (kA)

220 12,000 31.5

110 6,000 31.5

66 1,800 16

50 1,350 16

33 1,400 25

22 950 25

11 475 25

We calculated maximum fault levels in Tables C.2 and C.3 using the 2001 IEC 60909 method. 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 connected generation and embedded generation above 1 MW known to us. The existing wind 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 impedence is zero ohms.

Future committed changes to the power system including transmission upgrades and new generation detailed in this APR. We represented new transmission lines in the model with electrical parameters estimated from the best matches with existing lines of the same conductor type. We have represented committed generation in our power system model with their electrical parameters scaled from the latest example which their type is known to us. We based the timing of these connections on open discussion with the asset owner, and from the generator’s website. The actual commissioning date may vary.

Table C.2: Ten year forecast of three-phase maximum fault levels, (kA) of each point of service

Grid exit point Point of service

2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022

NORTHLAND

Albany ALB0331 19.2 19.2 20.6 20.7 20.8 21.2 21.2 21.2 21.6 21.6 21.6

Albany ALB1101 12.3 12.3 14.0 14.2 14.3 14.9 14.9 14.9 15.5 15.5 15.6

Albany ALB2201 9.9 9.9 13.1 13.3 13.5 14.7 14.8 14.8 16.0 16.0 16.1

Bream Bay BRB0331 10.3 10.3 10.5 10.5 10.6 11.6 11.6 11.6 11.7 11.7 11.8

Bream Bay BRB2201 5.0 5.0 5.4 5.4 5.5 7.9 8.0 8.0 8.1 8.1 8.7

Dargaville DAR0111 4.8 4.8 4.8 4.8 4.8 4.9 4.9 4.9 4.9 4.9 4.9

Henderson HEN0331 18.7 18.7 19.2 19.3 19.4 19.7 19.7 19.7 20.0 20.0 20.0

Henderson HEN1101 20.0 20.1 22.3 22.7 23.0 24.5 24.7 24.7 26.4 26.6 27.0

Henderson HEN2201 13.0 13.0 15.1 15.4 15.7 17.0 17.3 17.3 18.9 19.0 19.0

Hepburn Road HEP0331 21.1 21.2 21.8 21.9 22.0 22.3 22.4 22.4 22.8 22.9 23.0

Hepburn Road HEP1101 18.7 18.7 20.5 20.8 21.0 22.1 22.3 22.3 23.7 24.0 24.7

Huapai HPI2201 10.6 10.6 12.7 13.0 13.1 14.7 14.8 14.8 16.0 16.0 16.1

Kensington KEN0331 9.4 9.4 9.5 9.5 9.6 10.0 10.1 10.1 10.2 10.3 10.3

Marsden MDN1101 7.7 7.7 8.1 8.1 8.2 10.0 10.0 10.0 10.1 10.1 10.7




2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022

Marsden MDN2201 5.0 5.1 5.4 5.5 5.5 7.9 7.9 7.9 8.1 8.1 9.0

Maungatapere MPE0331 7.8 7.9 8.0 8.0 8.0 8.3 8.3 8.3 8.4 8.5 8.5


Maungaturoto MTO0331 4.6 4.6 4.7 4.7 4.7 4.8 4.8 4.8 4.8 4.8 4.8



Silverdale SVL0331 17.0 17.0 18.2 18.2 18.3 18.6 18.6 18.6 18.9 18.9 18.9

Wairau Road WRD0331 12.2 12.2 19.8 19.9 20.0 20.3 20.4 20.4 20.7 20.7 20.7

Wellsford WEL0331 7.6 7.6 7.7 7.7 7.7 7.9 7.9 7.9 8.2 8.2 8.2

AUCKLAND

Bombay BOB0331 9.1 9.1 9.1 9.2 9.2 9.2 9.2 9.2 9.2 9.2 9.2

Bombay BOB1102 11.1 11.0 11.2 11.3 11.4 11.4 11.5 11.5 11.7 11.7 11.7

Drury DRY2201 14.5 14.6 15.3 15.7 15.9 16.3 16.3 16.8 17.5 18.2 19.5

Glenbrook GLN0331 16.0 16.0 16.1 16.2 16.2 16.3 16.3 16.3 16.4 16.5 17.1

Glenbrook GLN0332 16.6 16.6 16.7 16.7 16.7 16.7 16.7 16.7 16.8 16.8 17.0

Glenbrook GLN2201 11.2 11.2 11.6 11.8 11.9 12.1 12.1 12.4 12.8 13.1 16.1

Mangere MNG0331 14.8 14.8 15.1 15.1 15.2 15.4 15.4 15.4 15.6 15.6 15.7

Mangere MNG1101 17.1 17.2 18.2 18.5 18.6 19.8 19.8 20.1 21.0 21.3 21.7

Mt Roskill ROS0221 21.8 21.8 22.2 22.3 22.4 22.6 22.6 22.7 22.9 23.0 23.2

Mt Roskill ROS1101 17.9 17.9 19.4 19.7 19.9 20.7 20.9 21.1 22.3 22.6 23.5

Otahuhu OTA0221 26.8 26.8 27.2 27.3 27.4 27.5 27.6 27.6 28.0 28.0 28.0

Otahuhu OTA1101 18.2 18.2 19.3 19.6 19.8 20.9 20.9 21.3 22.3 22.6 23.0

Otahuhu OTA1102 24.6 24.2 26.2 26.7 27.1 27.7 28.0 28.2 30.2 30.2 30.3

Otahuhu OTA2201 20.1 20.2 22.6 23.4 24.0 24.9 25.4 26.0 29.8 29.8 29.8

Otahuhu B OTC2201 20.1 20.2 22.6 23.4 24.0 24.9 25.4 26.0 29.8 29.8 29.8

Pakuranga PAK0331 16.5 25.2 25.8 26.0 26.1 26.3 26.3 26.4 26.9 26.9 26.9

Penrose PEN0221 21.0 21.3 21.6 21.6 21.7 21.8 21.8 21.8 22.1 22.1 22.1

Penrose PEN0331 32.0 32.8 33.8 34.1 34.4 34.7 34.8 34.9 35.9 35.9 35.9

Penrose PEN1101 22.8 22.0 25.0 25.6 25.9 26.6 26.9 27.0 29.0 29.0 29.0

Penrose PEN2201 16.1 17.6 19.7 20.4 20.9 21.7 22.1 22.4 25.2 25.2 25.2

Southdown SWN2201 17.0 17.1 18.7 19.3 19.7 20.5 20.8 21.3 23.5 23.5 23.5

Takanini TAK0331 17.6 17.6 17.8 21.3 21.3 21.4 21.4 21.5 21.7 21.7 21.7

Wiri WIR0331 19.5 19.5 19.8 19.9 19.9 20.0 20.1 20.1 20.4 20.4 20.4

WAIKATO

Arapuni ARI1101 11.8 11.9 11.7 11.7 11.9 11.9 12.0 12.2 12.3 12.4 12.3

Atiamuri ATI2201 17.1 17.8 18.1 18.1 18.4 18.4 25.6 25.7 25.8 25.8 25.8

Cambridge CBG0111 22.4 22.4 22.4 22.4 22.4 22.4 22.4 22.4 22.5 22.5 22.4

Hamilton HAM0111 13.4 13.4 13.4 13.4 13.4 13.4 13.4 13.4 13.4 13.4 13.4

Hamilton HAM0331 21.3 21.3 21.3 21.4 21.4 21.5 21.4 21.5 21.5 21.6 21.6

Hamilton HAM1101 15.2 15.2 15.2 15.3 15.5 15.5 15.5 15.7 15.7 15.7 15.7

Hamilton HAM2201 13.4 13.4 13.5 13.7 13.9 13.9 13.9 14.1 14.2 14.3 14.2

Hangatiki HTI0331 5.0 5.0 4.9 4.9 5.1 5.1 5.1 5.1 5.1 5.1 5.1




2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022

Hangatiki HTI1101 4.1 4.1 4.1 4.1 4.4 4.4 4.4 4.4 4.4 4.6 4.6

Hinuera HIN0331 6.9 6.9 6.9 6.9 6.9 7.0 7.0 7.0 7.0 7.0 7.0

Huntly HLY0331 15.0 15.0 15.0 15.1 15.1 15.1 15.1 15.1 15.1 15.1 15.1

Huntly HLY2201 27.3 27.4 28.1 30.0 30.4 30.8 30.5 32.2 30.4 31.9 30.5

Karapiro KPO1101 7.7 7.8 7.8 7.8 7.8 7.8 7.8 7.8 7.8 7.8 7.8

Kopu KPU0661 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7

Maraetai MTI2201 20.4 20.9 22.0 23.5 23.8 23.8 25.8 25.9 26.1 26.2 26.1

Ohakuri OHK2201 16.6 17.3 17.6 17.7 17.9 18.0 23.2 23.2 23.3 23.3 23.3

Te Awamutu TMU0111 17.4 17.4 17.4 17.4 17.4 17.4 17.4 17.4 17.4 17.4 17.4

Te Awamutu TMU1101 3.7 3.7 3.7 3.7 3.7 3.7 3.7 3.7 3.7 3.7 3.7

Te Kowhai TWH0331 21.2 21.2 21.3 21.4 21.4 21.4 21.4 21.5 21.4 21.5 21.4

Te Kowhai TWH2201 9.5 9.5 9.5 9.7 9.7 9.8 9.8 9.9 9.8 9.9 9.8

Waihou WHU0331 7.0 7.0 7.0 7.0 7.0 7.0 7.0 7.0 7.0 7.0 7.0

Waikino WKO0331 6.2 6.2 6.2 6.2 6.2 6.2 6.3 6.3 6.3 6.3 6.3

Waipapa WPA2201 12.9 13.1 13.5 14.1 14.2 14.2 14.8 14.9 14.9 14.9 14.9

Whakamaru WKM2201 24.9 25.8 27.7 30.5 31.0 31.1 34.9 35.3 35.7 35.8 35.5

BAY OF PLENTY

Edgecumbe EDG0331 14.5 14.6 14.6 14.6 14.7 14.7 15.8 15.8 15.9 15.9 15.9

Edgecumbe EDG1101 7.8 8.0 8.0 8.1 9.0 9.0 9.6 9.6 9.8 9.8 9.8

Edgecumbe EDG2201 7.4 7.6 7.6 7.6 7.8 7.8 11.0 11.0 11.0 11.0 11.0

Kaitimako KMO0331 7.6 7.6 7.6 7.6 7.7 7.7 8.8 8.8 8.8 8.8 8.8

Kaitimako KMO1101 9.3 9.3 9.4 9.4 9.6 9.6 20.6 20.6 20.6 20.6 20.6

Kawerau KAW0111 19.2 19.4 19.4 19.4 20.0 20.0 20.2 20.2 20.4 20.4 20.4

Kawerau KAW0114 16.7 16.9 16.9 16.9 17.3 17.3 17.5 17.5 17.6 17.6 17.6

Kawerau KAW0115 16.7 16.9 16.9 16.9 17.3 17.3 17.5 17.5 17.6 17.6 17.6

Kawerau KAW0116 17.4 17.5 17.5 17.5 18.0 18.0 18.2 18.2 18.3 18.3 18.3

Kawerau KAW0117 17.1 17.2 17.3 17.3 17.7 17.7 17.9 17.9 18.0 18.0 18.0

Kawerau KAW0118 34.5 34.7 34.7 34.7 35.1 35.1 36.8 36.8 36.8 36.8 36.8

Kawerau KAW1101 10.3 10.9 10.9 10.9 13.0 13.0 14.0 14.0 14.7 14.7 14.7

Kawerau KAW2201 7.3 7.4 7.5 7.5 7.8 7.8 9.8 9.8 9.9 9.9 9.9

Kawerau KIN0111 14.4 14.4 14.2 14.2 14.3 14.3 14.4 14.4 14.4 14.4 14.4

Kawerau KIN0112 14.1 14.2 14.0 14.0 14.1 14.1 14.2 14.2 14.2 14.2 14.2

Kawerau KIN0113 14.9 14.9 14.7 14.7 14.8 14.8 14.9 14.9 14.9 14.9 14.9

Kinleith KIN0331 5.0 5.0 5.0 5.0 5.0 5.0 5.0 5.0 5.0 5.0 5.0

Kinleith KIN1101 9.1 9.2 8.6 8.6 8.8 8.8 9.2 9.3 9.3 9.3 9.3

Lichfield Tee LFD1101 6.9 6.9 6.4 6.4 6.6 6.6 6.9 7.0 7.0 7.0 7.0

Matahina MAT1101 9.0 9.3 9.3 9.3 10.6 10.6 11.2 11.2 11.6 11.6 11.6

Mt Maunganui MTM0331 11.1 11.1 11.1 11.1 11.2 11.2 13.8 13.8 13.8 13.8 13.8

Mt Maunganui MTM1101 7.3 7.3 7.4 7.4 7.5 7.5 12.9 12.9 12.9 12.9 12.9

Owhata OWH0111 10.0 10.0 9.9 9.9 10.0 10.0 10.2 10.2 10.2 10.2 10.2

Owhata OWH1101 5.9 6.0 5.8 5.8 5.9 5.9 6.8 6.8 6.8 6.8 6.8

Rotorua ROT0111 18.4 18.4 17.5 17.5 17.9 17.9 18.4 18.4 18.4 18.4 18.4




2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022

Rotorua ROT0331 9.6 9.6 8.9 8.9 9.4 9.4 9.8 9.9 9.9 9.9 9.9

Rotorua ROT1101 8.3 8.4 6.9 6.9 8.9 8.9 10.0 10.1 10.1 10.1 10.1

Rotorua ROT1102 7.9 8.0 6.5 6.5 7.1 7.1 8.0 8.1 8.1 8.1 8.1

Tarukenga TRK0111 10.9 10.9 10.6 10.6 10.7 10.7 10.9 10.9 10.9 10.9 10.9

Tarukenga TRK1101 17.3 17.6 11.8 11.8 13.4 13.4 17.3 17.6 17.6 17.6 17.6

Tarukenga TRK2201 10.8 11.1 11.0 11.0 11.3 11.3 29.1 29.2 29.3 29.3 29.3

Tauranga TGA0111 14.4 14.4 14.4 14.4 14.4 14.4 15.7 15.7 15.7 15.7 15.7

Tauranga TGA0331 13.3 13.3 13.3 13.3 13.4 13.4 16.3 16.3 16.3 16.4 16.4

Te Kaha TKH0111 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8 0.8

Te Kaha TKH0501 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3

Te Matai TMI0331 7.5 7.5 7.5 7.5 7.6 7.6 8.3 8.4 8.4 8.4 8.4

Te Matai TMI1101 6.5 6.6 6.5 6.5 6.7 6.7 9.2 9.2 9.2 9.2 9.2

Waiotahi WAI0111 8.5 8.5 8.5 8.5 8.6 8.6 8.6 8.6 8.7 8.7 8.7


Aratiatia ARA2201 16.2 17.9 18.5 20.7 21.3 21.3 22.6 22.7 22.8 22.8 22.8

Bunnythorpe BPE0331 15.8 15.9 15.9 16.0 16.0 16.0 16.1 16.3 16.3 16.3 16.4

Bunnythorpe BPE1101 12.6 12.8 12.9 13.1 13.1 13.1 13.3 13.7 13.7 13.7 13.8

Bunnythorpe BPE2201 12.2 12.6 12.6 13.1 13.1 13.2 13.8 14.8 14.8 14.8 15.2

Dannevirke DVK0111 16.2 16.3 16.3 16.3 16.3 16.3 16.4 16.4 16.4 16.4 16.4

Linton LTN0331 8.8 8.8 8.9 8.9 8.9 8.9 8.9 9.0 9.0 9.0 9.0

Linton LTN0332 8.7 8.8 8.8 8.8 8.8 8.8 8.9 9.0 9.0 9.0 9.1

Linton LTN2201 8.7 8.9 8.9 9.2 9.2 9.2 9.5 9.9 9.9 9.9 10.1

Linton LTN2202 8.9 9.1 9.2 9.7 9.7 9.7 10.3 11.4 11.5 11.5 12.0

Mangahao MHO0331 9.0 9.0 9.0 9.0 9.0 9.0 9.0 9.0 9.1 9.1 9.1

Mangamaire MGM0331 4.6 4.6 4.6 4.6 4.6 4.6 4.6 4.6 4.6 4.6 4.6

Mangamaire MGM1101 4.8 4.8 4.8 4.9 4.9 4.9 4.9 4.9 4.9 4.9 5.0

Marton MTN0331 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.7 6.7 6.7 6.7

Marton MTN1101 5.2 5.3 5.3 5.3 5.3 5.3 5.3 5.4 5.4 5.4 5.5

Marton MTN1102 5.2 5.3 5.3 5.3 5.3 5.3 5.3 5.4 5.4 5.4 5.4

Mataroa MTR0331 3.6 3.6 3.6 3.6 3.6 3.6 3.6 3.6 3.6 3.6 3.6

National Park NPK0331 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6

Nga Awa Purua NAP2201 15.7 17.1 18.0 19.9 20.4 20.4 21.8 22.0 22.0 22.0 22.0

Ohaaki OKI0331 2.3 2.3 2.3 2.3 2.3 2.3 2.3 2.3 2.3 2.3 2.3

Ohaaki OKI2201 13.3 14.2 14.7 16.0 16.3 16.7 17.8 17.8 17.9 17.9 17.9

Ohakune OKN0111 4.7 4.7 4.7 4.7 4.7 4.7 4.7 4.7 4.7 4.7 4.7

Ongarue ONG0331 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6 2.6

Poihipi PPI2201 14.2 16.5 17.0 22.9 23.6 23.6 25.2 25.4 25.5 25.5 25.4

Rangipo RPO2201 6.7 6.8 7.1 7.2 7.2 7.3 7.4 7.4 7.4 7.4 7.4

Tangiwai TNG0111 19.7 19.7 19.8 19.8 19.8 19.8 19.9 19.9 19.9 19.9 19.9

Tangiwai TNG2201 5.0 5.0 5.1 5.1 5.1 5.2 5.2 5.2 5.2 5.2 5.2

Tararua Wind Central TWC2201 8.5 8.6 8.6 8.9 9.0 9.0 9.4 10.1 10.1 10.1 10.4

Tokaanu TKU0331 3.8 3.8 3.8 3.8 3.8 3.8 3.8 3.8 3.8 3.8 3.8




2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022

Tokaanu TKU2201 11.6 11.7 11.9 12.1 12.2 12.2 12.4 12.5 12.5 12.5 12.5

Tokaanu TKU2202 11.6 11.7 11.9 12.1 12.2 12.2 12.4 12.5 12.5 12.5 12.5

Waipawa WPW0111 4.2 4.2 4.2 4.2 4.2 4.2 4.2 4.2 4.2 4.2 4.2

Waipawa WPW0331 4.8 4.8 4.8 4.8 4.8 4.8 4.8 4.8 4.8 4.8 4.8

Wairakei WRK0331 21.3 21.6 21.7 22.0 22.1 22.1 22.2 22.2 22.2 22.2 22.2

Wairakei WRK2201 19.8 22.4 23.4 27.2 28.2 28.3 30.7 31.0 31.1 31.1 31.1

Woodville WDV0111 10.1 10.1 10.1 10.1 10.1 10.1 10.1 10.1 10.1 10.1 10.2

Woodville WDV1101 7.5 7.6 7.6 7.7 7.7 7.7 7.8 7.9 7.9 7.9 8.0

TARANAKI

Brunswick BRK0331 8.9 9.0 9.0 9.0 9.0 9.0 9.1 9.1 9.1 9.1 9.1

Brunswick BRK2201 10.1 10.4 10.4 10.9 11.0 11.0 11.4 11.4 11.4 11.4 11.5

Carrington Street CST0331 12.7 13.4 13.4 13.6 13.6 13.6 13.7 13.7 14.2 14.0 14.0

Hawera HWA0331 8.0 8.1 8.1 8.1 8.2 8.2 8.2 8.2 8.2 8.2 8.2

Hawera HWA0332 4.7 4.7 4.7 4.7 4.7 4.7 4.7 4.7 4.8 4.8 4.8

Hawera HWA1101 7.4 7.6 7.6 7.6 7.7 7.7 7.7 7.7 7.9 7.9 7.9

Hawera HWA1102 7.4 7.6 7.6 7.6 7.7 7.7 7.7 7.7 7.9 7.9 7.9

Huirangi HUI0331 6.0 6.2 6.2 6.2 6.2 6.2 6.3 6.3 6.4 6.3 6.3

Huirangi HUI1101 7.8 9.3 9.3 9.6 9.7 9.7 9.9 9.9 10.6 10.2 10.2

Kapuni KPA1101 5.4 5.5 5.5 5.6 5.6 5.6 5.7 5.7 5.7 5.7 5.7

Motunui MNI1101 7.2 9.3 9.3 9.5 9.6 9.6 9.7 9.7 10.2 9.9 9.9

New Plymouth NPL0331 10.1 10.4 10.4 10.6 10.6 10.6 10.7 10.7 11.0 10.9 10.9

New Plymouth NPL1101 11.2 12.7 12.7 13.3 13.5 13.5 13.9 13.9 16.2 15.2 15.2

New Plymouth NPL2201 8.5 9.2 9.2 10.0 10.2 10.2 10.9 10.9 11.0 10.9 10.9

Opunake OPK0331 4.3 4.3 4.3 4.4 4.4 4.4 4.4 4.4 4.4 4.4 4.4

Stratford SFD0331 7.4 7.4 7.4 7.5 7.5 7.5 7.5 7.5 7.5 7.5 7.5

Stratford SFD1101 11.8 12.3 12.3 12.8 13.0 13.0 13.3 13.3 13.4 13.3 13.3

Stratford SFD2201 12.7 13.5 13.5 15.6 16.1 16.1 17.8 17.8 17.8 17.8 17.8

Taumarunui TMN2201 4.2 4.3 4.3 4.4 4.4 4.4 4.4 4.4 4.4 4.4 4.4

Wanganui WGN0331 6.4 6.4 6.4 6.4 6.4 6.4 6.4 6.5 6.5 6.5 6.5

Wanganui WGN1101 5.1 5.2 5.2 5.2 5.2 5.2 5.2 5.3 5.4 5.4 5.4

Waverley WVY0111 2.7 2.7 2.7 2.7 2.7 2.7 2.8 2.8 2.8 2.8 2.8

Waverley WVY1101 4.2 4.5 4.5 4.5 4.5 4.5 4.5 4.5 5.2 5.2 5.2

HAWKE’S BAY

Fernhill FHL0331 9.1 9.2 9.2 9.2 9.2 9.3 9.3 9.3 9.3 9.3 9.3

Fernhill FHL1101 6.6 6.7 6.7 6.7 6.8 6.8 6.8 6.9 6.9 6.9 6.9

Gisborne GIS0501 3.5 3.6 3.6 3.6 3.6 3.6 3.6 3.6 3.6 3.6 3.6

Gisborne GIS1101 2.2 2.2 2.2 2.2 2.2 2.2 2.2 2.2 2.2 2.2 2.2

Redclyffe RDF0331 9.5 9.5 9.5 9.6 9.6 9.6 9.6 9.6 9.6 9.7 9.7

Redclyffe RDF1101 7.4 7.5 7.6 7.6 7.7 7.7 7.7 7.8 7.8 7.9 7.9

Redclyffe RDF2201 6.0 6.2 6.2 6.4 6.5 6.6 6.6 6.7 6.7 6.8 6.8

Tuai TUI0111 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.1




2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022

Tuai TUI1101 5.8 5.8 5.8 5.8 5.9 5.9 5.9 5.9 5.9 5.9 5.9

Wairoa WRA0111 9.1 9.1 9.1 9.1 9.1 9.2 9.2 9.2 9.2 9.2 9.2

Whakatu WTU0331 12.2 12.3 12.4 12.5 12.5 12.6 12.6 12.7 12.7 12.7 12.7

Whakatu WTU2201 5.2 5.3 5.3 5.5 5.5 5.6 5.6 5.7 5.7 5.8 5.8

Whirinaki WHI0111 22.0 22.1 22.1 22.2 22.3 22.4 22.4 22.5 22.5 22.5 22.5

Whirinaki WHI0112 21.9 22.0 22.0 22.1 22.2 22.3 22.3 22.4 22.4 22.4 22.4

Whirinaki WHI0113 22.3 22.4 22.5 22.6 22.7 22.7 22.7 22.8 22.8 22.9 22.9

Whirinaki WHI2201 5.9 6.1 6.1 6.3 6.4 6.6 6.6 6.7 6.7 6.8 6.8

WELLINGTON

Central Park CPK0111 7.2 7.2 7.2 7.2 7.2 7.2 7.4 7.4 7.4 7.4 7.4

Central Park CPK0331 18.3 18.6 18.6 18.7 18.7 18.7 22.4 22.4 22.6 22.6 22.8

Gracefield GFD0331 13.2 13.3 13.3 13.4 13.4 13.4 16.3 16.3 16.4 16.4 16.4

Greytown GYT0331 3.8 3.8 3.8 3.8 3.8 3.8 3.8 3.8 3.8 3.8 3.8

Haywards HAY0111 12.6 12.6 12.6 12.6 12.6 12.6 12.7 12.7 12.7 12.7 12.7

Haywards HAY0331 3.9 4.0 4.0 4.0 4.0 4.0 4.0 4.0 4.0 4.0 4.0

Haywards HAY1101 17.3 18.4 18.4 18.8 18.8 18.8 20.2 20.4 20.5 20.5 20.5

Haywards HAY2201 10.4 10.8 10.8 11.1 11.1 11.2 11.8 12.1 12.1 12.1 12.5

Kaiwharawhara KWA0111 7.9 8.0 8.0 8.0 8.0 8.0 8.0 8.0 8.0 8.0 8.0

Masterton MST0331 7.2 7.2 7.2 7.2 7.2 7.2 7.2 7.3 7.3 7.3 7.3

Melling MLG0111 13.5 13.6 13.6 13.6 13.6 13.6 13.7 13.7 13.7 13.7 13.7

Melling MLG0331 9.3 9.4 9.4 9.4 9.4 9.4 9.5 9.5 9.5 9.5 9.5

Paraparaumu PRM0331 7.9 8.0 8.0 8.0 8.0 8.0 8.1 8.1 8.1 8.1 8.1

Pauatahanui PNI0331 6.2 6.3 6.3 6.3 6.3 6.3 6.3 6.3 6.4 6.4 6.4

Takapu Road TKR0331 14.3 14.5 14.5 14.6 14.6 14.6 14.9 14.9 15.0 15.0 15.0

Takapu Road TKR1101 14.5 15.2 15.2 15.5 15.5 15.5 16.7 16.8 16.9 16.9 16.9

Upper Hutt UHT0331 9.5 9.5 9.5 9.6 9.6 9.6 9.7 9.7 9.7 9.7 9.7

West Wind WWD1101 8.3 8.4 8.4 8.5 8.5 8.5 9.1 9.2 9.2 9.2 9.3

West Wind WWD1102 8.2 8.4 8.4 8.5 8.5 8.5 9.1 9.1 9.2 9.2 9.2

Wilton WIL0331 13.1 13.2 13.2 14.3 14.3 14.3 14.4 14.5 14.5 14.5 14.6

Wilton WIL1101 12.4 12.8 12.8 13.0 13.0 13.0 14.3 14.4 14.4 14.4 14.6

Wilton WIL2201 7.7 8.0 8.0 8.2 8.2 8.2 8.7 8.8 8.9 8.9 9.0

NELSON-MARLBOROUGH

Argyle ARG1101 2.6 2.6 2.6 2.9 2.9 3.3 3.3 3.3 3.3 3.3 3.3

Blenheim BLN0331 6.6 6.6 6.6 7.0 7.1 12.2 12.2 12.2 12.2 12.2 12.2

Blenheim BLN1101 2.6 2.6 2.6 2.8 2.8 4.1 4.1 4.1 4.1 4.1 4.1

Cobb COB0661 2.9 2.9 2.9 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0

Motueka MOT0111 7.7 7.7 7.7 7.8 7.8 7.9 7.9 7.9 7.9 7.9 7.9

Motupipi MPI0661 1.6 1.6 1.6 1.7 1.7 1.7 1.7 1.7 1.7 1.7 1.7

Stoke STK0331 11.1 11.1 11.1 11.9 12.0 12.9 12.9 12.9 12.9 12.9 12.9

Stoke STK1101 3.9 3.9 3.9 4.4 4.4 5.3 5.3 5.3 5.3 5.3 5.3

Stoke STK2201 2.6 2.6 2.6 2.9 3.0 3.4 3.4 3.4 3.4 3.4 3.4

Upper Takaka UTK0661 2.6 2.6 2.6 2.6 2.7 2.7 2.7 2.7 2.7 2.7 2.7




2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022

WEST COAST

Arthurs Pass APS0111 2.2 2.2 2.2 2.3 2.3 2.3 2.3 2.3 2.3 2.3 2.3

Atarau ATU1101 1.5 1.5 1.5 1.9 2.0 2.1 2.1 2.1 2.1 2.1 2.1

Castle Hill CLH0111 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8

Dobson DOB0331 3.0 3.0 3.0 3.7 3.7 3.9 3.9 3.9 3.9 3.9 3.9

Greymouth GYM0661 2.5 2.5 2.5 3.5 3.5 3.6 3.6 3.6 3.6 3.6 3.6

Hokitika HKK0661 1.7 1.7 1.7 1.8 1.8 1.8 1.8 1.8 1.8 3.4 3.4

Inangahua IGH1101 2.2 2.2 2.2 3.7 4.2 4.3 4.3 4.3 4.3 4.3 4.3

Kikiwa KIK0111 2.9 2.9 2.9 2.9 2.9 3.0 3.0 3.0 3.0 3.0 3.0

Kikiwa KIK2201 3.1 3.1 3.1 3.5 3.6 4.0 4.0 4.0 4.0 4.0 4.0

Kumara KUM0661 2.3 2.3 2.3 2.8 2.8 2.9 2.9 2.9 2.9 3.5 3.5

Murchison MCH0111 2.6 2.6 2.6 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7

Otira OTI0111 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.7 1.7

Reefton RFN1101 1.8 1.8 1.8 2.7 2.8 2.9 2.9 2.9 2.9 2.9 2.9

Orowaiti ORO1101 1.5 1.5 1.5 2.5 3.1 3.1 3.1 3.1 3.1 3.1 3.1

Orowaiti ORO1102 1.5 1.5 1.5 2.5 2.7 2.7 2.7 2.7 2.7 2.7 2.7

Orowaiti ROB0331 3.5 3.5 3.5 4.7 5.1 5.1 5.1 5.1 5.1 5.1 5.1

Westport WPT0111 8.6 8.6 8.6 11.1 11.9 11.9 11.9 11.9 11.9 11.9 11.9

CANTERBURY

Addington ADD0111 15.9 15.9 15.9 16.0 16.0 16.1 16.4 16.4 16.4 16.4 16.4

Addington ADD0112 15.4 15.4 15.4 15.5 15.5 15.6 15.8 15.8 15.8 15.8 15.8

Addington ADD0661 11.0 11.0 11.0 11.5 11.5 11.8 12.6 12.6 12.6 12.6 12.6

Ashburton ASB0331 9.7 9.7 9.7 9.8 9.8 9.9 9.9 9.9 9.9 9.9 9.9

Ashburton ASB0661 7.7 7.7 7.7 7.9 7.9 7.9 8.0 8.0 8.0 8.0 8.0

Ashburton ASB2201 7.1 7.1 7.1 7.5 7.6 7.8 8.0 7.9 8.0 8.0 8.0

Ashley ASY0111 8.6 8.6 8.6 8.7 8.7 8.7 8.7 8.7 8.7 8.7 8.7

Ashley ASY0661 5.0 5.0 5.0 5.2 5.2 5.2 5.3 5.3 5.3 5.3 5.3

Bromley BRY0111 14.6 15.1 15.1 15.6 15.6 15.6 15.7 15.7 15.7 15.7 15.7

Bromley BRY0661 10.5 12.2 12.2 14.1 14.2 14.5 14.8 14.6 14.7 14.7 14.7

Bromley BRY2201 5.6 5.6 5.6 6.2 6.2 6.4 6.6 6.6 6.6 6.6 6.6

Coleridge COL0111 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6

Coleridge COL0661 4.2 4.2 4.2 4.3 4.3 4.3 4.3 4.3 4.3 4.4 4.4

Culverden CUL0331 7.1 7.1 7.1 7.2 7.2 7.3 7.3 7.4 7.4 7.4 7.4

Culverden CUL0661 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6 1.6

Hororata HOR0331 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8

Hororata HOR0661 4.5 4.5 4.5 4.5 4.5 4.6 4.6 4.6 4.6 4.6 4.6

Islington ISL0331 14.5 14.5 14.5 14.9 15.0 15.2 15.4 15.4 15.4 15.4 15.4

Islington ISL0661 15.0 15.0 15.0 15.9 16.0 16.5 18.1 18.1 18.1 18.1 18.1

Islington ISL2201 6.6 6.6 6.6 7.2 7.2 7.6 8.0 7.9 8.0 8.0 8.0

Kaiapoi KAI0111 12.9 12.9 12.9 13.0 13.1 13.1 13.2 13.2 13.2 13.2 13.2

Middleton Tee MLN0661 11.3 11.3 11.3 11.8 11.9 12.2 13.0 13.0 13.0 13.0 13.0




2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022

Middleton Tee MLN0662 11.3 11.3 11.3 11.8 11.9 12.2 13.0 13.0 13.0 13.0 13.0

Southbrook SBK0331 6.0 6.0 6.0 6.1 6.1 6.1 6.2 6.2 6.2 6.2 6.2

Springston SPN0331 6.9 6.9 6.9 7.0 7.0 7.0 7.2 7.2 7.2 7.2 7.2

Springston SPN0661 7.7 7.7 7.7 7.9 7.9 8.0 8.4 8.4 8.4 8.4 8.4

Waipara WPR0331 1.8 1.8 1.8 1.8 1.8 1.8 1.8 1.8 1.8 1.8 1.8

Waipara WPR0661 8.1 8.1 8.1 8.8 8.8 9.0 9.1 9.2 9.2 9.2 9.2

SOUTH CANTERBURY

Albury ABY0111 4.4 4.4 4.4 4.4 4.4 4.4 4.4 4.4 4.4 4.4 4.4

Aviemore AVI2201 15.6 15.6 15.8 17.1 17.4 17.5 19.3 19.3 19.4 19.4 19.5

Bells Pond BPD1101 2.8 2.8 2.8 2.8 2.8 2.8 2.9 2.9 2.9 2.9 2.9

Benmore BEN0161 97.7 97.8 97.8 98.1 98.2 98.3 99.0 99.0 99.1 99.2 99.2

Benmore BEN2201 19.4 19.5 19.5 20.0 20.3 20.4 21.8 21.8 22.1 22.1 22.2

Black Point BPT1101 3.5 3.5 3.5 3.5 3.5 3.5 3.7 3.7 3.7 3.7 3.7

Livingstone LIV2201 7.9 7.9 9.0 9.4 9.8 9.9 11.8 11.9 11.9 11.9 12.0

Oamaru OAM0331 5.4 5.4 5.4 5.4 5.4 5.4 5.6 5.6 5.6 5.6 5.6

Ohau A OHA2201 17.6 17.6 17.6 18.0 18.2 18.3 18.7 18.8 19.0 19.1 19.2

Ohau B OHB2201 19.1 19.1 19.1 19.5 19.8 20.0 20.5 20.5 20.9 20.9 21.0

Ohau C OHC2201 17.1 17.1 17.1 17.4 17.6 17.7 18.2 18.2 18.5 18.5 18.6

Opihi OPI2201 7.1 7.2 7.2 7.3 7.4 7.5 7.5 7.5 7.6 7.6 7.6

Opihi OPI2202 7.1 7.2 7.2 7.3 7.4 7.5 7.5 7.5 7.6 7.6 7.6

Studholme STU0111 7.4 7.4 7.4 7.4 7.4 7.4 7.5 7.5 7.5 7.5 7.5

Tekapo A TKA0111 14.5 14.5 14.5 14.5 14.5 14.5 14.5 14.5 14.5 14.5 14.5

Tekapo A TKA0331 1.3 1.3 1.3 1.3 1.3 1.3 1.3 1.3 1.3 1.3 1.3

Tekapo B TKB2201 11.8 11.8 11.8 12.0 12.4 12.5 12.6 12.6 12.8 12.8 12.9

Temuka TMK0331 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.5 6.6 6.6 6.6

Timaru TIM0111 20.3 20.3 20.3 20.3 20.4 20.4 20.4 20.4 20.4 20.4 20.4

Twizel TWZ0331 9.0 9.0 9.0 9.0 9.0 9.0 9.0 9.0 9.1 9.1 9.1

Twizel TWZ2201 20.5 20.5 20.6 21.0 21.4 21.6 22.2 22.2 22.7 22.7 22.8

Waitaki WTK0331 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6

Waitaki WTK2201 12.4 12.5 13.3 14.2 14.5 14.6 16.7 16.7 16.8 16.8 16.9

OTAGO-SOUTHLAND

Balclutha BAL0331 3.8 3.8 3.8 3.6 3.6 3.6 3.6 3.6 3.6 3.6 3.6

Berwick BWK1101 4.9 4.8 4.8 4.8 4.8 4.9 4.9 4.9 4.9 4.9 4.9

Brydone BDE0111 12.7 12.3 12.3 13.7 13.7 13.7 13.7 13.7 13.8 13.8 13.8

Clyde CYD0331 10.4 10.4 10.4 10.4 10.5 10.5 10.5 10.5 10.6 10.6 10.6

Clyde CYD2201 14.8 14.9 14.9 15.2 16.0 16.3 16.5 16.7 17.8 17.8 17.8

Cromwell CML0331 10.4 10.4 10.4 11.6 11.7 11.7 11.7 11.7 11.8 11.8 11.8

Edendale EDN0331 6.1 5.7 5.7 6.6 6.6 6.6 6.6 6.6 6.6 6.6 6.7

Edendale EDN1101 3.8 3.3 3.3 4.4 4.4 4.5 4.5 4.5 4.5 4.5 4.6

Frankton FKN0331 7.6 7.6 7.6 7.7 7.8 7.8 7.8 7.8 7.8 7.8 7.8

Gore GOR0331 6.2 6.0 6.0 7.5 7.5 7.6 7.6 7.6 7.6 7.6 7.7

Gore GOR1101 3.8 3.6 3.6 6.2 6.3 6.3 6.3 6.3 6.4 6.4 6.6




2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022

Halfway Bush HWB0331 16.0 16.0 16.0 16.9 16.9 17.0 17.0 17.1 17.2 17.2 17.4

Halfway Bush HWB0332 13.9 13.9 13.9 14.2 14.2 14.3 14.3 14.4 14.5 14.5 14.6

Halfway Bush HWB1101 9.1 9.2 9.2 10.2 10.3 10.4 10.4 10.5 10.7 10.7 10.8

Halfway Bush HWB2201 7.8 7.8 7.8 8.6 8.7 8.9 9.0 9.2 9.5 9.5 9.9

Invercargill INV0331 17.4 17.4 17.4 17.5 17.6 17.6 17.8 17.8 17.8 17.8 17.9



Manapouri MAN2201 11.5 11.5 11.5 11.7 11.7 11.8 12.0 12.0 12.0 12.0 12.2

Naseby NSY0331 7.7 7.8 7.8 7.9 8.0 8.0 8.1 8.1 8.1 8.1 8.1

Naseby NSY2201 5.9 5.9 6.2 6.9 7.6 7.7 8.3 8.3 8.4 8.4 8.4

North Makarewa NMA0331 10.5 10.5 10.5 10.5 10.5 10.6 10.6 10.6 10.6 10.6 10.7

North Makarewa NMA2201 9.7 9.7 9.7 10.0 10.1 10.2 10.6 10.6 10.7 10.7 11.0

Palmerston PAL0331 1.7 1.7 1.7 1.7 1.7 1.7 1.7 1.7 1.7 1.7 1.7

Roxburgh ROX1101 8.9 10.4 10.4 10.2 10.3 10.3 10.4 10.4 10.5 10.5 10.5

Roxburgh ROX2201 15.0 15.2 15.2 15.6 16.5 16.9 17.2 17.5 19.6 19.6 19.7

South Dunedin SDN0331 17.2 17.2 17.2 17.7 17.8 17.9 18.0 18.1 18.3 18.3 18.5


Three Mile Hill TMH2201 8.2 8.2 8.2 9.0 9.2 9.5 9.5 9.8 10.1 10.1 10.6

Tiwai TWI2201 8.6 8.6 8.6 8.8 8.9 9.0 9.3 9.3 9.3 9.3 9.5



Table C.3: Ten year forecast of single-phase maximum fault levels, (kA) of each point of service


2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021

NORTHLAND

Albany ALB1101 13.5 13.5 15.3 15.4 15.5 15.9 16.0 16.0 16.4 16.4 16.5

Albany ALB2201 11.2 11.3 15.8 16.0 16.2 17.3 17.4 17.4 18.5 18.5 18.5

Bream Bay BRB2201 4.9 4.9 5.2 5.2 5.3 7.7 7.8 7.8 7.9 7.9 8.3

Henderson HEN1101 24.0 24.0 26.3 26.7 26.9 28.3 28.5 28.4 29.9 30.1 30.5

Henderson HEN2201 14.8 14.8 16.8 17.1 17.3 18.4 18.5 18.5 19.8 19.8 19.8

Hepburn Road HEP1101 17.9 18.0 19.0 19.4 19.5 20.2 20.2 20.1 20.8 21.1 21.6

Huapai HPI2201 11.3 11.3 13.2 13.4 13.5 14.6 14.7 14.7 15.5 15.5 15.6

Marsden MDN1101 8.7 8.7 9.1 9.1 9.1 11.2 11.3 11.3 11.4 11.4 12.1

Marsden MDN2201 5.0 5.0 5.2 5.3 5.3 7.6 7.6 7.6 7.7 7.7 8.7




AUCKLAND

Bombay BOB1102 5.8 5.8 5.8 5.9 5.9 5.9 5.9 5.9 5.9 5.9 5.9

Drury DRY2201 13.6 13.7 14.2 14.4 14.5 14.7 14.7 15.3 15.6 16.3 17.2

Glenbrook GLN2201 10.5 10.5 10.8 10.9 11.0 11.1 11.1 11.3 11.5 11.8 15.2

Mangere MNG1101 16.6 16.6 17.2 17.4 17.5 18.6 18.6 18.8 19.3 19.5 19.8

Otahuhu OTA1101 22.0 22.0 23.2 23.4 23.6 24.8 24.8 25.1 26.0 26.3 26.7

Otahuhu OTA1102 28.5 27.4 29.2 29.7 30.0 30.4 30.7 30.9 32.5 32.5 32.5

Otahuhu OTA2201 24.6 25.0 27.8 28.6 29.2 30.0 30.5 31.3 35.2 35.2 35.2

Otahuhu B OTC2201 24.6 25.0 27.8 28.6 29.2 30.0 30.5 31.3 35.2 35.2 35.2

Penrose PEN1101 25.3 25.0 28.9 29.3 29.6 30.2 30.4 30.6 32.2 32.2 32.2

Penrose PEN2201 17.6 20.8 23.7 24.3 24.9 25.6 25.9 26.3 28.9 28.9 28.9

Mt Roskill ROS1101 15.5 15.5 16.2 16.4 16.5 16.9 16.9 17.1 17.6 17.9 18.9

Southdown SWN2201 17.9 18.1 19.3 19.7 20.0 20.5 20.8 21.9 22.6 22.8 23.3

WAIKATO

Arapuni ARI1101 12.6 12.6 12.5 12.5 12.7 12.7 12.7 13.0 13.0 13.1 13.1

Atiamuri ATI2201 16.9 17.3 17.3 17.4 17.5 17.6 21.6 21.7 21.7 21.7 21.7

Hamilton HAM1101 13.1 13.2 13.2 13.2 13.3 13.3 13.3 13.4 13.4 13.4 13.4

Hamilton HAM2201 10.5 10.5 10.6 10.7 10.7 10.8 10.7 10.8 10.8 10.9 10.9

Huntly HLY2201 32.1 32.3 32.9 34.8 35.1 35.5 35.2 37.0 35.0 36.5 35.0

Hangatiki HTI1101 2.7 2.7 2.7 2.7 3.0 3.0 3.0 3.1 3.1 3.3 3.3

Karapiro KPO1101 8.3 8.3 8.3 8.3 8.4 8.4 8.4 8.4 8.4 8.4 8.4

Maraetai MTI2201 21.0 21.3 22.2 23.6 23.8 23.9 25.1 25.2 25.4 25.4 25.3

Ohakuri OHK2201 16.5 17.0 17.1 17.2 17.3 17.4 20.4 20.5 20.5 20.5 20.5

Te Awamutu TMU1101 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8

Te Kowhai TWH2201 8.8 8.8 8.8 8.9 8.9 9.0 9.0 9.0 9.0 9.0 9.0

Whakamaru WKM2201 24.5 25.1 26.7 30.4 30.9 31.1 33.6 33.9 34.1 34.2 34.0

Waipapa WPA2201 11.8 11.9 12.1 12.5 12.6 12.6 12.9 13.0 13.0 13.0 13.0




2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021

BAY OF PLENTY

Edgecumbe EDG1101 7.0 7.2 7.2 7.2 7.8 7.8 8.1 8.1 8.2 8.2 8.2

Edgecumbe EDG2201 7.6 7.8 7.7 7.7 7.9 7.9 9.8 9.8 9.8 9.8 9.8

Kawerau KAW1101 12.0 12.6 12.6 12.6 14.9 14.9 15.8 15.8 16.5 16.5 16.5

Kawerau KAW2201 7.7 7.8 7.8 7.8 8.1 8.1 9.5 9.5 9.6 9.6 9.6

Kinleith KIN1101 8.5 8.5 8.2 8.2 8.3 8.3 8.5 8.6 8.6 8.6 8.6

Kaitimako KMO1101 10.6 10.7 10.5 10.5 10.6 10.6 25.3 25.3 25.3 25.4 25.4

Lichfield Tee LFD1101 5.8 5.8 5.5 5.5 5.6 5.6 5.8 5.8 5.8 5.8 5.8

Matahina MAT1101 9.4 9.7 9.7 9.7 10.7 10.7 11.1 11.1 11.4 11.4 11.4

Mt Maunganui MTM1101 7.0 7.0 6.9 6.9 7.0 7.0 11.2 11.2 11.2 11.2 11.2

Owhata OWH1101 4.0 4.0 3.9 3.9 3.9 3.9 4.2 4.2 4.2 4.2 4.2

Rotorua ROT1101 6.5 6.5 5.5 5.5 7.7 7.7 8.2 8.3 8.3 8.3 8.3

Rotorua ROT1102 6.1 6.1 5.1 5.1 5.7 5.7 6.2 6.2 6.2 6.2 6.2

Te Matai TMI1101 5.1 5.1 5.1 5.1 5.1 5.1 6.4 6.4 6.4 6.4 6.4

Tarukenga TRK1101 21.1 21.4 12.4 12.4 13.9 13.9 17.1 17.4 17.4 17.4 17.4

Tarukenga TRK2201 11.6 11.8 9.2 9.3 9.5 9.5 17.4 17.5 17.5 17.5 17.5


Aratiatia ARA2201 16.3 17.7 18.1 20.2 20.4 20.4 21.4 21.5 21.6 21.6 21.6

Bunnythorpe BPE1101 13.0 12.3 12.3 12.5 12.5 12.5 12.7 13.0 13.3 13.3 13.3

Bunnythorpe BPE2201 12.3 12.3 12.4 12.8 12.8 12.8 13.3 14.1 14.1 14.1 14.5

Linton LTN2201 7.4 7.4 7.4 7.6 7.6 7.6 7.9 8.3 8.3 8.3 8.4

Linton LTN2202 6.3 6.3 6.3 6.9 6.9 6.9 7.5 8.7 8.7 8.7 9.2

Mangamaire MGM1101 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8

Nga Awa Purua NAP2201 16.2 17.4 18.3 20.1 20.3 20.3 21.5 21.6 21.6 21.7 21.6

Ohaaki OKI2201 11.3 11.8 12.1 12.8 13.4 13.7 14.2 14.3 14.3 14.3 14.3

Poihipi PPI2201 13.0 15.1 15.4 21.7 22.0 22.0 23.2 23.3 23.3 23.3 23.3

Rangipo RPO2201 6.6 6.6 6.9 7.0 7.0 7.1 7.1 7.1 7.1 7.1 7.1

Tokaanu TKU2201 11.1 11.2 11.3 11.4 11.4 11.4 11.6 11.6 11.6 11.7 11.6

Tokaanu TKU2202 11.1 11.2 11.3 11.4 11.4 11.4 11.6 11.6 11.6 11.7 11.6

Tangiwai TNG2201 3.6 3.6 3.7 3.7 3.7 3.7 3.7 3.7 3.7 3.7 3.7

Tararua Wind Central

TWC2201 7.8 7.8 7.8 8.3 8.3 8.3 8.8 9.6 9.6 9.6 10.0

Woodville WDV1101 4.6 4.6 4.6 4.6 4.6 4.6 4.6 4.7 4.7 4.7 4.7

Wairakei WRK2201 21.5 24.1 25.0 29.3 29.8 29.8 32.2 32.4 32.5 32.5 32.5

TARANAKI

Brunswick BRK2201 6.9 7.0 7.0 7.2 7.2 7.2 7.3 7.3 7.3 7.3 7.4

Huirangi HUI1101 7.0 8.2 8.2 8.3 8.3 8.3 8.4 8.4 8.8 8.6 8.6

Hawera HWA1101 7.5 6.7 6.7 6.8 6.8 6.8 6.8 6.8 6.8 6.8 6.8

Hawera HWA1102 7.5 6.7 6.7 6.8 6.8 6.8 6.8 6.8 6.8 6.8 6.8

Kapuni KPA1101 3.8 3.8 3.8 3.9 3.9 3.9 3.9 3.9 3.9 3.9 3.9

Marton MTN1101 3.3 3.3 3.3 3.3 3.3 3.3 3.3 3.3 3.4 3.4 3.4




2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021

Marton MTN1102 3.3 3.3 3.3 3.3 3.3 3.3 3.3 3.3 3.4 3.4 3.4

Motunui MNI1101 7.2 9.3 9.3 9.4 9.5 9.5 9.6 9.6 9.9 9.7 9.7

New Plymouth NPL1101 12.8 14.0 14.0 14.5 14.7 14.7 15.0 15.0 17.5 16.7 16.7

New Plymouth NPL2201 7.9 8.3 8.3 8.8 8.9 8.9 9.2 9.2 9.5 9.2 9.2

Stratford SFD1101 12.9 13.3 13.3 13.8 13.9 13.9 14.2 14.2 14.2 14.2 14.2

Stratford SFD2201 14.9 15.6 15.6 17.8 18.4 18.3 20.1 20.1 20.1 20.1 20.1

Taumarunui TMN2201 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.8 2.9 2.9 2.9

Wanganui WGN1101 3.1 2.2 2.2 2.2 2.2 2.2 2.2 2.2 2.8 2.8 2.8

Waverley WVY1101 2.9 1.1 1.1 1.1 1.1 1.1 1.1 1.1 1.9 1.9 1.9

HAWKE’S BAY

Fernhill FHL1101 5.1 5.2 5.2 5.2 5.2 5.3 5.3 5.3 5.3 5.3 5.3

Gisborne GIS1101 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4

Redclyffe RDF1101 6.1 6.1 6.2 6.2 6.3 6.3 6.3 6.3 6.3 6.4 6.4

Redclyffe RDF2201 4.4 4.5 4.5 4.6 4.7 4.7 4.7 4.8 4.8 4.8 4.8

Tuai TUI1101 7.0 7.0 7.0 7.0 7.0 7.0 7.0 7.1 7.1 7.1 7.1

Whirinaki WHI2201 5.3 5.4 5.4 5.5 5.7 5.8 5.8 5.9 5.9 6.0 6.0

Whakatu WTU2201 3.7 3.8 3.8 3.8 3.9 3.9 3.9 4.0 4.0 4.0 4.0

WELLINGTON

Haywards HAY1101 19.6 20.4 20.5 20.8 20.9 20.9 22.2 22.4 22.5 22.5 22.5

Haywards HAY2201 12.4 12.7 12.9 13.2 13.2 13.3 13.9 14.2 14.3 14.3 14.7

Takapu Road TKR1101 11.7 11.9 12.0 12.1 12.1 12.1 12.6 12.7 12.7 12.7 12.8

Wilton WIL1101 10.5 10.6 10.6 10.8 10.8 10.8 11.3 11.4 11.4 11.4 11.5

Wilton WIL2201 7.3 7.4 7.4 7.6 7.6 7.6 7.9 8.0 8.0 8.0 8.1

West Wind WWD1101 6.0 6.0 6.1 6.1 6.1 6.1 6.3 6.3 6.3 6.3 6.3

West Wind WWD1102 6.0 6.0 6.0 6.1 6.1 6.1 6.3 6.3 6.3 6.3 6.3

NELSON-MARLBOROUGH

Argyle ARG1101 2.6 2.6 2.6 2.7 2.7 3.0 3.0 3.0 3.0 3.0 3.0

Blenheim BLN1101 2.3 2.3 2.3 2.4 2.4 2.9 2.9 2.9 2.9 2.9 2.9

Stoke STK1101 4.6 4.6 4.6 5.0 5.0 5.8 5.8 5.8 5.8 5.8 5.8

Stoke STK2201 2.7 2.7 2.7 2.9 2.9 3.2 3.2 3.2 3.2 3.2 3.2

WEST COAST

Atarau ATU1101 1.5 1.5 1.5 1.8 1.8 1.9 1.9 1.9 1.9 1.9 1.9

Inangahua IGH1101 2.1 2.1 2.1 3.5 3.8 3.9 3.9 3.9 3.9 3.9 3.9

Kikiwa KIK2201 3.5 3.5 3.5 3.8 3.9 4.2 4.2 4.2 4.2 4.2 4.2

Orowaiti ORO1101 1.2 1.2 1.2 1.9 2.6 2.6 2.6 2.6 2.6 2.6 2.6

Orowaiti ORO1102 1.2 1.2 1.2 2.0 2.1 2.1 2.1 2.1 2.1 2.1 2.1

Reefton RFN1101 1.6 1.6 1.6 2.2 2.3 2.3 2.3 2.3 2.3 2.3 2.3

CANTERBURY

Ashburton ASB2201 7.5 7.5 7.5 7.8 7.9 8.0 8.1 8.1 8.1 8.1 8.2




2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021

Bromley BRY2201 6.5 6.7 6.7 7.3 7.3 7.5 7.7 7.0 7.0 7.0 7.0

Islington ISL2201 8.2 8.2 8.2 8.8 8.9 9.2 9.6 9.5 9.5 9.5 9.6

SOUTH CANTERBURY

Aviemore AVI2201 17.0 17.0 17.1 17.9 18.1 18.2 19.4 19.4 19.5 19.5 19.5

Benmore BEN2201 22.8 22.8 22.9 23.1 23.3 23.4 24.4 24.5 24.6 24.6 24.7

Bells Pond BPD1101 1.7 1.7 1.7 1.7 1.7 1.7 1.7 1.7 1.7 1.7 1.7

Black Point BPT1101 2.3 2.3 2.3 2.3 2.3 2.3 2.4 2.4 2.4 2.4 2.4

Livingstone LIV2201 6.1 6.1 6.4 6.6 6.7 6.7 8.8 8.8 8.8 8.8 8.9

Ohau A OHA2201 18.3 18.3 18.3 18.5 18.7 18.8 19.0 19.0 19.2 19.2 19.3

Ohau B OHB2201 21.1 21.1 21.2 21.4 21.7 21.8 22.1 22.2 22.4 22.4 22.5

Ohau C OHC2201 18.5 18.5 18.5 18.7 18.9 19.0 19.3 19.3 19.4 19.4 19.5

Opihi OPI2201 5.9 5.9 5.9 6.0 6.0 6.0 6.1 6.1 6.1 6.1 6.1

Opihi OPI2202 5.9 5.9 5.9 6.0 6.0 6.0 6.1 6.1 6.1 6.1 6.1

Tekapo B TKB2201 11.8 11.8 11.8 11.9 12.3 12.3 12.4 12.4 12.5 12.5 12.5

Twizel TWZ2201 22.7 22.7 22.7 23.0 23.3 23.5 23.8 23.9 24.2 24.2 24.3

Waitaki WTK2201 13.4 13.4 14.0 14.6 14.8 14.8 16.5 16.5 16.6 16.6 16.7

OTAGO-SOUTHLAND

Berwick BWK1101 2.8 2.8 2.8 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7

Clyde CYD2201 16.4 16.4 16.4 16.6 17.2 17.5 17.6 17.8 18.7 18.7 18.7

Edendale EDN1101 2.8 2.6 2.6 3.5 3.5 3.5 3.5 3.5 3.5 3.5 3.6

Gore GOR1101 2.6 2.6 2.6 6.0 6.0 6.0 6.0 6.0 6.1 6.1 6.2

Halfway Bush HWB1101 9.5 9.5 9.6 10.6 10.7 10.8 10.8 10.9 11.0 11.0 11.1

Halfway Bush HWB2201 7.6 7.6 7.6 8.5 8.6 8.8 8.8 9.0 9.2 9.2 9.5



Manapouri MAN2201 14.1 14.1 14.1 14.2 14.3 14.3 14.6 14.6 14.6 14.6 14.7

North Makarewa

NMA2201 9.5 9.3 9.3 9.7 9.8 9.9 10.4 10.4 10.4 10.4 10.6

Naseby NSY2201 4.1 4.1 4.2 4.4 4.6 4.6 5.0 5.0 5.0 5.0 5.0

Roxburgh ROX1101 10.1 11.2 11.2 11.0 11.1 11.1 11.1 11.2 11.3 11.3 11.3

Roxburgh ROX2201 15.1 15.4 15.4 15.7 16.3 16.6 16.8 17.1 19.2 19.2 19.2


Three Mile Hill TMH2201 7.7 7.7 7.7 8.7 8.8 9.1 9.1 9.3 9.6 9.6 9.9

Tiwai TWI2201 7.3 7.1 7.1 7.3 7.3 7.4 7.6 7.6 7.6 7.6 7.7

Appendix D: Project Calendar


Appendix D Project Calendar

Table 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 4

2011/12

2012/13 Timaru substation development plan Upper South Island grid upgrade – Stage 1

Table D.2: Forecast submission dates for projects to the Commerce Commission post-2013/14

Year Project

2013/14 Upper South Island grid upgrade – Stage 2

Upper North Island reactive support – post-NIGUP

Lower North Island transmission capacity

2014/15 HVDC Stage 3

Valley spur security and reactive support

2015/16

To be advised174

Lower Waitaki Valley transmission development

Bunnythorpe interconnecting transformer replacement

Taranaki interconnecting transformer capacity and voltage quality

Wellington 110 kV supply security

Kaitimako interconnecting transformer capacity

Inangahua–Murchison–Kikiwa transmission capacity

174

Project submission date is pending on the outcome of investigations.



Table D-3: Base Capex175

with minor enhancement

Projects Forecast commissioning year

Resolve the protection limits on the Wellsford supply transformers. 2012/13

Resolve the protection limits on the Mangere supply transformers. 2012/13

Resolve the protection limits on the Takanini supply transformers. 2012/13

Resolve the protection limits on the Edgecumbe supply transformers. 2012/13

Resolve the protection limits on the Kopu supply transformers. 2012/13

Resolve the protection limits on the Carrington Street supply transformers. 2012/13

Resolve the metering and HV protection limits on Melling 110/33 kV and 110/11 kV supply transformers. 2012/13

Resolve the protection and metering limits on the Takapu Road supply transformers. 2012/13

Resolve the protection limits on the Motueka supply transformers. 2012/13

Resolve the protection limits on the Balclutha supply transformers. 2012/13

Resolve the protection limits on the Edendale supply transformers. 2012/13

Recalibrate metering parameters on the Invercargill supply transformer. 2012/13

Splitting Huapai 220 kV bus once the NAaN project is complete. 2013/14

Resolve the protection and metering limits on the Upper Hutt supply transformers. 2013/14

Resolve the protection limits on the Dobson supply transformers. 2013/14

Resolve the protection limits on the Oamaru supply transformers. 2013/14

Resolve the protection limits on the Mount Roskill supply transformers. 2014/15

Recalibrate metering parameters on the South Dunedin supply transformers. 2014/15

Resolve the protection limits on the Te Awamutu supply transformers. 2015/16

Resolve the metering and protection limits on the Waipawa 11/33 kV transformers. 2015/16

Resolve the metering and protection limits on the Greytown supply transformers. 2016/17

Resolve the protection and metering limits on the Maungaturoto supply transformers. 2019/20

175

These proposed projets are funded under approved Base Capex allowance.



Projects Forecast commissioning year

Resolve the protection limits on the Wiri supply transformers. 2019/20

Resolve the metering and protection limits on the Opunake supply transformers. 2019/20

Resolve the protection limits on the Cromwell supply transformers. 2019/20

Resolve protection and metering limits on the Tekapo A supply transformer. 2019/20

Resolve the 110 kV disconnector limit on the Stoke 220/110 kV interconnecting transformer. 2020/21

Resolve protection limits on the Bream Bay supply transformers. 2021/22

Resolve the protection and metering limits on the Frankton T4 supply transformer. 2022/23

Replace limiting switchgear on the Henderson T1. 2023/24

Resolve protection and circuit breaker limits on the Albany supply transformers. 2023/24

Resolve the metering limits on the Silverdale supply transformers. 2023/24

Resolve the metering parameters on the Marton supply transformers. 2023/24

Recalibrate the metering parameters on the Gisborne supply transformers. 2023/24

Resolve the protection limits on the Wilton supply transformers. 2023/24

Re-tune generator excitation systems and/or install power system stabilisers. To be advised

Table D-4: Forecast commissioning dates and project status

Forecast commissioning year

Projects Status Cost band

2012/13 A new 220/400 kV double-circuit transmission line from Pakuranga to Whakamaru. Committed G

Lower South Island Reliability projects (Commissioning years: 2012/13-2014/15). Committed E

Upper North Island reactive support – Stage 2 (Commissioning years: 2012/13-2013/14). Committed F

HVDC Pole 3 – Stage 1 and Stage 2 (Commissioning years: 2012/13-2013/14). Committed G and D

Replace the conductor on the 220 kV Bunnythorpe–Haywards 1 and 2 circuits (Commissioning years: 2012/13-2018/19). Proposal submitted F

Resolve the protection limits on the Mangere supply transformers. Base Capex A

Building a grid exit point at Piako. Committed (customer-specific) C





Resolve the protection limits on the Edgecumbe supply transformers. Base Capex A

Replace the conductors on the 110 kV circuits between Stratford and Wanganui. Committed D

Replace the Maungatapere 110/50 kV transformer with higher-rated units. Base Capex B

Resolve the protection limits on the Wellsford supply transformers. Base Capex A

Resolve protection limits on the Takanini supply transformers. Base Capex A

Resolve the bus and protection limits on the Cambridge supply transformers. Committed (customer-specific) A

Resolve the protection limits on the Kopu supply transformers. Base Capex A

Increase the rating of the two existing Te Kowhai transformers by installing radiators and fans. Committed (customer-specific) A

110 kV grid reconfigurations to relieve Kawerau generation constraint. Proposal submitted A

Thermally upgrade the Kaitimako–Tarukenga circuits and change the operating voltage from 110 kV to 220 kV, and install two 220/110 kV 150 MVA transformers at Kaitimako.

Committed D

A new feeder from Tangiwai to Ohakune. Not yet agreed with customer A

Increase protection limits on the Carrington Street supply transformers. Base Capex A

Replace the supply transformers at Stratford with two 40 MVA units (Commissioning years: 2012/13-2014/15). Base Capex B

Replace Masterton supply transformers with two 60 MVA units. Committed (customer-specific) B

Resolve the metering and HV protection limits on Melling 110/33 kV and 110/11 kV supply transformers. Base Capex A

Install new capacitors at Paraparaumu. Not yet agreed with customer A

Resolve the protection and metering limits on the Takapu Road supply transformers. Base Capex A

Resolve the protection limits on the Motueka supply transformers. Base Capex A

Replace Stoke supply transformers with two 120 MVA units. Committed (customer-specific) C

Install one 220/66 kV transformer at Bromley (committed), followed by a second and third transformer at later date. Committed (customer-specific) B

Install reactive support at Oamaru. Not yet agreed with customer A

Resolve the protection limits on the Balclutha supply transformers. Base Capex A

Resolve the protection limit and upgrade the cable on the Edendale supply transformers. Base Capex (protection), and not yet agreed with customer (cable)

A





Recalibrate metering parameters on the Invercargill supply transformer. Base Capex A

2013/14 Clutha-Upper Waitaki Lines Project (Commissioning years: 2013/14-2016/17). Committed F

Building a new 220 kV double circuit transmission line between Wairakei and Whakamaru. Committed F

Splitting Huapai 220 kV bus once the NAaN project is complete. Base Capex A

Increase supply transformer capacity at Dargaville by adding fans and/or pumps. Not yet agreed with customer A

New grid exit point at Wairau Road. Committed (customer-specific) C

North Auckland and Northland project. Committed G

New grid exit point at Hobson Street. Committed (customer-specific) D

Tarukenga interconnecting transformer replacement. Base Capex D

Replace Kawerau T12 with a 250 MVA 10 % impedance transformer. Proposal submitted B

Increase 110/11 kV supply transformer capacity at Rotorua or transfer some 11 kV load to the 33 kV bus and Owhata. Not yet agreed with customer TBA

Install an SPS scheme to automatically open the Mangamaire–Woodville circuit following an outage of one Bunnythorpe–Woodville circuit.

Proposal not submitted A

Replace Wanganui supply transformers with two 80 MVA units, or install new 110 kV feeders from Wanganui, or install 2nd

supply transformer at Brunswick and supply the load from Brunswick (Commissioning years: 2013/14-2015/16).

Base Capex for Wanganui transformer replacement

B

Replace Redclyffe supply transformers with two 120 MVA units. Committed (customer-specific) B

Replace Central Park 110/33 kV supply transformers with 120 MVA units. Base Capex C

Replace supply transformers at Haywards with two 110/33/11 kV 60 MVA units. Base Capex C

Resolve the protection and metering limits on the Upper Hutt supply transformers. Base Capex A

Install new capacitors at Motueka. Not yet agreed with customer A

Resolve the protection limits on the Dobson supply transformers. Base Capex A

Resolve the protection limits on the Oamaru supply transformers. Base Capex A

Install a 110 kV bus coupler at Timaru. Proposal not submitted A

Increase supply transformer’s capacity at Waitaki. Not yet agreed with customer A

2014/15 A sixth bus coupler at Islington. Proposal not submitted TBA





Install capacitors along the Valley Spur or within Powerco’s network, or replace existing transformers at Waikino and Waihou with on-load tap changing transformers (Commissioning years: 2014/15-2020/21).

Not yet agreed with customer A or B or A

Replace Hangatiki supply transformers with two 40 MVA units. Base Capex B

New grid exit point at Putaruru. Not yet agreed with customer C

Construct a second transmission circuit either from Hangatiki or Karapiro to Te Awamutu. Not yet agreed with customer D or C

Resolve the circuit breaker limits and protection limits on the Mount Roskill supply transformers. Not yet agreed with customer A

Upgrade the circuitbreaker and busbar ratings on the Takanini supply transformer. Not yet agreed with customer A

Increase the existing transformers capacity at Owhata. Three options are currently under reviewed. Not yet agreed with customer TBA

Thermally upgrade the Rotorua–Tarukenga circuits. Not yet agreed with customer TBA

Replace the Bunnythorpe interconnecting transformers with two 150 MVA units (Commissioning years: 2014/15-2016/17). Proposal not submitted B

Thermally upgrade the Carrington Street–Stratford circuit’s terminal spans near Carrington Street. Proposal not submitted A

Upgrade the LV bus section, disconnectors and current transformer limits on the Carrington–Street supply transformers. Not yet agreed with customer A

A third supply transformer at Paraparaumu or a new grid exit point at Otaki. Not yet agreed with customer A or C

Install a third 220/66 kV transformer at Ashburton. Not yet agreed with customer A

Replace Studholme supply transformers with higher-rated units. Not yet agreed with customer B

Replace the Timaru supply transformers with higher-rated units or transfer some loads to 33 kV by installing two 220/33 kV supply transformers.

Not yet agreed with customer C

Replace Gore supply transformers with two higher-rated units (Commissioning years: 2014/15-2024/25). Base Capex A

Replace Naseby supply transformers with two higher-rated units (Commissioning years: 2014/15-2020/21). Not yet agreed with customer A

Recalibrate metering parameters on the South Dunedin supply transformers. Base Capex A

2015/16 HVDC link expansion up to 1400 MW. Proposal not submitted E

Resolve the protection limits on the Te Awamutu supply transformers. Base Capex A

Replace the Kinleith 110/33 kV 20 MVA supply transformer with a 40 MVA unit. Not yet agreed with customer A

Reconductor the Bunnythorpe–Woodville circuits with higher-rated conductors, or convert Bunnythorpe–Woodville circuits to 220 kV operation (Commissioning years: 2015/16-2020/21).

Proposal not submitted TBA

Resolve the metering and protection limits on the Waipawa 11/33 kV transformers. Base Capex A





Install a second transformer at New Plymouth, or operate the 220 kV New Plymouth–Stratfird circuits at 110 kV (Commissioning years: 2015/16-2020/21).

Proposal not submitted TBA

Install reactive support at Hawera, or contract for aditional reactive support, or install under-voltage load shedding capability (Commissioning years: 2015/16-2020/21).

Proposal not submitted A

Install a second 250 MVA interconnecting transformer at Wilton (Commissioning years: 2015/16-2020/21). Proposal not submitted B

A new grid exit point at Brightwater. Not yet agreed with customer C

Replace the Dobson supply transformers with higher-rated units (Commissioning years: 2015/16-2017/18). Not yet agreed with customer B

Replace Ashley 66/11 kV supply transformers with two 40 MVA units. Base Capex A

2016/17 Install additional shunt reactive support around Islington or Bromley, or bus the existing circuits between Waitaki Valley and Islington where they converge near Geraldine.

Proposal not submitted D

Construct a new Hamilton–Waihou or upgrade existing Hamilton–Waihou circuits. Not yet agreed with customer D or C

Resolve the metering and protection limits on the Greytown supply transformers. Base Capex A

A new grid exit point at Riwaka. Not yet agreed with customer C

2017/18 Install a new 220/33 kV transformer at Hamilton and/or at Te Kowhai. Not yet agreed with customer A and/or C

Install a third 220/110 kV interconnecting transformer at Kaitimako. Proposal not submitted B

Install a new 220/33 kV supply transformer at Brunswick. Not yet agreed with customer B

Thermally upgrade the Inangahua–Murchison–Kikiwa circuit, or install a special protection scheme. Proposal not submitted A or TBA

Replace Edendale supply transformers with two higher-rated units. Base Capex B

Replace two Halfway Bush 110/33 kV transformers with one 220/33 kV transformer. Base Capex TBA

2018/19 Replace Huirangi supply transformers with two 50 MVA units and reconfigure the distribution system. Not yet agreed with customer B

Replace the Fernhill 30 MVA supply transformer with an 80 MVA unit. Base Capex A

Replace the North Makarewa 220/33 kV transformers with two 220/66 kV units. Not yet agreed with customer TBA

2019/20 Resolve the protection and metering limits on the Maungaturoto supply transformers. Base Capex A

Resolve the protection limits on the Wiri supply transformers. Base Capex A

Replace the transformers at Waiotahi with two higher-rated units. Base Capex A





Resolve the metering and protection limits on the Opunake supply transformers. Base Capex A

Resolve the protection limits on the Cromwell supply transformers. Base Capex A

Thermally upgrade the 110 kV Cromwell–Frankton circuits. Not yet agreed with customer TBA

Resolve protection and metering limits on the Tekapo A supply transformer. Base Capex A

2020/21 Resolve the constraint on the terminal spans at Otahuhu and Penrose substations. Base Capex A

Replace the supply transformers at Wiri with higher-rated units. Not yet agreed with customer B

Install a special protection scheme, or Kinleith 110 kV bus reconfiguration (Commissioning years: 2020/21-2026/27). Proposal not submitted A

Replace the supply transformers at Waikino with higher-rated units. Base Capex B

Resolve the 110 kV disconnector limit on the Stoke 220/110 kV interconnecting transformer. Base Capex A

Install additional capacitors in the West Coast, or install a special protection scheme Proposal not submitted A or TBA

Establish a new 220/66 kV grid exit point southof Christchurch. Not yet agreed with customer C

2022/23 Replace the Waihou supply transformers with higher-rated units (Commissioning years: 2022/23-2026/27). Base Capex B

Resolve protection and metering limits on Frankton T4 supply transformer and upgrade T2A & T2B supply transformer capacity. Base Capex (protection and metering), and not yet agreed with customer (transformer capacity)

A

A

Resolve the protection and metering limits on the Frankton T4 supply transformer. Base Capex A

Increase Frankton T2A & T2B supply transformers’ capacities by adding pumps. Not yet agreed with customer A

2023/24 Replace limiting switchgear on the Henderson T1. Base Capex A

Install a 3rd 220/110 kV transformer at Marsden, and convert the 220 kV and 110 kV buses to three zones Proposal not submitted B

Resolve protection and circuit breaker limits on the Albany supply transformers. Base Capex A

Resolve the metering limits on the Silverdale supply transformers. Base Capex A

Resolve the metering parameters on the Marton supply transformers. Base Capex A

Recalibrate the metering parameters on the Gisborne supply transformers. Base Capex A

Resolve the protection limits on the Wilton supply transformers. Base Capex A





2024/25 Automatic split the 110 kV network between Henderson and Maungatapere or thermal upgrade the Henderson–Wellsford circuits. Proposal not submitted TBA

2025/26 Install a new interconnecting transformer at Hamilton or at a new grid exit point. Proposal not submitted B or C

Replace Halfway Bush 220/33 kV 100 MVA transformers with one 220/33 kV 120 MVA transformer. Base Capex TBA

To be advised Upper North Island reactive support post 2014. Proposal not submitted TBA

Re-tune generator excitation systems and/or install power system stabilisers. Base Capex A

Increase the ratings of the 220 kV Brunswick–Stratford circuits, reconductor Huntly–Stratford circuits or a new line between Taumarunui and Whakamaru.

Proposal not submitted C and E

Tranche 1 – an SPS/series reactor/phase shifting transformer, or increase the capacity of Tokaanu–Whakamaru and Bunnythorpe–Tangiwai–Rangipo circuits.

Tranche 2 – reconductor the Bunnythorpe–Tokaanu circuits, or a new transmission capacity between Bunnythorpe and Whakamaru, or a new line from Taumarunui to Whakamaru, or Lower North Island-wide SPS.

Proposal not submitted F or G

Increase the HVDC line rating. Proposal not submitted TBA

Increase the ratings of the 220 kV Benmore–Twizel 1 circuit. Proposal not submitted B

Additional voltage support at Kaitaia or Maungatapere. Proposal not submitted TBA

Install a third supply transformer at Henderson. Not yet agreed with customer B

Thermal upgrade the 110 kV Kaikohe–Maungatapere circuits. Not yet agreed with customer TBA

Upgrade the Kensington 33 kV switchboard, and upgrade branch limiting components on the Kensington–Maungatapere circuits. Not yet agreed with customer TBA

Install a third supply transformer at Otahuhu, or replace with existing transformers with higher-rated units. Not yet agreed with customer B

Install a new cable from Otahuhu connecting to a new 110/ 33 kV transformer at Wiri, or a 110/33 kV transformer at Otahuhu and 33 kV cable to Wiri, or 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.

Under investigation D

Replace Otahuhu T2 & T4 with higher impedance transformers, or upgrade the Otahuhu–Penrose circuit capacity. Proposal not submitted TBA

Replace the Hinuera 30 MVA supply transformer with a 60 MVA unit. Not yet agreed with customer A

A new grid exit point at Papamoa. Not yet agreed with customer B

Replace Edgecumbe supply transformers with higher-rated units. Not yet agreed with customer C

Install either series reactors or phase shifting transformers to reduce the power flows on the Bunnythorpe–Mataroa circuits. Proposal not submitted TBA





Install new capacitors at Gisborne 110 kV bus. Proposal not submitted TBA

Upgrade the Takapu Road supply transformer capacity. Not yet agreed with customer B

Install a second 110/66 kV interconnecting transformer at Stoke. Not yet agreed with customer B

Thermal upgrade Kikiwa–Stoke 110 kV circuit. Proposal not submitted TBA

Replace Kikiwa T1 with a higher-rated unit. Proposal not submitted TBA

Implement Kawaka bonding project. Proposal not submitted TBA

Replace existing two 220/33 kV transformers with 220/66 kV higher-rated units at Culverden. Not yet agreed with customer TBA

Install two new 66 kV feeders from Southbrook. Not yet agreed with customer TBA

Install a new 220/66 kV transformer at Islington. Proposal not submitted B

To increase supply security at Bells Pond. Not yet agreed with customer TBA

A new grid exit point near St Andrews. Not yet agreed with customer TBA

Increase interconnecting transformer capacity at Timaru. Proposal not submitted TBA

Install a new 120 MVA transformer at Temuka, and upgrade the 110 kV Timaru–Temuka circuits. Not yet agreed with customer B and B

Install a second supply transformer at Waitaki. Not yet agreed with customer A

Appendix E: Investment Approvals Process


Appendix E Transpower’s Investment Approvals Process (IAP)

E.1 Purpose of the Investment Approvals Process

The Investment Approvals Process (IAP) is the decision – making framework for preparing investment proposals. It is a robust and replicable process, adaptable to the range of investment situations that arise: - large and small value proposals with many or few options to investigate. The output is a high quality investment proposal for approval by the Commerce Commission or a Customer. Transpower’s Board and stakeholders can be confident that the investment and delivery decisions are driven by a verified need and are efficient, appropriate and defensible.

There are two approval routes:

Regulatory approval of proposals for investment in interconnection assets allows Transpower to add the assets to its regulated asset base (RAB) and to recover costs via the Transmission Pricing Methodology (TPM), and

Investment in connection assets which are paid for by customers are not added to Transpower’s regulated asset base. The exception to this, which has not yet ever occurred, is where investment in connection assets is required to meet GRS and is approved by the Commerce Commisison via a Major Capex proposal.

E.2 IAP Framework

The Framework consists of five stages with generic actions occurring through each (outlined in Figure 1). Specific actions are required according to the rules

176 for

investment in interconnection assets and rules for investment in connection assets, e.g. proposals that require individual Regulator approval (for investment in interconnection assets) must comply with rules for consultation and methodology for economic analysis.

176

Relevant rules as at March 2012 are those in Part 12 Electricity Industry Participation Code 2010 and Capex Input Methodology 2012.

Need Options

Identification Options Analysis

Proposal Transition to

Delivery

Appendix E: Investment Approvals Process


Outline of IAP Stages

Needs are identified through Annual Planning Report process, including

consultation with Customers.

Each need is investigated and verified as an investment case.

Costs and benefits are assessed under the regulated cost/benefit test (the

Investment Test) with analysis commensurate with the likely investment cost.

Need

Options Identification

Options Analysis

Proposal

Transition to Delivery

Investment option confirmed

including through feedback from

stakeholders on short list options and/or

preferred option.

Investment proposal submitted to

Commerce Commission.

A range of investment options is

considered, including possible non-

transmission solutions

Consultation on need, approach,

assumptions, long list options; and

request additional information, through

consultation document and/or

Stakeholder forum.

The long list options are refined to a set

of credible options, using specific criteria

(high-level cost, feasibility, GEIP).

TP produces a High Level

Response for investment options,

taking into account Customer

need.

Interconnection Connection

A short-list of investments options is

identified from economic, technical and

feasibility analysis of credible options.

Investment option confirmed

and Transpower and the

Customer enter into an

Investment Contract.

Decision rule for proposed investment is

based on maximum net benefits or least

net cost (depending on whether

investment is to meet the Grid Reliability

Standards and / or to create net benefits

to the market).

The approved investment enters a detailed design (equipment and placement)

stage and approvals processes under the RMA are undertaken

Consultation continues within communities affected by ensuing works.

Customer decides on preferred option

and signs a contract for detailed study

design.

TP must assess any implications for

the Grid Reliability Standards (GRS)

arising from the investment.

Both TP and Customers have

requirements under the Code

depending on the GRS assessment.

Appendix F: Grid Support Contracts


Appendix F Grid Support Contracts

F.1 Background

Following the 2007 - 2008 demand-side participation trials and the consideration of the many complex issues and trade-offs involved, Transpower designed a grid support contract (GSC) product incorporating feedback from its industry consultation process. The design and sample contracts are available on Transpower’s project website.

177

Transpower has introduced grid support contracts (GSCs) to enable it to contract with proponents of non-transmission options to augment or substitute for grid capacity in specific circumstances.

F.2 Use of GSCs

GSCs as a risk management tool

Transpower has significant concerns over the risk to reliability of supply from insufficient transmission capacity that could arise from:

delayed build of new transmission assets - whether for reasons of regulatory approval, obtaining consents under the RMA, acquiring property, or due to competition in world markets for transmission assets and expertise

higher demand growth than was forecast at the time of investment decision, which would bring forward the need date, or

major asset failure - which is a growing concern given the age of Transpower’s asset base.

GSCs are designed to provide a useful product as part of a toolbox of approaches to managing such risks.

GSCs as a transmission deferral tool

GSCs may also be used to contract for products that can defer transmission investments where there is genuine option value in deferring an investment decision.

Where such option values do not exist, Transpower would not propose to use GSCs to push investment to the very edge of modelled ‘just in time’ limits. There are huge asymmetries 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 their advantage as an insurance against the delivery risks outlined above.

177

http://www.gridnewzealand.co.nz/gsc-publications.



F.3 Key parameters

Key parameters of Transpower’s GSC product design include the following.

GSCs will be specific to transmission capacity problems and offered only for specific regions and periods when these are occurring or are forecast to occur. GSCs will not be offered to address generation adequacy problems.

Transpower will not pick winners or losers: Transpower will identify a need, a potential provider may propose a commercial solution to the need, and Transpower will decide whether or not to offer a GSC for that proposal.

To encourage innovation in non-transmission solutions, GSCs will be open to all non-transmission options, but with clear qualification and evaluation criteria to ensure reliability.

To encourage competition in procurement, GSCs will be offered to successful tenders through a full request for information (RFI) and request for proposal (RFP) process: qualification and evaluation criteria will be applied.

GSCs will be contracts for services, not for Transpower ownership. Transpower will offer them in its capacity as grid owner. For those GSCs that require to be called or dispatched, this will be done by the System Operator on behalf of the grid owner.

As cost recovery will be through the transmission pricing methodology (TPM), approval of the GSCs will be required from the Commerce Commission (unless pre-approved by the former Electricity Commission). GSCs will be offered only as part of a reliability investment proposal for assets on the interconnected grid: they will not be offered for connection asset issues or for economic investments.

F.4 Design issues

Transpower has concerns about some specific issues around GSC design and operation and the GSC product on offer is intended to minimise these risks. Transpower’s main concern is how to obtain the benefits possible from GSCs without:

compromising reliability

significant interference in the wholesale electricity market

significant distortions in electricity generation investment incentives, or

Transpower becoming relied on for energy as well as transmission capacity provision.

Reliability

Historically, the transmission grid was developed to link previously unconnected regions to provide greater levels of reliability through access to more generation resources. While initially undertaken for energy transport reasons, more recently investment 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 to achieve transmission levels of reliability. Rather, a reliability level of around 99% to 99.9% may be achievable, which may be adequate if exposure to these lower reliability levels is limited to system peaks for limited periods. Using these options it must be appreciated that reliability may decline, but the options still add value as a risk management tool. Even lower levels of reliability, or prolonged exposure to such levels, 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 appropriate reliability criteria are set for proponents wishing to enter into GSCs.



Market distortion

A significant issue for our GSC design process is to what extent the use of GSCs could distort existing markets, in particular the wholesale generation investment and operations market. The wholesale electricity market is a multi-billion dollar per annum market, whereas the GSC market is likely to be in the order of some tens of millions per annum at most. Designing and operating GSCs to minimise interference in the wholesale market is essential.

F.5 Forms of GSC

The design encompasses three forms of GSC:

Demand-side participation (DSP), including non-market generation

Transpower has trialled small aggregated DSP in its 2007 Pilot and 2008 Trial. These demonstrated that, under certain conditions, blocks of aggregated small DSP sources can be made reliable. Significant issues arose in forecasting the time and size of need sufficiently accurately at the time of call. Transpower is investigating improvements to the load forecasting processes and also the criteria for calling Demand Response as a means to address the issues identified at the time of those trials. A Demand-side participation GSC may include a variety of Demand Response (DR) resources, including aggregated blocks of multiple small DR resources, blocks made up of single load, and in principle, non-market generation sources (although the latter are likely to be part of an aggregated block). Blocks would be called individually by the System Operator in accordance with instructions from Transpower as grid owner reflecting the contract terms. Blocks would be expected to deliver the contracted capacity: their reliability would be a paramount consideration in the design, procurement and operation of this form of GSC. Blocks would either be called ahead of time using a Demand Response Management System (DRMS), or be operated automatically post-contingency.

Voltage support

Transpower will use GSCs for contracting for voltage support over medium to long term planning horizons. They will in effect replace the voltage support ancillary service contracts over these timeframes. This will provide improved integration in grid planning, as the grid planner can better ‘co-optimise’ real and reactive power issues and transmission and non-transmission reactive support options, over planning horizons from technical, good electricity industry practice and economic perspectives. In particular, the grid planner can test and contract for the availability and cost of future voltage support, rather than simply assume that this will be the eventual outcome of ancillary service voltage support contracts. Cost allocation would change from zonal under Part 8 (of the Electricity Industry Participation Code) to national under the Part 12 transmission pricing methodology, aligning cost allocation for transmission and non-transmission reactive support solutions. The System Operator would still procure contracts of a short-term nature to cover for unanticipated reactive power requirements.

Market generation

For market generation, avoiding interference in the operational market is paramount. GSCs will not be offered to define how generators would offer real power into the market, whether in time, quantity or price. Rather, GSCs will be limited to contributions to capital or other fixed ‘up front’ costs. In effect, GSCs will be used to buy certainty over a particular generator’s development path – be it for example in time, equipment or location – to allow transmission to be safely designed around it. Proponents will be required to demonstrate that they are sufficiently committed to be able to deliver and that their contract price is a fair and reasonable reflection of actual cost.



F.6 Process for offering GSCs

As GSCs are specific to transmission capacity problems, GSCs will be offered only as part 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 there is a proponent of a non-transmission option (identified through Transpower’s RFI and RFP process) that meets the GSC qualification and evaluation criteria, the option will become part of the preferred option that is submitted as an investment proposal under a GUP.

The diagram on the next page illustrates how GSCs are integrated into the existing grid planning process.

F.7 Updates and further information

In 2011, Transpower released a request for proposal for the procurement of 60 MW of demand-side response in the Upper North Island. No demand response was procured through this process, due to the offers being deemed uneconomic as a transmission deferral option for Upper North Island.

A key finding from the tender process was that demand response needs to be established if it is to be an economic transmission deferral product. Requiring proponents to provide adequate demand response within a condensed timeframe and for a relatively short contract period only drives prices upward. Reliability demand response 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 can be delivered at economic cost. The re-scoped project builds on what we learnt during the tender process in 2011. The project includes implementing a pilot which will:

test a demand response management system for effective dispatch of demand response.

assess whether the management system reduces barriers to entry for different types of demand response.

discover the economic price points for different types of demand response.

determine whether a sustainable demand response programme can be established.

The implementation of the pilot will be conducted over a number of months, with a review at each stage.

It is anticipated that the GSC product will be progressively refined with experience. The current design details of the product may differ slightly from those outlined above.



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Appendix G Generation Scenarios



This section details the timing, type, location and size of new generators assumed in each 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 modelled generators. The choice of connection point is often arbitrary, but required in order to effectively model future transmission grids. Changes to these connection points may be necessary when testing proposed transmission investment into a region.

G.1 Scenario 1: Sustainable Path

The major features of the Sustainable Path scenario are:

Carbon charges and gas prices are both very high. As a result, renewable energy production exceeds 90% of total generation (on average) from 2020 onwards.

Major development of renewable generation takes place in both North and South Islands. By 2027, geothermal capacity has reached 1500 MW, wind capacity exceeds 3,000 MW, and 1,000 MW of new hydro has been constructed.

Tidal and wave energy, distributed solar power, and biomass cogeneration also feature.

Baseload thermal generation is largely phased out, with all four Huntly coal-fired units, Otahuhu B, Taranaki CC and Southdown decommissioned by 2027.

Thermal peaking plants are required in order to balance intermittent generation, provide dry-year swing, and supply reliable capacity to meet peak demand. By 2027, over 1,400 MW of thermal peakers are available.

Interruptible load (IL) and price-responsive demand, driven by advanced metering, time-of-use tariffs, and other initiatives, have an important role to play in balancing intermittent generation and meeting peak demand.

The extent of demand-side management, however, is substantially less than was assumed in the 2010 Statement of Opportunities (and hence the last APR). The total (firm) demand-side management capacity increases by 400 MW between 2011 and 2027.

Appendix G: Generation Scenarios


Projects and commission dates – Sustainable Path scenario

Year Plant description Technology description Capacity MW

Substation (approx)

2013 Huntly coal unit 1 Coal 0 (Decomm.) Huntly

2013 Wairakei Geothermal 0 (Decomm.) Wairakei

2013 Kawerau Norske Skog Geothermal 25 Kawerau

2013 Te Mihi Geothermal 165 Wairakei

2013 Remaining part of Wairakei Geothermal 110 Wairakei

2013 Waitara McKee peaker Peaker, fast start gas-fired peaker

100 Motunui Deviation

2014 Ngatamariki Geothermal 82 Nga Awa Purua


2015 Tauhara stage 2 Geothermal 200 Wairakei

2015 Demand side response 1 NI Price-responsive load curtailment

50 Takapuna

2015 Demand side response 1 SI Price-responsive load curtailment

50 Bromley

2015 Generic solar 1 Solar 50 Penrose

2015 Mill Creek Wind 60 Wilton

2016 Generic geo 1 Geothermal 100 Kawerau

2016 Pukaki Gates Hydro, peaking 35 Pukaki

2016 Arnold Hydro, run of river 46 Dobson

2016 New IL 1 Interruptible load 50 Penrose

2017 Wairau Hydro, run of river 73 Blenheim

2012 2014 2016 2018 2020 2022 2024 2026 0

2000

4000

6000

8000

10000

12000

14000

Year

MW

Installed capacity by technology - Sustainable path (mds1)

Wind

Wave

Tidal

Solar

Cogeneration, other

Open cycle gas turbine - gas

Interruptible load

Coal, IGCC w ith CCS

Hydro, schedulable

Hydro, run of river

Hydro, peaking

Hydro, pumped storage

Geothermal

Peaker, fast start gas-fired peaker

Cogeneration, gas-fired

Peaker, diesel-f ired OCGT

Price-responsive load curtailment

Coal

Combined cycle gas turbine

Cogeneration, biomass-fired




Substation (approx)

2017 Stockton Hydro, run of river 30 Westport


50 Mangere

2017 Castle Hill 1 Wind 200 Linton

2017 Central Wind Wind 120 Rangipo

2018 Southdown Combined cycle gas turbine 0 (Decomm.) Southdown

2018 Generic geo 2 Geothermal 100 Ohaaki

2018 Generic geo 4 Geothermal 100 Whakamaru

2018 Generic geo 5 Geothermal 100 Rotorua

2018 Diesel fired OCGT 1 Peaker, diesel-fired OCGT 40 Marsden

2018 Diesel fired OCGT 10 Peaker, diesel-fired OCGT 40 Kaitemako

2018 Diesel fired OCGT 19 Peaker, diesel-fired OCGT 40 Gracefield


50 Central Park

2018 Generic solar 3 Solar 50 Addington

2019 Taranaki CC Combined cycle gas turbine 0 (Decomm.) Stratford

2019 Kaituna Hydro, run of river 15 Tarukenga

2019 Diesel fired OCGT 9 Peaker, diesel-fired OCGT 100 Huntly

2019 Gas fired OCGT 9 Peaker, fast start gas-fired peaker

160 Huntly

2019 Maungaharuru Wind 94 Whirinaki


2019 Hauauru ma raki 1 Wind 250 Huntly

2019 Taharoa Wind 54 Hangatiki

2019 Mt Cass Wind 50 Waipara


2020 Otahuhu B Combined cycle gas turbine 0 (Decomm.) Otahuhu

2020 Biomass Cogen, Kawerau Cogeneration, biomass-fired 31 Kawerau

2020 North Bank Tunnel Hydro, peaking 280 Waitaki



100 Southdown


100 Otahuhu


50 Penrose

2020 Generic tidal 1 Tidal 200 Wellsford

2020 Waverley Wind 135 Waverley

2021 Generic solar 2 Solar 50 Mt Roskill

2021 Mahinerangi stage 2 Wind 170 Halfway Bush


2022 Clutha River Hydro, peaking 200 Roxburgh

2022 New IL 2 Interruptible load 50 Mt Roskill

2023 Diesel fired OCGT 6 Peaker, diesel-fired OCGT 100 Otahuhu




Substation (approx)


2023 Long Gully Wind 12.5 Central Park

2023 Hurleyville Wind 100 Hawera

2024 Generic run of river 1 Hydro, run of river 50 Stoke

2024 Waitahora Wind 175 Linton

2024 Taumatatotara Wind 44 Hangatiki


2025 Waikato upgrade Hydro, peaking 150 Whakamaru

2025 Generic run of river 9 Hydro, run of river 50 Tarukenga

2025 Generic run of river 5 Hydro, run of river 50 Culverden

2025 Diesel fired OCGT 15 Peaker, diesel-fired OCGT 100 Whirinaki


50 Mt Roskill

2025 Cape Campbell Wind 150 Blenheim

2026 Generic run of river 8 Hydro, run of river 50 Wanganui

2026 Generic solar 4 Solar 50 Stoke

2026 Generic wind North Isthmus 1 Wind 200 Maungatapere


2027 Generic wave 2 Wave 38 Waimangaroa

2027 Kaiwera Downs Wind 240 North Makarewa

G.2 Scenario 2: South Island Wind

The key features of the South Island Wind scenario are:

Carbon prices and gas prices are both high. As a result, renewable energy production exceeds 85% of total generation (on average) from 2020 onwards.

By 2020, over 600 MW of new hydro and 600 MW of new wind generation have been added in the South Island. This is less than assumed in the 2010 Statement of Opportunities (and hence the last APR), but still a substantial amount.

There is also substantial development of wind generation in the lower North Island, with nearly 1,000 MW added by 2022.

Overall there is strong wind and hydro development in both islands. By 2027, wind capacity exceeds 3000 MW, and 1000 MW of new hydro has been constructed. Geothermal development is slower than in other scenarios, with capacity maxing out at 1,000 MW.

Baseload thermal generation is considerably reduced, with three out of four Huntly coal-fired units, Taranaki CC and Southdown decommissioned by 2027.

Over 1400 MW of thermal peakers are available by 2027. Interruptible load and price-responsive demand increase by 350 MW over the same period.



Projects and commission dates – South Island Wind scenario


Substation (approx)











2015 Hawea Control Gate Retrofit Hydro, peaking 17 Cromwell

2015 Mohikinui Hydro, run of river 85 Inangahua


160 Huntly


2015 Mt Cass Wind 50 Waipara

2015 Turitea Wind 180 Linton


2016 Stockton Hydro, run of river 30 Westport


2016 Taharoa Wind 54 Hangatiki

2012 2014 2016 2018 2020 2022 2024 2026 0

2000

4000

6000

8000

10000

12000

14000

Year

MW

Installed capacity by technology - SI wind (mds2)

Wind

Solar

Cogeneration, other


Interruptible load

Coal, IGCC w ith CCS

Hydro, schedulable

Hydro, run of river

Hydro, peaking

Geothermal





Coal






Substation (approx)



50 Takapuna


50 Mangere


2017 Project Hayes stage 1 Wind 150 Roxburgh

2018 Southdown Combined cycle gas turbine 0 (Decomm.) Southdown



50 Central Park




160 Southdown


100 Huntly


100 Stratford



2019 Project Hayes stage 2 Wind 160 Roxburgh


2020 Clutha River Hydro, peaking 200 Roxburgh



2020 Diesel fired OCGT 6 Peaker, diesel-fired OCGT 100 Otahuhu



50 Penrose

2020 Long Gully Wind 12.5 Central Park

2021 Taumatatotara Wind 44 Hangatiki


2021 Generic wind North Isthmus 1 Wind 200 Maungatapere

2022 Puketoi Wind 175 Linton

2022 Puketiro Wind 90 Pauatahanui

2023 Generic run of river 9 Hydro, run of river 50 Tarukenga

2023 Generic run of river 10 Hydro, run of river 50 Wairoa

2023 Generic wind Wellington Wind 80 Takapu Rd

2024 Biomass Cogen, Kawerau Cogeneration, biomass-fired 31 Kawerau

2024 Biomass Cogen, Central Cogeneration, biomass-fired 63 Tangiwai

2024 Generic run of river 8 Hydro, run of river 50 Wanganui

2025 Waikato upgrade Hydro, peaking 150 Whakamaru

2025 Hurleyville Wind 100 Hawera




2012 2014 2016 2018 2020 2022 2024 2026 0

2000

4000

6000

8000

10000

12000

Year

MW

Installed capacity by technology - Medium renewables (mds3)

Wind

Cogeneration, other


Interruptible load

Hydro, schedulable

Hydro, run of river

Hydro, peaking

Hydro, pumped storage

Geothermal





Coal




Substation (approx)


50 Mt Roskill

2027 Biomass Cogen, Whirinaki Cogeneration, biomass-fired 63 Whirinaki

2027 Generic run of river 2 Hydro, run of river 50 Inangahua


100 Otahuhu


50 Central Park

G.3 Scenario 3: Medium Renewables

The key features of the Medium Renewables scenario are:

Gas prices are lower than in the previous two scenarios, though the volume available is still limited. Carbon prices are moderate.

The NZAS aluminium smelter is progressively phased out between 2022 and 2027. No new generation build is required over the phase-out period.

Baseload thermal generation is considerably reduced, with two out of four Huntly coal-fired units, Taranaki CC and Southdown decommissioned. However, an efficient 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 little new hydro generation.

Over 1,400 MW of thermal peakers are available by 2022. The demand side contributes relatively little, with interruptible load and price-responsive demand increasing by just 150 MW over the same period.



Projects and commission dates – Medium Renewables scenario

Year Plant description Technology description

Capacity MW

Substation (approx)










2016 Mohikinui Hydro, run of river 85 Inangahua

2016 Maungaharuru Wind 94 Whirinaki



2017 Hawea Control Gate Retrofit Hydro, peaking 17 Cromwell


50 Takapuna


50 Bromley




2019 Southdown Combined cycle gas turbine

0 (Decomm.) Southdown

2019 Generic geo 3 Geothermal 100 Wairakei


2019 Diesel fired OCGT 16 Peaker, diesel-fired OCGT

40 New Plymouth

2019 Puketoi Wind 175 Linton

2020 Taranaki CC Combined cycle gas turbine

0 (Decomm.) Stratford


100 New Plymouth


160 Otahuhu


160 Stratford

2020 Turitea Wind 180 Linton


2021 Generic run of river 4 Hydro, run of river 50 Hokitika


100 Kaitemako


160 Southdown


160 Huntly

2022 Marsden Coal Coal 320 Marsden



G.4 Scenario 4: Coal

The key features of the Coal scenario are:

Gas prices are lower than in the Sustainable Path and South Island Wind scenarios, though the volume available is still limited. This is the scenario with the lowest carbon prices.

Most existing baseload thermal generation remains online. Taranaki CC is decommissioned, 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.

There is also some renewable development. Geothermal capacity climbs to 1,400 MW, and 250 MW of new hydro and 250 MW of wind are added.

The output of existing hydro generation is curtailed due to difficulties in obtaining water rights.

Over 1,000 MW of thermal peakers are available by 2027 (less than in the more renewable scenarios). Interruptible load and price-responsive demand increase by 400 MW over the same period.

Projects and commission dates – Coal scenario


Substation (approx)







2012 2014 2016 2018 2020 2022 2024 2026 0

2000

4000

6000

8000

10000

12000

Year

MW

Installed capacity by technology - Coal (mds4)

Wind

Cogeneration, other


Lignite

Interruptible load

Hydro, schedulable

Hydro, peaking

Geothermal





Coal






Substation (approx)



50 Takapuna



50 Mangere


50 Bromley


50 Central Park


50 Islington

2018 Kaiwera Downs Wind 240 North Makarewa








160 Stratford

2021 New IL 2 Interruptible load 50 Mt Roskill

2022 Generic coal 1 Glenbrook Coal 400 Glenbrook


160 Otahuhu


2025 Generic lignite 1 Southland Lignite 400 North Makarewa


50 Mt Roskill


160 Huntly

G.5 Scenario 5: High Gas Discovery

The key features of the High Gas Discovery scenario are:

Substantial volumes of natural gas are available at affordable prices. Carbon prices are moderate.

All four coal-fired Huntly units are decommissioned by 2020. However, existing gas-fired generators remain online.

Efficient new CCGTs are constructed - a 200 MW plant in Taranaki in 2015, a 240 MW plant in Northland in 2017, and 400 MW plants in Auckland in 2020 and 2025.

New gas-fired peakers are added, with thermal peaking capacity reaching 1,100 MW by 2027. There is also new gas-fired cogeneration.

There is also some renewable development. Geothermal capacity climbs to 1,200 MW, and 650 MW of new wind is added. There is little new hydro generation.



Interruptible load and price-responsive demand increase by 200 MW (rather less than in the 2010 SOO, and hence the last APR).

Projects and commission dates – High Gas Discovery scenario


Substation (approx)










2015 Todd CCGT Combined cycle gas turbine 200 Stratford



50 Takapuna


50 Bromley

2016 Taranaki Cogen Cogeneration, gas-fired 50 Stratford



2017 Rodney CCGT stage 1 Combined cycle gas turbine 240 Huapai


2012 2014 2016 2018 2020 2022 2024 2026 0

2000

4000

6000

8000

10000

12000

Year

MW

Installed capacity by technology - High gas discovery (mds5)

Wind

Cogeneration, other


Interruptible load

Hydro, schedulable

Hydro, run of river

Hydro, peaking

Geothermal





Coal





2012 2014 2016 2018 2020 2022 2024 2026

0

200

400

600

800

1000

1200

1400

1600

Year

MW

Installed capacity of coal and lignite

Sustainable path (mds1)

SI w ind (mds2)

Medium renew ables (mds3)

Coal (mds4)

High gas discovery (mds5)


Substation (approx)


2018 Diesel fired OCGT 19 Peaker, diesel-fired OCGT 40 Gracefield


160 Huntly


160 Stratford


50 Islington


2020 Generic gas 1 Auckland Combined cycle gas turbine 410 Otahuhu


2021 Diesel fired OCGT 13 Peaker, diesel-fired OCGT 40 Whirinaki




160 Southdown


2023 Generic wind Wellington Wind 80 Takapu Rd


2024 Slopedown Wind 150 Gore

2025 Otahuhu C Combined cycle gas turbine 407 Otahuhu


160 Otahuhu

G.6 Plots of installed capacity for major generation technologies



2012 2014 2016 2018 2020 2022 2024 2026

5200

5400

5600

5800

6000

6200

Year

MW

Installed capacity of hydro


SI w ind (mds2)


Coal (mds4)


2012 2014 2016 2018 2020 2022 2024 2026

500

1000

1500

2000

2500

Year

MW

Installed capacity of gas


SI w ind (mds2)


Coal (mds4)


2012 2014 2016 2018 2020 2022 2024 2026

700

800

900

1000

1100

1200

1300

1400

1500

1600

Year

MW

Installed capacity of geothermal


SI w ind (mds2)


Coal (mds4)




2012 2014 2016 2018 2020 2022 2024 2026 500

1000

1500

2000

2500

3000

Year

MW

Installed capacity of wind


SI w ind (mds2)


Coal (mds4)


2012 2014 2016 2018 2020 2022 2024 2026

100

200

300

400

500

600

Year

MW

Installed capacity of interruptible load and price-responsive load curtailment


SI w ind (mds2)


Coal (mds4)


2012 2014 2016 2018 2020 2022 2024 2026

400

600

800

1000

1200

1400

Year

MW

Installed capacity of thermal peakers


SI w ind (mds2)


Coal (mds4)


Appendix H: Project Naming


Appendix H Transpower Project Naming

Transpower assigns a unique project reference to each project. This is to assist internally and externally in ensuring unambiguous project references between Transpower and its customers, industry, the Electricity Authority and the wider New Zealand public.

All projects are named according to the following convention:

LocationIdentifier-AssetCategory-TypeOfWork-UniqueID

Location Asset Category Work Type Unique ID

Region Site Parent

AKLD

WAKT

BOPE

WGTN

CHCH

etc

Existing

Station

codes: +

GRD

PAO

PTR

or

Line code:

ADD_ISL

ARI_EDG

MTI_WKM

etc

NIGU

NAAN

SIGU

Asset

Categories:

POW_TFR

TRAN

REA_SUP

SUBEST

BUSC

BUS_PTN

C_BANKS

POW_TFR_DIS

POW_TFR_PTN

BUSZ_PTN

Work Types:

DEV

EHMT

REPL

Unique ID:

01

02

03

...

+++

or or

H.1 Location Identifier

The first block of letters is the location identifier, which can be one of three types:

region

site, or

major project parent.

The region/site codes are largely based on Transpower’s existing site/line specific abbreviations (e.g. OTA for Otahuhu). Where new sites are contemplated, a new abbreviation will be formed (e.g. GRD for Geraldine).

Unique codes of four characters will be made for regions or cities where a project is not sufficiently well defined in location to use a site/line abbreviation (for example, AKLD for Auckland, CHCH for Christchurch).

Unique four character codes will also be used for parent projects (e.g. large umbrella projects encompassing a number of individual projects). Examples used in the APR include:

Appendix H: Project Naming


NIGU – North Island Grid Upgrade

NAAN – North Auckland and Northland

HVDC – HVDC

UPNI – Upper North Island

H.2 Asset Category

Codes for the asset category are to be based on Transpower’s internal coding practices. These include:

C_BANKS – Capacitor banks

SYN_COND – Synchronous Condenser

TRAN – Transmission

REA_PWRC – Reactive Power Controller

REA_PWRS – Reactive Power Support

BUSG – Bussing

POW_TFR – Power Transformer

SUBEST – Substation Establishment

H.3 Work Type

Codes for the work type also reflect Transpower’s internal coding. Examples include:

DEV – Development

EHMT – Enhancement

REPL – Replacement

H.4 Unique ID

Finally, a unique numeric identifier is added at the end of the code sequence to distinguish projects for which all other parts of the name are identical. This can occur in particular over a ten year forecast period.

Appendix I: Glossary


Appendix I Glossary

Term Description

After Diversity Maximum Demand

The peak consumption of energy (averaged over a half-hour period and expressed in Watts) that incorporates the non-simultaneous nature of each point of supply’s load peak time.

automatic under frequency load shedding

The automatic disconnection of customers for severe or prolonged under frequency. Implemented on relays installed within the distribution network or at Transpower’s substations, customers are tripped in two, nominally, 20% groups.

availability The number of hours per year the network or part thereof is in service. Unavailability is the opposite of availability (for example, the hours per year the network or part thereof is not providing service).

bay (of a station) That part of a substation or power station where a given circuit’s switchgear is located. According to the type of circuit, a substation or power station may include: feeder bays, transformer bays, bus coupler bays, etc.

breaker-and-a-half station

A double-bus substation where, for two circuits, three circuit-breakers are connected in series between the two buses, the circuits being connected on each side of the central circuit-breaker.

bus The common primary conductor of power from a power source to two or more separate circuits.

bus coupler circuit-breaker

A circuit-breaker located between two busbars that can both be accessed by the same external circuit. The bus coupler circuit-breaker permits the busbars to be connected together or separated under load or fault conditions.

bus section Part of a bus that can be isolated from another part of the same bus.

cable One or more insulated conductors forming a transmission circuit above or below ground.

capacitor bank A number of capacitors connected together in series and/or parallel to form the requisite capacitance and voltage rating for reactive compensation and harmonic filters on the HVAC and HVDC power systems.

charging current (line) The current taken by a transmission circuit to energise its conductors due to the capacitive effect of the circuit.

circuit (transmission) (cct)

A set of conductors (normally three) plus associated hardware and insulation on a transmission line, which together form a single electrical connection between two or more stations and which, when faulted, is removed automatically from the system (by circuit-breakers) as a single entity.

circuit-breaker A switching device, capable of making, carrying and breaking currents under normal circuit conditions and also making, carrying for a specified time and breaking currents under specified abnormal conditions, such as those of short circuit.

co-generation The use of high-pressure steam from a turbo-generator set for an industrial process. The production of electricity is usually secondary to the requirements of the industrial process.

commissioned The operational state of equipment that has undergone the commissioning process and is brought under the operational control of a service centre/controller.

committed projects

Refers to actual proposed projects that satisfy a number of criteria indicating that they are extremely likely to proceed in the near future. For example:

land has been acquired for construction of the project

planning consents, construction approvals and licences have been obtained

construction has begun, or a firm commencement date has been set

contracts for supply and construction have been finalised, and

financing arrangements are largely complete.

constraint A local limitation in the transmission capacity of the grid required to maintain grid security or power quality.

contingency The uncertainty of an event occurring, and the planning to cover for this. For example, a single contingency could be:

a. in relation to transmission, the unplanned tripping of a single item of equipment, or

b. in relation to a fall in frequency, the loss of the largest single block of generation in service, or the loss of one HVDC pole.

contingent event Those events for which, in the reasonable opinion of the system operator, resources can be economically provided to maintain the security of the grid and power quality without the



Term Description

shedding of demand.

continuous rating The maximum rating to which equipment can be operated continuously.

decommissioned The status of equipment which is permanently disconnected from the power system, made permanently inoperable, and free of any operational identification.

demand A measure of the rate of consumption of electrical energy.

demand-side management

Initiatives or mechanisms used to control electricity demand. Examples include ripple controls on water heating or contracted shedding of load (demand).

disconnector A switch that, when in the open position, provides an isolating distance in accordance with specified requirements.

dispatch The process of :

a. pre-dispatch scheduling to allocate active and reactive power generation, including additional ancillary services and reserve, to match expected demand, within the limitations of the grid and equipment

b. rescheduling to meet forecast demand, and

c. issuing instructions based on the schedule and the real-time conditions to manage resources to meet the actual demand.

distribution (of electricity)

The transfer of electricity between the transmission network and end users through a local network.

distribution line An electric line that is part of a local network.

double circuit line A transmission line carrying two circuits.

duplicate protection A protection scheme for a plant item such that any fault on the plant item can be cleared by two independent sets of relays, either of which is able to operate correctly even if the other fails completely.

electricity distributor An asset owner whose assets are predominantly for the distribution of electricity to customers.

Electricity Governance Regulations

The Electricity Governance Regulations 2003 and all amendments and codes of practice following therefrom.

Electricity Governance Rules

The rules made pursuant to the Electricity Governance Regulations 2003.

embedded generators Embedded generators are smaller power plants connected to a regional electricity line business’s distribution network (as opposed to the high voltage transmission network).

end user An entity connected to the power system for the primary purpose of consuming electricity.

event 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 environment

c. a disturbance to the power system

d. a significant change in the state of the grid

e. equipment defects, and

f. fire or intruder alarm operation.

feeder A circuit that provides a direct connection to a customer.

firm capacity Power capacity intended to be available at all times during the period covered by a guaranteed commitment to deliver, even under adverse conditions.

forced outage The automatic or urgent removal from service of an item of equipment.

frequency (power) The rate of cyclic change in value of current and voltage, quantified by the international standard term ’Hertz‘ (Hz).

frequency excursion A variation of the power system frequency above 50.25 Hz or below 49.75 Hz.

gas turbine (GT) A heat engine that uses the energy of expanding gases passing through a multi-stage turbine to create rotational power.

generating set 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 is taken to include the limitations of the energy source, turbine, generator, cable, set transformer and switchgear. [GOSP glossary - IEC 50 (602-02-01)]

generation The electrical energy produced by a generator, a generating station or within a power system as a whole.



Term Description

The process of producing electricity.

generator A person who owns and/or manages one or more generating sets that are physically connected to the grid assets or to a network or to other assets connected to the grid assets.

grid That part of the New Zealand electricity transmission system, the operation of which is undertaken by the grid operator.

grid asset owner Transpower New Zealand Limited.

grid assets At any time, the plant, transmission lines and other facilities, owned or managed by the grid asset owner, and which are used to interconnect all the points of connection for connected parties.

grid exit point (GXP) A point of connection where electricity may flow out of the grid.

grid injection point A point of connection where electricity may flow into the grid.

HVAC High voltage alternating current.

HVDC High voltage direct current.

in service The state of equipment that is connected to a source of energy or may be connected to a source of energy by an operating action.

instantaneous load The maximum instantaneous current drawn. It consists of continuous, non-continuous and momentary currents.

intertrip A protection signalling system whereby a signal initiated at one station trips a circuit-breaker at another station.

islanded operation The condition that arises when a section of the power system is disconnected from and operating independently of the remainder of the power system.

life expectancy The date where replacement/major refurbishment is necessary.

line [overhead] A series of structures carrying overhead one or more transmission circuits.

load control 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), and

manual load shedding (see manual load shedding).

load shedding The forced disconnection of load, in stages. This is either manual (see load control) or automatic (see MW reserve [of a power system]).

main protection Protection equipment (or a system) expected to have priority in initiating either a fault clearance or an action to terminate an abnormal condition in the power system.

manual load shedding The forced disconnection of load by an operator/controller.

maximum continuous rating (MCR)

The value assigned to an equipment parameter by the manufacturer, and at which the equipment may be operated for an unlimited period without damage.

maximum demand The peak consumption of energy (averaged over a half-hour period and expressed in watts) recorded during a given time, for example, a day, week, or year.

MegaVoltAmpere (MVA)

1000 kVA. The flow of active power is measured in megaWatts (MW). When compounded with the flow of reactive power, which is measured in Mvar, the resultant is measured in MegaVoltAmperes (MVA).

n-1, “n” 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 single credible contingency with all the assets that can reasonably be expected in service. The single credible contingencies that are defined in the Rules are:

a single transmission circuit interruption

the failure or removal from operational service of a single generating unit

an HVDC link single pole interruption

the failure or removal from service of a single bus section

a single interconnecting transformer interruption, and

the 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 smaller supply areas, where just one transmission circuit or supply transformer provides supply.

nominal rating The design rating of the equipment or transmission circuit. For equipment, this is often referred to as the 'nameplate rating'.



Term Description

nominal system frequency

50 Hertz.

non-continuous load A load that is energised for a portion of the duty cycle greater than one minute. It may be for a set period, and removal may be automatic or by operator action or it may continue to the end of the duty cycle.

normal system conditions

The state of the power system when it is operating in accordance with statutory requirements as regards quality of supply and within basic design and operational parameters.

on-load tap-changer (OLTC)

Equipment fitted to a power transformer by which the voltage ratio between the windings can be varied while the transformer is on-load.

outage 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.

overhead line A transmission line.

overload A load greater than the maximum continuous rating.

peak demand See maximum demand.

peak load The maximum peak load (in amps) that can be expected to be carried within a twelve month period on the circuit or by the equipment/component.

planned outage A deliberate outage scheduled for maintenance purposes.

power factor The ratio between active power (expressed in watts, W) and true power (expressed in volt-amperes, VA). Can vary between 1 and 0. A load with a low power factor uses more reactive current than a load with a high power factor for the same amount of useful power transferred.

power flow analysis Simulation of the actual power system using computer models, so as to analyse the effects of changes to inputs (like demand, supply, and asset ratings), and identify constraints or other issues that might affect security of supply to a region.

power system stability

The capability of a power system to regain a steady state, characterised by the synchronous operation of the generators after a disturbance due, for example, to variation of power or impedance.

power transformer A transformer that primarily changes voltage and current for the efficient conveyance of electricity over the circuits connected to it.

protection The equipment provided for detecting abnormal conditions in a power system and then initiating fault clearance or actuating signals or indications.

reactive power Energy that flows in the power system between alternators, capacitors, SVCs, etc., and inductive and capacitive equipment such as transmission lines and low power factor loads. It is the product of the voltage and out-of-phase components of the alternating current and is measured in vars.

relay A device designed to produce predetermined changes in one or more electrical output circuits, when certain conditions are fulfilled in the electrical input circuits controlling the device.

reliability The failure rate. For example, the number of failures per year based on experience over a long time period, say 10 years or more.

resource consent A consent to use land, air or water granted by the local government under the Resource Management Act. The consent usually imposes limits on that use.

return period The statistical return period of a weather-related event, load or load effect.

runback scheme An automatic limit on generation or HVDC transfer, which typically would be enabled when there is loss of a particular circuit, transformer, signalling or control system.

security A term used to describe the ability or capacity of a network to provide service after one or more 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 in the network means that ‘m’ component failures can be tolerated without loss of service.

short circuit rating The three second fault rating of equipment.

short term rating The maximum rating to which equipment can be operated for a specified duration.

single-circuit line A transmission line carrying one circuit.

spur circuit A circuit connected to the transmission system at only one point.

stability limit The critical value of a given system state variable that cannot be exceeded without endangering power system stability.



Term Description

For a power system without a fault, this concept is related to the steady state stability of the system.

steady state stability A power system stability in which disturbances have only small rates of change and small relative magnitudes.

substation A building, structure or enclosure incorporating equipment used principally for the control of the transmission or distribution of electricity.

switchgear A collective term for switches of all types and their associated equipment, including circuit-breakers, disconnectors, and earthing switches.

switchgear group A circuit-breaker and related disconnectors. The relationship is determined by switchgear numbering.

switching station A station existing solely for the purpose of transmission rather than supply.

synchronous condenser

A synchronous machine running without mechanical load and supplying or absorbing reactive power to regulate local voltage.

system frequency 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.

system normal The power system is operating in the normal state when:

generation meets the demand at 50Hz (±0.2 Hz)

voltage requirements are met

grid equipment is operated within design ratings, and

reserve margins and the power system configuration provide an adequate level of operational security.

system operator The person responsible from time to time for the operation of the grid system. The system operator is Transpower New Zealand Limited.

tee (or T) point The point at which a branch transmission circuit is solidly and permanently connected to a main circuit, usually without switchgear. See also tee-off.

tee-off A branch transmission circuit joining a main circuit and that is protected as part of the main circuit.

thermal constraints/limits/ capacities

Refers to the temperature ratings of the assets (lines, generators, transformers) connected to the power system, beyond which the assets cannot securely be operated.

thermal upgrade The increase in temperature ratings of assets to provide more capacity.

transformer A static electric device consisting of a winding or two or more coupled windings which transfer power by electromagnetic induction between circuits of the same frequency, usually with changed values of voltage and current.

transient (in)stability Refers to the response of the power system when it experiences a large disturbance like a line fault or outage of a generator.

transmission The conveying of bulk electricity from power stations to points of supply (compared with distribution).

transmission circuit An electrical circuit the primary purpose of which is the transmission of electricity from one geographical location to another.

transmission line A series of structures carrying one or more transmission circuits overhead.

transmission system That part of the power system primarily intended for the conveyance of bulk electricity.

voltage The nominal potential difference between conductors or the nominal potential difference between a conductor and earth, whichever is applicable.

voltage collapse A sudden and large decrease in the voltage of the electrical system.

voltage (in)stability Refers to the power system’s ability to maintain a satisfactory voltage at all buses for any disturbance, such as a variation in load or an outage of plant.

Appendix J: Grid Exit and Injection Points


Appendix J Grid Exit and Injection Points

Table J-1: North Island Grid Exit and Injection Points

North Island

North Isthmus Auckland Waikato Bay of Plenty Central North Island Taranaki Hawkes Bay Wellington

Albany GXP Bombay GXP Cambridge GXP Edgecumbe GXP Bunnythorpe GXP Brunswick GXP Fernhill GXP Central Park GXP

Bream Bay GXP Glenbrook GXP Hamilton GXP Kaitimako GXP Dannevirke GXP Carrington St GXP Gisborne GXP Gracefield GXP

Dargaville GXP Hobson Street GXP Hangatiki GXP Kinleith GXP Linton GXP Hawera GXP Redclyffe GXP Greytown GXP

Henderson GXP Mangere GXP Hinuera GXP Lichfield GXP Mangamaire GXP Huirangi GXP Tokomaru Bay

GXP Haywards GXP

Hepburn Road GXP Meremere GXP Kopu GXP Mt Maunganui GXP Marton GXP Motunui GXP Wairoa GXP Kaiwharawhara GXP

Huapai GXP Mount Roskill GXP Piako GXP Owhata GXP Mataroa GXP Opunake GXP Whakatu GXP Masterton GXP

Kensington GXP Pakuranga GXP Putaruru GXP Rotorua GXP National Park GXP Taumarunui GXP Tuai GIP Melling GXP

Maungatapere GXP Penrose GXP Te Awamutu GXP Tarukenga GXP Ohakune GXP Wanganui GXP Whirinaki GIP Paraparaumu GXP

Maungaturoto GXP Takanini GXP Te Kowhai GXP Tauranga GXP Ongarue GXP Waverley GXP Pauatahanui GXP

Silverdale GXP Wiri GXP Waihou GXP Te Kaha GXP Tangiwai GXP Kapuni GIP Takapu Rd GXP

Wellsford GXP Otahuhu GIP/ GXP

Waikino GXP Te Matai GXP Waipawa GXP New Plymouth

GIP Upper Hutt GXP

Marsden GIP Southdown GIP Huntly GIP/ GXP

Waiotahi GXP Woodville GXP/ GIP

Stratford GIP Wilton GXP

Drury SWI Arapuni GIP Kawerau GIP/ GXP

Aratiatia GIP West Wind GIP

Atiamuri GIP Matahina GIP Mangahao GIP

Karapiro GIP Nga Awa Purua

GIP

Maraetai GIP Ohaaki GIP

Mokai GIP Poihipi GIP

Ohakuri GIP Rangipo GIP



North Island

North Isthmus Auckland Waikato Bay of Plenty Central North Island Taranaki Hawkes Bay Wellington

Waipapa GIP Tararua GIP

Whakamaru GIP Tokaanu GIP

Ohinewai SWI Wairakei GIP

Table J-2: South Island Grid Exit and Injection Points

South Island

Nelson/Marlborough West Coast Canterbury South Canterbury Otago/Southland

Argyle GXP Arthurs Pass GXP Addington GXP Albury GXP Balclutha GXP

Blenheim GXP Atarau GXP Ashburton GXP Bells Pond GXP Brydone GXP

Motueka GXP Castle Hill GXP Ashley GXP Black Point GXP Cromwell GXP

Motupipi GXP Dobson GXP Bromley GXP Oamaru GXP Edendale GXP

Stoke GXP Greymouth GXP Culverden GXP Studholme GXP Frankton GXP

Cobb GIP Hokitika GXP Hororata GXP Temuka GXP Gore GXP

Upper Takaka SWI Kikiwa GXP Islington GXP Timaru GXP Halfway Bush GXP

Murchison GXP Kaiapoi GXP Twizel GXP Invercargill GXP

Otira GXP Middleton GXP Aviemore GIP Naseby GXP

Reefton GXP Southbrook GXP Benmore GIP North Makarewa

GXP

Orowaiti (Robertson Rd)

GXP Springston GXP Ohau A GIP Palmerston GXP

Westport GXP Waipara GXP Ohau B GIP South Dunedin

GXP

Kumara GIP Coleridge GIP Ohau C GIP Tiwai GXP

Inangahua SWI Tekapo A GIP Berwick GIP



South Island

Nelson/Marlborough West Coast Canterbury South Canterbury Otago/Southland

Waimangaroa SWI Tekapo B GIP Clyde GIP

Waitaki GIP Manapouri GIP

Livingstone SWI Roxburgh GIP

Three Mile Hill

SWI

GXP – Grid Exit Point

GIP – Grid Injection Point

SWI – Switching Station

Annual Planning Report 2012 Complete

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