Transmission and Distribution planning in Australia

Prepared by

2007

Transmission and Distribution Annual Planning Report

safe reliable efficient

2007 Transmission and Distribution Annual Planning Report2

Disclaimer

This document is published by Western Power as an information service. It does not purport to contain all the information that may be necessary to enable a person to assess whether to pursue a particular investment. It contains only general information and should not be relied upon as a substitute for independent research and professional advice.

Western Power makes no representations or warranty as to the accuracy, reliability, completeness or suitability for particular purposes of the information in this document.

Copyright Notice

All rights reserved. This entire publication is subject to the laws of copyright and intellectual property rights. This publication may not be resold or reproduced without the prior permission of Western Power, except as permitted under the Copyright Act 1968.

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This year we have written a more comprehensive Annual Planning Report, which we trust gives interested people greater insight to our planning process and our goals for the network.

In simple terms, our objective is to serve WA people and industry by planning prudent investment in the network to meet their needs for safe, reliable electricity and secure, timely connection.

As I hope is clear throughout the report, we would value your feedback about the amount and form of detail provided, about specific projects, and about any additional information you believe we need to take into account.

Mark de LaeterGeneral ManagerAsset Management DivisionWestern Power

Preface

Welcome to the 2007 Transmission and Distribution Annual Planning Report. This report outlines Western Power’s network development plans, which have been prepared in response to forecast electricity demand growth from existing and prospective customers, including expected generation requirements.

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Disclaimer 2

Preface 3

Executive summary 7

1 Introduction 111.1 Purpose of this document 111.2 Interaction with the Statement of Opportunities report 121.3 Role of Western Power 12

2 Network development planning process 152.1 Network development analysis 162.2 Customer expectations 172.3 Transmission network planning standards 17

2.3.1 The bulk transmission network 172.3.2 The sub-transmission network 182.3.3 Radial networks 182.3.4 Substations 18

2.4 Distribution network planning standards 192.4.1 CBD 192.4.2 Metropolitan 192.4.3 Rural 20

2.5 Quality of supply requirements 20

3 Network planning assumptions 213.1 Developing and applying electricity demand forecasts 21

3.1.1 Typical drivers of load growth 213.1.2 Western Power’s load forecasting methodology 213.1.3 Managing weather sensitivity risks in demand forecasting 223.1.4 Review of load forecasting practice 22

3.2 Location of new generation 233.2.1 Southern generation development scenario 243.2.2 Northern generation development scenario 253.2.3 Metropolitan generation development scenario 263.2.4 Eastern generation development scenario 27

4 Description of load areas 294.1.1 Bulk transmission network 314.1.2 Northern Terminal 314.1.3 Muja 324.1.4 Kwinana 324.1.5 Cannington 324.1.6 Bunbury 324.1.7 Western Terminal 334.1.8 East Perth 334.1.9 Southern Terminal 344.1.10 South Fremantle 344.1.11 East Country 344.1.12 Eastern Goldfields 344.1.13 North Country 354.1.14 Guildford 354.1.15 Load area constraints 36

Contents

2007 Transmission and Distribution Annual Planning Report�

Contents (cont.)

5 Projects (Approved, committed or commissioned) 375.1 Committed transmission projects 37

5.1.1 Bulk transmission 375.1.2 Bunbury 405.1.3 East Perth CBD 425.1.4 Cannington Terminal 435.1.5 Eastern Goldfields 445.1.6 Kwinana 455.1.7 Muja 465.1.8 North Country 475.1.9 Northern Terminal 475.1.10 South Fremantle 505.1.11 Southern Terminal 505.1.12 Western Terminal 535.1.13 Guildford Terminal 535.1.14 East Country 54

5.2 Committed distribution projects 545.2.1 State Underground Power Program (SUPP) 555.2.2 Reliability Improvement Program 56

5.3 Commissioned projects 61

6 Network development options 63

7 Other planning issues 697.1 Sustainability 69

7.1.1 Planning checklist 697.1.2 Environmental management 697.1.3 Stakeholder engagement 707.1.4 Environmental initiatives 70

7.2 Communications network 727.2.1 Western Power communication technologies 727.2.2 Protection 727.2.3 SCADA (Supervisory Control and Data Acquisition) 727.2.4 Operations 727.2.5 Choice of bearer 737.2.6 Communication projects 75

8 Abbreviations 81

9 Appendix A – Introduction to network issues 839.1.1 Planning and operating electricity networks 839.1.2 Faults on electricity networks 849.1.3 Meshed and radial networks 849.1.4 Peak demand, weather and diversity 85

10 Appendix B – Substation load forecasts 8710.1.1 Load forecasts for connection points 87

11 Appendix C – Estimated maximum short circuit levels 9711.1.1 Maximum short circuit levels 97

12 Appendix D – Proposed transmission capacity expansion projects 105

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Executive summary

Network development planning process

Western Power’s network development plans are based on regional forecasts of peak demand, assumptions about generation developments and a detailed understanding of the capacity of the existing network. These assumptions are used in sophisticated network analysis that ensures each network element satisfies a number of planning and technical criteria.

For convenience, the network is considered to be divided into the bulk transmission network and a number of load areas. As a minimum, each load area is studied in detail every two years to ensure that it will continue to meet the relevant planning and technical criteria. Where there have been significant changes in a load area (perhaps due to significant load growth or a new generator connecting), it will be re-assessed as a matter of priority.

The network planning process is a continuous one. As such, this Annual Planning Report is a snapshot as to the constraints and the network development options as they are currently understood.

Network planning assumptions

Three levels of demand forecast are required for network planning purposes:

• a demand forecast for the bulk transmission system, which is broadly based on the demand forecasts reported in the 2006 Statement of Opportunities Report (SOO), and which allows peak network flows across the bulk transmission network to be modelled;

• demand forecasts for each substation, which are developed by extrapolating previous system peaks for each substation, and which allow peak power flows across each substation element to be modelled; and

• demand forecasts for each load area, which allow peak power flows across the network elements in each load area to be modelled. These forecasts are developed using the bulk transmission forecasts and the individual substation forecasts.

In each case, the focus is on understanding the most onerous conditions that will affect each network element.

The purpose of this document is to provide existing and prospective network users and other interested parties information on major planned developments on Western Power’s South-West Interconnected System. It also provides some background on Western Power’s network development planning process.

2007 Transmission and Distribution Annual Planning Report�

For example, the bulk transmission network’s most onerous power flows are usually at the time of system peak. An individual substation may have its peak load at a different time to the remainder of the network. Simply using a load forecast for the time of system peak would potentially understate the duty on each substation element, and lead to inadequate development plans. The most onerous operating condition for each load area is derived from a combination of the demand at the time of system peak and local demand peaks, depending on the characteristics of that load area.

The peak demand for electricity is highly sensitive to temperature. The forecasts used for network planning purposes are based on a 10 per cent Probability of Exceedance: that is, the probability that Western Power’s peak demand forecast is likely to be exceeded one year in every ten.

The timing, location and type of generation and major load projects are the other main planning assumptions. The 2006 SOO identifies ‘committed’ and ‘announced’ projects. Committed projects are included in the base assumptions used for the system analysis

underpinning this Annual Planning Report. Scenario analysis has been performed based on the announced generation projects to assess the impact on the network.

The need for network development is highly sensitive to the location and type of generation development. Western Power is aware of generation projects that cannot be reflected in this public document. For reasons of commercial confidentiality, future development plans may be materially different from those published here.

Where prudent to do so, Western Power will seek to anticipate generation location decisions, and commence investment to ensure that the network can respond to market needs in a timely fashion. This investment will be subject to, among other things, the regulatory regime, including the access code and capital contributions policy.

Network constraints

Over the ten years considered by this report, a number of network constraints have been identified based on network planning assumptions. These are summarised in Table 1 below:

Table 1. Summary of network constraints.

Load area Immediate network constraints1

Bulk transmission Largely driven by generation location decisions

Northern Terminal Thermal capacity of transmission lines and substation capacity shortfalls

Muja Voltage constraints on long lines and distribution network limitations

Kwinana Thermal and voltage constraints on transmission lines and substation capacity shortfalls

Cannington Substation capacity shortfalls

Bunbury Thermal and voltage constraints on transmission lines and substation capacity shortfalls

Western Terminal Substation capacity shortfalls

East Perth Thermal capacity of transmission lines and substation capacity shortfalls

Southern Terminal Substation capacity shortfalls

South Fremantle Thermal capacity of transmission lines and substation capacity shortfalls

East Country Voltage constraints on transmission lines and substation capacity shortfalls

Eastern Goldfields Voltage and stability constraints on transmission lines – No further generation is possible in this region

North Country Highly sensitive to connection of generation and/or loads – No further generation is possible in this region

Guildford Terminal Thermal line constraints

1 Load areas can exhibit all of these types of constraint – this table highlights the most immediate concerns.

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Depending on the nature of the network constraints, different solutions may be available. In some cases, it may be possible to avoid network augmentation if demand side or generation solutions are brought forward in the right locations.

Approved or committed projects

In light of the most pressing constraints identified in Table 1, Western Power is implementing the ‘committed’ projects to manage these network constraints. A brief discussion of Western Power’s major committed projects is detailed in Chapter 5. Projects are deemed to be committed when, among other things, they have achieved Western Power’s internal Business Case approval. While these projects are committed, they may still change in timing, scope and cost prior to commencement as a consequence of revised forecasts and other risk factors.

Network development options

Where constraints are identified for later years, network development options have been identified. The term ‘network development options’ is used deliberately. These options represent Western Power’s preferred development approach, given available information at the time of consideration. Demand and generation assumptions may change considerably before any commitment to the project is made. Furthermore, these options have not yet been subject to a detailed engineering review, which could change the preferred option. Finally, there may well be demand side or generation options that would delay, advance, change or remove the need for these projects. Indeed, the intention of publishing this information is to provide sufficient information for project developers to bring forward proposals in this regard. A brief discussion of Western Power’s major network development options is detailed in Chapter 6.

Sustainability

Western Power’s Environmental and Land Management Services (ELMS) team aims to provide an ethical and sustainable works program. We have implemented initiatives such as the Environmentally Sensitive Area Program and the Carbon Neutral Program that focuses on sustainability and protection of the environment.

Communications network

Western Power is committed to providing a robust, flexible communications network. The recently introduced regulatory and electricity market framework places higher reliance on available, accurate and timely data. Western Power has correspondingly improved its design criteria to ensure:

• high circuit availability;• provision for redundant paths; • a fibre optic cabling based solution as the first

preference; and • a suitable environment for communications

equipment.

Invitation to provide feedback

Western Power would welcome feedback on this Transmission and Distribution Annual Planning Report.

Comments on this document should be sent to:

Manager Network Planning & DevelopmentWestern Power CorporationGPO Box L921, Perth WA 6842Telephone: (08) 9326 6293Facsimile: (08) 92185167

Western Power would particularly like to hear from parties who are considering investments that, based on the information provided here, would appear to either:

• delay requirements for network development options; or

• accelerate requirements for network development options.

Relevant information will be incorporated in the Western Power‘s planning process and reflected in any updates to the Committed Projects and in future editions of the Annual Planning Report.

1 Introduction

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The report’s structure is as follows:

• Chapter 2 describes Western Power’s planning process and standards;

• Chapter 3 explains the key assumptions (namely demand and generation forecasts) that underpin the network development plans reproduced here;

• Chapter 4 provides a description of the load areas within the Western Power network;

• Chapter 5 sets out the major committed projects intended to address the most pressing constraints;

• Chapter 6 describes future development options available to resolve constraints in later years, but, which are yet to be approved;

• Chapter 7 describes other network issues relating to sustainability and communications;

• Appendix A provides a short introduction to network planning issues;

• Appendix B details substation load forecasts; and

• Appendix C details maximum three phase and single phase to ground short circuit levels.

The remainder of this introduction describes the purpose of this document more fully, its interaction with the Statement of Opportunities Report and an overview of the role of Western Power.

1.1 Purpose of this document

The purpose of this document is to provide existing and prospective network users and other interested parties information on planned developments on Western Power’s South-West Interconnected System (SWIS). It also provides some background on Western Power’s planning process.

Any existing or prospective user may also request a corporation to provide a report and forecast of electricity distribution capacity of the electricity distribution system operated by the corporation as applicable to that user’s particular requirements.

The purpose of this document is to:

• identify constraints on the transmission network likely to emerge in the next ten years;

• provide advance information on the nature and location of network constraints. This information should allow other parties to formulate and propose options to relieve the constraints. These options may include local generation, Demand Side Management (DSM) or other economic options;

• discuss options for relieving each constraint including network and other options; and

• provide further details on the load forecast data used as the basis for this analysis.

Western Power publishes this document on an annual basis. The future versions will reflect the latest available (commercially non-sensitive) information, including feedback received on the previous edition.

The 2007 Transmission and Distribution Annual Planning Report (APR) describes Western Power’s major network development plans from 200� to 201�.


1.2 Interaction with the Statement of Opportunities report

This report complements the role of the 2006 Statement of Opportunities report. While the Statement of Opportunities focuses on the overall adequacy of generation capacity, the focus of the APR is on the adequacy and development of the network components of the SWIS.

Where applicable, the generation and demand forecast information used in the preparation of this APR has been largely based on the 2006 Statement of Opportunities. Given the inherent complexity of the network planning process, it is necessary to allow sufficient time for assimilating relevant new or revised information in the Statement of Opportunities to produce network development outcomes that reflect any such information. As a consequence, publication of the APR follows the Statement of Opportunities.

Network planning is based on the predicted load growth throughout the South-West Interconnected System. The Independent Market Operator (IMO) publishes a forecast of maximum demand at 10 per cent Probability of Exceedence (PoE), 50 per cent PoE and 90 per cent PoE. This forecasted overall load growth is shown in the graph below:

1.3 Role of Western Power

The Electricity Networks Corporation trades as Western Power.

Western Power is responsible for the safe, reliable and efficient distribution and transmission of electricity in the SWIS, which spans from Albany to Kalbarri and across to Kalgoorlie.

Western Power connects electricity to homes and businesses, and is responsible for maintaining and upgrading the electricity network.

Until recently, Western Power Corporation was an integrated energy company, which owned and operated generation, transmission and distribution infrastructure supplying electricity to more than 875,000 customers in Western Australia.

On 1 April 2006, Western Power Corporation was restructured into four new Government-owned corporations:

• Verve Energy, a generation corporation, responsible for power generation in the SWIS;

• Synergy, a retail corporation responsible for the sale of electricity in the SWIS;

Figure 1.1 SWIS load forecasts (based on the 2006 Statement of Opportunities report).

2000

2500

3000

3500

4000

4500

5000

2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016

MW

IMO History 10% PoE 50% PoE 90% PoE

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• Horizon Power, a regional power corporation responsible for electricity in all areas outside of the SWIS; and

• The new Western Power, a networks corporation responsible for the transport of electricity within the SWIS.

The new Western Power owns, operates and maintains transmission and distribution assets in the SWIS. The SWIS contains more than 140 major substations, 6,000 km of transmission lines (operating at voltages of 66 kV and greater) and more than 64,000 km of high voltage distribution lines (operating at 33 kV and lower).

Western Power’s operations are guided by regulations, codes and legislation that have been developed by various regulatory bodies and the State Government, including the Economic Regulation Authority (ERA), the Office of Energy (OOE), EnergySafety (part of the Department of Consumer Protection), and other miscellaneous bodies such as the Environmental Protection Authority and WorkSafe. These regulations cover almost all aspects of our operations, from our performance targets and return on assets, through to the proper disposal of waste and the safety of employees and the public.

The Network Access Code 2004 establishes a framework for third party access to electricity transmission and distribution networks. This code promotes the economically efficient investment in, and operation of networks and services in Western Australia to promote competition in markets upstream and downstream of the networks.

The introduction of a new economic regulatory regime represents the single biggest shift in the business environment for Western Power. In accordance with the Code, Western Power has submitted to the ERA a proposed access arrangement which describes the terms and conditions on which users (typically retailers and generators) can obtain access to the SWIS.

Once approved by the ERA, in conjunction with the Code, it will provide a solid regulatory framework for the Western Power business. The final ruling will represent the approved network tariffs and resultant revenue projections, service standards and levels of capital and operating investment to meet the prescribed standards over the next three years.

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As a prudent commercial organisation, Western Power applies risk management principles when determining its network development options. Applying agreed network investment criteria, Western Power’s planning process is focussed on balancing network costs against the impact of unreliable supply on its customers.

Those planning principles are applied within the planning and development framework, illustrated in Figure 2.1. The Network Investment Strategy takes into account the following issues:

• Planning criteria: Following consultation, Western Power has established transmission and distribution planning criteria under the relevant regulations that, broadly, describe the design requirements for the network under various scenarios.

• Technical code: Following extensive consultation, Western Power has established technical codes for transmission and distribution that, among other things, set performance standards for the network and

technical requirements for plant connected to the network.

• Load and generation forecasts: Western Power uses a rigorous process to develop detailed forecasts of load and generation across its networks. This process includes obtaining independent expert advice on key planning parameters, such as projections of State economic growth. Western Power also makes prudent assumptions about the development of generation projects. This approach is described further in chapters 2 and 3.

• Asset management plans: Among other things, the asset management plans are based on condition assessment of the elements comprising the network to ensure that it will continue to provide reliable service. Condition assessments drive the asset replacement component of the Network Investment Strategy.

2 Network development planning process

This chapter provides an overview of the network development planning process, our understanding of customer expectations, the planning criteria used in developing the network and other technical requirements.

Figure 2.1 Overview of network planning process.

Optimised, prioritisedworks program

Project approvals,contracts, funding

IMPLEMENTATION

Development options,consultation & APR forum

Customer, stakeholder & community expectations

Demand & generation requirements

Sustainability & technology developments

Network performance &condition (Reliability, Quality, Safety)

Load & generationforecasts

Technical code

Technology plan

Planning criteria

Networkasset missions

& plans

Embeddedgeneration

opportunities

Demand sidemanagementopportunities

Network investmentstrategy

WESTERN POWER’SCUSTOMER VISION

Regulatoryframework & codes

Regulatory submission Funding submissionto government

2007 Transmission and Distribution Annual Planning Report1�

• Western Power’s commercial objectives: Western Power’s strategy is developed in light of the various drivers illustrated in figure 2.1, and includes the normal commercial objectives of any business, as required for Western Power under the Electricity Corporation Act 1994. In addition, the new regulatory environment means Western Power’s capital expenditures now need to satisfy the stringent requirements of the new Access Code, including approval of investment plans by the ERA. It also has to demonstrate that costs of investments are efficient under the New Facilities Investment test, and that possible alternative options to major investments have been evaluated and considered as part of the regulatory test.

These various inputs are used in sophisticated network analysis that ensures each network element satisfies a number of planning and technical criteria (described further in the introduction to network issues in Appendix 1), so that:

• each individual network element is operated within its design limits. This requires voltage and power transfer for each asset to be assessed under a wide range of potential conditions, including for example modelling the effect of faults on the network. Failure to meet voltage design limits can result in malfunction or damage to customer equipment, while exceeding power transfer limits creates potential safety hazards and reliability issues arising from the failure of network equipment due to overloads;

• the network can withstand credible faults and unplanned outages. A fault is considered credible if it is considered likely given the prevailing circumstances. If there is a credible fault or unplanned outage, all plant must still operate within its design limits and the network must continue to deliver the required performance;

• quality of supply is maintained to the appropriate standards. Quality of supply is a term that embraces voltage, frequency and other technical aspects of power supply;

• potential for future growth is adequately provided for, where economically viable to do so, ensuring that Western Power’s electricity networks do not impede Western Australia’s economic development. This may mean, in some circumstances, installing ‘larger’ plant than is immediately required to cater for expected load growth over the next, say, ten years; and

• environmental impacts are responsibly managed.

For convenience, the network is considered to be divided into the bulk transmission network and a number of load areas. As a minimum, each load area is studied in detail every two years to ensure that it meets the relevant planning and technical criteria. Where there have been significant changes in a load area (perhaps due to significant load growth or a new generator connecting), it will be re-assessed as a matter of priority.

The network planning process is a continuous one. As such, this APR is a snapshot as to the constraints and the network development options as they are currently understood. As underlying assumptions change, as further studies are carried out and as each development option’s details are confirmed, there will be changes to the plans published here.

2.1 Network development analysis

As discussed above, the planning and operation of electricity networks must meet certain technical requirements. There are various factors that will change power flows across the network, which must be taken into account when planning and operating the system, including:

• changes in network configuration, either by construction of new elements or outages of existing network elements. For example, introducing new parallel electricity lines affects the network performance;

• location and timing of new generation sources impacts on thermal capacity, stability and fault performance, and thus the need for network augmentation;

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• location and timing of major new loads or load centres. For example, the location and timing of a new aluminium smelter may advance or defer the need for network augmentations; and

• rate of forecast network load growth and long-term growth trends also determine the need for network augmentations. For instance, high growth scenarios will advance network augmentation requirements.

The network development analysis presented in this APR (or any such document) is highly sensitive to changes in any of these factors. Therefore, network development analysis can only indicate likely network constraints. Similarly, the options for addressing these constraints are based on specific assumptions and judgements regarding future events. Variations from these specific assumptions may change the development scenario profoundly.

2.2 Customer expectations

Publicly available surveys have found that consumers expect, in order of preference, their electricity supply to be provided at:

• reliable levels;• appropriate quality; and• low prices.

The network planning and development process depends crucially on understanding and managing customer expectations at the local network level.

Reviews of previous public surveys have noted the importance of methodology in understanding customer preferences. For example, consumers must be given specific examples of reliability improvements before they will express a preference for even limited price rises. Increased understanding of customer expectations allows a better-informed trade-off between acceptable customer service and cost. This further supports the new regulatory regime, and may inform changes to the transmission and distribution planning criteria.

2.3 Transmission network planning standards

Western Power develops its transmission network in line with the network planning criteria2, published by Western Power as required by the Electricity Transmission Regulations 1996.

Generally, the transmission system is a meshed network with a high proportion of elements in service at any given time. The transmission system is broadly divided into the bulk transmission network, the sub-transmission network, radial networks and substations.

Planning criteria for the transmission network are based on a thorough risk analysis. This analysis takes into account:

• the size, extent and sensitivity of load or generation which may be affected;

• the physical location of various components of the network and their exposure to damage risk;

• the relative merits of other alternatives; and• the efficient use of capital.

2.3.1 The bulk transmission network

The bulk transmission network operates at 330 and 132 kV. It consists of the power station switchyards, major terminal switchyards and the transmission lines that interconnect them.

The bulk transmission network is designed to withstand a single unplanned outage without loss of load.

Moreover, the bulk transmission network is generally designed to withstand one forced outage and one planned outage at 80 per cent of forecast peak load (assuming generation rescheduling after the first outage).

For example, this would provide sufficient network capacity to cope with a planned outage (for maintenance or construction activities) at the same time as a second unplanned outage (due to a network fault). When there are two coincident outages and demand is more than 80 per cent of forecast peak load, there may not be adequate network capacity to supply all load.

2 Available at www.westernpower.com.au


The economic justification for this high level of supply security (and consequently reliability) is the high capacity of the bulk transmission network – losses of supply on the bulk transmission network may affect many customers.

2.3.2 The sub-transmission network

The sub-transmission network operates at 132 and 66 kV. It consists of zone substations that transform these primary voltages to 33, 22, 11 and 6.6 kV secondary voltages and the transmission lines that interconnect them.

The sub-transmission network is generally designed to withstand a single unplanned outage without loss of load.

When there is more than one outage at the same time, there may not be enough network capacity to meet all demand. Sometimes, there may be limited back-up capacity available via the distribution network.

These planning criteria broadly apply to parts of the network supplying urban areas in the Perth metropolitan region and major regional centres. These parts of the network tend to be characterised by relatively high load densities and shorter transmission lines.

2.3.3 Radial networks

Radial networks operate at 220, 132 and 66 kV and generally supply loads of less than 20 MW. The 220 kV network supplies the Eastern Goldfields due to the large distance between the supply source and load centre. The 132 and 66 kV radial networks generally supply regional townships in Western Australia’s South-West region. These 132 and 66 kV radial networks include zone substations that transform the primary voltages to 33 kV or 22 kV.

Radial networks are designed taking into account analysis of network reliability, risk and economic factors. Radial network backup may be provided by other parts of the transmission network, the distribution network, local generation or not at all, depending on this analysis.

It is not always economic to provide full redundancy on the radial networks due to the large line-lengths, geographically dispersed loads and generally smaller loads (when compared to metropolitan areas).

2.3.4 Substations

Substations interconnect the sub-transmission network with the distribution network. Each substation is designed to meet planning criteria that depend on the substation’s location and the type of load it supplies:

• Substations in the Perth central business district are designed to provide the highest level of security due to the relative importance of the load supplied by these substations.

• Regional substations are designed to provide the next highest level of security due to the long travelling times required before plant can be repaired or replaced, although there are some remote substations designed to provide a relatively low level of security, for reasons described below.

• Substations in the Perth metropolitan area are designed to accept a higher level of risk of load shedding, as they are accessible for plant repairs or replacement. The designs of the various types of substations recognise the need to optimise security of supply and capital expenditure.

CBD substations are designed to withstand the failure of a single item of plant without any sustained loss of load. They are also designed to withstand the failure of either two items of plant or both transmission lines supplying a substation with only a temporary interruption to load.

Most regional substations are designed to withstand the failure of a single item of plant without sustained loss of any load. A small number of regional substations are designed to withstand the failure of a single item of plant with a small risk that up to 10 per cent of the load may need to be shed. This risk only applies for one per cent of the time throughout a year, and is based on the availability of suitable spares.

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A small number of regional substations are not able to continue to supply load for a failure of a single item of plant. These substations have usually been established for one customer where the customer has accepted the risk. Even if nearby loads then take the opportunity to be supplied from these substations, it is often not economic to provide higher supply security.

Most substations supplying the Perth metropolitan area are designed to withstand the failure of a single item of plant (about a one in 20-year event), accepting that some load may be shed, on a rotational basis, for up to nine hours. In line with commercial imperatives, since 1996, Western Power has accepted the risk of short-duration load-shedding to increase the utilisation of substation capacity.

2.4 Distribution network planning standards

The distribution network operates at 33, 22, 11, 6.6 kV and 415 V. It is broadly separated into CBD, metropolitan and rural networks. Each of these categories is discussed below.

Western Power’s distribution system is generally designed to operate radially. Normally, the loss of a network element will interrupt supply to a number of users. There are a number of factors which mitigate the length of interruption for customers.

Ties between feeders provide backup connections when the normal feeder is out of service, for example, and reclosers and sectionalisers are also used. To ensure that equipment is not needlessly out of service, some equipment will automatically re-energise the network element after a short delay. This is known as ‘reclosing’. Sectionalisers allow the location of the fault to be identified and service restored to customers upstream from the fault. Western Power also uses fault indicators, load-break switches and remote-control pole-top switches to improve the speed of fault location and isolation, which facilitates more rapid restoration.

In the future, embedded generation, may be able to assist in these circumstances. However, embedded generation must disconnect from the network if its local distribution feeder is separated from the wider power system. If the embedded generation could remain connected, this would be known as islanded operation. Currently the distribution system cannot support islanded operation because it is not fitted with synchronising equipment to reconnect islanded feeders to the wider power system when it is safe to do so.

2.4.1 CBD

The CBD distribution network is an open-meshed and remotely-switched design. This facilitates rapid restoration of supply to healthy sections of the network after faults. In addition, CBD zone substations automatically reconfigure feeders after the loss of step-down transformers. The total loss of a single-zone substation requires manual network reconfiguration to restore supplies within four hours. CBD feeders are normally limited to 50 per cent of their maximum-rated capacity. This provides leeway to remotely reconfigure the network and so restore load after a feeder outage.

2.4.2 Metropolitan

Metropolitan distribution networks are open-meshed networks with radial feeders and inter-feeder ties that can be switched into service as required3. This moderate level of interconnection between feeders and a planned maximum feeder loading of 80 per cent allows for the transfer of load between feeders after a fault. In contrast to the CBD, this transfer of load may require a number of manual-switching operations.

This feeder arrangement minimises fault levels and simplifies technical and operational requirements. With multiple open points, improved supply restoration times are possible, although the initial loss of supply will still occur.

3 These are known as ‘normally open points’.


2.4.3 Rural

The distribution networks in rural areas are radial and are much longer than metropolitan feeders, with limited inter-feeder ties. As a result, supply restoration after network faults takes longer. Some distribution feeders can be very long, with no interconnection to accelerate supply restoration.

Users requiring security of supply above the standard design philosophy will be provided with network back-up where practicable. However, on-site standby generation may be the only economic solution. Investment to provide additional security of supply is normally at the user’s expense.

2.5 Quality of supply requirements

Aside from the extensive planning criteria described above, Western Power applies technical requirements to ensure that the quality of electricity supplied to customers is acceptable. These requirements affect the design of the network and its elements. They include characteristics such as flicker, voltage limits, waveform distortion and waveform unbalance. Broadly speaking, the requirements are found in various national and international codes of practice and standards. They are widely accepted by electricity utilities and by electrical equipment manufacturers.

Western Power has other obligations established by legislation. The Electricity (Supply Standards and System Safety) Regulations 2001 contains various quality-related benchmarks. The Electricity Transmission Access Technical Code and the Distribution Technical Code and Planning Criteria also set out requirements, although the codes are in the process of being replaced by technical rules that are being prepared by the ERA in consultation with Western Power and other Network users4.

4 Electricity Transmission Access: Technical Code and Electricity Distribution Regulations: Technical Code, Western Power Corporation, Perth.

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3.1 Developing and applying electricity demand forecasts

In contrast to the Statement of Opportunities report, which provides forecasts at the overall system level, the network development planning process also requires forecasts for each substation and terminal station. To then determine augmentation needs, Western Power assesses network capability against electricity demand forecasts by:

• direct comparison with each network element’s thermal rating; and

• computer simulations to identify thermal, voltage, stability and fault rating constraints.

3.1.1 Typical drivers of load growth

In the SWIS, typical drivers of load growth include:

• penetration of air-conditioners. Recently, increased residential air-conditioning has boosted electricity demand significantly. If air-conditioner penetration grows further, weather sensitivity is likely to increase strongly;

• new residential sub-divisions. There is rapid growth in new residential developments along the northern and southern coastal strip towards Two Rocks and Mandurah, as detailed in the Metropolitan Development Program – Urban Land Release Plans, released by the Western Australian Planning Commission, and available at www.wapc.wa.gov.au;

• in-fill growth in older metropolitan suburbs, resulting in increased housing and hence increased load density; and

• isolated larger customers such as shopping centres and particular industrial/commercial loads. There have been a number of announcements of sizeable industrial loads to come into operation over the next decade. These loads are included in the base assumptions when they can be considered as committed, using similar criteria to those used in the SOO.

3.1.2 Western Power’s load forecasting methodology

Three levels of demand forecast are required for network planning purposes. These include:

• a demand forecast for the bulk transmission system, which is broadly based on the demand forecasts reported in the Statement of Opportunities Report, and which allows peak network flows across the bulk transmission network to be modelled. An overall load forecast for the bulk transmission network is the sum of individual substation forecasts at the time expected system peak load, corrected to match the demand forecasts reported in the SOO;

• demand forecasts for each substation, which are developed by extrapolating previous peaks for each substation, and which allow peak power flows across each substation element to be modelled. Western Power’s forecasting methodology is based on statistical analysis of historic load information for every substation and terminal station. Expected block loads are, as appropriate, added to these demand forecasts; and

• demand forecasts for each load area, which allow peak power flows across the network elements in each load area to be modelled. These forecasts are developed using the bulk transmission forecasts and the individual substation forecasts.

In each case, the focus is on understanding the most onerous conditions that will affect each network element. For example, the bulk transmission network’s most onerous power flows are normally at the time of system peak. An individual substation may have its peak load at a different time to the remainder of the network. Simply using load forecast for the time of system peak would potentially understate the duty on each substation element, and lead to inadequate development plans.

� Network planning assumptions

This chapter provides some background on the latest planning assumptions underpinning the Annual Planning Report. The main network planning assumptions are peak demand across the network and the location of new generation.


The most onerous operating condition for each load area is derived from a combination of the demand at time of system peak and local demand peaks, depending on the characteristics of that load area.

The SWIS load forecast, as reported in the 2006 SOO, exhibits a load growth of approximately 3.4 per cent or 20 MW per annum, which is in line with historical load growth. Individual years and substations vary significantly around this average. The load growth in recent years has exceeded the average growth rate.

3.1.3 Managing weather sensitivity risks in demand forecasting

The highest peak demand for the SWIS is generally mid-week after a consecutive string of hot and humid days with temperatures between the high 30s and mid-40s, with hot and humid conditions overnight.

In a hot summer, such as the summer of 1997, (where peak day temperatures reached 44.5°C, minimum 29.0°C), peak demand was about 150 MW above that on an average summer peak day.

In contrast, during a mild summer, such as in 2002, (where peak day temperatures reached a maximum of 36.3°C, minimum 21.5°C), peak demand was about 100 MW below that of an average summer peak day.

To account for weather-related variation in forecasts, peak demand is expressed as PoE values. Taking 50 per cent PoE as an example, for every ten demand readings, on average five readings would be over the 50 per cent PoE value and five would be below the 50 per cent PoE value. Similarly, on average, one sample would be above the 10 per cent PoE value and nine samples would be below the 10 per cent PoE value.

The peak demand day has generally occurred between the end of the summer school holidays and the middle of March. Over the past 50 years, the average highest maximum temperature each summer has been 41°C. The average of the highest minimum temperature each summer has been 26°C.

This average ‘hottest’ day is the basis of peak demand projections and is known as the 50 per cent PoE. The variations that may occur on warmer or milder ‘hottest’ days are known as the 10 per cent and 90 per cent PoEs respectively.

Western Power uses the 10 per cent PoE in its modelling. This provides an appropriate level of capacity within the network following the implementation of network development plans.

3.1.4 Review of load forecasting practice

Load forecasts are a critical input into the network planning and development process. Western Power’s network reinforcement plans and capital expenditure requirements are developed from load flow studies that depend on forecasts of load at the low voltage side of each individual substation’s transformer. The forecasted loads with reactive power compensation removed are directly uploaded in to Western Power’s load flow model for performing load flow studies under contingency conditions to identify network constraints.

This process enables the identification of network constraints and the necessary network augmentations to increase capacity in the SWIS network such that growth in peak electricity demand can be catered for.

Given the fundamental importance of load forecasts to the electricity network development process, that is, the ability to cater for peak demand growth with prudent and timely capital expenditure, it is vitally important for Western Power to continually improve its capability and excellence in the following areas:

• understanding of anticipated load growth. Demand growth can arise from the development of proposed large bulky loads such as new mining projects, land developments, economic factors, population growth and other demographic factors. Western Power will be increasingly more connected with industry and other government agencies to ensure that the anticipated needs of network users are adequately catered for in a timely and cost effective manner;

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• understanding the sensitivity of peak demand to weather conditions. Weather conditions play a significant role in driving growth in peak demand primarily due to increased use of electricity for space cooling and, to a lesser extent in the SWIS, space heating; and

• understanding of the diversity of loads across different regions throughout the SWIS. This takes in to consideration varying weather conditions over different regions and varying economic and demographic conditions over different regions.

Western Power is presently conducting a review of its existing load forecasting processes, methodologies and assumptions, with a view to identifying the opportunities for improvement to achieve credible forecasts. The review will also seek to identify areas of best practice in respect to load forecasting in Australia. This review will be completed by Q2 2007.

3.2 Location of new generation

As noted in the Introduction, Western Power provides non-discriminatory access to the SWIS. Pricing signals are provided to users of the network by Western Power with the intention of optimising the development of the system, including the location of new generation sources. However, Western Power may not direct the location for new generation. Therefore, Western Power must make prudent assumptions regarding possible generation development scenarios in its network development planning process.

The 2006 Statement of Opportunities reported that 1087 MW of new generation capacity will be committed to connect to the SWIS during the next three years and an additional 713 MW of new generation capacity has been proposed for connection to the SWIS during the next three years.

The load forecast published in the 2006 SOO will require that a total of around 2500 MW of new generation capacity will be required to connect to the SWIS to meet electricity demand growth over the next 10 years.

The location for this generation capacity is not certain, however it is anticipated that a considerable proportion of this capacity will be located south of the Perth metropolitan area in the region between

Pinjarra and Collie. This assumption is based on the availability of fuel resources for coal, gas and renewable plant, as well as compatible process industries for cogeneration plant.

Western Power relies on proponents to provide details of their projects early enough to allow timely network reinforcement. While proponents provide information in good faith, there is a range of factors that can change the feasibility, timing, size and location of such projects. Moreover, in some instances, proponents only provide details of their intentions once the projects are nearly committed to minimise the commercial risk to the project. Equally, Western Power is aware of generation projects that cannot be reflected in this public document due to confidentiality constraints. It is possible therefore that future development plans will be materially different from those published here.

Western Power’s planning process must manage the high level of uncertainty associated with the timing, size and location potential future generation sources. The impact of this uncertainty is exacerbated by the time taken to complete major transmission network augmentation projects, such as the construction of 330 kV transmission lines required to accommodate large new generation sources. The construction phase of a generation project can take as little as two years, whereas establishing a new transmission line can take up to seven years from conception to commissioning. Much of the time required to establish a new transmission line is associated with the environmental processes that need to be completed to identify and gain approval for line routes.

Without the necessary network infrastructure to provide minimum levels of power transfer capability, generator outputs may need to be restricted to maintain network safety, reliability and security. Such restrictions may have an adverse impact on the development of a competitive generation market. Consequently, Western Power’s planning processes are designed to identify universally required network developments and to commence investment to ensure that the network can respond to market needs in a timely fashion. This investment will be subject to, among other things, the regulatory regime, Access Code and capital contributions policy.


The 2006 SOO identifies ‘committed’ and ‘proposed’ generation projects. Committed projects are included in the base assumptions used for the system analysis underpinning this APR. Scenario analysis has been performed on the proposed generation projects to assess the impact on the network. The following sections develop scenarios that allow consideration of network constraints arising from potential new generation.

The consideration of these various scenarios enables Western Power to identify elements of commonality between generation development scenarios and where particular options are beneficial to all development scenarios. Where this occurs, the network option can be demonstrated to be sound from a regulatory perspective allowing the network reinforcements to be implemented in a timely manner. A basic level of access to the network would then be available for whichever development scenario eventuates. As particular generators commit to connecting to the network, additional network reinforcement is likely to be required to tailor the network to suit that particular connection. Therefore, some generator output constraints may still be required until all reinforcements can be completed.

In developing and considering these scenarios, Western Power is neither recommending particular locations nor is it judging which generation projects are most likely to succeed. It is simply ensuring that its network plans are robust enough to cope with the potential generation developments.

3.2.1 Southern generation development scenario

The 2006 SOO reports that 736 MW of new generation is committed to connect in the southern part of the SWIS by 2008/09. Unlike previous editions of the Statement of Opportunities (formerly the Generation Status Review), no information is available regarding proposed generation connections. Committed projects reported in the 2006 Statement of Opportunities are as follows:

• a 129 MW generator in the Pinjarra area;• a 52 MW upgrade of existing plant at Muja;• a 351 MW power station in the Wagerup area;

and • a 204 MW generator in the vicinity of Collie.

In addition to the committed projects, there are a number of other new generation proposals.

The new generation proposals for this area are considered realistic given the ready access to a range of fuel sources together with suitable process industries that could accommodate cogeneration projects.

The development of new generation sources in the southern areas exposes the network to the following limitations:

• an increased requirement for reactive power support within the metropolitan area; and

• overloading of 330/132 kV transformers interconnecting the 330 kV bulk transmission and 132 kV sub-transmission networks.

Reactive Support

Additional reactive power support is required for two reasons. Firstly, the four 330 kV transmission lines between the South-West generation sources and the Perth metropolitan area are all around 200 km long. Any 330 kV lines of this length can transfer no more than 500 MW of power each before voltage stability limits begin to constrain their power transfer capacity. To maintain stable and secure network operation at loading levels above 500 MW, reactive power support is required. Even with this measure, the risks of system voltage collapse are significantly increased by the connection of the new generators.

Secondly, with increased base load power generation at 330 kV, the 132 kV generation elsewhere in the network is displaced. This displaced generation is typically located near to the Perth metropolitan area and due to its proximity to the load, it would normally provide dynamic reactive power support to stabilise the network during faults. When this generation is displaced, the reactive power support normally provided by it needs to be sourced from elsewhere.

Means of alleviating the demand for increased reactive support include the provision of alternative sources of reactive power (for example, using static var compensators) or by reducing the load transferred by transmission lines by either connecting additional lines or by reducing generator outputs.

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Tranformer capacity

The increased loading of the 330 kV network that will result from the connection of new generation sources at 330 kV will require additional 330/132 kV transformer capacity within the Perth metropolitan area, which is the main load centre.

Network augmentation

Therefore, significant network augmentations will be required to enable the SWIS to accommodate additional generation in the South-West region. All or some of the following network reinforcements will be required to accommodate the new generation proposed in the 2006 SOO:

• imposition of generation scheduling restrictions (in some cases, for specific times);

• installation of additional 330/132 kV transformer capacity in the metropolitan area;

• construction of additional transmission lines within the metropolitan area; and

• construction of new terminal stations within the metropolitan area.

Additional generation beyond that proposed in the 2006 Statement of Opportunities would extend the reinforcement works:

• construction of 330 kV transmission lines from the South-West region into the Perth metropolitan area; and

• installation of additional reactive power compensation, in the form of static var compensators, shunt capacitor banks within the metropolitan area or series line capacitor banks on the major 330 kV infeeds to the metropolitan area.

The most significant work would entail the construction of new 330 kV transmission lines between the South-West region and Perth. The installation of reactive power compensation will provide temporary alleviation of network constraints. Providing longer-term solutions to these constraints would require construction of additional 330 kV interconnectors and hence the acquisition of new transmission line easements. This process can take between three to five years owing to the potentially long environmental approvals and public consultation procedures.

3.2.2 Northern generation development scenario

This generation scenario has been developed around the projects outlined in the 2006 Statement of Opportunities and has been extended considering the potential fuel sources in the area. There is only one committed project in the 2006 SOO:

• an 80 MW wind farm near Cervantes.

There is potential for further development of renewable and fossil fuel energy resources such as wind farms in the area. The northern part of the SWIS extending from the Perth metropolitan area to Geraldton is supplied via a number of long parallel 132 kV transmission lines. With a distance of approximately 400 km between Northern Terminal and Geraldton, this is a long and weak interconnection and it provides only limited power transfer capability for this area of the state. This system currently operates close to its power transfer limits.

This area is also constrained by the following thermal, voltage and stability limitations:

• Thermal: Most of the 132 kV transmission lines in the North Country area are thermally rated to allow power transfers of up to 85 MVA (without considering synchronous stability limits);

• Voltage: Due to the long route of the North Country system and its relatively high power transfer requirement, high loads can cause the system voltage in the North Country area to drop to unacceptable levels; and

• Synchronous stability transfer limits: Due to the long interconnection between the North Country system and the SWIS, faults on the interconnection or in the SWIS can cause synchronous instability between generator groups in the Perth metropolitan area and North Country. This situation may be exacerbated by the connection of additional generators in the North Country. Provided the power transfer from the metropolitan area to the North Country region is held below the transient stability limits, local generation in the North Country area will retain synchronism with the metropolitan system for system faults that are cleared normally. If the power transfers are excessive then units may lose synchronism. Therefore, the connection of generation in the North Country region will necessitate significant network reinforcements to alleviate the network constraints.


In addition to the network limitations within the northern area, the connection of additional generation sources in this area exposes the network within the Perth metropolitan region to several limitations, including an increased requirement for reactive power support and potential overloading of the 132 kV transmission lines.

Additional reactive support is needed for two reasons. Firstly, the additional generation provided by the wind farms means that generation elsewhere in the network is displaced. Most usually this displaced generation is located near to the Perth metropolitan area and due to its proximity to load, it would normally provide reactive power support to stabilise the network during faults. When this generation is displaced, the reactive power support normally provided by it needs to be sourced from elsewhere. Secondly, the remoteness of the proposed wind farms and the long 132 kV transmission lines that connect them to the load centre means the lines are too long to transfer any reactive power from the wind farms to the load centre.

The 132 kV transmission network in the North Country area was originally designed for load to be transferred northwards. With the connection of large sources of generation north of this region, the power flow is reversed with load flowing into the Perth region. The network has not been designed for this scenario and needs reinforcing as utilisation of the network at its limits. Installation of additional generation within the North Country is unviable due to thermal and synchronous limitations.

Therefore, substantial network augmentation will be required to enable the connection of additional generation sources in the area north of Perth. Some or all of the following work will be required to accommodate the generation project included in the 2006 SOO:

• installation of additional reactive power compensation, in the form of static var compensators, shunt capacitor banks within the metropolitan area and/or series line capacitor banks on the major 132 kV infeeds to the metropolitan area;

• imposition of generation scheduling restrictions (a matter of negotiation between Western Power and the generation proponent);

• development of new 132 kV transmission lines within the metropolitan area;

• establishment of a 330 kV bulk transmission network north of Perth to towards the Geraldton region; and

• installation of additional 330/132 kV transformer capacity in the metropolitan area.

As noted earlier, establishing 330 kV transmission lines requires a substantial lead-time, with approval for and acquisition of transmission line easements taking in the order of three to five years.

3.2.3 Metropolitan generation development scenario

A single project for the connection of a new 320 MW generator in the Perth metropolitan area is identified in the 2006 Statement of Opportunities. Beyond this, Western Power is aware of several proposals for additional generators within the metropolitan area.

The electricity transmission network within the Perth metropolitan area is characterised by high loads and high fault levels. The fault levels on the 132 kV network within the metropolitan region are nearing design limits and the 132 kV network between the metropolitan power stations and terminal stations is loaded to capacity. As a result Western Power requires that all new generating sources within the metropolitan area be connected to the 330 kV network. To facilitate this requirement, it will be necessary to establish new 330 kV transmission interconnectors within the Perth metropolitan area to connect new power stations with the bulk transmission network in the future.

Specifically, the development of additional generation within the Perth metropolitan area will:

• increase fault levels;• increase loading of the 330 kV transmission

network within the metropolitan area (for some connection locations); and

• increase loading of 330/132 kV transformers interconnecting the 330 kV bulk transmission and 132 kV sub-transmission networks.

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The retirement of some generators within the Perth metropolitan area will:

• reduce reactive power support for the network during faults;

• increase demand for reactive power support due to replacement of metropolitan generation with remote generation and resultant higher loading of long 330 kV bulk transmission lines; and

• increase loading of 330/132 kV transformers interconnecting the 330 kV bulk transmission and 132 kV sub-transmission networks.

Therefore the connection of additional generation sources within the Perth metropolitan area would require some network augmentation, but may also have some beneficial effect on the network by providing reactive power support. The exact siting of generation within the metropolitan areas will significantly affect the timing, type and location of network development required.

For example:

• concentration of new generation in the southern part of Perth, alongside existing generation, would increase network loading and fault levels, requiring some reinforcement; and

• the siting of new generation in the northern part of Perth would initially require the establishment of a new 330 kV connector but should minimise any other fault uprates, network reinforcements or reactive power support requirements.

3.2.4 Eastern generation development scenario

There are no current generation project proposals in the SOO for connection to the eastern part of the SWIS. The inclusion of this generation development scenario here seeks to provide a general overview of the existing network and the constraints that are likely to be encountered with the connection of generation in this part of the network. The connection points at Northam and Kalgoorlie are presented for illustrative purposes.

Generation at Northam

This scenario has been included (even though there are few convenient fuel sources) to illustrate the impact of significant generation developments in the area.

Northam zone substation is interconnected into the metropolitan area via three 132 kV lines and a normally open 66 kV transmission line. The transmission system supplying Northam has been designed to supply relatively small loads in the Northam and its surrounding areas. It also provides back-up capacity to supply loads in the areas surrounding Merredin.

Given that the network was designed to supply relatively small loads, there would be significant thermal, voltage and stability constraints associated with power transfer from Northam into the metropolitan area. Further, significant line losses may result from this power transfer. Network reinforcement costs to cater for the connection of significant amounts of generation in this area are likely to be high due to the absence of existing 330 kV transmission infrastructure or strong points of connection at lower voltages. For example, the straight line distance from Northam substation to the closest 330 kV circuit line is approximately 67 km. The network reinforcements associated with this scenario are similar to those required for the Northern generation development scenario.

Generation at Kalgoorlie

Kalgoorlie is located approximately 550 km east of the Perth metropolitan area and is connected to the SWIS via a radial 220 kV transmission line. There is potential for generation proponents to propose connecting to this system to supply local load and potentially export surplus power into the SWIS given that:

• there is an existing gas pipeline providing a readily available source of fuel;

• there are existing process industries in the area; and

• there is an existing 220 kV transmission system.

The interconnection from Muja in the south-west to Kalgoorlie is via a 650 km long 220 kV transmission line that was originally designed and constructed in 1984 to supply loads in the Kalgoorlie area. Due to its length, reactive power compensation is required along the 220 kV line to maintain the voltage profile along the line (enabling power transfer capacity to the Kalgoorlie area).


At the time the 220 kV line was designed and constructed, it was intended that generators were connected to the network in the Eastern Goldfields area for emergency stand-by purposes only, to supply some load when the radial 220 kV line was out-of-service.

More recently generators have connected in the Kalgoorlie area to supply local load. A Remedial Action Scheme (RAS) has been installed at Kalgoorlie to ‘island’ this generation for local and remote faults in the SWIS, which could otherwise result in synchronous instability. This scheme is required in service only when power transfer from Muja exceeds certain thresholds.

Operation of the RAS and subsequent islanding of the generation in Kalgoorlie can result in substantial and abrupt changes in power flow along the 220 kV line from Muja to Kalgoorlie. The system was not designed to cater for such large abrupt changes in power transfer. There are limitations in the dynamic range of fast-acting reactive power compensation equipment and therefore while the RAS enhances the transfer capability of the existing system, it also imposes limits on the amount of power that can be exported from generators in the Kalgoorlie area without undertaking additional reinforcement of the network.

Given that generation in the Kalgoorlie area can be operated in a synchronously stable mode if power transfer across the Muja to Kalgoorlie 220 kV interconnection is maintained within a particular threshold, there is scope for additional generation to be accommodated within the Eastern Goldfields system. Power transfer limitations imposed by synchronous instability constraints would need to be managed with the careful design of power plant to ensure that the system operates in a synchronously stable state.

If the amount of generation connected in the Kalgoorlie area exceeds the local load, then power would be transferred across the 220 kV transmission line into the SWIS via Muja. This has similar effects as the southern generation development scenario with similar network reinforcement requirements.

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A new load area called Guildford has recently been created with the construction of Guildford Terminal. A number of existing substations including Midland Junction, Forrestfield, Darlington and Kalamunda have been allocated to the Guildford load area. The bulk transmission network interconnects these load areas. Figure 4.1 provides a simplified single line representation of the SWIS.

Historically, these load areas tended to consist of a number of zone substations centred on a major terminal station. However, with increasing numbers of substations being cut into interconnecting transmission lines to minimise substation establishment costs, the network is becoming increasingly meshed.

Each load area has its own unique characteristics and load growth in the area tends to be influenced by them. For example, the load areas supplying the northern and southern coastal areas are experiencing rapid load growth due to residential housing developments, whereas growth in the Eastern Goldfields areas is highly sensitive to the activities of mining companies in response to world metal prices. As might be expected, the greatest distinctions are between load areas that cover urban and rural load areas.

The maximum demand forecasts for each load area are shown as a percentage of the total load for 2006 and 2011 in Figure 4.2. The load proportions are not expected to drastically change over the next five years.

Average annual peak demand growth is shown in Figure 4.3.

4.1.1 Bulk transmission network

Power is transferred over the 330 and 132 kV bulk transmission networks from five major and a number of smaller interconnected power stations to 12 bulk supply terminals for transformation to lower voltages. Electrical energy is then distributed to a host of zone substations supplying localised areas via the sub-transmission networks operating at 132 and 66 kV voltages.

The bulk transmission network comprises the 330 kV network and major 132 kV links between power stations and terminal stations. At present there are four major 330 kV transmission ties linking the South-West power stations with the Perth metropolitan area, two major 330/132 kV terminal stations at Northern Terminal and Southern Terminal and three main 330 kV transmission lines within the Perth metropolitan area. There are also a number of major 132 kV transmission ties that are considered to be part of the bulk transmission network.

In assessing the adequacy of the bulk transmission network, generation forecasts are as important as load forecasts given that the timing, size, and location of new generation connections significantly affect the network development. Consequently, network performance studies have been conducted assuming that required additional generation is connected to the bulk transmission network. However, the generation siting issue is constantly changing, so the information presented represents a snapshot only.

4.1.2 Northern Terminal

The Northern Terminal load area covers the north of the Perth’s metropolitan region, extending from the coast to Osborne Park and Morley in the south, to Yanchep in the north, and West Swan in the east. At 833 MW, the load area represents approximately 26 per cent of the total load in Western Power’s SWIS. There are presently 14 substations in the load area, all with summer peaks.

The area contains commercial, light industrial, residential and semi-rural loads. Parts of the area are sparsely populated but will be subjected to intensive residential and some commercial development in coming years. Long-term development plans indicate that heavy industrial load centres may be developed in the area within 20 years.

The recent trend of high-load growth is expected to continue for the next ten years.

� Description of load areas

The SWIS is grouped into 1� load areas primarily along geographical lines – Northern Terminal, Muja, Kwinana, Cannington, Bunbury, Western Terminal, East Perth, Southern Terminal, South Fremantle, East Country, Eastern Goldfields, and North Country.

2007 Transmission and Distribution Annual Planning Report�0

Figure 4.1 Simplified SWIS single-line diagram.

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Figure 4.2 Peak demand proportions by load area in 2006 and 2011.

• Bunbury 7%

• Cannington 8%

• East Country 3%

• East Perth 10%

• Eastern Goldfields 3%

• Guildford 4%

• Kwinana 9%

• Muja 8%North Country 5% •

Northern Terminal 22% •

South Fremantle 6% •

Southern Terminal 11% •

Western Terminal 4% •

Peak demand proportions by load area – 2011

• Bunbury 8%

• Cannington 9%

• East Country 3%

• East Perth 10%

• Eastern Goldfields 3%

• Guildford 4%

• Kwinana 8%

• Muja 5%North Country 6% •

Northern Terminal 23% •

South Fremantle 6% •

Southern Terminal 11% •

Western Terminal 4% •

Peak demand proportions by load area – 2006

Figure 4.3 Annual average (over five years) peak demand growth rate, by load area.

0.0% 1.0% 2.0% 3.0% 4.0% 5.0% 6.0% 7.0%

Load

Are

a

Western Terminal

SouthernTerminal

South Fremantle

Nothern Terminal

North Country

Muja

Kwinana

Guildford

Eastern Goldfields

East Perth

East Country

Cannington

Bunbury

Load Growth


Beyond this, overall development may moderate, as vacant land becomes scarce. Even so, there may be localised growth pockets, particularly along the North-West coastal strip.

The average load growth for this load area is forecast to be in the order of four per cent to seven per cent per annum, almost double the forecast system average.

If achieved, the forecast load growth would require the establishment of at least ten new substations and the construction of two new transmission lines during the next 10 years. In addition, a number of existing substations will need to be uprated.

4.1.3 Muja

The Muja load area supplies predominantly agricultural loads, with some mining, milling and light industrial loads. It extends from Muja Power station to Manjimup and Beenup in the south-west, Albany in the south-east, Boddington in the north and Narrogin in the north-east. Due to the large geographical area, the load area’s substations supply their peak loads at different times:

• The substations supplying predominantly domestic loads normally supply their peak load during winter.

• The substations supplying mining and agricultural loads normally supply their peak load during summer.

Local load growth is generally slow, although there are some developing areas and there have been some new mining loads connected recently. Albany, the main population centre, has had the most significant load growth and is forecast to grow at a rate of around 2.5 per cent per annum over the next 10 years. The loads at Narrogin, Wagin and Katanning substations are forecast to grow on average 2 per cent per annum, while the rest of the load area has a forecast load growth of one per cent or less.

4.1.4 Kwinana

The Kwinana load area roughly follows the administrative boundaries of the City of Kwinana, and the towns of Rockingham and Mandurah. All the substations in this area experience peak demand during summer.

Two infrastructure developments are anticipated to have a major long-term impact on the area. These are:

• the South-West Metropolitan Railway project that will extend the South-West Metropolitan Railway to Rockingham and Mandurah by 2007; and

• the Kwinana freeway, which has recently been extended to Safety Bay and a further section between the Mandurah bypass and Lake Clifton is due for completion by 2008. The section of freeway between Safety Bay and Mandurah is due for completion by 2011.

Both of these major infrastructure projects are expected to provide a more attractive environment for residential development. These projects are accelerating development and therefore load growth in the area from Rockingham to south of Mandurah. The load in the Kwinana load area is forecast to grow at an average rate of 6 per cent.

4.1.5 Cannington

The Cannington load area covers the south-east metropolitan area, bounded by the Swan and Canning rivers and extending east to Mundaring. The load area supplies a broad mix of load types ranging from industrial and commercial to residential and semi-rural. All the substations in this area supply their peak load during summer.

Commercial and industrial loads in the area are experiencing strong growth, and overall load demand in the area is growing at around 4 per cent. The residential areas in Cannington load area are fairly well established and domestic load growth is expected to be relatively subdued but steady. Urban consolidation and major development projects, many of which will be located along the shores of the Swan and Canning rivers, will be the main drivers for domestic load growth in the well-developed residential areas. Urban sprawl will be one of the main drivers for domestic load growth in the fringe areas.

4.1.6 Bunbury

The Bunbury load area covers a large region from Pinjarra in the north to Margaret River in the south. The region supplies a diverse range of load types, varying from mining and minerals

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processing, to timber milling, light industry, food production, domestic and agriculture. The substations within this load area predominantly supply their peak load during summer. However, some substation loads are increased by the influx of tourists during holiday seasons.

The load in this area has grown rapidly, particularly around Picton, Pinjarra, Busselton and Margaret River, primarily due to the expansion of the tourism, wine and food producing industries and some residential development. This expansion is expected to continue over the medium term.

Major residential development projects, many located along the coastal strip south of Bunbury and spot developments along the Leeuwin-Naturaliste line, will be the key drivers for forecast load growth. Furthermore, expansion of Mandurah inland towards Pinjarra and the Peel Deviation is expected to drive load growth in the Pinjarra region. Large industrial developments are expected around Kemerton and Marriott Road.

Bunbury load growth is expected to be around 4 per cent, driven by the major load centres of Picton, Bunbury Harbour, Pinjarra and Busselton. The highest rate of load growth, at 5 per cent, is forecast at Busselton substation. The forecast load growth in this area will require additional capacity between Waterloo, Busselton and Margaret River.

4.1.7 Western Terminal

The Western Terminal load area supplies the western suburbs bound by the Perth CBD to the east, Swan River to the south, the coast to the west, and the suburbs of Scarborough and Yokine to the north. Western Terminal supplies predominantly commercial and residential customers.

The western suburbs are generally well-established and mature, with above average socio-economic demographic. Analysis of available data and information pertaining to proposed residential, commercial, industrial and infrastructure developments in the area indicates that most of the area’s substations are likely to experience steady growth in load over the medium to long term.

Load growth in the area is expected to be driven by expansion of existing major commercial loads, natural growth and the increased uptake of residential air-conditioning and other appliances. A number of the area’s major commercial customers, including the University of Western Australia, Claremont Shopping Village, and Sir Charles Gardiner and Hollywood Private hospitals, have indicated they are likely to double demand over the next ten years. Contributions from infill developments and re-development of small pockets of land following re-zoning are expected to be insignificant.

The forecast average annual load growth for substations in the Western Terminal Load Area is about 3 per cent. Cottesloe, Nedlands, Shenton Park and Wembley Downs, which are the four largest substations in the area, are growing at more than 3 per cent per annum, with Cottesloe and Shenton Park in particular experiencing significant jumps in peak demand during summer 2004.

4.1.8 East Perth

The East Perth load area includes the CBD, Town of Vincent, City of Subiaco, and parts of Maylands. The substations within the East Perth load area all supply predominantly commercial loads with peak load during summer. The CBD load represents around 10 per cent of the total system peak load.

Load growth in the East Perth load area has been subdued over the last five years. A lack of any significant new development, redevelopment of the East Perth precinct, and redevelopment associated with the Northbridge tunnel, appears to have shifted load profiles and temporarily reduced load. With the completion of these developments, it seems likely that underlying growth and the connection of block loads will cause higher levels of load growth over the short term.

The potential for future load growth in the East Perth load area is largely related to the growth in the economy and the resulting increase in commercial activity in the CBD. It is recognised that strong economic growth could lead to a commercial building boom and significant load growth with little warning.

2007 Transmission and Distribution Annual Planning Report��

Perth CBD population growth is reasonably high at double the Perth metropolitan average. However, high population growth has not translated into high load growth. The residential load profile complements the area’s dominant commercial load profile as population growth has contributed to energy growth without increasing peak demand.

The forecast load growth for the area is higher than average for the next five years. This is due to a number of large new loads including the Perth Convention Centre, Woodside Building and East Perth Redevelopment Project.

4.1.9 Southern Terminal

Substations in the Southern Terminal load area, from Riverton and Canning Vale in the north, to Cockburn Cement in the west and Byford in the south, supply a mixture of commercial, industrial and residential customers, with the peak load occurring during summer.

Many substations in the area have experienced rapid load growth over the last five years due to increased land development activities. In particular, the area supplied by Cockburn Cement substation has seen load growth at close to nine per cent per annum due to new commercial loads around Jervoise Bay and local residential subdivisions. As there is still much vacant land in the area, rapid load growth appears likely to continue.

The forecast load growth rates for substations in the Southern Terminal load area range from 3 per cent to 7 per cent.

The main constraints facing the Southern Terminal load area during the next 10 years relate to shortfalls in substation capacity. The forecast rapid load growth will require five new substations to be established in the area over the next 10 to 12 years.

4.1.10 South Fremantle

The South Fremantle load area is relatively compact and mainly supplies the city and port of Fremantle. The load area extends south to Beeliar, east to the Kwinana Freeway and north to the Swan River. Substations in the area supply a mixture of commercial, industrial and residential customers and supply their peak load during summer.

This area is well established and is not expected to experience rapid load growth in the medium to long term. Load growth in the area is most likely to be from redevelopment of small areas of land or infill developments. The load growth in the area is forecast to be around four per cent per annum.

4.1.11 East Country

The East Country load area covers extensive, primarily Wheatbelt areas to the east of the Perth metropolitan area, bounded by Sawyers Valley in the west and Southern Cross in the east. The network supplies a mixture of Wheatbelt, water pumping and mining loads. The Mundaring-Kalgoorlie water pipeline is a significant portion of the load in this area. The main population centre of the region is at Northam and York. The peak loading for this area occurs during summer.

Analysis of the historic load growth and regional development information indicates that the substations in this area will have relatively low growth rates. The towns in this area are mostly mature and experiencing little growth. There is potential for industrial and commercial development in the region, which may accelerate demand at any of the substations and this potential requires close monitoring. The highest rates of growth in this area are predicted to occur at the substations in the areas near the coast and the Perth metropolitan area.

4.1.12 Eastern Goldfields

The Eastern Goldfields load area supplies mainly mining loads in the vicinity of Kalgoorlie. This load area is supplied by a radial 220 kV line and four other substations at Narrogin South, Kondinin, Merredin and Yilgarn.

Over the medium term, the Eastern Goldfields area has exhibited consistent growth. The nature of the mining industry means that demand for electricity is largely dependent on international commodity prices. Historically, load growth from year to year has varied with the demand for output from the mines but, over the medium term, has continued to grow.

The load growth predicted for the Eastern Goldfields area is approximately 3.4 per cent.

��

This trend includes the average growth of the mining loads. However, the mining loads potential to change the growth rate suddenly may necessitate rapid changes to the network reinforcement plans, and therefore require close monitoring.

The substations at Narrogin South, Kondinin, Merredin and Yilgarn supply areas that are mostly mature and experiencing insignificant growth. There is some potential for mining, industrial and commercial development in the region to accelerate demand at these substations.

The transmission capacity is limited by voltage and synchronous stability constraints due to large distances required to transmit power to this region, although in some cases thermal constraints may also arise. There are two interrelated constraints in the Eastern Goldfields:

• limiting power exports from local generators due to risk of voltage collapse; and

• limiting power transfer capacity due to risk of synchronous instability.

The constraint on power transfer capacity is the most significant issue facing the Eastern Goldfields load area over the next five years. A review of available options to provide a long-term solution to alleviate these critical constraints is being performed and the preliminary study results are presently under review.

4.1.13 North Country

The North Country region transmission network is connected to the rest of the SWIS via very long 132 kV transmission lines. The North Country load area is located north of the Perth metropolitan region, stretching from Regans Ford and Moora to Kalbarri. The load area extends into the Northern areas of the Wheatbelt, around 150 km east of the coast. The load area supplies a range of mining and industrial loads, as well as many rural centres and the main population centre of Geraldton. All the substations in this area supply their peak load during summer.

The load growth forecast for the substations supplying Geraldton is in the order of 7 per cent over the last six years.

The load growth is highest in the coastal areas of Geraldton, Kalbarri, Dongara, and Jurien. The load growth forecast for the remaining substations in the area is expected to be around one per cent.

The North Country network was designed to supply relatively small loads distributed over a large geographical area. It is currently not capable of transferring large amounts of power due to thermal, voltage and synchronous stability limitations. This constraint results in no capacity to connect large industrial customers and as such major reinforcement to this system is planned. Heavy reliance is placed on the use of generating plant at Mungarra and Geraldton to top up transmission capacity to meet the load demand. Western Power plans to continue using this generating capacity until major transmission reinforcement works are delivered.

4.1.14 Guildford

Guildford Terminal station was energised in December 2006. The substations in the Guildford Road area are Midland Junction, Darlington, Kalamunda and Forrestfield, which supply a mixture of commercial, industrial and residential customers with peak load during summer.

Many substations in the area have experienced rapid load growth over the last five years due to increased land development activity. In particular, the area supplied by Midland Junction substation and Forrestfield substation have experienced higher load growth due to new commercial loads from Westralia Airport, BCG and local residential subdivisions. As there is still much vacant land in the area, rapid load growth appears likely to continue. The forecast load growth rates for substations in the Guildford Terminal load area are around 3.5 per cent.


4.1.15 Load area constraints

Over the ten years considered by this report, a number of network constraints have been identified based on network planning assumptions. These are summarised in Table 4.1:

Table 4.1 Summary of Network Constraints.

Load area Immediate network constraints5

Bulk transmission Largely driven by generation location decisions

Northern Terminal Thermal capacity of transmission lines and substation capacity shortfalls

Muja Voltage constraints on long lines and distribution network limitations

Kwinana Thermal and voltage constraints on transmission lines and substation capacity shortfalls

Cannington Substation capacity shortfalls

Bunbury Thermal and voltage constraints on transmission lines and substation capacity shortfalls

Western Terminal Substation capacity shortfalls

East Perth Thermal capacity of transmission lines and substation capacity shortfalls

Southern Terminal Substation capacity shortfalls

South Fremantle Thermal capacity of transmission lines and substation capacity shortfalls

East Country Voltage constraints on transmission lines and substation capacity shortfalls

Eastern Goldfields Voltage and stability constraints on transmission lines – No further generation is possible in this region

North Country Highly sensitive to connection of generation and/or loads – No further generation is possible in this region

Guildford Terminal Thermal line constraints

5 Load areas can exhibit all of these types of constraint – the table highlights the most immediate concerns.

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The definition for committed projects used in the Statement of Opportunities is broadly used in this chapter, namely that a project is identified as committed if the following criteria are met:

• The project has purchased/settled/acquired land (or commenced legal proceedings to acquire the land) for the construction of the proposed development.

• Contracts for the supply of major components of plant and equipment have been finalised.

• All planning consents, approvals and licences have been secured.

• Business Case Approval has been achieved.• Construction has commenced, or a firm date

for construction has been set.

Please note that while the projects below have met the criteria, they may still change in timing, scope and cost prior to commencement as a result of revised forecasts and other factors. Only projects expected to cost more than two million dollars are included in this section. Projects less than two million dollars are shown in appendix D.

5.1 Committed transmission projects

5.1.1 Bulk transmission

Pinjar to Wanneroo – new 132 kV line construction

At medium to high system loads during 2007, an outage of two transmission lines supplying the Northern Terminal load area will have the potential to cause a cascade failure of numerous transmission lines in the load area, resulting in disruption of up to 22 per cent of the SWIS load. By 2009, an outage of a single transmission line will result in low voltages at Wanneroo and Yanchep substations.

In response, a 21 km, 132 kV transmission line will be constructed between Pinjar Power Station and Wanneroo Zone substation. This 132 kV transmission line is integral to the interconnection of the new Neerabup Terminal station with the 132 kV transmission network.

This project will be completed by Q1 2007.

� Projects (Approved, committed or commissioned)

In this chapter, information on major committed projects intended to address network constraints is presented. This chapter does not include information on the connection of new generators or major loads.

Figure 5.1 Diagram showing approximate location of 132 kV easement.


Shotts to Kemerton – stringing second side on 330 kV

A new generator will connect to the 330 kV network in the Collie region during 2008. Subsequent new generators will connect near Collie during 2009 and 2010.

The operation of the new generators will increase the loading of the 330 kV transmission lines that transfer power from the South-West generation sources to the Perth metropolitan area. As these lines become more heavily loaded, they become weaker and lose their ability to provide reactive support to the network, instead requiring reactive power for the network to remain stable.

Between Shotts and Kemerton terminal stations, a spare circuit is available on the existing transmission towers. This project involves stringing conductor along this spare circuit to allow the power flows through the network to be better balanced, particularly for 330 kV line outages. This will reduce the impact of particular contingencies on the network, increase the efficiency of the network and reduce the need for reactive power support within the metropolitan area.

By balancing the power flow along existing transmission lines and therefore reducing the load on the most heavily loaded line, the new transmission line will reduce network losses and greenhouse gas emissions during normal and contingency situations.

This project will be completed by 2008.

Reactive compensation southern load area

Increased generation connecting into the 330 kV network at Wagerup will increase loading of the 330 kV network between the South-West generation sources and Perth (the load centre). As these lines become more heavily loaded, they become weaker and lose their ability to provide reactive support to the network, instead requiring reactive power for the network to remain stable.

As the new generators will be highly efficient units entering the competitive generation market it is anticipated that they will operate at a relatively high utilisation levels. As a result, generators at Pinjar and Kwinana will be displaced. The Kwinana and Pinjar generators provide a vital source of reactive power support due to their close proximity to the load centre. These generators work to ensure secure operation of the network through faults and without them operating, the network is at risk of voltage collapse.

To alleviate this risk, capacitor banks will be installed within five metropolitan zone substations to increase reactive support levels and therefore minimise the extent of other, more expensive, reinforcements. A total of 40 MVAr of capacitor banks will be installed at Clarkson, Hay Street, Medina, Mandurah and Mason Rd substations.

Figure 5.2 Pinjar to Wanneroo – new 132 kV transmission line.

Existing 330 kV line section

New 132 kV line section


Northern Terminal

Mullaloo

Muchea

Landsdale

Pinjar

Henley Brook

Wanneroo

Clarkson

Yanchep

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This project will be completed concurrently with other projects that will reinforce the network to enhance network security. Installing these capacitor banks will not prevent the need for network reinforcements, but will reduce the extent of network reinforcement required.


Convert Southern Terminal to Kwinana line from 132 kV to 330 kV

New generator connections change the loading of parts of the network, causing a change in response of the network to contingency situations. This reduces the ability of the network to maintain stable operations, thereby reducing network security.

New generators will connect to the 330 kV network at Kwinana during 2008 and generators presently connected to the 132 kV network at Kwinana will be retired during 2008 and 2009. This will increase the loading of the 330 kV transmission lines that transfer power to the major terminal stations within the Perth metropolitan area and at the same time the network support provided by 132 kV generators at Kwinana will be lost. Under these circumstances, there will be a risk of voltage collapse within the network.

The network will be reinforced by converting the KW-ST 82 line from 132 kV to 330 kV. The line reinforces the 330 kV bulk transmission network by reducing the impact of the worst-case contingency by better balancing the load flows along the available 330 kV transmission lines.

This project is relatively inexpensive to implement as it takes advantage of an existing transmission line that presently operates at 132 kV, but is designed for 330 kV. The retirement of 132 kV plant at Kwinana releases capacity within the 132 kV network, allowing this line to be reconfigured to form part of the 330 kV network.


Southern Terminal – install third 330/132 kV transformer

A new 320 MW generator will connect to the 330 kV network at Kwinana and a new 200 MW generator will connect to the 330 kV network near Collie during 2008. At the same time, the Kwinana Stage B generators presently connected to the 132 kV network will be retired. These changes to the generation profile will increase the load transferred across the 330 kV network and will increase the loading of the 330/132 kV bulk transmission transformers supplying loads in the Perth metropolitan area.

The load increase on the bulk transmission transformers will be such that the failure of one transformer would result in the overload of the other transformers remaining in service. A third 330/132 kV 490 MVA transformer will be installed at Southern Terminal to ensure that there is adequate transformer capacity within the network to securely supply all load.

The installation of the 330/132 kV transformer will result in increased 132 kV fault levels at Southern Terminal and the surrounding zone substations. The resulting fault levels will be greater than the fault rating of existing plant. Fault limiting reactors will therefore be installed at Southern Terminal to mitigate the rise in fault levels and avoid the need for plant uprates.


Neerabup – establish new 330/132 kV terminal station

A new 320 MW generator will connect to the 330 kV network at Kwinana and a new 200 MW generator will connect to the 330 kV network near Collie during 2008. These new generators will increase the power flow through the 330/132 kV transformers within the Perth region, such that during an outage of one of the two Northern Terminal 330/132 kV transformers, the other transformer would be overloaded.

To cater for connection of the new generation and to prevent transformer overloading or load shedding, a new 330/132 kV 490 MVA transformer will be installed at a new terminal station at Neerabup, as shown in Figure 5.3.


The new terminal station will supply substations at Yanchep, Wanneroo, Clarkson and Joondalup, offloading the transformers at Northern Terminal and the 132 kV transmission lines supplying the Northern Terminal load area. The new terminal will provide substantial loss savings for the network.

The Neerabup terminal is optimally located to supply the areas of rapid load growth at the northern edge of the Perth metropolitan area.


Eastern Goldfields fault clearance time reduction

Recent system studies have identified that reducing the existing fault clearance times on a number of 132 kV circuits in Eastern Goldfields will improve voltage stability in the region, and increase power transfers up to a total of 90 MW on the 220 kV line at West Kalgoorlie Terminal. Protection relays and circuit breakers on the following 132 kV circuits need to be upgraded:

• West Kalgoorlie Terminal, Boulder circuit;• Boulder, Western Mining Smelter circuit; and• Boulder, Parkeston to Piccadilly Tee circuit.

This project is scheduled for completion by Q3 2007.

5.1.2 Bunbury

Margaret River – establish 132 kV transmission line and upgrade substation

Margaret River is an existing substation currently supplied via a 37 km radial 66 kV transmission line installed in 1967.

Reliability of supply to Margaret River is expected to reduce over the next few years due to the rapid growth in load in this region. When the radial line to Margaret River fails Western Power is unable to supply up to half the local load until the line is returned to service. The transmission line is mostly of overhead construction with the final 2 km section underground. The repair time for this line may be many hours depending on the location and type of fault. An outage of this nature would be of concern to Western Power and the local community.

Load growth at Margaret River has been consistently high over the last eight years and is predicted to remain at a high rate for the foreseeable future. The Margaret River load growth is currently around six per cent per year. By 2010 the expected load that will not be able to be serviced is expected to approach 10 MW. The magnitude of expected un-served energy to the community in the Margaret River area will be sufficient to justify the establishment of a new 132 kV line by 2010.

Figure 5.3 Neerabup – terminal establishment.





NorthernTerminalTo Mullaloo

Neerabup

To Yanchep Pinjar

To Muchea

To North Country

To Clarkson

Wanneroo

�1

This project involves the installation of a double circuit 132 kV line from Busselton to Margaret River and the installation of a 132/22 kV 33 MVA transformer at Margaret River. The two 66 kV transformers at Margaret River are 57 years old and are considered unreliable for further service. To maintain the security of the transformer supply it is necessary to replace the old 66 kV transformers with a new unit.

As part of this project a 132/22 kV 33 MVA transformer will be installed to utilise the extra security and capacity of the new 132 kV line. Land from the adjacent Margaret River Depot will be reclaimed to expand the existing Margaret River substation. The two existing old Margaret River transformers will be removed.

The existing Margaret River to Busselton 66 kV line will be removed as one side of the new double circuit 132 kV line will be initially energised at 66 kV. The new double circuit line will run adjacent to the existing 66 kV line to minimise community concern on the visual impact.

The establishment of the first 132 kV line to Margaret River is part of the plan to convert the 66 kV Margaret River substation to 132 kV. The complete conversion to 132 kV will not be undertaken until the existing 66 kV plant reaches the end of its economic life or has insufficient capacity to meet the load.

Figure 5.4 Diagram showing approximate location of 132 kV easement.

Figure 5.5 Margaret River Substation and depot – aerial photo.

Figure 5.6 Margaret River – substation reinforcement.




Margaret River

To Picton, Pinjarra

Busselton

New double circuit132 kV line, one side initially energised at 66 kV

remove 66 kV line


Pinjarra Substation – installation of second 132/22 kV 33 MVA transformer and two new feeder circuits

Pinjarra substation originally supplied Water Corporation pumping station, however over time, several residential loads have been connected to the substation. As there is only one feeder connected to Pinjarra substation and no 22 kV busbar, the ability to connect more loads to Pinjarra substation is limited. Due to high growth, driven by coastal developments, Mandurah substation cannot support the connection of substantial developments inland.

15 MVA of subdivision load is forecast to come online within the next five years. Pinjarra substation will be used to supply this load. Loads originally connected to Mandurah and Coolup substations may also be supplied from Pinjarra. This requirement has arisen due to existing capacity constraints on feeders from both Mandurah and Coolup substations and a need to supply these loads from a more reliable source.

This project requires installing an indoor switchboard by Q4 2007 (Stage 1), and installing a second 132/22 kV 33 MVA transformer by Q4 2008 (Stage 2).

Traditionally Pinjarra has been considered as a country substation and an outdoor arrangement has been adopted. With the expansion of the Mandurah metropolitan area, the installation of an indoor switchboard at Pinjarra will reduce visual impact to the community and prepare Pinjarra for a relatively quick and low cost expansion as the load growth continues to increase.

5.1.3 East Perth CBD

James Street to Milligan Street 132 kV cable replacement

The CBD loads are projected to continue to grow steadily and Milligan Street substation will reach its design capacity by 2008. The existing 132 kV cables supplying the Milligan Street substation will be upgraded. The new cables are expected to provide sufficient capacity to at least 2025.

This project is split into three stages:

• Stage one involves the replacement of cables from James Street Substation to a point just south of the railway line;

• Stage two involves the replacement of cables from a point just south of the railway line to a joint close to Murray Street; and

• Stage three will see the replacement of cables from a joint close to Murray Street to Milligan Street.

The Perth Rail Project required that stage one of the works be completed by June 2005. To minimise the number of cable joints, stage two was completed at the same time. Stage three will be completed by Q4 2007.

James Street Terminal, which is to be established by Q4 2016, will require strong 132 kV links with CBD substations which will strengthen supply to CBD. The replacement cables will provide some of this additional capacity.

Figure 5.7 Pinjarra Substation – aerial photo.

Figure 5.8 Routing of existing cables and approximate demarcation points showing three stages of their replacement.

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5.1.4 Cannington Terminal

Rivervale Substation – conversion to 132 kV

This project is necessitated by anticipated shortfalls in 132/22 kV transformer capacity at Belmont substation as well as shortfalls in the capacity at Cannington Terminal. The project is to be implemented in two stages. Stage one involves the installation of the first 33 MVA, 132/22 kV transformer, conversion of Rivervale’s load from 6.6 kV to 22 kV and decommissioning of the 66 kV substation plant; stage two involves the installation of a second 33 MVA transformer and transference of load from Belmont substation to Rivervale substation.

Stage one of the project is nearly completed and stage two will be completed in Q2 2007.

It is forecast that the 132 kV two-transformer Rivervale substation will have enough capacity to meet the area’s forecast load growth to about 2011, at which time a third transformer will be installed.

Cannington to Rivervale – 132 kV line uprate

The conversion of Rivervale substation to 132 kV required the establishment of a new Cannington to Rivervale 132 kV line. The line is currently rated for 166 MVA. In the event of an outage of the supporting Cannington to Welshpool 132 kV line, it is forecast that the thermal capacity of the Cannington to Rivervale line will exceed capacity by summer 2007. It is therefore planned to uprate the Cannington to Rivervale line to 242 MVA by upgrading the overhead conductor.

This project will be completed in Q4 2007.

Reinforce Cannington 132 kV transmission network

This project reinforces the Cannington Terminal 132 kV network via the establishment of a Cannington Terminal to Belmont 132 kV line and Welshpool-to-Belmont/Rivervale 132 kV lines. The project will ensure the continued secure operation of the transmission network as generation and demand grow.

All Cannington transmission lines operate within their thermal ratings under normal operating conditions.

However, as load increases, some of the lines will need reinforcement to prevent them operating outside their designed ratings during certain contingencies.

The project will involve reinforcement and re-configuration of the network. As the work will be completed at the same time that Kewdale substation is commissioned, the new transmission lines will incorporate the connection of the new substation. The project will form the Cannington Terminal to Kewdale, Kewdale to Belmont and the Welshpool to Belmont/Rivervale 132 kV lines.

This project will have the added advantage of re-enforcing system security for Cannington and East Perth terminal load areas, including Perth CBD. Without the network reinforcements proposed, the security of the 132 kV supply to the CBD and the rest of the East Perth and Cannington Terminal load areas will be jeopardised under certain contingencies, possibly resulting in load-shedding or voltage collapse.


Kewdale – establish new substation

The establishment of Kewdale substation is required to meet the area’s forecast demand for electricity. The area to be supplied by the future Kewdale substation consists largely of industrial loads and is currently supplied from Belmont and Welshpool substations. With an estimated load growth rate of about four per cent, it is forecast that the area’s demand for electricity will exceed Belmont and Welshpool substations’ capacity by summerr 2008/09.

Analysis of a number of options determined the establishment of a new substation at Kewdale to be optimal. Western Power already owns a site in the area about 200m from an existing 132 kV line, which minimises transmission costs for the establishment of the new substation. Also, the new substation site is located about halfway between Belmont and Welshpool substations, which would enable it to effectively offload demand from either of the substations. This has the added advantage of circumventing considerable expenditure on adding new feeders to Welshpool substation. The substation will contain one 33 MVA transformer, with capacity for two more 33 MVA transformers.



Bentley: establish new substation

Load forecasts have shown that the Cannington 66 kV supply will reach its limit in 2011 with Collier Street and Clarence Street substations also forecast to exceed capacity. The establishment of a new 132/22 kV Bentley substation next to Curtin University will relieve the capacity shortfall. The substation will contain two 33 MVA transformers, with capacity for a third 33 MVA transformer (Refer to Figure 5.10).

The new Bentley substation will be supplied by two one km, 132 kV cables that cut into the existing Southern Terminal to East Perth 132 kV line. The location of the new substation allows it to supply Curtin University, the area’s major load. About 10 MVA of Curtin load will be transferred from Collier Street substation to the new Bentley substation. Up to 20 MVA of additional load from planned developments at Curtin and in surrounding areas is forecast to come on line between 2007 and 2010. It is also planned to transfer some load from Tate Street substation to Bentley in 2009.

The Bentley substation will be completed in Q3 2007 to meet the University requirements.

5.1.5 Eastern Goldfields

Piccadilly Substation – installation of third transformer

Projected load growth indicates that Piccadilly substation will exceed capacity by December 2008. This substation is located in a high load growth area with a large number of residential and commercial developments in the Kalgoorlie CBD. This will contribute to a higher than expected deficit of capacity and increased risk of power supply interruptions to customers if a third transformer is not installed by summer 2008-09. Any loading above the firm capacity would expose the Piccadilly load to an increased risk of shedding.

This project requires:

• installation of a third transformer;• installation of a new 11 kV switchboard; and• distribution reinforcement and other

associated works.

The estimated completion date for this project is Q4 2008.

Figure 5.9 Future transmission line layout with Kewdale substation.



Cannington Terminal

Rivervale

Kewdale

Belmont

Welshpool

East Perth

Northern Terminal

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5.1.6 Kwinana

Waikiki – establish zone substation

The electrical demand in the Rockingham area has increased substantially over the recent past. With two major infrastructure projects due for completion in the near future, the Perth-Mandurah railway and the extension of Kwinana freeway to Mandurah, it is expected that load growth will be sustained at the same rate and may increase in the future.

The load forecast indicates that Rockingham substation will reach its capacity during summer 2007-08. Studies have confirmed that a new substation at Waikiki will best accommodate the increase in power demand.

Western Power commissioned an external engineering consultant to undertake a siting study on five different sites, investigating the potential environmental, economic, technical and social issues associated with this substation.

This project will include the establishment of a new substation with one 132/22 kV 33 MVA transformer at Waikiki and line works to cut into the Rockingham to Mandurah 132 kV line as shown in Figure 5.11.

Much of the new loads are expected to be around residential development areas of Baldivis, Port Kennedy and Secret Harbour. These suburbs are located more than 10 km from the existing Rockingham substation. It is therefore preferable to establish a new substation at Waikiki to meet this demand.

Mason Road Substation – install second transformer

Mason Road zone substation supplies predominantly industrial load and demand has been steady in the last few years. A number of new large industrial loads are scheduled to commence early in 2007 and others are planned for end of 2007.

Detailed studies have shown that the most effective and economical long term solution for Mason Rd is to install an additional 132/22 kV 33 MVA transformer and an indoor 22 kV switchboard.

Project completion is expected by Q4 2008.

Figure 5.10 Bentley – substation establishment.



SouthernTerminal

East Perth

Bentley


5.1.7 Muja

Katanning Substation – fourth transformer installation

The load at Katanning substation has been steadily growing at a rate of around 2.4 per cent annually and the peak load has been near to the substation capacity for a number of years. During 2001, the transformers at Katanning were fitted with additional cooling fans to increase the substation capacity. During 2003, Katanning substation was loaded to 87 per cent of its capacity. It is forecast that the substation load will exceed capacity by summer 2007/08.

The scope of works includes the installation of a new 66/22 kV 33 MVA transformer, installation of associated secondary plant including required protection equipment and rearrangement of the 22 kV busbar at Katanning to accommodate the new transformer.

Following the installation of the new transformer, the substation will normally operate with the new transformer supplying the load. The three existing 5 MVA transformers will be used as back-up to supply the load in the event of a failure of the new transformer.


Muja to Bridgetown/Manjimup – construct new 132 kV line

Due to the limited capacity of the 66 kV network to provide back–up supply to the 132 kV network, a project is presently underway to construct a second 132 kV line from Muja to Bridgetown and Manjimup. This line will use part of the existing 66 kV line routes and has already resulted in decommissioning of the 66 kV substations at Yornup and Quinninup.

This project includes the following scope of work:

• line route investigation, approval, easement acquisition and line route preparation;

• construction of around 45 km of new 132 kV line and conversion of around 90 km of existing 66 kV line to 132 kV;

• construction of new 132 kV circuits at Muja, Bridgetown and Manjimup substations;

• installation of new 22 kV feeder circuits at Bridgetown and Manjimup substations; and

• distribution works to transfer load from Yornup and Quinninup substations to Bridgetown and Manjimup substations.

This project will be completed in Q4 2007.

Figure 5.11 Waikiki – substation establishment.



Mandurah

Meadow Springs

Rockingham

Waikiki

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5.1.8 North Country

Rangeway – establish new substation

The Geraldton CBD is presently supplied from the Durlacher Street 33/11 kV substation. During summer 2004-05, the CBD load exceeded the substation firm capacity. As there is no space to extend this substation, a new 132/33 kV substation located at Rangeway is under construction.

The new substation is located in a high-load growth area where there is a dramatic increase in load demand particularly from the Geraldton Port. It will also supply the Geraldton Port until a new, dedicated substation to accommodate the increasing Port load is established.

This project involves the establishment of a new Rangeway 132/11 kV substation about 2 km south of Durlacher Substation (Refer to Figure 5.12). The substation comprises a single 132/11 kV 33 MVA transformer supplied via a new 132 kV double-circuit line from Geraldton, about 7 km in length. Initially only one Geraldton-Rangeway line circuit will be energised. The second circuit will be required in the future as part of the integrated reinforcement plan for the Geraldton area. This plan involves the use of the second circuit to create a future Geraldton-Rangeway-Chapman-Geraldton 132 kV ring when a second 132/11 kV transformer is required at Chapman substation.

This new zone substation will be completed in Q1 2007.

5.1.9 Northern Terminal

Landsdale Substation – install third transformer

Landsdale Substation was commissioned with a single transformer in Q4 2001 and a second transformer was commissioned in Q4 2003. Load was originally transferred to Landsdale from Arkana, Malaga, Mullaloo and Beechboro substations for the summer of 2001-02. Additional load was transferred from North Beach and Mullaloo Substations to Landsdale during 2003.

The forecast load growth rate for Landsdale Substation is high due to rapid residential development in the area. The load at Landsdale is forecast to reach the substation capacity by 2006. A third 132/22 kV 33 MVA transformer will be completed in Q4 2006.

By 2011, it is forecast that the load supplied by Landsdale Substation will exceed the substation capacity. At this time it will be necessary to either expand the capacity of Landsdale Substation or to transfer load to an adjacent site.

As Landsdale will be fully developed and the existing substations in the area are also heavily loaded, the preferred option is to establish a new substation in the area. It is planned to establish Wangara Substation to offload Landsdale Substation by 2011.

Figure 5.12 Geraldton – Rangeway substation establishment.




To WWF andMGA

Durlacher St

Chapman

Geraldton

New 132 kV line in 2006

132 kV line proposed for 2010

Rangeway


Morley Substation - install third transformer

The forecast demand at Morley Substation will exceed capacity by 2008. To expand capacity, a third 132/11 kV 33 MVA transformer at Morley Substation will be installed. Following installation of the third transformer, the substation will have sufficient capacity until around 2019. This project will be completed by Q1 2008.

Clarkson – establish new substation

Clarkson Substation is required by Q4 2006 to provide additional capacity to offload Wanneroo Substation and will supply load to the area around the suburbs of Clarkson and Quinns Rocks.

The load will be primarily residential but may include some light industrial loads located around the Flynn Drive industrial estate.

Wanneroo and Yanchep substations presently supply the load in this area and transmission forecasts indicate that these substations have sufficient capacity to supply the area until 2007.

The substation will initially consist of a single 132/22 kV 33 MVA transformer with capability for future expansion. Once established, the capacity of Clarkson Substation will be gradually expanded by installing the second and third 132/22 kV 33 MVA transformers in 2010 and 2014.

The new substation will require a 132 kV line cut

in along the existing Wanneroo to Yanchep 132 kV line as shown in Figure 5.10.

The load at Clarkson Substation is forecast to again reach its capacity by 2023. At this point, a new substation will be required. The new substation will be established in the Two Rocks area. Load will be transferred from Yanchep to Two Rocks, releasing capacity at Yanchep to offload Clarkson Substation.

Joondalup – establish new substation

Joondalup Substation (with a single 132/22 kV 33 MVA transformer) will be required by 2010 to provide additional capacity to offload Mullaloo and Wanneroo substations.

The site for Joondalup Substation is located adjacent to the Joondalup city centre and this substation is proposed to supply a mixture of commercial, light industrial and residential load in the immediate vicinity. The establishment of Joondalup Substation may be brought forward if any large block loads require connection before 2010.

As shown in Figure 5.13, the new substation will require a 132 kV line cut in along the existing Mullaloo to Wanneroo 132 kV line. Forecasts predict that once the substation is established load growth at Joondalup will require the second transformer by 2012 and the third transformer by 2016.

Figure 5.13 Joondalup – substation establishment.



Joondalup

Yanchep

Clarkson

Wanneroo

Mullaloo

To Pinjar

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Yokine Substation – install third transformer

Yokine Substation supplies a relatively mature load area, however the historical and forecast load growth rate is very high for an established area. Residential lot development projections predict that demand will reach substation capacity by 2006.

Load was transferred from Yokine substation to Morley substation in 2005. This will relieve overloading of Yokine until 2008. By 2008, it will be necessary to either transfer additional load from Yokine substation or to expand the capacity of Yokine Substation. Recent investigations have determined that although Yokine is a small site, a third 132/11 kV 33 MVA transformer can be accommodated, and the plan is to install this transformer by Q4 2008.

Henley Brook – establish new substation

The northern suburbs of Perth have been developing rapidly over the past decade. This development has included residential, commercial and light industrial and reflects population growth of around 3.5 per cent and electricity growth of over 6 per cent per year.

Beechboro Substation is located on the fringe of the metropolitan area and has been supplying loads across a broad geographical area. Residential developments have increased load at Beechboro over the last few years and this forecast is set to continue.

Henley Brook Substation, with a single 132/22 kV 33 MVA transformer, will be required by Q4 2008 to provide additional capacity to offload Beechboro Substation. It is anticipated establishing Henley Brook Substation will not only relieve overloading at Beechboro Substation but will also substantially benefit distribution development on existing heavily loaded, long feeders that supply the Beechboro area.

Load forecasts indicate that a second transformer will be required at Henley Brook by 2013 and the third transformer will be required by 2019. In order to establish Henley Brook Substation, a 4.4 km double circuit line to cut into Northern Terminal to Muchea will be required as shown in Figure 5.14.

Padbury – establish new substation

The northern suburbs of Perth have experienced strong growth in residential, commercial and light industrial load resulting in electricity growth of 6 per cent per year. Load forecasts demonstrate that the load at Mullaloo will exceed substation capacity by 2007 and the load at North Beach will exceed substation capacity by 2009. Therefore additional capacity in this area is required before 2007.

Analysis has shown that the most effective way to supply additional load in the Mullaloo and North Beach areas is to establish a new substation in Padbury. The substation will initially consist of a single 132/22 kV 33 MVA transformer with capacity for future expansion.

Figure 5.14 Henley Brook – new substation.



NorthernTerminal

HenleyBrook

MucheaPinjar

Figure 5.15 Padbury – new substation.



NorthernTerminal

Landsdale

Mullaloo

Padbury

NorthBeach


Due to the magnitude of load that needs to be transferred from North Beach and Mullaloo, the second transformer will be required at Padbury by Q4 2008. Load forecasts indicate that the third transformer will be required at Padbury by 2009 and that the load at Padbury will exceed the full design capacity of the substation by 2015.

The new Padbury substation will require a 132 kV line cut in along the existing North Beach to Mullaloo 132 kV line as shown in Figure 5.15.

This project is scheduled for completion in Q4 2006.

5.1.10 South Fremantle

Amherst Substation – third transformer installation

Load growth in the area surrounding Amherst Street substation is expected to increase beyond the existing Amherst 132/22 kV substation capacity during 2008. To meet customer demand, the installation of a third 33 MVA transformer is expected to be completed by Q4 2007.

South Fremantle Terminal to Kwinana Terminal line – conversion to double circuit

If an outage of the South Fremantle Terminal to Kwinana Terminal line occurs, the line may be overloaded. To ensure this does not happen, the South Fremantle Terminal to Kwinana Terminal split phase line will be converted to a double circuit. This project will be completed in 2007.

Bibra Lake – establish new substation

The forecasted load in the area supplied by the existing Australian Paper Mills Substation is increasing as a result of new residential and commercial developments. Load forecasts show that this substation will be unable to supply the maximum summer demand in 2007-08. There is no space available at this substation for future expansion to increase capacity.

To supply the increased demand, Bibra Lake Substation will be established to support the Australian Paper Mills substation. The substation will cut into the existing 132 kV line from Kwinana to South Fremantle. The site will consist of a single 33 MVA transformer with potential for additional capacity.

Project completion is scheduled for Q4 2007.

5.1.11 Southern Terminal

Byford Substation – install third transformer

Byford Substation supplies predominantly residential and commercial customers. The load has increased rapidly over the last two years due to numerous commercial/industrial developments and new residential lot releases in the area. Two new shopping centres will be operational over the next two years and the Metropolitan Development Program (published by Department for Planning and Infrastructure) has indicated that the area supplied by Byford Substation will have one of the

Figure 5.16 SF-KW 82.



Kwinana Terminal

South FremantleTerminal

Figure 5.17 Bibra Lake – substation establishment.



Kwinana

South Fremantle

Bibra Lake

Substation cut into KW-SF 132 kV line

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highest number of new residential developments among Perth suburbs. By December 2007, the substation may not be able to support the summer peak demand for the area.

Detailed studies have shown that the most effective and economical long term solution for the Southern area is to install an additional 132/22 kV 33 MVA transformer at Byford Substation and an indoor 22 kV switchboard.


Murdoch – establish new substation

The existing Riverton Substation has experienced rapid growth with an average of 9 per cent per year over the last five years. Increasing population as a result of higher housing density, new developments at Murdoch University and the surrounding commercial areas is likely to continue in the foreseeable future. Riverton substation is approaching its capacity and based on load forecasts will be exceeded by summer 2006-07. A new substation is needed to support this increase in electrical demand.

The new Murdoch Substation will be situated on the north-eastern corner of Murdoch Drive and Farrington Road. This project will require the establishment of a new substation at Murdoch with one 33 MVA transformer and line works to cut into the Southern Terminal to Riverton 132 kV line.

The project will be completed in Q4 2006.

Southern River – establish new substation

Gosnells and Canning Vale substation load areas have experienced rapid growth over the past two years. Load supplied by these substations has increased by about 30 per cent and 20 per cent respectively since summer 2001-02. With increasing population and a relatively large amount of vacant land available for developments, it is expected that growth in this region will continue for the foreseeable future, with the substations approaching their capacity limit by summer 2006-07 and summer 2007-08 respectively. A new substation is needed to support this electrical demand.

The new Southern River substation is strategically placed to offload both Gosnells and Canning Vale substations, and also to supply future load growth in the area.

The substation was completed in Q3 2006 and is situated approximately 4 km south-west of the Gosnells substation and 5.5 km south-east of the Canning Vale substation. The substation site is also near the existing Gosnells-Byford 132 kV transmission line.

This new substation comprises one 33 MVA transformer and is supplied from a cut into the into the Gosnells-Byford 132 kV line (Refer to Figure 5.18).

Latest demand forecasts predict that Southern River Substation will be overloaded by summer 2007-08. This future demand will require the installation of a second 132/22 kV 33 MVA transformer at Southern River Substation by Q4 2007.

Figure 5.18 Murdoch – substation establishment.


Existing 132 kV line sectionMurdoch

Southern TerminalRiverton

Substation cut into ST-RTN 132 kV line


Southern River Substation – cut into Southern Terminal to Wagerup/Alcoa Pinjarra 132kV line

The capacity of the Southern Terminal to Cannington Terminal 132 kV line will be exceeded by summer 2008-09 with a single outage of either the Southern Terminal to Kenwick Link 330 kV line, Kenwick Link 330/132 kV transformer or Kenwick Link to Cannington Terminal 132 kV line.

Southern River Substation is approximately 1.3 km from the Southern Terminal to Wagerup/

Alcoa Pinjarra 132 kV line. By cutting this line into Southern River Substation, the loading of the Southern Terminal to Cannington Terminal 132kV line will be reduced as power will be flowing into Cannington Terminal from Gosnells substation (Refer to Figure 5.19). This will ensure the Southern Terminal to Cannington Terminal 132kV line will have sufficient capacity until other planned reinforcements are implemented.


Figure 5.19 Southern River – establish new substation.




Gosnells

Southern Terminal

Riverton

SouthernRiver

Byford

Murdoch

Cockburn Cement

Canning Vale

Cannington Terminal

To Pinjarra and Wagerup

KenwickLink

Southern River – cut into ST-WGP/APJ line




Gosnells

Southern Terminal

Riverton

SouthernRiver

Byford

Murdoch

Cockburn Cement

Canning Vale

Cannington Terminal

To Pinjarra and Wagerup

KenwickLink

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5.1.12 Western Terminal

Cottesloe – upgrade existing substation to 132 kV

The upgrade of the 66/6.6 kV Cottesloe Substation to 132/11 kV is required to increase the substation’s capacity as well as the local distribution network capacity to meet forecast local demand. Forecasts predict that the Cottesloe area’s demand will exceed the existing substation capacity by December 2008.

This project requires the conversion of Cottesloe’s operating voltages from 66/6.6 kV to 132/11 kV and replacement of the substation’s existing transformers with higher capacity transformers by Q4 2009. The substation will contain two 33 MVA transformers, with provision for a third 33 MVA transformer.

The project has the additional advantage of avoiding expenditure on maintenance of aged 66 kV plant. Most of Cottesloe’s 66 kV plant is more than 35 years old and would require extensive maintenance or replacement within the next 10 years.

Wembley Downs – increase substation capacity

This project is required to increase Wembley Downs Substation and the associated distribution network capacity in order to meet forecast local demand. Demand is expected to exceed the existing substation capacity by Q4 2008.

The conversion of the Wembley Downs

distribution network to 11 kV and replacement of existing transformers with 32 MVA 66/11 kV transformers will increase system capacity. This project will make use of ex-North Perth 66/11 kV transformers. It also has the advantage of avoiding major expenditure on new transmission lines.

This project will be staged and the total work to be completed by Q4 2009.

5.1.13 Guildford Terminal

Forrestfield Substation – install second transformer

Forrestfield Substation supplies predominantly industrial and commercial customers. Growth has been low, until recently when loads were transferred from Midland Junction and Kalamunda.

Major commercial and industrial developments are in progress within the Perth Airport land holding and it is therefore necessary to expand substation capacity to cater for this increase in demand.

Studies have shown that the most effective and economical solution to support the Guildford Terminal area in the long term is to install an additional 132/22 kV 33 MVA transformer at Forrestfield Substation by Q4 2007.

Westralia Airports Corporation has indicated that an extra 40-50 MVA will be required over the next eight to ten years. A new substation will be required at the airport to cater for the growth.

Figure 5.20 Cottesloe – convert to 132kV substation.

Amherst St

Western Terminal

CottesloeTee

Nedlands

To NorthFremantle

Cottesloe

To Northern Terminal




To Cook St

Figure 5.21 Guildford Terminal to Midland Junction substation – construct second 132kV line.



Midland Junction

GuildfordTerminal


Guildford Terminal to Midland Junction Substation – construct second 132 kV line

Major commercial and industrial developments within Perth Airport land holding are the main drivers of this project. With the forecast of extra 40 MVA for Perth Airport in the next 10 years, it is necessary to reinforce the transmission system, which is currently supplying the substations in the areas.

Studies have shown that the most effective and economical solution to support the Guildford Terminal area in the long term is to build an second 132 kV line between Guildford and Midland Junction Substation.


Kalamunda Substation – install third transformer

Kalamunda Substation supplies predominantly residential customers. Load growth has increased steadily at 2.4 per cent per annum due to new residential lot releases in the area and it is forecast that Kalamunda substation will reach its capacity by December 2009.

Detailed studies have shown that an additional 132/22 kV 33 MVA transformer at Kalamunda Substation is the optimal reinforcement option.

Project completion date is scheduled for Q4 2009.

Darlington Substation – install third transformer

Darlington Substation supplies predominantly residential customers. Load growth has increased steadily at 3.4 per cent per annum due to new residential lot releases in the area. Darlington Substation is forecast to reach its capacity limit by Q4 2009.

Detailed studies have shown that it will be costly and inconvenient for Darlington Substation to offload to other substations because of its surrounding parks, rivers and bushland. The area will be supported with an additional 132/22 kV 33 MVA transformer at Darlington Substation.


5.1.14 East Country

No major projects have been committed.

5.2 Committed distribution projects

Due the large number of distribution assets, the total list of individual projects is too extensive to detail in the annual planning report. The following information covers only the major distribution programs initiated by Western Power to improve overall system reliability and to provide network reinforcement.

Distribution capacity capital expenditure

Distribution capacity capital expenditure includes all demand-driven reinforcement of the distribution system. The reinforcement is essentially required to increase distribution network capacity to supply ongoing load growth. The growth in load is across most areas of the network with significant increases in inner city redevelopment areas, in outer metropolitan residential development areas and in country coastal regions.

The budget provision is divided into HV distribution capital expenditure and LV distribution capital expenditure. HV distribution capital expenditure primarily includes all expenditures relating to distribution feeder reinforcement to supply load growth and to interconnect new zone substation developments. Feeder reinforcements may include new feeders, feeder capacity upgrades, optimisation of network configuration, the installation of voltage regulators, reactive compensation, and automated network switching devices.

LV distribution capital expenditure includes upgrade of distribution transformers and transformer LV exit circuits. High network load growth creates network capacity, voltage and reliability constraints. Distribution capital expenditure projects are developed to reinforce the system to overcome these constraints. Reinforcements are planned in accordance with satisfying distribution planning criteria as outlined in the technical rules.

The reinforcement projects specifically address the following network constraints:

• the presence of small cross-section conductor or cable in close proximity to zone substations, which impose thermal constraints on feeder ratings or cannot sustain the fault levels at that location;

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• distribution feeder thermal overloading due to customer load growth in specific areas, resulting in either the construction of additional feeders or increasing the HV distribution feeder voltage from 6.6 kV to 11 kV or 22 kV;

• distribution feeder voltage constraints due to load growth in rural areas, resulting in either the installation of voltage regulators, capacitors, or the construction of additional feeder sections;

• the exceeding of distribution planning guidelines requiring feeder exit cable loads to be kept below 80 per cent of their background normal cyclic rating (NCR), so that one feeder can be offloaded to four other feeders;

• the need to interconnect new greenfields zone substations in the distribution network. Each new greenfields zone substation requires three or four feeders to be constructed and commissioned;

• increasing fault levels in the metropolitan area due to the penetration of underground cables and the integration of new zone substations. The existence of underrated conductors can also cause under voltage situations which impact on power quality;

• the need to construct new distribution feeders to supply new developing subdivisions in the outer areas of the network;

• reinforcement of feeder interconnections and reconfiguration of networks to improve reliability and backup performance; or

• overloaded distribution transformers and LV circuits.

Table 5.1 lists the notable distribution capacity expansion projects over the next two years. This is not a comprehensive list of all Western Power’s distribution projects.

5.2.1 State Underground Power Program (SUPP)

In 1994, severe storm damage to the overhead distribution system left many thousands of customers in the metropolitan area and the southwest region without power for several days. As a result, the State Government established a Steering Committee comprising representatives of the Office of Energy, Western Power and the WA Local Government Association, to investigate undergrounding the overhead distribution system.

Undergrounding of the transmission system was not included in this due to the very high costs and robustness against damage. A pilot program of 4 projects started in 1996 established the technical and financial viability of undergrounding local power lines.

In 1998 the Government established two strands to the program – major residential projects and the smaller localised enhancement projects with a commitment to having half the Perth metropolitan area serviced by underground power by the year 2010. This target is to be achieved by the combination of the program and new property subdivisions that must only use underground power.

Each major residential project is funded jointly by the State Government, Western Power (25 per cent each) and 50 per cent by the relevant local government. For low socio-economic localities, the local government funds 35 per cent of the total cost. The base cost is around $7,000 - $8,000 per electrical meter for 1,000 to 1,500 meters in a typical project. Local governments usually fund these projects through rates on property owners.

For localised enhancement projects the cost is about $500/metre and the State Government and Western Power equally fund up to $250,000 on a dollar per dollar basis with the local government.

The program has now completed 28 major residential projects, costing $167 million and undergrounding power to 56,000 electrical meters – about 10 per cent of the original overhead distribution system. This has been achieved through the pilot (four projects), round one (eight projects), round two (12 projects) and round three (four projects). Some 18 localised enhancement projects have now also been completed, involving $6.8 million expenditure and undergrounding 15 km of overhead lines in focal areas of communities.

There are five major residential projects in round three now in progress (Port Hedland, Nedlands East, Fremantle, Highgate East and Wembley Downs), with Como East due to commence in early 2007. In 2005 the Minister for Energy approved nine localised enhancement projects for round three (Balingup, Boddington, Bunbury, Geraldton, Lake Grace, Manjimup, Mt Barker, Nannup and Waroona) with Bunbury, Mt Barker and Balingup now complete and Nannup under construction.


Seven major residential projects were announced for round four, by the Minister for Energy in March 2006 after 89 applications from local governments (Mt Pleasant North, Palm Beach, Gosnells South, Wilson West, Withers (Bunbury), Balcatta & Greenwood West). Round four will run from 2007 to 2010.

5.2.2 Reliability Improvement Program

Western Power’s reliability improvement plan was established in 2004-05. The plan established solid and robust business rules and processes for the effective, practical, cost effective and efficient delivery of reliable power to all Western Power customers. To ensure that reliability performance is constantly monitored and improved, it needs to be recognised that governance and management systems must be established to

• identify process/systems gaps;• introduce and manage change; and • develop and enhance systems, processes,

procedures and resources.

The reliability improvement plan is applicable to all processes that fit within the Key Process of Delivery of Electricity to Western Power’s customers. The Key Process Map for the Delivery of Electricity is represented in Figure 5.23.

The plan establishes management and governance frameworks for issues relating to power reliability, including, but not limited to, processes, measurements, equipment, structures, communication systems and customer/stakeholder’s expectations.

Figure 5.22 Before and after undergrounding of overhead distribution lines.

Figure 5.23 Key process map for delivery of electricity.

Plan Design Procure Build Manage& Monitor

Maintain

Operate

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Reliability performance over the past three years has improved by approximately 16 per cent since June 2004, including an 11 per cent improvement over the past 12 months. This is indicative of the impact that recent reliability driven initiatives are having on the network as well as favourable weather conditions over the past 12 months.

The reliability improvement program consists of a number of a number of distribution projects as described below:

40 Worst Feeders Program

The 40 Worst Feeders Program targets feeders that contribute the most towards SAIDI across the South-West Interconnected System.

The intention is to inspect every indentified feeder to validate asset conditions and suspected root causes of unreliability and to have them fixed within agreed times for specific asset severity conditions.

A dedicated Reliability management team is responsible for the program. It analyses the performance of the feeders and recommends solutions to existing problems. The team monitors the program of works on the feeders to ensure that issues are identified and addressed promptly.

Rogue Feeder Program

The intention of this strategy is to engage dedicated and experienced resources to continuously monitor the performance of feeders and conduct regular line patrols to ensure that obvious or potential fault situations are detected prior to a fault occurring.

A total of 20 feeders were selected as part of this program for 2005-06. These feeders have all been inspected and subsequent inspection cycles (in accordance with the program) are being planned. Corrective action has been fully implemented on all critical asset conditions. A further 20 feeders have been selected for the 2006-07 financial year. Inspection of these feeders is scheduled for Q4 2006.

Targeted network reinforcement

This strategy targets reinforcement activities on poor reliability areas across the SWIS and includes feeders within and outside the 40 worst feeders list. This is a recently developed strategy where considerable work is taking place to finalise the scope of work, processes and procedures. Progress in this strategy has varied between country and metropolitan regions due to the nature of the reinforcement activities being applied as well as the resource skills involved.

Distribution automation

Distribution is in the midst of a multi-year roll out of distribution automation equipment that will assist in improving the network reliability. The equipment includes remotely controlled and monitored reclosers, pole-top switches, fault indicators, voltage controllers and capacitor banks. The distribution automation equipment allows operators in East Perth Control Centre to quickly identify faults, and remotely operate switches to isolate the faulted line section and reconfigure the network to restore power around the faulted line to minimise the extent of the outage. The operators can also remotely monitor and adjust line voltage and by changing capacitance values and transformer settings.

Western Power is rolling out radio-based infrastructure to allow data communications to these distribution automation devices. Radio bases are being installed at strategic locations in both metro and country locations to provide coverage to the pole mounted distribution automation devices. The radio bases poll the remote data to retrieve the line voltage and current information and also issue commands to open and close pole-top switches or change capacitor or transformer settings.


Faulted equipment repair

This strategy aims to establish a governance framework, process, guidelines and supporting systems to manage the implementation of repair works on faulty operational assets in the network. Considerable progress has been achieved in the following areas:

Faulted equipment repair.

Establishment of prioritisation framework

100 per cent complete

Establishment of works management process


Implementation of work instructions, training and procedures


Backlog management process implementation


Implementation of corrective works


All faulted pole-top switches, cables and ring main units will be repaired by Q1 2007.

Emergency response generators

A total of 6.6 MVA of emergency response generation has been secured for the 2006-07 summer period. This complements the existing 6.7 MVA used for daily business operations and is estimated to be sufficient to respond to any increased fault activity during hot summer months as well as providing contingency coverage for capacity or reliability enhancement projects that do not meet their scheduled implementation date.

Regional Power Improvement Program

This program targets work that provides measurable improvements in electricity supply in rural areas where reliability is unsatisfactory and not likely to be addressed through any other Western Power program of work.

$20 million of reliability improvement projects across rural networks in North Country and South Country regions have been identified for phase 3 of the project. Construction work will commence in Q1 2007 (2007-08 to 2008-09). RPIP phase one and (two conducted from May 2005 to May 2006) has resulted in an average 14.5 per cent improvement for the feeders involved. This compares favourably to an improvement of only 6.7 per cent across the entire rural network over the same period.

Enabling strategies

In addition to the above programs a number of strategies that enable the effective management of reliability performance on a day to day basis have also been addressed as part of the Reliability Improvement Plan. These strategies include system enhancement projects, protection reviews, reliability complaints and issues management, statistical analysis and load-forecasting models.

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Table 5.1 Committed large distribution projects (2007 – 2009).

Load area Substation Committed projects Project drivers

Scheduled completion

Bunbury Bunbury Harbour

Reinforcement of the distribution network. This project involves reinforcement of the feeder network to provide for ongoing load growth.

Capacity, voltage, reliability

Q4 2007

Cannington Terminal

Rivervale & Vic Park

Distribution network upgrade from 6.6 kV to 22 kV. Upgrade the local distribution network from 6.6kV to 22kV. This will also increase capacity and provide for ongoing load growth.

Capacity Q4 2008

Cannington Terminal

Sawyer’s Valley

Reinforcement of 22 kV network to improve reliability and capacity. This project is a targeted network reinforcement and network reconfiguration to improve network capacity and reliability performance.

Capacity, reliability, voltage

Q4 2008

Kwinana Waikiki Distribution works for new Waikiki Substation connection. The new feeders will provide for load growth in the Rockingham and Baldivis areas.

Capacity, reliability

Q4 2007

North Country

Chapman New feeder to off load Waggrakine feeder cable. This feeder is required to support the load growth arising from new residential subdivisions.


Q4 2007

Northern Terminal

Henley Brook

Distribution works for new Henley Brook Substation connection. Establishment of Henley Brook 132/22kV substation, new feeders will provide for load growth in the Henley Brook area.

Capacity, reliability, voltage

Q4 2007

Northern Terminal

Joondanna Distribution works for new Joondanna Substation connection. Establishment of Joondanna 132/22kV substation, distribution works to create 4 feeders to interconnect with Joondanna substation, provide for load growth in Osborne Park area.

Capacity Q4 2009

Southern Terminal

Pinjarra New Murray Lakes Feeder. This new feeder is required to support load growth and improve reliability in the Pinjarra area.


Q4 2007

South Fremantle

Australian Paper Mills

North Lake Rd Feeder Interconnection. Reconfiguration of North Lake feeder to balance feeder loads and provide for load growth.


Q4 2007


Table 5.1 Committed large distribution projects (2007 – 2009) (continued).

Load area Substation Committed projects Project drivers

Scheduled completion

South Fremantle

Bibra Lake Distribution works for new Bibra Lake substation connection. Distribution works to create 4 feeders to interconnect with Bibra Lake substation. The new feeders provide for load growth in the Bibra Lakes and Cockburn areas.


Q4 2007

South Fremantle

Bibra Lake New Success/Thomsons Lake Feeder. New feeder required to provide for load growth associated with new residential and commercial developments in the Success area.


Q4 2007

South Fremantle

Medina Installation of new Wellard Feeder stage one. New feeder required to provide for load growth associated with new residential and commercial developments in Wellard and Highbury Park.


Q2 2007

Western Terminal

Cottesloe Distribution network upgrade from 6.6 kV to 11 kV. Upgrade the local distribution network from 6.6kV to 11kV to increase capacity and provide for ongoing load growth in the Cottesloe.

Capacity Q4 2008

Western Terminal

Wembley Downs

Distribution network upgrade from 6.6 kV to 11 kV. Upgrade the local distribution network from 6.6kV to 11kV and increase capacity and provide for ongoing load growth in the Wembley Downs.

Capacity Q4 2009

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5.3 Commissioned projects

The table below identifies some key projects that were energised by Western Power in 2006. Projects are classed as ‘commissioned’ when they are energised. However, they may not be fully complete.

Table 5.2 Commissioned projects 2006.

Load area Location Project description Project driver

Energised date

Southern Terminal

Bibra Lake to Cannington

New 330 kV transmission line from Southern Terminal to Cannington Terminal

Capacity Q1 2006

Muja Narrogin Install fourth transformer at Narrogin substation

Capacity Q1 2006

Northern Terminal

Malaga Install new line circuit, new capacitor circuit and uprate capacitor circuits at Northern Terminal

Voltage, reliability

Q1 2006

Northern Terminal

Hadfields Replace transformer at Hadfields substation

Reliability, safety

Q1 2006

Muja Collie Worsley substation augmentation, stage one

Customer Q1 2006

Muja Collie Worsley substation augmentation, stages two and three

Customer Q1 2006

Kwinana Meadow Springs

Establish new substation Capacity Q1 2006

East Perth Hay and Milligan St

Fire system upgrade at Hay and Milligan Street substation

Safety Q2 2006

Kwinana Kwinana Install two reactors at Kwinana 132 kV switchyard

Safety Q2 2006

Muja Collie Worsley substation augmentation, stage four

Capacity Q2 2006

Muja Collie - Bridgetown - Manjimup

New 132 kV transmission line from Muja power station to Bridgetown and to Manjimup substations

Capacity Q2 2006

Kwinana Kwinana Install cable from Kwinana desalination plant substation to transmission line from Kwinana to Mason Road substations

Capacity Q2 2006

Kwinana Kwinana Install cable from Kwinana desal. plant substation to transmission line from Kwinana to Mason Rd substations (unregulated works)

Capacity Q2 2006

North Country

Emu Downs Regulated works required to connect Emu Downs Wind Farm to Western Power’s network

Capacity Q3 2006


Table 5.2 Commissioned projects 2006 (continued).

Load area Location Project description Project driver

Energised date

General Multiple Replacement of 92 voltage transformers

Reliability, safety

Q3 2006

General Multiple Purchase spare 132/22/11 kV transformer

Reliability Q3 2006

Northern Terminal

Yanchep Replace 10 MVA transformer with 33 MVA transformer at Yanchep substation

Capacity Q3 2006

Southern Terminal

Bibra Lake Install two reactors at Southern Terminal

Safety Q3 2006

General Multiple Install capacitor banks in substations to enable wind farm operation

Reliability, voltage

Q3 2006

Northern Terminal

Malaga to East Perth and Belmont

Connect the line from Northern Terminal to East Perth Terminal with the line from Northern Terminal to Belmont substation

Capacity Q3 2006

Southern Terminal

Southern River

Establish new substation Capacity Q3 2006

Bunbury Oakley Transmission works required for connection of Alinta’s second co-generation unit at the Alcoa Pinjarra refinery.

Capacity Q4 2006

Guildford Terminal

Forrestfield Construct an additional 132/22 kV 33 MVA transformer and a second 132 kV line

Capacity Q4 2006

Guildford Guildford Terminal

Establish 330/132 kV terminal station Capacity Q4 2006

Northern Terminal

Padbury substation

Construct a new 132/22 kV substation with one transformer

Capacity Q4 2006

Cannington Terminal

Kenwick Link

Establish 330/132 kV transformer station

Capacity Q4 2006

��

Different load and generation scenarios (location, size, timing etc) may significantly change the timing and/or nature of network development. All proponents (load or generator) of new connections or expanded existing loads or generators are encouraged to contact Western Power’s Access Services Section for advice.

These solutions are in addition to the committed projects in chapter 5. Changes in load forecasts, generation forecasts and other factors will significantly affect the plans presented. Further detailed technical and economic assessments of each option are carried out before committing to a particular project.

Following such a detailed investigation, the option selected to address identified network constraints may or may not involve the solution described here. Clearly, the options selected to

address the network constraint are selected on their technical and economic merits at the time.

Furthermore, all projects over $15M are required to satisfy a Regulatory test under the Access Code. This process may include a formal period of public consultation, at the ERA’s discretion.

In particular, if interested parties are able to identify DSM or distributed generation options that would address these constraints, the need for these projects may be deferred or obviated.

Major transmission network development options expected to cost more than five million dollars are detailed in Table 6.1 below. Projects less than five million are shown in appendix D. For commercial-in-confidence reasons, Western Power does not publish any information about potential generation developments.

� Network development options

The network development options identified in this section only provide an indication based on information available at the time of network performance assessment and of Western Power’s favoured network augmentation solution in response to committed and proposed generation and load growth.

Table 6.1 Proposed network development options.

Load area Network development Drivers Proposed completion

Bulk transmission

Establish South-East Terminal: cut in to Muja to Northern Terminal 330 kV and Kwinana to Northern Terminal 330 kV

Reactive reserve shortfall Q4 2010

Kemerton to South-East Terminal: construct a double circuit 330 kV line


330 kV Transmission lines: convert to HSSPAR

To improve reliability Q4 2011

Muja to Northern Terminal: cut into Shotts Terminal


Shotts to Southern Terminal/Oakley: cut into Landwehr Terminal


Southern Terminal to Guildford Terminal: construct overhead earth wire on 330 kV line

To improve reliability Q4 2013

Northern Terminal: install third transformer

Bulk supply transformer capacity shortfall

Q4 2014

Northern Terminal: install 132 kV series reactors

To limit potential fault levels to within plant ratings

Q4 2014

Northern Terminal: install 200 MVAr SVC Reactive reserve shortfall Q4 2014


Table 6.1 Proposed network development options (continued).


Bunbury Busselton Substation: Install first 132/22 kV 33 MVA transformer, feeder circuit, 3 MVAr capacitor bank

Capacity shortfall due to load growth

Q4 2008

Busselton Substation: install second 132/22 kV 33 MVA transformer and switchboard


Q4 2012

Busselton Substation: establish 132 kV line from Picton to Busselton Substation.

Voltage support during N-1 contingency

Q4 2012

Capel Substation: upgrade to 132 kV Capacity shortfall due to load growth

Q4 2014

Preston Park Substation: establish a new substation with two 132/22 kV 33 MVA transformers


Q4 2014

Cannington Terminal

Cannington Terminal: establish 330 kV switchyard

Bulk supply transformer capacity shortfall

Q4 2013

Belmont to Rivervale: uprate to 132 kV line

Transmission network capacity shortfall

Q4 2009

Victoria Park: establish new 132/22 kV substation

Capacity shortfall Q4 2013

East County Sawyers Valley Substation: convert to 132 kV

Capacity shortfall at Sawyers Valley Substation

Q4 2010

East Perth / CBD

Northern Terminal to East Perth: construct new 330 kV line

Supply shortfall in the East Perth and Western Terminal load areas

Q4 2016

Joel Terrace: 132 kV conversion stage one

Shortfall in NCR capacity Q4 2008

East Perth to Belmont: rebuild transmission line

Shortfall in N-2 capacity to E. Perth load area and CBD

Q4 2010

James Street: establish new substation Capacity shortfall at N. Perth, Joel Terrace, Forrest Avenue

Q4 2015

James Street: establish new 330/132 kV terminal

Shortfall in N-2 capacity to E. Perth load area and CBD; 132 kV supply point for new CBD substations

Q4 2016

��



Eastern Goldfields

West Kalgoorlie to Black Flag: construct second 132 kV line

Need to meet reliability. Load exceeds 20 MW.

Q4 2011

Guildford Terminal

Munday: establish new substation Rise in Westralia Airports’ corporation bulk loads

Q4 2009

Hazelmere: establish new substation Midland Junction Substation capacities exceeded

Q4 2015

Kwinana Mason Road Substation: fault level uprate

Connections expected to increase fault levels at Mason Road substation

Q4 2012

Clifton: establish new zone substation Needed to supply residential, commercial developments south of Mandurah

Q4 2013

Baldivis: establish new zone substation Need to supply residential, commercial developments in Baldivis areas

Q4 2013

Hopeland: establish new 330 kV terminal station

Supply shortfall in developing Rockingham/Mandurah areas

Q4 2013

Kwinana: install 330/132 kV transformer Bulk supply transformer capacity shortfall

Q4 2010

Muja Kojonup to Albany: transmission line uprate

Line overload for loss of Kojonup to Mt Barker line

Q4 2009

Kojonup to Wagin: reconductor line Support for 66 kV contingencies

Q4 2010

Kojonup to Albany: transmission line construction 132 kV

Shortfall in firm capacity at Albany

Q4 2011




North Country

Pinjar to Geraldton: 330 kV line construction and establishment of new 330 kV Moonyoonooka Terminal

Shortage of supply capacity by summer 2008-09. Required to provide capacity to the Geraldton load area under contingency. Risk of major load shedding or voltage collapse

Q4 2010

Chapman Substation: installation of second transformer with second line conversion to 132 kV

Shortage of supply capacity by summer 2010-11. Without reinforcement, a risk of customer load shedding

Q4 2010

Rangeway Substation: installation of second transformer with second 132 kV line

Shortfall in DTC to provide backup from the Durlacher Street Substation for N-1 transformer contingency. Without reinforcement, risk of customer load shedding

Q4 2010

Chapman to Northampton: new 132 kV line

Shortfall in distribution capacity

Q4 2010

Jurien Bay: establish new substation and 132 kV line

Forecasted shortfall in distribution capacity

Q4 2011

Wongan Hills: new substation and line conversion to 132 kV

Shortfall in distribution capacity and improve supply reliability to Koorda area

Q4 2011

Rudds Gully: establish new substation Shortage of supply capacity by 2011 driven by new land releases in South Geraldton.

Q4 2011

Rangeway to Rudds Gully to Moonyoonooka: new 132 kV line construction

Capacity shortfall in lines to Geraldton area forecast by 2012. Supply at risk under certain contingencies.

Q4 2011

Regans re-supply: construction of 132 kV double -circuit line

Required before second 330 kV circuit Pinjar to Geraldton can be energised at 330 kV.

Q4 2012

Badgingarra Terminal and 330 kV line upgrade

Terminal needed for connection of prospective wind farms in the waiting in the Cataby area.

Q4 2014

�7



North Country

Dongara: new substation Shortfall in distribution capacity by about 2016

Q4 2016

Northampton: new substation, Chapman to Northampton line upgrade to 132 kV

Shortfall in distribution capacity by about 2018

Q4 2018

Northern Terminal

Joondanna: establish new substation Capacity shortfall at Osborne Park Substation

Q4 2009

Wangara: establish new substation Capacity shortfall at Mullaloo and Landsdale substations

Q4 2010

Wanneroo to Hocking to Wangara: build new 132 kV line

Transmission line capacity shortfall

Q4 2010

Warwick: establish new substation Capacity shortfall at Arkana, North Beach and Padbury substations

Q4 2010

Northern Terminal to Mount Lawley: 132 kV line uprate

Lines overloaded Q4 2011

Guildford to Hadfields: construct new 132 kV line


Q4 2012

Flynn Drive: establish new substation Capacity shortfall at Clarkson, Wanneroo substations

Q4 2015

Bayswater: establish new substation Capacity shortfall at Hadfields substation

Q4 2015

Hocking: establish new substation Capacity shortfall at Mullaloo, Wangara and Wanneroo substations

Q4 2016

Stirling: establish new substation Capacity shortfall at Arkana, North Beach and Manning St substations

Q4 2017

South Fremantle

O’Connor Substation: replace with 132/22kV substation

Substation capacity exceeded

Q4 2014

Myaree Substation: replace with 132/22 kV substation


Q4 2016

Aust. Paper Mills Substation: replace with 132/22 kV substation


Q4 2017

Southern Terminal to South Fremantle: line conversion to double circuit


Q4 2013




Southern Terminal

Thornlie: new substation Gosnells Substation capacity exceeded

Q4 2010

Willeton: new substation Canningvale Substation capacity exceeded

Q4 2010

Jandakot: new substation Cockburn Cement Substation capacity exceeded

Q4 2013

Kwinana to Southern Terminal: construct new 132 kV line


Q4 2014

Western Terminal

Medical Centre Substation: new 66/11 kV substation to replace 66/6.6 kV substation

Substation and distribution network capacity shortfall

Q4 2010

Western Terminal to Cook Street: install second 132kV line

Transmission capacity shortfall in some cases

Q4 2014

Nedlands Substation: new 132/11 kV substation to replace existing 66/6.6 kV substation


Q4 2014

Shenton Park Substation: 132/11 kV substation to replace existing 66/6.6 kV substation


Q4 2015

University Substation: new 66/11 kV substation to eventually replace 66/6.6 kV substation


Q4 2016

Herdsman Parade substation: replace existing 66/6.6 kV with a new 66/11 kV substation.

System security, primary plant due for retirement

Q4 2016

South Fremantle to Amherst: rebuild line as double circuit with one side strung with venus conductor.

Transmission network capacity shortfall during certain contingencies

Q4 2024

��

7.1 Sustainability

Western Power follows a rigorous consultative approach to selecting its preferred options and in obtaining approvals for all infrastructure projects.

This approach supports Western Power’s commitment to ensuring that line routes and other asset locations, such as substations, are regarded by the business, the community and other stakeholders as socially, environmentally and economically sustainable options.

The Environment and Land Management Section (ELMS) manages the approval process for Western Power. ELMS’ aim is to facilitate an ethical and sustainable works program on behalf of Western Power.

ELMS is responsible for obtaining all necessary environmental and planning approvals, negotiating land easements where required, and engaging with all impacted stakeholders as part of the planning process.

7.1.1 Planning checklist

Western Power considers many issues when selecting its projects and suitable line routes or sites for other electricity infrastructure. These include economic, technical, social and community, and environmental factors:

• Economic – this involves assessing the cost of various options.

• Technical – this considers the impact of issues such as losses, energy efficiency, demand side options, access, hydrology, river crossing, and existing and planned infrastructure.

• Social and community – this addresses visual impact, proximity of homes and businesses, cultural issues and impact on land use.

• Environment – this looks at proximity to environmentally sensitive areas or areas of high conservation value (for example, national parks, nature reserves), existence of rare, protected or threatened flora, impact on fauna and their habitats, and issues related to watercourses, water catchment areas and wetlands.

These issues are examined by Western Power staff, consultants and regulatory authorities. This information is used in submissions to obtain mandated approvals such as those required under the Access Arrangement, the Environmental Protection Act and the Planning and Development Act.

7.1.2 Environmental management

Western Power is committed to protecting the environment and continuing to improve its environmental performance.

To deal with its many and varied environmental impacts, Western Power has established an Environmental Management System (EMS). An EMS is a structured process for achieving continuous improvement in environmental performance. It also helps to prevent environmental incidents from occurring.

The foundation of Western Power’s EMS is its environmental policy. To coincide with the launch of the new business, Western Power developed, and has adopted, a new environmental policy, which sets the level of responsibility and performance. It builds on the successes of previous policies and establishes a range of strategies and actions, many of which go beyond standard environmental compliance.

Following the assessment of environmental issues identified in the planning process, a thorough environmental management process is followed to ensure that all issues related to the environment are fully considered and addressed.

This process involves liaising with stakeholders regarding environmental issues that have been identified and commissioning necessary surveys to address environmental and heritage uses. An Environmental Management Plan is then developed to manage the identified issues.

All construction activities are required to comply with the Environmental Management Plan. A post-construction audit of any environmental conditions is undertaken, and if required, remediation work carried out.

7 Other Planning Issues

Western Power follows a rigorous consultative approach to obtaining approvals for all infrastructure projects.


7.1.3 Stakeholder engagement

Western Power aims to meet its obligations and responsibilities to the people who live, and businesses that operate, near its assets.

In planning large transmission projects, Western Power consults with local communities and other stakeholders to identify and address potential issues. For all its projects, Western Power seeks to inform affected stakeholders of its business activities and where possible, involve them in the decision-making process. For example, residents and local governments provide input into line route selection and landscaping plans surrounding new substations sites.

Stakeholders that may be affected by Western Power projects vary, but typically include:

• relevant government agencies;• local government;• community and special interest groups;• Indigenous groups; • environment groups;• local Members of Parliament; and• residents, landowners and businesses.

The method Western Power uses to engage with its stakeholders varies depending on the type of stakeholder and the nature of the issues surrounding a project. Communications used to inform and/or engage with stakeholders include:

• information briefings (by invitation or open forms);

• individual briefings, for example, to local Members of Parliament;

• regular newsletters;• newspaper advertising;• door knocking at individual residents and

businesses;• website updates; and• displays at local shopping centres, libraries

and other community centres.

7.1.4 Environmental initiatives

A range of new innovative environmental initiatives has been developed that reflect Western Power’s commitment to promoting sustainable development across the business. Some are listed below:

Landcare Australia partnership

Landcare Australia Limited (LAL) is responsible for promoting and sponsoring the Landcare movement that is working to protect and repair the environment. It assists businesses to work with local communities on environmental and sustainable agriculture repair projects, providing corporate funds, staff and resources.

Western Power is developing a partnership with LAL to link into the state-wide network of local Landcare groups to facilitate contact with local communities, individual landowners and other stakeholders impacted by the construction and operation of the electricity network. This partnership is an important tool being used by Western Power to ensure that new capital works are planned, designed and constructed in a sustainable manner.

Environmentally Sensitive Area Program (ESA)

Established in 1996, the ESA program was developed to ensure Western Power and its activities did not compromise existing conservation values of an area. The program addresses environmental issues such as declared rare flora, threatened ecological communities, biosecurity threats such as dieback, weeds and diseases, and more recently organic farms. This program ensures that Western Power employees and contractors are made aware of any special environmental considerations prior to attending a site and undertaking works, ensuring compliance with environmental legislation and stakeholder requirements.

Landcare Australia Ltd engaged in community consultation in the State’s South-West.

71

When new infrastructure is designed to traverse an environmentally sensitive area, management strategies are developed and included in the project’s Environmental Management Plan. These strategies ensure that conservation values will not be compromised during construction works. Once the infrastructure is operational, the area of conservation value is included in the ESA program for protection.

Carbon Neutral Program

Western Power is developing a major new sustainability initiative that will involve planting 93,000 tree seedlings in 2007 to offset the carbon emissions produced by fleet vehicles and mobile generating facilities. The planting will also increase the amount of habitat for local fauna.

The program will be carried out the through the Carbon Neutral Program, a Men of the Trees initiative established in 2001 to involve the community and industry in responsibly offsetting greenhouse gas emissions from their business activities. Future planting in subsequent years is expected.

Environmentally Sensitive Area sign.

Threatened ecological community near Western Power’s Cannington Substation.

Planting for tomorrow.


7.2 Communications Network

7.2.1 Western Power communication technologies

Western Power is committed to providing a robust, flexible communications network. The recently introduced regulatory and electricity market framework places higher reliance on available, accurate and timely data. Western Power has correspondingly improved stringency in design to ensure:

• high circuit availability;• provision for redundant paths; • a fibre-optic cabling-based solution as the

first preference; and• a suitable environment for communications

equipment.

Development of the communications network is primarily driven by transmission network augmentation, however the communications network is heavily influenced by rapid changes in communications technology and the relatively short asset life of communications equipment.

Communications are necessary to ensure the safe, efficient and reliable operation of the electrical network. The communications requirements flow from three basic areas, Protection, SCADA and Operations.

7.2.2 Protection

Protection of Western Power’s electricity network requires the fast detection and isolation of electrical short circuits. In order to minimise damage to transmission lines and transformers in the event of an electrical fault on the network, a means of isolating the fault is necessary. On critical lines, the fault has to be precisely identified and cleared to maintain network stability. Only the line affected must be taken out of service to avoid unnecessary interruption to Western Power customers.

To enable the protection scheme to quickly identify and clear faults on two-ended lines, protection relays at opposite ends of the line are connected with one or more analogue or digital communication links. Except for very long lines, the protection systems are typically duplicated, using two

completely independent systems. This physical duplication extends to the communications links at the site. Each site must be connected by at least two physically diverse bearers.

A growing number of Tee’d line configurations in Western Power’s network has increased the use of digital differential protection schemes. This type of protection requires each site to compare current and voltage waveforms with the other sites. High-speed digital communications links in a mesh configuration are required to achieve adequate protection. Duplicated digital differential protection on a Tee’d line places special requirements on the communications network. In addition to the two physically diverse bearers required in a two-ended line, a Tee’d line arrangement requires a third physically diverse bearer path between two of the three sites.

7.2.3 SCADA (Supervisory Control and Data Acquisition)

SCADA functions as the monitoring system used by operators. Without SCADA, operators would have to be dispatched for every switch operation and to check the status of every item of plant at Western Power’s substations and terminals. SCADA remote terminal units (RTUs) are installed at sites to monitor plant status, report alarms, record current and voltage and to operate circuit breakers and other plant. RTUs are connected back to the SCADA Master Station at East Perth Control Centre and to the backup master stations at the head office and Southern Terminal.

A dedicated analogue or digital circuit is required for SCADA, and RTUs at critical sites require a physically diverse duplicate communications connection.

7.2.4 Operations

Telephones are required for safe operation of electricity sites. Remote condition monitoring and work efficiency are driving the requirement for corporate LAN at substations and terminals. Fault recorders that store large quantities of power quality data require LAN access for quick data retrieval. The engineering officers need access to email, electronic drawings and software databases while on site.

7�

7.2.5 Choice of bearer

WP has a number of bearer options to use to support the communication requirements of a project. The decision as to which bearer to use is influenced by a several factors. These include:

• the cost of the bearer;• the nature of the project;• proximity of existing communications facilities;

and• requirements of other projects in the vicinity.

Where possible the communications bearer is selected to form a strategic link in the communications network that creates a platform for connecting related or future projects. Western Power’s most common bearer options are detailed below:

Optical fibre

Optical fibre is the preferred communications bearer for a number of reasons. It is intrinsically dielectric and is immune from electrical disturbances and magnetic fields, making it ideal for electricity sites. Optic fibre is immune to radio frequency interference and weather anomalies that affect microwave radio communications. Fibre offers virtually unlimited bandwidth and can be buried or installed on overhead power lines.

Including fibre during new line works is the least expensive option for installation. Western Power has installed buried optical fibre while distribution undergrounding works are underway. Including optical ground wire (OPGW) in a new line build incurs only an incremental increase over the cost of the overhead earth wire (OHEW). The disadvantage of optical fibre is the cost when the installation cannot be leveraged off works that are underway.

Microwave

While Western Power still maintains an extensive microwave radio network, the reliance of microwave has been reduced over recent years. This is because of limitations inherent in the technology.

Experience has shown that Perth’s weather exhibits two characteristics that degrade the viability of microwave:

• the presence of dense rain micro cells where rainfall is concentrated at much higher densities than average figures would indicate. In combination with the typical south-west orientation of incoming storm fronts this results in regular “rain fade” outages for microwave links oriented on a north-west to south-east line; and

Figure 7.1 Western Power’s optical fibre network, existing and proposed, and detail of the metropolitan area.


• the known tendency for sub-refractive ducting along the coast from Perth to Carnarvon. This weather anomaly regularly takes the microwave out of service for periods ranging from minutes to hours.

Both these outages tend to occur at times of maximum stress for the electricity network, and for that reason a weather immune bearer such as optical fibre is the preferred solution for at least one of the bearers into each critical site.

There is also increased difficulty in obtaining planning approval for microwave towers. Environmental Land Services reports ever-increasing community resistance to siting microwave towers. This is due to the increasing public sensitivity to the proliferation of towers initiated by the mobile phone rollouts, and to the concern about the health effects of electro-magnetic radiation from the antennas. Microwave’s main advantage is that the hardware is required only at the ends of the link so intervening easements or right-of-ways are not required.

Pilot cable

The Western Power pilot network is a legacy of early protection relays. Pilot cable is typically 40-core copper with a steel armour jacket. This poses a number of concerns.

It requires elaborate and costly treatment at each electricity site to avoid earth loops and inducted voltages damaging equipment.

Sectionalising transformers are required at each node for each circuit, requiring substantial wall space in substation control rooms. The cable also supports only very low bandwidth requirements and will not reliably run even minimal digital services further than 10 km.

The intrinsic hazards entailed mean that specific inductions and qualifications are required to work in the pilot enclosures, qualifications that only a small number of WP employees possess. At present there is an extensive pilot network installed connecting most metro substations.

Power line carrier

Western Power has only one power line carrier, on the Merredin Terminal to West Kalgoorlie 220 kV line. Power line carrier uses the transmission line as the communications bearer to provide a small number of low speed voice or data services and protection. A power line carrier link is roughly the same cost as a microwave link, and a single link can span a much greater distance compared with microwave technology. However, this technology offers only half a dozen circuits rather than the hundreds offered by microwave and thousands offered by fibre.

Existing practices allow two independent power line carrier systems to carry duplicate protection over the same transmission line, but this practice is under review, and it appears likely to be deemed unacceptable for future installation.

Carrier services (such as Telstra and Optus.)

Western Power makes wide use of carrier-leased lines for voice services and for connection to SCADA RTUs where no communications bearer exists. Carriers provide circuits on a “best efforts” basis that do not meet the availability requirements adopted by the National Electricity Rules in the Eastern states. “Best effort” service delivery means:

• Carriers do not provide a guaranteed availability of service.

• Carriers do not guarantee a minimum restoration time.

• Carriers do not announce or coordinate scheduled circuit outages.

• Carriers do not guarantee or even release details of circuit routing (in the instances where physical diversity is required).

Figure 7.2 Western Power’s microwave network, existing and proposed.

7�

7.2.6 Communication projects

Table 7.1 Communication projects.

Load area Project Drivers Technology choice

Reason Proposed completion

Bulk transmission

Kenwick Link: Establish 330/132 kV transformer station

Duplicated digital diff protection on all lines, LAN access for fault recorder, SCADA RTU circuit to EPCC, dial-up for sub phone and SCADA data recorder

Fibre optic using OPGW for both physically diverse bearers

OPGW included in ST-KNL91 line build. Second bearer direction provided by cutting in to existing ST-CT83 OPGW that passes through KNL

Q4 2006

Pinjar to Wanneroo: new 132 kV line construction

Duplicated digital diff protection, LAN access for fault recorder

Fibre optic using OPGW for one physically diverse bearer, existing WNO-MUL buried optic fibre for other physically diverse bearer

OPGW included in PJR-WNO81 line build. Communications funded WNO-MUL buried optic fibre eliminated need for microwave at WNO and NBP

Q4 2006

Shotts to Kemerton: stringing second side on 330 kV

Duplicated digital diff protection on new line

Existing communications optic fibre bearer and microwave

Existing bearer adequate to support new requirements.

Q4 2007

Convert Southern Terminal to Kwinana line from 132 kV to 330 kV

Line reconfiguration requires two new digital diff and two new POR protection schemes

Existing communications optic fibre bearer and microwave.

Existing bearer adequate to support new requirements.

Q4 2008

Neerabup: establish new 330/132 kV terminal station

Duplicated digital diff protection on all lines, LAN access for two fault recorders, two SCADA RTU circuits to EPCC, dial-up for sub phone and SCADA data recorder

OPGW on NBT to WNO-MUL81 DC line build. OPGW on NBT to NT-PJR 81&82 line DC line build

Fibre optic cable in trench or conduit between buildings

This project creates NBT-WNO81 and NBT-PJR81 by building a DC from NBT to cut in to the WNO-PJR81 line. Also NBT-PJR81 and NBT-NT91 by building a DC from NBT to cut in to the NT-PJR81 line. Establish HBK provided OPGW on the NT-PJR81 line most of the way to NBT. By installing OPGW the rest of the way to PJR and on the DC line builds, physically diverse optical fibre connectivity is created from NBT to WNO, PJR and NT

Q4 2008


Table 7.1 Communication projects (continued).



Bunbury Margaret River Substation: establish 132 kV transmission line and 132/22 kV 33 MVA transformer

Digital diff and time- step distance protection on BSN-MR81 and BSN-MR71 lines, SCADA RTU circuit to EPCC, LAN access for fault recorder and terminal server, dial-up for sub phone.

OPGW on line build, only one bearer required.

OPGW was chosen over microwave radio because of concerns over negative community reaction to siting a mast in Margaret River.

Q4 2009

Communications required for SCADA between existing 66 kV control room and new transportable control room

Fibre optic cable in trench or conduit between buildings

Chosen to avoid equipment damage from voltage transients and earth loops

Pinjarra Substation: installation of second 132/22 kV 33 MVA transformer and two feeder circuits

Communications required between existing control room and new transportable switch room for SCADA

Fibre optic cable in trench or conduit


Q4 2008

Eastern Goldfields

Piccadilly Substation: installation of third transformer

Communications required between control room and transportable switch room for SCADA



Q4 2008

Kwinana Waikiki: establish zone substation

Duplicate high-speed protection, SCADA RTU circuit to EPCC, dial-up for sub phone and SCADA data recorder

Optical fibre in the form of a ring, to provide two physically diverse bearer paths

Council refused WP’s request for a microwave tower. Waikiki, Golden Bay and Meadow Springs substations are planned in response to load growth. Rather than implement multiple microwave solutions, money was used to create an optic fibre loop from Pinjarra to Kwinana, passing through these sites and Rockingham.

Q2 2008

77




North Country

Rangeway: establish new substation

Digital diff protection and POR distance protection, SCADA RTU circuit to EPCC, dial-up for sub phone

Fibre optic using OPGW for one physically diverse bearer and radio for the other

OPGW included on GTN-RAN81 line build. Radio selected as the least expensive option for second bearer.

Q4 2006

DPNGP analogue radio replacement

Protection and SCADA for GTN, TS, RAN substations and WWF and MGA power stations

Microwave The existing microwave radio equipment is at end of life. Optical fibre is not expected to be installed north of Eneabba until 2012

Q4 2008

Northern Terminal

Joondalup: establish new substation

Duplicated high speed protection, SCADA RTU circuit to EPCC, LAN access, dial-up for sub phone

Buried optical fibre to cut into existing Perth fibre network

Existing Perth fibre network optical fibre less than 500m away. Nearest pilot cable 4.5 km away.

Q4 2009

Henley Brook: establish new substation

Duplicated high speed protection, SCADA RTU circuit to EPCC, LAN access, dial-up for sub phone

Fibre optic using OPGW for one physically diverse bearer and microwave radio for the other

NT-HBK OPGW provided the first part of the OPGW link later to be used by NBT. Microwave radio was the least expensive option for the second bearer

Q4 2007

Padbury: establish new substation

Duplicated high speed protection, SCADA RTU circuit to EPCC, LAN access for fault recorder, dial-up for SCADA datastore and sub phone

Optic fibre using connections to the Perth fibre network and existing microwave radio.

Optic Fibre required for LAN access. Perth Fibre Network access located near Padbury. Physically diverse route uses existing microwave.

Q4 2006


Fibre optic cable in trench or conduit.


Clarkson: establish new substation

Duplicated high speed protection, SCADA RTU circuit to EPCC, dial-up for SCADA datastore and sub phone

Buried optical fibre Cost allocated for microwave mast and relocation of CLK-YP pilot used for WNO-CLK-YP underground optic fibre, eliminating need for microwave at CLK, WNO and NBP

Q4 2006





Reinforce Cannington 132 kV transmission network

Duplicated digital diff protection on new lines WE-BEL/RVE81 and CT-BEL81

Optical fibre, using the Perth fibre network

Protection configuration unable to be met with pilot on Tee’d line. All sites are in close proximity to Perth fibre network. Optical fibre has value for related project in the same area (see Kewdale – establish new substation)

Q4 2008

Kewdale: establish new substation

Duplicated high speed protection, SCADA RTU circuit to EPCC, dial-up for SCADA datastore and sub phone, LAN access for fault recorder

Optical fibre, using the Perth fibre network

Related approved Project CT-circuit reinforcement in the area provides most of the required OF bearer

Q4 2008

Bentley: establish new substation

High speed protection on BTY-EP81, BTY-EP-ST81 and EP-ST81, SCADA RTU circuit to EPCC, LAN access for fault recorder, dial-up for SCADA datastore and sub phone

Buried optical fibres cut in to EP-ST81 and 82 OPGW to get two directions out

Substation cable cuts into ST-EP81 and 82 that has OPGW on it. Buried fibre will share trench with 132 kV electrical cables to BTY substation

Q4 2007

Southern Terminal

Murdoch: establish new substation

Duplicated high speed protection, SCADA RTU circuit to EPCC, dial-up for sub phone and SCADA data recorder

Pilot cable using pilot protection and digital line drivers for voice or FXO/FXS cards if that doesn’t work

Substation cuts into line between two sites with pilot protection. Pilot cable runs past the sites. Nearest Perth fibre network too distant to be practical.

Q4 2006

Southern River: establish new substation

Duplicated high speed protection, SCADA RTU circuit to EPCC, dial-up for sub phone and SCADA data recorder

Microwave radio Site is near to an existing WP microwave site with adequate path. No new line builds to leverage OPGW installation

Q3 2006

7�




South Fremantle

Amherst Substation: third transformer installation




Q4 2007

Establish Bibra Lake substation

Duplicated digital diff protection, SCADA RTU circuit to EPCC, LAN access for fault recorder, dial-up for sub phone

Fibre optic using OPGW for both physically diverse bearers

This substation cuts into the existing KW-SF81 line that has OPGW installed, providing two directions out. OPGW option is less expensive than microwave alternative

Q2 2008

�1

APR Annual Planning Report

CBD Central business district

DNSP Distribution network service provider

DSM Demand Side Management

DUOS Distribution use of system charge

EPA Environmental Protection Authority

ERA Economic Regulation Authority

ERTF Electricity Reform Taskforce

Firm Capacity A substation designed to the N-1 reliability criteria must be capable of withstanding the loss of any single transmission plant item comprising the substation transformer circuits at any load level without loss of load

IMO Independent market operator

IPP Independent power producers

kA Kilo Amperes (measure of electrical current)

kV Kilo Volts (measure of electrical potential)

MDP Metropolitan Development Plan

MVA Mega Volt Ampere (measure of electrical demand)

MW Mega Watts (measure of the active component of electrical demand)

N – 0 For a substation to be designed to N reliability criteria means all load supplied by the substation may be lost as the result of an outage on any single transmission plant item comprising the substation

N – 2 at 80 per cent Peak Load

N-2 criteria means the consequences of the coincidence of one planned and one unplanned outage of transmission elements, at or below 80 per cent of peak load, will normally result in supply being maintained without loss of load, provided generation is rescheduled prior to the second outage

NCR Criteria A zone substation designed to the Normal Cyclic Rating (NCR) reliability criteria allows for the loss of an amount of load equivalent to a transformer’s pre-outage loading at any load level ensuring the outage of any single transmission plant item comprising the substation transformer circuits. Loss of load is permitted for the period required to install the Rapid Response Spare Transformer (RRST)

OHEW Overhead earth wire

OOE Office of Energy

OPGW Optical ground wire

PoE Probability of Exceedance

SECWA State Energy Commission of Western Australia

SOO Statement of Opportunity Report

SWIS South-West Interconnected System

TNSP Transmission Network Service Provider

� Abbreviations

��

9.1.1 Planning and operating electricity networks

Electricity networks are used to transport electricity from the power station to the customer. The transmission network allows the bulk transport of power across long distances at high voltages. The distribution network delivers electricity from the transmission substation to the end customer, usually over shorter distances and at lower voltages.

The planning, design, operation, maintenance and augmentation of electricity networks must ensure that each individual piece of network equipment is operated within its design limits. This requires voltage and power transfer for each asset to be assessed under a wide range of potential conditions, including for example modelling the effect of faults on the network. This is illustrated in Figure 9.1. Failure to meet voltage design limits can result in malfunction or damage to customer equipment, while exceeding power transfer limits creates potential safety and reliability hazards;

The network can withstand credible faults and unplanned outages. A fault is considered credible if it is considered likely given the prevailing circumstances. For example, a simultaneous fault on two adjacent circuits might be considered credible in a severe storm, but not in normal weather conditions. If there is a credible fault or unplanned outage, all plant must still operate within its design limits and the network must continue to deliver its required performance.

Required performance will be related to underlying economics:

• In the CBD, for example, a fault or unplanned outage on the transmission system should not

result in a loss of supply. The large number of customers connected to the system justifies back-up systems.

• In a rural distribution network, however, a fault may result in a loss of supply but this should be for a limited load and a limited time. There will be contingency plans to restore supplies after a fault. The smaller number of customers connected to a rural system is unlikely to justify (economically) extensive back-up systems.

• The quality of supply should be maintained to the appropriate standards. Quality of supply is a term that embraces voltage, frequency and other technical aspects of power supply.

• The potential for future growth should also be adequately provided for, where economically viable to do so, ensuring that Western Power’s electricity networks do not impede Western Australia’s economic development. This may mean, in some circumstances, installing ‘larger’ plant than is immediately required, to cater for expected load growth over the next, say, ten years.*

• Environmental impacts must also be responsibly managed.

In planning and operating the system, it is important to distinguish between system security and supply to individual customers. For example, the system is insecure, even if all customers are currently being supplied, if there is a credible fault that would lead to widespread loss of supply. The system is secure, even if some customers are currently without power, if the system can withstand a credible fault. The most famous example of this paradox was in California in early 2001 where suburbs were subjected to rolling black-outs to maintain overall system security. Overall, a secure system is likely to lead to more reliable supplies to customers.

� Appendix A – Introduction to Network Issues

Figure 9.1 Need for back-up facilities.

* Western Power’s development plans are subject to regulatory tests which balance cost and benefit in ensuring prudent network augmentation work only.


9.1.2 Faults on electricity networks

A fault on the electricity network may be caused by, among other things, lightening strikes, catastrophic failure of equipment, debris falling on lines or vegetation touching lines. A fault will tend to result in:

• a very high current flowing towards the location of the fault, many times the normal rating of the network equipment, known as the fault current; and

• a very low voltage (tending towards zero) near the location of the fault.

If a network fault is not addressed immediately, it could eventually black out the whole system. As such, networks are designed to immediately isolate the faulted network element from the rest of the network. For example, if a crane were to stray too close to a distribution line and cause a fault, the distribution line would be automatically switched out of service.

Short-lived faults are known as transient faults. For example, a lightening strike will cause a temporary fault on the network. To ensure that equipment is not needlessly out of service, transmission equipment will automatically reenergise the network element after a short delay. This is known as ‘reclosing’. If the fault is still present, the network element will be automatically isolated once more. The network element will remain isolated until the fault has been investigated and repairs made.

Circuit breakers are used to switch out the faulted elements. Clearly, circuit breakers must be capable of interrupting the very high currents safely. To this end, circuit breakers (and associated equipment) have fault current ratings. Complex calculations are carried out to identify the potential fault currents at different locations on the network, and the circuit breakers installed must have a fault current rating that is greater than the potential fault current.

Similarly, all other network equipment must have a fault withstand capability greater than the potential fault current at its network location. That is, it must be able to safely carry fault current, albeit for a very short time. The extremely short-lived nature of fault current explains why plant can carry fault current many times its rating in normal use.

Two things primarily affect the potential fault current at a point on the network: the proximity to

generation and the impedance of the local network. Fault current is ‘fed’ by generation, and so the nearer the network element is to a power station, the greater the potential fault current. Impedance can be described as an object’s opposition to the flow of electric current. A low impedance network will therefore give rise to a high fault current, where a high impedance network will limit fault currents.

The isolation of faulted equipment will, generally, increase flows on other network elements. If this contingency would overload another network element, so-called ‘pre-contingent’ action will be taken. This means that the network will be operated less efficiently to allow for the possibility of a contingency or fault.

9.1.3 Meshed and radial networks

An electricity network is described as highly meshed when each substation is connected to a number of other substations, as illustrated in Figure 9.2.

The main advantage of a highly meshed network is clear – if line 1 were taken out of service, substation A would still supplied by three other lines. The meshed network provides a secure supply. However, a network as highly meshed as that in the figure above would also be extremely expensive to develop. This expense is often justified on the transmission network, only.

A radial network is illustrated in Figure 9.3.

Figure 9.2 Highly meshed network.

Figure 9.3 Radial network.

��

A radial network is inherently less secure – if line 2 is lost, substation B would lose its supply. Nonetheless a radial network is much cheaper than a meshed network and so is more suitable for distribution networks. Furthermore, a meshed distribution network could give rise to very high fault currents.

Inter-tie feeders are used to provide fast restoration of supplies following faults. Following a fault, the affected network will be switched out of service, and the normally open switch energised. The switch is normally open as to have it energised before the fault would give rise to very high fault currents.

9.1.4 Peak demand, weather and diversity

Peak electricity demand may last for only a few hours. However, the network must be capable of supplying the maximum load that occurs.

The extent of simultaneous consumer demand affects peak demand significantly. For example, a bakery’s peak demand may occur overnight when it is in full production. During the day, its demand is likely to be low. On the other hand, an office building would normally operate during business hours and shut down overnight. Maximum demand in an office building tends to occur during the mid-afternoon.

This load diversity is helpful to Western Power, as it tends to reduce demand peaks and increases asset utilisation.

The figure below shows typical load demand profiles for substations supplying mostly residential, mixed residential/commercial and mostly commercial load. Residential loads tend to peak later in the evening towards 8pm whereas commercial loads tend to peak in mid-afternoon at approximately 3pm. The mixed residential/commercial profile is a reasonable composite of the residential and commercial profiles, where the peak depends on the mix of residential and commercial loads.

While the underlying trend in peak demand may be steady, peak demand in any particular year is very sensitive to prevailing weather conditions. Heating loads in winter and air-conditioning loads in summer are the two main influences on peak demand. On a particularly hot (or cold) day, everyone turns on the air-conditioner (or heater) at roughly the same time. This simultaneous consumption behaviour drives peak demand. Moreover, most air-conditioners are turned on during the hottest part of the day and turned off as the temperature declines in late afternoon, exacerbating peak demand – air-conditioning loads are described as having low diversity.

Figure 9.4 Typical SWIS load profiles for different load types during summer substation peak.

0.0

0.2

0.4

0.6

0.8

1.0

1.2

0005

0040

0115

0150

0225

0300

0335

0410

0445

0520

0555

0630

0705

0740

0815

0850

0925

1000

1035

1110

1145

1220

1255

1330

1405

1440

1515

1550

1625

1700

1735

1810

1845

1920

1955

2030

2105

2140

2215

2250

2325

2400

No

rmal

ised

Dem

and

Commercial Mixed Residential/Commercial Residential Time of day

�7

10.1.1 Load forecasts for connection points

This appendix presents detailed tables of load forecasts at each of Western Australia’s South-West Interconnected System (SWIS) major nodes.

The load forecasts are for the peak demand at each major node and are grouped based on the bulk injection points for the geographic area. Western Power prepared these load forecasts, in MW and MVA.

Where a major customer is associated with a node then the total of the load forecasts is summarised in the Contract Customer group (Refer to Table 10.14) irrespective of the geographic area where the customer is connected to the SWIS.

The forecasts do not represent maximum demands that are coincident with overall SWIS peak demand but rather the expected maximum demand at each major node. Where there is embedded generation connected, then the load forecast is on the basis that this generation is not operating at the time of maximum demand.

The real maximum demand at any connection point in any year may vary from these load forecasts due to socio-economic factors, weather conditions (particularly temperature) and changes in network connectivity.

10 Appendix B – Substation load forecasts


Tab

le 1

0.1

Bu

nb

ury

load

are

a –

Load

for

ecas

t

2006

2007

2008

2009

2010

2011

Sub

stat

ion

MW

MVA

MW

MVA

MW

MVA

MW

MVA

MW

MVA

MW

MVA

Bun

bury

Har

bour

47.7

055

.47

52.3

160

.82

54.4

363

.29

56.5

565

.76

58.6

768

.22

60.7

970

.69

Bus

selto

n30

.90

32.5

331

.57

33.2

333

.08

34.8

234

.59

36.4

136

.10

38.0

037

.62

39.5

9

Cap

el16

.90

17.6

017

.58

18.3

118

.25

19.0

118

.93

19.7

219

.60

20.4

220

.28

21.1

3

Coo

lup

8.10

8.71

10.1

810

.94

10.4

311

.22

10.6

911

.49

10.9

411

.77

11.2

012

.04

Mar

gare

t Riv

er9.

409.

4911

.44

11.5

612

.03

12.1

512

.61

12.7

413

.19

13.3

313

.78

13.9

2

Mar

riott

Roa

d23

.40

24.6

326

.97

28.3

927

.47

28.9

227

.97

29.4

528

.48

29.9

828

.98

30.5

1

Pic

ton

40.4

045

.19

47.1

852

.78

49.3

955

.25

51.6

057

.72

53.8

160

.19

56.0

362

.67

Pin

jarr

a6.

907.

346.

737.

167.

307.

777.

878.

378.

448.

989.

019.

59

Tota

l Lo

ad18

3.70

200.

9620

3.96

223.

1921

2.38

232.

4322

0.81

241.

6622

9.23

250.

8923

7.69

260.

14

Tab

le 1

0.2

Can

nin

gto

n lo

ad a

rea

– Lo

ad f

orec

ast

2006

2007

2008

2009

2010

2011

Sub

stat

ion

MW

MVA

MW

MVA

MW

MVA

MW

MVA

MW

MVA

MW

MVA

Bel

mon

t48

.50

55.1

158

.02

65.9

359

.67

67.8

051

.32

58.3

252

.97

60.1

954

.62

62.0

7

Ben

tley

n/a

n/a

n/a

n/a

20.0

022

.73

30.0

034

.09

37.6

642

.80

37.8

242

.98

Cla

renc

e S

treet

26.9

029

.89

33.4

837

.20

34.6

438

.49

35.8

039

.78

31.9

635

.51

32.9

236

.58

Col

lier

40.3

045

.80

50.2

357

.09

38.4

743

.72

39.7

145

.12

40.9

546

.53

42.1

847

.94

Kew

dale

n/a

n/a

n/a

n/a

n/a

n/a

20.0

023

.26

20.7

024

.07

21.4

024

.88

Riv

erva

le25

.00

28.7

425

.83

29.6

826

.65

30.6

332

.48

37.3

333

.51

38.5

134

.54

39.7

0

Tate

Stre

et54

.90

63.8

457

.40

66.7

458

.35

67.8

549

.31

57.3

450

.10

58.2

655

.50

64.5

4

Vict

oria

Par

k4.

305.

314.

305.

314.

305.

314.

305.

314.

305.

31n/

an/

a

Wel

shpo

ol76

.60

89.0

782

.65

96.1

085

.28

99.1

667

.91

78.9

669

.84

81.2

171

.77

83.4

5

Tota

l Lo

ad27

6.50

317.

7531

1.90

358.

0432

7.36

375.

6933

0.82

379.

5034

1.99

392.

4035

0.76

402.

13

��

Tab

le 1

0.3

Eas

t C

oun

try

load

are

a –

Load

for

ecas

t

2006

2007

2008

2009

2010

2011

Sub

stat

ion

MW

MVA

MW

MVA

MW

MVA

MW

MVA

MW

MVA

MW

MVA

Car

rabi

n1.

201.

451.

812.

181.

832.

201.

852.

221.

862.

251.

882.

27

Cun

derd

in7.

107.

557.

868.

368.

709.

258.

779.

338.

859.

428.

939.

50

Kel

lerb

errin

2.80

2.98

3.33

3.54

3.36

3.58

3.40

3.61

3.43

3.65

3.46

3.68

Kon

dini

n7.

007.

007.

587.

587.

777.

777.

957.

958.

148.

148.

328.

32

Mer

redi

n8.

508.

859.

319.

699.

429.

819.

539.

929.

6410

.04

9.75

10.1

5

Mun

darin

g W

eir

4.40

4.94

4.40

4.94

4.40

4.94

4.40

4.94

4.40

4.94

10.4

011

.69

Nor

tham

22.1

026

.22

24.6

127

.04

25.3

627

.86

26.1

128

.69

26.8

629

.51

27.6

130

.34

Saw

yers

Val

ley

11.5

012

.11

15.2

516

.06

16.0

516

.89

16.8

417

.72

17.6

318

.56

18.4

219

.39

Sou

ther

n C

ross

3.40

3.40

3.40

3.40

4.40

4.40

4.40

4.40

4.40

4.40

4.40

4.40

Wun

dow

ie8.

909.

089.

749.

949.

9310

.14

10.1

210

.33

10.3

110

.52

10.5

110

.72

Yerb

illon

0.20

0.24

0.19

0.23

0.20

0.24

0.21

0.25

0.22

0.27

0.23

0.28

Yilg

arn

14.6

016

.04

16.4

618

.09

16.6

218

.27

16.7

918

.45

16.9

518

.63

17.1

118

.81

Tota

l Lo

ad91

.70

99.8

610

3.94

111.

0510

8.04

115.

3511

0.37

117.

8111

2.69

120.

3312

1.02

129.

55

Tab

le 1

0.4

Eas

t P

erth

load

are

a –

Load

for

ecas

t

2006

2007

2008

2009

2010

2011

Sub

stat

ion

MW

MVA

MW

MVA

MW

MVA

MW

MVA

MW

MVA

MW

MVA

Coo

k S

treet

56.3

063

.98

57.1

464

.94

57.9

965

.90

58.8

366

.86

59.6

867

.82

60.5

268

.78

Forr

est A

ve27

.60

32.4

730

.56

33.9

531

.41

34.9

030

.36

33.7

431

.15

34.6

132

.00

33.6

2

Hay

Stre

et69

.70

87.1

382

.37

102.

9783

.16

103.

9583

.95

104.

9484

.74

105.

9385

.53

106.

91

Joel

Ter

race

28.2

030

.65

33.3

236

.22

34.4

237

.41

37.5

240

.78

38.6

942

.05

39.8

643

.32

Milli

gan

Stre

et83

.30

95.7

510

5.18

120.

8910

7.22

123.

2410

9.26

125.

5911

1.31

127.

9411

3.35

130.

29

Nor

th P

erth

38.6

039

.79

53.1

554

.79

54.6

556

.34

56.1

557

.89

57.6

559

.44

59.1

660

.99

Wel

lingt

on S

treet

16.9

018

.99

20.1

722

.66

20.5

823

.12

20.9

923

.58

21.4

024

.05

21.8

124

.51

Tota

l Lo

ad32

0.60

368.

7638

1.89

436.

4238

9.43

444.

8639

7.06

453.

3840

4.62

461.

8441

2.23

468.

42


Tab

le 1

0.5

Eas

tern

Gol

dfi

eld

s lo

ad a

rea

– Lo

ad f

orec

ast

2006

2007

2008

2009

2010

2011

Sub

stat

ion

MW

MVA

MW

MVA

MW

MVA

MW

MVA

MW

MVA

MW

MVA

Bla

ck F

lag

16.4

017

.45

26.8

928

.61

27.3

829

.13

27.8

829

.66

28.3

730

.18

28.8

630

.70

Bou

lder

22.7

024

.15

26.3

828

.06

27.0

628

.79

27.7

429

.51

28.4

230

.24

29.1

130

.96

Pic

cadi

lly29

.20

33.9

536

.08

41.9

636

.93

42.9

437

.77

43.9

238

.61

44.9

039

.46

45.8

8

Wes

t Kal

goor

lie T

erm

inal

23.5

023

.98

38.5

339

.32

40.8

641

.70

43.2

044

.08

45.5

346

.46

47.8

748

.84

Tota

l Lo

ad91

.80

99.5

312

7.88

137.

9513

2.23

142.

5613

6.59

147.

1714

0.93

151.

7814

5.30

156.

38

Tab

le 1

0.6

Gu

ildfo

rd lo

ad a

rea

– Lo

ad f

orec

ast

2006

2007

2008

2009

2010

2011

Sub

stat

ion

MW

MVA

MW

MVA

MW

MVA

MW

MVA

MW

MVA

MW

MVA

Dar

lingt

on19

.60

21.3

020

.20

21.9

520

.79

22.6

021

.39

23.2

521

.98

23.8

922

.57

24.5

4

Forr

estfi

eld

18.3

020

.33

20.1

422

.38

24.8

127

.56

39.4

643

.84

40.9

345

.48

42.4

147

.12

Kal

amun

da39

.10

42.9

744

.28

48.6

641

.93

46.0

743

.14

47.4

144

.35

48.7

445

.57

50.0

7

Mid

land

Jun

ctio

n61

.40

71.4

068

.35

79.4

869

.80

81.1

657

.75

67.1

658

.85

68.4

359

.95

69.7

1

Tota

l Lo

ad13

8.40

156.

0015

2.97

172.

4715

7.33

177.

4016

1.74

181.

6516

6.12

186.

5417

0.50

191.

44

�1

Tab

le 1

0.7

Kw

inan

a lo

ad a

rea

– Lo

ad f

orec

ast

2006

2007

2008

2009

2010

2011

Sub

stat

ion

MW

MVA

MW

MVA

MW

MVA

MW

MVA

MW

MVA

MW

MVA

Brit

ish

Pet

role

um14

.20

17.5

314

.20

17.5

314

.20

17.5

314

.20

17.5

314

.20

17.5

314

.20

17.5

3

Man

dura

h60

.40

64.9

564

.84

69.7

268

.54

73.7

072

.24

77.6

875

.94

81.6

564

.64

69.5

1

Mas

on R

oad

15.3

017

.59

20.5

023

.56

26.1

030

.00

31.1

035

.75

31.1

035

.75

35.1

040

.34

Mea

dow

Spr

ings

16.7

017

.40

21.6

422

.54

22.7

923

.74

23.9

424

.94

25.0

926

.14

41.2

442

.96

Med

ina

31.5

034

.24

37.6

440

.91

38.7

942

.16

39.9

443

.41

41.0

944

.66

42.2

445

.91

Roc

king

ham

72.5

078

.80

73.7

580

.16

57.3

962

.38

59.9

665

.17

62.5

267

.96

65.0

870

.74

Wai

kiki

n/a

n/a

n/a

n/a

24.0

026

.09

26.1

528

.42

28.3

030

.76

30.4

433

.09

Tota

l Lo

ad21

0.60

230.

5123

2.57

254.

4225

1.81

275.

6026

7.53

292.

9027

8.24

304.

4529

2.94

320.

08

Tab

le 1

0.8

Mu

ja lo

ad a

rea

– Lo

ad f

orec

ast

2006

2007

2008

2009

2010

2011

Sub

stat

ion

MW

MVA

MW

MVA

MW

MVA

MW

MVA

MW

MVA

MW

MVA

Alb

any

33.2

033

.88

35.2

235

.22

36.3

436

.34

37.4

737

.47

38.5

938

.59

39.7

139

.71

Bee

nup

4.80

4.85

6.25

6.31

6.42

6.49

6.60

6.67

6.78

6.85

6.96

7.03

Brid

geto

wn

22.6

025

.68

25.2

528

.70

25.3

828

.84

25.5

128

.98

25.6

329

.13

25.7

629

.27

Col

lie15

.90

17.6

716

.38

18.2

016

.85

18.7

317

.33

19.2

617

.81

19.7

918

.29

20.3

2

Kat

anni

ng10

.80

11.1

314

.03

14.4

614

.37

14.8

214

.72

15.1

715

.06

15.5

315

.41

15.8

9

Koj

onup

1.90

1.96

2.70

2.79

2.80

2.88

2.89

2.98

2.99

3.08

3.09

3.18

Man

jimup

14.5

016

.11

12.7

214

.13

12.9

514

.39

13.1

814

.65

13.4

114

.90

13.6

515

.16

Mou

nt B

arke

r5.

906.

086.

446.

646.

766.

977.

087.

307.

407.

637.

727.

96

Nar

rogi

n14

.40

15.3

214

.88

15.8

215

.35

16.3

315

.83

16.8

416

.30

17.3

416

.78

17.8

5

Wag

erup

14.3

015

.54

14.8

016

.09

15.3

016

.63

15.8

017

.18

16.3

017

.72

16.8

018

.26

Wag

in4.

104.

326.

176.

496.

316.

646.

456.

786.

596.

936.

737.

08

Tota

l Lo

ad14

2.40

152.

5415

4.84

164.

8515

8.83

169.

0616

2.86

173.

2816

6.86

177.

4917

0.90

181.

71


Tab

le 1

0.9

Nor

th C

oun

try

load

are

a –

Load

for

ecas

t

2006

2007

2008

2009

2010

2011

Sub

stat

ion

MW

MVA

MW

MVA

MW

MVA

MW

MVA

MW

MVA

MW

MVA

Cha

pman

12.5

014

.04

14.7

516

.57

15.3

317

.23

15.9

217

.89

16.5

018

.54

17.0

819

.20

Dur

lach

er S

treet

24.9

028

.95

22.7

226

.41

23.5

427

.37

24.3

628

.32

19.1

722

.30

19.9

923

.25

Enea

bba

24.0

026

.09

24.4

826

.61

24.9

627

.13

25.4

427

.65

25.9

228

.17

26.4

028

.70

Ger

aldt

on62

.40

65.0

061

.69

64.2

663

.55

66.1

965

.40

68.1

361

.26

63.8

163

.11

65.7

4

Kal

barr

i3.

603.

603.

693.

693.

793.

793.

893.

894.

004.

004.

104.

10

Moo

ra11

.40

11.4

012

.65

12.6

513

.16

13.1

613

.67

13.6

714

.18

14.1

814

.69

14.6

9

Ran

gew

ayn/

an/

a6.

006.

956.

006.

956.

006.

9512

.00

13.9

112

.00

13.9

1

Reg

ans

11.2

011

.55

12.6

413

.03

13.7

814

.21

14.9

215

.39

16.0

716

.56

17.2

117

.74

Thre

e S

prin

gs7.

307.

308.

068.

068.

248.

248.

438.

438.

628.

628.

808.

80

Tota

l Lo

ad15

7.30

167.

9316

6.68

178.

2317

2.35

184.

2717

8.03

190.

3217

7.72

190.

0918

3.38

196.

13

��

Tab

le 1

0.10

Nor

ther

n T

erm

inal

load

are

a –

Load

for

ecas

t

2006

2007

2008

2009

2010

2011

Sub

stat

ion

MW

MVA

MW

MVA

MW

MVA

MW

MVA

MW

MVA

MW

MVA

Ark

ana

65.8

073

.93

68.2

976

.73

70.1

778

.85

62.0

569

.72

63.6

671

.52

65.2

673

.33

Bee

chbo

ro66

.50

70.7

483

.16

88.4

766

.94

71.2

169

.81

74.2

672

.68

77.3

275

.55

80.3

7

Cla

rkso

nn/

an/

a24

.95

27.4

227

.97

30.7

330

.99

34.0

534

.01

37.3

749

.02

53.8

7

Had

field

s54

.10

62.1

860

.20

69.1

961

.68

70.8

963

.16

72.5

964

.64

74.2

966

.12

76.0

0

Hen

ley

Bro

okn/

an/

an/

an/

a22

.40

23.8

324

.50

26.0

726

.61

28.3

128

.71

30.5

4

Joon

dalu

pn/

an/

an/

an/

an/

an/

an/

an/

a22

.00

24.1

823

.27

25.5

7

Joon

dann

an/

an/

an/

an/

an/

an/

an/

an/

a15

.00

17.8

615

.42

18.3

6

Land

sdal

e53

.90

58.2

772

.56

78.4

478

.19

84.5

383

.83

90.6

389

.47

96.7

280

.10

86.6

0

Mal

aga

29.0

032

.33

41.2

245

.96

43.8

348

.87

46.4

451

.77

49.0

554

.68

51.6

657

.59

Man

ning

Stre

et28

.60

31.4

337

.05

40.7

138

.49

42.3

039

.94

43.8

941

.38

45.4

842

.83

47.0

7

Mor

ley

44.4

051

.63

50.2

258

.39

51.6

360

.04

53.0

461

.68

54.4

563

.32

55.8

764

.96

Muc

hea

16.3

018

.52

20.9

123

.76

21.9

724

.97

23.0

326

.18

24.1

027

.38

25.1

628

.59

Mul

lalo

o76

.60

85.1

167

.57

75.0

872

.09

80.1

066

.60

74.0

060

.46

67.1

863

.70

70.7

8

Nor

th B

each

73.9

081

.21

72.7

379

.92

75.3

082

.75

67.8

874

.59

70.0

977

.03

72.3

179

.46

Osb

orne

Par

k53

.10

63.2

164

.18

76.4

166

.74

79.4

669

.31

82.5

156

.87

67.7

058

.01

69.0

6

Pad

bury

n/a

n/a

30.0

032

.97

31.3

834

.48

62.7

568

.96

65.4

271

.89

68.0

974

.82

Wan

gara

n/a

n/a

n/a

n/a

n/a

n/a

n/a

n/a

n/a

n/a

15.0

016

.22

Wan

nero

o69

.00

75.8

274

.13

81.4

678

.78

86.5

883

.44

91.6

976

.10

83.6

368

.10

74.8

3

Yanc

hep

29.7

031

.94

26.5

328

.52

28.3

930

.52

30.2

532

.52

32.1

134

.52

33.9

736

.52

Yoki

ne42

.00

46.6

750

.97

56.6

353

.01

58.8

955

.04

61.1

657

.08

63.4

259

.12

65.6

9

Tota

l Lo

ad70

2.90

783.

0084

4.66

940.

0688

8.96

988.

9993

2.06

1036

.27

975.

1610

83.7

810

17.2

611

30.2

2


Tab

le 1

0.11

Sou

th F

rem

antl

e lo

ad a

rea

– Lo

ad f

orec

ast

2006

2007

2008

2009

2010

2011

Sub

stat

ion

MW

MVA

MW

MVA

MW

MVA

MW

MVA

MW

MVA

MW

MVA

Am

hers

t41

.20

45.7

847

.60

52.8

946

.72

51.9

148

.76

54.1

750

.79

56.4

352

.83

58.6

9

Aus

tralia

n P

aper

Mills

42.9

050

.47

48.5

057

.06

28.3

433

.34

29.2

534

.41

30.1

635

.49

31.0

736

.56

Bib

ra L

ake

n/a

n/a

n/a

n/a

26.5

028

.49

27.4

829

.55

28.4

630

.60

29.4

431

.66

Edm

und

Stre

et26

.30

30.2

326

.85

30.8

727

.30

31.3

827

.75

31.9

028

.20

32.4

128

.65

32.9

3

Mya

ree

39.4

044

.27

44.3

849

.87

49.0

055

.05

50.7

056

.97

52.4

158

.88

54.1

160

.80

Nor

th F

rem

antle

15.0

017

.44

13.3

815

.55

13.7

515

.99

14.1

316

.42

14.5

016

.86

14.8

817

.30

O’C

onno

r32

.80

37.2

734

.28

38.9

535

.75

40.6

337

.23

42.3

038

.70

43.9

840

.18

45.6

6

Sou

th F

rem

antle

1.90

2.16

1.98

2.25

2.05

2.33

2.13

2.42

2.20

2.50

2.28

2.59

Tota

l Lo

ad19

9.50

227.

6221

6.97

247.

4422

9.41

259.

1223

7.43

268.

1424

5.42

277.

1525

3.44

286.

19

Tab

le 1

0.12

Sou

ther

n T

erm

inal

load

are

a –

Load

for

ecas

t

2006

2007

2008

2009

2010

2011

Sub

stat

ion

MW

MVA

MW

MVA

MW

MVA

MW

MVA

MW

MVA

MW

MVA

Byf

ord

40.0

044

.94

50.6

756

.93

52.4

458

.92

54.2

160

.91

55.9

862

.89

57.7

564

.88

Can

ning

Val

e81

.50

92.6

184

.43

95.9

587

.98

99.9

791

.52

104.

0095

.06

108.

0278

.61

89.3

2

Coc

kbur

n C

emen

t51

.40

55.2

752

.80

56.7

743

.23

46.4

944

.82

48.1

946

.41

49.9

048

.00

51.6

1

Gos

nells

74.3

082

.56

70.3

078

.11

72.0

780

.08

73.8

582

.05

75.6

284

.02

57.3

963

.77

Mur

doch

n/a

n/a

15.0

016

.67

22.4

524

.94

23.1

825

.76

23.9

126

.57

44.6

449

.60

Riv

erto

n72

.70

80.7

870

.35

78.1

672

.41

80.4

674

.48

82.7

676

.55

85.0

658

.62

65.1

3

Sou

ther

n R

iver

n/a

n/a

36.8

040

.39

39.9

843

.88

43.1

647

.37

51.3

456

.35

54.5

259

.84

Thor

nlie

n/a

n/a

n/a

n/a

n/a

n/a

n/a

n/a

n/a

n/a

20.0

022

.22

Wille

ton

n/a

n/a

n/a

n/a

n/a

n/a

n/a

n/a

n/a

n/a

20.0

022

.73

Tota

l Lo

ad31

9.90

356.

1638

0.35

422.

9839

0.56

434.

7440

5.22

451.

0442

4.87

472.

8143

9.53

489.

10

��

Tab

le 1

0.13

Wes

tern

Ter

min

al lo

ad a

rea

– Lo

ad f

orec

ast

2006

2007

2008

2009

2010

2011

Sub

stat

ion

MW

MVA

MW

MVA

MW

MVA

MW

MVA

MW

MVA

MW

MVA

Cot

tesl

oe28

.10

31.2

233

.06

36.7

334

.26

38.0

635

.45

39.3

939

.65

44.0

640

.94

45.4

9

Her

dsm

an P

arad

e11

.50

12.7

813

.44

14.9

413

.67

15.1

813

.89

15.4

314

.11

15.6

814

.33

15.9

2

Med

ical

Cen

tre16

.50

18.9

717

.65

20.2

817

.95

20.6

418

.26

20.9

918

.57

21.3

418

.87

21.6

9

Ned

land

s22

.00

25.0

025

.84

29.3

626

.66

30.3

027

.49

31.2

428

.32

32.1

829

.15

33.1

2

She

nton

Par

k23

.30

26.7

826

.69

30.6

823

.72

27.2

624

.63

28.3

125

.54

29.3

526

.45

30.4

0

Uni

vers

ity16

.10

18.5

116

.78

19.2

817

.11

19.6

717

.44

20.0

514

.78

16.9

815

.02

17.2

6

Wem

bley

Dow

ns22

.80

25.6

228

.04

31.5

028

.85

32.4

229

.67

33.3

430

.49

34.2

631

.31

35.1

8

Tota

l Lo

ad14

0.30

158.

8816

1.50

182.

7716

2.22

183.

5316

6.83

188.

7517

1.46

193.

8517

6.07

199.

06

Tab

le 1

0.14

Con

trac

t C

ust

omer

s in

all

load

are

a –

Load

for

ecas

t

2006

2007

2008

2009

2010

2011

Sub

stat

ion

MW

MVA

MW

MVA

MW

MVA

MW

MVA

MW

MVA

MW

MVA

Con

trac

t Cus

tom

ers

200.

8421

8.05

256.

5527

9.37

259.

0228

1.98

462.

6949

8.64

464.

2450

0.29

464.

7150

0.78

Tota

l Lo

ad20

0.84

218.

0525

6.55

279.

3725

9.02

281.

9846

2.69

498.

6446

4.24

500.

2946

4.71

500.

78

�7

11.1.1 Maximum short circuit levels

This appendix presents tables of maximum forecasted short circuit levels at each of Western Australia’s South-West Interconnected System (SWIS) major nodes.

Western Power has prepared these fault levels for three-phase and single-phase to earth faults. This information should be taken as an approximate guide only. The short circuit level calculations were determined using AS 3851-1991: The calculation of short-circuit currents in three-phase AC systems.

11 Appendix C – Estimated maximum short circuit levels

Bunbury

2007 Fault Current ( kA ) 2012 Fault Current ( kA )

Substation Three Phase One Phase Three Phase One Phase

Barrack Silicon Smelter 132 kV 8.28 7.76 8.59 8.14

Bunbury Harbour 132 kV 8.19 8.27 8.13 8.27

Busselton 132 kV 2.27 2.34 2.09 2.55

Busselton 66 kV 3.87 4.92 3.18 4.24

Capel 66 kV 4.45 3.99 3.16 2.66

Coolup 66 kV 1.03 0.62 1.03 0.62

Kemerton 132 kV 9.86 10.81 10.52 11.51

Kemerton 330 kV 11.20 11.89 17.02 17.53

Kemerton Power 330 kV 10.93 11.58 15.85 16.25

Margaret River 132 kV n.a. n.a. 1.48 1.66

Margaret River 66 kV 1.36 0.97 1.42 1.27

Marriott Road 132 kV 8.90 8.86 9.08 9.24

Marriott Road 132 kV 8.90 8.86 9.08 9.24

Picton 132 kV 9.49 9.99 9.47 10.00

Picton 66 kV 8.05 10.54 7.81 10.24

Pinjarra 132 kV 10.54 8.72 10.46 9.09

Wagerup Terminal 330 kV n.a. n.a. 16.09 16.07

Westralian Sands 66 kV 4.28 3.99 3.18 2.98

Cannington



Beckenham 132 kV 23.51 26.36 23.63 26.88

Belmont 132 kV 18.26 17.06 19.10 18.46

Bentley 132 kV n.a. n.a. 16.09 19.57

Cannington Terminal 132 kV 25.07 28.14 25.21 28.75

Cannington Terminal 66 kV 11.43 13.97 11.97 14.61

Clarence Street 66 kV 7.23 5.82 7.04 6.59

Collier 66 kV 7.12 5.82 7.09 6.19

Darlington 132 kV 10.78 9.83 12.69 12.13

Forrestfield 132 kV 11.01 9.68 12.22 11.32

Kalamunda 132 kV 9.02 8.22 11.31 10.36


Cannington (continued)



Kenwick Link 132 kV 22.72 23.74 22.95 24.25

Kenwick Link 330 kV 11.92 11.72 14.06 13.61

Kewdale 132 kV n.a. n.a. 17.89 16.99

Manning Street 132 kV 15.01 14.88 15.63 15.47

Rivervale 132 kV 16.67 14.61 17.02 15.37

Tate Street 66 kV 10.03 10.98 10.06 10.69

Tomlinson Street 66 kV 7.90 6.99 7.67 6.50

Victoria Park 66 kV 9.55 9.90 n.a. n.a.

WEB Forge 66 kV 8.69 7.90 9.12 8.42

Welshpool 132 kV 19.51 19.62 19.62 20.03

East Country



Baandee 66 kV 1.20 1.29 1.71 1.67

Bounty 132 kV 0.61 0.74 0.62 0.74

Carrabin 66 kV 0.88 0.95 0.96 1.01

Cunderdin 66 kV 1.05 1.15 1.67 1.71

Kellerberrin 66 kV 0.90 1.08 1.53 1.69

Kondinin 132 kV 1.32 1.59 1.34 1.61

Kondinin 220 kV 2.29 2.32 2.36 2.36

Merredin 132 kV 2.92 3.59 3.26 4.14

Merredin 66 kV 1.75 2.38 2.18 2.90

Merredin Terminal 132 kV 3.23 4.38 3.43 4.62

Merredin Terminal 220 kV 2.19 2.81 2.30 2.93

Mundaring Weir 66 kV 2.57 1.64 3.51 2.53

Northam 132 kV 4.28 4.80 5.97 6.72

Northam 66 kV 3.66 4.77 5.15 6.42

Sawyers Valley 132 kV n.a. n.a. 7.19 5.78

Sawyers Valley 66 kV 2.08 1.30 3.12 2.33

Southern Cross 66 kV 0.51 0.41 0.53 0.42

Wundowie 66 kV 1.46 1.76 2.81 2.99

Yerbillon 66 kV 0.83 0.86 0.90 0.91

Yilgarn 220 kV 1.85 1.87 1.90 1.91

��

East Perth



Cook Street 132 kV 19.35 21.57 19.55 22.41

East Perth 132 kV 20.32 22.66 20.60 23.80

East Perth 66 kV 4.99 6.48 4.99 6.49

Forrest Ave 66 kV 4.63 5.20 4.63 5.21

Hay Street 132 kV 18.39 19.96 18.62 20.72

Joel Terrace 132 kV n.a. n.a. 20.33 22.75

Joel Terrace 66 kV 4.95 6.40 4.94 6.41

North Perth 132 kV 17.99 17.63 18.18 18.22

Summers Street 132 kV 20.03 21.89 20.30 22.90

Wellington Street 132 kV 18.41 19.94 18.64 20.72

Wellington Street 66 kV 4.77 5.49 4.76 5.52

Eastern Goldfields



Black Flag 132 kV 2.22 2.48 2.23 2.49

Boulder 132 kV 3.76 4.94 3.79 4.98

Boulder 132 kV 3.76 4.94 3.79 4.98

Jan 132 kV 1.79 1.99 1.80 1.99

Jan 66 kV 2.01 2.62 2.01 2.62

Parkeston Sub 132 kV 3.72 4.69 3.75 4.72

Piccadilly 132 kV 3.68 4.83 3.72 4.87

West Kalgoorlie Terminal 132 kV 3.67 5.06 3.71 5.11

West Kalgoorlie Terminal 220 kV 2.09 2.74 2.12 2.76

Western Mining Kambalda 132 kV 2.46 2.83 2.47 2.84

Western Mining Smelter 132 kV 3.49 4.06 3.51 4.07

Guildford Terminal Station



Munday 132 kV n.a. n.a. 12.22 11.32

Kwinana



ALCOA Kwinana 132 kV 30.56 34.71 22.21 24.17

ALCOA Pinjarra 132 kV 10.60 10.89 10.84 11.14

ALCOA Pinjarra 330 kV 11.99 11.75 14.48 13.44

Australian Fused Materials 132 kV 18.00 15.84 16.07 14.71

B.P. Refinery 132 kV 24.47 25.21 20.50 21.84


Kwinana (continued)



British Petroleum 66 kV 5.90 6.42 5.75 6.29

Broken Hill Kwinana 66 kV 5.96 6.43 5.80 6.31

CSBP 132 kV 22.97 22.15 19.43 19.41

Hismelt 132 kV 22.75 22.18 19.25 19.42

Kerr McGee Kwinana 132 kV 27.10 29.45 22.30 24.81

Kwinana 132 kV 31.44 36.47 23.59 26.85

Kwinana 330 kV 13.84 15.12 19.72 22.59

Kwinana 66 kV 6.18 7.23 6.02 7.42

Kwinana Desalination Plant 132 kV 25.44 27.78 21.44 23.56

Kwinana Power Partnership 132 kV 25.27 26.58 21.06 22.85

Mandurah 132 kV 8.43 7.76 8.24 7.74

Mason Road 132 kV 27.10 29.45 22.30 24.81

Meadow Springs 132 kV 8.85 7.99 8.59 8.17

Medina 132 kV 17.98 15.93 16.52 15.00

Rockingham 132 kV 16.76 15.19 15.29 14.47

Tiwest Pigment Plant 132 kV 27.10 29.45 22.30 24.81

Waikiki 132 kV n.a. n.a. 11.18 9.55

Western Mining 132 kV 19.95 18.04 17.51 16.48

Muja



Albany 132 kV 1.45 1.93 1.75 2.28

ALCOA Boddington 132 kV 3.53 3.19 9.01 10.26

Beenup 132 kV 1.14 1.27 1.13 1.27

Bluewaters Power Station 330 kV n.a. n.a. 18.83 21.23

Boddington 132 kV 3.53 3.19 9.01 10.26

Boddington Reynolds 132 kV 3.53 3.19 9.01 10.26

Bridgetown 132 kV 4.25 4.50 4.06 4.71

Collie 66 kV 2.01 2.44 1.99 2.42

Collie Power Station Terminal 330 kV

11.60 12.19 18.32 20.56

Katanning 66 kV 1.82 2.01 1.82 1.99

Kojonup 132 kV 3.79 3.79 3.64 3.77

Kojonup 66 kV 2.92 3.63 2.90 3.62

Manjimup 132 kV 2.84 2.99 2.75 2.95

Mount Barker 132 kV 1.53 1.65 1.65 1.74

Muja 132 kV 18.81 23.33 15.48 18.45

101

Muja (continued)



Muja 220 kV 7.12 8.53 7.19 8.55

Muja 330 kV 14.42 17.32 18.54 21.46

Muja 66 kV 3.48 3.96 3.41 3.89

Narrogin 66 kV 1.78 2.32 1.81 2.34

Narrogin South 220 kV 3.15 2.59 3.20 2.61

Narrogin South 66 kV 1.81 2.38 1.83 2.41

Shotts 330 kV 12.13 12.81 18.89 21.34

Wagerup 132 kV 7.23 5.91 7.23 5.91

North Country



Cataby 132 kV 3.84 3.70 3.86 3.71

Chapman 132 kV 2.35 2.70 2.41 2.99

Eneabba 132 kV 3.49 3.38 3.51 3.39

Geraldton 132 kV 2.61 3.21 2.61 3.33

Golden Grove 132 kV 0.83 0.54 0.83 0.54

Kerr McGee Cataby 132 kV 3.81 3.67 3.83 3.69

Moora 132 kV 2.33 2.03 2.33 2.21

Mungarra 132 kV 3.74 4.59 3.73 4.58

Rangeway 132 kV 2.35 2.73 2.41 3.01

Regans 132 kV 3.46 3.49 3.48 3.52

Three Springs 132 kV 3.26 2.98 3.27 3.00

Walkaway Windfarm 132 kV 3.23 3.99 3.23 4.00

Wongan Hills 132 kV n.a. n.a. 1.01 1.12

Northern Terminal



Arkana 132 kV 16.34 16.93 16.91 17.38

Beechboro 132 kV 17.67 17.08 18.28 17.53

Clarkson 132 kV 10.67 9.73 12.29 11.51

Edgewater 132 kV 14.67 14.28 16.52 16.41

Guildford Terminal 132 kV 18.76 20.43 20.15 22.14

Guildford Terminal 330 kV 11.62 11.78 13.79 13.79

Hadfields 132 kV 14.39 13.61 14.79 13.93

Henley Brook 132 kV n.a. n.a. 11.89 9.39

James Street 132 kV 15.74 16.12 16.23 16.05

Joondalup 132 kV n.a. n.a. 15.97 15.70


Northern Terminal (continued)



Joondanna 132 kV n.a. n.a. 16.59 16.63

Kerr McGee Muchea 132 kV 11.98 9.30 12.12 9.54

Landsdale 132 kV 15.81 15.36 16.79 16.23

Malaga 132 kV 25.30 31.96 26.63 33.78

Midland Junction 132 kV 15.31 15.28 18.54 20.60

Milligan Street 132 kV 15.72 16.16 16.21 16.34

Morley 132 kV 15.64 16.45 16.13 17.04

Mount Lawley 132 kV 18.55 20.52 19.30 21.31

Muchea 132 kV 14.60 12.41 14.83 12.86

Mullaloo 132 kV 14.67 14.28 16.52 16.41

Neerabup Terminal 132 kV n.a. n.a. 19.00 21.75

Neerabup Terminal 330 kV n.a. n.a. 9.39 8.50

North Beach 132 kV 15.57 15.67 16.36 16.76

Northern Terminal 132 kV 25.38 32.06 26.71 33.87

Northern Terminal 330 kV 11.78 12.36 14.53 15.34

Osborne Park 132 kV 16.29 16.95 16.94 17.66

Padbury 132 kV 13.61 12.24 14.59 13.68

Pinjar 132 kV 21.55 23.52 22.91 25.39

Wangara 132 kV n.a. n.a. 15.53 14.66

Wanneroo 132 kV 13.21 12.87 17.83 18.90

Warwick 132 kV n.a. n.a. 16.03 15.81

Yanchep 132 kV 10.78 9.77 11.81 10.75

Yokine 132 kV 16.41 16.87 17.02 17.65

South Fremantle



Amherst 132 kV 17.22 14.38 16.58 14.88

Australian Paper Mills 66 kV 8.96 7.77 9.03 8.36

Bibra Lake 132 kV n.a. n.a. 17.06 15.92

Edmund Street 66 kV 10.29 9.91 8.98 9.03

Myaree 132 kV n.a. n.a. 12.32 11.83

Myaree 66 kV 8.20 6.72 8.24 9.19

North Fremantle 66 kV 9.55 8.47 8.43 7.83

O’Connor 132 kV n.a. n.a. 15.49 15.97

O’Connor 66 kV 9.33 8.56 n.a. n.a.

South Fremantle 132 kV 24.38 24.46 22.28 24.31

South Fremantle 66 kV 13.16 16.88 11.08 14.49

10�

Southern Terminal



Byford 132 kV 9.88 8.97 10.78 10.01

Canning Vale 132 kV 16.53 16.03 16.51 16.08

Cockburn Cement 132 kV 18.74 17.19 17.94 16.77

Cockburn Cement Ltd 132 kV 18.74 17.19 17.94 16.77

Glen Iris 132 kV 25.97 28.47 22.18 24.77

Gosnells 132 kV 17.37 16.65 19.44 18.94

Murdoch 132 kV 21.20 18.78 20.36 18.69

Riverton 132 kV 18.21 15.57 18.03 15.61

South-East Terminal 330 kV n.a. n.a. 18.04 18.50

Southern River 132 kV 13.51 12.06 17.86 16.65

Southern Terminal 132 kV 30.57 35.63 27.30 32.60



Thornlie 132 kV n.a. n.a. 20.03 18.51

Willeton 132 kV n.a. n.a. 22.70 20.50

Western Terminal



Cottesloe 132 kV n.a. n.a. 15.92 13.74

Cottesloe 66 kV 8.57 7.31 n.a. n.a.

Herdsman Parade 66 kV 7.68 5.87 6.25 4.12

Medical Centre 66 kV 9.42 8.70 9.35 8.60

Nedlands 66 kV 10.05 9.74 9.76 9.13

Shenton Park 66 kV 10.42 11.06 10.30 10.86

University 66 kV 9.28 8.36 9.17 8.17

Wembley Downs 66 kV 8.77 7.31 8.25 6.43

Western Terminal 132 kV 19.17 19.12 19.22 19.54

Western Terminal 66 kV 11.97 15.27 11.94 15.26

10�

12.1.1 Major committed and uncommitted projects less than $5m and gretaer than $0.5m, 10 year forecast

Load area Project Required in service date

Bunbury Bunbury: Uprate line section limitations Q2 2010

Busselton S/S: Install 132/22 kV transformer Q4 2008

Picton: Augment 22 kV busbar Q4 2009

Bunbury Harbour: Augment 22 kV busbar Q4 2010

Pinjarra – Alcoa Pinjarra: Line uprate Q4 2011

Busselton S/S: Install 2nd transformer Q4 2012

Marriot Rd S/S: Install 3rd transformer Q4 2013

Muja – Western colleries limited: Line uprate Q4 2014

Picton – Preston Park: New 132 kv line Q4 2014

Picton S/S: Install capacitor bank Q4 2014

Pinjarra S/S: Install 3rd transformer Q4 2014

CBD East Perth S/S: Earthing system works Q2 2008

Hay St S/S: Install capacitor bank Q4 2012

East Perth, Joel Terrace, Wellington St: 66 kV fault uprate Q4 2012

Wellington Street – Hay Street: Line uprate Q4 2013

CT Bentley S/S: Install 3rd transformer Q2 2013

Cannington: 132 kV fault uprate Q2 2013

Kewdale S/S: Install 2nd transformer Q2 2013

Rivervale S/S : Install 3rd transformer Q3 2010

Belmont – Rivervale: Line uprate Q4 2009

Kewdale S/S: Install 3rd transformer Q4 2013

Cannington S/S: 66 kV fault level uprate Q4 2015

ECR Cannington – Northam – Merredin: Install new lines Q2 2007

Northam S/S: Install 2nd transformer Q3 2008

Merredin Terminal – Merredin construct new 132 kV line Q3 2012

Sawyers Valley and Wundowie: Install cap banks Q4 2008

EGF Boulder S/S: Install 4th transformer Q3 2017

Black Flag S/S: Install 3rd transformer Q4 2011

West Kalgoorlie: Install 3rd transformer Q4 2012

12 Appendix D – Proposed transmission capacity expansion projects



Kwinana Rearrange Kwinana – southern terminal 132 kV Q4 2008

Meadow Springs S/S: Install 2nd transformer Q4 2010

Medina S/S: Install of 3rd transformer Q4 2010

Waikiki S/S: Install 2nd transformer Q4 2010

Rockingham-Waikiki line: Uprate to 244 Q4 2013

Waikiki S/S: Install capacitor bank Q4 2013

Kwinana-Mason Rd: Line uprate Q4 2016

Western Mining-Rockingham: Line uprate Q4 2016

Muja Kojonup S/S: Install 66/22 kV transformer Q2 2009

Muja – Kojonup: Line uprate Q2 2014

Wagin S/S: Install 3rd transformer Q3 2013

Beenup S/S: Install 3rd transformer Q3 2016

Katanning S/S: Install capacitor bank Q4 2007

Mt barker S/S: Install 2nd transformer Q4 2008

Bridgetown S/S: Install 3rd transformer Q4 2012

NT Padbury S/S: Install 2nd transformer Q2 2008

Manning St S/S: Install 2nd lv switchboard Q3 2008

Mount Lawley – Morley: Line uprate Q3 2009

Henley Brook S/S: Install 2nd transformer. Q3 2010

Northern Terminal – Beechboro: Line uprate Q3 2010

Joondalup S/S: Install 2nd transformer Q3 2011

Joondanna S/S: Install 2nd transformer Q3 2012

North Beach – Warwick: Line uprate Q3 2012

Clarkson S/S: Install 3rd transformer Q3 2013

Wannerooo – Neerabup terminal: Convert to double cct line Q3 2014

Stirling S/S: Install 2nd transformer Q3 2016

Clarkson S/S: Install 2nd transformer Q4 2008

Padbury S/S: Install 3rd transformer Q4 2008

Muchea S/S: Install 3rd transformer Q4 2009

North Beach – Padbury: Line uprate Q4 2010

Northern Terminal: Fault rating uprate Q4 2010

Malaga S/S: Install 3rd transformer Q4 2011

Morley S/S: Install lv switchboard & reactors Q4 2011

Wangara S/S: Install 2nd transformer Q4 2012

Warwick S/S: Install 2nd transformer Q4 2014

Yanchep S/S: Install new transformer Q4 2016

Wangara S/S: Install 3rd transformer Q4 2016

107


SF Amherst S/S: Install 3rd transformer Q4 2007

Bibra Lake S/S: Install 2nd transformer Q4 2008

O’connor S/S: Install 3rd transformer Q4 2010

Uprate O’connor–Myaree, Myaree-APM and South Fremantle-APM 66 kV lines

Q4 2010

O’Connor S/S: Install capacitor bank Q4 2010

Bibra Lake S/S: Install 3rd transformer Q4 2011

ST Gosnells S/S: Uprate fault rating of circuit breakers Q2 2010

Southern Terminal – Kwinana: Upgrade to 33 0kV Q3 2008

Southern River S/S: Install 2nd transformer Q4 2007

Murdoch S/S: Install 2nd transformer Q4 2010

Southern River S/S: Install 3rd transformer Q4 2012

Willetton S/S: Install 2nd transformer Q4 2013

WT Medical Centre – Western Terminal: Line uprate Q2 2010

Herdsman Parade S/S: New lv switchboard Q4 2011

363 Wellington Street Perth WA 6000GPO Box L921 Perth WA 6000T: (08) 9326 4911 F: (08) 9326 4595www.westernpower.com.auELECTRICITY NETWORKS CORPORATIONABN 18 540 492 861

Documents

Transmission and Distribution planning in Australia