Pg 1

Mandurah Load Area Non-Network Options Report

May 2016

Page 2 of 37

Disclaimer This non-networks options report has been prepared in accordance to Western Power’s network planning standard and it Non-networks solution strategy. The purpose of this document is to consult with Registered Participants, Interested Parties, solution providers and customers regarding a specific set of identified needs. It is not intended to be used for other purposes, such as making decisions to invest in generation, transmission or distribution capacity.

This document contains assumptions regarding, among other things, economic growth and load forecasts that, by their nature, may or may not prove to be correct. Western Power recommends and advises that anyone proposing to use this information should verify its reliability, accuracy and completeness before committing to any course of action or expenditure.

Western Power accepts no responsibility or liability of any nature whatsoever for any loss or damage that may be incurred by any person acting in reliance on the information or assumptions contained in this document. Any use of or reliance upon the information or assumptions contained in this report is at the sole risk of the user.

Western Power makes no warranties or representations whatsoever as to the reliability, accuracy and completeness of any information contained in this document. Western Power specifically disclaims any liability or responsibility for any errors or omissions in any of the information contained in this document.

The information provided is to be used with reference to the Non-Network Options Report for Mandurah Load Area only.

Document release information

Project name Mandurah Load Area: Rebuild MH

Project number T0417971 / N0421678

Document title Non Network Options Report (NNOR)

Revision status 1

Document prepared by:

Western Power

ABN 18540492861

© 2016 Electricity Networks Corporation t/a Western Power

Any use of this material except in accordance with a written agreement with Western Power is prohibited.

Page 3 of 37

Table of contents

Abbreviations 5

Glossary 7

Executive summary 8

1 Introduction 9

1.1 Network regulation in Western Australia 9

1.2 Purpose 9

1.3 Structure 9

2 Background 10

2.1 Network topography 10

2.1.1 Zone substations 10 2.1.2 Distribution network 12

2.2 Recent network investment in the Mandurah load area 13

2.3 Embedded generation 14

2.4 Demand side management 14

3 Description of identified need 15

3.1 Load forecast and emerging constraints in the Mandurah load area 15

3.2 Summary of identified need 19

4 Planning assessment and assumptions 20

4.1 Planning methodology 20

4.2 Technical rules 20

4.3 Demand forecasts 21

4.4 Demand management screening tool 21

4.5 Value of customer reliability 21

4.6 Discount rate 22

4.7 Cost estimates 22

5 Potential credible options 23

5.1 Base Case 23

5.2 Network options 23

5.2.1 OPTION 1 – STAGED REBUILD OF MH AND EXPAND MSS ZONE SUBSTATION 23 5.2.2 OPTION 2 – STAGED REBUILD OF MH ZONE SUBSTATION 24

Page 4 of 37

5.2.3 OPTION 3 – EXPAND MSS AND BUILD NEW ZONE SUBSTATION 25 5.2.4 PREFERRED NETWORK OPTION 25 5.2.5 NON-CREDIBLE NETWORK OPTIONS 26

5.3 Credible non-network options 26

5.3.1 EMBEDDED GENERATION 26 5.3.2 DEMAND MANAGEMENT 27

6 Technical characteristics for non-network options 28

6.1 Size and location of peak load reduction or additional supply 28

6.2 Network risk profile and potential deferral benefit 28

6.3 Investment timing requirements 29

6.4 Zone substation operating profile 30

6.5 Power system security and reliability 34

6.6 Operation 34

6.7 Fault level contribution 35

7 Submissions from interested parties 36

7.1 Invitation for submissions 36

7.2 Information from non-network solution proponents 36

7.3 Next steps 37

Page 5 of 37

Abbreviations

AEMO Australian Energy Market Operator

AER Australian Energy Regulator

CBD Central Business District

DLC Direct Load Control

DMST Demand Management Screening Tool

DTC Distribution Transfer Capacity

EMR Electricity Market Review

ERA Economic Regulation Authority

FSE Furnissdale Zone Substation

HV High Voltage

LV Low Voltage

MH Mandurah Zone Substation

MSS Meadow Springs Zone Substation

NCR Normal Cyclic Rating

NEM National Electricity Market

NER National Electricity Rules

NNOR Non-network Options Report

NPC Net Present Cost

PNJ Pinjarra Zone Substation

PoE Probability of Exceedance

PFC Power Factor Correction

PTA Public Transport Authority

PV Photovoltaic

RIT-D Regulatory Investment Test for Distribution

RO Rockingham Zone Substation

RRST Rapid Response Spare Transformer

Page 6 of 37

SWIS South West Interconnected System

TORP Transformer Overloading Ratings Program

USE Unserved Energy

VCR Value of Customer Reliability

WACC Weighted Average Cost of Capital

WAI Waikiki Zone Substation

Page 7 of 37

Glossary

Term Definition

Constraint Refers to an emerging limitation on network power transfers that can affect customer

service

Contingency

capacity

The capacity of a zone substation to ensure continuous operation during planned and

unplanned outages of plant and equipment due to faults or maintenance requirements.

The Normal Cyclic Rating criterion determines the contingency capacity for metropolitan

zone substations

Credible network

option

An option (or group of options) that; addresses the identified need; is (or are)

commercially and technically feasible; and can be implemented in sufficient time to meet

the identified need

Deterministic

planning

Network investment is proposed when a criterion in the Technical Rules can no longer be

met. i.e. the forecast load exceeds the contingency capacity of a zone substation

Total capacity Total installed transformer capacity of a zone substation

Post-contingent The condition of the system following a contingency event i.e. system abnormal

Pre-contingent The condition of the system prior to a contingency event i.e. system normal

Probability of

exceedance

The likelihood that a given level of maximum demand forecast will be met or exceeded in

any given year

Risk-based

planning

Network investment is proposed based on assessment of the costs and economic

benefits of network augmentation by quantifying the cost consumers incur when their

electricity supply is interrupted for a period of time.

Page 8 of 37

Executive summary

Western Power is seeking submissions from non-network solution proponents in relation to network capacity constraints in the Mandurah load area. Consideration of non-network options is an important aspect of Western Power’s obligation to deliver a reliable electricity network service at the lowest possible cost. This is because in some cases, non-network solutions may be more cost efficient than investing in network assets with long asset lives that may not reach full utilisation.

Located 80 km south of Perth City, the Mandurah load area includes the southern metropolitan coastal strip bound by Safety Bay Road in the north, Mandurah and Harvey Estuary in the south and extends to encompass Pinjarra. Supply to the Mandurah load area comes from 132 kV transmission lines in the north via Rockingham (RO) zone substation and from the east via Pinjarra (PNJ) zone substation. The neighbouring Kwinana and Bunbury load areas supply the area with the bulk of its power.

The bulk of load in the area is along the coastal strip and served by the existing Meadow Springs (MSS) and Mandurah (MH) zone substations, both of which are experiencing rapid growth and are encroaching on network capacity during periods of peak demand. To date, Western Power has alleviated capacity constraints through a number of permanent distribution load transfers from MH to MSS and MSS to Waikiki (WAI) zone substations in the period 2009/10 to 2013/14. Continued growth in the area however will require further investment in the Mandurah load area to meet its forecast capacity needs.

Factoring in historic load volatility in the face of continued strong growth in peak demand, a detailed planning assessment was initiated to determine the most economically efficient investment pathway to address the identified future needs of the area. This option involves the staged rebuild of MH zone substation at an estimated net present cost of $30.7 million. The two stages include:

1. Major extension of MH site and installation of a 132/22 kV 66 MVA transformer and includes distribution network augmentation to facilitate 10 MVA load transfer from MSS to MH for service by 2020/21

2. Installation of a second 132/22 kV 66 MVA transformer and includes distribution network augmentation to facilitate 20 MVA load transfer from MSS to MH for service by 2023/24

Alternatively, non-network solutions such as embedded generation, energy storage and a range of demand management services could enable Western Power to operate the electricity system in a more cost-effective manner. In addition, Mandurah’s recent high uptake rate of solar PV paired with the future potential of energy storage technologies, adds further uncertainty to whether the current load forecast will materialise.

From summer 2017/18 onwards, Western Power is seeking to manage a forecast 5.5 MVA of peak demand growth in the Mandurah load area, with the intent to minimise costs, increase network utilisation and defer network augmentation. Western power is aiming to defer the aforementioned network investment from 2020/21 to 2021/22 or further years depending on the technical potential and cost effectiveness of non-network solutions. In order to meet forecast demand in the area, Western Power intends to confirm the type of network investment to be undertaken by 2018/19 to ensure a solution is in place by 2020/21.

Western Power welcomes written submissions from interested parties to support development of a non-network solution for the Mandurah load area to be provided on or before 12 August 2016.

All submissions should be directed to the Western Power Head of Network Planning and Standards at nonnetwork@westernpower.com.au.

Page 9 of 37

1 Introduction

1.1 Network regulation in Western Australia

The Electricity Networks Access Code 2004 (the Code) “establishes a framework for third party access to electricity transmission and distribution networks with the objective of promoting the economically efficient investment in, and operation and use of, networks and services of networks in Western Australia in order to promote competition in markets upstream and downstream of the networks.”

Section 9 of the Code, requires Western Power to conduct a Regulatory Test for major augmentation projects whose estimated costs exceed the following thresholds:

Transmission $35.5 million;

Distribution $11.8 million; or

Combined transmission and distribution $35.5 million

Solutions proposed to address network issues are required to meet the following criteria:

All credible options have been considered, including non-network options; and

The proposed approach maximises the net benefit to those who generate, transport and consume electricity

The Code also obliges Western Power to conduct a public consultation process for major augmentation projects.

1.2 Purpose

Western Power aims to deliver a reliable electricity network service at the lowest possible cost, with non-network solutions potentially more cost efficient than investing in assets with long operating lifespans. The NNOR process facilitates identification of the most appropriate non-network solution to deliver the lowest-cost solution to our customers. This document describes:

The identified need in relation to the Mandurah and Meadow Springs network;

The potential credible network options that address this need; and

The technical characteristics of a credible non-network option

1.3 Structure

This document is structured as follows:

Section 2 provides background information on the Mandurah and Meadow Springs network and the associated network infrastructure;

Section 3 describes the identified need that is to be addressed;

Section 4 reviews the planning methodology and assumptions used in assessing the credible options;

Section 5 details the credible network options, indicative augmentation costs and estimated commissioning dates;

Section 6 presents the technical characteristics of the identified need that a non-network option would be required to meet; and

Section 7 provides guidance on the assessment process to third parties interested in submitting a response

Page 10 of 37

2 Background The bulk of load in the Mandurah area is located along the southern metropolitan coastal strip served by the MH and MSS zone substations, both of which are experiencing rapid growth. The locational share of electricity demand at peak is approximately 70% residential and 30% commercial/light industrial load. This compares to the overall customer numbers of 97% residential and 3% commercial/light industrial. The Mandurah load area network is illustrated in Figure 1 below.

Figure 1: Mandurah load area network diagram

In 2014/15, the network demand growth rates were high with the majority of future urban development expected to appear in the coastal corridor north of MSS. This urban growth is the primary driver behind the emerging capacity constraints at MH and MSS zone substations.

2.1 Network topography

2.1.1 Zone substations

Mandurah (MH)

MH zone substation was established in 1982 and is located within one kilometer of the Mandurah CBD. MH is fed from two 132 kV transmission circuits, one from PNJ zone substation and another from MSS/WAI

Page 11 of 37

zone substations. MH is designed to transform power from 132 kV to 22 kV, supplying Mandurah city and the surrounding southern and eastern suburbs via the distribution network.

MH currently consists of three 33 MVA power transformers which supply three 22 kV outdoor switchyards with nine 22 kV distribution feeders, three capacitor circuits and one station transformer for LV supplies (refer to Figure 2). The power transformers are in good condition and there is currently no scheduled 132 kV or 22 kV primary plant asset replacement works for MH.

MH is a summer critical substation and currently provides a total rating of 101.3 MVA, with a contingency capacity of 72.2 MVA based on the loss of one transformer. MH operates under the Normal Cyclic Rating (NCR) criterion and has the facility to connect a Rapid Response Spare Transformer (RRST) in the event of a major transformer failure.

Figure 2: MH zone substation single line diagram

Meadow Springs (MSS)

MSS zone substation was established in 2005 and is located within six kilometers of the Mandurah CBD. MSS is fed from two 132 kV transmission circuits, one from WAI/MH zone substations and another from Cannington terminal/PNJ zone substation. MSS is designed to transform power from 132 kV to 22 kV, supplying Mandurah city and the surrounding northern and eastern suburbs via the distribution network. MSS also supplies the adjacent Parklands traction station via two 132 kV circuits.

MSS currently consists of two 33 MVA power transformers which supply two 22 kV indoor switchboards with seven 22 kV distribution feeders, four capacitor circuits and two station transformers for LV supplies (refer to Figure 3). The power transformers are in good condition and there is currently no scheduled 132 kV or 22 kV primary plant asset replacement works for MSS.

MSS is a summer critical substation and currently provides a total rating of 74.1 MVA, with a contingency capacity of 52.8 MVA based on the loss of one transformer. MSS also operates under the NCR criterion and has the facility to connect a RRST in the event of a major transformer failure.

Page 12 of 37

Figure 3: MSS zone substation single line diagram

2.1.2 Distribution network

Mandurah 22 kV feeders

There are currently nine feeders emanating from MH zone substation. Feeders MH502 and MH522 primarily supply the Mandurah CBD. Feeders MH501, MH515 and MH520 supply the east and south eastern Mandurah suburbs. Feeders MH502, MH504, MH509, MH512 and MH521 supply Mandurah Island from Halls Head to Wannanup and extending further south to Herron.

The summer ratings, circuit length and number of customers supplied by each feeder are provided in Table 1 below.

Table 1: MH 22 kV feeder details

Feeder ID Feeder name Rating (A) Circuit length (km) # of customers

MH501 L213 Pinjarra Rd 324 59 3,709

MH502 Elizabeth St 324 127 5,419

MH504 France St 324 85 4,031

MH509 Waxflower Vsta 324 155 4,684

MH512 Lanyon St 324 286 5,519

MH515 4 Dower St 324 65 1,502

Page 13 of 37

MH520 Dower St South 324 188 3,805

MH521 Old Coast Rd 324 143 3,198

MH522 79 Allnutt St 324 46 1,979

Meadow Springs 22 kV feeders

There are currently seven feeders emanating from MSS zone substation. Feeder MSS540 primarily supplies the Mandurah CBD and Ocean Marina. Feeders MSS505, MSS508, MSS536 and MSS537 supply the northern and coastal Mandurah suburbs. Feeder MSS504 supplies the eastern suburbs and feeders MSS507 and MSS536 supply the northern suburbs from Secret Harbour to Port Kennedy.

The summer ratings, circuit length and number of customers supplied by each feeder are provided in Table 2 below.

Table 2: MSS 22 kV feeder details

Feeder ID Feeder name Rating (A) Circuit length (km) # of customers

MSS504 L1808 Tandure Cir 324 191 3,661

MSS505 L327 Fremantle Rd 324 133 4,988

MSS507 Parklands Tunnel 324 244 4,037

MSS508 Meadow Springs B RMU 324 142 4,296

MSS536 L141 Tangadee Rd 324 103 604

MSS537 L281 Gordon Rd 324 57 37

MSS540 L303 Meadow Springs Drv 324 83 2,925

2.2 Recent network investment in the Mandurah load area

To date, all proposals to alleviate the capacity constraints in the Mandurah area have developed from the Mandurah Load Area Investment Strategy. In the period 2009/10 to 2013/14, substation capacity was managed through a number of permanent distribution load transfers from MH to MSS and MSS to WAI zone substations.

Factoring in historic load volatility in the face of continued strong growth in peak demand, a detailed planning assessment was initiated to determine the most economically efficient investment pathway to address the identified need. The outcome from the assessment recommended the MSS Expansion project

Page 14 of 37

which includes the installation of a third transformer at MSS and load transfers from MH to MSS by 2017/18.

This investment decision was endorsed by the ERA as detailed1 in their ‘Determination on Application for Exemption from certain requirements of the Technical Rules submitted by Western Power’ on 20 July 2015. The MSS Expansion project provides additional substation capacity, however it does not meet the entire capacity and compliance requirements for the Mandurah load area. Consequently, this report refers to the identified need following completion of the ERA endorsed MSS Expansion project.

2.3 Embedded generation

Since 2011, Mandurah has experienced a rapid uptake of residential and commercial solar photovoltaics (PV) systems. The estimated installed PV inverter capacity is approximately 20 MW with an average system size of 2.2 kW. Despite the high penetration of solar PV, analysis has shown that PV contributes a mere 2% reduction at time of substation peak loading with the MH and MSS zone substations peaking between 5pm and 7pm in the evening.

There is no declared or registered large embedded generation connected in the Mandurah load area to provide network support capacity. Western Power is aware some customers have their own stand-by generators but no arrangement is in place to call on network support capacity.

2.4 Demand side management

Initial investigation indicates that there is some existing aggregated demand side response in the Mandurah load area. Existing aggregated demand side response would support adoption of a demand response component of any non-network solution.

1 https://www.erawa.com.au/electricity/electricity-access/western-power-network/technical-rules/era-

determinations-on-exemptions-from-the-technical-rules/meadow-springs-zone-substation

Page 15 of 37

3 Description of identified need This section describes the remaining substation capacity constraints in the Mandurah load area following completion of the earlier mentioned MSS Expansion project in 2017/18.

3.1 Load forecast and emerging constraints in the Mandurah load area

MH zone substation is a summer critical substation with a total rating of 101.3 MVA, a NCR contingency capacity of 72.2 MVA and a growth rate of 2.3 MVA per annum. MSS zone substation is a summer critical substation with a total rating of 74.1 MVA, a NCR contingency capacity of 52.8 MVA and a growth rate of 3.2 MVA per annum.

The Mandurah load area has a combined total rating of 175.4 MVA and a NCR contingency capacity of 125.0 MVA. The combined rate of growth is 5.5 MVA per annum.

Western Power plans zone substation capacity based on a 10% PoE load forecast. Table 3 shows the MH and MSS zone substations 2015 summer 10% and 50% probability of exceedance (PoE) peak demand forecasts for the ten year period.

Table 3: Zone substation load forecasts 2015

Substation Forecast

(MVA) 15/16 16/17 17/18 18/19 19/20 20/21 21/22 22/23 23/24 24/25

MH (non-coincident)

Summer

50% PoE 73.6 75.5 67.4 69.1 70.8 72.4 74.1 75.8 77.5 79.2

Summer

10% PoE 81.0 83.3 75.5 77.5 79.5 81.5 83.5 85.5 87.4 89.4

MSS (non-coincident)

Summer

50% PoE 55.7 58.6 71.5 74.9 78.3 81.7 85.1 88.5 91.8 95.2

Summer

10% PoE 61.9 65.1 78.3 82.0 85.7 89.4 93.1 96.8 100.5 104.3

Mandurah load area

(MH + MSS coincident)

Summer

50% PoE 127.1 132.0 137.0 142.1 147.2 152.2 157.3 162.4 167.5 172.6

Summer

10% PoE 140.7 146.2 151.9 157.6 163.3 169.0 174.7 180.4 186.1 191.9

Figures 4-6 compare the summer peak demand forecasts against the total capacity and NCR contingency capacity for MH, MSS and the Mandurah load area.

Page 16 of 37

Figure 4: MH zone substation summer peak demand forecast

For MH, beyond 2017/18, the 10% PoE load forecast continues to exceed NCR capacity and the 50% PoE load forecast is expected to exceed NCR capacity by 2020/21.

Figure 5: MSS zone substation summer peak demand forecast

In order to best manage zone substation capacity in the area for the 2017/18 period, additional transformer capacity is planned to be installed in 2017/18 through the MSS Expansion project, with a 10 MVA load transfer from MH to MSS. Beyond 2017/18, the 10% PoE load forecast is expected to exceed NCR capacity by 2018/19 and the 50% PoE load forecast is expected to exceed NCR capacity by 2020/21. This is primarily due to the load transfer from MH to MSS.

Page 17 of 37

Figure 6: Mandurah load area summer peak demand forecast

Considering the Mandurah load area, beyond 2017/18, the 10% PoE load forecast continues to exceed NCR capacity and the 50% PoE load forecast is expected to exceed NCR capacity by 2020/21.

Table 4 presents the summer peak load and customers at risk under 10% and 50% PoE forecasts for the Mandurah load area. Post-contingent2 load at risk occurs from 2020/21 onwards under a 50% PoE forecast. Under a 10% PoE forecast, the post-contingent load at risk in 2020/21 is 18.1 MVA, which represents approximately 7,000 customers without electricity supply.

There is no pre-contingent3 load at risk during the ten year period.

2 Post-contingent – system abnormal conditions (i.e. load above NCR capacity)

3 Pre-contingent – system normal conditions (i.e. load above N capacity)

Page 18 of 37

Table 4: Load and customers at risk in the Mandurah load area (combined MH + MSS)

MVA 15/16 16/17 17/18 18/19 19/20 20/21 21/22 22/23 23/24 24/25

Summer 50% PoE 127.1 132.0 137.0 142.1 147.2 152.2 157.3 162.4 167.5 172.6

Summer 10% PoE 140.7 146.2 151.9 157.6 163.3 169.0 174.7 180.4 186.1 191.9

N capacity 175.4 175.4 211.7 211.7 211.7 211.7 211.7 211.7 211.7 211.7

N – load at risk

50% PoE 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

N – load at risk

10% PoE 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

NCR capacity 125.0 125.0 150.8 150.8 150.8 150.8 150.8 150.8 150.8 150.8

NCR – load at risk

50% PoE 2.2 7.0 0.0 0.0 0.0 1.4 6.5 11.6 16.7 21.7

NCR – customers

at risk 50% PoE 943 3,059 0 0 0 487 2,693 4,898 7,100 9,301

NCR – load at risk

10% PoE 15.8 21.3 1.0 6.7 12.4 18.1 23.9 29.6 35.3 41.0

NCR – customers

at risk 10% PoE 6,216 8,380 315 2,555 4,791 7,023 9,251 11,474 13,694 15,912

In addition to the zone substation capacity constraints, there are two MH 22 kV distribution feeders forecast to be over-utilised (>80%) from 2017/18. Western Power is currently investigating solutions to manage utilisation levels. These feeders are identified in the table below.

Table 5: Forecast over-utilised 22 kV distribution feeders at MH

Feeder ID Feeder name Utilisation % (by 2017/18)

MH509 Waxflower Vsta 84

MH512 Lanyon St 96

Limited Distribution Transfer Capacity (DTC) exists between the Mandurah load area and adjacent zone

substations and is expected to diminish as load growth increases in the area. DTC between MH and PNJ is

negligible due to limited interconnectivity and large distances between MH and PNJ. DTC between MSS and

WAI is negligible due to feeder capacity constraints on WAI and limited interconnectivity between MSS and

WAI.

Page 19 of 37

Approximately 10 MVA of DTC is currently available between MH and MSS networks however this capacity

is expected to be limited following the MSS Expansion project in 2017/18, where further offloading of MH

will be restricted due to the new network configuration.

3.2 Summary of identified need

Following completion of the MSS Expansion project in 2017/18, Western Power forecasts the following capacity constraint will need to be addressed:

MH zone substation will continue to be non-compliant with the NCR Criterion across the ten year

period under a 10% PoE load forecast;

MSS zone substation will become non-compliant with the NCR Criterion in 2018/19 under a 10%

PoE load forecast;

The combined Mandurah load area will continue to be non-compliant with the NCR Criterion across

the ten year period under a 10% PoE load forecast;

Inadequate DTC between the Mandurah load area and adjacent zone substations; and

Two 22 kV distribution feeders forecast to be over-utilised by 2017/18

Initial economic and risk analysis has concluded that augmenting the Mandurah load area network to increase substation transformer capacity to address the identified need is required in-service by 2020/21. A decision to trigger network investment would be required three years prior (2018/19) to the required in-service date to allow time to plan, design, procure, construct and commission the proposed network solution.

Page 20 of 37

4 Planning assessment and assumptions

4.1 Planning methodology

Western Power must develop the SWIS in accordance with the Technical Rules, approved by the ERA in April 2007. The Technical Rules is a document enabled by the Code which defines the performance requirements for the electricity network.

The SWIS must operate during planned and unplanned outages of plant and equipment, due to faults or maintenance requirements. With respect to system reliability, the contingency criteria in clause 2.5 of the Technical Rules outline the number and type of outages that need to be allowed for in designing various parts of the transmission and distribution networks. Each contingency criterion implies a degree of reliability security and guides the determination of zone substation capacity.

For zone substation capacity, compliance is evaluated by comparing the 10% PoE load forecast against the contingency capacity of the zone substation. The trigger year for network investment is the year when the forecast exceeds contingency capacity.

Western Power has introduced risk-based planning techniques to supplement deterministic contingency criteria in the Technical Rules. Risk-based planning assesses the costs and economic benefits of network augmentation to help define the optimal network investment trigger year to address a particular network constraint.

The planning criterion in the Technical Rules is inherently deterministic and does not explicitly consider the application of risk-based (or ‘probabilistic’) planning techniques. However, if a decision on a risk-based planning investment conflicts with compliance obligations prescribed in the Technical Rules, Western Power will engage with the ERA to assess the risks associated with the cost of compliance (compared to non-compliance) to determine if an exemption is applicable. This approach is undertaken on a case-by-case basis to reconcile the outcomes of the two planning approaches.

4.2 Technical rules

MH and MSS zone substations are located in the metropolitan area and are classified under the planning criteria, clause 2.5.4(b) – Normal Cyclic Rating Criterion, in the Technical Rules4.

2.5.4 Zone Substations

(b) Normal Cyclic Rating (NCR) Criterion

(1) The NCR risk criterion permits the loss of a portion of power transfer capacity at a substation following the unplanned loss of a supply transformer within that substation

(2) The portion of the power transfer capacity that may be lost is the lesser of:

(A) 75% of the power transfer capacity of the smallest supply transformer within the substation; and

(B) 90% of the power transfer capacity of the rapid response spare supply transformer

4 Refer to p.27 - http://www.westernpower.com.au/corporate-information-technical-rules.html

Page 21 of 37

4.3 Demand forecasts

The 2015 annual peak demand forecasts used in this report were developed by Western Power’s System Forecasting area. Two peak demand forecasts are developed for each substation:

Non-coincidental with the SWIS annual peak demand; and

Coincidental with the SWIS annual peak demand

The non-coincidental substation forecasts identify the maximum annual peak demand for each substation whilst the coincidental forecast is the demand at each substation recorded at the time of the SWIS annual peak demand.

Annual peak demand in the Mandurah load area is forecast to grow at an average rate of 5.5 MVA per annum. This growth is primarily due to future urban development underpinned by population increase and is consequently driving the emerging capacity constraints at MH and MSS zone substations.

4.4 Demand management screening tool

Western Power’s Demand Management Screening Tool (DMST) is used within Western Power’s demand management screening test process. This screening test is conducted as the first step of Western Power’s non-network solutions evaluation framework, which is used to determine whether cost-effective non-network solutions exist as feasible alternatives to network solutions.

The DMST calculates the cost-effectiveness of demand management solutions and the amount of peak demand reduction these measures are expected to achieve. This is used to determine if the peak demand reduction expected from cost-effective demand management solutions is sufficient to defer network investment within a realistic timeframe.

The DMST output summary on assessment of the Mandurah load area indicates there may be sufficient technical potential to procure up to 7.6 MVA of non-network solutions from commercial and light industrial customers at a cost below the benefit of deferring the preferred network solution. Hence there is an opportunity to defer network investment by one year (or potentially longer).

4.5 Value of customer reliability

The Value of Customer Reliability (VCR) is a cost of consequence metric expressed in $/kWh or $/MWh and aims to represent the willingness of customers to pay for a reliable supply of electricity. Western Power’s VCR estimates were developed from methodology specified in the Oakley Greenwood report5 whilst also taking into account Western Australian statistics.

Western Power applies a locational VCR when valuing unserved energy in constrained areas of the network. The locational VCR was derived from the sector VCR estimates and weighted by the composition of load by sector at the relevant zone substations. Further VCR sensitivity analysis will be applied in preparation of the Draft Project Assessment Report.

5 This report and further information can be obtained from AEMO’s website:

http://www.aemo.com.au/Electricity/Planning/Value-of-Customer-Reliability-review

Page 22 of 37

Table 6: Locational VCRs

Zone substation VCR ($/MWh)

MH 48,416

MSS 48,434

Mandurah Load Area 48,423

4.6 Discount rate

A discount rate of 6.53% (pre-tax nominal WACC for the Access Arrangement 3 period) has been utilised in the initial investment evaluation to estimate the net present cost of each option.

4.7 Cost estimates

The capital cost estimates are determined from Network Planning’s Estimating Handbook. Cost estimates are indicative costs only and represent ±30% accuracy. Cost estimates will be refined in preparation of the Draft Project Assessment Report.

Page 23 of 37

5 Potential credible options This section provides a summary of potential credible options including network and non-network options that may address the identified need. It also identifies the preferred network option.

The analysis of options presented in this report may be subject to change due to additional information considered in preparation of the Draft Project Assessment Report.

5.1 Base Case

The Base Case represents the state of the network following completion of the MSS Expansion project in 2017/18. It is essentially the ‘Do Nothing’ option, with respect to the identified need in this report, and is used to benchmark against all the credible options to determine the option that maximises net benefits.

The calculated expected unserved energy is 4 MWh in 2020/21 and increases to 52 MWh in 2024/25. The associated annual value of unserved energy is $219k and $2.5 million respectively with a cumulative total of $81.7 million from the period 2017/18 to 2029/30. Further details on expected unserved energy are provided in section 6.2.

5.2 Network options

5.2.1 OPTION 1 – STAGED REBUILD OF MH AND EXPAND MSS ZONE SUBSTATION

Option 1 involves the staged installation of additional transformer capacity at both zone substations in the Mandurah load area.

Table 7: Description and timing of Option 1

Stage Summary description Timing

1

Major extension of MH substation site to enable installation of 1x

132/22 kV 66 MVA power transformer, 1x 22 kV indoor switchroom,

new relay control room and one new 132 kV line supply circuit. Load

transfer 10 MVA from MSS to MH via new distribution interconnections

and switching

2020/21

2

Minor extension of MSS substation site to enable installation of 1x

132/22 kV 33 MVA power transformer, 1x 22 kV indoor switchroom and

new relay control room

2023/24

3 Installation of 1x 132/22 kV 66 MVA power transformer and 1x 22 kV

indoor switchroom at MH. 2027/28

MH substation is located close to the Mandurah CBD in a highly dense urban area surrounded by residential properties. In 2012/13, land adjacent to MH was purchased to facilitate the proposed site extension. Following completion of stage 1, the new 66 MVA transformer will initially be limited to 33 MVA capacity until completion of stage 3. The MH substation will continue to operate under the NCR criterion.

MSS substation is located adjacent to the Lakelands residential estate and the Perth Transport Authority (PTA) traction substation and is immediately surrounded by bushland owned by WESTERN POWER. MSS site will require extension to facilitate the installation of a fourth transformer and associated switchgear

Page 24 of 37

and protection equipment. Following completion of stage 2, the MSS substation will continue to operate under the NCR criterion.

Stage 3 is the final stage of the MH Rebuild and involves the installation of a second 66 MVA transformer and associated switchgear and protection equipment. Upon completion of stage 3, MH will operate as a split NCR/N-1 substation as follows:

N-1 operation for the two new 66 MVA transformers providing a contingency capacity of 66 MVA

NCR operation for the existing three 33 MVA transformers providing a contingency capacity of 72.2 MVA

The advantage of this option is that there is no residual unserved energy after completion of stage 1 until 2031/32. The main disadvantage is that two substation sites require more complex capacity expansion upgrades beyond their intended design rating which results in additional capital expenditure. The estimated Net Present Cost (NPC) for option 1 is $35.7 million.

5.2.2 OPTION 2 – STAGED REBUILD OF MH ZONE SUBSTATION

Option 2 involves the staged rebuild of the MH zone substation including augmentation of the distribution network to enable two large load transfers of approximately 30 MVA from MSS to MH.

Table 8: Description and timing of Option 2

Stage Summary description Timing

1

Major extension of MH substation site to enable installation of 1x

132/22 kV 66 MVA power transformer, 1x 22 kV indoor switchroom,

new relay control room and one new 132 kV line supply circuit. Load

transfer 10 MVA from MSS to MH via new distribution interconnections

and switching

2020/21

2

Installation of 1x 132/22 kV 66 MVA power transformer and 1x 22 kV

indoor switchroom. Load transfer 20 MVA from MSS to MH via new

distribution interconnections and switching

2023/24

Following completion of stage 1, the new 66 MVA transformer will initially be limited to 33 MVA capacity until completion of stage 2. The MH substation will continue to operate under the NCR criterion.

Stage 2 is the final stage of the MH Rebuild and involves the installation of a second 66 MVA transformer and associated switchgear and protection equipment. Upon completion of stage 2, MH will operate as a split NCR/N-1 substation as follows:

N-1 operation for the two new 66 MVA transformers providing a contingency capacity of 66 MVA

NCR operation for the existing three 33 MVA transformers providing a contingency capacity of 72.2 MVA

The advantages of this option is that there is no residual unserved energy after completion of stage 1 until 2031/32 and it is the least cost network solution across the investment period. Option 2 is the preferred credible network option with an estimated NPC of $30.7 million.

Page 25 of 37

5.2.3 OPTION 3 – EXPAND MSS AND BUILD NEW ZONE SUBSTATION

Option 3 involves the expansion of MSS zone substation and the establishment of a new Furnissdale (FSE) zone substation including augmentation of the distribution network to enable load transfers of approximately 35 MVA from MH and MSS to FSE throughout the investment period.

Table 9: Description and timing of Option 3

Stage Summary description Timing

1

Minor extension of MSS substation site to enable installation of 1x

132/22 kV 33 MVA power transformer, 1x 22 kV indoor switchroom and

new relay control room. Load transfer 10 MVA from MH to MSS via new

distribution interconnections and switching

2020/21

2

Establish new FSE zone substation and install 1x 132/22 kV 33 MVA

power transformer, 1x 22 kV indoor switchroom, new relay control

room and two new 132 kV line supply circuits. Install 2x 22 kV

distribution feeders and interconnect with MH and MSS feeders to

enable 20 MVA load transfers

2022/23

3

Installation of 1x 132/22 kV 33 MVA power transformer and 1x 22 kV

indoor switchroom. Load transfer 10 MVA from MSS to FSE and 5 MVA

from MH to FSE via new distribution interconnections and switching

2025/26

MSS site will require extension to facilitate the installation of a fourth transformer and associated switchgear and protection equipment. Following completion of stage 1, the MSS substation will continue to operate under the NCR criterion.

Stage 2 establishes a new FSE zone substation in the Mandurah load area, initially built with one 33 MVA transformer, and supplied by two 132 kV line circuits. The two 132 kV line circuits cut-in to the nearby MH-PNJ 132 kV line circuit. Upon completion of stage 2, FSE will operate under the NCR criterion.

Stage 3 involves the installation of a second 33 MVA transformer at FSE resulting in a contingency capacity of 55 MVA. Upon completion of stage 3, FSE will continue to operate under the NCR criterion.

The advantage of this option is that there is no residual unserved energy after completion of stage 1 until 2031/32. The disadvantages of this option include:

Stage 2 involves establishing a new substation including two new 132 kV transmission lines to supply the site and;

Most expensive credible network option with an estimated NPC of $42.4 million

5.2.4 PREFERRED NETWORK OPTION

Based on the initial investment evaluation presented above, Western Power has identified Option 2 as the preferred credible network option to address the identified need in the Mandurah load area. The table below summarises the indicative cost estimates for each of the credible network options.

Page 26 of 37

Table 10: Cost estimates of credible network options

Option

Stage 1

nominal

capex

All stages NPC ($M) Capacity

increase

(MVA)

$/kVA

Capex Opex Total

Base Case 0 0 0 0 0 0

Option 1 – Staged Rebuild of

MH and Expand MSS Zone

Substation

20.3 31.1 4.6 35.7 94.8 376

Option 2 – Staged Rebuild of

MH Zone Substation 20.3 26.1 4.6 30.7 69.0 445

Option 3 – Expand MSS and

Build New Zone Substation 13.2 39.4 3.0 42.4 80.3 528

5.2.5 NON-CREDIBLE NETWORK OPTIONS

The following short term network options were considered and assessed as non-credible as they did not substantively address the capacity constraint, were technically or practically unviable or cost prohibitive. These network options include:

Transfer of load from MH and MSS to PNJ zone substation;

Transfer of load from MSS to WAI zone substation;

Continued management of load transfers between MH and MSS zone substations;

Review of Transformer Overloading Ratings Program (TORP) studies for MH and MSS transformers using actual temperature series data with the view to increase transformer normal cyclic ratings

Paralleling transformers to improve load sharing and maximise utilisation of transformer capacity; and

Install additional cooling fans to increase transformer ratings and operate fans earlier in the day during the summer period

5.3 Credible non-network options

Network support services assist in managing network flows to ensure secure and reliable operation and can also support the deferral of network augmentation. These services can be provided through embedded generation and/or demand management services.

5.3.1 EMBEDDED GENERATION

Embedded generation is typically connected to the LV or HV distribution network or directly connected to a zone substation. Embedded generation may include but are not limited to:

Gas turbines

Reciprocating engines (diesel, gas or oil);

Wind turbines;

Battery storage technologies;

PV generation (solar); and

Cogeneration or poly-generation from industrial processes (combined cooling, heat and power)

Page 27 of 37

At the time of preparing this report, there are no known proponents for connection of substantial additional embedded generation to the MH and MSS networks in the Mandurah load area other than the ongoing installation of PV systems. Proponents of generation are encouraged to apply or express their interest to Western Power. Refer to section 7 for submission details6.

5.3.2 DEMAND MANAGEMENT

Demand management involves the agreement of customers, typically industrial and commercial customers, to curtail their load, run on-site standby generation or disconnect from the network for short periods to reduce their impact on the network during times of peak load. Reducing residential peak load may also be achieved by customers shifting their usage away from peak periods or reducing their overall consumption by implementing energy efficiency measures. The effectiveness of these initiatives depends on the extent of participant uptake.

Demand management services may include but are not limited to:

Dispatchable (demand response) o Curtailable loads o Interruptible loads o Stand-by generators o Direct Load Control (DLC)

Non-dispatchable o Energy efficiency programs o Education programs to reduce peak demand o Tariffs/Pricing o Chilled water/ice storage o Power Factor Correction (PFC) o Energy management systems

At the time of preparing this report, with the exception of identified aggregated demand response, there are no other known proponents of demand management services on the MH and MSS networks in the Mandurah load area. Proponents of demand management services are encouraged to apply or express their interest to Western Power. Refer to section 7 for submission details.

6 Refer to the following websites for more details on the connection process: http://www.westernpower.com.au/electricity-retailers-generators-generator-and-transmission-connections.html & https://www.cleanenergycouncil.org.au/technologies/grid/grid-connection.html

Page 28 of 37

6 Technical characteristics for non-network options This section describes the technical characteristics required of a non-network solution to address the identified need. A potential credible non-network option must satisfy the timing, operational and technical requirements as detailed below. Western Power’s intent is to evaluate all potential non-network solutions with proponents in order to deliver the lowest-cost solution to our customers.

6.1 Size and location of peak load reduction or additional supply

Table 11 outlines the estimated peak load reduction, or additional generation in the Mandurah load area that would alleviate the network capacity constraint. The 2015 growth rate is 5.5 MVA per annum.

Table 11: Summer peak demand offsets required from non-network solutions (under 10% PoE)

Year 15/16 16/17 17/18 18/19 19/20 20/21 21/22 22/23 23/24 24/25

Load at risk

(MVA) 15.8 21.3 1.0 6.7 12.4 18.1 23.9 29.6 35.3 41.0

Customers

at risk 6,216 8,380 315 2,555 4,791 7,023 9,251 11,474 13,694 15,912

A credible non-network solution may provide the full or partial annual peak demand offsets to address the forecast capacity shortfall in order to defer network augmentation. Due to the high growth rate and inherent load volatility, Western Power is seeking a peak demand reduction of 5.5 MVA to achieve a one year deferral of network augmentation. Additional years of deferral will also be considered.

6.2 Network risk profile and potential deferral benefit

As detailed in section 5.1, the impact of the network limitations under the Base Case (no action taken) results in a significant amount of unserved energy towards the end of the ten year period, refer to Table 12 below.

Page 29 of 37

Table 12: Forecast network limitation (Base Case)

Year 15/16 16/17 17/18 18/19 19/20 20/21 21/22 22/23 23/24 24/25

Energy at risk

(MWh) 197.8 354.9 8.6 39.7 106.1 203.6 340.4 525.7 756.6 1044.6

Hours at risk

(hr) 47 69 6 18 29 41 60 75 93 120

% of year 0.54 0.79 0.07 0.21 0.33 0.47 0.68 0.86 1.06 1.37

Expected

unserved

energy

(MWh)

17.25 24.03 0.83 1.59 2.84 4.53 6.85 9.93 19.97 52.18

Value of

expected

unserved

energy

($’000)

836 1,164 40 77 137 219 332 481 967 2,526

The expected unserved energy7 is the energy at risk weighted by the probability of an outage due to a major transformer failure. The value of expected unserved energy is then obtained by multiplying the expected unserved energy by the VCR.

A deferral benefit of $1.2 million was estimated based on deferring the preferred network option (Option 2) by one year. Additional benefits may be achieved by further reductions in peak demand.

6.3 Investment timing requirements

Based on Western Power’s Technical Rules, to recover and maintain compliance with clause 2.5.4 (b) at MH and MSS zone substations, the deterministic network investment trigger year is 2017/18.

By applying risk-based planning techniques and quantifying the expected unserved energy in the Mandurah load area, the risk-based network investment trigger year is 2020/21. This assessment also considers other ‘collective’ network risk factors associated with the substation including load transfers, network interconnectivity, upstream/downstream constraints, strategic spares and contingency plans. Deferral benefits are based on the risk-based network investment trigger year which seeks to defer the preferred network investment from 2020/21 to 2021/22 (or further years).

Proposed non-network options, at a minimum, must be capable of reducing network loading or increasing network capacity in the Mandurah load area during the summer period between January and February on very hot afternoons/evenings between 4pm and 9pm.

7 Unserved energy is estimated by taking 30% weighting of the unserved energy at 10% PoE demand forecast and 70%

weighting of the unserved energy at 50% PoE demand forecast

Page 30 of 37

6.4 Zone substation operating profile

Mandurah (MH)

MH zone substation provides electricity to 33,000 customers and the load is comprised primarily of residential and commercial customers. The hourly load trace for MH is shown in Figure 7 below.

Figure 7: MH zone substation hourly load trace (2008 to 2016)

The load profile on the day of peak demand in summer 2016 is shown in Figure 8. The average summer daily load profile is compared with the peak day to illustrate the significant difference in customer demand requirements at these times.

Figure 8: Peak vs average daily summer load profile at MH in 2016

The scatter plot in Figure 9 illustrates that the summer peaks regularly occur around 6pm. Other seasonal peaks are likely correlated with residential evening loads.

Page 31 of 37

Figure 9: Seasonal daily peak times for MH in 2014

Figure 10 shows the normalised load duration curve for MH substation in 2014. The plot shows that the top 20% of demand occurs for less than 1% of the year. This implies that although the probability of a major contingency event is low, the impact of not having sufficient capacity can result in a significant amount of load at risk.

Figure 10: MH normalised load duration curve 2014

Page 32 of 37

Meadow Springs (MSS)

MSS zone substation provides electricity to 20,000 customers and the load is comprised primarily of residential and commercial customers. The hourly load trace for MSS is shown in Figure 11 below.

Figure 11: MSS zone substation hourly load trace (2008 to 2016)

The load profile on the day of peak demand in summer 2016 (same time and day as MH peak) is shown in Figure 12. The average summer daily load profile is compared with the peak day to illustrate the significant difference in customer demand requirements at these times.

Figure 12: Peak vs average daily summer load profile at MSS in 2016

The scatter plot in Figure 13 illustrates that the summer peaks regularly occur around 6pm. Other seasonal peaks are likely correlated with residential evening loads.

Page 33 of 37

Figure 13: Seasonal daily peak times for MSS in 2014

Figure 14 shows the normalised load duration curve for MSS substation in 2014. Similar to MH, the plot shows that the top 20% of demand occurs for less than 1% of the year.

Figure 14: MSS normalised load duration curve 2014

Page 34 of 37

6.5 Power system security and reliability

Proposed non-network options must be capable of reliably meeting electricity demand under a range of conditions. If the non-network option is a large generator operating in parallel with the Western Power HV distribution network, the generator must comply with the requirements prescribed in the connection application process8. If the non-network option is an embedded generator connecting to the Western Power LV and HV distribution network, the embedded generator must comply with criteria outlined in the Network Integration Guidelines9 for inverter embedded generation.

6.6 Operation

An event is defined as the loss of a power transformer at MH or MSS zone substations coincident on very hot afternoons/evenings between 4pm and 9pm. Any post-contingent non-network solution will need to be capable of operating continuously, during high demand periods where this is insufficient distribution transfer capacity, until the faulted asset is repaired or replaced. Any pre-contingent non-network solution will need to be capable of operating continuously over this period. Table 13 defines the network support parameters associated with such an event.

Table 13: Summary of network support parameters

Parameter Value Comment

Season Summer MH and MSS are both summer critical zone substations

Year 2018 onwards Load at risk in the event of a transformer failure on very

hot afternoons/evenings

Peak period (dates) Weekdays in January and

February Based on statistical analysis from historical data

Peak hours (time) 4pm to 9pm Based on historical data

Support magnitude (MVA) 1.0 in summer 2018

18.1 in summer 2021

Magnitude is dependent upon the load forecast

actualising. The forecast growth rate is 5.5 MVA per

annum. Western Power requires 5.5 MVA peak demand

reduction by summer 2021 to maintain the current risk

threshold

Maximum support/dispatch

hours per event 1-2 hours in summer 2018

Based on statistical analysis from historical data. Duration

expected to increase to 4-5 hours by summer 2021

Maximum consecutive days

for support/dispatch

1-2 days: typical summer

day

5-6 days: extreme event

Based on statistical analysis from historical data. Highly

dependent on weather conditions i.e. heat waves; wind

patterns; cloud cover etc.

8 http://www.westernpower.com.au/electricity-retailers-generators-generator-and-transmission-connections.html

9 http://www.westernpower.com.au/residential-customers-technical-guidance-for-suppliers-and-installers.html

Page 35 of 37

The market benefits associated with the identified need relate to reducing the expected amount of supply interruption that is forecast to occur during the event. To achieve similar levels of market benefits, it is expected that a non-network option also be able to reduce the amount of supply interruption during peak demand periods.

6.7 Fault level contribution

Western Power must design and construct the distribution system so that the potential maximum fault currents do not exceed the following values in Table 14 below.

Table 14: SWIS Technical Rules fault levels

Network voltage (kV) Short circuit level kA

33 13.1

22 16

11 25

6.6 21.9

0.415 31.5

The installation of an embedded generator may raise the fault level of the network to which it is connected. Western Power may need to assess a generator’s contribution to system fault levels against plant and conductor ratings to ensure safety standards and compliance with the Technical Rules10 is maintained.

Table 15: Zone substation fault levels

Substation Voltage level

(kV)

Fault levels (kA)

3 phase 1 phase

MH 132 10.47 10.18

22 4.37 0.99

MSS

132 11.02 10.84

22 4.25 0.97

10 http://www.westernpower.com.au/corporate-information-technical-rules.html

Page 36 of 37

7 Submissions from interested parties

7.1 Invitation for submissions

Western Power is seeking submission from interested proponents of potential credible non-network solutions that either partially or completely addresses the identified need outlined in this report. All submissions should completely and comprehensively address the technical characteristics of non-network options provided in Section 6 and summarised in Section 7.2.

All submissions should be directed to:

Andy Kondola Head of Network Planning and Standards E: nonnetwork@westernpower.com.au All submission enquiries should be directed to: Frendy Engineering Team Leader P: (08) 9326 6119 E: nonnetwork@westernpower.com.au Submissions are due on or before 12 August 2016.

All submissions will be published on the Western Power website unless otherwise requested. Please indicate if you do not wish to have your submission or parts of it published.

7.2 Information from non-network solution proponents

Proponents are invited to make a detailed submission to assist in the assessment of non-network options and should include the following details:

Proponent name and contact details;

An opening statement that describes the proposal and the extent to which it address the identified

need;

For submissions involving installation of products or technology, a technical description, including

but not limited to:

o Location;

o Size of the peak load reduction or additional supply capacity offered;

o Electrical layout schematics (if applicable);

o Network connection requirements (if applicable);

o Contribution to power system security or reliability;

o Contribution to power system fault levels and load flow and stability studies (if applicable);

o The operating profile;

o Reliability;

Page 37 of 37

o How each of these matters is consistent with Western Power technical standards and

statutory requirements11;

Implementation timeline and key milestones;

Measurement and verification procedures;

Proposed operational and contractual commitments, including financier commitments;

Itemised investment proposal including but not limited to:

o Cost of solution ($/kVA) to reduce peak demand; and

o Customer incentive payment scheme (if applicable)

Potential risks associated with the proposal and comparison with the risks associated with the

deferred augmentation, and any actions that can be taken to mitigate these risks. This should

address the risk of not meeting the demand requirement and how any penalties for non-supply will

be addressed; and

Testimonials

Western Power will review each non-network option proposal and may seek further information from the

non-network option proponent to better understand the design of the proposed solution and its impacts

on the network and other network users.

7.3 Next steps

As outlined in Section 1, this report aims to assist Western Power and interested parties identify potential credible non-network options to address the identified need in the Mandurah load area. Western Power will hold a Public Briefing Session on 23 May 2016 to answer questions from interested parties about the report’s content.

Following consideration of submissions in response to the NNOR, Western Power will prepare a Draft Project Assessment Report. That report will present a detailed assessment of all options to address the identified need, including a summary of, and commentary on, the submissions received. Western Power intends to publish the Draft Project Assessment Report in November 2016.

11 http://www.westernpower.com.au/customer-service-customer-applications.html