AusNet Electricity Services
Pty Ltd
Contingent Project Application – Tranche 3

Bushfire Mitigation

Submitted: 31 May 2019

AusNet Services

About AusNet Services
AusNet Services is a major energy network business that owns and operates key regulated
electricity transmission and electricity and gas distribution assets located in Victoria, Australia.
These assets include:An electricity transmission network that services all electricity consumers across Victoria.
We do this via 55 terminal stations, 13,000 transmission towers and 6,600 kilometres ofhigh-voltage transmission powerlines.;An electricity distribution network delivering electricity to more than 740,000 customers
in eastern Victoria. We do this via more than 45,000 kilometres of overhead andunderground powerlines and 335,000 power poles; andA gas distribution network delivering gas to approximately 690,000 customer supply
points in central and western Victoria. We do this via 11,400 kilometres of undergroundgas pipelines.

AusNet Services’ purpose is ‘to provide our customers with superior network and energy
solutions.’ The AusNet Services company values are:

We work safely

We do what’s rightWe’re one team

We deliver

For more information visit: www.ausnetservices.com.au
Contact
This document is the responsibility of the Regulated Energy Services business of
AusNet Services. Please contact the indicated owner of the document below with any inquiries.
Michael Larkin
AusNet Services
Level 31, 2 Southbank Boulevard
Melbourne Victoria 3006
Ph: +61 3 9695 6346

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Table of Contents
1

2

3

Executive summary........................................................................................................................... 5
1.1

Overview ................................................................................................................................. 5

1.2

Tranche 3 contingent project application ................................................................................ 5

1.3

Summary of expenditure and revenue requirements ............................................................. 6

Background and regulatory framework .......................................................................................... 8
2.1

Bushfire risk ............................................................................................................................ 8

2.2

Regulatory Regime ................................................................................................................. 8Contingent project regulatory requirements ................................................................................ 13
3.1

Trigger event ......................................................................................................................... 13

3.2

Materiality threshold .............................................................................................................. 14

4

What is REFCL technology? .......................................................................................................... 15

5

REFCL Program Progress Update ................................................................................................. 19

6

5.1

Overview ............................................................................................................................... 19

5.2

Financial performance against budget .................................................................................. 20

5.3

Technical Issues ................................................................................................................... 22

5.4

HV customers solutions ........................................................................................................ 24

5.5

Key Learnings ....................................................................................................................... 24

Tranche 3 Overview ........................................................................................................................ 26
6.1

7

8

Necessary works ................................................................................................................... 28

Project management process ........................................................................................................ 30
7.1

Program Governance Framework ........................................................................................ 30

7.2

Efficient Delivery ................................................................................................................... 32

7.3

Project cost estimates and unit rates .................................................................................... 32

7.4

Efficient delivery .................................................................................................................... 33

7.5

Change management ........................................................................................................... 34

7.6

Training ................................................................................................................................. 36

Forecast capital expenditure ......................................................................................................... 38
8.1

Introduction ........................................................................................................................... 38

8.2

Prudent and efficient – satisfying the capital expenditure criteria......................................... 38

8.3

RIS Comparison .................................................................................................................... 39

8.4

Zone substation works .......................................................................................................... 40

8.5

Network balancing ................................................................................................................ 41

8.6Line hardening ...................................................................................................................... 43

8.7

Compatible equipment .......................................................................................................... 45

8.8

Assisting HV customers to achieve Code compliance ......................................................... 47

8.9

Program management costs ................................................................................................. 48

8.10 Capital Expenditure in the 2021-25 Regulatory Control Period ............................................ 48
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8.11 Summary of forecasts ........................................................................................................... 49
9Forecast incremental operating expenditure ............................................................................... 50
9.1

Expenditure categories and drivers ...................................................................................... 50

9.2

Forecasting efficient and prudent operating expenditure ..................................................... 50

9.3

Summary of forecasts ........................................................................................................... 51

10

Expenditure factors to be considered by the AER ...................................................................... 53

11

Accelerated Depreciation of Retired Assets ................................................................................ 55

12

Incremental revenue requirement ................................................................................................. 58
12.1 Introduction ........................................................................................................................... 58
12.2 Regulated asset base and depreciation ............................................................................... 58
12.3 Return on capital ................................................................................................................... 60
12.4 Tax allowance ....................................................................................................................... 61
12.5 Incremental operating expenditure ....................................................................................... 62
12.6 Incremental revenue allowance ............................................................................................ 63
12.7 Revised revenue determination ............................................................................................ 63

13

List of supporting documents ....................................................................................................... 66

14

Compliance Checklist ..................................................................................................................... 68

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Section 1 – Executive summary

1 Executive summary
1.1

Overview

The installation of Rapid Earth Fault Current Limiters (REFCL) technology is delivering bushfire
mitigation benefits to Victoria and our customers. The program is a world first in using REFCL
technology to mitigate bushfire risk, in accordance with the bushfire mitigation regulations (theRegulations)1.
The REFCL Program is being delivered in three Tranches to align with compliance dates of
1 May 2019, 1 May 2021 and 1 May 2023, as set out in the Regulations.
Our understanding of the technical and operational challenges of the REFCL technology
continues to improve as the Tranche 1 compliance deadline has been achieved, [ C-I-C
C-I-C] Updates on Tranche 1 and 2 are set out in section 5.
We continue to work closely with Energy Safe Victoria (ESV) to mitigate bushfire risk andappropriately address the technical issues encountered in Tranche 1.

1.2

Tranche 3 contingent project application

This document is AusNet Services’ contingent project application in relation to Tranche 3 of the
REFCL Program and provides a detailed explanation of the expenditure required to complete
this final tranche of the program. The application is being made to the Australian Energy
Regulator (AER) in accordance with the National Electricity Rules (Rules) and the AER’s 20162020 regulatory determination for AusNet Services.
AusNet Services submits that capital expenditure (capex) of $105.5 million (real $2015) andoperating expenditure (opex) of $3.3 million (real $2015) is the prudent and efficient cost ofundertaking this program of works over the remainder of the current regulatory control period
and into the 2021-25 period. This contingent project application explains the measures AusNet
Services has taken to ensure the project scope and costings comply with the prudency andefficiency requirements in the Rules.
The lessons learnt to date from Tranches 1 and 2 have been reflected in the scope of works
and costing for the Tranche 3 zone substations and their respective networks. As explained inour contingent project applications for Tranches 1 and 2, the scope of work varies according to
the particular characteristics at each zone substation and their associated network. Thisremains the case for the remaining 5 zone substations that comprise Tranche 3. The functional
scope of work for each zone substation is summarised in the attachments that accompany thiscontingent project application.
Tranche 3 costs are higher, per zone substation, than in Tranche 1 and 2 due to a number offactors including single REFCL zone substations compared to dual REFCL zone substations,
incorporation of learnings from Tranche 1 and 2 and the unique characteristics of the Tranche 3
zone substations and their associated networks. In particular, Kalkallo zone substation presents
challenges in terms of the network capacitance levels and the implications for the operation of
REFCLs.

1

Electricity Safety (Bushfire Mitigation) Regulations 2013 as amended on 1 May 2016 by the Electricity Safety (Bushfire
Mitigation) Amendment Regulations 2016

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Section 1 – Executive summary
AusNet Services is actively managing the costs of the REFCL program to ensure it is delivered
in a prudent and efficient manner. In relation to the scope of work for Tranche 3, our forecasts
include savings from technical scope exemption requests that we propose to submit. These
exemptions ensure that the necessary safety and bushfire mitigation benefits are achieved
while minimising required expenditure.
As explained in our contingent project applications for Tranches 1 and 2, AusNet Services is
continuing to work closely with Powercor Australia (Powercor) so that both companies canbenefit from an improved understanding of the technology and its operation on the network,
together with efficient practice. This cooperative approach delivers customer benefits byachieving the benefits of bushfire risk reduction as efficiently as possible.
AusNet Services is confident the expenditure forecasts in this contingent project application
comply with the requirements of the Rules. Accordingly, these expenditure forecasts arerecommended for acceptance by the AER for the purpose of amending the 2016-20 revenue
determination to enable AusNet Services to recover the cost of this contingent project. As
Tranche 3 will not be completed until 2023, the AER’s decision in relation to this contingent
project application will also be reflected in AusNet Services’ revenue proposal for the 2021-25
regulatory control period.

1.3

Summary of expenditure and revenue requirements

The amended revenue requirements reflect the expenditure forecasts set out in Table 1 below.
Table 1

Expenditure summary – Current Period ($m, 2015)
2016

2017

2018

2019

2020

Total

Capital Expenditure

-

-

0.2

9.5

32.1

41.9

Operating Expenditure

-

-

-

-

0.03

0.03

Source: AusNet Services

Table 2 below shows the expenditure forecasts for the 2021-25 regulatory control period.
Table 2

Expenditure summary – 2021-25 Period ($m, 2015)
2021

2022

2023

2024

2025

Total

Capital Expenditure

39.0

24.6

-

-

-

63.6

Operating Expenditure

0.4

0.4

0.8

0.8

0.8

3.3

Source: AusNet Services

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Section 1 – Executive summary
The table below shows the building block elements that comprise the incremental revenue
requirement for the contingent project over the 2016-20 regulatory control period.
Table 3

Contingent project revenue requirement, 2016-20 ($m, nominal)
2016

2017

2018

2019

2020

Total

Return on capital

-

0.0

0.0

0.0

0.7

0.8

Regulatory depreciation

-

-0.0

-0.0

-0.1

0.1

0.1

Operating expenditure

-

0.0

0.0

0.0

0.0

0.0

Revenue adjustments

-

-

-

-

-

-

Net tax allowance

-

-0.0

-0.0

-0.0

-0.0

-0.1

Annual revenue requirement(unsmoothed)

-

0.01

0.01

-0.1

0.8

0.8

Annual revenue requirement(smoothed)

-

-

-

-

0.8

0.8

Source: AusNet Services PTRM

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Section 2 – Background and regulatory framework

2 Background and regulatory framework
2.1

Bushfire risk

AusNet Services’ network operates in a geographical location which is exposed to extreme
bushfire risk. These conditions warrant significant investment to mitigate the bushfire risk.
Figure 1: AusNet Services’ extreme bushfire risk.
Following the 2009 bushfires, the Victorian Bushfire Royal Commission (VBRC) wasestablished and the recommendations made by the VBRC drove changes to the Regulatory
Regime (as described below) that ultimately have led to the roll-out of the REFCL technology.

2.2

Regulatory Regime

The AusNet Services REFCL program is necessary to comply with the bushfire safety
obligations imposed by the Victorian Government (Government) and is governed by a numberof regulatory instruments. The regulatory framework has evolved and has become increasingly
prescriptive over time and strict penalties for non-compliance are in place.
Each of the key regulatory instruments is described below.
2.2.1

Victorian Bushfire Royal Commission

The 2009 VBRC made several recommendations with respect to fires originating from electricity
networks. Recommendation 27 called for new technology that delivered greatly reduced
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Section 2 – Background and regulatory framework
bushfire risk, being applied to all overhead conductors (Single Wire Earth Return (SWER) and
22kV powerlines) in hazardous bushfire risk areas. The VBRC also suggested an expert
taskforce be established to advise on the best means of achieving the intent of thisrecommendation. The Powerline Bushfire Safety Taskforce (PBST) was established for thispurpose.
2.2.2

Powerline Bushfire Safety Taskforce

The PBST made its report to Government in September 2011 in which it recommended that therisk of powerlines starting bushfires could be reduced by:Installing REFCLs on selected 22kV powerlines to reduce the risk of polyphasepowerlines starting fires by automatically reducing the electric current in some types ofpowerline faults;

Installing remotely controlled Automatic Circuit Reclosers (ACRs) on SWER lines toreduce the risk of SWER lines starting fires by enabling the devices to be set remotely
so that they turn off those powerlines quickly when faults occur; and

Putting powerlines underground or insulating conductors in the areas of highest bushfire
risk.

The PBST also indicated the need for further research and development, noting REFCLs had
not previously been used for bushfire suppression. In December 2011, the Government
accepted the Taskforce’s recommendations and established the Powerline Bushfire Safety
Program to determine the optimal method for deploying REFCLs for bushfire prevention.
REFCL trials were subsequently conducted at Frankston South and Kilmore South zone
substations.
2.2.3

REFCL – Regulatory impact statement

A Regulatory Impact Statement (RIS) was prepared by the consulting firm, ACIL Allen, on behalfof the Victorian Department of Economic Development, Jobs, Transport and Resources,2 on the
Government’s proposal to mandate new fault suppression standards through the Electricity
Safety (Bushfire Mitigation) Regulations 2013. The RIS assessment incorporated a cost-benefit
analysis indicating that the estimated costs of deploying REFCLs would be more thanoutweighed by the reliability and bushfire risk reduction benefits.
The RIS recommended the installation of REFCLs at 45 zone substations across Victoria of
which 22 zone substations form part of AusNet Services’ network.
2.2.4

Electricity Safety (Bushfire Mitigation) Amendment Regulations 2016

Following the completion of the RIS process, the Government made the Electricity Safety(Bushfire Mitigation) Amendment Regulations 2016 which amend the Electrical Safety (Bushfire
Mitigation) Regulations 2013.
The amended Regulations require that each polyphase electric line originating from the 45
specified zone substations must have the following capability in the event of a phase to ground
fault:

2

ACIL Allen Consulting, Regulatory Impact Statement – Bushfire Mitigation Regulations Amendment, 17 November 2015.
Available at http://www.acilallen.com.au/cms_files/ACILAllen_BushfireMitigationRIS_2015.pdf

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Section 2 – Background and regulatory frameworka)reduce the voltage on the faulted conductor in relation to the station earth whenmeasured at the corresponding zone substation for high impedance faults to 250 volts
within 2 seconds; andb)

reduce the voltage on the faulted conductor in relation to the station earth whenmeasured at the corresponding zone substation for low impedance faults to —

c)

(i)

1,900 volts within 85 milliseconds; and(ii)

750 volts within 500 milliseconds; and(iii)

250 volts within 2 seconds; andduring diagnostic tests for high impedance faults, limit —(i)fault current to 0.5 amps or less; and(ii)

the thermal energy on the electric line to a maximum I t value of 0.1. 3

2

The practical effect of the amendment is to impose an obligation on AusNet Services to install
REFCLs (or equivalent technology) at the 22 zone substations specified in the regulations by
1 May 2023.
The Regulations use a scoring system to establish milestones for completing the required
works. Each zone substation is attributed a point score from 1 to 5, with the highest value
attributed to those zone substations where fire mitigation measures would provide the greatest
benefit.
AusNet Services is required to complete the works necessary in order to accumulate:

30 points by 1 May 2019;

55 points by 1 May 2021; and64 points by 1 May 2023.

2.2.5

Electricity Safety Amendment (Bushfire Mitigation Civil Penalties Scheme) Act 2017

The Victorian Government subsequently introduced legislation4 which amended the Electricity
Safety Act 1998 (Vic) (ESA) to provide for significant financial penalties if AusNet Services fails
to achieve the number of points prescribed by the Regulations by the applicable deadline.
The Act fixes a maximum penalty of $2,000,000 per point that AusNet Services falls short of theprescribed number of points. Each zone substation is assigned a number of points (up to 5)
depending on the degree of bushfire risk. Accordingly, penalties of up to $10 million per zone
substation can apply if AusNet Services fails to achieve the Required Capacity by theprescribed dates. Additionally, a daily penalty of $5,500 can be applied for each day AusNet
Services remains non-compliant.
AusNet Services could incur significant financial penalties if it fails to meet its obligations under
the ESA. Additionally, the ESA:

3

4



Requires AusNet Services to prepare annual compliance reporting and associatedindependent audit; andEmpowers ESV to request audits and information.

Other performance requirements are also specified in the definition of ‘required capacity’ in the Electricity Safety (Bushfire
Mitigation) Amendment Regulations 2016.
Electricity Safety Amendment (Bushfire Mitigation Civil Penalties Scheme) Act 2017 (Vic).

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Section 2 – Background and regulatory framework
2.2.6

Electricity Safety (Bushfire Mitigation Duties) Regulations 2017

The Electricity Safety (Bushfire Mitigation Duties) Regulations 2017 supports the amendments
made to the ESA by prescribing:The performance ability that every polyphase electric line originating from a prescribedzone substation is required to have;The zone substations at which the required capacity is to be installed; andThe points allocated to each substation for the purpose of meeting the milestones for
installation.

2.2.7

Energy Safe Victoria’s Administration Policy

ESV has a policy5, outlining how it intends to administer its audit and information gathering
powers to ensure that appropriate regulatory oversight and assurance is achieved. The policy
also outlines the penalty scheme associated with failing to comply with the additional bushfire
mitigation duties. The topics covered include:The exemption request process;

The modification of later dates and periods for compliance;

Information notices; and

Audit by ESV.

2.2.8

Exemptions and extensions

The ESA allows for exemptions or extensions to be granted in relation to certain obligations set
out in the Act and the Regulations. In September 2017, ESV clarified its expectations forapplications for an exemption. ESV has outlined a rigorous set of requirements for any
exemption request, including:6
The applicant must demonstrate the risk of granting the exemption to be equivalent to orless than the risk without the exemption;

In deciding whether to grant an exemption, ESV will be informed by the Risk Reduction
Model;



Safety outcome under an exemption must be maintained or enhanced compared to strict
compliance; andThe application must be specific (no blanket exemptions) and set out:oZone substation and feeders highest level;oDesign philosophy to be applied; andoSpecific technologies to be deployed.

Exemptions
During 2018, AusNet Services utilised the exemption process to obtain technical scope
exemptions in relation to the installation of isolating transformers to isolate certain High Voltage

56Electricity Safety Amendment (Bushfire Mitigation Civil Penalties Scheme) Act 2017 – Energy Safe Victoria’s
Administration Policy.
Process for the Administration of Exemption Requests, Powerpoint Presentation, ESV, September 2017.

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Section 2 – Background and regulatory framework(HV) customers from REFCL operations on certain feeders. The technical scope exemptions
were granted by the Governor in Council on the short sections of underground cable (polyphaseelectric line) between the isolating transformer and the HV customer’s connection point as thesepolyphase electric lines are not REFCL enabled.
Tranche 2 & 3 exemptions
AusNet Services anticipates submitting further exemption requests to ESV. These are intended
to ensure a cost effective delivery of the REFCL program whilst still achieving the safety
improvements necessary to mitigate bushfire risk.
The scope of Tranche 3 includes the installation of a number of isolating transformers to isolate
sections of the network from REFCL operations in order to reduce network capacitance.
Technical exemptions will be prepared to support the installation of these isolating transformers.
Deferral of commencement of Initial Period
On 15 April 2019, AusNet Services wrote to ESV to request that ESV specify a later date for thecommencement of the Initial Period, being the date by which AusNet Services must achieve theprescribed number of points for complying substations (the ‘extension of time’ request). ESV isstill considering AusNet Services’ request.
2.2.9

Victorian Electricity Distribution CodeIn 2018, the Essential Services Commission (ESC) reviewed the voltage standards specified inthe Victorian Electricity Distribution Code (EDC). The purpose of the review was to ensure that
the EDC was fit for purpose in light of the introduction of REFCL equipment. In particular, it wasrecognised that when REFCLs are commissioned, tested or used to respond to a fault, they arelikely to increase voltage levels at High Voltage (HV) customers’ connection points beyond theallowable range specified in the EDC.
The ESC’s final decision7 on its voltage review introduced a new table of voltage variation limits
in the EDC that are only applicable when REFCLs operate in accordance with an approved
mode, which includes the commissioning, testing and maintenance of a REFCL. The ESC
retained the previous phase-to- earth and phase-to-phase voltage variation limits when REFCLs
are not operating.
As a result of the new EDC provisions, HV customers are now responsible for upgrading their
HV electrical assets to accommodate the permitted voltage variations when REFCLs operate inapproved mode. It is noted that the Victorian Government has developed a High Voltage
Customer Assistance Program (HCAP) that includes assistance measures for affected highvoltage customers.
AusNet Services is also providing support to HV customers to ensure that their HV electricalassets can either withstand, or be isolated from, REFCL operations.. Whilst we recognise theneed to manage the costs of providing support to HV customers, it is prudent and efficient toensure that customers have a good understanding of the required works and the actions
required in order to be EDC compliant.

7

Essential Services Commission, Electricity Distribution Code – Review of voltage standards for bushfire mitigation, Final
Decision 14 August 2018.

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Section 3 – Contingent project regulatory requirements

3 Contingent project regulatory requirements
Under the Rules, a distributor may apply to the AER during a regulatory control period to amend
its distribution determination where a trigger event for a contingent project has occurred. It is
not until the pre-defined trigger event occurs, and the application is made, that the AER
undertakes a detailed examination of the efficient costs required to satisfy the capital
expenditure factors.
The Regulations were not settled prior to the AER finalising its 2016-20 Electricity Distribution
Price Review (EDPR) for the Victorian distributors. At that time, there was considerable
uncertainty regarding the likely costs of meeting the proposed regulations. Accordingly, theAER approved a contingent project to enable AusNet Services to obtain a cost allowance if theregulations were enacted and a project scope completed.
The AER defined three Tranches of projects, each with its own ‘trigger event’. AusNet Services
considers that the trigger event for Tranche 3 has now been satisfied.

3.1

Trigger event

The AER’s final decision set the trigger event for the third Tranche as follows:Bushfire Mitigation contingent project 38
In circumstances where a new or changed regulatory obligation or requirement (within themeaning given to that term by section 2D of the National Electricity Law) ("relevant
regulatory obligation or requirement") in respect of earth fault standards and/or standards for
asset construction and replacement in a prescribed area of the State is imposed on AusNet
Services during the 2016–20 regulatory control period, the trigger event in respect ofbushfire mitigation contingent project 3 occurs when all of the following occur:
1. AusNet Services has identified the proposed capital works forming a part of the
project, which must relate to earth fault standards and/or standards for asset
construction and replacement in a prescribed area of the State and which arerequired for complying with the relevant regulatory obligation or requirement. The
proposed capital works must be listed for commencement in the 2016–20 regulatory
control period in regulations or legislation, or in a project plan or bushfire mitigation
plan, accepted or provisionally accepted or determined by Energy Safe Victoria;
2. for each of the proposed capital works forming a part of the project AusNet Services
has completed a forecast of capital expenditure required for complying with therelevant regulatory obligation or requirement;
3. for each of the proposed capital works forming a part of the project that relate toearth fault standards, AusNet Services has completed a project scope which
identifies the scope of the work and proposed costings;
4. The AER has made a determination under clause 6.6A.2(e)(1) of the National
Electricity Rules in respect of bushfire mitigation contingent project 2."98

Similar provisions apply to the first and second Tranches.

9

AER, Final Decision, AusNet Services distribution determination 2016 to 2020, Attachment 6 – Capital expenditure May
2016, page 6-127.

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Section 3 – Contingent project regulatory requirements
3.1.1

Assessment of the Trigger Event

AusNet Services is lodging this contingent project application for Bushfire Mitigation Project 3 as
the trigger event has occurred in relation to the introduction of earth fault standards. In
particular:

As previously noted, the Victorian Government has introduced regulations in respect ofearth fault standards.



A revised Bushfire Mitigation Plan (BFM Plan) was provided to ESV on 20 April 2018.
The BFM Plan details the required Tranche 3 capital works and their location inaccordance with the AER’s approved trigger event. The BFM Plan, which has received
provisional acceptance from ESV10, updated the REFCL Program activities, compliancetesting and operating modes. A copy of the BFM Plan is provided to the AER alongside
this contingent project application.



AusNet Services has prepared forecast capital expenditure for Tranche 3, as describedin Section 8.

The capital works for Tranche 3 are fully scoped and costed, as described in theattachments, models and supporting documents.



The AER made a determination under clause 6.6A.2(e)(1) of the National Electricity
Rules in respect of bushfire mitigation contingent project 2 on 31 August 2018.11

3.2

Materiality threshold

The Rules12 require the contingent project application to demonstrate that proposed capital
expenditure exceeds either:$30 million; or

5 per cent of value of the annual revenue requirement for the relevant Distribution
Network Service Provider for the first year of the relevant regulatory control period,
whichever is the larger amount13

AusNet Services’ maximum allowed revenue in the first year of the current regulatory period is$586.0 million (real $2015), 5 per cent being $29.3 million. Therefore, the applicable thresholdin relation to this contingent project is $30 million, being the larger amount.
As shown in Section 8, the total forecast capital expenditure is $41.9 million (real $2015) in the
2016-2020 regulatory period for this contingent project, and therefore the threshold has beenmet.
As such AusNet Services is seeking approval of the incremental capital and operating
expenditure arising from Tranche 3 of the REFCL Program, which we propose to recoverthrough our distribution network tariffs from 1 January 2020.

10
11

12
13

Letter from ESV to Tom Hallam, dated 28 November 2018.
AER, Final Decision, AusNet Services Contingent Project Installation of Rapid Earth Fault Current Limiters (REFCLs) –Tranche two, August 2018.
Clause 6.6A.2(b)(iv).
Clause 6.6A.1(b)(2)(iii).

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Section 4 – What is REFCL technology?

4 What is REFCL technology?
A REFCL is a type of electricity network protection device, which is designed to minimise thefault current (energy) dissipated from phase to earth (wire to ground) faults on the 22kV networkin order to reduce the risk of fire ignition associated with network incidents, as shown below.
Figure 2: How does REFCL technology work?

Source: AusNet Services

There are various types of technology that fall under the REFCL umbrella, however the only
type of REFCL currently considered suitable by the Victorian Electric Supply Industry (VESI) for
bushfire safety is known as the Ground Fault Neutraliser (GFN), a proprietary product by
Swedish Neutral. Presently, the GFN is the only device that can meet the performance criteriaof the Regulations.14
REFCL technology operating at the required performance standard will minimise the risk of fire
ignition associated with phase to ground faults on days of heightened fire danger, such as thoseexperienced on Ash Wednesday and Black Saturday. Based upon a sample period of network
fault data, analysis undertaken by the Government and CSIRO predict network fire related
incidents associated with the nominated zone substations may be reduced by between 50-55%.
A REFCL operates when a single phase-to-earth fault occurs. Its operation causes the phaseto ground voltage of the faulted phase to be reduced to near earth potential (zero volts), thereby
working to eliminate the flow of fault current. To achieve this outcome, the REFCL is tuned tothe capacitance of the electrical network and a current injected into the transformer neutral thatcancels the residual active fault current. This compensation results in phase to ground voltage
on the faulted phase reducing to near 0 volts and the fault current being reduced to a very low
value. The healthy phases could rise from 12.7 kilo Volts (kV) to 24.2kV, being 22kV plus 10
per cent.

14

As noted elsewhere in this application, AusNet Services is working with alternative providers to develop alternative
solutions.

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Section 4 – What is REFCL technology?
While the REFCL is compensating for a fault, the healthy phases remain energised andcustomers remain on supply. However, there remains a risk the energised phases may be in an
unsafe condition depending on the nature of the network fault. Accordingly, a maximum
compensating period will apply, which may be varied subject to a detailed risk assessment.
The REFCL technology is made up of 4 main components:


Arc Suppression Coil (ASC) , also known as a large inductor, which compensates for the
leakage current during an earth fault;

Residual Current Compensator (RCC), also referred to as the inverter, which is locatedin the zone substation control building or switchroom. It is used to reduce fault current
by compensating for the active current during an earth fault;Control Cubicles (CC), which controls the equipment; andGrid Balancing Cabinet (GRBC), which fine tunes capacitive imbalance from the zone
substation to achieve better detection sensitivity.

Figure 3: Four components to REFCL technology

Source: AusNet Services

As explained in further detail below, the scope of the required works is much broader than thefour components described above. This is because the installation of REFCLs requires aparadigm shift in how our network is designed, operated and maintained. As such, allcomponents of the affected 22kV distribution network need to be reviewed to ensure that the
REFCL-enabled network continues to operate safely and reliably.

4.1

Alternative technologies

The Regulations prescribe a performance standard that must be met, rather than specifying aparticular technological solution. However, in this instance, the mandated performancestandard was based on REFCL trials conducted by the Powerline Bushfire Safety Program(PBSP), as explained below:

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Section 4 – What is REFCL technology?
“PBSP conducted a series of world-first trials of Rapid Earth Fault Current Limiter (REFCL)
technology for use on electricity networks to reduce fire risks on bare-wire overhead
powerlines.
[…]
Through this research, the Victorian Government and electricity distribution businesses
identified and confirmed new fault detection and suppression standards required tosignificantly lower the risks that 22kV powerlines will start bushfires in worst bushfire risk
conditions. These standards are now in force from the 1 May 2016 commencement of theElectricity Safety (Bushfire Mitigation) Amendment Regulations.” 15

The Victorian Government also highlighted the superior performance of the REFCL technology
in its factsheet ‘REFCL – Introducing best knowledge and technology’:“In a series of world-first trials, the Victorian Government together with the electricity
distribution businesses and research experts demonstrated that REFCLs can suppress arcinduced bushfire ignitions from wire-to-earth faults on 22kV powerlines.
The technology was successfully tested under worst-case bushfire conditions, confirming
critical fault detection and suppression standards, which are necessary to stop downed
powerlines from starting bushfires, and further determining the optimal safety settings ofthese devices to reduce the risk of powerlines-started fires.
The test program demonstrated that REFCLs provide over 10-times better protection thanthe current best network protection technology.
These standards were mandated for 22 kV powerlines proceeding from 45 zone substations
by the Government’s 1 May 2016 amendments to the Electricity Safety (Bushfire Mitigation)
Regulations.”16

At the time the Regulations were made, the REFCL technology was the only technology
available to meet the performance requirements. This remains the case. In Tranche 1, theAER approved an allowance to assist AusNet Services to explore alternative technologies andmanage its sole supplier risk. However, the AER did not provide any such allowance in relation
to Tranche 2 on the basis that17:


The project is now substantially underway and any benefits of identifying an alternative
supply source are likely to be minimal; andIf an alternative source of supply were identified this cost could be funded from thesavings achieved on the allowances granted in this decision.

Although the AER did not provide any allowance in relation to Tranche 2, AusNet Services has
continued to incur costs as technical issues associated with GFN performance remainunresolved. [C-I-C
C-I-C
C-I-C
C-I-C

15

`

Department of Environment, Land, Water and Planning, Investing in new technology, research and development.

16`

Department of Environment, Land, Water and Planning, REFCL – Introducing best knowledge and technology.

17

AER, Final Decision, AusNet Services Contingent Project Installation of Rapid Earth Fault Current Limiters (REFCLs) –Tranche two, August 2018, page 19.

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Section 4 – What is REFCL technology?

C-I-C
C-I-C
C-I-C
C-I-C
]

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Section 5 – REFCL Program Progress Update

5 REFCL Program Progress Update
5.1

Overview

The figure below shows the current status for each Tranche of the REFCL program as at end
May 2019.
Figure 4: REFCL Program Overview

Source: AusNet Services

Tranche 1 of the REFCL Program has been delivered in accordance with the mandatorycompliance deadline of 1 May 2019. However, a number of technical issues, as discussed in
the next section, have resulted in ESV providing conditional compliance on six (6) of the eight(8) Tranche 1 zone substations and an extension of time request has been submitted to ESV for
two (2) of the eight (8) Tranche 1 zone substations.
It is noted that Wonthaggi (WGI) zone substation was originally expected to be completed aspart of the Tranche 1 REFCL Program. As a result of delays encountered in the replacement ofan underground feeder cable due to cultural heritage management plan requirements, this zone
substation will now be delivered in the Tranche 2 timeframe. This timing change does notpreclude AusNet Services from achieving the prescribed points for Tranche 1 because theremaining eight (8) zone substations meet the required 30 compliance points. It is noted that
the Wonthaggi zone substation continues to be treated as a Tranche 1 project for the purposeof the AER’s contingent project determination.
A further change in the program delivery timing is that the delivery of the Mansfield (MSD) zone
substation, which falls within Tranche 3, has been brought forward so that it will be completed
by the Tranche 2 compliance deadline of 1 May 2021. The MSD delivery has been brought
forward as a risk mitigation measure to provide additional assurance that 55 points will beachieved by the Tranche 2 compliance date. Similar to WGI, although the delivery timing of thisproject now falls within the Tranche 2 timeframe, this does not affect the regulatory
arrangements for remunerating this zone substation. In particular, for the purposes of the cost
recovery arrangements, MSD will continue to be treated as a Tranche 3 zone substation.
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Section 5 – REFCL Program Progress Update

5.2

Financial performance against budget

Our contingent project applications for Tranches 1 and 2 emphasised the unique and complex
nature of the REFCL program.
One consequence of this world first project is that
AusNet Services is exposed to asymmetric budgeting risks. This risk is asymmetric because
unexpected technical and delivery issues are likely to arise, whilst unexpected cost savings aremuch less likely to occur.
5.2.1

Tranche 1

For Tranche 1, the majority of zone substation projects are forecasting overspends compared tobudget primarily as a result of rework, remediation activities and further testing requirements as
described below:


At Kinglake (KLK), a drum of faulty cable required AusNet Services to remove and reinstall cable which resulted in a 3 month delay to the installation of a new supply
transformer. The faulty cable was identified during the partial discharge (PD) testing
which is carried out on all newly installed cable. The faulty cable was as a result of amanufacturing defect.



At four (4) of the zone substations, the performance of the Current Transformers (CTs)was identified during primary earth fault and compliance testing as not being sufficiently
sensitive to meet the required compliance performance criteria. CT remediation works
were carried out at these zone substations in early 2019.



As a result of GFN software defects, a number of versions of the software have been
installed and tested. As an example, testing of the first two (2) GFN zone substations on
the AusNet Services network at Woori Yallock (WYK) in November 2017 identified anumber of software defects with operating the REFCLs in the required ‘split bus’ mode.
This mode is used to meet the performance criteria in the Regulations. Testing of the
updated software in late May 2018 identified further software defects which prevented
the planned ESV-observed compliance testing occurring in June 2018 at WYK.
Following the installation of further updated software, ESV compliance testing conductedat the Rubicon A (RUBA) zone substation in August 2018 identified new software
issues, a number of which were resolved by new code being written by the Swedish
Neutral (SN) resources at location (SN resources were onsite during August 2018 tosupport testing activities). Due to the issues identified, together with CT performanceissues, ESV-observed compliance testing was again cancelled and primary earth fault
testing undertaken to assist with technical issue identification and resolution.

The effort involved in commissioning and testing of the REFCLs is significantly greaterthan assumed and budgeted for. There are a number of steps in the commissioning andtesting process including conducting:oInsulation (also referred to as stress) testing – this is where the voltage on thezone substation network is increased for a period of time. The purpose of thetesting is to identify any assets which are unable to withstand REFCL operations.
This testing may be completed in a single day or, if there are asset failuresencountered, may take a number of days to successfully complete.

oPrimary earth fault (PEF) testing – this is where a fault is introduced onto the
REFCL-protected network to test whether the REFCL can identify the fault andcompensate for the fault in accordance with the performance criteria in theRegulations. The allowance of one (1) day PEF testing per feeder is a minimum
requirement. During Tranche 1 commissioning, PEF testing may need to berepeated a number of times on the same feeder over multiple days due to

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Section 5 – REFCL Program Progress Update
network faults, the requirement to obtain multiple setting data (particular at dual
GFN zone substations) and adverse weather conditions.
o

ESV-observed compliance testing – this is where representatives from ESV
observe the testing of each REFCL-enabled feeder against the performance
criteria in the Regulations. This is very similar to primary earth fault testing withthe exception that the purpose of the testing is to execute a pre-agreed test plan
to demonstrate compliance with the performance criteria and is observed by ESV
representatives. A minimum allowance of one (1) day per feeder is assumed
from a planning perspective, together with a number of contingency days in theevent of delays to testing. Delays can occur due to network faults and adverse
weather conditions, in addition to other factors.



Underground cable failures as a result of REFCL testing have been encountered which,in addition to impacting the reliability of the network for customers, has resulted inadditional costs to repair and, in some cases, replace the cable. No allowance wasincluded in the Tranche 1 contingent project application for the testing and replacementof underground cable.



A each of the eight (8) Tranche 1 zone substations, different challenges wereencountered which have resulted in increased costs and, in order to meet the 1 May
2019 compliance deadline, an extremely compressed delivery schedule wasestablished. The completion of zone substation projects has been much later thanoriginally budgeted.

The total projected capex for Tranche 1 now exceeds the AER approved capex forecast. It isnoted that the current Tranche 1 forecasts do not include costs which may be incurred toresolve the current technical issues.
5.2.2

Tranche 2

For Tranche 2, whilst the zone substations works are currently in the design phase, the latest
forecasts indicate that the capex will exceed the AER’s allowance due a number of factors
including:Higher than budgeted design costs – designing for REFCLs is complex and the numberof zone substations in Tranche 2 has resulted in four (4) design teams from different
organisations being responsible for producing the designs. Design learnings fromTranche 1 are being incorporated into Tranche 2 designs however, as previously
mentioned, each zone substation presents its own unique challenges. A number of theTranche 2 zone substations are located in residential areas with no space for expansion
to accommodate the REFCL equipment. In addition, seven (7) of the Tranche 2 zone
substations require two (2) GFNs to be installed. This is compared to three (3) zone
substations in Tranche 1;

Improved network capacitance forecasts have identified higher network capacitancethan was assumed in the Tranche 2 contingent project application, particularly in thecentral region which includes the following zone substations: Belgrave (BGE), Ferntree
Gully (FGY), Ringwood North (RWN), Eltham (ELM) and Lilydale (LDL). Options toaddress the increased capacitance to ensure the performance criteria in the Regulations
is met include feeder switching, installation of a 3rd GFN at FGY and/or the isolation ofunderground residential developments from REFCL operations;

Significant volumes of underground cable need to be PD tested and/or replaced. Due tothe location of the majority of the Tranche 2 zone substations, cable testing and/or
replacement requires council permits, additional reinstatement requirements enforecedby councils and traffic management which increases the cable repair cost and can delay
the completion of the works. In addition, a number of large residential developments built
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Section 5 – REFCL Program Progress Updatein the 1980s have been identified as having underground cable which is unlikely to beable to withstand REFCL operations. These underground cables will be isolated, subject
to obtaining the required technical scope exemption approvals;

PD testing of feeder exit cables has identified a larger number of replacements than wasbudgeted. To date, of the PD testing undertaken in Tranche 2, 44% of the feeder exit
cables have failed PD testing resulting in the replacement of feeder exit cables being
required. Furthermore, as a result of capacitive balancing requiring the relocation offeeders to alternate buses and the replacement of outdoor switchgear with indoor
switchboards, 36% of additional feeder exit cables are to be replaced in Tranche 2. In
total, 80% of the feeder exit cables are currently requiring replacement;An additional 22kV capacitor (cap) bank is required at Bairnsdale (BDL) to address bothvoltage regulation and harmonics. As BDL is a two (2) GFN ZSS, the GFNs will operatewith the bus tie open on Total Fire Ban (TFB) days. This means that each bus needs tobe able to operate independently of the other bus in terms of voltage regulation andharmonics; and

Removal of fuses on network segments with excessive capacitive current as single
phase fuse operation will cause excessive imbalance causing the GFN to trip the feeder.
Therefore, to solve the excessive imbalance, replacement of the existing fuses on the
network with solid links is planned. As a result of protection studies performed, it has
been concluded that the installation of fuse savers are required for network protection.
These costs were not considered in the previous contingent project applications.

It is important to note that the contingent project provisions place strong financial incentives on
AusNet Services to minimise the costs of delivering the REFCL program. The projected cost
overruns for Tranche 1 and 2 therefore highlight the challenges of forecasting the required
expenditure given the newness of the technology and the demanding performancerequirements in the Regulations.

5.3

Technical Issues[C-I-C
C-I-C[C-I-C]

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Section 5 – REFCL Program Progress Update
Table 4

Principal technical Issues

Issue[C-I-C]

Description and current status[C-I-C][C-I-C][C-I-C][C-I-C][C-I-C][C-I-C][C-I-C][C-I-C][C-I-C][C-I-C][C-I-C][C-I-C][C-I-C]
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Section 5 – REFCL Program Progress Update

5.4

HV customers solutions

As explained in section 2.2, the Victorian Electricity Distribution Code has been amended sothat Tranche 2 and 3 HV customers are now responsible for ensuring their HV electrical assets
are either able to withstand, or be isolated from, REFCL operations.
For Tranche 2 HV Customers, the AER accepted that AusNet Services would incur expenditure
in relation to:installation of ACRs at all HV customer sites to mitigate the risk of a cross-country fault;



protection investigation;

consultant reports to assess the current condition of the HV assets to withstand REFCL
operations and, where applicable, recommend required works to either harden towithstand, or isolate the HV assets, from REFLC operations;backup generation to isolate customers during commissioning;

project oversight;

updating schematics for hardening.

For Tranche 3, equivalent expenditure in relation to HV Customers is proposed.

5.5

Key Learnings

Learnings from Tranche 1 are being factored into the delivery of Tranche 2 and the scoping ofTranche 3.
Key learnings include:

The importance of integrated schedules – two dedicated schedulers will support the
REFCL Program post 1 May 2019 and Primavera P6 is being implemented, replacing
reliance on MS Project which has limitations in relation to resource management andintegrated schedule management.

Confirmation of scope of works – the implementation of REFCLs is complex and eachzone substation and its respective network is unique in terms of how many REFCLs areto be implemented and the associated works. The timely confirmation of the condition ofexisting assets and whether they can withstand REFCL operations is essential to avoid
the late identification of the replacement of long lead assets including supply
transformers, replacement of feeder exit cables and critical underground cables. A
Tranche 2 Program Manager commenced in early October 2018 with a key objective to
confirm the Tranche 2 scope of works. A Tranche 3 Program Manager commenced inearly March 2019 with the key objective of developing the scope, budget and schedulefor Tranche 3.

Timely procurement of assets, including spares – The lead time for REFCL equipment
including GFNs from Swedish Neutral, supply transformers and isolating transformers
can be up to 12 months. If orders are not placed with suppliers on a timely basis, the riskof being unable to complete construction activities increases. In addition, issues havebeen encountered with defective equipment which has required the use of spareequipment. An increased number of spares of key/long lead equipment will be available
for the remaining tranches to avoid unnecessary delays in commissioning.



Access to the network – As part of a REFCL Prioritisation Review conducted in earlyFebruary 2019, amended network access protocols were identified and implemented toprovide the commissioning and testing teams with greater flexibility to undertake therequired commissioning and testing activities. For example, rather than network access
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Section 5 – REFCL Program Progress Update
having to be requested on a feeder by feeder basis, network access is requested at azone substation level so that, in the event testing is unable to be conducted on aparticular feeder due to a network fault or other issue, the testing effort can be redirected
to an alternate feeder on the network. This also allows for multiple feeders to be tested
in one day in the event the testing on the initial feeder is completed without issues being
encountered. These amended network access protocols enabled the recent ESVobserved compliance testing to be undertaken quicker than scheduled.
Integrated works governance – following the REFCL Prioritisation Review, an integrated
works governance working group was established to review, prioritise where required
and manage outages required to undertake bushfire mitigation, REFCL, othermaintenance and customer-initiated works. This integrated and co-ordinated approach to
managing network access resulted in fewer works being cancelled due to job clashes
and, as this process continues, should result in fewer customer outages and outage
cancellations.

Community engagement – whilst community engagement activities were undertaken
during Tranche 1, they were often reactive rather than proactive and did not promotebenefits of the REFCL Program. A more holistic, proactive community engagement
approach is under development for Tranche 2.

A formal post implementation review of Tranche 1 commenced in May 2019 to identify areas forfurther improvement in the remaining tranches.

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Section 6 – Tranche 3 Overview

6 Tranche 3 Overview
Each of the three Tranches have different characteristics and challenges, reflecting the different
nature of the substations and their respective supply networks progressed in each Tranche.
Tranche 1 – the majority of zone substations are situated in rural locations;

Tranche 2 – apart from 3 zone substations, the zone substations are situated in periurban location – locations between urban and rural areas; andTranche 3 – the zone substations are predominately situated in rural locations, apartfrom Kalkallo (KLO) which is located in a peri-urban area in an area of significant
growth.

Figure 5 below shows the substations that are being undertaken in each Tranche.
Figure 5

REFCL Program Overview

Source: AusNet Services

The different locations and characteristics of the zone substations, and their respective supply
networks, give rise to several key aspects of the Tranche 3 program including:

Kalkallo (KLO) zone substation supplies the Jemena network in addition to the AusNet
network. KLO is located in an area of high residential growth and a number of thefeeders are predominantly underground cable. The network capacitance forecasts for
KLO indicate a large growth in capacitance over the next ten year period. Increasing thenumber of GFNs to cater for this capacitance growth is not a sustainable solution fromeither a technical or economic perspective. AusNet Services and Jemena have jointly
engaged an independent consultant to assess the potential REFCL solutions and torecommend the preferred solution covering compliance with the Regulations, technicaland economic perspectives. For the purposes of this contingent project application, themost likely solution has been included which is the installation of 2 GFNs, 5 isolating
substations and the development of a new zone substation;
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Section 6 – Tranche 3 Overview
Aside from KLO, the other zone substations in Tranche 3 are single GFN zone
substations with a higher proportion of overhead lines compared to underground cable;



The number of HV customers is significantly lower than that of Tranche 2, with no HV
Customers on the Mansfield (MSD) network, single HV Customers on the Sale (SLE)and Lang Lang (LLG) networks and two (2) HV Customers on the Benalla (BN) network;andComplexity in the delivery of Tranche 3 program includes the requirement to avoid
outages during the snow season on the MSD network and to minimise outages during
school holidays/peak holiday seasons at a number of zone substations.

The proposed delivery schedule for each Tranche 3 zone substation is set out in Figure 6
below.
Figure 6: REFCL Tranche 3 timeline
2019# of GFN's

Mansfield (MSD)

1Lang Lang (LLG)

1

Sale (SLE)1

Benalla (BN)1

Kalkallo (KLO)

2

2021

2022

2023

Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3

T3 compliance date

Zone Substation

2020* Compliance testing is subject to HV customers meeting the HV Customer REFCL readiness date of 30 June 2022
DesignConstruction

Compliance testing

Key characteristics of each Tranche 3 Zone Substation are set out in Table 5 below.
Table 5

Summary of zone substations

Zone
substation

22kV
Network
Size (km)Customers

22kV
Insulated
Network
Size (km)22kV
Feeders

22kVTransfer
Feeders (tozone
substations
that will not
be fitted witha REFCL in
Tranche 3.)

MSD

619.4

6,448

8.5

3

0

12

321.1

0

LLG

498

6,585

11.7

4

1

24

204

1

SLE

677

12,755

29

4

1

33

240

1

BN

1,383.1

12,134

12

5

0

33

915.4

2

KLO

301.9

9,406

50.9

4

1

7

118.9

3

Total

3,479.4

47,328

112.1

20

3

109

1,799.4

7

Source: AusNet Services

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Automatic
switchable
sections

Singlephase kmrequiringbalancing
capacitors
or linebalancing

HVconnection
pointsAusNet Services

Section 6 – Tranche 3 Overview

6.1

Necessary works

As explained in our contingent project applications for Tranches 1 and 2, significant work is
required at each zone substation to accommodate the installation of the REFCL equipment. For
example, the speed and sensitivity at which the REFCLs operate means traditional protection
schemes distributed along a feeder will not operate as they normally would, to detect andisolate a faulted section of the network. In addition, the operation of the network with REFCLs
in service imposes higher electrical stresses on the network.
As a consequence, capital works extend beyond the immediate confines of the zone substation
to ensure that the network continues to operate safely and reliably and AusNet Services
maintains compliance with its obligations. The REFCL project therefore involves five capital
expenditure workstreams, described below:

Zone substation works
Includes: REFCL installation (being the GFN) and associated equipment within the zone
substation. It also includes the replacement of assets that fail during network hardening
tests of the relevant high voltage network.
Reason: In addition to installing the REFCL, additional works are required because the
REFCL technology is based on a different earthing philosophy. It is essential that thezone substation operates safety and reliability in the new environment.



Network Balancing
Includes: Initial desktop and field modelling work following by: low voltage (LV) capacitor
bank installations, third phase installations and re-phasing long single phase lines.
Reason: Long single phase (two-wire) spurs teed off three-phase lines can create
significant capacitive imbalance. Fire risk reduction relies on minimal capacitive
imbalance on switchable sections of the network.

Line and Cable Hardening
Includes: Surge Arrestor replacement and underground cable testing and/or
replacements
Reason: When an earth fault occurs, the REFCL response creates increased voltage
stresses (compared to without REFCLs) on line equipment connected to un-faulted
phases, which can lead to a second fault. In the absence of line hardening, the REFCL
installation would increase fire risk and decrease network reliability. Increased voltage
levels can also lead to cable failures.

Compatible Equipment
Includes: Automatic Circuit Reclosers (ACR), Voltage Regulators, sectionalisers andCapacitor Bank replacements.
Reason: Some widely utilised line equipment cannot be used with REFCLs due to the
reduced fault currents. This is separate to line hardening, which is solely concerned withthe ability of line equipment to withstand over-voltage events.

Assisting HV customers to achieve Electricity Distribution Code (EDC) compliance
Includes: The costs of working with HV customers to ensure that the appropriate works
are undertaken to achieve EDC compliance in readiness for the REFCL program.
Reason: The timely completion of HV customers works is essential to the successful
implementation of the REFCL program. It is therefore prudent and efficient for AusNet
Services to provide support to HV customers to ensure that the lowest cost, effective
options are adopted to achieve EDC compliance in a timely manner.
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Section 6 – Tranche 3 Overview
In addition to these capital works, the project will also entail expenditure for an incremental
increase in AusNet Services’ operating expenditure. This contingent project application andattachments provide a detailed explanation of the proposed expenditure. In accordance withthe contingent project provisions in the Rules, only the incremental costs associated with thetrigger event are included in this contingent project application.

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Section 7 – Project management process

7 Project management process
7.1

Program Governance Framework

AusNet Services’ REFCL Program Governance Framework will continue to apply throughout
Tranche 3 of the REFCL Program. The governance framework aligns with AusNet Services’
values and commitment to safety with:

Clear accountabilities, reporting and robust risk and issue management;

Sustainable, long term, reliable, economical and workable whole of life designs;

Delivery as per agreed timelines without compromising reliability and other service
standards;

Integration with the rest of AusNet Services’ work program;Compliance with required obligations;Strong relationships with all stakeholders in order to successfully manage change;

Development of internal capability in order to facilitate the transition to business as usual(BAU); andUse of BAU processes and resources where possible.

Risk management is an important aspect of the governance framework, as the REFCL
technology has never been operationalised at the performance standard required by theRegulations. The potential exposure is therefore significant and must be proactively managed.
The Program Management team includes a dedicated risk management resource who works
proactively with the work stream leaders, project managers and the program management team
to identify and assess risks and to develop and monitor risk mitigation measures and controls
and to monitor their implementation and effectiveness.
The following figure depicts the REFCL Program Governance Framework.

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Section 7 – Project management process
Figure 7: REFCL Program Governance Framework

Source: AusNet Services

A REFCL Steering Committee was established in early 2016. Its members include key
Executive General Managers, General Managers and key program management teamrepresentatives.
The Steering Committee is accountable for the successful delivery of a functioning REFCL
system across the affected 22 zone substations in AusNet Services 22kV electricity distribution
network, in accordance with the regulated schedule and performance criteria.
The Steering Committee:
Provides strategic and operational direction and support;Acts as an escalation point for issue resolution; andActively monitors the Program’s critical risks and their mitigations, issues, budget andschedule.

The Steering Committee has met regularly since March 2016.
As noted in our contingent project applications for Tranches 1 and 2, the governance frameworkprovides strong evidence that the REFCL program is well managed with program and delivery
project risks identified and managed effectively. Further information on our REFCL governancearrangements can be provided to the AER on request.

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Section 7 – Project management process

7.2

Efficient Delivery

AusNet Services’ objective is to ensure that the forecast expenditure for this contingent projectis prudent and efficient18. For the purposes of this contingent project, we consider expenditureis:

Prudent if it is necessary to ensure AusNet Services’ compliance with the mandated
earth fault standards and mitigates bushfire risk to the maximum extent possible withoutcompromising safety.

Efficient if it delivers the scope of works at the least possible cost to customers, including
the expected costs of unserved energy during construction and following theestablishment of the REFCL.

To ensure the expenditure forecast for AusNet Services’ project scope is expenditure that would
be incurred by a prudent and efficient Distribution Network Service Provider (DNSP), a specificcost-benefit analysis is conducted for each workstream which:Describes the investment need;

Identifies the alternative credible engineering options at that location;

Determines the costs and risks associated with each option; andSelects the least cost, prudent option having regard to safety and performance risks.

The cost-benefit assessment described above is consistent with the Regulatory Investment Testfor distribution (RIT-D)19. In accordance with the RIT-D principles specified in the Rules20,
AusNet Services’ cost-benefit analysis:Is proportionate to the scale and likely impact of each option; andIs applied in a predictable, transparent and consistent manner.

The cost-benefit analysis determines AusNet Services’ strategy for each workstream, ensuringthat the preferred option will deliver the most prudent and efficient outcome. The possibility of
non-network options or operating and capital expenditure substitution are also considered.
AusNet Services is confident our approach ensures the scope of work and the resulting
expenditure forecasts are prudent and efficient, in accordance with the capital and operating
expenditure criteria in the Rules, which are addressed in Chapters 8 and 9 respectively21.

7.3

Project cost estimates and unit rates

As explained in our contingent project applications for Tranches 1 and 2, project cost estimates
are prepared as part of AusNet Services’ standard approach to developing, managing andreporting projects and programs of works in accordance with defined project execution
procedures and practices. AusNet Services’ estimates are founded on the following five key
principles:

18

19

20
21

Clause 6.6A.2(f)(2) refers to the capital expenditure criteria, which refer to the efficient and prudent costs of meeting thecapital expenditure objectives.
The REFCL project is also subject to a separate RIT-D process, although it relies on the costs benefit analysis presented
in this contingent project application and supporting documents.
Clause 5.17.1(c).
Clause 6.6A.2(f).

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Section 7 – Project management process
1. All projects are to be project managed in accordance with AusNet Services’ project
execution procedures and practices.
2. For business case investment approval and implementation, P9022 estimates provide
confidence in processes of project priority, affordability and strategic fit. However, thecosts presented in this contingent project application are P(50) estimates23, i.e.
expected cost, which excludes project risk and uncertainty covered by management
reserve provision in a business case.
3. Estimates are subject to reviews and a sign-off process based on consistent clear
lines of responsibility and accountability that will ensure costing standards and controls
are applied.
4. Regular system reviews are conducted to encourage and facilitate continuous
improvement.
5. Project learnings are shared to increase corporate knowledge.
The unit costs assumed for GFNs reflect a quotation provided by the manufacturer, Swedish
Neutral.
Unit rates for other works are primarily based on the rates incurred in recently completed workor where possible, updated based on experience from Tranches 1 and 2. These unit rates
therefore reflect the efficient costs of delivering similar projects in AusNet Services’ network
area.
Work is delivered utilising an efficient combination of competitively tendered and internal
resources. Pre-qualified panels of design and installation service providers have been
established by competitive tender and ensure that providers have the skills and resources toundertake the required work in a safe and competent manner and can comply with works
management processes.
Further information on AusNet Services’ cost estimating process are provided in the supporting
document, Cost Estimating, Program Delivery & Unit Rates, which accompanies this contingent
project application. AusNet Services’ actual unit rates are confidential, and are provided to the
AER on that basis.

7.4

Efficient delivery

As explained in our contingent project applications for Tranches 1 and 2, AusNet Services has
implemented a number of initiatives to ensure that the REFCL Program is delivered efficiently,
as discussed below.
Standard Designs
AusNet Services utilises a number of standard designs and modular constructions to aid thedelivery of zone substation projects. For example, a standard modular 22 kV switchboard has
been utilised in zone substation construction and rebuild projects. This switchboard has anumber of advantages over the installation of stand-alone switchgear, including the ability tofabricate and fit-out the building off-site in a factory and to readily relocate the switchboard
should it no longer be required in its current location.

22
23

A detailed cost estimate that has a 90% confidence factor of not being exceeded by cost at project completion.
The costs presented in this application also exclude the written down value of assets that need to be replaced prior to end oflife. While the written down value of these assets are project costs, and included in the business case,33 / 69
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Section 7 – Project management process
To deliver the REFCL Program, the standard switchboard has been modified to ensure all theequipment is rated for REFCL operation and to include measuring transformers capable ofdetecting low fault currents. The use of a pre-assembled switchboard speeds delivery of the
REFCL Program because the switchboard utilises a standard design and is assembled off-siteby a supplier and delivered complete to site (already fitted with all the components andaccessories such as air-conditioning). This reduces the design and on-site construction effort
leading to more efficient and faster project delivery.
Shared experience
The operation of REFCLs to mitigate bushfire risk has not been undertaken other than in
Victoria and so, at the start of the Tranche 1 project, no knowledge relating to the installation oroperation of the REFCL existed. AusNet Services and Powercor are both required to achieve
the required capacity mandated in the Regulations. The businesses have therefore been
sharing information on the installation and operation of their respective units to increase
expertise and reduce the probability of unplanned customer interruptions.
In addition, AusNet Services and Powercor have shared the results of tests such as surgearrestor testing to reduce the time and cost of testing a statistically significant sample. A key
learning from Tranche 1 has been the need for proactive cable testing and, where necessary,cable replacement. Cable failure data, and cable testing results to date, has been shared
between AusNet Services and Powercor.
Leveraging existing contracts and relationships
Delivery of the REFCL program in the required timeframe would not be possible without using
existing contracts and relationships. The procurement of equipment relies on establishedcontracts with suppliers and enables the use of standard equipment such as the 22 kV
switchboards. Additionally, the pre-qualified service providers (described below) will be used todeliver on-site work.
Resourcing
Our approach is to employ a combination of in-house and outsourced resources to optimise theoverall program costs while meeting the delivery timetable. Additional external resources havebeen, and will continue to be engaged to meet the peak workload. These additional resources
are not retained when the volume of work reduces, following the completion of the REFCL
program, ensuring that internal resources are always fully occupied.
The establishment of pre-qualified panels of service providers using a competitive processensures efficient costs and that appropriate quality services are provided. In addition, the cost
and time taken to engage resources is reduced. The use of different labour sources also allows
benchmarking comparisons to reduce the risk of cost blowouts, which are not uncommon forlarge capital projects such the REFCL program, especially given the nature of the technology.

7.5

Change management

Our approach to change management and training continues to evolve as we better understandthe impacts of introducing REFCLs on existing business processes, systems and teams. The
scale of change is significant and complex when considering the following key factors:We are installing new assets on our network that have never been used for bushfire
mitigation before anywhere in the world.

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Section 7 – Project management process

The transition from low resistive to enhanced resonant earthing represents a paradigm
shift in how we design, maintain and operate the affected parts of our electricity
distribution network. Processes that are new or are changing significantly include:oFault detection and location (change);oPlanning and switching (change);oAnnual compliance testing (new); andoMaintain network balance (new).



Network capacitive balancing, one of our critical dependencies, is a new concept to
AusNet Services.



Safety practices have been enhanced to recognise the network has the potential tooperate at higher voltages. No glove and barrier work is to be undertaken with REFCLs
in service, however live line stick work will be allowed. Further investigation into safety
practices and appropriate personal protection equipment (PPE) is continuing.

When REFCLs are operating, more customers might experience outages on Total FireBan (TFB) days or Code Red days as a result of the technology shutting down sectionsof the network where a fault is detected.

Change management is a fundamental element of the REFCL program implementation, as
illustrated in Figure 8 below.
Figure 8: Internal change impacts for implementation of the REFCL Program

Source: AusNet Services

AusNet Services’ REFCL Program Change Management Strategy provides the framework toaddress how we are managing and integrating each of the eleven change impacts. The
framework details how we:

Conduct the overall change management approach for the REFCL Program;

Optimise audience buy-in;Embed the change and ownership;
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Section 7 – Project management process

Build capability;



Minimise business disruption; andManage and mitigate change resistance.

This is achieved by using the following strategies:

Stakeholder Engagement: Involve stakeholders in problem solving or decision making
and listening to what they need, then incorporating that into the Change Management
plan in order to increase their commitment to the change;Training: Understand what learning and performance support is needed to enable users
to confidently perform their job in the new environment to enable knowledge, confidence
and adoption;

Business Readiness: Prepare the business for the change to enable a successfultransition from project activities to Business As Usual (BAU) and continuous
improvement;Communication: Effectively and consistently communicating information using theappropriate channels to stakeholders to build awareness and understanding of thechange; andMeasuring Change Effectiveness: Outline how we will measure the effectiveness ofthe change management strategy.

Whilst it is anticipated that the majority of change management activities will be completed andembedded into BAU by the end of Tranche 2, there is the possibility new change impacts will beidentified, given the complex nature of the Program. These changes will need to be managed
on an ongoing basis, using the same framework.

7.6

Training

A key component of our change management activities is training.
overview of the training modules for the REFCL Program.

Figure 9 provides an

Figure 9: Training plan for the REFCL Program# ofpeopletrained(as ofApril’19)

784

525

-

101

46

30

6

286

288

-

Source: AusNet Services

Employees from across AusNet Services, together with external service providers, have been
identified as requiring the REFCL induction training either for awareness or because they play a
specialist REFCL related role.

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Section 7 – Project management process
For those resources who perform a specialist REFCL related role, the training curriculum istargeted depending on the role the resource performs. Various delivery mechanisms are used
to deliver these modules. The training plan will be reviewed regularly and updated as needed.

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Section 8 – Forecast capital expenditure

8 Forecast capital expenditure
8.1

Introduction

As explained in our contingent project applications for Tranches 1 and 2, there are fivecategories of direct capital expenditure in the REFCL installation Program:

Zone substation works;

Network balancing;Line and cable hardening;Compatible equipment; andAssisting HV Customers to achieve Code compliance.

In addition to these five categories, capital expenditure is required for program management
expenses incurred in overseeing the project.
The purpose of this section is to provide a high level description of the required work for each of
the five categories. Additional detailed information can be found in:Functional scopes for each zone substation, which explain the zone substation works indetail.



The relevant strategy documents, which explain our approach to network balancing, line
and cable hardening and compatible equipment.



The Total Cost model, which sets out the volumes and unit rates for work to be carriedout on each element of the program.

A more technical summary of the impact of the REFCL installation on the existing network isprovided in the REFCL Equipment Building Block Functional Description, which is provided as asupporting document to this contingent project application.

Prudent and efficient – satisfying the capital expenditure criteria

8.2

AusNet Services recognises that the AER must consider whether the forecast expenditure in
relation to this contingent project is prudent and efficient, in accordance with the capital
expenditure criteria in the Rules24, taking into account the capital expenditure factors in thecontext of the contingent project.
In the context of this project, we consider capital expenditure is:Prudent if it is necessary to ensure AusNet Services’ compliance with the mandated
earth fault standards and mitigates bushfire risk to the maximum extent possible withoutcompromising safety.

Efficient if it delivers the scope of works at the least possible cost to customers, including
the expected costs of unserved energy during construction and following theestablishment of the REFCL.

As explained in section 7 of this contingent project application, our approach to managing thisproject ensures that the required works are efficiently scoped and costed. AusNet Services has

24

Clause 6.6A.2(f)(2).

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Section 8 – Forecast capital expendituresought opportunities to reduce the cost of the REFCL program wherever possible. This isdemonstrated by the following work:


AusNet Services plans to submit an exemption request to ESV relating to the isolation ofunderground cable on the KLO network.



AusNet Services has conducted a comprehensive review of transfer feeders (which areconnectable to both a REFCL protected zone substation and a non-REFCL protectedzone substation). This process has identified opportunities to change the existingtransfer arrangements and hence allowed AusNet Services to remove a number feeders
from Tranche 3 works, with no expected change in reliability performance. In doing so,
AusNet Services has avoided costs associated with line hardening and compatible
equipment.



AusNet Services is undertaking an extensive cable testing program to ensure that it
identifies and replaces critical cables that are prone to failure. However, we are taking arisk-based approach and non-critical cables will not be tested and will be replaced on
failure. This is a prudent and efficient approach to managing the risk of failure of theseassets overall against the cost of replacement.

As already explained, we draw on the lessons from our current work to inform and improve ourmanagement of the REFCL program. Project risks have been identified and processes put inplace to manage them effectively. We have also examined the change management
implications of the project to ensure that the project impacts on the business are properly
understood and included in the project costings. In terms of program management, we have acomprehensive program governance arrangement in place.
The project scopes have been developed by considering the alternative engineering solutions
that are available to address the identified investment need, while costs are determined using
our standard project costing approach. In summary, AusNet Services is confident that it has
adopted a comprehensive and rigorous approach to this project which will ensure that theresulting expenditure forecasts ‘reasonably reflect the capital expenditure criteria’ in the Rules,
as required by clause 6.6A.2(f)(2).

8.3

RIS Comparison

In our contingent project applications for Tranches 1 and 2 of the REFCL program, we
compared the costs at each zone substation with the estimates in the Government’s Regulatory
Impact Statement (RIS)25. A key difference between the RIS estimates and the actual project
costs is that the RIS assumed that one GFN would be sufficient at most sites, whereas this has
not been the case. In addition, a program of cable replacements has been necessary, which
was not anticipated in the RIS.
In addition to these differences, our previous analysis also identified the following works thatwere either not included or under-estimated in the RIS cost assessment:25



Neutral bus switchboard – This is required for effective year-round protection of the
network. Balancing bushfire risk reduction with network reliability requires multiple
operating modes with differing earthing arrangements. A neutral bus switchboard
facilitates these arrangements.



REFCL backup protection and interface control systems – Protection and control
equipment must operate in several earthing fault modes. Additional control systems are
required to provide the interface between the GFN and AusNet Services’ equipment.

http://www.acilallen.com.au/cms_files/ACILAllen_BushfireMitigationRIS_2015.pdf

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Section 8 – Forecast capital expenditure
New protection devices are also needed to provide an adequate backup for the GFN for
the instances of mal-operation.


Testing the REFCL – As part of the project commissioning it will be necessary to fully
test the functionality of the REFCL to ensure that it is capable of operating to meet theRegulations. The capital cost of REFCL installation includes the first instance of stress(insulation) and compliance tests to demonstrate the correct operation of the device.

Community engagement plan – This is required due to the number of outages forecast
for the community and the new network insulation tests, which in the short term are
expected to produce unfavourable reliability outcomes for customers.

Work required to achieve the performance criteria in each automatic switchingzone – This involves a combination of additional capital works including adding
balancing capacitors and adding a third phase conductor to balance each section. The
RIS included phase rotations alone as the only network balancing cost, and this will notachieve the performance required by the Regulations.

Works needed to maintain balance – These include replacing fuses with solid links
where fuse operation will lead to out of balance, potential non-compliance with theRegulations, and possible REFCL mal operation. Furthermore, fuse savers are required
either where fuses cannot be replaced with solid links because the fault level at aparticular location on the network is too high or where fuses are required to provide
protection reach for the network.

Subsequently, the AER has undertaken detailed reviews of our capex forecasts for Tranche 1
and Tranche 2 in accordance with the Rules requirements. With the exception of relatively
minor adjustments, the AER concluded that our capex forecasts were prudent and efficient.
Section 5.1 of this contingent project application shows that our actual capex is likely to exceed
the AER’s allowance for Tranche 1 and 2, despite the strong incentives we face to minimise thecosts of delivering the REFCL program.
In summary, whilst the RIS cost estimates were reasonable given the state of knowledge at thattime, we now have much better information for the purpose of developing capex forecasts for
Tranche 3 works. In contrast to our earlier contingent project applications, therefore, we havenot provided a substation by substation analysis of the cost differences between the RIS andthis contingent project application. However, we would be pleased to provide this analysis if
requested by the AER.

8.4

Zone substation works

The following type of work is typical of the investment required at most Tranche 3 zone
substations:Specification, procurement and installation of a GFN, including an Arc Suppression Coil,Residual Current Compensation, Grid Balancing Cabinet and control system.

Specification, procurement and installation of a neutral bus switchboard. The
introduction of the GFN requires a neutral bus which enables different earthingarrangements to be automatically configured. This enables remote earthing andprotection scheme selection depending on network and weather conditions.



Upgrade of the existing station service transformers and changeover boards. This work
is required because the AC auxiliary supply requirement dramatically increases due tothe GFN installation.



Testing and potential replacement of cables and equipment incapable of operating atelevated voltages.
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Section 8 – Forecast capital expenditureReplacement and extension of existing protection and control equipment with equipment
capable of operating in several modes including resonant earthing and traditional earth
fault modes. Additional protection and control systems are also required to protect the
newly installed REFCL equipment.



Prior to commissioning the GFN, network hardening tests involve the process of lifting
voltages (using the GFN) in a healthy three phase powerline network (phase by phase)to check network readiness for future states of REFCL operation. During this activity,
there is an increased likelihood of asset failures. These tests are necessary to ensure
the GFN can operate without causing line and station equipment to fail, potentiallyresulting in a fire start. We would replace any assets that fail during the testing process,and a forecast cost has been included in the zone substation works.

In addition to the above, location-specific work may be required. The project scopes set out thezone substation works required at each Tranche 3 zone substation.
Table 6

Summary of required zone substation works

Zone
substation

GFN(including
neutralbus)

Battery
Set

AuxiliaryTransformerCapacitance
reducing
Isolation
Transformer

22Kv
Capacitor
Banks

Cableszone
substation(metres)

2016-20
Cost ($0002015
direct)2021-25
Cost ($0002015
direct)

MSD

1

0

2

0

1

680

8,057

-

LLG

1

0

2

0

0

2,210

2,088

6,438

SLE

1

1

2

0

1

810

3,879

5,229

BN

1

0

2

0

0

3,008

5,189

6,222

KLO

2

0

2

5

1

2,530

2,694

12,797

KLO2

0

1

0

0

1

900

6,248

10,517

Total

6

2

10

5

4

10,13828,154

41,202

Source: AusNet Services

To demonstrate the efficiency and prudency of our proposed expenditure, we have regard toavailable benchmark information. Attachment 20 shows a comparison of the proposed unit
rates against the Tranche 1 and 2 applications. Generally, the cost differences are attributed to
the reflection of actual cost information, as explained in Attachment 20.

8.5

Network balancing

In order to meet the performance standards in the Regulations, capacitive balance must be
achieved and maintained. Capacitive imbalance will negatively affect REFCL performance
because:
1. It increases residual earth fault current, i.e. fire ignition risk; and2. It increases the standing level of neutral voltage, i.e. it constrains fault detection sensitivity.
As fire risk reduction relies on low residual fault current, capacitive imbalance can pose a risk tofire safety and so must be managed. In Victoria, long single phase (two-wire) spurs teed off
three-phase lines can create significant capacitive imbalance.
In broad terms, the potential actions to balance network capacitance include:
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Section 8 – Forecast capital expenditure

Two-wire spur lines must be connected to the three phase network in a way that limits
capacitive imbalance, i.e. the phases to which each spur line is connected must be
selected for capacitive balance, not just load balance.

Balancing capacitance can be added by installing pole-mounted capacitors along
feeders, e.g. on the third phase at a tee-off pole where a long two-wire spur leaves afeeder.



Improved fault detection algorithms with increased tolerance to imbalance also have apotential role in addressing the potential impact of imbalance.

To satisfy the legislated performance criteria the network leakage current will need to be at aminimum under normal operating conditions. The leakage current required will vary site to site
however the target is less than 0.1A. Our approach is to achieve this outcome through a
combination of:

Performing single-phase spur and distribution substation phase transpositions;

Installing a balancing capacitor bank at the beginning of single phase spur sections;

Installing LV balancing capacitor banks on the three-phase backbone;In a small number of cases adding a third conductor to the beginning of a single-phasespur section and converting that section to three-phase; and

Removal of fuses on network segments with excessive capacitive current as single
phase fuse operation will cause excessive imbalance causing the GFN to trip the feeder.
Therefore, to solve the excessive imbalance, it is essential AusNet Services remove theexisting fuses and replace the fuse elements with solid links and to install fuse savers
where required for network protection.

As explained in our Network Balancing Strategy, we tested three alternative options before
selecting the preferred approach, which is also the lowest cost solution. The volume of work issite specific, dependant on total 22kV line length and the degree that it is out of balance. The
required volumes and costs of work for network balancing is set out in the following table.
Table 7

Summary of required balancing works

UnbondThird
Phase

Install
Third
Phase
of
conductor

Fuse
replace
ment
with
solid
links

Fusesaver
installation – no of
sites

Phase
Plate
Correction2016-20
Cost
($000
2015
direct)2021-25
Cost
($000
2015
direct)

15

1

0

13

12

15

1,817

-

3

11

1

0

13

20

29

810

1,154

67

4

21

1

0

15

15

38

1,026

1,548

BN

57

17

20

0

18

29

27

38

1,552

2,349

KLO

24

1

14

0

0

2

9

11

517

917

Total

224

28

81

3

18

72

83

131

5,722

5,968

Zone
substat
ion

Phase
Trans
positions

SinglePhase
Balanci
ng
Caps

Three
Phase
Balancing Caps

MSD

33

3

LLG

43

SLE

Source: AusNet Services

We note that the AER accepted our approach to balancing works in Tranche 1 and 2 of the
REFCL program. We have incorporated the learnings from Tranche 1 and Tranche 2 and now
included the replacement of fuse savers in Tranche 3. We have determined that fuse savers are
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Section 8 – Forecast capital expenditure
required either where fuses cannot be replaced with solid links because the fault level at aparticular location on the network is too high or where fuses are required to provide protection
reach for the network. Otherwise, this program is consistent with previous approach. An
analysis of the unit costs for Tranche 3 is provided in Attachment 20.

8.6

Line hardening

When an earth fault occurs on a REFCL-protected network, over-voltage on un-faulted phases
occurs and can lead to failure of equipment installed on the network. Such equipment failure
constitutes a second earth fault on the network, termed a ‘cross-country fault’ because it isusually remote from the initial fault and always occurs on one of the un-faulted phases.
REFCLs can only deal with multiple earth faults if they all occur on a single phase. With across-country fault, the network has two phase-to-earth faults at different locations and highcurrents will flow in both fault locations. To minimise the risks arising from cross-country faults,
equipment that is liable to fail under REFCL voltages must be replaced. Our line hardening
program covers two key pieces of equipment: surge arrestors and cables, which are discussed
below.
Surge Arrestors
In preparation for Tranche 1, Powercor and AusNet Services jointly conducted tests todetermine the whether some existing types of surge arrestors are capable of withstanding
24.2kV. Testing has concluded that two particular types of line surge arrestors that make up
60% of the population of AusNet Services’ line surge arrestor fleet do not need replacing as
they are capable of withstanding the increased voltages associated with the operation of a
REFCL.
AusNet Services’ Tranche 3 total line surge arrestor population is 15,673 units. Out of thispopulation, 4,529 units at 1,934 sites need to be replaced to withstand over-voltage events.
This is 29% of the surge arrestor population and is less than the overall proportion of 40% thatmust be replaced. The costs of replacing surge arrestors in relation to each zone substation
installation will depend on the number and type of surge arrestors at that location.
Table 8

Summary of required surge arrestor replacements
Unacceptable Surge
Arrestor Sites
Requiring
Replacement

Unacceptable
Surge Arrestor
Units Requiring
Replacement

2016-20 Cost($000 2015
direct)2021-25 Cost($000 2015
direct)

MSD

429

977

1,021

-

LLG

214

511

218

317

SLE

529

1,281

545

793

BN

682

1,559

664

966

KLO

80

201

86

125

Total

1,934

4,529

2,533

2,200

Zone substation

Source: AusNet Services

We note that the AER accepted our approach to surge arrestor replacements in Tranche 1 and
2 of the REFCL Program. The approach in this contingent project application is unchanged. An
analysis of the unit costs for Tranche 3 is provided in Attachment 20.
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Section 8 – Forecast capital expenditure
Cable Replacement
As noted above, the REFCLs increase the risk that 22kV cables may fail, as they will experienceelevated phase-to ground-voltages when a REFCL operates. Following cable failures when
testing at the Woori Yallock (WYK) zone substation, AusNet Services concluded that aproactive approach is required to identify and repair or replace critical cables in poor condition
or insufficiently rated cables prior to operating a REFCL protected network.
As explained in our contingent project application for Tranche 2, following an examination ofalternative options, we developed the following approach to address this risk:
1. Desktop and field identification of critical cable types and population currently on the
network; and2. Targeted on-line and off-line testing to confirm if the cables cannot withstand elevatedvoltages.
oOn-line tests ranging from visual inspection, spot Partial Discharge (PD)measurements using on-line PD measurement devices and non-invasive
inspection methods (RF scanners, Ultrasonic and Corona cameras); andoOff-line tests ranging from sheath integrity, Dielectric Spectroscopy (DS),Dielectric Dissipation Factor (DDF) and Capacitance, Partial Discharge (PD) andHigh Voltage (HV) withstand.

Targeted testing ensures all critical feeder cables in a REFCL protected network areappropriately rated and with a sound condition score minimising the risk of failure during REFCL
operation. Based on this approach, AusNet Services has proposed a program of:proactive cable repair and replacement; andreactive cable repair and replacement.

Cables that are identified as being unable to sustain REFCL operation will be either repaired or
replaced using a proactive replacement program prior to commissioning the REFCLs. However,
not all cables will be tested and testing may fail to identify some cables that could fail under
REFCL operation. Accordingly, we anticipate some cables will need to be repaired or replacedon a reactive basis.
The forecasts presented in the table below reflects the updated information obtained during
Tranche 1 and, to date, in Tranche 2.
Table 9

Summary of required cable replacements
On-line Tests

Off-line Tests

Repairs

Replacement(m)

2016-20 Cost($000 2015
direct)2021-25 Cost($000 2015
direct)

MSD

5

5

6

0

175

-

LLG

4

4

4

395

79

245

SLE

5

5

6

3,224

359

1,447

BN

8

8

6

2,774

329

1,280

KLO

6

6

4

540

100

317

Total

28

28

26

6,933

1,043

3,288

Zone substation

Source: AusNet Services

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Section 8 – Forecast capital expenditure
In its decision for Tranche 2, the AER accepted our forecasts for cable replacements following adetailed review. As noted above, our assessment for this contingent project application reflects
the latest available information, but our approach is unchanged. Further information on the cost
analysis is provided in Attachment 20.

8.7

Compatible equipment

Some network equipment is not compatible with REFCL operation and must be upgraded or
replaced with equipment that is compatible. This is a separate issue to the network hardening
testing, described in section 8.4 above, which is solely concerned with the capability of theequipment to withstand the increased voltage. In contrast, incompatible equipment can prevent
correct REFCL operation, prevents the operation of the DFA scheme, or may produce
dangerous network conditions with a REFCL in service.
ACRs and sectionalisers will need to be replaced or altered due to their incompatibility withREFCLs.
8.7.1

Automatic Circuit Reclosers (ACRs)

A significant issue arises in relation to existing earth fault protections, which are non-directional.
The devices act when they detect earth fault current flow without information on its direction, i.e.
whether the fault is ‘upstream’ or ‘downstream’ of them. This is not a problem in non-REFCL
networks, since all earth fault currents flow only one way – from the zone substation to the fault.
With a REFCL in service, however, earth fault current flows back into the zone substation from
un-faulted feeders before a portion (the uncompensated residual current) flows out along thefaulted feeder to the fault. Using non-directional feeder earth fault relays with a REFCL inservice will lead to tripping of healthy feeders or whole groups of feeders.
To address this issue, AusNet Services will replace or upgrade unsuitable ACRs on feeders
connected to REFCLs with new ACRs that have reverse power flow capability. In addition, the
new ACRs have more sensitive earth fault detection capability to assist in locating faults when a
REFCL operates. AusNet Services’ Automatic Circuit Recloser Strategy provides further
information on the rationale for the planned scope of work and the alternative options that wereconsidered.
The general DFA and sectionaliser algorithm will require an ACR or equivalent to be present at
key points on each feeder to allow the DFA/Sectionalisers to locate a fault with the GFN in
service. Without these additional devices, the DFA/Sectionaliser algorithm will not be able toidentify which feeder is faulted. As a result, additional ACRs are required to be installed.
Furthermore, as part of the fuse review detailed above in section 8.5, additional ACRs are
required as a least cost alternative to the replacement of many fuse sites within a network
segment and utilising the much larger protection coverage of the ACR. There is also
considerable labour cost savings to be gained from adapting this method. As a result, additional
ACRs are required to be installed.
The proposed costs are set out in the following table.

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Section 8 – Forecast capital expenditure
Table 10

Summary of required ACR compatible equipment costs
Units requiring
upgradeUnits requiring
replacement

2016-20 Cost($000s 2015
direct)2021-25 Cost($000s 2015
direct)

MSD

1

4

302

-

LLG

1

5

180

156

SLE

5

6

510

187

BN

5

9

396

281

KLO

3

1

98

32

Total

15

25

1,486

656

Source: AusNet Services

In its decisions for Tranches 1 and 2, the AER accepted our forecasts for ACR replacements,
noting that the costs were lower than the RIS estimates. Our strategy remains unchanged forthis contingent project application. Further information on the cost analysis is provided in
Attachment 20.
Sectionalisers
Our existing 22kV feeder fault treatment scheme, Distribution Feeder Automation (DFA)involves a combination of sectionalising switches, ACR operations plus the use of adjacentfeeders to supply feeder sections downstream of a faulted section. The DFA philosophy andtechnology developed by AusNet Services is unique and plays an important role in maintaining
network reliability.
The introduction of REFCLs affects the operation of DFA, such that each ‘automated switchingzone’ in a DFA scheme must be both capacitively balanced and able to detect faults (thiscapability is impacted by the much lower fault currents as a result of the installation of REFCLs).
The existing sectionalisers are unable to detect the low fault current and as such, need to be
upgraded to restore the DFA functionality. Additionally, the DFA algorithm operating within the
SCADA system is not compatible with REFCL technology, and needs to be rewritten.
The use of DFA significantly increases the number of automated switching zones, which is afeeder section delineated by sectionalising switches. As a consequence, AusNet Services’ total
network balancing and switch upgrade costs are affected by AusNet Services’ historicinvestment decision to implement DFA in order to improve reliability.
Unless DFA capability is restored, customers will suffer a degradation in reliability outcomes asa result of the REFCL program. In our contingent project applications for Tranches 1 and 2, theAER examined the case for including the costs of rectifying the DFA scheme. In both cases, theAER concluded that the costs should be allowed. In relation to Tranche 2, the AER gave
particular consideration to the appropriate regulatory treatment, given the importance of

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Section 8 – Forecast capital expenditureproviding appropriate incentives and promoting the National Electricity Objective. The AER
commented as follows:26
Our investigation of this issue concluded that in periods outside the peak bushfire season,
the REFCL cannot operate without the DFA scheme being modified or it will adversely
affect customer reliability. This is because a REFCL operating in “reliability mode” will
maintain supply into a fault that the DFA scheme cannot identify and isolate without
modification. Moreover, AusNet Services invested in DFA to gain a reward under the
STPIS which funds its investment in DFA. If the DFA works were not funded, AusNet
Services would suffer penalties under the STPIS that exceed the cost of the upgrade,which is not an equitable or efficient outcome. However, compared to compensating
AusNet Services for the cost of upgrading the DFA system, we do not consider a directcompensation payment desirable or preferable. This is because a compensation payment
would have an equal or greater impact on customer prices but reliability would be reduced
compared to our preferred alternative. This would not satisfy the NEO.
We agree with the AER’s reasoning for including the costs of the DFA rectification in Tranche 2.
The rationale for the inclusion of the DFA costs are unchanged in relation to Tranche 3 andtherefore we have included the costs of the following work:
Replacement of sectionalisers - these are switches designed to interrupt load current,
but not fault current. Similarly to the ACRs (which are designed to interrupt fault
current), these sectionalisers do not have the requisite detection sensitivity to support
the DFA scheme when a REFCL is in operation and will need to be replaced; andDFA algorithm design - the DFA algorithm interprets real time network status data anddevises the switching sequence to isolate a faulted switching zone and restore supply tothe maximum number of customers achievable, typically within a period of 1 minute.

The estimated number of switches requiring change and total costs to rectify the DFA schemes
to ensure reliability is maintained are set out in the table below. The costs reflect the latest
available information obtained from Tranches 1 and 2.
Table 11

Reliability expenditure and units required, ($m, $2015 direct)
2016-2020
Units

2021-2025
Units

2016-20 Cost($000s 2015
direct)2021-25 Cost($000s 2015
direct)Forecast no. of switches[C-I-C][C-I-C][C-I-C][C-I-C]New ACR units &control box[C-I-C][C-I-C][C-I-C][C-I-C]

Source: AusNet Services

8.8

Assisting HV customers to achieve Code compliance

Whilst the ESV’s amendments to the EDC have clarified that HV customers are responsible forhardening works on their assets, the delivery of the REFCL program depends on the timely
completion of this work. It is therefore appropriate for AusNet Services to work with HV
customers to provide assistance in relation to understanding the works required and identifying
the preferred solution.

26

AER final decision, AusNet Services Contingent Project, Installation of Rapid Earth Fault Current Limiters (REFCLs) –tranche two, 31 August 2018, page 42.

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Section 8 – Forecast capital expenditure
For example, AusNet Services reimburses the costs of independent consultants engaged by the
HV customers to assess the current condition of the HV electrical assets and to recommend thepreferred solution. Given the significant dependence of the REFCL Program on the timely
remedial work to enable HV customers to comply with the EDC, it is prudent and efficient for thecosts of assisting HV customers to be included in this contingent project application.
In addition, to ensure AusNet Services can detect faults and safely operate its network, we will
install an ACR at HV customer’s site, where they undertake asset hardening works (as opposed
to AusNet Services installing an isolating transformer). This is critical for our staff when
patrolling lines to identify faults. We consider this is prudent and efficient expenditure andnecessary to enable an overall cheaper solution to be implemented at these customers sites.
The cost of installing new ACRs reflects the latest available information. The ACR will be owned
and operated by AusNet Services and is distinct from work undertaken on the customers’
premises.
In its decision on our Tranche 2 contingent project application, the AER accepted the need for
ACRs at HV customers’ site to mitigate significant risk of a cross-country fault. Our approach inrelation to this contingent project application is unchanged, with the exception of adopting thelatest cost information.
A summary of the estimated costs in assisting HV customers at each of the Tranche 3 zone
substations is set out in the table below.
Table 12

Costs associated with HV customers ($m, $2015 direct)
HV connection points

2016-20 Cost ($000 2015
direct)2021-25 Cost ($000 2015
direct)

MSD

n/a

n/a

n/a

LLG

1

45

45

SLE

1

45

45

BN

2

91

91

KLO

3

133

133

Total

7

314

314

Zone substation

Source: AusNet Services

8.9

Program management costs

The AER examined our program management office costs in its decision for Tranche 2. The
AER noted that on average total per zone substation, AusNet Services’ costs of $858 000 (real,$2016) were within 1% of Powercor’s costs. The AER also concluded that the respective
accounting treatments are reasonable, having regard to the approved Cost Allocation
Methodologies.
In this contingent project application, we have adopted the same approach to estimating
Program Management Costs.

8.10 Capital Expenditure in the 2021-25 Regulatory Control Period
Clause 6.5.7(f) of the NER describes how capital expenditure for a contingent project, which is
expected to be incurred in a subsequent regulatory period, is to be treated. These provisions
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Section 8 – Forecast capital expenditure
are operative where the AER determines under clause 6.6A.2(e)(1)(iii) that the likely completion
date for a contingent project is a date which occurs in the immediately following regulatory
control period.
AusNet Services is required to complete the Tranche 3 zone substations by 1 May 2023, which
is approximately half way through the forthcoming regulatory period. Accordingly, we requestthat the AER determine pursuant to clause 6.6A.2(e)(1)(iii) that the likely completion date for thiscontingent project is a date which occurs in the immediately following regulatory control period.
A forecast of the capital expenditure in the 2021-25 regulatory period is set out in Table 15
below.
Table 13Capex in subsequent regulatory period ($000s 2015 direct)

Capex in subsequent
regulatory period

2021

2022

2023

2024

2025

Total

38,96024,627---

63,587

Source: AusNet Services

8.11 Summary of forecasts
The table below summarises our capital expenditure for each of the six workstreams.
Table 14

Summary of Direct capital expenditure requirements ($000s 2015, direct)
2016

2017

2018

2019

2020

Total

Zone Substations

-

-

-

6,001

22,15328,154

Network Balancing

-

-

-

1,392

4,330

5,722

Line andHardening

-

-

226

850

1,457

2,533

HV customers

-

-

-

16

299

314

Compatible
Equipment

-

-

-

495

990

1,486

Other

-

-

-

215

488

703

Total

-

-

226

9,095

30,63439,956

Cable

Source: AusNet Services

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Section 9 – Forecast incremental operating expenditure

9 Forecast incremental operating expenditure
9.1

Expenditure categories and drivers

In addition to the capital works, AusNet Services will incur incremental operating expenditure asa result of the installation of REFCLs, requiring additional specialist planning resources andresources to deliver the following activities:

Annual testing
Annual tests take the form of Primary Earth Fault Testing and Insulation Testing at eachsite. The first of these tests will be performed as part of the capital installation project forthat site. However, annual testing is an on-going operating cost, and has been included in
the forecast incremental operating expenditure.



Network Balancing
This involves monitoring capacitive balance and initiating corrective action where balance is
outside range. Forecasting capacitive balance is necessary to ensure that material changes
to the network (such as conductor replacement or retirement, and changes in loads orgeneration) are known in sufficient time to rebalance the network.

Fault response and analysis
It is expected the time spent on fault response and analysis will increase due to thecomplexities of the resonant earthing network. A small incremental operating expenditure
allowance has been included to address this new activity. It is noted that each Tranche
increases the number of REFCLs installed and the requirement for additional analysis on
effected feeders.



Equipment maintenanceFollowing the installation of the REFCL devices, routine maintenance is required, similar toany other plant and equipment in the zone substation. A small incremental cost has been
included in the forecast operating expenditure to perform this routine maintenance.

Line equipment purchases
The introduction of the REFCL devices imposes higher voltage conditions on existing
installed lines infrastructure. Some of the equipment that AusNet Services uses for
operating and maintaining the network is not rated to handle these higher voltages. Many ofthese items are capitalised, but insulated hard covers do not meet the unit costrequirements for capitalization. Therefore the cost of these items has been included as anincremental operating cost.

9.2

Forecasting efficient and prudent operating expenditure

AusNet Services has adopted a ‘bottom up’ forecasting approach for each of the activities
described in section 9.1. The objective of the forecasting method is to determine the efficientand prudent incremental operating expenditure associated with each activity. This forecasting
approach is unchanged from Tranche 2.
AusNet Services has adopted ‘global’ assumptions in relation to the REFCL installation
timetable and labour rates, which apply across each of the operating expenditure activities. The
labour rates are consistent with the rates adopted by the AER in its 2016-20 EDPR Final
Decision. AusNet Services is not seeking to amend these rates or the rate of escalation during
the current regulatory control period.
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Section 9 – Forecast incremental operating expenditure
In addition to these global assumptions, AusNet Services has developed specific assumptions
regarding the resource requirements for each activity. These assumptions are explained in therelevant supporting documents. In each case, the resource requirements reflect AusNet
Services’ estimate of the efficient and prudent level of activity.
The AER must accept AusNet Services’ operating expenditure forecast if it is satisfied that theforecast reasonably reflects the operating expenditure criteria in the Rules27, taking into accountthe expenditure factors in the context of the contingent project. The application of theexpenditure factors to this contingent project is discussed in Section 10. For the reasons
outlined in the REFCL Program Operational Requirements supporting document,
AusNet Services considers that the application of its forecasting methodology produces
operating expenditure forecasts that comply with the Rules requirements.

9.3

Summary of forecasts

The annual incremental operating expenditure is set out in Table 15 below.
Table 15: Forecast incremental operational costs, $000’s, $2015
2016

2017

2018

2019

2020

Total

Fault response & analysis

-

-

-

-

11.0

11.0

Operating, maintenance and testing
instructions

-

-

-

-

-

-

Routine maintenance of zone
substation assets

-

-

-

-

-

-

Network Balancing

-

-

-

-

22.3

22.3

Annual Testing

-

-

-

-

-

-

HV Customers

-

-

-

-

-

-

Live line equipment purchases

-

-

-

-

-

-

Training & Change Management

-

-

-

-

-

-

Total

-

-

-

-

33.4

33.4

Source: AusNet Services

As shown in the above table, in relation to the REFCL devices installed in Tranche 3 of the
REFCL Program, incremental operating expenditure of $0.03 million is required in 2020. The
operating expenditure for Tranche 3 is all incremental to the operating expenditure alreadyincluded in Tranche 1 and 2.
For the reasons outlined in section 9.1, each of the operating expenditure activities is requiredin order to ensure that the network operates safely and reliably during REFCL implementationand the subsequent operation of REFCL equipment.

27

Clause 6.6A.2(f)(2).

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Section 9 – Forecast incremental operating expenditure
AusNet Services will propose an opex step changes as part of the 2021-25 regulatory proposal
to cover the step change required to operate all three tranches of the REFCL program in the2021-25 period. This consolidated approach to handling all three tranches should makeassessment easier for the AER and ensure a consistent approach is applied.

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Section 10 – Expenditure factors to be considered by the AER

10 Expenditure factors to be considered by the AER
The NER requires the AER to consider a number of operating and capital expenditure factors in
its assessment of the forecast expenditure in the contingent project application. These
expenditure factors include:The substitution possibilities between operating and capital expenditure;

Whether the expenditure forecast is consistent with any incentive schemes that apply tothe distributor;The extent the expenditure forecast is referable to arrangements with a person otherthan the distributor that do not reflect arm’s length terms; andThe extent the distributor has considered, and made provision for, efficient and prudent
non-network alternatives.

The following paragraphs comment on each of these factors in turn.
10.1.1 Substitution possibilities between operating and capital expenditure
The capital works are driven by an obligation to comply with new performance standards that
apply to each polyphase electric line originating from a list of specified zone substations. As
explained in section 4, the installation of REFCL technology is the only feasible method that is
capable of complying with the Regulations. At this highest level, there are no substitution
possibilities in relation to the proposed project.
However, feasible alternative options are available in determining the strategies for theparticular workstreams (such as network balancing) and the scope of the station works as wemove beyond the immediate task of installing the GFNs. In some instances, the feasible
options include different mixes of operating and capital expenditure, and therefore reflectsubstitution possibilities.
The incremental operating expenditure activities in relation to the contingent project application
are discussed in section 9 and the supporting document, Operational Requirements. The
nature of many of these activities (such as testing, document updates and reporting) is suchthat there are no substitution opportunities between operating and capital expenditure.
10.1.2 Consistency with the incentive schemes – reliability impacts
As already noted, the impact of REFCL installation on network reliability was examined in the
AER’s final decisions on our contingent project applications for Tranches 1 and 2. The Victorian
Government queried whether modification of the DFA system is a valid project cost to be
included. For the reasons already outlined, however, these matters have been considered by
the AER.
The operation of the other economic regulatory regime incentive schemes are unaffected by thecontingent project. The implications of REFCL operation on the Victorian Government F-Factor
Scheme has been accounted for through the F-Factor Scheme Order in Council gazetted on 22
December 2016. This amends the target ignition risk units for financial year 2019/20.

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Section 10 – Expenditure factors to be considered by the AER
10.1.3 Related parties
The AER is required to consider the extent the expenditure forecast is referable toarrangements with a person other than the distributor that do not reflect arm’s length terms.
AusNet Services’ related party arrangements were described in detail in Appendix 1C of theRegulatory Proposal for the 2016-20 period. AusNet Services confirms that there are no related
party margins in the capital expenditure forecasts presented in this contingent projectapplication.
10.1.4 Non-network alternatives
The nature of the capital expenditure workstreams – being station works, network balancing,line and cable hardening and compatible equipment – is such that there are no practical
opportunities for non-network alternatives. In particular, much of the work is focused on
ensuring that AusNet Services’ network is capable of continuing to provide safe and reliable
distribution services with REFCLs in service. Inevitably, the issues to be resolved necessitate
capital works in relation to AusNet Services’ network assets, rather than non-network solutions.

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Section 11– Accelerated Depreciation of Retired Assets

11 Accelerated Depreciation of Retired Assets
AusNet Services proposes to accelerate depreciation of certain network assets that will be
removed from service over the current regulatory period. The nature of the assets and asset
classes is such that they will be replaced ahead of the end of their expected economic and/or
technical lives. The AER has approved AusNet Services’ proposal to accelerate depreciation ofcertain high bushfire risk assets which have been, or are forecast to be replaced as part of oursafety programs and approved this approach in our Tranche 1 and 2 contingent projectapplications.28
AusNet Services’ proposal to apply accelerated depreciation to the identified assets in thiscontingent project application accurately reflects changes to the remaining economic lives of
those assets. Accordingly, AusNet Services’ proposal conforms to the requirement in NERclause 6.5.5(b)(1)29.
The methodology undertaken by AusNet Services to determine the proposed accelerated
depreciation is unchanged from our approach used in the 2016-20 EDPR proposal and Tranche
2 contingent project application. For this contingent project application AusNet Services has
used the following methodology:
1. Identify assets that are to be removed in both the current period (2016-20) and next
regulatory control period (2021-25).
2. Estimate opening RAB value of relevant asset classes (as at January 2015).
3. Determine portion of asset class to be accelerated (i.e. proportion removed from assetbase).
4. Roll forward the estimated 2015 opening RAB values:a. For assets removed in the current period roll forward the estimated 2015 opening
RAB values to January 2019 using a nominal RAB roll forward approach.
b. For assets to be removed in the following period (2021-25) roll forward theestimated 2015 opening RAB values to January 2021 using a nominal RAB roll
forward approach.
Step 1 – Identify assets
The assets considered in AusNet Services’ accelerated depreciation proposal include:Protection Relays within Zone Substations

Surge Arrestors;

Automatic Circuit Reclosers (ACRs);



Sectionalisers; and

22kV HV overhead cables

The proposed protection relay replacements form part of protection and control systems
replacement and extension works within zone substations as outlined in section 8.4. The
proposed surge arrestor replacement program and proactive 22kV cable replacement program28
29

AER - Final decision, AusNet distribution determination - Attachment 5 - Regulatory depreciation - May 2016, p.5-13
NER clause 6.5.5(b)(1) requires that “the schedules must depreciate using a profile that reflects the nature of the assets
or category of assets over the economic life of that asset or category of assets”.

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Section 11– Accelerated Depreciation of Retired Assets
each form part of the Line hardening outlined in sections 8.6. ACR replacements andsectionaliser replacements are under compatible equipment investments in section 8.7.
Step 2 – Estimate RAB value of identified asset class
AusNet Services has relied on data within its 2015 Repex Model30 to establish each asset
class’s share of the total RAB value. The Repex model contains Electricity Distribution systemassets including Network SCADA assets and does not contain IT or Non Network assets. The
proportion obtained from the Repex model for each asset class was then separately applied to
the 2015 opening RAB values31 (excluding assets not modelled in the Repex model, such as IT
assets) to derive estimated 2015 opening RAB values for each asset class.
In the case of surge arrestors and protection relays the respective shares of total RAB value
were determined using the current replacement unit rate multiplied by total volume multiplied byan average remaining life factor (average remaining life / standard life). This depreciatedreplacement value was then divided into the total depreciated replacement value for all asset
classes consistent with the approach used for the other assets identified in step 1 above. The
Repex model does not separately track surge arrestors or protection relay systems in zone
substations. Instead, they are either incorporated within an aggregated benchmark asset
category or allocated across multiple benchmark categories. Therefore this alternate approach
was used and is considered management’s best estimate of the 2015 opening RAB values.
Step 3 – Determine proportion of identified RAB value to be depreciated
The portion of the asset class that is to be included in the accelerated depreciation proposal iscalculated based on forecast replacement volumes included in this contingent projectapplication, as a share of the total volume of assets in each asset class as at January 2015.
The total volume of assets within the identified asset classes are obtained from the 2015 Repex
model. In the case of surge arrestors the total volume was taken from AusNet Services’ 2016
RIN in lieu of available data within the Repex model. As noted in step 2 above, surge arrestors
and protection relays are not captured in a single benchmark asset category within the Repex
model, rather they are spread across multiple categories.
Step 4 - Roll forward the estimated 2015 opening RAB values to 1 January 2019
Since the approach described above established the opening RAB values as at January 2015,
there is a requirement to roll forward the RAB values to 31 December 2020 to align with the endof the current regulatory period. AusNet Services has applied the AER’s standard nominal RAB
roll forward approach to establish the January 2019 opening RAB values32.
AusNet Services therefore proposes to accelerate depreciation over 2019 and 2020 in line withexpected timing of certain asset replacements to be undertaken at Mansfield (MSD) Zone
Substation and along three MSD feeders. To facilitate this in the Proposed Amended Post Tax
Revenue Model (“PTRM”) we have established a new asset class ‘Accelerated Depr - Distr
assets (Contingent Project 3)’. The calculations are provided in the amended RAB depreciation
model33 which is provided as a supporting attachment to this contingent project application.
In summary, AusNet Services’ proposed accelerated depreciation allowance for selected assets
in the current control period is $0.32 million ($Nominal) as shown in the table below.

30
312015 Repex Model owned and maintained by the Regulatory & Network Strategy team within AusNet Services.
Opening RAB values obtained from the AER Final Decision Roll Forward Model, May 2016.

32

Using forecast inflation consistent with the AER’s Amended Final Decision for 2016-20 period.

33

AusNet Services’ Amended RAB Depreciation model. The PTRM depreciation schedule for the opening RAB has been
updated accordingly.

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Section 11– Accelerated Depreciation of Retired Assets
Table 16

Proposed Accelerated Depreciation Allowance – Current Period ($m, nominal)

Accelerated
Depreciation

2016

2017

2018

2019

2020

Total

-

-

-

$0.16

$0.16

$0.32

Source: AusNet Services

In addition, AusNet Services proposes to accelerate a further $2.68 million ($Nominal) in thenext regulatory control period (2021-25) relating to assets replaced at Kalkallo (KLO), Benalla(BN), Lang Lang (LLG) and Sale (SLE).
The remaining value of these assets as at January 2021 has been calculated using theapproach outlined above, i.e., by establishing the 2015 estimated opening values and rolling
forward to January 2021 using a nominal RAB roll forward approach.
As shown in Table 17 below, the remaining RAB value shall be accelerated over the first two
years of the period (2021-22) in line with construction dates at these four sites. AusNet
Services will include this forecast of accelerated depreciation within its forthcoming 2021-25
Electricity Distribution Revenue Proposal.34
Table 17

Accelerated
Depreciation

34

Proposed Accelerated Depreciation Allowance – 2021-25 Period ($m, nominal)
2021

2022

2023

2024

2025

Total

$1.34

$1.34

-

-

-

$2.68

In accordance with AusNet Services’ 2021-25 Electricity Distribution Revenue Proposal - Regulatory Depreciation chapter

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Section 12 – Incremental revenue requirement

12 Incremental revenue requirement
12.1 Introduction
This section presents information on the incremental revenue requirement of the contingent
project described in this application. We have used the post-tax building block approach
outlined in NER 6.5.4, and the AER’s post-tax revenue model to calculate the incremental
revenue requirement. Information that explains and substantiates the forecast incremental
capital and operating expenditure has been set out in sections 8 and 9.
The building block formula applied in each year of the regulatory control period is:MAR=

return on capital + return of capital + opex + revenue adjustments + tax=(WACC x RAB) + D + opex + revenue adjustments + tax

MAR=

Maximum allowed revenue

WACC

=

Post tax nominal weighted average cost of capital

RAB=

Regulatory Asset Base

D
RAB)

=

Economic depreciation (nominal depreciation minus indexation of the

Opex

=

Operating and maintenance expenditure

where:

Revenue adjustments = efficiency benefit sharing scheme carry-overs, forecast DMIA, 2010
S-factor scheme close out and shared asset adjustments
Tax=

Cost of corporate income tax of the regulated business

The sections below set out further information on each building block component of theincremental revenue requirement. Details regarding the total incremental revenue allowanceand the amended revenue determination to enable recovery of the contingent project costs areprovided at the conclusion of this section.

12.2 Regulated asset base and depreciation
The forecast RAB in relation to the contingent project is set out in the table below. These
values incorporate the capital expenditure plans set out in section 1, and the forecast
depreciation over the period.

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Section 12 – Incremental revenue requirement
Table 18

Contingent Project Regulatory Asset Base ($m, nominal)
2016

2017

2018

2019

2020

Contingent project Opening RAB

-

0.5

0.5

0.5

11.2

Contingent project capital
35
expenditure

0.5

-

-

10.6

36.7

CPI indexation on opening RAB

-

0.0

0.0

0.0

0.3

Contingent project depreciation

-

-0.0

-0.0

0.1

-0.4

Contingent project Closing RAB

0.5

0.5

0.5

11.2

47.9

Source: AusNet Services PTRM.

The regulatory depreciation in relation to this contingent project has been calculated using thestraight-line depreciation method and the standard asset lives approved by the AER in its final
decision for the 2016-20 regulatory period. Full details of this calculation are provided in the
updated PTRM which is submitted as part of this contingent project application.
For completeness, the table below shows the derivation of the regulatory asset base (RAB) for
the 2016-20 period, sourced from the AER’s Final Determination PTRM model and updated forthe 2019 cost of debt in accordance with the Final Determination WACC requirements andTranches 1 and 2 of this REFCL Program.
Table 19

AER’s Final Decision Regulatory Asset Base 2016-20 ($m, nominal)
2016

2017

2018

2019

2020

Opening RAB

3,442.1

3,685.3

4,025.4

4,338.0

4,674.7

Capital expenditure

346.3

427.7

405.6

433.3

390.8

CPI indexation on opening RAB

80.9

86.6

94.6

101.9

109.8

Straight-line depreciation-183.9-174.2-187.5-198.6-215.3

Closing RAB

3,685.3

4,025.4

4,338.0

4,674.7

4,960.0

Source: AusNet Services PTRM.

Table 20 below shows the amended RAB for the 2016-20 period, which reflects the summationof the values set out in Table 18 and Table 19.

35

Note: the capital expenditure reported in 2016 reflects the change in equity raising costs over the regulatory period.

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Section 12 – Incremental revenue requirement
Table 20

AusNet Services’ Amended Regulatory Asset Base ($m, nominal)
2016

2017

2018

2019

2020

Amended Opening RAB

3,442.1

3,685.8

4,025.8

4,338.5

4,685.9

Amended Capital expenditure

346.7

427.7

405.6

444.0

427.5

CPI indexation on opening RAB

80.9

86.6

94.6

101.9

110.1

Amended Straight-line depreciation-183.9-174.2-187.5-198.5-215.7

Amended Closing RAB

3,685.8

4,025.8

4,338.5

4,685.9

5,007.9

Source: AusNet Services PTRM.

12.3 Return on capital
The return on capital in relation to the contingent project has been calculated by applying the
AER’s estimated post-tax nominal vanilla WACC to the regulatory asset base, in accordancewith the AER’s 2016-2020 EDPR Final Decision. This calculation is shown in the table below.
Table 21Return on capital for contingent project, 2016-20 ($m, nominal)

Contingent project RAB for revenue
calculation purposes
WACC (percent per annum)36
Contingent project return on capital

2016

2017

2018

2019

2020

-

0.5

0.5

0.5

11.2

6.31%

6.27%

6.24%

6.18%

6.18%

-

0.0

0.0

0.0

0.7

Source: AusNet Services PTRM.

For completeness, Table 22 below shows the return on capital for the 2016-20 period, as set
out in the AER’s Final Determination, updated to include its decision on Tranches 1 and 2 of the
REFCL contingent project application and updates to the annual WACC allowance.
Table 22

AER’s Final Decision Return on capital, 2016-20 ($m, nominal)
2016

2017

2018

2019

2020

RAB for revenue calculation purposes

3,442.1

3,685.3

4,025.4

4,338.0

4,674.7

WACC (percent per annum)37

6.31%

6.27%

6.24%

6.18%

6.18%

Return on capital

217.3

230.9

251.2

268.2

289.0

Source: AusNet Services PTRM.

Table 23 below shows the amended return on capital for the 2016-20 period, which reflects thesummation of the values set out in Table 21 and Table 22.

36
37

Updated annually for return on debt.
Updated annually for return on debt.

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Section 12 – Incremental revenue requirement
Table 23

AusNet Services’ Amended return on capital, 2016-20 ($m, nominal)
2016

2017

2018

2019

2020

Amended RAB for revenue calculation
purposes

3,442.1

3,685.8

4,025.8

4,338.5

4,685.9

WACC (percent per annum)38

6.31%

6.27%

6.24%

6.18%

6.18%

Amended return on capital

217.3

230.9

251.2

268.2

289.7

Source: AusNet Services PTRM.

12.4 Tax allowance
The calculation of estimated corporate income tax attributable to the contingent project has
been undertaken in accordance with the provisions set out in clause 6.5.3 of the NER. The
estimated tax allowance is shown in the table below.
Table 24

Estimated cost of corporate tax for contingent project, 2016-20 ($m, nominal)
2016

2017

2018

2019

2020

Tax payable

-

-0.0

-0.0

-0.1

-0.0

Less value of imputation credits

-

0.0

0.0

0.0

0.0

Net corporate income tax
allowance

-

-0.0

-0.0

-0.0

-0.0

Source: AusNet Services PTRM.

For completeness, the table below shows the corporate tax allowance for the 2016-20 period,
as set out in the AER’s Final Determination updated to include its decision on Tranches 1 and 2of the REFCL contingent project applications.
Table 25

AER’s Final Decision on corporate tax allowance, 2016-20 ($m, nominal)
2016

2017

2018

2019

2020

Tax payable

55.1

44.8

45.9

48.3

47.2

Less value of imputation credits

-22.0

-17.9

-18.4

-19.3

-18.9

Net corporate income tax
allowance

33.0

26.9

27.6

29.0

28.3

Source: AusNet Services PTRM.

Table 26 below shows the amended tax allowance for the 2016-20 period, which reflects thesummation of the values set out in Table 24 and Table 25.

38

Updated annually for return on debt.

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Section 12 – Incremental revenue requirement
Table 26

AusNet Services’ Amended corporate tax allowance, 2016-20 ($m, nominal)
2016

2017

2018

2019

2020

Tax payable

55.1

44.8

45.9

48.2

47.2

Less value of imputation credits

-22.0

-17.9

-18.4

-19.3

-18.9

Amended net corporate income
tax allowance

33.0

26.9

27.5

28.9

28.3

Source: AusNet Services PTRM.

12.5 Incremental operating expenditure
AusNet Services’ operating expenditure forecasts for this contingent project are described in
section 1 of this proposal.
The table below shows the operating expenditure allowance for the 2016-20 period set out in
the AER’s Final Determination updated to include its decision on Tranche 1 of the REFCL CPA.
Also shown is the amended operating expenditure allowance for the 2016 period, which is thesum of the AER’s Final Determination allowance and the incremental operating expenditure forthe contingent project.
Table 27

Amended operating expenditure allowance, 2016-20 ($m, nominal)
2016

2017

2018

2019

2020

Contingent project operating expenditure

-

-

-

-

0.04

Opex allowance, AER Final Determination(updated)

230.4

240.2

251.8

262.7

275.1

Revised operating expenditure
allowance

230.4

240.2

251.8

262.7

275.14

Source: AusNet Services

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Section 12 – Incremental revenue requirement

12.6 Incremental revenue allowance
The table below shows the building block elements that comprise the incremental revenue
requirement for the contingent project over the 2016-20 period.
Table 28

Contingent project revenue requirement, 2016-20 ($m, nominal)
2016

2017

2018

2019

2020

Total

Return on capital

-

0.0

0.0

0.0

0.7

0.8

Regulatory depreciation

-

-0.0

-0.0

-0.1

0.1

0.0

Operating expenditure

-

0.0

0.0

0.0

0.0

0.0

Revenue adjustments

-

-

-

-

-

-

Net tax allowance

-

-0.0

-0.0

-0.0

-0.0

-0.1

Annual revenue requirement(unsmoothed)

-

0.0

0.0

-0.1

0.8

0.8

Annual revenue requirement(smoothed)

-

-

-

-

0.8

0.8

Source: AusNet Services

12.7 Revised revenue determination
Table 29 below shows the revenue allowance and X factors for the 2016-20 period sourced
from the AER’s Final Determination and updated to include its decision on Tranche 1 and 2 of
the REFCL contingent project application. Accordingly, the 2020 X Factor has been updated todetermine the smoothed revenue requirement shown in Table 30.

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Section 12 – Incremental revenue requirement
Table 29

AER Final Determination revenue requirement, 2016-20 ($m, nominal)
2016

2017

2018

2019

2020

Total

Return on capital

217.3

230.9

251.2

268.2

289.0

1,256.6

Regulatory depreciation

103.0

87.6

92.9

96.7

105.5

485.7

Operating expenditure

230.4

240.2

251.8

262.7

275.1

1,260.1

Revenue adjustments

5.3

-6.4

-3.6

16.2

0.1

11.6

Net tax allowance

33.0

26.9

27.6

29.0

28.3

144.8

Annual revenue requirement(unsmoothed)

589.0

579.3

619.8

672.7

698.0

3,158.7

Annual expected revenue(smoothed)

586.0

597.9

623.0

656.9

692.6

3,156.4

8.27%

0.30%

-1.84%-3.01%-3.01%

39

X factor

39

The X factors from 2018 to 2020 will be revised to reflect the annual return on debt update. Under the CPI–X framework, theX factor measures the real rate of change in annual expected revenue from one year to the next.

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Section 12 – Incremental revenue requirement
The table below shows our amended revenue requirement, which includes the contingent
project Tranche 3 revenue requirement.
Table 30

Amended revenue requirement, 2016-20 ($m, nominal)
2016

2017

2018

2019

2020

Total

Return on capital

217.3

230.9

251.2

268.2

289.7

1,257.4

Regulatory depreciation

103.0

87.6

92.9

96.6

105.6

485.7

Operating expenditure

230.4

240.2

251.8

262.7

275.1

1,260.1

Revenue adjustments

5.3

-6.4

-3.6

16.2

0.1

11.6

Net tax allowance

33.0

26.9

27.5

28.9

28.3

144.7

Annual revenue requirement(unsmoothed)

589.0

579.3

619.8

672.6

698.8

3,159.4

Annual expected revenue(smoothed)

586.0

597.9

623.0

656.9

693.3

3,157.1

8.27%

0.30%

-1.84%-3.01%-3.13%

40

X factor

40

The X factors from 2018 to 2020 will be revised to reflect the annual return on debt update. Under the CPI–X framework, theX factor measures the real rate of change in annual expected revenue from one year to the next.

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Section 13 – List of supporting documents

13 List of supporting documents
The following documents are provided as attachments to this document.
Table 31

Attachment List

Attachment

Title

Attachment 1

REF 70-23 REFCL Program - MSD Functional Scope v1.0

Attachment 2

REF 70-24 REFCL Program - LLG Functional Scope v1.0

Attachment 3

REF 70-25 REFCL Program - SLE Functional Scope v1.0

Attachment 4

REF 70-26 REFCL Program - BN Functional Scope v1.0

Attachment 5

REF 70-27 REFCL Program - KLO Functional Scope v1.0

Attachment 6

REFCL Program - Equipment Building Block Functional Description Issue 3

Attachment 7

REFCL Program Network Balancing Strategy Issue 2

Attachment 8

REF 20-10 REFCL Program Primary Assets Hardening Strategy Issue 1

Attachment 9

REF 20-07 REFCL Program Line Hardening Strategy v0.4 - PUBLIC

Attachment 10

REF 20-08 Compatible Equipment Automatic Circuit Recloser Strategy
Issue 2

Attachment 11

REF 20-09 REFCL Program Voltage Regulator Strategy Issue 2

Attachment 12

REF 20-13 REFCL Program Distribution Feeder Automation Strategy Issue
1

Attachment 13

Operating Modes Policy - REF 30-16 - PUBLIC

Attachment 14

REF 30-04 REFCL Program - Arc Suppression Coil Sizing Policy Issue 3

Attachment 15

REF 30-10 REFCL Program HV Customer Policy Issue 3 - PUBLIC

Attachment 16

REF 70-22 REFCL Program - Cost Estimating and Program Delivery v3.0 PUBLIC

Attachment 17

BFM 10-01 BFM Plan Distribution v25 - PUBLIC

Attachment 18

REF 70-28 REFCL Program T3 HV Customer Engagement Overview v1.0 PUBLIC

Attachment 19

REF 70-29 REFCL Program T3 HV Customers v1.0 - CONFIDENTIAL

Attachment 20

Capex Unit Rate Analysis - PUBLIC

Attachment 21

KLO overview presentation - CONFIDENTIAL

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Section 13 – List of supporting documents

Table 32

Model List

Attachment

Title

Attachment 22

AST Contingent Project 3 Total Cost Model - CONFIDENTIAL

Attachment 23

AER - AST 2019 debt update PTRM - REFCL T3_CONFIDENTIAL

Attachment 24

AST Distribution Amended Depreciation model - Public

Attachment 25

T3 HV customer model - CONFIDENTIAL

Attachment 26

Cables - Condition and Criticality in Sections - CONFIDENTIAL

Attachment 27

DFA reliability model - CONFIDENTIAL

Attachment 28

Capacitance Forecast model - CONFIDENTIAL

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Section 14 – Compliance Checklist

14 Compliance Checklist
This document and the accompanying supporting documents provide the following informationin accordance with the National Electricity Rules41:
Table 33 Compliance Checklist
Rule provision

Requirement

Relevant section

Part C: Building block determinations for standard control services
6.6A

Contingent Projects

6.6A.2(a)Subject to paragraph (b), a Distribution Network Service
Provider may, during a regulatory control period, apply to
the AER to amend a distribution determination thatapplies to that Distribution Network Service Provider
where a trigger event for a contingent project in relation tothat distribution determination has occurred.

Noted

6.6A.2(b)An application referred to in paragraph (a):Noted

6.6A.2(b)(1)

must not be made within 90 business days prior to theend of a regulatory year;

Noted

6.6A.2(b)(2)subject to subparagraph (1), must be made as soon aspracticable after the occurrence of the trigger event;

Noted

6.6A.2(b)(3)must contain the following information:

Noted

6.6A.2(b)(3)(i)an explanation that substantiates the occurrence of thetrigger event;

Section 3.1

6.6A.2(b)(3)(ii)

a forecast of the total capital expenditure for thecontingent project;

Section 8.10

6.6A.2(b)(3)(ii)

a forecast of the capital and incremental operating
expenditure, for each remaining regulatory year which theDistribution Network Service Provider considers is
reasonably required for the purpose of undertaking thecontingent project;

Section 1

6.6A.2(b)(3)(iv)

how the forecast of the total capital expenditure for thecontingent project meets the threshold as referred to inclause 6.6A.1(b)(2)(iii);

Section 3.2

6.6A.2(b)(3)(v)

the intended date for commencing the contingent project(which must be during the regulatory control period);

Section 6

41

NER, clause 6.6A.2(b).

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Section 14 – Compliance Checklist

Rule provision

Requirement

Relevant section

Part C: Building block determinations for standard control services
6.6A

Contingent Projects

6.6A.2(b)(3)(vi)

the anticipated date for completing the contingent project(which may be after the end of the regulatory control
period);Section 8.10

6.6A.2(b)(3)(vii) an estimate of the incremental revenue which theDistribution Network Service Provider considers is likely
to be required to be earned in each remaining regulatory
year of the regulatory control period as a result of thecontingent project being undertaken as described insubparagraph (iii); andSection 12

6.6A.2(b)(4)the estimate referred to in subparagraph (3)(vii) must be
calculated:

6.6A.2(b)(4)(i)in accordance with the requirements of the post-tax
revenue model referred to in clause 6.4.1;

Section 12

6.6A.2(b)(4)(ii)

in accordance with the requirements of the roll forward
model referred to in clause 6.5.1(b);Section 12

6.6A.2(b)(4)(iii)

using the allowed rate of return for that Distribution
Network Service Provider for the regulatory control period
as determined in accordance with clause 6.5.2;

Section 12

6.6A.2(b)(4)(iv)

in accordance with the requirements for depreciationreferred to in clause 6.5.5; andSection 12

6.6A.2(b)(4)(v)on the basis of the capital expenditure and incremental
operating expenditure referred to in subparagraph (3)(iii).

Section 12

6.6A.2(i)A Distribution Network Service Provider must provide the
AER with such additional information as the AER requires
for the purpose of making a decision on an application
made by that Distribution Network Service Provider underparagraph (a) within the time specified by the AER in a
notice provided to the Distribution Network Service
Provider by the AER for that purpose.

Noted

Source: AusNet Services

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Noted