2006 Electricity Distribution Price Revie · 4.5.2 Comparison with NIEIR Forecast ... (MDM, excluding IMRO) ... 2006 Electricity Distribution Price Review Submission

October 2004

2006 Electricity DistributionPrice Review

Submission By

AGL Electricity LimitedABN 82 064 651 083

2006 Electricity Distribution Price Review Submission


Table Of Contents

1. OVERVIEW...................................................................................................................................1

1.1 INTRODUCTION.............................................................................................................................11.1.1 Basis for the Price Review and Submission........................................................................11.1.2 AGLE Area .........................................................................................................................2

1.2 KEY ISSUES ..................................................................................................................................21.2.1 Electricity Safety Regulations.............................................................................................31.2.2 Interval Meter Rollout ........................................................................................................61.2.3 Total Employment Costs .....................................................................................................61.2.4 Road Management Act........................................................................................................71.2.5 Ring-fencing Guidelines .....................................................................................................7

2. SUMMARY OF OUTCOMES .....................................................................................................9

2.1 RELIABILITY AND SERVICE LEVELS .............................................................................................92.2 CUSTOMER, ENERGY AND DEMAND FORECASTS .........................................................................92.3 CAPITAL EXPENDITURE................................................................................................................92.4 OPERATING AND MAINTENANCE EXPENDITURE.........................................................................102.5 EFFICIENCY CARRYOVER MECHANISM ......................................................................................102.6 REGULATORY DEPRECIATION ....................................................................................................112.7 REGULATORY ASSET BASE ........................................................................................................112.8 RETURN ON CAPITAL .................................................................................................................122.9 TAX LIABILITY...........................................................................................................................122.10 REQUIRED REVENUE ..................................................................................................................132.11 PRICE CONTROLS AND TARIFFS..................................................................................................142.12 EXCLUDED SERVICE...................................................................................................................142.13 METERING..................................................................................................................................14

3. SERVICE LEVELS AND SERVICE INCENTIVE MECHANISM.......................................17

3.1 INTRODUCTION...........................................................................................................................173.2 PAST AND CURRENT LEVELS OF RELIABILITY............................................................................173.3 RELIABILITY IMPROVEMENT ......................................................................................................18

3.3.1 Targeted Expenditure .......................................................................................................183.3.2 Momentary Interruptions..................................................................................................19

3.4 RELIABILITY TARGETS ...............................................................................................................203.5 S-FACTOR SCHEME ....................................................................................................................20

3.5.1 Reliability Measures .........................................................................................................203.5.2 Customer Service Measures .............................................................................................203.5.3 Targets for the S-Factor Scheme ......................................................................................213.5.4 Incentive Rates..................................................................................................................213.5.5 Exclusions.........................................................................................................................22

3.6 GUARANTEED SERVICE LEVEL PAYMENTS ................................................................................233.6.1 Repair of Streetlights ........................................................................................................243.6.2 Appointments ....................................................................................................................243.6.3 New Connections ..............................................................................................................243.6.4 Supply Restoration............................................................................................................243.6.5 Supply Reliability..............................................................................................................253.6.6 Payments to Large Customers ..........................................................................................25

3.7 REPORTING ................................................................................................................................253.7.1 National Regulatory Reporting Requirements..................................................................253.7.2 Thresholds for Low Reliability Feeders............................................................................263.7.3 Quality of Supply ..............................................................................................................263.7.4 Customer Service Complaints...........................................................................................27

4. CUSTOMER, ENERGY AND DEMAND FORECASTING...................................................29

4.1 INTRODUCTION...........................................................................................................................294.2 CUSTOMER CONNECTIONS .........................................................................................................30

4.2.1 Residential Connections ...................................................................................................304.2.2 Total Business Connections..............................................................................................31


4.2.3 Small Business Connections .............................................................................................314.2.4 Large Business Connections.............................................................................................32

4.3 CUSTOMER NUMBERS ................................................................................................................324.4 ENERGY CONSUMPTION .............................................................................................................334.5 NETWORK DEMAND ...................................................................................................................33

4.5.1 System Demand Forecast .................................................................................................344.5.1.1 Historical Peak Demands ....................................................................................................... 344.5.1.2 Known Load Changes ............................................................................................................ 344.5.1.3 Economic Trends/Planning Schemes ..................................................................................... 354.5.1.4 Temperature Sensitivity ......................................................................................................... 35

4.5.2 Comparison with NIEIR Forecast ....................................................................................364.6 CONTRACT DEMAND..................................................................................................................364.7 VERIFICATION OF FORECASTS....................................................................................................37

4.7.1 National Institute of Economic and Industrial Research..................................................374.7.2 Scope of Works for NIEIR.................................................................................................374.7.3 Verification of Forecasts ..................................................................................................37

5. CAPITAL EXPENDITURE REQUIREMENTS......................................................................39

5.1 INTRODUCTION...........................................................................................................................395.2 OVERALL FORECAST CAPITAL EXPENDITURE ............................................................................405.3 NETWORK RELATED CAPITAL EXPENDITURE.............................................................................40

5.3.1 Demand Related – Reinforcement ....................................................................................405.3.2 Demand Related – New Customer Connections ...............................................................445.3.3 Demand Related – Load Movement..................................................................................455.3.4 Non Demand Related – Reliability and Quality Maintained ............................................46

5.3.4.1 Pole Replacement and Reinstatement .................................................................................... 485.3.4.2 Overhead Service Replacement.............................................................................................. 495.3.4.3 Pole Top Replacement ........................................................................................................... 505.3.4.4 Communications/Protection Systems Replacement ............................................................... 525.3.4.5 Underground Cable Replacement .......................................................................................... 525.3.4.6 High Voltage Installation Replacement.................................................................................. 525.3.4.7 Zone Substation Equipment Replacement.............................................................................. 52

5.3.5 Non Demand Related – Reliability and Quality Improvements ........................................535.3.6 Non Demand Related – Environmental, Safety and Legal................................................545.3.7 Standard Metering (2004 and 2005 only).........................................................................575.3.8 SCADA/Network Control..................................................................................................57

5.4 NON NETWORK GENERAL - IT ...................................................................................................585.4.1 System Replacements ........................................................................................................59

5.4.1.1 Geographic Information System Update ................................................................................ 595.4.1.2 Document Management System Update ................................................................................ 605.4.1.3 Substation Utilisation and Profiling System Update .............................................................. 605.4.1.4 AutoCAD Updates ................................................................................................................. 605.4.1.5 Field Data Collection Hardware Replacements...................................................................... 605.4.1.6 Routine IT Expenditure.......................................................................................................... 605.4.1.7 Hardware Replacements (GIS, SUPS, SCADA).................................................................... 605.4.1.8 General IT expenditure .......................................................................................................... 605.4.1.9 SAP Update............................................................................................................................ 60

5.4.2 New System Developments ...............................................................................................615.4.2.1 Ring-fencing .......................................................................................................................... 615.4.2.2 Meter Data Management (MDM, excluding IMRO).............................................................. 615.4.2.3 MSATS Developments and Retailer of Last Resort............................................................... 615.4.2.4 B2B Developments ................................................................................................................ 625.4.2.5 FRC and Network Billing ...................................................................................................... 625.4.2.6 Standing Data Repository (SDR) ........................................................................................... 625.4.2.7 CIS Plus Trouble Order Retirement and Outage Management Implementation.................... 62

5.4.3 Business Improvement ......................................................................................................625.4.3.1 Mobile Works Management Implementation......................................................................... 635.4.3.2 Various SAP Modules............................................................................................................ 635.4.3.3 Others..................................................................................................................................... 63

5.4.4 System Modifications and Enhancements.........................................................................645.5 NON NETWORK GENERAL - OTHER............................................................................................645.6 LONG TERM CAPITAL FORECAST ...............................................................................................66

6. OPERATING AND MAINTENANCE EXPENDITURE REQUIREMENTS.......................69


6.1 INTRODUCTION...........................................................................................................................696.2 EXPENDITURE FOR 2001 TO 2004...............................................................................................706.3 BASE COSTS FOR 2006 AND 2010...............................................................................................70

6.3.1 Adjustment from 2004 to 2005..........................................................................................706.3.2 Rate of Change .................................................................................................................706.3.3 Costs due to Customer Growth.........................................................................................71

6.4 COST OF STEP CHANGES ............................................................................................................716.4.1 Road Management Act 2004.............................................................................................736.4.2 Electricity Demand Side Response ...................................................................................736.4.3 Head Office Relocation Cost ............................................................................................746.4.4 Additional Surge Compensation Claims...........................................................................746.4.5 Additional EWOV Cases...................................................................................................746.4.6 Inspection and Testing of Earthing Systems .....................................................................756.4.7 Inspection and Testing of Service Neutrals, Bonding and Materials................................756.4.8 Transformer Platform Heights .........................................................................................756.4.9 Vegetation Management ...................................................................................................766.4.10 Protection from Terrorist Attacks / Security Costs...........................................................766.4.11 Rectification of faulty XLPE cable....................................................................................766.4.12 OCEI audits ......................................................................................................................766.4.13 Commission Regulatory Audits.........................................................................................776.4.14 Additional Regulatory Reporting Costs ............................................................................776.4.15 Financial Report for 2009 Regulatory Financial Information .........................................776.4.16 Ring-fencing .....................................................................................................................786.4.17 Sponsorship and Marketing..............................................................................................786.4.18 Public Consultation ..........................................................................................................796.4.19 Total Employment Costs ...................................................................................................796.4.20 Apprentices .......................................................................................................................796.4.21 Gather and Provide Data on all Public Lighting Poles....................................................806.4.22 Mobile Computing Implementation ..................................................................................806.4.23 Outage Management, Market and Billing Systems...........................................................806.4.24 GSL Payments (Current and New) ...................................................................................81

6.5 TRANSMISSION RELATED CHARGES...........................................................................................816.5.1 VENCorp Charges............................................................................................................816.5.2 SPI PowerNet Connecting Fees........................................................................................826.5.3 Inter-Network Provider Distribution Service Charges/Revenue ......................................826.5.4 Payments to Embedded Generators..................................................................................82

6.6 EXECUTIVE REMUNERATION ......................................................................................................82

7. EFFICIENCY CARRYOVER MECHANISM .........................................................................85

7.1 INTRODUCTION...........................................................................................................................857.2 CALCULATION OF THE 2001 TO 2005 PERIOD EFFICIENCY CARRYOVER AMOUNT .....................85

7.2.1 Adjustment of Reinforcement/Augmentation Benchmark .................................................857.2.2 Adjustment of Customer Connection Benchmark .............................................................867.2.3 Adjustment of Operating Expenditure ..............................................................................867.2.4 Efficiency Carryover Amount for 2006 to 2010................................................................87

7.3 THE 2006 TO 2010 PERIOD EFFICIENCY CARRYOVER ................................................................877.3.1 Proposed Efficiency Carryover Mechanism .....................................................................877.3.2 Marginal Cost of Reinforcement/Augmentation ...............................................................877.3.3 Average Cost of Customer Connections ...........................................................................887.3.4 Marginal Operating Cost .................................................................................................88

8. COST OF CAPITAL FINANCING ...........................................................................................89

8.1 INTRODUCTION...........................................................................................................................898.2 OPENING VALUE OF THE REGULATED ASSET BASE ...................................................................89

8.2.1 Roll forward of asset base from 2000...............................................................................898.2.2 Capital Expenditure..........................................................................................................898.2.3 Customer Contribution .....................................................................................................908.2.4 Regulatory Depreciation ..................................................................................................908.2.5 Disposals ..........................................................................................................................90

8.3 RETURN OF CAPITAL (REGULATORY DEPRECIATION) ................................................................908.3.1 Method Applied.................................................................................................................91


8.3.2 Asset Lives ........................................................................................................................918.3.3 Accelerated Depreciation for Accumulation Meters ........................................................92

8.4 REGULATORY ASSET BASE 2006 TO 2010 .................................................................................928.5 RETURN ON CAPITAL .................................................................................................................93

8.5.1 Calculating WACC ...........................................................................................................938.5.2 Real Risk Free Rate ..........................................................................................................958.5.3 Market Risk Premium .......................................................................................................968.5.4 Equity Beta .......................................................................................................................968.5.5 Gearing.............................................................................................................................968.5.6 Debt Margin .....................................................................................................................96

8.6 TAXATION..................................................................................................................................988.6.1 Variables for Tax Calculation ..........................................................................................988.6.2 Franking Benefit ...............................................................................................................99

9. REVENUE REQUIREMENTS ................................................................................................101

10. PRICE CONTROLS AND TARIFFS......................................................................................103

10.1 INTRODUCTION.........................................................................................................................10310.2 PROPOSED PRICE PATH ............................................................................................................10310.3 CUSTOMER MOVEMENTS .........................................................................................................103

10.3.1 Re-Assignment of Customers to the Appropriate Tariffs ................................................10410.3.2 Movement to the multiple supply tariffs..........................................................................10410.3.3 Reassignment of residential customers resulting from the IMRO ..................................104

10.4 TARIFF PROPOSALS FOR THE 2006 TO 2010 PERIOD .................................................................10510.5 PASS THROUGH PROVISIONS ....................................................................................................105

10.5.1 Changes in Taxes............................................................................................................10510.5.2 Financial Failure of a Retailer.......................................................................................105

11. EXCLUDED SERVICES..........................................................................................................107

11.1 INTRODUCTION.........................................................................................................................10711.2 EXCLUDED SERVICES PROVIDED..............................................................................................107

11.2.1 Connections ....................................................................................................................10811.2.2 Public Lighting Operations, Maintenance, Repairs and Replacements .........................10811.2.3 Field Officer Visits..........................................................................................................10911.2.4 Service Truck Visit..........................................................................................................11011.2.5 Electrical Inspections .....................................................................................................11011.2.6 Metering .........................................................................................................................11111.2.7 Provision of a Switching Service ....................................................................................11211.2.8 Provision of Service Fuses..............................................................................................11211.2.9 Elective Underground Servicing.....................................................................................11211.2.10 Temporary Cover of Low Voltage mains ........................................................................11311.2.11 Service Cable Pulled Down by High Loads....................................................................11311.2.12 Standard Charge for Connection of Small Generators ..................................................11311.2.13 Metering Services (type 5 or 6) for Large First Tier Customers ....................................113

11.3 MOVEMENTS IN PRICES............................................................................................................11411.4 OTHER NON - REGULATED SERVICES ......................................................................................114

12. METERING SERVICES ..........................................................................................................115

12.1 INTRODUCTION.........................................................................................................................11512.2 AGLE INTERVAL METER ROLLOUT PLAN ...............................................................................11512.3 CAPITAL COSTS........................................................................................................................117

12.3.1 Excluded Services ...........................................................................................................11812.3.1.1 Meter Provision and Installation .......................................................................................... 11812.3.1.2 Overheads ............................................................................................................................ 118

12.3.2 Prescribed Services ........................................................................................................11812.3.2.1 Meter Provision & Installation ............................................................................................. 11812.3.2.2 Project Management............................................................................................................. 11912.3.2.3 Overheads ............................................................................................................................ 119

12.3.3 IT Capital Expenditure (Metering) .................................................................................12012.4 OPERATING COSTS ...................................................................................................................120

12.4.1 Meter Data Services .......................................................................................................121


12.4.2 Meter Reading ................................................................................................................12112.4.3 Meter Data Processing ...................................................................................................12112.4.4 Meter Maintenance.........................................................................................................12112.4.5 IT Maintenance & Support .............................................................................................121

12.5 REQUIRED REVENUE ................................................................................................................12112.6 METERING PRICES....................................................................................................................12212.7 INCENTIVE SCHEME .................................................................................................................123

APPENDICES ....................................................................................................................................125

APPENDIX A............................................................................................................................................Prescribed Services Revenue and Cost Data Templates – Current Regulatory Obligations.............

APPENDIX B............................................................................................................................................Prescribed Services Network Data Templates – Current Regulatory Obligations............................

APPENDIX C............................................................................................................................................Excluded Services and Other Activities Templates – Current Regulatory Obligations .....................

APPENDIX D............................................................................................................................................Distribution Tariff Templates – Current Regulatory Obligations .....................................................

APPENDIX E ............................................................................................................................................Prescribed Services Revenue and Cost Data Templates – Safety Management Scenario .................

APPENDIX F ............................................................................................................................................Prescribed Services Network Data Templates – Safety Management Scenario ................................

APPENDIX G............................................................................................................................................Excluded Services and Other Activities Templates – Safety Management Scenario .........................

APPENDIX H............................................................................................................................................Distribution Tariff Templates – Safety Management Scenario..........................................................

APPENDIX I .............................................................................................................................................Safety Management Scenario – Assumptions.....................................................................................

APPENDIX J .............................................................................................................................................Description of PB Associates Asset Replacement Model...................................................................

APPENDIX K............................................................................................................................................Weighted Average Cost of Capital, by KPMG...................................................................................

APPENDIX L ............................................................................................................................................A Framework for Quantifying Estimation Error in Regulatory WACC, by SFG Consulting ............

APPENDIX M...........................................................................................................................................The value of Imputation Franking Credits: Gamma, by SFG Consulting .........................................

APPENDIX N............................................................................................................................................Customer Re-assignments and Movements........................................................................................


2006 Electricity Distribution Price Review Submission - 1 -

1. Overview

1.1 Introduction

1.1.1 Basis for the Price Review and Submission

The Essential Services Commission (the Commission) licenses AGL ElectricityLimited (AGLE) to distribute electricity in accordance with the Distribution Licenceissued to AGLE (formerly Solaris Power1) on 3 October 1994 and last amended on29 April 2002.

The electricity distribution price path applicable from 1 January 2001, which wasdetermined by the (then) Office of the Regulator-General, expires on 31 December20052. The Commission is currently undertaking a review to set the price path fordistribution prices for the Victorian Distribution Businesses for the 2006 to 2010period.

As part of the process of reviewing and deciding new price controls, the Commissionissued the “Electricity Distribution Price Review 2006 – Final Framework andApproach: Volume 1, Guidance Paper” (Guidance Paper); and the “ElectricityDistribution Price Review 2006 – Final Framework and Approach: Volume 2,Information Requirements and Templates” (Templates Paper). The Commission alsoprovided a set of Templates for AGLE to complete.

In the Guidance Paper, the Commission has invited the distributors to submit theirprice-service proposals3:

“A key feature of that consultation process is an invitation to distributors tosubmit to the Commission consolidated price service proposals. The priceservice proposals provide the distributors with an opportunity to lay out a planfor consideration by the Commission and stakeholders on how investment intheir distribution networks should be undertaken to meet customer demandsand technical and safety requirements, and how the costs of this investmentwill be recovered through the distribution tariffs they charge customers forusing the network.”

Subject to the matters raised in this submission, the information provided by AGLE,including forecast capital, operating and maintenance costs, has been prepared onthe assumptions that current relevant technical standards and electricity industrypractice will continue to apply during the forecast period.

The information and projections contained in this Submission have been certified bytwo Directors of AGLE, as representing a true and fair view of the current positionand future financial and operating performance of AGLE for the 2006 to 2010 period.

Unless otherwise stated, all dollar amounts are in 2004 dollars.

1 Solaris Power changed its name to AGL Electricity in 1998 and to AGL Electricity Limited in 1999.2 Office of the Regulator-General (2000) “Electricity Distribution Price Determination 2001-05 –Volume II – Price Controls” page v.3 The Guidance Paper page 8.


1.1.2 AGLE Area

AGLE’s distribution network area covers approximately 950 square kilometres of thenorth western area of greater Melbourne. The area includes the city’s internationalairport, major transport routes and areas of residential and industrial growth.

1.2 Key Issues

There are a number of issues that will impact the operations of AGLE, causing it toincur additional costs in the 2006 to 2010 period. These are:

• Electricity Safety Regulations;• Interval Meter Rollout;• Employment costs;• Road Management Act; and• Ring-fencing Guidelines.

Each of these matters is discussed below and the impacts have been included in thisSubmission.

•

CRAIGIEBURN

•

FENTONHILL

•SUNBURY

• DIGGERS REST

• SYDENHAM

•BROADMEADOWS

•

ESSENDON

• COBURG

• PRESTON

• HEIDELBERG

•

FOOTSCRAY

• WILLIAMSTOWN


1.2.1 Electricity Safety Regulations

The standards to which the electricity network must be constructed, operated andmaintained are contained in a number of Acts, codes and regulations including:

• Electricity Safety Act 1998 (Vic);• Electricity Safety (Network Assets) Regulations 1999;• Electricity Safety (Electric Line Clearance) Regulations 1999; and• Code of Practice for Electric Line Clearance (Vegetation) 1999.

The Electricity Safety (Network Assets) Regulations 1999 and the Electricity Safety(Electric Line Clearance) Regulations 1999 (the Safety Regulations) both came intoeffect on 31 December 1999. The Office of the Chief Electrical Inspector (OCEI)administers the Safety Regulations.

With the exception of the limited transitional provisions, the Safety Regulations applyequally to network assets installed before and after 31 December 1999.

The Electricity Safety (Network Assets) Regulations 1999 impose substantiallychanged obligations in a number of areas. A key change is to the minimum heightsof service lines over footpaths, driveways and elsewhere. Service lines constructedin compliance with the previous regulations are now non-compliant under the currentregulation and, accordingly would require reconstruction to achieve compliance.

The Electricity Safety (Electric Line Clearance) Regulations 1999 require electricitydistributors, including AGLE, to maintain a space of specified dimensions that is clearof vegetation around electric lines4. Industry practice has been to ensure that lines indesignated bushfire areas are clear of vegetation to the required dimensions duringeach bushfire season, and for other lines, cleared of vegetation to the specifieddimensions on a 2 yearly cycle.

As a consequence of these changes, significant elements of the distribution networkwould need substantial upgrading to meet all applicable regulations.

AGLE, along with the other Victorian distributors, has been working with the OCEI inan attempt to address some of the more costly aspects of these regulations sincethey came into effect. AGLE has applied to the OCEI for approval of an ElectricitySafety Management Scheme, pursuant to the Electricity Safety Act. Once thatscheme has received all of the necessary approvals (approval is required from theOCEI and the Minister prior to acceptance by the Governor-In-Council) then specificexemptions can be sought (again pursuant to the Electricity Safety Act) fromparticular regulations. The Act and the Safety Regulations make it clear that AGLE’scompliance obligation (under the present regulations) may only be altered byexemptions granted by the OCEI pursuant to that legislation.

AGLE has been advised that both the OCEI and the Minister have approved AGLE’sElectricity Safety Management Scheme and have prepared the way for acceptanceby the Governor-in-Council. This is a positive move and AGLE has alreadyapproached the OCEI to initiate the next phase in the process, which will involvesubmission by AGLE of detailed safety management plans and an application to theOCEI for exemptions.

4 Code of Practice for Electric Line Clearance (Vegetation) 1999 clause 3.1.1. This Code is a prescribedCode under the Electricity Safety (Electric Line Clearance) Regulations 1999.


AGLE believes that exemptions could be granted by the OCEI under the ElectricitySafety Management Scheme, now approved by the Minister, that would address thefollowing issues and could result in a significantly improved outcome for Victorianconsumers:

• Changes to the requirements for testing service neutrals, bonding and materials;• Changes to the retrospectivity of the regulations in respect of the height of aerial

service lines;• Changes to the requirements in respect of transformer platform heights;• Changes to the minimum distance between aerial lines and parts of tramway

systems;• Changes to the requirements in respect of vegetation clearing; and• Changes to the requirement for the inspection and testing of earthing systems.

Further details of AGLE’s proposals are set out in Appendix I.

Given the expectation that safety regulations (or their application to AGLE) maychange prior to the finalisation of this Distribution Price Review, and that suchchange may result in significant reductions in the costs that need to be incurred(compared to the costs that would otherwise apply to achieve compliance withcurrent safety regulations), AGLE has decided to adopt the following approach in thisSubmission:

• AGLE’s Submission is based on the cost of compliance with network safetyobligations that are contained in currently applicable regulations. This scenario isreferred to as the Current Regulatory Obligations. For clarity, this pricingproposal (supported by a complete data set, including a full set of Templates) hasbeen prepared on the basis that AGLE will incur all capital and operatingexpenditure necessary for its distribution network to comply with the ElectricitySafety Act 1998, the Electricity Safety (Network Assets) Regulations 1999, andthe Electricity Safety (Electric Line Clearance) Regulations 1999 as they currentlyapply to AGLE. AGLE notes that if there are no legislative changes orexemptions to AGLE’s regulatory obligations (as discussed earlier in this section)prior to finalisation of the Distribution Price Review, then the only relevant part ofthis Submission is that set out under Current Regulatory Obligations.

• AGLE’s Submission also includes a scenario, which may apply through thegranting of exemptions under the Electricity Safety Management Schemeapproved by the Minister. AGLE believes this scenario (referred to as the “SafetyManagement Scenario”) represents an improved approach to the issue ofappropriate network safety regulations.

The proposed variations to current regulations that underpin this scenario arebased on a set of assumptions about the nature and form of obligations thatmight apply in the future. These assumptions are detailed in Appendix I(Assumptions) and will form the basis of AGLE’s application to the OCEI forexemptions. This application will be supported by Safety Management Plans.


• In the event that changes to regulatory obligations are implemented prior to thefinalisation of the Distribution Price Review, but those changes are not, in AGLE’sview, entirely consistent with the Assumptions, it then will be necessary for AGLEto lodge a supplementary Submission to reflect the impact on costs and prices ofthose actual changes to the current regulatory obligations. Under thesecircumstances, the only relevant part of this Submission is that set out under theCurrent Regulatory Obligations, as varied by any supplementary Submissionmade by AGLE at that later date.

• In the event that legislative changes or exemptions are implemented prior to thefinalisation of the Distribution Price Review such that the Assumptions arefulfilled, AGLE will then advise the Commission that, in its view, the Assumptionshave been met, and that the costs and pricing outcomes set out in thisSubmission under the Safety Management Scenario form the basis of AGLE’sSubmission for this Distribution Price Review.

Wherever relevant throughout this Submission, AGLE has provided cost and pricingoutcomes for both the Current Regulatory Obligations and the Safety ManagementScenario.

The cost of complying with the Safety Management Scenario and the CurrentRegulatory Obligations are shown in Table 1.1.

Table 1.1

COST OF COMPLYING WITH SAFETY REGULATIONS (IN ADDITION TO CURRENT LEVELS OFEXPENDITURE) ($000)

Safety Management Scenario Current Regulatory Obligations

Activities Capital Costs OperatingCosts Capital Costs Operating

CostsTesting of Earthing Systems 816 250 4,091 250Inspections and testing ofservice neutral 6,802 0 12,240 26,050

Overhead services minimumdistance between aerial linesand the ground

5,451 0 217,596 0

Supporting platform andequipment for a polemounted substation 2006

1,084 250 6,745 250

CMEN and Neutral EarthResistors 8,953 0 8,953 0

Clearance from Tramwaysoverhead conductors 0 0 20,672 0

Vegetation Management 0 0 0 800TOTAL 23,106 500 270,300 27,350


1.2.2 Interval Meter Rollout

In accordance with the decision from the Commission5, AGLE has included in thisSubmission the costs associated with a rollout of interval meters.

The costs include:

• The accelerated replacement of meters due to the Interval Meter Rollout (IMRO),including the cost of appropriate procedures to manage replacement of asbestosswitchboards and carrying out other works on the customers’ premises whichwould not have been required other than for the installation of the interval meter;

• Installation of the meters to new sites;• Installation of meters when existing meters are due for, or require replacement;• The additional cost of reading these meters over and above the cost of reading

existing current meters;• The cost of new meter reading equipment;• The cost of responding to an increased level of customer enquiries;• The cost of developing and enhancing systems to manage the increased level of

meter data; and• Project management and administration costs.

AGLE’s proposed rollout plan is detailed in Section 12.2. Details of the costs formetering services and the proposed metering charges are contained in Section 12 ofthis Submission.

The costs of metering are shown in Table 1.2.

Table 1.2

METERING COSTS ($000)2006 2007 2008 2009 2010 TOTAL

Capital Expenditure 13,177 7,762 9,416 19,633 20,492 70,480Operating and MaintenanceExpenditure 5,315 5,402 5,997 6,976 7,706 31,396

1.2.3 Total Employment Costs

The Australian electricity industry has undergone unprecedented reform over the lastdecade or so. This has included structural, cultural, and labour reforms and has ledto increases in efficiency, reduction in labour and other costs, and reduced pricesand improved services to customers.

The demand for skilled labour is being driven by significant increases in expenditureand the aging of the existing work force. These factors will place increased pressureon future labour costs and this is reflected in this submission.

AGLE is addressing this issue through a planned and systematic approach torecruitment of apprentice linesman and technical trainees. The ratio of apprenticesand trainees to the technical staff is currently 25%, with increased recruitment levelsplanned over the next five years.

5 Essential Services Commission (2004) “Mandatory Rollout of Interval Meters for Electricity Customers– Final Decision” July 2004.


1.2.4 Road Management Act

The Road Management Act 2004 (Vic) was passed by the Victorian Parliament inMay 2004. This Act, and its associated regulations, will cause an increase in costsfor AGLE when doing work on or near road reserves. The additional activities andthe associated cost of these activities are shown in Table 1.3.

Table 1.3

ROADS MANAGEMENT ACT COSTS ($000)2006 2007 2008 2009 2010 TOTAL

Capital CostsNotification Costs 8 8 8 8 8 40Permit Costs 59 60 62 63 64 308Additional construction costs due to moreexpensive design 813 832 850 869 888 4252

TOTAL Capital Costs 880 900 920 940 960 4600Operating and Maintenance CostsNotification - Fault and Emergency Work 25 23 23 23 25 119Notification - Pole and Line Inspection 190 174 174 175 192 905Notification - Other Maintenance Activities 15 13 13 13 15 69TOTAL Operating and Maintenance Costs 230 210 210 211 232 1,093

1.2.5 Ring-fencing Guidelines

The Commission released a Draft Decision and Draft Guideline on Ring-fencing inMarch 20046. The implementation of the Draft Decision and the Draft Guidelines willrequire AGLE to incur additional costs7 in relation to physical separation of staff,enhancements to existing IT systems, the review of a number of business processes,compliance auditing, and training. The costs to be incurred are shown in Table 1.4.

Table 1.4

IMPACT OF RING-FENCING DRAFT DECISION ($000)2006 2007 2008 2009 2010 TOTAL

Physical separation,training, process review 200 150 100 100 100 650

IT enhancements 100 50 0 0 0 150TOTAL 300 200 100 100 100 800

6 Essential Services Commission (2004) “Draft Decision: Ring-fencing in the Victorian ElectricityIndustry” March 2004.7 AGLE has based its costs in this area on complying with the Draft Guideline, which was released at thesame time as the Draft Decision, as the final guideline has not been released. If the final guideline isreleased in time, AGLE will provide updated costs for this area.



2. Summary of Outcomes

2.1 Reliability and Service Levels

AGLE believes that current levels of average reliability in AGLE’s network areacceptable and largely meet customers’ expectations. AGLE is proposingexpenditures on improving the level of reliability to customers on its network whocurrently experience reliability significantly below the average. This will involvespecific programs targeted at these areas, as well as increasing the focus of existingprograms, such as asset replacement and maintenance, on the assets supplyingthese areas. This work, while delivering improvements to the customers affected, willnot have any measurable impact on the overall average reliability of the network.AGLE proposes maintaining the current targets for 2005 as its target for each of theyears 2006 to 2010 (with the exception of the target for momentary interruptions,which was previously set incorrectly).

AGLE proposes that the Service Incentive Scheme remain in a similar form and of asimilar magnitude to that which currently applies, with some modifications to thereliability measures included in the scheme. AGLE does not propose the inclusion ofa customer service measure in the scheme at this stage, but rather a clarification ofthe definitions of appropriate measures, and the reporting of these measures infuture Comparative Performance Reports.

AGLE is also proposing changes to its Guaranteed Service Level scheme, includingreducing the threshold at which a payment is made for supply restoration from 12hours to 10 hours, and reducing the threshold for supply reliability payments in ruralareas from 15 outages to 11 outages in a calendar year.

2.2 Customer, Energy and Demand Forecasts

AGLE engaged the National Institute of Economic and Industry Research (NIEIR) toassist it in developing and to verify its forecasts. In particular, NIEIR providedforecasts of customer connections, customer numbers and energy. AGLE developedits own forecasts of network demand and contract demand, which have been verifiedby NIEIR.

AGLE is forecasting that customer numbers will increase at an average rate of 1.6%per annum and that energy through the network will increase at an average rate of0.4% per annum. AGLE forecasts that the average overall network demand growthwill be 2.3% per annum.

2.3 Capital Expenditure

AGLE has undertaken detailed forecasts of capital expenditure to meet networkgrowth and reliability forecasts. To support these forecasts, AGLE engaged PBAssociates to model the capital requirements for asset replacement.


AGLE will incur increases in capital costs during the 2006 to 2010 period due to:

• The need to modify elements of the network to achieve compliance withapplicable regulation, either under the Current Regulatory Obligations or theSafety Management Scenario discussed earlier;

• Replacement of assets that will come to the end of their life during the 2006to 2010 period;

• An increase in the required expenditure on IT; and• Increased total employment costs.

AGLE’s forecast of Capital Costs for the 2006 to 2010 period are shown in Table 2.1.

Table 2.1

FORECAST CAPITAL COSTS (EXCLUDING INTERVAL METER RELATED CAPITAL) ($000)2006 2007 2008 2009 2010 TOTAL

Safety Management Scenario 61,230 70,670 71,210 64,290 78,440 345,830Current Regulatory Obligations 109,940 120,420 122,010 116,170 131,410 599,950

2.4 Operating and Maintenance Expenditure

AGLE will incur additional operating and maintenance costs during the 2006 to 2010period that are not reflected in the 2004 forecast costs due to a number of factors,including:

• Meeting safety obligations, either under the Current Regulatory Obligations or theSafety Management Scenario;

• Meeting obligations under the Road Management Act;• Increased total employment costs;• Growth in customers to be served;• An increase in surge compensation claims from insurers;• An increase in the required expenditure on IT;• Proposed changes to the Guaranteed Service Level scheme;• Compliance with the expected ring-fencing guideline8; and• The training of additional apprentices.

AGLE’s forecast operating and maintenance costs for the period 2006 to 2010 areshown in Table 2.2.

Table 2.2

FORECAST OPERATING AND MAINTENANCE COSTS ($000)2006 2007 2008 2009 2010 TOTAL


2.5 Efficiency Carryover Mechanism

AGLE supports the continued inclusion of the Efficiency Carryover Mechanism.AGLE has identified the marginal costs of: reinforcement/augmentation; customerconnection; customer service; and billing and revenue collection, so that the 2001 to2005 benchmarks can be adjusted for actual growth.

8 The current Guideline is in draft form and was released in March 2004.


AGLE has also identified the forecast marginal costs for these items for the 2006 to2010 period to facilitate adjustment at the next Distribution Price Review.

The Efficiency Carryover amounts to be included in the required revenue for theSafety Management Scenario and the Current Regulatory Obligations are shown inTables 2.3A and 2.3B respectively.

Table 2.3A

EFFICIENCY CARRYOVER AMOUNTS - SAFETY MANAGEMENT SCENARIO ($M)2006 2007 2008 2008 2010

Operating Efficiency Carryover -2.5 -8.6 -2.0 0.6 0.0Capital Efficiency Carryover 9.5 6.6 4.3 1.9 0.0Total Efficiency Carryover 7.0 0.0 0.2 2.4 0.0

Table 2.3B

EFFICIENCY CARRYOVER AMOUNTS - CURRENT REGULATORY OBLIGATIONS ($M)2006 2007 2008 2008 2010

Operating Efficiency Carryover -2.5 -8.6 -2.0 0.6 0.0Capital Efficiency Carryover 9.4 6.5 4.3 1.8 0.0Total Efficiency Carryover 6.9 0.0 0.1 2.4 0.0

Note: The difference in Efficiency Carryover amounts between the Current Regulatory Obligations andthe Safety Management Scenario is due to variations in the average tax wedge caused by the differenttax liabilities.

2.6 Regulatory Depreciation

AGLE has elected to apply straight-line depreciation to its regulatory asset baseusing asset lives consistent with that used in the last period. The only exception tothis is that AGLE has elected to fully depreciate all accumulation meters when theyare replaced as part of the Interval Meter Rollout.

The forecast Regulatory Depreciation is shown in Table 2.4.

Table 2.4

FORECAST REGULATORY DEPRECIATION ($000)2006 2007 2008 2009 2010 TOTAL


2.7 Regulatory Asset Base

The opening value of the Regulatory Asset Base on 1 January 2006 is forecast to be$576.8 million.


The Regulatory Asset Base for the Safety Management Scenario and the CurrentRegulatory Obligations is shown in Tables 2.5A and 2.5B respectively.

Table 2.5A

REGULATORY ASSET BASE – SAFETY MANAGEMENT SCENARIO ($M)2006 2007 2008 2009 2010

Opening RAB 576.8 597.2 625.4 652.2 669.9Gross capital expenditure 61.2 70.7 71.2 64.3 78.4Customer contributions 4.5 4.7 4.4 4.6 5.4Disposals 0.0 0.0 0.0 0.0 0.0Regulatory depreciation 36.3 37.8 40.0 41.9 43.3Closing RAB 597.2 625.4 652.2 669.9 699.7Average RAB 587.0 611.3 638.8 661.1 684.8

Table 2.5B

REGULATORY ASSET BASE – CURRENT REGULATORY OBLIGATIONS ($M)2006 2007 2008 2009 2010


2.8 Return on Capital

AGLE has engaged KPMG and SFG Consulting to assist in the development of itsproposed Return on Capital. Based on market parameters as at 30 September 2004,the details for AGLE’s proposed Return on Capital are shown in Table 2.6.

Table 2.6

WACC VARIABLES (%)Variable Value / DistributionReal Risk Free Rate 2.79Market Risk Premium Mean: 6.0

Standard Deviation: 1.8Normal distribution

Equity Beta 0.9 – 1.0Uniform distribution

Gearing 60Debt Margin 1.51 – 1.71

Uniform distributionWACC (80th percentile of distribution) 6.7Gamma 30

2.9 Tax Liability

AGLE has forecast its Tax Liability, less the benefit of franking credits assuming agamma of 30%.


The forecast tax liability for the Safety Management Scenario and the CurrentRegulatory Obligations is shown in Tables 2.7A and 2.7B respectively.

Table 2.7A

FORECAST TAX LIABILITY – SAFETY MANAGEMENT SCENARIO ($M)2006 2007 2008 2009 2010 TOTAL

Cost of tax 9.2 10.3 11.3 12.5 13.6 56.9Franking benefit 2.8 3.1 3.4 3.7 4.1 17.1Forecast tax liability 6.5 7.2 7.9 8.7 9.5 39.9

Table 2.7B

FORECAST TAX LIABILITY – CURRENT REGULATORY OBLIGATIONS ($M)2006 2007 2008 2009 2010 TOTAL


2.10 Required Revenue

The Required Revenue for the Safety Management Scenario and the CurrentRegulatory Obligations is shown in Tables 2.8A and 2.8B respectively.

Table 2.8A

REVENUE REQUIREMENT – SAFETY MANAGEMENT SCENARIO ($M)2006 2007 2008 2009 2010 TOTAL

Return on assets 39.33 40.96 42.80 44.29 45.88 213.26Regulatory depreciation 36.25 37.83 40.03 41.95 43.33 199.39O&M expenditure 56.74 57.43 57.89 58.46 59.44 289.96Efficiency carryover 7.00 0.00 0.21 2.43 0.00 9.64Forecast tax liability 6.46 7.23 7.93 8.73 9.50 39.86Revenue Requirement 145.79 143.45 148.87 155.86 158.15 752.11

Table 2.8B

REVENUE REQUIREMENT - CURRENT REGULATORY OBLIGATIONS ($M)2006 2007 2008 2009 2010 TOTAL



2.11 Price Controls and Tariffs

The price path for distribution charges levied by AGLE was set by the 2001 ElectricityDistribution Price Determination9 (the 2001 Determination) and expires on 31December 2005. The Commission has commenced the review of distribution pricesin order to set the price path for the 2006 to 2010 period.

This Submission details AGLE’s forecasts of the costs it will incur for the 2006 to2010 period, which need to be recovered through revenue from distribution chargesduring this period. The price path will consist of two factors, P0 and X. The value P0represents the real change in average prices from 2005 to 2006, such that 2006average prices will not be greater than 2005 average prices multiplied by(1+CPI)(1-P0). Similarly, the value of X represents the real price reductions for eachyear within the period in relation to prices in the previous year.

The proposed price path for the Current Regulatory Obligations and the SafetyManagement Scenario is shown in Table 2.9.

Table 2.9

PRICE PATH (%)

SAFETY MANAGEMENT SCENARIO CURRENT REGULATORYOBLIGATIONS

Po -7.8 -16.9X -1.0 -2.0

Note: A negative value represents a price increase

AGLE has included in its proposed prices:

• The reassignment of customers whose load and connection characteristics aresuch that they should be on a different tariff, and where this reassignment wouldlead to a lower total network charge;

• To reset customers’ contract demand;• An increase in the number of customers who take up the AGLE multiple supply

tariffs; and• The reassignment of customers to time of use tariffs when an interval meter is

installed.

2.12 Excluded Service

AGLE is not proposing any additional excluded services nor any changes to thecurrently approved excluded service prices. AGLE is proposing that all excludedprices be adjusted each year for CPI so as to maintain the value of the current prices.AGLE’s forecasts of excluded services revenue incorporates this change.

2.13 Metering

In accordance with the Commission’s decision on an Interval Meter Rollout (IMRO),AGLE has planned the installation of interval meters. AGLE will continue to installaccumulation meters in 2006 and 2007 in accordance with this decision. Table 2.10shows the costs that AGLE will incur in metering.

9 Office of the Regulator-General, Victoria (2000) “Electricity Distribution Price Determination 2001-2005– Volume I and II” September 2000.


Table 2.10

METERING COSTS ($000)2006 2007 2008 2009 2010 TOTAL

Capital Expenditure 13,177 7,762 9,416 19,633 20,492 70,480Operating and MaintenanceExpenditure 5,315 5,402 5,997 6,976 7,706 31,396

From 2006, the cost recovery for basic metering will change from being included indistribution charges to being charged as a Monopoly Provided Ancillary Service, withits own asset base and required revenue. However, it is not possible to transfer theasset value of meters previously installed. Consequently, the metering asset basewill start at a value of zero at the commencement of 2006 and will increase as capitalexpenditure is incurred. This will result in metering prices that will increase for eachyear of the period.

AGLE is opposed to the inclusion of the Commission’s proposal for a one-sidedincentive mechanism in relation to the installation of interval meters that will penalisedistributors for delaying the installation of interval meters. This will impose anasymmetric risk that is not incorporated in the return on metering asset.



3. Service Levels and Service Incentive Mechanism

3.1 Introduction

The AGLE network is predominantly an overhead network. As such, the reliabilityperformance of the network is influenced by two types of factors:

• Internal Factors – those things that AGLE can control, such as assetreplacement, maintenance, network planning, network operation and investmentin reliability improvement programs; and

• External Factors – those things that are largely beyond the control of AGLE, suchas weather, vehicles colliding with poles, birds, and strong winds causing treesand debris to fall over lines.

In this Section, AGLE discusses:

• The strategy for targeting reliability improvement expenditure and its reliabilitytargets for the 2006 to 2010 period;

• The service incentive scheme for the 2006 to 2010 period;• Guaranteed service level payments; and• Proposed changes to reporting arrangements.

3.2 Past and Current Levels of Reliability

Over the 1998 to 2003 period, the reliability of the AGLE network has shown a trendof improvement, as shown in Graph 3.1. The average number of minutes that acustomer connected to the AGLE network was without supply in a year, as measuredby the System Average Interruption Duration Index (SAIDI), has reduced from 107minutes in 1998 to 85 minutes in 2003, an improvement of 20%.

Graph 3.1

While Graph 3.1 indicates a trend of improving reliability, it is possible for externalfactors to cause reliability to deteriorate in any one year, as occurred in 2001 and2003.

Total SAIDI

0.0

20.0

40.0

60.0

80.0

100.0

120.0

1998 1999 2000 2001 2002 2003

Years

Min

utes


3.3 Reliability Improvement

3.3.1 Targeted Expenditure

At the current level of reliability, the cost of further improving reliability broadly acrossthe AGLE network would be high, and the benefits to customers generally would bemarginal. For this reason, AGLE does not plan to invest to improve averagereliability. However, there are pockets of AGLE’s area where reliability is significantlybelow the average level and AGLE proposes to make moderate investments to bringsupply reliability for those areas up to a level closer to the system average.

There are 24 supply areas in AGLE’s area. The supply areas where the averageminutes-off-supply per customer were above 120 minutes per year for the years 2000to 2003 are:

2003 Coburg North (CN), North Heidelberg (NH), Newport (NT), St. Albans(SA), Sunbury (SBY), Tottenham (TH) and Yarraville Terminal Station(YTS);

2002 Airport West (AW), Broadmeadows (BD), Coburg North (CN), Sunbury(SBY) and (Thomastown) TT;

2001 Coburg North (CN), Footscray West (FW), Newport (NT), Somerton(ST), Sunbury (SBY), Thomastown (TT) and Tottenham (TH); and

2000 Broadmeadows (BD), North Heidelberg (NH), Sunbury (SBY).

AGLE’s approach to improving areas of poor reliability is to examine the assetperformance in detail and to identify the:

• Causes of unreliability;• Maintenance programs that have applied;• Age and condition of the assets; and• Loading of the asset.

Following this analysis, one or multiple actions can be taken to improveperformance. In some cases, a specific capital expenditure program is undertakento improve the reliability of the assets. In other cases, performance is improved bytargeting asset replacement programs, increasing capacity, or relieving the loadingon the affected assets.

AGLE proposes to improve reliability to customers in the areas of low reliability bytwo means. A small number of targeted projects will be undertaken, the costs ofwhich are shown in Table 3.1. These projects include:

• Installation of vermin protection on feeders;• Replacement of connectors on feeders; and• Replacement of surge diverters on feeders.

These projects will improve the reliability to customers in the areas of lower reliabilitybut will have no measurable impact on overall network reliability.


Table 3.1

NETWORK RELIABILITY IMPROVEMENT PROJECTS ($000)2006 2007 2008 2009 2010 TOTAL

Vermin proofing feeder 435 0 0 0 0 435Upgrade non-tension connectors 0 213 60 0 0 273Upgrade surge diverters 0 0 244 161 164 569TOTAL 435 213 304 161 164 1,277

Reliability will also be improved in these areas through targeted maintenance,replacement and enhancement of assets. These targeted programs are dealt with inmore details in other sections of this Submission and the expenditure is included inthe forecasts of maintenance expenditure, network reinforcements, and assetreplacement.

3.3.2 Momentary Interruptions

The target set for AGLE in the 2001 Price Determination for Momentary Interruptions,as measured by the Momentary Average Interruption Frequency Index (MAIFI) wasbased on limited information and thus, in AGLE’s view, was set incorrectly. Graph3.2 shows the actual MAIFI performance against this target.

Graph 3.2

The target set in 2000 for the 2001 to 2005 period did not adequately take intoaccount that AGLE proposed to increase the number of auto-reclose devices on itsnetwork during the period. This was done to reduce the number of sustainedinterruptions but had the effect of increasing the number of momentary interruptions.AGLE’s proposed target for MAIFI for 2006 to 2010 is shown in Table 3.2.

Momentary Average Interruption Frequency Index

0.000

0.200

0.400

0.600

0.800

1.000

1.200

1998 1999 2000 2001 2002 2003

Years

MAI

FI

MAIFI

Target


3.4 Reliability Targets

AGLE’s reliability targets for the 2006 to 2010 period are shown in Table 3.2. In mostcases, AGLE has adopted the 2005 target as the target for the 2006 to 2010 period.It should be noted that, as discussed previously, the proposed expenditure inimproving reliability to targeted areas will have no measurable impact on overallaverage network performance.

Table 3.2

RELIABILITY TARGETSMeasure 2005 Target Proposed Target 2006 - 2010UrbanPlanned SAIDI (minutes) 6 6Unplanned SAIDI (minutes) 73 73Unplanned SAIFI10 1.27 1.27MAIFI 0.40 0.80RuralPlanned SAIDI (minutes) 14 14Unplanned SAIDI (minutes) 113 113Unplanned SAIFI 2.25 2.25MAIFI 1.84 2.63

3.5 S-Factor Scheme

AGLE agrees with the inclusion of an appropriate Service Incentive (S-Factor)Scheme as part of the regulatory regime. AGLE proposes that the scheme for the2006 to 2010 period should be based on the existing scheme with someimprovements as detailed below.

3.5.1 Reliability Measures

AGLE accepts the Commission’s guidance on replacing CAIDI11 with SAIDI and theinclusion of MAIFI (with an appropriate MAIFI target as discussed in Section 3.3.2).

3.5.2 Customer Service Measures

The Commission has proposed the inclusion of a Customer Service Measure relatingto fault call centre response, such as the percentage of calls not answered withinthirty seconds. AGLE does not support such a move at this point in time.

The rate of calls to a fault call centre is very strongly influenced by outage eventssuch as storms. During a period when there are no major outages occurring on thenetwork, the rate of calls is relatively low. During these times, which is the majority ofthe time in AGLE’s area, response to calls is very high. However, during periods ofsignificant outage events the rate of calls increases many times and thus the rate atwhich calls are answered deteriorates.

The effect of averaging the responsiveness of the fault call centre over a whole yearis to give a result which is so heavily influenced by the effect of periods of outageevents that the measure is meaningless as an indicator of call centre response. Theresult will be more influenced by the number of outage events in a year, which isbeyond the control of AGLE, than by any action to deliver improved customerservice. 10 SAIFI – System Average Interruption Frequency Index.11 CAIDI – Customer Average Interruption Duration Index.


AGLE does not believe that it has sufficiently robust data over a long enough periodof time to be able to set a target with any confidence. It must be recognised that theinclusion of a measure in the S-Factor Scheme will mean that actual performanceagainst the target for that measure will have a revenue impact for AGLE.Consequently, it is essential that AGLE have confidence in the data that underlies thetargets in order to have confidence in the scheme itself.

A clear example of the potential danger of setting targets without robust data over aperiod of time can be seen in the previous targets for MAIFI. As discussed in Section3.3.2, the AGLE target for MAIFI set at the last Determination was not based onrobust information and was at a level significantly below what it should have been.Fortunately, MAIFI was not included in the current incentive scheme. However, if ithad been part of the scheme, AGLE would have suffered adverse financial impactdue to an inappropriately set target.

AGLE’s proposal in relation to fault call centre response is two fold. Firstly, AGLEproposes that the measure be split into two separate measures: call centre responseduring outage events and call centre response during other times. This wouldseparate the effects of the two periods and give a truer indication of the level ofservice.

Secondly, during this review, the definition and reporting framework for thesemeasures be clarified so that the actual performance can be included in futureComparative Performance Reports.

3.5.3 Targets for the S-Factor Scheme

AGLE’s proposed reliability targets for the S-Factor Scheme are the same as itsproposed reliability targets overall, as discussed in Section 3.4 and shown in Table3.2.

3.5.4 Incentive Rates

AGLE proposes that the potential revenue impact of the S-Factor Scheme for the2006 to 2010 period should be similar to the potential revenue impact of the schemethat applies for the current period. Consequently, AGLE proposes the following ratesfor each of the components of its scheme for the 2006 to 2010 period.

Table 3.3

S-FACTOR SCHEME RATES (%)Measure Actual 2001- 2005 Proposed 2006 - 2010UrbanPlanned SAIDI 0.0097 0.0097Unplanned SAIDI 0.0129Unplanned CAIDI 0.0357Unplanned SAIFI 0.0231 0.0219MAIFI 0.0022RuralPlanned SAIDI 0.0006 0.0006Unplanned SAIDI 0.0014Unplanned CAIDI 0.0039Unplanned SAIFI 0.0013 0.0012MAIFI 0.0001


It must be recognised that the S-Factor Scheme is a part of the regulatory regimeand business environment. In particular, the S-Factor Scheme operates inconjunction with the Efficiency Carryover Mechanism and Return on Capital to givethe appropriate incentives for distributors for investment. AGLE believes that anymove to change the potential impact of the scheme in isolation of other parts of theregime is inappropriate.

3.5.5 Exclusions

A necessary characteristic of the scheme is that the impact of events that are beyondthe control of the distributor are excluded. This matter relates to both the S-FactorScheme and the Guaranteed Service Level payments (see Section 3.6).

AGLE supports the retention of exclusions for the following events:

• Supply interruptions made at the request of a customer;• Supply interruptions caused by a failure of the shared transmission network; and• Supply interruptions caused by a failure of the transmission connection asset, but

only to the extent that the interruptions were not due to inadequate planning oftransmission connections.

The Commission also proposes an exclusion for the following type of event:

• Load shedding due to a shortfall in generation, but not where embeddedgeneration has been connected to provide network support.

AGLE supports the allowance of an exclusion for load shedding due to a shortfall ingeneration, but not the preclusion of embedded generation used for network support,in the criteria. AGLE is concerned that the Commission risks stifling the use ofembedded generation as network support by not allowing a shortfall of embeddedgeneration that is providing network support as grounds for an exclusion.

The Commission’s reason for precluding embedded generation is that the networksupport agreement between the distributor and the embedded generator should passthrough to the generator the financial consequences for the distributor of thegenerator not being able to provide support when required. It is AGLE’s experiencethat the risk of this exposure, given the operational characteristics of an embeddedgenerator, can be greater than the network support payments paid to the generator.

The current S-Factor Scheme excludes events, which are12:

“Widespread supply interruptions due to rare events which are notreasonably able to be foreseen, but only to the extend that thedistributor is not reasonably able to mitigate the impact of suchinterruptions on customers.”

The Commission proposes to replace the “rare event” criteria in this exclusion with aquantitative measure. AGLE supports this change and proposes the exclusion of anyevent that has a SAIDI impact above a certain level.

12 Office of the Regulator-General (2000) “Electricity Distribution Price Determination 2001-05 –Volume II – Price Controls” clause 2.3.11(e).


During the 2001 to 2003 period, the Commission approved five applications forexemptions based upon the “rare event” criteria. Furthermore, the Commission hasacknowledged the difficulty that the distributors faced in proving justification for the“rareness” of the event, that was the subject of other applications, due to the lack ofrobust external data. Thus it is reasonable to assume that under the currentexclusion criteria, a distributor is exposed to approximately one “rare” event everytwo years on average.

Table 3.4 shows the number of events that occurred on the AGLE network in the 11year period from July 1993 to July 2004 that exceeded certain levels of SAIDI.

Table 3.4

NUMBER OF EVENTS EXCEEDING SAIDI THRESHOLDS – JULY 1993 TO JUNE 2004SAIDI exceeded Caused by Storm Caused by Pole Fire Total

8 minutes 2 1 37 minutes 3 2 56 minutes 7 3 10

It can be seen that AGLE has experienced an event which exceeded a SAIDI ofseven minutes approximately once every two years. AGLE proposes that clause6.3.4 of the Electricity Distribution Code and Clause 2.3.11 (e) of the Price Controlsbe replaced with:

“Supply interruptions which are caused by any event or series of events andwhere the cumulative System Average Interruption Duration Index (SAIDI) forthe interruption is greater than or equal to seven minutes.”

3.6 Guaranteed Service Level Payments

AGLE is required under the Electricity Distribution Code13 (EDC) and other Codes tomake Guaranteed Service Level (GSL) payments to customers when AGLE fails tomeet certain levels of service. The Codes specify minimum thresholds and theminimum levels of payment. However, AGLE is able to make larger payments and/orimpose tighter service level thresholds.

AGLE is proposing changes to its current GSL’s for:

• New connections;• Appointments;• Supply restoration;• Supply reliability; and• Payments to customers consuming greater than 160MWh per annum.

AGLE believes that it is important to maintain consistency between the exclusionprovisions that relate to the Service Incentive Scheme and those that relate to theSupply Restoration and Supply Reliability GSL’s. AGLE’s comments and proposalsrelating to exclusions in Section 3.5 are also applicable to the exclusion provisions ofthe EDC.

AGLE’s current GSL’s and the proposed changes are described below. The costdetails are shown in Section 6.

13 Office of the Regulator-General (2002) “Electricity Distribution Code” January 2002.


3.6.1 Repair of Streetlights

The Public Lighting Code requires AGLE to make a payment of $10 if it does notrepair a public light within 2 days of it being reported14. AGLE currently pays $20under these circumstances.

AGLE proposes no change to its current GSL arrangement.

3.6.2 Appointments

The EDC requires AGLE to make a payment of $20 if it is more than 15 minutes latefor an appointment15. AGLE currently pays $40 in these circumstances. TheCommission proposes that appointments be based on a two hour window. AGLEaccepts the Commission’s proposal that appointments be made on the basis of a twohour window, and will adjust its GSL arrangements accordingly.

3.6.3 New Connections

The EDC requires AGLE to connect customers by the agreed date or within 20 daysafter the request for connection is made if no date is agreed16. If connection is notmade within this timeframe, AGLE is required to make a payment of $50 per day thatthe connection is late, up to a maximum of $250.

AGLE proposes offering two connection windows. Firstly, for the current fee, AGLEwill maintain its current connection window of 20 days. The current connection fee is$198 for a domestic connection. For a fee of 1.5 times the current connection fee,AGLE will offer a 10-day connection window. This increased charge would allowAGLE to meet the 10-day window through increasing the number of connectionsbeing made after business hours. AGLE will continue to pay a $50 GSL for each daythat it is late, up to a maximum of $250.

3.6.4 Supply Restoration

Under the EDC, AGLE is required to make a supply restoration payment of $80 to acustomer whose supply is not restored within 12 hours17. AGLE can apply to theCommission to be relieved of this requirement for certain events18.

These payments are almost exclusively as a result of an incident that causes a verylarge number of outages or significant damage to the network that takes an extendedperiod of time to rectify, during which a small number of customers are withoutsupply.

AGLE believes that a 12 hour restoration time is beyond the level of service thatcustomers in its area should expect and proposes to reduce this threshold to 10hours, such that AGLE will pay $80 to any customer whose supply is not restoredwithin 10 hours.

14 Office of the Regulator-General (2001) “Public Lighting Code” September 2001 clause 2.5.15 Office of the Regulator-General (2002) “Electricity Distribution Code” January 2002 clause 6.1.16 Ibid clause 2.2.17 Ibid clause 6.3.1.18 Ibid clause 6.3.3 and 6.3.4.


3.6.5 Supply Reliability

Under the EDC, AGLE is required to pay $80 to any rural customer who experiencesmore than 15 outages or any other customer who experiences more than 9 outagesin any calendar year19. The same exclusions apply for this GSL as for the SupplyRestoration GSL.

The customers in AGLE’s area that are supplied from feeders that are classified as‘short rural’ expect a higher level of reliability than rural customers elsewhere inVictoria. This is because they consider themselves to be ‘urban fringe’ rather thanrural. AGLE believes that, for these customers, more than 15 outages in a calendaryear is beyond the level of service that they expect.

AGLE proposes no change to the supply reliability GSL relating to urban customers,and to reduce the threshold for the payment of a supply reliability payment for ruralcustomers to more than 11 outages in a calendar year.

3.6.6 Payments to Large Customers

Currently, AGLE is only required to make supply reliability payments and supplyrestoration payments to customers consuming less than 160MWh per annum. TheCommission has proposed that this payment be extended to include all customers.

AGLE supports the extension of these payments to all customers except customerswho have a specific supply agreement with AGLE. Customers with specific supplyagreements are likely to have reliability provisions included in their agreement.

3.7 Reporting

The Commission has proposed a number of changes to the current reportingrequirements including:

• Aligning the reporting with the national regulatory reporting requirements;• Revision of the threshold for reporting low reliability feeders, and the inclusion of

a threshold for feeders with low reliability with respect to MAIFI;• The reporting of quality of supply data; and• The addition of a measure for complaints regarding customer service, particularly

relating to the provision of information required to transfer customers to a newretailer.

3.7.1 National Regulatory Reporting Requirements

The National Regulatory Reporting Requirements not only have additional items tobe reported but also extend the existing reporting items to further drill down intonetwork type, customer type and supply voltage level.

AGLE would require extra resources and upgrades to a number of informationsystems, such as CIS plus and GIS, in order to capture the detailed informationrequired.

19 Ibid 6.3.2.


AGLE believes the additional reporting requirements would only increase operationalcosts while adding minimal value to either customers or distributors.

The cost of moving to the National Regulatory Reporting framework has not beenincluded in this Submission.

3.7.2 Thresholds for Low Reliability Feeders

The Commission established the low reliability feeder benchmarks in 1999 for theaverage annual minutes-off-supply as shown in Table 3.5. The benchmark thresholdfor each category was set based on the analysis of the 1997 and 1998 averages ofthe individual feeder performance reports such that approximately 95% of Victoriancustomers can expect on average, that level of service, or better.

Analysis of the 2001 to 2003 AGLE individual feeder performance reports suggeststhat the threshold for urban feeders should be reduced to 260 minutes (a reduction of7%) and the same percentage reduction can apply to the short rural feeder threshold,which would become 660 minutes. These will maintain the original intent of settingthe benchmark threshold such that approximately 95% of Victorian customers canexpect, on average, that level of service or better.

Table 3.5

THRESHOLD FOR LOW RELIABILITY FEEDERS – SAIDI PLANNED AND UNPLANNED(MINUTES)

Feeder Category 2001 - 2005 Proposed 2006 - 2010Central business district 65 -Urban 280 260Short rural 710 660Long rural 1010 -

AGLE suggests that should a low reliability feeder benchmark be set with respect toMAIFI, the same principle should apply using the 2002 and 2003 averages of theindividual feeder performance reports. AGLE does not suggest the inclusion of 2001MAIFI data because the commissioning of the majority of AGLE’s auto-reclosersstarted in the second half of 2001, which shifted the MAIFI profile, as shown in Graph3.2.

Based on an analysis of the results of the 2002 and 2003 individual feederperformance, it is recommended that the MAIFI threshold for urban feeder be set at 3and for short rural feeder be set at 7. With these thresholds, approximately 95% ofVictorian customers can expect, on average, that level of service or better.

3.7.3 Quality of Supply

As required under the EDC20, AGLE has completed the installation of voltagemonitoring recording equipment at each zone substation and at the extremity of onefeeder from each zone substation.

20 EDC clause 4.2.6.


AGLE raised a number of matters for clarification in relation to the definition ofvoltage variation and the acceptable methods of monitoring, in 200221. AGLE urgesthe Commission to respond to these matters so that consistent and reliable data canbe reported.

3.7.4 Customer Service Complaints

AGLE supports the reporting of measures related to the level of service thatdistributors provide to retailers. In the development of the measures, however, it isimportant to take into account not only the benefit of the measures, but also theability of the distributor to accurately collect the data without incurring additionalcosts. AGLE looks forward to further discussions on this matter.

21 AGL Electricity Limited (2002) “Response by AGL Electricity Limited to Victorian ElectricityDistributors Information Specification – Service Performance” 22 February 2002.



4. CUSTOMER, ENERGY AND DEMAND FORECASTING

4.1 Introduction

Customer, Energy and Demand Forecasts play an important role in the Price Reviewprocess. Forecasts of network demand and customer connections drive much of theneed for investment in the network. Forecasts of customer numbers, energyconsumption and contract demand are key inputs to developing network tariffs.

The Commission has proposed that the distributors obtain independent verification oftheir quantity forecasts. As a starting point, the Commission will then assess thequality of the verification and the credentials of the party giving the verification, ratherthan the Commission developing its own forecasts22.

AGLE has engaged NIEIR to assist it in developing its forecasts and to provideverification. In relation to customer connections, customer numbers and energyconsumption, NIEIR has developed forecasts for AGLE, which AGLE has adopted.In relation to network demand and contract demand, AGLE has developed its ownforecasts, which have been verified by NIEIR.

AGLE notes the recent closure of Kodak Australia’s plant in Coburg. AGLE has notadjusted its forecast to take into account this event because NIEIR’s forecastincorporates some of the downside risks to AGLE in the manufacturing sector. Theclosure of Kodak Australia’s plant in Coburg supports AGLE’s view that it isappropriate to incorporate these risks in the forecasts.

The forecast for growth in customers, energy and contract Demand for the 2006 to2010 period are shown in Table 4.1.

Table 4.1

GROWTH IN CUSTOMERS, ENERGY AND CONTRACT DEMAND GROWTH (%)2006 2007 2008 2009 2010

Customers 1.6 1.7 1.5 1.5 1.8Energy 0.1 0.4 0.3 0.5 0.9Contract Demand* (6.4) 0.4 0.4 0.0 0.0

*The sharp decrease in 2006 is due to a re-set of customers contract demand at the start of 2006.

In this Section AGLE describes its forecasts for:

• Customer connections;• Customer numbers;• Energy consumption;• Network demand; and• Contract demand.

22 Guidance Paper, page 56.


4.2 Customer Connections

Customer connections represent new physical connections to the network thatrequire the investment of capital. AGLE has adopted the NIEIR forecast as itsforecast for customer connections.

In compiling the forecast for Customer Connections, NIEIR has considered a numberof factors including customer growth, connections growth, disconnections, historicalgrowth and customer churn. NIEIR has used a top-down model incorporatingnational, state and regional economic factors.

Table 4.2 shows the historical and forecast customer connections for the 2000 to2010 period.

Table 4.2

CUSTOMER CONNECTIONSYear Residential Total Business Small Business Large Business

2000 4,747 1,437 - -2001 5,464 1,753 - -2002 4,964 1,556 - -2003 4,583 2,230 - -2004 4,316 2,321 - -2005 4,266 2,083 2,054 292006 4,724 2,004 1,973 312007 5,017 1,846 1,815 312008 4,346 2,011 1,980 312009 4,305 2,239 2,208 312010 5,378 2,347 2,315 32

4.2.1 Residential Connections

The forecast for Residential Connections for the 2006 to 2010 period is 23,773.Graph 4.1 shows the number of residential connections.

Graph 4.1

Residential Connections

0

1,000

2,000

3,000

4,000

5,000

6,000

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010Years

Num

ber o

f Con

nect

ions

Historical Forecast


4.2.2 Total Business Connections

The forecast for Total Business Connections for the 2006 to 2010 period is 10,537.Graph 4.2 shows the number of Total Business Connections.

Graph 4.2

4.2.3 Small Business Connections

The total number of Small Business Connections for the period 2006 to 2010 is10,291. Graph 4.3 illustrates this.

Graph 4.3

Total Business Connections

0

500

1,000

1,500

2,000

2,500

2001 2002 2003 2004 2005 2006 2007 2008 2009 2010Years

Num

ber o

f Con

nect

ions

Historical Forecast

Small Business Connections

0

500

1,000

1,500

2,000

2,500

2005 2006 2007 2008 2009 2010Years

Num

ber o

f Con

nect

ions


4.2.4 Large Business Connections

The forecast for large business connections is 156 connections over the 2006 to2010 period. Graph 4.4 illustrates this.

Graph 4.4

4.3 Customer Numbers

AGLE has adopted the NIEIR projection as its forecast for customer numbers.

This forecast has concluded that over the 2006 to 2010 period the number ofcustomers connected to the AGLE network will grow by an average rate of 1.6% perannum. Long term annual growth in each major network tariff category is expectedto be:

• 1.6% for residential customers;• 1.5% for small business customers; and• 0.2% for large customers.

In compiling these forecasts, NIEIR has considered all aspects of net customergrowth including connections, disconnection’s, existing growth and movement bycustomers to other networks. NIEIR has also extensively reviewed local andinternational economic factors in determining an accurate and reasonable forecast.

Table 4.3 identifies the forecast customer numbers by major tariff category for the2006 to 2010 period.

Large Business Connections

27

28

29

30

31

32

33

2005 2006 2007 2008 2009 2010Years

Num

ber o

f Con

nect

ions


Table 4.3

AVERAGE NUMBER OF CUSTOMERS BY MARKET SEGMENT2006 2007 2008 2009 2010

Residential 258,320 262,707 266,507 270,270 274,972Small Business 25,902 26,162 26,499 26,970 27,503Large Business 893 903 901 901 900TOTAL 285,115 289,773 293,907 298,141 303,375

Note: Customer numbers for each year are the average customer numbers over the 12-month period

4.4 Energy Consumption

AGLE has adopted the NIEIR projection as its forecast for energy consumption.

Energy consumption projections developed by NIEIR have concluded that, over theforecast period, total load on the AGLE network will grow by an average rate of 0.4%per annum. Growth (decline) in terms of major tariff categories23 is expected to be:

• 1.6% for residential customers;• 2.1% for small business customers; and• (0.6%) for large business customers.

Further analysis of the NIEIR projection was carried out by AGLE to ensure thatcustomers were allocated to the correct tariff category. This included the allocationof customers to multiple supply tariffs, reserve feeder tariffs, subtransmission MAtariffs and subtransmission EG tariffs (see Section 10.3).

Table 4.4 shows the projected energy consumption by market segments for the 2006to 2010 period.

Table 4.4

ENERGY (MWh)2006 2007 2008 2009 2010

Residential 1,169,675 1,192,178 1,210,705 1,226,383 1,248,387Small Business 744,645 753,724 768,463 787,151 808,705Large Business 2,220,616 2,204,671 2,184,116 2,170,035 2,165,747TOTAL 4,134,936 4,150,573 4,163,283 4,183,570 4,222,839

4.5 Network Demand

The peak demand placed upon an electricity network is influenced by many factors,including the economy, customer activity, the type and nature of customerinstallations connected to the network, and the extremes of weather conditions.AGLE forecasts the network peak demand annually to enable forward planning.

Demand forecasts are used in the assessment of network adequacy to identifysystem deficiencies. This leads to investigations into network solutions and non-network solutions (such as demand management). The demand forecasts are one ofthe main drivers for AGLE’s five-year network strategic capital expenditure plan.

For this Submission, AGLE has used its own internal forecast of network demand,which is in line with NIEIR’s forecast of demand for the AGLE network overall.

23 Major tariff categories include network tariff codes A100, A180, A140, A200, A210, A230, A250, A270,A290, A300, A320, A340, A370, A400, A480 and A500.


4.5.1 System Demand Forecast

AGLE has developed a model to forecast peak electricity demand. The demandforecasts are built up from a feeder level to a zone substation level and finally to aterminal station level. The forecasts take into account known load changes,economic forecasts, government (state and local) planning schemes and historicalpeak demands. The model also takes into account proposed load to be transferredbetween zone substations.

Separate demand forecasts for summer and winter are produced. These forecastscorrespond to average daily temperatures, which have a 50% probability ofexceedence under a medium economic scenario. A 10% probability of exceedence(that is, 1 in 10 chance of occurrence) forecast at the zone substation and terminalstation levels are also produced for use in contingency planning and in compliancewith the Electricity System Code24 and the National Electricity Code25.

The following factors are taken into account in developing the system demandforecast.

4.5.1.1 Historical Peak Demands

Historical peak demands are analysed for variations from the previous year’sforecast, load growth trends and changes in usage patterns. The most recenthistorical peak demands are also used as the starting point for the forecasts, afteradjustment for temperature variations.

4.5.1.2 Known Load Changes

AGLE monitors connection and disconnection of loads and prospective load changesthrough both internal channels (eg. connection enquires and applications) andexternal channels (eg. media reports and customer discussions). These prospectiveload changes are incorporated into the system demand forecast.

Large loads seeking connection are recorded and included at the appropriatenetwork level. With commercial/industrial loads, the nature of the load is taken intoaccount and appropriate diversities are applied. Large loads that are disconnectingare also recorded and these changes taken into account. This includes the likes ofthe recent closure of the Kodak plant.

With residential development the load is dependent upon the number of residentiallots available and the take-up-rate for those lots. Recently completed estates arealso included as new customers continue to take up vacant lots and existingcustomers connect new appliances.

24 Office of the Regulator-General (2000) “Electricity System Code” October 2000.25 National Electricity Code Administrator “National Electricity Code.”


Table 4.5 shows the Underground Residential Development (URD) take-up-ratesused in preparing the load demand forecasts. AGLE assumes the estates will be atfull capacity after 5 years from the time development commences. These take-up-rates are based on historical data for URD estates.

Table 4.5

URD TAKE-UP RATESYear Rate (%)

1 162 303 304 155 9

New load increases are appropriately diversified and Table 4.6 shows the diversityfactors used. These factors are based on historical data.

Table 4.6

DIVERSITY FACTOR FOR VARIOUS LOAD TYPESLoad Type Diversity Factor (%)

URD 65Commercial 60-80

Industrial 50-85

4.5.1.3 Economic Trends/Planning Schemes

Other inputs into system demand forecasts include:

• Documents produced by state and local governments detailing population growth,population movement and planning schemes. This information is used primarilyin formulating average long-term demand growth rates for the next five to tenyears;

• Land availability, particularly re-zoning of land and large areas within the urbanarea that will potentially be made available for development (eg. Essendonairport), are identified within the AGLE area. Where necessary, a judgement ismade on the type of development (ie residential or commercial/industrial) likely tooccur. Estimates are then made of the amount of load for the area based on astandard design philosophy for the type of development expected. Standardtake-up-rates and diversities are applied to these loads and the growth rate isadjusted for the issues outlined above;

• General economic forecasts are compared with the long-term growth rate toensure consistency.

4.5.1.4 Temperature Sensitivity

The AGLE network is summer critical, as annual peak demand occurs during thesummer months. Summer load demands have a high correlation with ambienttemperature due to air conditioning and refrigeration loads. Winter load demands aregenerally lower than the previous summer demands and are relatively less sensitiveto ambient temperature due to the high penetration of gas hot water and heating inmany of the AGLE supply areas.


Temperature sensitivity factors are derived from historical demand information andthe corresponding average daily temperatures. Table 4.7 shows the temperaturepercentiles and the corresponding average summer daily temperature. Thesetemperatures are identical to those adopted by VENCorp in its summer demandforecast.

Table 4.7

PROBABILITY OF EXCEEDING AVERAGE DAILY SUMMER TEMPERATURETemperature percentiles 10th 50th 90thAverage daily temperature 32.9°C 29.6°C 27.1°C

AGLE’s summer 50% probability of exceedence forecasts correspond to an averagedaily temperature of 29.6°C.

4.5.2 Comparison with NIEIR Forecast

AGLE commissioned NIEIR to independently prepare a peak demand forecast for theAGLE total network. NIEIR used its own econometric model to assess expectedmacroeconomic activity and electricity consumption. The forecasting processinvolved mapping economic data for each region within the AGLE supply area to thesupplying terminal stations. These were then compared with historical energy anddemand data for those terminal stations. The terminal station forecasts were thenaggregated to give total network forecasts.

The NIEIR forecast supports AGLE’s internal forecast. Over the 2006 to 2010period, NIEIR forecast an average growth rate of 2.52% per annum for the 50%probability of exceedence, and the corresponding growth rate from AGLE’s was2.30% per annum.

4.6 Contract Demand

AGLE has developed a model to forecast contract demand for demand tariffcustomers. This forecast has been verified by NIEIR.

The development of the contract demand forecast involved the following elements:

• An analysis of the relationship between demand and energy at the tariff level.This was done by sampling customers in each demand tariff category. Theelasticity of contract demand with respect to energy was calculated for each tariffcategory; and

• Forecasts from 2006 to 2010 of contract demand by demand tariff category werebased upon applying the growth rate in energy for the relevant network tariff, tothe elasticity of contract demand.

AGLE intends to offer customers a one off automatic reset in their contract demandon 1 January 200626 to reflect the maximum demand recorded in calendar year200527. This will result in overall contract demand levels falling, since manycustomers have a contract demand that exceeds their actual maximum demand.The lower level of contract demand in 2006 reflects this factor.

26This does not apply to customers who have signed a ‘Connection and Connection Work’ agreement

with AGLE, which specifies a contract demand level.27 Customers contract demand would be reset to the highest of the maximum demand recorded in 2005,or the minimum chargeable demand applicable to the network tariff assigned to the customer.


Table 4.8 shows the projected contract demand for the 2006 to 2010 period.

Table 4.8

CONTRACT DEMAND2006 2007 2008 2009 2010

Contract Demand (kW) 613,177 615,682 618,090 617,632 617,795

4.7 Verification of Forecasts

As discussed previously, AGLE has either adopted NIEIR developed forecasts or hashad NIEIR verify and reconcile AGLE forecasts for all quantity forecasts used in thisSubmission.

4.7.1 National Institute of Economic and Industrial Research

NIEIR is one of Australia's leading economic consultancy and research organisation.NIEIR was engaged by AGLE in the last Price Review, and in the last 10 years it hasprepared both energy forecasts and maximum demand forecasts (at various levels ofdisaggregation - terminal stations, BSPs, zone sub-stations) for many distributionbusinesses in Victoria.

4.7.2 Scope of Works for NIEIR

The scope of works included the following:

• Electricity sales and customer number projections by major network tariffcategory;

• Verification of the more detailed network tariffs forecasts prepared by AGLE toensure consistency with NIEIR’s projections;

• Verification of the contract demand forecasts prepared by AGLE; and• Projections of new connections, both residential and business.

4.7.3 Verification of Forecasts

Customer growth and load projection models were provided by NIEIR. AGLEcompiled the forecast of contract demand for demand customers. NIEIR hasreviewed this forecast and verified that the methodology and assumptions underlyingit are the best estimates arrived at on a reasonable basis.



5. CAPITAL EXPENDITURE REQUIREMENTS

5.1 Introduction

The AGLE forecast of capital expenditure has been prepared using the best availableinformation to forecast the required level of expenditure by category. Thisinformation comes from detailed planning and modelling work and results in anexpenditure forecast that should closely match the expenditure required to meetAGLE network growth and reliability forecasts. An alternative approach that useshistorical expenditure to project future expenditure was considered. However, thisapproach was rejected as it fails to use the detailed information available, and is notlikely to result in an accurate forecast of required future expenditure.

The capital expenditure forecast has been developed taking into account a number offactors that are likely to impact on required expenditure. These factors include:

• The AGLE network provides electricity supply to a large proportion of the northernand western suburbs of Melbourne. Many of these suburbs are old andconsequently the network consists of many old assets that are nearing the end oftheir life;

• Complex and constantly changing regulations affect both the network and theway that work is performed on the network. These regulations add complexity tonetwork activities and generally increase costs. Examples include changingenvironmental regulations and work safety regulations;

• The network primarily serves an inner urban area. These areas are undergoingsignificant change and renewal, which brings changing community attitudes andlifestyles. Councils, representing their changing constituents are takingincreasing interest in the form of the network and the manner in which work onthe network is undertaken. This affects network activities by necessitatingadditional consultation in areas such as the location of new assets;

• Community expectations of the electricity network are changing with constant andreliable supply becoming the accepted standard. One example of suchexpectation is the negative publicity on the recent outages experienced inQueensland and New South Wales. Clearly the community expects thatwidespread outages, particularly during periods of high temperatures, should notoccur. To meet these expectations it is necessary to ensure that adequatecapacity is available in the electricity system to meet anticipated peaks and toensure that the system remains secure even when components fail.

The methodology used to forecast each category of expenditure is described below.Forecasts have been developed based on detailed information and planningprocesses. This information is largely derived from the latest information technologybased systems that are used to support AGLE’s asset management activities. Thesesystems are integrated to provide the highest level of accuracy and efficiency inasset record management. The core systems include:

• Geographical Information System (GIS);• Works Management and Logistics (SAP);• SCADA and Distribution Management System (DMS);• Substation Utilisation and Profiling System (SUPS);• DINIS/PSSE Power Flow Simulation; and• Document Management System.


These systems enable detailed analysis of asset performance and the operationalmanagement of the network. The principles underlying the asset managementsystems and record management strategy are to ensure high quality and accurateasset data that is readily accessible to authorised users through efficient use oftechnology.

5.2 Overall Forecast Capital Expenditure

The forecast Capital Expenditure for the Current Regulatory Obligations and theSafety Management Scenario is shown in Tables 5.1A and 5.1B respectively.

Table 5.1A

FORECAST CAPITAL EXPENDITURE – CURRENT REGULATORY OBLIGATIONS ($000)2006 2007 2008 2009 2010 TOTAL

Reinforcements 12,950 16,260 13,490 11,510 17,250 71,460New customer connections 16,190 16,450 15,630 16,300 18,960 83,530Load movement 0 0 0 0 0 0Reliability and qualitymaintained 11,290 13,540 16,070 17,790 22,670 81,360

Reliability and qualityimprovements 440 210 300 160 160 1,270

Environmental, safety andlegal 53,340 55,330 55,630 57,470 58,910 280,680

SCADA/Network control 2,950 1,660 3,320 3,970 2,130 14,030Non-network general assets- IT 9,670 9,860 9,200 7,140 9,580 45,450

Non-network general assets- Other 3,110 7,100 8,370 1,830 1,750 22,160

TOTAL 109,940 120,420 122,010 116,170 131,410 599,950

Table 5.1B

FORECAST CAPITAL EXPENDITURE – SAFETY MANAGEMENT SCENARIO ($000)2006 2007 2008 2009 2010 TOTAL

Reinforcements 12,950 16,260 13,490 11,510 17,250 71,460New customer connections 16,190 16,450 15,630 16,300 18,960 83,530Load movement 0 0 0 0 0 0Reliability and qualitymaintained 9,960 12,190 14,690 16,380 21,230 74,450

Reliability and qualityimprovements 440 210 300 160 160 1,270

Environmental, safety andlegal 5,960 6,940 6,210 7,000 7,380 33,490

SCADA/Network control 2,950 1,660 3,320 3,970 2,130 14,030Non-network general assets- IT 9,670 9,860 9,200 7,140 9,580 45,450

Non-network general assets- Other 3,110 7,100 8,370 1,830 1,750 22,160

TOTAL 61,230 70,670 71,210 64,290 78,440 345,840

5.3 Network Related Capital Expenditure

5.3.1 Demand Related – Reinforcement

Demand Related (Reinforcement) capital expenditure is required to ensure thenetwork has adequate capacity to meet predicted demand for electricity suppliedthrough the sub-transmission lines, zone substations and high voltage lines.


Reinforcement capital is identified through the system planning process.

The aim of distribution system planning is to optimise the expenditure required tomeet the demands of load growth and the renewal of the aging parts of the network.It includes a commitment to maximise the utilisation of assets and to employ non-network asset solutions where they are cost effective. The system planning processis an integral part of asset management.

All expenditure on the network (capital, operating and maintenance) is evaluated andranked on a consistent basis to ensure an optimum investment plan. The investmentplanning and risk management processes are integrated to ensure that investmentsprovide the maximum benefit and efficiency to customers.

Diagram 5.1 provides a summary of the distribution system planning andaugmentation process.

AGLE regularly carries out detailed analysis of the network to identify performanceand capability shortcomings. This includes mathematical modelling of the totalnetwork to determine its ability to meet the forecast requirements (loading andperformance), including the state of individual components with respect to lineloading and voltage levels under normal and contingency conditions. Results of thismodelling are used to identify when and what potential inadequacies are likely toarise in the future, and determine which augmentation or operational options arefeasible and satisfy the requirements.

The current rate of technological change requires continual assessment of newconcepts in plant and technology. All viable augmentation and operational optionsare considered, balancing performance risk against costs, to identify optimalsolutions to meet forecast requirements. The options are also risk evaluated forperformance and reliability in an integrated system. Accurate modelling requires ahigh level of understanding of the complex behaviour of all network elements, suchas lines, transformers, and capacitors.


Diagram 5.1 Flow-chart of distribution system planning and augmentation process

Prepare Capital Plan:HV network – 5 years,Major works – 10 years.

Model network loading andperformance.Identify system inadequaciesand constraints and evaluaterisks and options.

Plant ratingsand network capacity

Proponents of non-networksolutions respond to DistributionSystem Planning Report

Select preferred options

Implementation of projects

Management/Board approvalof projects

Vencorp

Load data forecast

Regulatory Documents

Service standards

Condition monitoring

Asset managementsystem

Identify feasible networkoptions. Estimate costs andlead times.

Review compliance withLicence and Distribution Coderequirements

Detailed economic andtechnical evaluation of feasibleoptions

Publish Distribution SystemPlanning Report


The current rate of technological change requires continual assessment of newconcepts in plant and technology. All viable augmentation and operational optionsare considered, balancing performance risk against costs, to identify optimalsolutions to meet forecast requirements. The options are also risk evaluated forperformance and reliability in an integrated system. Accurate modelling requires ahigh level of understanding of the complex behaviour of all network elements, suchas lines, transformers, and capacitors.

The forecasts included in this Submission for reinforcement capital expenditure havebeen derived from the AGLE system planning process and are detailed in Table 5.2.

Table 5.2

REINFORCEMENT CAPITAL EXPEDITURE ($000)2006 2007 2008 2009 2010 TOTAL

HV Augmentation 4,414 5,390 5,568 4,875 6,180 26,427LV Augmentation 210 210 210 218 224 1,072Subtransmission LinesAugmentation 3,534 2,770 2,903 2,207 541 11,955

Zone SubstationAugmentation 3,282 5,560 1,949 712 4,960 16,463

Network VoltageConversion 1,200 1,710 2,545 3,498 5,015 13,978

Property purchases 310 620 315 0 330 1,575TOTAL 12,950 16,260 13,490 11,510 17,250 71,460

In order to test the appropriateness of the AGLE forecast, AGLE commissioned PBAssociates to develop a generic model for estimating demand related capitalexpenditure and load demand growth. AGLE supplied PB Associates withinformation including:

• Various network configurations used across the AGLE network;• AGLE network planning criteria;• Standard equipment used in augmentation and construction works;• The fully installed costs of standard equipment based on recent similar projects;• Utilisation profiles for various parts of the network; and• Forecast demand growth rates for each network level and type.

Using this information PB Associates developed a model that provided an annualestimate of the capital expenditure required to meet AGLE’s forecast demand. ThePB Associates model only takes account of network reinforcement that is a result ofdemand exceeding capacity, and thus did not recognise the following types of work:

• Conversion of 6.6kV network assets to 22kV;• Sub-transmission line augmentation resulting from the augmentation of terminal

stations; and• Augmentation where prescribed voltage levels are breached before plant/line

ratings are exceeded.

In particular, the Preston distribution network has a primary voltage level of 6.6kV.The area is supplied from two AGLE zone substations. The voltage level of 6.6kV isinefficient for today’s electricity supply requirements due to its low capacity. There isinsufficient capacity for load growth and in some areas no capacity for emergencytransfers. As a result of this, a long-term program to progressively convert this areato a voltage of 22kV is being undertaken. This voltage conversion program was notmodelled in the PB Associates model.


AGLE’s and PB Associates’ estimates compare favourably and AGLE’s estimatesare adopted in this Submission.

Both estimates are shown in Table 5.3.

Table 5.3

COMPARISON OF AGLE AND PB ASSOCIATES GROWTH CAPITAL ($000)2006 2007 2008 2009 2010 TOTAL

Total Reinforcements CapitalExpenditure 12,950 16,260 13,490 11,510 17,250 71,460

AGLE estimate (excluding 6.6kVconversion and connectionasset sub-transmission lineaugmentation)

11,792 14,651 11,158 8,475 12,961 59,037

PB Associates estimate 12,680 15,610 8,520 10,310 9,340 56,460

5.3.2 Demand Related – New Customer Connections

The forecast capital expenditure for new customer connections has been preparedusing a number of categories. These are:

• Medium density housing;• Dual and multiple occupancy;• Low density/rural supplies;• Business supply projects;• Services;• Special capital works; and• Recoverable works.

NIEIR has provided forecasts of the number of new connections for residential andbusiness customers. Details of the forecast of new customer connections areincluded in Section 4.2 of this Submission.

The cost of a customer connection includes the direct cost of connecting thecustomer along with “shallow” network augmentation costs. For business customersthis will often include a component of low voltage network augmentation and/or thecost of installing a new distribution substation. As requested by the Commission, thecost of providing meters and the cost of installing streetlights have been excludedfrom this forecast and have been included elsewhere. (See Sections 11 and 12respectively).

Forecasts of expenditure on special capital works and recoverable works are basedon a proportion of total new customer connections capital expenditure. Historically,the level of activity in this area has shown a strong correlation with customerconnections expenditure. Further, these activities attract a large proportion ofcustomer contributions, and therefore there is little impact on required networkrevenue as a result of any inaccuracies in this forecast.


Table 5.4 shows the forecast customer connection expenditure.

Table 5.4

CUSTOMER CONNECTIONS EXPENDITURE2006 2007 2008 2009 2010 TOTAL

New ConnectionsResidential Connections 4,724 5,017 4,346 4,305 5,378 23,770Small Business Connections 1,973 1,815 1,980 2,208 2,315 10,291Large Business Connections 31 31 31 31 32 156Total Connections 6,728 6,863 6,357 6,544 7,725 34,217Capital Expenditure ($000)Medium Density Housing 4,804 5,143 4,490 4,483 5,645 24,566Dual & Multiple Occupancy 734 786 686 685 863 3,753Low Density/Small Business 1,134 1,214 1,060 1,059 1,333 5,800Business Supply Projects 5,729 5,438 5,836 6,376 6,713 30,092Services 988 1,016 827 848 1,103 4,782Special Capital Works 2,242 2,280 2,177 2,271 2,636 11,607Recoverable Works 561 570 544 568 659 2,902TOTAL 16,190 16,450 15,630 16,300 18,960 83,530

5.3.3 Demand Related – Load Movement

The Commission has requested forecasts for network reinforcement brought aboutby the movement of load within the network. The intention of this is to recognise thecost impact of load that moves from one part of the network to another part of thenetwork. The result of this load movement is a reduction in utilisation on some partsof the network, and the requirement for capital expenditure to increase capacity onother parts of the network, without a resulting increase in customer numbers.

In cases where it is known that a specific customer will move from one location withinthe network to another location within the network, a calculation can be performed toestimate the capital cost of this load movement. However, in the case of residentialand small business customers, the house or premises vacated is usually reoccupiedby another customer with similar load characteristics. In these cases the net effect isthe same as for a new customer.

It is uncommon for larger customers to move from one part of the AGLE network toanother part of the AGLE network. However, it is not uncommon for largercustomers to move from one part of the state to another, from one part of Australia toanother, or, increasingly, from one country to another. The effect on the AGLEnetwork of such moves is the same as a new customer arriving or an existingcustomer leaving the AGLE area.

AGLE does not keep records of customers who move within its network area. It isconsidered that smaller customers make the majority of these moves and the resultof the move does not affect the overall level of capital expenditure. There are noknown larger customers who are planning to move from one location to anotherwithin the AGLE network area.

Consequently, AGLE is forecasting no capital expenditure due to load movements.


5.3.4 Non Demand Related – Reliability and Quality Maintained

Asset replacement involves the replacement of assets that have reached the end oftheir useful life. AGLE engaged PB Associates to model the capital requirements forasset replacement.

The model used by PB Associates provided a detailed assessment of the futurecapital requirements. A description of the PB Associates Asset Replacement modelis given in Appendix J.

The PB Associates model of non-load related capital expenditure forecasts that, dueto the aging of assets, there is a requirement for increased capital expenditure duringthe 2006 to 2010 period and beyond. The model predicts that average expenditureover the next 20 years will be $19 million per year.

The model uses a number of input variables provided by AGLE, and calculatesrequired annual replacement expenditure. These inputs include asset age, assetlives, replacement costs and asset condition. PB Associates has reviewed the keyinputs and advised that the AGLE inputs are in line with other similar electricitydistribution businesses.

The estimates provided by the PB Associates model are supported by AGLE’sestimates. This Submission is based on PB Associates estimates.

The forecast of asset replacement capital expenditure for the Current RegulatoryObligations and the Safety Management Scenario are shown in Graphs 5.1A and5.1B respectively.

Graph 5.1A

Asset Replacement Capital Expenditure - Current Safety Obligations

0

5,000

10,000

15,000

20,000

25,000

2006 2007 2008 2009 2010

Year

($'0

00s)


Graph 5.1B

The distribution network asset replacement program is generated from periodic andcyclical inspection and survey. This program is in accordance with relevant technicalmanuals and guidelines, and is designed to replace assets that are in poor conditionso that the integrity of the network is maintained.

Maintenance of zone substations and communications systems is essential tomaintain safety in the work place, provide quality of supply, and minimise potentialenvironmental exposure. Various categories of work consisting of preventativemaintenance, condition monitoring, breakdown maintenance and plant replacementare required to be performed within 22 zone substations and one terminal station.

The main areas of asset replacement expenditure are:

• Pole replacement and reinstatement;• Overhead service replacement;• Pole top replacement;• Communication / protection systems replacement;• Underground cable replacement;• High voltage installation replacement; and• Zone substation equipment replacement.

The costs of each of the major areas of asset replacement for the Current RegulatoryObligations and the Safety Management Scenario are shown in Tables 5.5A and5.5B respectively.

Asset Replacement Capital Expenditure - Safety Management Scenario

0

5,000

10,000

15,000

20,000

25,000

2006 2007 2008 2009 2010

Year

($'0

00s)


Table 5.5A

ASSET REPLACEMENT CAPITAL EXPENDITURE – CURRENT REGULATORY OBLIGATIONS(EXCLUDING METERING, STREET LIGHTING AND RECOVERABLE WORKS ($000)

2006 2007 2008 2009 2010 TOTALPoles replacement &reinstatement 2,798 3,015 3,697 3,611 4,807 17,928

Overhead Services 1,511 1,716 1,800 1,913 2,530 9,470Pole top replacement 2,687 2,914 3,254 3,333 4,735 16,923Communication/protectionsystems replacement 420 1,054 580 3,077 3,906 9,036

Underground Cable 163 73 250 150 90 726High voltage installationreplacement 2,949 3,795 4,015 3,267 4,205 18,231

Zone Sub Equipment 761 974 2,475 2,439 2,396 9,045TOTAL 11,290 13,540 16,070 17,790 22,670 81,360

Table 5.5B

ASSET REPLACEMENT CAPITAL EXPENDITURE – SAFETY MANAGEMENT SCENARIO(EXCLUDING METERING, STREET LIGHTING AND RECOVERABLE WORKS ($000)

2006 2007 2008 2009 2010 TOTALPoles replacement andreinstatement 2,798 3,015 3,697 3,610 4,807 17,928

Overhead servicereplacement 1,511 1,716 1,801 1,913 2,530 9,470

Pole Top replacement 2,687 2,914 3,254 3,333 4,735 16,923Communication/protectionsystem replacement 420 1,054 580 3,077 3,906 9,036

Underground Cable 163 73 250 150 90 726High voltage installationreplacement 1,619 2,445 2,634 1,857 2,765 11,320

Zone Sub Equipment 761 974 2,475 2,439 2,396 9,045TOTAL 9,960 12,190 14,690 16,380 21,230 74,450

5.3.4.1 Pole Replacement and Reinstatement

Poles to be replaced are identified from the pole and line inspection program usingthe AGLE line inspection manual criteria. The current AGLE line inspection programuses a technical measurement procedure to determine the serviceability of woodpoles and if the pole has retained sufficient residual strength above ground to make itsuitable to be reinstated using pole staking.

Approximately 30% of wood poles on the AGLE network are classified as class 3, thelowest durability of wood poles. Based on an analysis of the age of previous polesthat have reached the end of their useful life, the life expectancy of this class of polehas been determined to be 45 years. The age profile of class 3 poles on the AGLEnetwork is shown in Graph 5.2. It can be seen that the profile centres on a pole ageof 36-40 years. This means that an increasing number of class 3 poles will requirereinstatement or replacement during the 2006 to 2010 period.


Graph 5.2

5.3.4.2 Overhead Service Replacement

Overhead services are upgraded to current standards in conjunction with other worksuch as network augmentation, pole replacement, re-conductoring, and assetrelocation. Particular attention is paid to open wire, red lead and aluminium screenedservices. Overhead services have a life expectancy of 45 years.

Overhead services operate in an environment where they are subjected to the effectsof weathering and many are impacted by trees and vegetation. There is a range oftypes of services in use related to their age. There are some types that are notconsidered serviceable any longer and are targeted for replacement.

As a result of the inspection and testing it is expected that an increasing number ofservices will be identified as requiring replacement.

The age profile of overhead service conductors on the AGLE network is shown inGraph 5.3. It can be seen that the profile is highest at an overhead service age of36-40 years. This means that an increasing number of overhead service conductorswill require replacement during the 2006 to 2010 period.

Wood Class 3 Pole Age Profile

0

100

200

300

400

500

600

700

800

1 6 11 16 21 26 31 36 41 46 51 56 61 66 71 76 81 86 91 96 101

Years since installation

Num

ber o

f pol

es

Poles Wood Class 3 -HV - To be replaced Poles Wood Class 3 -HV - To be staked Poles Wood Class 3 -HV - Existing staked

Poles Wood Class 3 -LV - To be replaced Poles Wood Class 3 -LV - To be staked


Graph 5.3

5.3.4.3 Pole Top Replacement

This activity involves the replacement of high and low voltage pole top assembliesthat have reached the end of their service life, including the assemblies on poles thathave been reinstated. Based on an analysis of the age of wood cross-arms thathave reached the end of their useful life, the life expectancy of cross-arms has beendetermined to be 45 - 50 years. There are no effective preventative maintenanceprograms that extend their life.

The age profile of cross-arms on the AGLE network is shown in Graph 5.4. It can beseen that the profile is highest at a cross-arm age of 36-40 years. This means thatan increasing number of high voltage and low voltage cross-arms will requirereplacement.

Overhead Service Age Profile

0.00

20.00

40.00

60.00

80.00

100.00

120.00

140.00

160.001 6 11 16 21 26 31 36 41 46 51 56 61 66 71 76 81 86 91 96 101


Kilo

met

ers

of C

ondu

ctor

Overhead Services


Graph 5.4

Porcelain surge diverters in excess of 20 years of age are demonstrating signs offailure in service under fault conditions. The increase in failure rate is small but isbeing monitored. Surge diverters are used extensively across the network to protectequipment from damage caused by over voltages associated with lightning strike andnetwork operational activities.

Pole or cross-arm fires are a significant issue, and are a consequence of thecombined effects of environmental conditions and pole top design that utiliseswooden cross-arms. A build up of airborne particles on insulators is generally thecause of pole fires. When moisture is added to this, usually in the form of light rain orfog, the particles may conduct electricity. This may cause arcing at the base of theinsulator and ignition of the pole or cross-arm.

The factors which increase the likelihood of a pole fire are particle build up oninsulators and the ‘dryness’ of the pole and cross-arm. The greater the build up ofparticles and the drier the pole, the more likely a fire is to occur.

Between 1997 and September 2004, there have been 389 instances of either poleand cross-arm fires or evidence of charred assets. The pole and pole top hardwareinspection and maintenance program has been reviewed as a part of developing thepole fire mitigation strategy. Emphasis is placed on visually identifying thecontributing factors to pole fires. The pole fire mitigation strategy focuses on modernpole top design that utilises steel cross-arms, and these structures are particularlydesigned to prevent pole and cross-arm fires.

Crossarm Age Profile

0

500

1000

1500

2000

2500

3000

1 6 11 16 21 26 31 36 41 46 51 56 61 66 71 76 81 86 91 96 101


Num

ber o

f Cro

ssar

ms

Cross Arms Wood 66kV (incl. Insulators) Cross Arms Wood HV (incl. Insulators) Cross Arms Wood LV (incl. Insulators)


5.3.4.4 Communications/Protection Systems Replacement

This activity covers the replacement of communications and protection schemesassociated with the sub transmission system. Manufacturers no longer supportvarious communications system equipment installed in the AGLE network, due to itsage, and therefore equipment failures cannot be repaired. Failure to replace thisequipment will lead to reduced reliability of supply and will increase the risk ofextensive plant damage and supply interruptions.

Much of the existing copper communication cable network is very old and isperforming poorly. For example, in some locations the cables are paper insulatedand 60 years old. The paper insulation has broken down in many places and thenumber of useable pairs of wires within the cable is limited.

5.3.4.5 Underground Cable Replacement

In conjunction with other works or projects, underground cables that have reachedthe end of their economic life may be replaced, including the removal of oldertechnology compound filled termination boxes.

High Voltage Cross-linked Polythene insulated cable (HV XLPE) was introducedapproximately 25 years ago. The initial cables were manufactured using a steamcuring process. Water, in contact with XLPE insulation, is now known to causepremature failure of the insulation by a process known as “treeing.” AGLE is alreadyexperiencing some failure of early manufactured cable that was installed only 25years ago.

It is estimated that recently manufactured XLPE cables will have an operating life of45 years.

5.3.4.6 High Voltage Installation Replacement

The need to replace high voltage switches is identified when the switches areoperated. Any switch that is found to be inoperable or that requires extensivemaintenance is assessed for operational requirement and possible replacement witha gas insulated switch.

There have been a number of incidents of premature failure of overhead high voltagesingle blade isolators. This has been associated with the failure of one or bothsupporting porcelain insulators. These failures have been associated with isolatorsmanufactured in 1996.

5.3.4.7 Zone Substation Equipment Replacement

AGLE has in place an ongoing project to refurbish some of the zone substationbuildings identified in an audit of the condition of the buildings. Various zonesubstation buildings have foundation movement and require remedial action. Othermatters that have been identified include the presence of asbestos and general age-related deterioration. The failure to replace deteriorating buildings may lead to theloss of the station and rotational load shedding of customers.

The age profile of zone substation transformers on the AGLE network is shown inGraph 5.5.


Between 2006 and 2010, transformers at five zone substations will be in excess of 50years of age. Notwithstanding, these transformers are exhibiting signs ofdeterioration and are likely to need replacing. These transformers are conditionmonitored via oil analysis to ensure that they are not subjected to overload. Oilreclamation has already been performed for the purpose of slowing the degradationof the paper insulation and extending the life of the transformers.

Graph 5.5

Bushings on certain outdoor circuit breakers are leaking insulating material and willeventually fail, interrupting supply to customers. A program has been developed toreplace all bushings in order of priority.

Metal clad switchgear at various zone substations is more than 50 years old and thisintroduces a number of maintenance problems. The most significant problem is theloss of insulation pitch from the bus chamber that could lead to catastrophic failure ifnot replaced. This would cause unacceptable interruption to supply.

Circuit breakers that are used to switch capacitor bank installations on a daily basisoperate far in excess of normal zone substation circuit breakers. Mechanical failuresoccur in the primary contact drive systems and this is attributable to age and fatiguefailure.

5.3.5 Non Demand Related – Reliability and Quality Improvements

Section 3 of this Submission details the targets proposed by AGLE for the 2006 to2010 period. The AGLE network is generally reliable and there are no plans toimprove average network reliability over this period.

Zone Substation Transformer Age Profile

0

1

2

3

4

5

6

7

8

1 6 11 16 21 26 31 36 41 46 51 56 61 66 71 76 81 86 91 96 101


Num

ber o

f Tra

nsfo

rmer

s

Transformers 20/33MVA - Zone Substation Transformers 10/13.5MVA - Zone Substation


AGLE plans to maintain average network reliability and to improve reliability for thosecustomers on the least reliable parts of the network by a combination of targetedprojects, maintenance programs, asset replacement and capacity development. Thisapproach will ensure that those customers experience improvements in reliabilitywhile current average reliability is maintained. The approach also minimises the costof improving reliability for those customers by directing programs and projects thatare primarily planned for other purposes to these areas of the network.

The specific reliability improvement projects are intended to improve reliability byvermin proofing structures, replacing connectors that are susceptible to failure underfault conditions and upgrading surge diverters that do not perform adequately. Thecost of these programs is shown in Table 5.6.

Table 5.6

NETWORK RELIABILITY IMPROVEMENT PROJECTS ($000)2006 2007 2008 2009 2010 TOTAL

Vermin proofing feeder 435 0 0 0 0 435Upgrade non-tension connectors 0 213 60 0 0 273Upgrade surge diverters 0 0 244 161 164 569TOTAL 435 213 304 161 164 1,277

It is likely that these specific projects alone will not result in the desiredimprovements, and therefore these specific projects will be supplemented byexpenditure that has been categorised as maintenance, demand relatedreinforcements, and non-demand related reliability and quality maintained. Thisadditional expenditure will involve direct replacement and development programs atareas where reliability is unsatisfactory. This approach will ensure that low reliabilityis not a result of insufficient network capacity, insufficient maintenance or agedassets that have reached the end of their life.

5.3.6 Non Demand Related – Environmental, Safety and Legal

The expenditure forecast for environmental, safety and legal for the 2006 to 2010period has been categorised into:

• Expenditure relating to compliance with Electricity Safety Regulations;• Expenditure required to meet changing environmental standards;• Increased expenditure as a result of the Roads Management Act; and• Other safety and security expenditure.

As discussed in Section 1.2.1, the cost of compliance with the Safety Regulations isbeing dealt with through the presentation of two scenarios in this Submission.

The details of environmental, safety and legal expenditure forecasts for the CurrentRegulatory Obligations and the Safety Management Scenario are shown in Tables5.7A and 5.7B respectively.


Table 5.7A

ENVIRONMENTAL, SAFETY & LEGAL EXPENDITURE – CURRENT REGULATORYOBLIGATIONS ($000)

2006 2007 2008 2009 2010 TOTALElectricity safety regulations 51,350 53,300 53,550 55,350 56,750 270,300Environmental 690 700 720 730 740 3,580Roads Management Act 880 900 920 940 960 4,600Safety & security 420 430 440 450 460 2,200TOTAL 53,340 55,330 55,630 57,470 58,910 280,680

Table 5.7B

ENVIRONMENTAL, SAFETY & LEGAL EXPENDITURE – SAFETY MANAGEMENT SCENARIO($000)

2006 2007 2008 2009 2010 TOTALElectricity safety regulations 3,970 4,910 4,130 4,880 5,216 23,106Environmental 690 700 720 730 740 3,580Roads Management Act 880 900 920 940 960 4,600Safety & security 420 430 440 450 460 2,200TOTAL 5,960 6,940 6,210 7,000 7,380 33,490

In addition to the costs relating to the Safety Regulations (see Section 1),expenditure for environmental, safety and legal is required:

• Environmental expenditure will involve the continuing installation of soundenclosures and improved oil containment at specific zone substations;

• Expenditure as a result of the Roads Management Act is uncertain as the codesof practice that will define the cost to distribution businesses are currently underdevelopment. There are two likely impacts. The first is a notification andpermission scheme administered by councils and VicRoads. This scheme willincrease the cost of all capital works by adding to the complexity of work planningand reporting processes. The second is the requirement to install protectivebarriers or bury assets where new lines are proposed; and

• Safety and security expenditure is additional expenditure required at zonesubstations to improve security and to meet regulations regarding “working atheights”.

A detailed breakdown of expenditure forecasts for the Current Regulatory Obligationsand the Safety Management Scenario is shown in Tables 5.8A and 5.8B respectively.


Table 5.8A

DETAILS OF ENVIRONMENTAL, SAFETY & LEGAL EXPENDITURE - CURRENT REGULATORYOBLIGATIONS ($000)

2006 2007 2008 2009 2010 TOTALElectricity Safety RegulationsRectification following inspectionand testing of earthing systems 786 810 813 832 850 4,091

Rectification following inspectionsand testing of service neutral 2,346 2,396 2,447 2,499 2,552 12,240

Overhead services minimumdistance between aerial lines andthe ground

41,712 42,596 43,500 44,423 45,364 217,595

Supporting platform andequipment for a pole mountedsubstation 2006

1,293 1,320 1,349 1,377 1,406 6,745

CMEN and Neutral Earth Resistors 1,251 2,130 1,305 1,999 2,268 8,953Clearance from Tramwaysoverhead conductor 3,963 4,047 4,133 4,220 4,310 20,672

TOTAL 51,350 53,300 53,550 55,350 56,750 270,300Environmental RegulationsAsbestos Regulations 230 234 240 244 248 1,196Oil Containment – ZoneSubstations 115 115 120 120 122 592

Zone Substation Noise Reduction 345 351 360 366 370 1,792TOTAL 690 700 720 730 740 3,580Road Management ActInstallation and Maintenance Costs 880 900 920 940 960 4,600TOTAL 880 900 920 940 960 4,600Safety and SecurityZone Substation Security 229 235 240 245 250 1,199Fall Prevention 191 195 200 205 210 1,001TOTAL 420 430 440 450 460 2,200


Table 5.8B

DETAILS OF ENVIRONMENTAL, SAFETY & LEGAL EXPENDITURE – SAFETY MANAGEMENTSCENARIO ($000)

2006 2007 2008 2009 2010 TOTALElectricity Safety RegulationsRectification following inspectionand testing of earthing systems 156 160 163 167 170 816

Rectification following inspectionsand testing of service neutral 1,304 1,337 1,359 1,384 1,418 6,802

Overhead services minimumdistance between aerial lines andthe ground

1,049 1,070 1,088 1,110 1,134 5,451

Supporting platform andequipment for a pole mountedsubstation 2006

210 213 215 220 226 1,084

CMEN and Neutral Earth Resistors 1,251 2,130 1,305 1,999 2,268 8,953Clearance from tramwaysoverhead conductor 0 0 0 0 0 0

TOTAL 3,970 4,910 4,130 4,880 5,216 23,106Environmental RegulationsAsbestos Regulations 230 234 240 244 248 1,196Oil Containment – ZoneSubstations 115 115 120 120 122 592

Zone Substation Noise Reduction 345 351 360 366 370 1,792TOTAL 690 700 720 730 740 3,580Road Management ActInstallation and Maintenance Costs 880 900 920 940 960 4,600TOTAL 880 900 920 940 960 4,600Safety and SecurityZone Substation Security 229 235 240 245 250 1,199Fall Prevention 191 195 200 205 210 1,001TOTAL 420 430 440 450 460 2,200

5.3.7 Standard Metering (2004 and 2005 only)

Expenditure in 2004 and 2005 involves the installation of meters for newconnections, and the replacement of meters that either fail in service or have reachedthe end of their life.

5.3.8 SCADA/Network Control

Much of the improvements to network reliability that have occurred during the currentregulatory period are underpinned by automation and control systems. To maintainthis reliability while the average age of the network increases is a key challenge forAGLE. The Substation Control and Data Acquisition (SCADA), communications andnetwork control systems are key components in maintaining the reliability and qualityof the network.

The existing AGLE SCADA system is currently undergoing a mid-life refurbishmentthat will extend the life of the system by another four years. As a result, a newSCADA system will be required over 2008 and 2009.


The infrastructure that provides communications between the SCADA system andzone substations and between the protection devices on the network is largely basedon aging copper conductors. This communications network is becoming increasinglyunreliable and as a result the network is becoming less secure and the probability ofa major network outage as a result of a communications network failure is increasing.Plans have been developed to replace the aging copper network with a modernnetwork consisting of fibre optic cables. Work to construct this new network hascommenced and will continue during the 2006 to 2010 period. The new network isinitially installed in areas where the risk of failure of the existing network is high andwill gradually be installed in other areas based on risk.

Forecast expenditure on SCADA, communications network and network control isshown in Table 5.9.

Table 5.9

SCADA/NETWORK CONTROL ($000)2006 2007 2008 2009 2010 TOTAL

SCADA and Network control 2,950 1,660 3,320 3,970 2,130 14,030

5.4 Non Network General - IT

IT Systems are critical for AGLE to deliver high quality and efficient networkoperations, regulatory compliance, and for full retail competition. Systems thatsupport the efficient operation of the network include:

• Management information systems;• Field services; and• Network monitoring and control.

Regulatory compliance support includes:

• Service to end-customers; and• Ring-fencing of competitive information.

Support for full retail competition includes:

• Conformance with the market operator (NEMMCO) procedures and servicelevels;

• Network billing of retailers; and• The integration of electronic business to business (B2B) transactions.

The expenditure required by AGLE can be divided into four categories:

• System replacements;• System modifications and enhancements;• New system developments; and• Business Improvements.


The Total Capital expenditure for IT is shown in Table 5.10.

Table 5.10

IT CAPITAL EXPENDITURE ($000)2006 2007 2008 2009 2010 TOTAL

System Replacements 2,675 5,150 4,300 2,575 5,250 19,950New System Developments 4,190 1,720 1,855 1,520 1,185 10,470Business Improvements 1,530 1,815 1,870 1,870 1,970 9,055System Modifications 1,275 1,175 1,175 1,175 1,175 5,975TOTAL 9,670 9,860 9,200 7,140 9,580 45,450

5.4.1 System Replacements

Expenditures in this category include the replacement of hardware that has reachedthe end of its useful life. This includes PCs, peripherals, LAN/WAN components andmainframe infrastructure. Also included in this category are the costs for licence andsystem updates to maintain appropriate vendor support for third party suppliedsoftware applications. AGLE’s system policy is to update all systems that manageand store key corporate data to ensure ongoing vendor support to minimise thebusiness continuity risk of a major system failure.

Table 5.11 shows the capital expenditure required for system replacement.

Table 5.11

IT CAPITAL EXPENDITURE FOR SYSTEM REPLACEMENT ($000)2006 2007 2008 2009 2010 TOTAL

Geographic Information SystemUpdate 1,500 1,500

Document Management SystemUpdate 500 500 1,000

Substation Utilisation andProfiling System Upgrade 200 200

AutoCAD Updates 150 150 300Field Data Collection HardwareReplacements 75 75 150

Routine IT Expenditure 500 500 500 500 500 2,500Hardware Replacements (GIS,SUPS, SCADA) 100 100 100 300

General IT expenditure 2,000 2,000 2,000 2,000 2,000 10,000SAP Update 2,000 2,000 4,000TOTAL 2,675 5,150 4,300 2,575 5,250 19,950

The individual item for replacement capital expenditure is discussed in the followingSections.

5.4.1.1 Geographic Information System Update

AGLE’s implementation of the Smallworld GIS is approaching the stage where it isout of support because it is two versions behind the most recent release. Therequirement exists to update GIS during the 2006 to 2010 period.

The GIS application provides a development environment in addition to theunderlying asset and geographical database. The toolkits transform the GIS from anasset database into an operational tool.


The asset data, application functionality and interlinking, underpin and support thecapabilities of all other asset related applications. The GIS is a fundamentalrequirement for electricity networks because geography is such an importantconsideration in the management of the network.

5.4.1.2 Document Management System Update

AGLE must maintain and have ready access to all of the information about the assetsthat are to be managed. A key element of this capability is AGLE’s DocumentManagement System.

The Document Management System will be due for updates on two occasions in the2006 to 2010 period.

5.4.1.3 Substation Utilisation and Profiling System Update

This operational system will require ongoing maintenance and updates.

5.4.1.4 AutoCAD Updates

This operational software system will require ongoing updates and maintenance.

5.4.1.5 Field Data Collection Hardware Replacements

This equipment will require augmentation or upgrading throughout the 2006 to 2010period.

5.4.1.6 Routine IT Expenditure

The routine expenditure for miscellaneous on-going capital items and is based onhistorical trend. These items include computer printers, camera card readers, specialcomputer monitors, small software packages, etc.

5.4.1.7 Hardware Replacements (GIS, SUPS, SCADA)

The various elements of hardware for the Geographical Information System, theSubstation Utilisation and Profiling System, and SCADA will require augmentation orupdating.

5.4.1.8 General IT expenditure

As part of the group of AGL companies, AGLE benefits from the shared use of AGL’sIT systems and infrastructure such as PCs’ and servers, internet and intranet, LotusNotes and data telecommunications. AGLE contributes to the replacement of thehardware and software that support the use of general business applications andsystems.

5.4.1.9 SAP Update

AGLE uses SAP as its works management, materials management, humanresources, general accounting, costing and ledger systems. Two SAP updates havebeen anticipated in the 2006 to 2010 period.


5.4.2 New System Developments

Capital investment in this area is required to meet externally imposed informationsystem obligations or to efficiently and reliably meet network operational obligations.They are mainly driven by the requirements from external market or regulatoryobligations and the needs to upgrade obsolete internal systems.

Table 5.12 summarises the cost related to new system developments

Table 5.12

IT CAPITAL EXPENDITURE FOR NEW SYSTEM DEVELOPMENTS ($000)2006 2007 2008 2009 2010 TOTAL

Ring-fencing 110 30 140Meter Data Management 270 120 120 120 120 750MSATS Development andRetailer of Last Resort 470 210 210 210 210 1,310

B2B Development 290 290 290 290 290 1450FRC and Network Billing 1,060 410 710 510 310 3,000Standing Data Repository (SDR) 325 125 125 125 125 825CIS Plus Trouble OrderRetirement and OutageManagement Implementation

1,665 535 400 265 130 2,995

TOTAL 4,190 1,720 1,855 1,520 1,185 10,470

The individual cost items are discussed in the following Sections:

5.4.2.1 Ring-fencing

In March 2004, the Commission released Draft Decision and draft Guidelines on ring-fencing28. In order to comply with this guideline, AGLE will be required to makechanges to its existing systems. Some cost will be incurred in 2005 to meet theobligations, but additional expense will be required to replace “work arounds” withmore efficient and robust solutions.

5.4.2.2 Meter Data Management (MDM, excluding IMRO)

A new system is required to manage the very large volumes of interval meter dataresulting from the Interval Meter Rollout (IMRO). However, the majority of this ITcapital expenditure is not included here, as the Commission requires that IMRO ITcapital expenditure be incorporated into the Metering costs (see Section 12).Notwithstanding, there are additional requirements to provide metering data tointernal business systems, and it is those requirements that have been addressed inthis Section.

5.4.2.3 MSATS Developments and Retailer of Last Resort

AGLE will be required to incur costs to maintain the interface (“Gateway”) betweenAGLE’s internal business systems and NEMMCO’s MSATS system. Thisexpenditure is anticipated in order to accommodate NEMMCO MSATS releases,which are currently two to three times per year. This does not include theconsequential expenditure required for internal business systems, as that is includedelsewhere in this Submission. 28 Draft Decision on Ring-fencing and draft Guidelines March 2004.


It is anticipated that NEMMCO and the Commission will require that Electricity LocalNetwork Service Providers (LNSP’s), provide systems to support the transfer ofcustomers from a Tier 2 retailer to the Host retailer on the occasion of a Retailer ofLast Resort event. Although the requirements have not been fully specified, it isknown that the requirements will be different to the current market transferprocedures.

5.4.2.4 B2B Developments

AGLE will be required to incur costs to provide future B2B developments, subsequentto the requirements of B2B “Tranche 1” due in 2005. It is anticipated that this willrequire enhancements to procedures already in place before, as well as futuretranches of National B2B interchanges that will be developed under the new B2BNEC provisions.

5.4.2.5 FRC and Network Billing

AGLE will be required to incur costs to support expected on-going systemdevelopments for market systems obligations, and to support customer transfers andnetwork billing. Currently much of this work is carried out manually or in ad hocsystems. New systems will be required to support new time-of-use network tariffsand the substantial increase in data volumes driven by the interval meter rollout.

5.4.2.6 Standing Data Repository (SDR)

AGLE has the obligation to maintain “standing data” (describing all electricity supplypoints in the AGLE’s area) and to maintain that data in NEMMCO’s NationalElectricity Market database (“MSATS”). Currently AGLE’s standing data isdistributed over multiple systems and will be required to be rebuilt as a result of theimplementation of the Meter Data Management system driven by the Interval MeterRollout. The proposed SDR system will become the single master repository ofstanding data and will facilitate the maintenance of the standing data in MSATS. Itwill also support other requirements such as ring-fencing, network billing and meterdata processing.

5.4.2.7 CIS Plus Trouble Order Retirement and Outage ManagementImplementation

The current CIS Plus Trouble Order system is limited, inflexible and poorly integratedwith the SAP Asset Management system. A new Outage Management system withthe ‘SAP Service Management Module’ is required to provide efficient and timelymanagement of power outages. This implementation will leverage on the integrationwith the SAP Plant Maintenance, SAP Project Systems, SAP Materials Management,and SAP Finance and Human Resource modules. This will provide the opportunityto track and manage all work using a single application. The system will provide thefunctionality to automatically dispatch jobs to the field.

5.4.3 Business Improvement

Table 5.13 provides a summary of the cost for Business Improvements


Table 5.13

IT CAPITAL EXPENDITURE FOR BUSINESS IMPROVEMENTS ($000)2006 2007 2008 2009 2010 TOTAL

Mobile Works Management 200 600 700 700 800 3,000Various SAP Modules 800 800 800 800 800 4,000Marketing and Claims Database andCapital Approval 175 60 15 15 15 280

Geographic Information SystemEnhancements 100 100 100 100 100 500

SAP Enhancements (Electricity portion) 100 100 100 100 100 500CIS Plus Enhancements (ElectricityNetwork) 50 50 50 50 50 250

Document Management SystemEnhancements 65 65 65 65 65 325

Field Data Collection Enhancements 40 40 40 40 40 200TOTAL 1,530 1,815 1,870 1,870 1,970 9,055

5.4.3.1 Mobile Works Management Implementation

The provision of mobile computing connectivity will allow the extension of workflow,work organisation, and organisation correspondence into the field. Field access towork scheduling information will facilitate job-to-job scheduling and remote materialdeliveries and truck stocking, thus reducing the need for crews to return to depots.The technology will also provide additional work and asset information directly to thecrews and the subsequent return of this information into the backend businesssystems.

5.4.3.2 Various SAP Modules

Various modules of the AGLE SAP system will require improvements andenhancements during the 2006 to 2010 period, including:

• Maintenance Forecasting and Scheduling;• Service Management;• Environment, Health and Safety; and• Quality Management.

With an increased emphasis on quality management, various new QM modules willbe beneficial.

5.4.3.3 Others

General improvements to the functionality’s and features of the IT systems arerequired for the following:

• Marketing and Claims Database and Capital Approval;• Geographic Information System Enhancements;• SAP Enhancements;• CIS Plus Enhancements;• Document Management System Enhancements; and• Field Data Collection Enhancements.


5.4.4 System Modifications and Enhancements

AGLE will be required to incur costs to keep operational systems functioning asrequired to meet changing business requirements and to support expansion in thenumber of users operating a system. These modifications and enhancements are ongoing and more routine in nature than new system developments.

Expenditure in this category includes ad-hoc system enhancements and “bug-fixes”required for the ongoing efficient delivery of AGLE services. Modifications andenhancement are estimated based on a number of IT systems listed below and Table5.17 summarises the cost associated to these changes.

• Geographic Information System enhancement;• SAP Enhancements;• SAP Licence Growth;• CIS Plus Core System (exclusive of other specific changes such as B2B, etc);• Document Management System Enhancements;• Field Data Collection Enhancements;• Geographic Information System Licence Growth• Middleware Growth; and• General Hardware and Software Enhancement and Modifications

Table 5.14

IT CAPITAL EXPENDITURE FOR SYSTEM MODIFICATIONS ($000)2006 2007 2008 2009 2010 TOTAL

Geographic Information System 100 100 100 100 100 500SAP Enhancements 200 100 100 100 100 600SAP Licence Growth; 100 100 100 100 100 500CIS Plus Core System 100 100 100 100 100 500Document Management SystemEnhancements

75 75 75 75 75 375

Field Data CollectionEnhancements;

50 50 50 50 50 250

Geographic Information SystemLicence Growth

100 100 100 100 100 500

Middleware growth 50 50 50 50 50 250General Hardware and SoftwareEnhancement and Modifications

500 500 500 500 500 2,500

TOTAL 1,275 1,175 1,175 1,175 1,175 5,975

5.5 Non Network General - Other

There are three major areas of expenditure within this category. They are thereplacement of heavy vehicles, light vehicles and rebuilding of the Broadmeadowsdepot. Other areas of expenditure are tools, test equipment, furniture and officeequipment.


Table 5.15

NON-NETWORK GENERAL – OTHER ($000)2006 2007 2008 2009 2010 TOTAL

Heavy vehicles 930 1,550 2,136 653 750 6,019Light vehicles 796 863 1,542 480 298 3,977Land and buildings 375 4,020 4,025 30 35 8,485Other 1,009 66 667 66 667 3,677TOTAL 3,110 7,100 8,370 1,830 1,750 22,160

Heavy vehicles are primarily Elevated Platform Vehicles (EPVs). The estimate isbased on replacing existing vehicles at the end of their ten-year useful life. Tenyears is the effective operational life of an EPV as the vehicle requires an extensiverebuild after this time to meet electrical safety requirements for use in themaintenance and construction of live lines. Additional EPVs are also forecast to bepurchased in years 2009 and 2010. These are required to provide vehicles foradditional crews to undertake the increasing volume of asset replacement work.

The forecast cost of light vehicles is based on replacing the existing fleet inaccordance with AGLE guidelines for operational vehicles. These vehicles arereplaced at 4 years or 100,000 km.

Over the current regulatory period secondary depots at Spotswood and Heidelberghave been closed and field operations have been consolidated at the Broadmeadowsdepot. The forecast for land and buildings is based on maintaining the condition ofthe Broadmeadows depot during 2006 and then undertaking a rebuild of the depotduring 2007 and 2008. There are a number of factors that justify a total rebuild of theBroadmeadows depot. These include:

• The depot consists of three substantial buildings and a large number ofrelocatable buildings. The main store building contains asbestos and is in poorcondition. The use of the building is limited and it is approaching a point wherethe building can no longer be safely maintained;

• The permanent buildings on the site (other than the store) were built for purposesother than the asset management and service of an electricity network and areunsuited to their current use;

• The increasing volume of heavy traffic at the site is leading to problems such ascracking of concrete aprons, increasing risk of traffic accident and equipmentsecurity issues. A redesign of heavy traffic areas is required to meet the needs ofthe electricity business;

• The depot provides a back up control room in case of a need to evacuate the citycontrol room. However, the current location for the back up control is unsuited tothis function; and

• The age of the electricity network and growth rate indicates that increasingamounts of expenditure will be required to maintain and replace networkcomponents. These maintenance and replacement activities will requireadditional personnel, additional materials movements and additional vehicles.The current depot is currently at capacity and cannot accommodate theseincreasing requirements in its present form.


If major reconstruction of the Broadmeadows depot is not undertaken then operatingcosts will increase in a number of areas including maintenance of the depot,refurbishment of buildings, and rent of additional storage and depot space at otherlocations.

Other expenditure consists of miscellaneous capitalised items such as tools, testequipment, furniture and office equipment. The forecast expenditure on these itemsis in line with current levels of expenditure.

5.6 Long Term Capital Forecast

The Commission has requested that 25-year capital forecasts be provided in thisSubmission.

Graph 5.6

The long-term forecast of asset replacement has been prepared using the PBAssociates asset replacement model (this model is described in Section 5.3.4 –Reliability and Quality Maintained). The results of this are shown in Graph 5.629. Thetrend line (the solid line) indicates a gradual increase in expenditure over the twenty-year period from $12 million in 2006 to $27 million in 2025. Over the same period theaverage remaining life (dotted line) continues to decrease indicating further aging(and associated increasing risk) of the network. This forecast has been included inthe 25 year forecast.

29 The costs in this graph have not been escalated to take account of anticipated Employment costincreases described in Section 2.3.

Replacement Capital Expenditure RequirementsAge + condition based replacement

0

5

10

15

20

25

30

35

40

2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025Year

DPR

200

5 C

apex

Req

uire

men

t ($

m)

0%

10%

20%

30%

40%

50%

60%

Wei

ghte

d A

vera

ge R

emai

ning

Life

%


AGLE is not able to apply any more than a basic, high level, approach to forecastingrequired expenditure in other areas. Costs in these areas are heavily influenced byfactors beyond AGLE’s control, such as general economic and legislative changes.Consequently, AGLE is only able to provide simple projections for forecasts beyond2010, based on current forecast levels of growth. AGLE recommends that theCommission take no account of these forecasts in reviewing requirements for the2006 to 2010 period. The approach adopted is described in Table 5.16 and theresulting forecast is shown in Table 5.17.

Table 5.16

APPROACH ADOPTED TO DEVELOPMENT OF LONG TERM FORECASTCategory Basis of estimate

Reinforcements Expenditure for each year 2011 – 2025 is the average of theannual expenditure forecast for 2006 – 2010.

New customer connectionsNew customer connections are assumed to grow at a rate of1.36% per year. Expenditure if therefore forecast to increaseat the same rate.

Load Movement No forecast is provided.

Reliability and quality maintained

Expenditure in this category is driven by asset age. As goodinformation is available on asset age, replacement cost andasset life then a model has been used to forecast expenditurein this category through to 2025. See Graph 5.6.

Reliability and quality improvements Expenditure for each year 2011 – 2025 is the average of theannual expenditure forecast for 2006 – 2010.

Environmental, safety and legal Expenditure for each year 2011 – 2025 is the average of theannual expenditure forecast for 2006 – 2010.

SCADA/Network control Expenditure for each year 2011 – 2025 is the average of theannual expenditure forecast for 2006 – 2010.

Non-network general assets - IT Expenditure for each year 2011 – 2025 is the average of theannual expenditure forecast for 2006 – 2010.

Non-network general assets - Other Expenditure for each year 2011 – 2025 is the average of theannual expenditure forecast for 2006 – 2010.


Table 5.17

2025

1429

0

2321

0

3628

0

220

6890

2850

8890

3900

9653

0

2024

14,2

90

22,9

00

17,8

50

220

6,89

0

2,85

0

8,89

0

3,89

0

77,7

80

2023

14,2

90

22,5

90

22,7

50

220

6,89

0

2,85

0

8,89

0

3,89

0

82,3

70

2022

1429

0

2229

0

2269

0

220

6890

2850

8890

3910

8203

0

2021

14,2

90

22,0

00

29,7

00

220

6,88

0

2,85

0

8,89

0

3,94

0

88,7

70

2020

1429

0

2169

0

2225

0

220

6890

2830

8920

3900

8099

0

2019

14,2

90

21,4

00

20,4

50

210

6,90

0

2,85

0

8,89

0

3,81

0

78,8

00

2018

14,2

90

21,1

10

20,0

10

220

6,89

0

2,87

0

8,87

0

3,88

0

78,1

40

2017

14,2

90

20,8

30

22,0

40

220

6,88

0

2,86

0

8,89

0

4,02

0

80,0

30

2016

14,2

90

20,5

50

16,1

60

220

6,85

0

2,85

0

8,92

0

4,09

0

73,9

30

2015

14,2

90

20,2

80

24,4

50

210

6,94

0

2,73

0

9,03

0

3,70

0

81,6

30

2014

1429

0

2000

0

1604

0

200

6950

2930

8720

3390

7252

0

2013

1429

0

1974

0

2011

0

220

6820

3000

8800

4220

7720

0

2012

1429

0

1947

0

2100

0

220

6840

2770

8980

4700

7827

0

2011

1429

0

1921

0

1753

0

260

6690

2800

9090

4430

7430

0

($00

0 1/

7/20

04)

Rei

nfor

cem

ents

New

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onne

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ns

Load

mov

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Rel

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and

qual

ity m

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d

Rel

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and

qual

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prov

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Envi

ronm

enta

l, sa

fety

and

lega

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SC

AD

A/N

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ork

cont

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Non

-net

wor

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nera

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- IT

Non

-net

wor

k ge

nera

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ets

- Oth

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TOTA

L G

RO

SS C

APE

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POSE

BA

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PEN

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LON

G T

ERM

FO

REC

AST


6. OPERATING AND MAINTENANCE EXPENDITUREREQUIREMENTS

6.1 Introduction

The Commission proposes to rely on reported actual operating and maintenanceexpenditure as the basis for developing the forecast for 2006 to 2010. In particular,the following process is proposed:

• Adjust the 2004 reported expenditure (excluding GSL payments) by the efficiencygain implied in the 2001 Determination for 2004 to 2005;

• Adjust the base cost for 2006 by an appropriate ‘rate of change’ to derive thebase costs for 2007 to 2010;

• Add to these base costs the increase in costs due to growth in customernumbers; and

• Add the additional costs due to step changes.

In relation to step changes in operating and maintenance costs, the Commission hassaid:30

“The onus is on the distributors to identify any changes which result in a stepexpenditure and provide appropriate supporting evidence.”

In accordance with this approach, the operating and maintenance expenditure for theCurrent Regulatory Obligations and the Safety Management Scenario is shown inTables 6.1A and 6.1B respectively.

Table 6.1A

TOTAL OPERATING AND MAINTENANCE COSTS – CURRENT REGULATORY OBLIGATIONS($M)2004 2005 2006 2007 2008 2008 2010 TOTAL

(2006-2010)

Base Costs 50.58 50.33 50.33 50.33 50.33 50.33 50.33 251.65Rate of Change 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00Cost of CustomerGrowth 0.06 0.12 0.17 0.23 0.30 0.88

Step Changes 11.71 12.34 12.76 13.28 14.20 64.28TOTAL 50.58 50.33 62.09 62.79 63.26 63.84 64.83 316.81

Table 6.1B

TOTAL OPERATING AND MAINTENANCE COSTS – SAFETY MANAGEMENT SCENARIO ($M)2004 2005 2006 2007 2008 2008 2010 TOTAL

(2006-2010)

Base costs 50.58 50.33 50.33 50.33 50.33 50.33 50.33 251.65Rate of change 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00Cost of customergrowth 0.06 0.12 0.17 0.23 0.30 0.88

Step changes 6.36 6.98 7.39 7.90 8.81 37.43TOTAL 50.58 50.33 56.74 57.43 57.89 58.46 59.44 289.96

30 Guidance Paper page 67.


The remainder of this Section discusses:

• Actual and Forecast Expenditure for 2001 to 2004;• Base Costs for 2006 to 2010; and• Costs due to step changes.

6.2 Expenditure for 2001 to 2004

The actual operating and maintenance costs for 2001 to 2003, as reported in theAGLE Regulatory Accounts and a forecast of the costs for 2004 are shown in Table6.2.

Table 6.2

ACTUAL/FORECAST OPERATING AND MAINTENANCE EXPENDITURE 2001 - 2004 ($M)2001 2002 2003 2004

Operating 34.60 36.30 36.65 37.00Maintenance 12.50 12.90 13.18 13.63TOTAL 47.10 49.20 49.83 50.63

Note: The operating and maintenance expenditure figures are before the adjustment of provisions

6.3 Base Costs for 2006 and 2010

6.3.1 Adjustment from 2004 to 2005

The adjusted operating and maintenance costs for 2004 and 2005 from the 2001Price Determination is shown in Table 6.3.

Table 6.3

OPERATING AND MAINTENANCE COST BENCHMARKS IN 2001 DETERMINATION ADJUSTEDFOR GROWTH ($M)Year Amounts2004 48.02005 47.8Change % 0.52

Based on the forecast operating and maintenance cost of $50.63 million in 2004,excluding the GSL payment and standard metering, the 2005 derived base Operatingand Maintenance costs, in 2004 dollars is $50.33 million.

6.3.2 Rate of Change

AGLE strongly opposes reducing forecast costs for future unidentified efficiencies.This is inconsistent with incentive regulation and places the distributor at significantrisk if these implied efficiencies cannot be realised.

The current regulatory regime includes an efficiency carryover mechanism to provideincentives for distributors to pursue efficiencies. Assuming a certain level ofefficiencies will be achieved significantly diminishes the effectiveness of themechanism, and puts at question the effectiveness of the regime. AGLE hasassumed a rate of change of zero.


6.3.3 Costs due to Customer Growth

The costs relating to customer service, and billing and revenue collection would beexpected to increase as a function of customer numbers. AGLE estimates that themarginal cost of these functions per customer is $12.76 (2004 dollars) based on the“Cost Allocation Report” prepared by KPMG on 28 September 2000.

The growth in customer numbers, as discussed in Section 4.3, for 2005 to 2010, andthe increase in operating and maintenance costs related to this growth, is shown inTable 6.4.

Table 6.4

COST INCREASE DUE TO CUSTOMER NUMBER GROWTH2004 2005 2006 2007 2008 2009 2010

Customer Numbers 279,720 283,916 288,494 293,274 297,531 301,895 307,271Increase from 2005 4,578 9,358 13,615 17,979 23,355Costs Increase ($M) 0.06 0.12 0.17 0.23 0.30

Note: Customer numbers as at the month of December

6.4 Cost of Step Changes

AGLE has identified a number of items for which it will incur costs in the 2006 to 2010period that are not reflected in the forecast expenditure for 2004, from which the basecosts are derived.

AGLE has assumed that Electricity Distribution License fees will remain constant atthe 2004 level in real terms.

These items are shown for the Current Regulatory Obligations and the SafetyManagement Scenario in Tables 6.5A and 6.5B respectively.


Table 6.5A

ADDITIONAL/STEP CHANGE OPERATING AND MAINTENANCE COSTS – CURRENTREGULATORY OBLIGATIONS ($000)

2006 2007 2008 2009 2010 TOTALRoad Management Act 2004 230 210 210 210 230 1,090Electricity Demand Side Response 110 110 110 110 110 550Head office relocation costs 400 400 0 0 0 800Additional Surge Compensation Claims 720 720 720 720 720 3,600Additional EWOV cases 40 40 40 40 40 200Inspection & testing of earthing systems 50 50 50 50 50 250Inspection & testing of service Neutrals,Bonding & Material

5,190 5,200 5,210 5,220 5,230 26,050

Transformer Platform Heights 50 50 50 50 50 250Vegetation Management 160 160 160 160 160 800Protection from Terrorist Attacks/Securitycosts

60 60 60 60 60 300

Rectify Faulty XLPE cable 100 100 100 100 100 500OCEI Audits 200 0 200 0 200 600Commission Regulatory Audits 140 140 140 140 140 700Additional Regulatory reporting costs 30 30 30 30 30 150Financial Report for 2009 RegulatoryFinancial Information

0 0 0 0 50 50

Ring-fencing 300 200 100 100 100 800Sponsorship & Marketing Scheme 100 70 70 70 70 380Public consultation on various matters 100 100 100 100 100 500Increase in real employment cost 1,810 2,380 2,960 3,570 4,200 14,920Additional Apprentices 920 1,310 1,500 1,590 1,590 6,910Gather and provide data on all publiclighting poles

90 90 20 20 20 240

Mobile Computing Implementation 400 400 400 400 400 2,000Outage Management, Market and BillingSystems

350 360 370 380 390 1,860

GSL Scheme payments( existing) 50 50 50 50 50 250GSL Scheme payments( new) 110 110 110 110 110 530TOTAL 11,710 12,340 12,760 13,280 14,200 64,280


Table 6.5B

ADDITIONAL/STEP CHANGE OPERATING AND MAINTENANCE COSTS – SAFETYMANAGEMENT SCENARIO ($000)

2006 2007 2008 2009 2010 TOTALRoad Management Act 2004 230 210 210 210 230 1,090Electricity Demand Side Response 110 110 110 110 110 550Head Office Relocation Costs 400 400 0 0 0 800Additional Surge Compensation Claims 720 720 720 720 720 3,600Additional EWOV cases 40 40 40 40 40 200Inspection & testing of earthing systems 50 50 50 50 50 250Inspection & testing of service Neutrals,Bonding & Material

0 0 0 0 0 0

Transformer Platform Heights 50 50 50 50 50 250Vegetation Management 0 0 0 0 0 0Protection from Terrorist attacks/securitycosts

60 60 60 60 60 300

Rectify Faulty XLPE cable 100 100 100 100 100 500OCEI Audits 200 0 200 0 200 600Commission Regulatory Audits 140 140 140 140 140 700Additional Regulatory reporting costs 30 30 30 30 30 150Financial Report for 2009 RegulatoryFinancial information

0 0 0 0 50 50

Ring-fencing 300 200 100 100 100 800Sponsorship & Marketing Scheme 100 70 70 70 70 380Public consultation on various matters 100 100 100 100 100 500Increase in real employment cost 1,810 2,380 2,960 3,570 4,200 14,920Additional apprentices 920 1,310 1,500 1,590 1,590 6,910Gather and provide data on all publiclighting poles

90 90 20 20 20 240

Mobile Computing Implementation 400 400 400 400 400 2,000Outage Management, Market and BillingSystems

350 360 370 380 390 1,860

GSL Scheme payments( existing) 50 50 50 50 50 250GSL Scheme payments( new) 110 110 110 110 110 530TOTAL 6,360 6,980 7,390 7,900 8,810 37,430

6.4.1 Road Management Act 2004

The Victorian Road Management Act provides road authorities with wide powers overthe use of road reserves. The detailed workings of the Act will not be known until thecodes of practice are developed in the next few years. It is anticipated that there willbe additional costs associated with negotiating and seeking permission for works.

6.4.2 Electricity Demand Side Response

There is increasing interest from energy network participants in demand sideresponse. Already AGLE is fielding a number of preliminary inquiries from partieswishing to undertake demand side response and AGLE is participating in aninternational study into network demand side management. Interest in demand sideresponse is likely to increase further as the Interval Meter Rollout occurs.

AGLE will face a number of new costs as specific demand side projects aredeveloped. These costs will include negotiating with potential demand sidesuppliers, developing technical and operating standards and legal costs associatedwith entering agreements with demand side suppliers.


6.4.3 Head Office Relocation Cost

The lease on AGLE’s current head office at 333 Collins Street is due to expire duringthe 2006 to 2010 period. While a decision as to the new location has not beenfinalised at this point in time, costs will be incurred in relocating.

6.4.4 Additional Surge Compensation Claims

In January 2001, the Commission introduced the “Electricity Industry Guideline No.11-Voltage Variation Compensation” (Guideline 11). Under Guideline 11, distributorsare required to pay compensation to customers who suffer loss or damage as aresult of a voltage variation. The customers affected are defined as those having anelectrical installation where the annual aggregate consumption of electricity is lessthan 160 MWh. The level of compensation is limited to the cost of repairs to anappliance. Where an appliance is beyond economical repair, the amount to be paidis the cost of replacing the damaged item with one of substantially the same age,functionality and appearance.

Since the commencement of Guideline 11, insurers have made limited attempts torecover the cost of claims administered by them for voltage variation related claims.Whilst these attempts to date have been limited, distributors have recently receiveddirection from the Commission that stipulated that a distribution business must nowaccept such claims from insurance companies due to the insurers ‘right ofsubrogation’.

Having considered legal advice on the matter, the Commission is of the view that aninsurance company that has paid out to a policyholder on a claim in connection withdamage caused by an unauthorised voltage variation has the right to claim from thedistributor any compensation payable to the policyholder under the Guideline. Assuch, AGLE will now be exposed to an increase in the number of claims.

Additionally, the Commission has indicated its intention to modify Guideline 11 torequire distributors to pay for new appliances to replace appliances less than 10years old. This will significantly increase the average amount paid by AGLE for eachclaim.

6.4.5 Additional EWOV Cases

Should a distribution business offer a customer an amount less than that claimed, inaccordance with Guideline 11, the distribution business is obliged to inform thecustomer of their right to raise the complaint with the Energy and Water Ombudsman(EWOV). This process exposes AGLE to costs from the EWOV to administer thecomplaint and determine whether the amount offered by the distribution business isin accordance the Guideline 11.

As discussed in Section 6.4.4, the number of surge compensation claims is expectedto increase. Thus, it follows that the number of claims that are raised with the EWOVwill also increase.


6.4.6 Inspection and Testing of Earthing Systems

The Electricity Safety (Network Assets) Regulations 1999 contain a requirement forall earthing systems, except Common Multiple Earthed Neutral (CMEN) systems tobe inspected for compliance every ten years. The regulations, in some cases,impose lower earth resistances (a higher, more difficult to attain standard) thanrequired under usual industry design standards. The proposed expenditure providesfor the extension of rural earth testing to concrete poles, in areas where CMEN is notproposed, and for augmentation of earthing systems at rural substations and at ruralconcrete poles.

Although this is a safety issue, the additional operating and maintenance costsproposed for this activity would be the same under the Current RegulatoryObligations and the Safety Management Scenario.

6.4.7 Inspection and Testing of Service Neutrals, Bonding and Materials

The Safety Regulations require an integrity test to be conducted on the neutralconnection of customer services at least every ten years. Currently, a practical testhas been adopted that is being carried out at the connection point between eachelectricity customer’s electrical installation and the electricity distribution system.This practical test, whilst in accordance with OCEI guidelines, does not achievecomplete compliance with the Safety Regulations. Literal interpretation of theregulation requires each customer to be notified and disconnected from supply whilea more sophisticated test is performed. This process is more complex and labourintensive than the current process.

Arrangement and material requirements for overhead services were changed in1999. The regulation accords with practice at the time of the regulation but not withearlier practices. The inspection program for services reveals a number of serviceswhich do not comply with current regulation and which should be replaced.Allowance is made for the detection and replacement of services, the material ofwhich met standards that applied at the time of construction, but which do not complywith the 1999 regulations.

Costs are based on extrapolation of the extensive results that have been gatheredfrom the existing service inspection program and the average costs of servicereplacement.

Under the Safety Management Scenario, there would be no additional costs in thisarea.

6.4.8 Transformer Platform Heights

Minimum heights for pole mounted transformers adjacent to roads were increased in1988 so that older installations may not comply. Road widening has reducedclearance of transformers from roads in some cases.

AGLE has a program of work, which involves survey and risk assessment of non-complying transformers. Rectification of non-compliant transformers in a risk basedpriority order will take place over a number of years.

However, the safety regulations require all non-complying transformers, even thoseprotected by other structures, to be rectified.


Costs have been based on an initial sample survey undertaken to estimate thedegree of non-compliance and estimates of rectification costs based on the availablerectification methods.

The additional costs proposed for this activity would be the same under the CurrentRegulatory Obligations and the Safety Management Scenario.

6.4.9 Vegetation Management

Tree clearing requirements are regulated in terms of “clearance at all times”. Currentpractices ensure that in hazardous bushfire risk areas the clearance space ismaintained at all times during the fire season and in low bushfire risk areasvegetation is allowed to enter the clearance space between cycles.

To ensure that the clearance space is not encroached between cycles, compliancewould require a combination of more frequent inspection and cutting, and much moresevere cutting.

Under the Safety Management Scenario, there would be no additional costs in thisarea.

6.4.10 Protection from Terrorist Attacks / Security Costs

As a result of the increasing threat of terrorism, AGLE is undertaking reviews of thesecurity of key infrastructure.

These reviews have identified that the risk to customers from terrorist activities whichaffect the electricity network are low across much of the network. However there aresome parts of the network that present a higher risk. These reviews are focussed onthese areas of higher risk and has lead to a number of initiatives to improve securityof key installations, including system control centres, sub-transmission lines andzone substations. These initiatives will involve both capital (see safety & security inTable 5.8 Section 5.3.6) and operating expenditure. Operating expenditure willinvolve items such as additional patrols of key infrastructure and remote monitoringof alarms by accredited security service providers.

6.4.11 Rectification of faulty XLPE cable

HV XLPE (Cross-linked Polythene insulated) cable was introduced approximately 25years ago. The initial cables were manufactured using a steam curing process.Water in contact with XLPE insulation is now known to cause premature failure of theinsulation by a process known as “treeing.”

It is estimated that recently manufactured XLPE cables will have an operating life ofapproximately 40 years, whereas AGLE assets are experiencing some failure of theinitial manufacture. AGLE will incur additional operating and maintenanceexpenditure in identifying and monitoring suspect cables.

6.4.12 OCEI audits

The OCEI undertook a major audit of all of the electricity distribution businesses in2001. Delivery of reports and other follow up actions were not completed until 2003.The OCEI levy was increased in one year by $300,000 to cover the cost of the audit.


It is understood that in the future the OCEI will undertake more frequent audits,targeted at specific areas and three audits are anticipated during the regulatoryperiod.

In addition, AGLE has submitted an Electricity Safety Management Scheme (ESMS)to OCEI. The Electricity Safety Act allows the OCEI to require independent audits ofthe ESMS and it is good practice for the ESMS to be subject to regular externalaudits. It is anticipated that annual external audits of the ESMS will be undertaken.

6.4.13 Commission Regulatory Audits

The Commission has indicated that in the future Regulatory Audits will be performedevery year. Over the current regulatory period there has been one audit. There havecurrently been minimal costs incurred in 2004 for regulatory audits. The cost ofundertaking additional audits includes the cost of inviting and selecting auditors, auditfees and legal fees associated with audit deeds and contracts.

6.4.14 Additional Regulatory Reporting Costs

The Commission is currently undertaking a review of regulatory accounts and theregulatory reporting process. It is likely that the outcome of this review will lead toadditional costs for AGLE in relation to audits.

6.4.15 Financial Report for 2009 Regulatory Financial Information

AGLE has been in discussions recently with the Commission about the timing ofregulatory accounts in relation to AGLE’s statutory accounts. In particular, as AGL isan Australian listed company, it prepares its accounts on a financial year basis (ie 1July to 30 June). However, Guideline 331 requires regulatory accounts to beprepared on a calendar year basis (ie 1 January to 31 December). Additionally,Guideline 3 also requires that the regulatory accounts are derived from the statutoryaccounts32 and that they are audited33.

The Commission and AGLE have agreed alternative arrangements whereby AGLEwill provide regulatory accounts on a statutory year basis and summary informationon a financial year basis. Also, in the penultimate year before a Price Review (ie2004, 2009, etc) AGLE will be required to provide audited regulatory accounts on acalendar year basis. The net effect of this is that AGLE will incur additional costs in2009 to:

• Prepare a set of half-year accounts for the period 1 July 2009 to 31 December2009;

• Have these accounts audited;• Prepare an additional set of regulatory accounts for the 2009 calendar year; and• Have these audited.

31 Essential Services Commission (2004) “Electricity Industry Guideline No. 3 – Regulatory informationrequirements – issue no. 4” January 2004 clause 4.5.1.32 ibid, clause 3.5.1.33 ibid, clause 4.43.


6.4.16 Ring-fencing

As discussed in Section 2.6, the Commission released its Draft Decision and draftguidelines in relation to ring-fencing in March 2004. In order for AGLE to becompliant with the draft guidelines and to remain compliant over the period, it will benecessary for AGLE to carry out a number of activities, including:

• Some locational changes to ensure appropriate separation of staff;• Review a number of existing procedures;• Ongoing training; and• Internal auditing and review to ensure compliance.

The cost of these activities are shown in Table 6.6.

Table 6.6

RING-FENCING ($000)2006 2007 2008 2009 2010 TOTAL

Locational Changes 100 0 0 0 0 100Training 50 50 50 50 50 250Review Procedures 50 50 0 0 0 100Compliance Auditing 0 50 50 50 50 200IT Enhancements 100 50 0 0 0 150TOTAL 300 200 100 100 100 800

6.4.17 Sponsorship and Marketing

AGLE has included in its Submission additional Sponsorship and Marketingexpenditure for the 2006 to 2010 period. AGLE believes that contributing to bothmarketing schemes and sponsorships is an effective tool to promote awareness andgrowth within the AGLE network area.

AGLE has allowed for expenditure in 2006 to provide comprehensive information toelectricity retailers about the multiple supply tariffs offered by AGLE in certaincircumstances where a distribution customer has multiple supply points at one site(see Section 10.3.2). The multiple supply tariff allows distribution customers to“aggregate” the metered consumption for more than one supply point, thus allowingthe customer to be assigned to an appropriate network tariff based on the usagecharacteristics of the combined supply points.

AGLE has also allowed for the funding of a number of economic development groupsthat cover the AGLE network area. The aim of these groups is to stimulate economicgrowth within various regions in Australia. These groups rely heavily on localgovernment and business funding and support to continue. By sponsoring theseeconomic development groups, AGLE is provided with access to strategic decision-makers and information on future developments, particularly in the AGLE networkarea, which assists AGLE in planning and development of the network.


These projected costs are shown in Table 6.7.

Table 6.7

SPONSORSORSHIP & MARKETING ($000)2006 2007 2008 2009 2010 TOTAL

Marketing 25 0 0 0 0 25Sponsorship 71 71 71 71 71 355TOTAL 96 71 71 71 71 380

6.4.18 Public Consultation

AGLE has recognised a need to carry out more customer and stakeholderconsultation, particularly in areas such as network pricing and network development.This need is emphasised in the process for deviating from the five-year tariff report.34

“If a distributor wishes to deviate from the information and strategy outlined inthe tariff report, the distributor would be required to demonstrate that thevariation had been consulted on with customer groups, and an amendedreport would then need to be published.”

6.4.19 Total Employment Costs

AGLE’s observations in the market support the view that sectoral wage rates areexpected to increase over the 2004 to 2010 period, due to significant increases ininvestment in electricity infrastructure in Australia and a smaller and aging workforce.Accordingly, AGLE has escalated field and technical labour rates. The amountincluded as a step change represents the effect of this increase on the baseoperating and maintenance costs.

6.4.20 Apprentices

AGLE is addressing the increasing demand for skilled technical through a plannedand systematic approach to recruitment of apprentice linesman and technicaltrainees. The ratio of apprentices and trainees to the technical staff is currently 25%,with increased recruitment levels planned over the next five years.

Forward and prudent planning completed in 2003 indicated that the intake ofapprentices needs to increase in 2005 to eight per year. As the number of qualifiedand experienced tradesmen increases, the intake of apprentices could alsoproportionally increase. The plan in 2007 to 2010 is to increase the intake ofapprentices to fifteen each year, to replenish the ranks of suitably qualifiedtradesmen to support the network into the future.

In determining the additional operating cost, AGLE has recognised that apprenticesdo provide some productive output, particularly in the latter years. The additionalcosts reflect 100% of the costs of a first year apprentice, 75% of the costs of asecond year apprentice, 50% of the costs of a third year apprentice and only 25% ofthe costs of a fourth year apprentice.



6.4.21 Gather and Provide Data on all Public Lighting Poles

In the Final Decision on the Review of Public Lighting Charges in August 2004, theCommission required distributors to collect, record and disseminate additional assetinformation on public lighting in accordance to the Public Lighting Code35.

This new obligation will require AGLE to determine the date of installation and thepole types of public lights. AGLE proposes to carry out an audit of the public lightingpoles to collect and/or confirm this data. The audit is expected to be carried out overa number of years due to the large number of lights. The current IT software andprocess relating to the storage and retrieval of these additional asset data will bemodified and expanded accordingly.

In addition, AGLE proposes to provide additional technical support and training onthe use of the modified software to service customer inquiries for this and otherpublic lighting data.

6.4.22 Mobile Computing Implementation

The investment in a mobile computing system, with host systems connectivity, willallow the extension of workflow, work organisation and organisation correspondenceinto the field. The implementation of a new mobile computing system will require thecontracted support from the vendor for maintenance of the core product, correction ofsoftware defects and response to technical queries. The on-going support will allowAGLE to achieve the maximum benefit from the investment in this new IT application.

6.4.23 Outage Management, Market and Billing Systems

A new outage management system will leverage off the integration with the plantmaintenance, project systems, materials management, finance and human resourceSAP modules. This will require the contracted support from the vendor formaintenance and enhancements of the core product, correction of software defectsand response to technical queries. The on-going support will allow AGLE to achievethe maximum benefit from the investment in this new IT application.

AGLE’s Retailer Support Group (RSG) provides operational support for customertransfers, business to business information exchange (B2B) and tier-2 networkbilling. The support of these functions requires occasional systems investigationsand systems modification or enhancement.

35 Clauses 5.1.2(e) and 5.12(I) of Public Lighting Code September 2001. Essential ServicesCommission.


6.4.24 GSL Payments (Current and New)

The Guidance Paper (page 67-68) required AGLE to remove the cost of payingGSL’s from its 2004 operating and maintenance costs for the purpose of developingthe base operating costs. The cost of GSL payments is a legitimate business costand should be allowed for in AGLE’s required revenue. This is supported by theCommission in the Guidance Paper, where it says that one of the principles for whichany changes to the GSL scheme should be based is:36

“It may not be economically efficient to improve the reliability for theseparticular customers. Where reliability is not improved, the GSL paymentsare an acknowledgment to these customers that this may be the case.”

Consequently, the payment of GSL’s needs to be seen not only as an incentivemechanism but also as an alternative to investment in service improvement wherethis is the most economically efficient alternative.

Further, if the cost of GSL’s is not allowed for in the required revenue, the payment ofGSL’s would constitute an asymmetric risk.

AGLE has recognised the current level of GSL payments as well as the additionalGSL payments under the enhancements to the scheme detailed in Section 3.6.

6.5 Transmission Related Charges

AGLE incurs costs associated with the use of and connection to the transmissionsystem as well as inter-network provider distribution charges and embeddedgenerator payments. These costs are passed onto network customers in the form oftransmission tariffs.

Table 6.8 shows the Transmission Related charges for the period 2004 to 2010.Each of these items is discussed in the following Sections.

Table 6.8

TRANSMISSION RELATED CHARGES ($M)2004 2005 2006 2007 2008 2009 2010 TOTAL

TUoS charges 28.02 34.76 35.48 35.99 36.20 36.20 36.20 242.85GPU connecting fees 6.08 6.48 6.54 6.53 6.58 6.87 7.19 46.27Cross boundarynetwork charges -0.91 -0.98 -1.27 -1.26 -1.25 -1.25 -1.24 -8.16

Payment toembedded generators 0.70 0.68 0.67 0.37 0.21 0.21 0.10 2.94

TOTAL 33.89 40.94 41.42 41.63 41.74 42.03 42.25 283.90

6.5.1 VENCorp Charges

VENCorp charges cover the following costs:



• Transmission Use of System charges - These charges cover the costs incurredby SPI PowerNet to provide and maintain the transmission system and the costsincurred by VenCorp in operating the transmission system;

• Land tax on transmission easements. AGLE estimated the Transmission Use ofSystem charges and the land tax on transmission easements based on theinformation provided in Table 1 of the ACCC’s letter of 3 May 2004 (VENCorpapproved letter), in which the ACCC has approved VENCorp’s application foradjustment of VENCorp’s maximum allowable aggregate revenue. AGLE hasestimated its share of the overall expenditure and tax liability to be 10%;

• Equalisation payment. This has been projected in accordance with Clause 4.6and Attachment 7 of the Victorian Electricity Supply Industry Tariff Order; and

• Settlement residue that causes a reduction in VenCorp charges. This has beenprojected to be in line with current level.

6.5.2 SPI PowerNet Connecting Fees

The SPI PowerNet connecting fees consist of the prescribed charge, and theexcluded charge.

AGLE has projected that the prescribed charge will remain at current levels, whichhave been approved by the ACCC.

The excluded charge represents charges for ongoing contracts that are currently inplace between AGLE and SPI PowerNet. AGLE has also incorporated into theprojection amounts for additional excluded charges related to new works.

6.5.3 Inter-Network Provider Distribution Service Charges/Revenue

The inter-network provider distribution service charges (revenue) are derived bymultiplying projected delivered energy in a given year by current network prices.

6.5.4 Payments to Embedded Generators

Payments to embedded generators comprise payment for avoidable transmissioncosts and avoidable TUoS usage charge.

The payments for avoidable transmission costs have been estimated based on theTransmission Network Support payment schedule as approved by the Commission.

The avoidable TUoS usage charges have been estimated as follows:

• Firstly, estimate the incremental maximum demand that would have beenrecorded on the system had the embedded generator not been connected; and

• Secondly, multiply the incremental maximum demand calculated in step 1 by aprojected TUoS usage charge.

6.6 Executive remuneration

The Commission requires disclosure of the executive remuneration of persons whoare concerned or take part in the management of AGLE and whose Remunerationamounts to or exceeds specified levels (definition of "Executive Remuneration"). Inthe context of a corporate group such as AGL, there is uncertainty as to whether aparticular person falls within the scope of this template given the nature of the reviewbeing conducted by the Commission.


Accordingly, AGLE has shown the portion of executive remuneration of all Directorsand other persons who are regarded as taking part directly in the management ofAGLE's distribution business, and whose remuneration amounts to or exceeds thespecified level. The remuneration received by the Directors and other persons hasbeen allocated between their involvement in management of AGLE and otheractivities.

Executive Remuneration is forecast to be constant at $980k per annum in 2004dollars. The net number of executives included is 9.1 (ten executives of which 0.9 ofa person is allocated to excluded and other services).



7. Efficiency Carryover Mechanism

7.1 Introduction

The Efficiency Carryover Mechanism is an integral part of the regulatory regime,ensuring that distributors receive reward for efficiency improvements and providing amechanism for ultimately passing cost reductions to customers.

This Submission assumes the continuation of the Efficiency Carryover Mechanismfor the 2006 to 2010 period.

This Section discusses:

• The carryover amount from the 2001 to 2006 period; and• The Efficiency Carryover Mechanism to apply to the 2006 to 2010 period.

The Commission has noted the appeal panel outcome following the 2001 PriceDetermination and proposes to adjust the benchmarks set in the 2001 to 2005 reviewfor actual growth. Further, the Commission has sought to confirm the process foradjusting the benchmarks for the 2006 to 2010 period. These matters are alsodiscussed.

7.2 Calculation of the 2001 to 2005 period Efficiency Carryover amount

7.2.1 Adjustment of Reinforcement/Augmentation Benchmark

In order to adjust the efficiency carryover to recognise actual demand growth, theCommission proposed that the models that were used to determine thereinforcement and augmentation capital expenditure benchmarks for the 2001 to2005 period be re-run with the demand growth forecast at that time replaced with theactual demand growth that has occurred. AGLE supports this approach.

AGLE retained PB Associates to re-run their 1999/2000 Growth model. The model,supplied by the Commission (to AGLE), was given to PB Associates and AGLEprovided the necessary input information. PB Associates then re-ran the model toprovide the revised capital benchmark based on actual demand growth.

The forecast growth rate for the 2001 to 2005 period was 2.09%. The actualtemperature corrected demand growth rate was above forecast at 2.54%. Thetemperature corrected growth rate represents the demand level for the 50th percentilemaximum temperature (see Section 4.5.1.4). Table 7.1 details the additionalcalculated capital expenditure that would have been required to reinforce the networkto meet demand growth in excess of forecast.

Table 7.1

CAPITAL EXPENDITURE – ADJUSTMENT FROM PB ASSOCIATES MODEL ($000)2001 2002 2003 2004 2005

Difference in Capital Expenditure Benchmark 4,040 4,360 4,720 5,110 5,540


7.2.2 Adjustment of Customer Connection Benchmark

Customer growth has been significantly in excess of the forecast for the 2001 to 2005period.

At the time that the 2001 to 2005 forecast was prepared, economic forecasters werepredicting a downturn in new housing due to the introduction of the GST and theoutlook for general economic activity was bleak. The actual result has been quitedifferent. Factors such as low interest rates and the new homebuyer’s grant(s) haveboosted new housing to record levels. Also, economic activity has been moderatelystrong. The result is that more customers were connected to the network than wasforecast.

Table 7.2 shows the adjustment due to actual customer connections.

Table 7.2

ADJUSTMENT FOR CUSTOMER CONNECTIONS2001 2002 2003 2004 2005 TOTAL

Forecast of Customer Connectionsfrom 2001 Determination

2621 2537 3023 3277 3133 11,838

Actual / forecast Connections 7217 6520 6813 6637 6348 18,944Net Average Cost of Connections(2004 dollars)

2,373 2,439 2,257 2,277 2,492 2,368

Cost Adjustment ($000) 10,905 9,716 8,554 7,650 8,011 44,836

7.2.3 Adjustment of Operating Expenditure

Customer Service, and Billing and Revenue Collection are operating activities thatincrease with customer numbers.

Along with the greater number of customer connections as compared to the 2001 to2005 forecast, actual customer numbers were also higher than forecast. During the2001 Price Review KPMG were engaged to review the operating costs of thedistributors. From the results of this review, the marginal operating cost percustomer averaged across all the distributors was $9.02 per customer in 2004dollars.

Table 7.3 shows the required adjustment to the operating and maintenance costbenchmark for actual customer numbers.

Table 7.3

ADJUSTMENT TO OPERATING COSTS2001 2002 2003 2004 2005 TOTAL

Forecast CustomerNumbers from 2001Determination

255,600 258,137 261,160 264,436 267,569 1,306,902

Actual/ForecastCustomer Numbers 263,043 269,166 275,635 279,720 283,919 1,371,48

3Average Marginal Costper Customer (2004dollars)

9.02 9.02 9.02 9.02 9.02 9.02

Cost Adjustment ($000) 67 99 131 138 147 583


7.2.4 Efficiency Carryover Amount for 2006 to 2010

The Efficiency Carryover amounts to be included in the required revenue for 2006 to2010 for the Current Regulatory Obligations and the Safety Management Scenarioare shown in Tables 7.4A and 7.4B respectively.

Table 7.4A

EFFICIENCY CARRYOVER AMOUNTS – CURRENT REGULATORY OBLIGATIONS ($M)2006 2007 2008 2008 2010

Operating Efficiency Carryover -2.5 -8.6 -2.0 0.6 0.0Capital Efficiency Carryover 9.4 6.5 4.3 1.8 0.0TOTAL 6.9 0.0 0.1 2.4 0.0

Table 7.4B

EFFICIENCY CARRYOVER AMOUNTS – SAFETY MANAGEMENT SCENARIO ($M)2006 2007 2008 2008 2010

Operating Efficiency Carryover -2.5 -8.6 -2.0 0.6 0.0Capital Efficiency Carryover 9.5 6.6 4.3 1.9 0.0TOTAL 7.0 0.0 0.2 2.4 0.0

Note: The difference in efficiency carryover amounts is due to different effective after tax WACC causedby variations in the average tax wedge caused by the different tax liabilities.

7.3 The 2006 to 2010 Period Efficiency Carryover

7.3.1 Proposed Efficiency Carryover Mechanism

AGLE supports the maintenance of a mechanism to reward distributors for pursuingefficiencies. However AGLE believes that the current proportion of the benefits thataccrue to distributors of approximately 30% is insufficient. Significant improvementsin efficiency have been obtained and passed through to customers. However, therealisation of further efficiencies becomes harder as the distributors become moreefficient. As the realisation of efficiencies become harder, the reward for obtainingefficiencies must increase.

In order to allow the 2006 to 2010 benchmarks to be adjusted at the next pricereview, the Commission has requested distributors to provide for the 2006 to 2010period:

• The forecast marginal cost per MVA of network reinforcement;• The forecast average cost of customer connections; and• The average marginal operating and maintenance cost per customer.

These matters are discussed in the following Sections.

7.3.2 Marginal Cost of Reinforcement/Augmentation

The marginal cost of reinforcement has been estimated based on analysis of recentlycompleted projects. This approach leads to a cost that includes all the activitiesrequired to augment or reinforce the network, not just the direct cost of construction.For example the cost will include items such as community consultation and ElectroMagnetic Field (EMF) studies.


This marginal cost has been reviewed by PB Associates and applied in the currentgrowth model. The marginal cost of reinforcement/augmentation is shown in Table7.5.

Table 7.5

MARGINAL COST OF AUGMENTATION / REINFORCEMENT ($000)2006 2007 2008 2009 2010

Marginal Cost per MVA 290 295 302 308 315

7.3.3 Average Cost of Customer Connections

The average cost of customer connections for the 2006 to 2010 period is based onthe actual average cost of connection over recent years. The forecast average costof customer connections is $1950 per connection in 2004 dollars.

7.3.4 Marginal Operating Cost

The marginal operating cost per customer has been based on the average of thehigh and low benchmark for AGLE from the previous KPMG report, in 2004 dollars.The marginal operating cost per customer is $12.76.


8. Cost of Capital Financing

8.1 Introduction

This Section addresses the cost of capital financing for AGLE. This Section details:

• The opening asset base (including actual asset disposals and additions);• Forecast return of capital (regulatory depreciation);• The rate of return (weighted average cost of capital) with details of the underlying

assumptions and analysis used to support the relevant parameters; and• The benchmark tax liability.

8.2 Opening Value of the Regulated Asset Base

The opening asset base for the commencement of the 2006 to 2010 period iscalculated by the following equation, where all amounts are expressed in 2004dollars.

Asset Asset Actual/Forecast Actual/Forecast RegulatoryBase = Base + Net Capex - Net Disposals - Depreciation

1/1/06 1/1/00 1/1/06-31/12/05 1/1/06-31/12/05 1/1/06-31/12/05

8.2.1 Roll forward of asset base from 2000

The roll-forward of the asset base (in 2004 dollars) for the regulatory periodcommencing 1 January 2006 is set out in Table 8.1.

Table 8.1

REGULATORY ASSET BASE ($M)2000 2001 2002 2003 2004 2005

Opening RAB 569.2 572.4 578.1 572.4 563.5 562.4Add Capital Expenditure 42.7 44.1 39.9 39.8 44.6 58.7Less Customer Contributions 8.7 5.6 7.3 7.2 4.7 1.8Less Disposals 0.4 0.1 1.7 2.5 - -Less Regulatory Depreciation 30.4 32.7 36.7 39.0 41.0 42.5Closing RAB 572.4 578.1 572.4 563.5 562.4 576.8

8.2.2 Capital Expenditure

The capital expenditure for 2000 to 2003 is based on actual historical expenditure.However, the historical annual capital expenditure numbers adopted by theCommission omit capital expenditure “transferred”. The transfer components of theactual capital expenditure represent the transfers from work-in-progress to theindividual asset components in the asset register and are reported in the Fixed Assetschedules in the Regulatory Accounts.

A forecast capital expenditure for 2004 has been included, and the forecast capitalexpenditure for 2005 is as allowed in the 2001 Price Determination.


Capital Expenditure amounts in Table 8.1 also include AGL Corporate IT capitalexpenditure specifically identified as electricity distribution network assets. Thesecapital amounts include an allocation of the electricity network share of group-widePC upgrades, as well as enhancements and upgrades to group-wide systems andhardware. These amounts have not previously been included in the RegulatoryAccounts.

8.2.3 Customer Contribution

Customer contribution figures are derived from the same approach described inSection 8.2.2.

8.2.4 Regulatory Depreciation

Regulatory depreciation included is the forecast regulatory depreciation allowed inthe 2001 Price Determination.

8.2.5 Disposals

Actual disposals for the 2000 to 2003 period have been included. No disposals havebeen identified for 2004, and no disposals were included the 2001 FinalDetermination for 2005.

8.3 Return of Capital (Regulatory Depreciation)

Regulatory depreciation for the 2006 to 2010 period for the Current RegulatoryObligations and the Safety Management Scenario is shown in Tables 8.2A and 8.2Brespectively.

Table 8.2A

TOTAL REGULATORY DEPRECIATION – CURRENT REGULATORY OBLIGATIONS ($M)2006 2007 2008 2009 2010 TOTAL

Subtransmission 3.4 3.6 3.8 4.0 4.1 18.9Distribution system assets 19.2 20.7 22.3 24.0 25.4 111.7Standard metering 3.8 3.3 3.8 5.7 5.4 22.1Public lighting 1.5 1.5 1.4 1.2 1.1 6.8SCADA/Network control 0.2 0.3 0.4 0.6 0.7 2.1Non-network general assets - IT 5.8 6.9 7.4 6.8 7.9 34.8Non-network general assets - Other 2.9 2.9 3.2 3.0 2.9 14.9TOTAL 36.7 39.2 42.4 45.3 47.7 211.3

Table 8.2B

TOTAL REGULATORY DEPRECIATION – SAFETY MANAGEMENT SCENARIO ($M)2006 2007 2008 2009 2010 TOTAL

Subtransmission 3.4 3.6 3.8 4.0 4.1 18.9Distribution system assets 18.7 19.3 19.9 20.6 21.1 99.6Standard metering 3.8 3.3 3.8 5.7 5.4 22.1Public lighting 1.5 1.5 1.4 1.2 1.1 6.8SCADA/Network control 0.2 0.3 0.4 0.6 0.7 2.1Non-network general assets - IT 5.8 6.9 7.4 6.8 7.9 34.8Non-network general assets - Other 2.9 2.9 3.2 3.0 2.9 14.9TOTAL 36.3 37.8 40.0 41.9 43.3 199.3


8.3.1 Method Applied

Regulatory depreciation projections for 2006 to 2010 have also been calculatedbased on a straight-line depreciation methodology, consistent with the approachused for the 2001 Price Determination.

8.3.2 Asset Lives

To ensure consistency, the asset lives used for this Submission are based on thoseused for the 2001 to 2005 period. The asset life of each asset class is shown inTable 8.3.

Table 8.3

ASSET LIVES FOR NETWORK ASSETS (YEARS)Asset Categories Asset Life

Distribution Control and Monitoring Equipment 15HV Meters / Timeswitches 15HV O/H Conductor 58HV Poles and Pole Tops 50HV Switchgear and Protection 35HV U/G Cable 46LV Meters / Timeswitches 39LV O/H Conductor 70LV Poles and Pole Tops 45LV Switchgear and Protection 33LV U/G Cable 50Public Lighting Poles 45Services 40 - 44Sub-transmission Control and Monitoring Equipment 42Sub-transmission Meters / Timeswitches 15Sub-transmission O/H Conductor 60Supervisory Cables and Equipment 60Sub-transmission Poles and Pole Tops 56Sub-transmission Transformers 50Sub-transmission Switchyard Equipment 58Street Lights 20Sub-transmission Reactive Plant 44Sub-transmission U/G Cable 70Transformers (distribution) 46Zone Substation Buildings 48

The asset lives for non-network assets are shown in Table 8.4.

Table 8.4

ASSET LIVES FOR NON-NETWORK ASSETS (YEARS)Asset Categories Asset Lives

Buildings 50Motor Vehicles 4 - 8Plant and Equipment 5-20Computer 4Software Development 7


8.3.3 Accelerated Depreciation for Accumulation Meters

According to Statement of Accounting Concept (SAC) No. 4, assets are defined asthe “future economic benefits controlled by the entity as a result of past transactionsor other past events”. Accordingly, the accounting treatment for accumulation metersreplaced by interval meters should be to fully depreciate their remaining value at thetime that they are replaces as they no longer generate future economic benefits.

By applying this accounting principle, the regulatory value of the accumulation metersincluded in the Regulated Asset Base (RAB) should be fully depreciated as and whenthey are replaced. The regulatory depreciation in Table 8.2 includes an amount of$3.6m attributable to the accelerated depreciation of the accumulation meters for the2006 to 2010 period.

8.4 Regulatory Asset Base 2006 to 2010

The Regulatory Asset Base for the Current Regulatory Obligations and the SafetyManagement Scenario is shown in Tables 8.5A and 8.5B respectively.

Table 8.5A

REGULATORY ASSET BASE – CURRENT REGULATORY OBLIGATIONS ($M)2006 2007 2008 2009 2010


Table 8.5B

REGULATORY ASSET BASE – SAFETY MANAGEMENT SCENARIO ($M)2006 2007 2008 2009 2010



8.5 Return on Capital

In the Guidance Paper, the Commission has set out its proposed approach todetermining the applicable return on capital for the electricity distribution businesses.The Commission proposes to estimate the real after tax cost of capital using the'‘vanilla WACC37" approach. The following is the applicable formula:

WACC = Re (E/V) + Rd (D/V),

where Re is the (real) cost of equity, Rd is the (real) cost of debt and E, D and V arethe values of equity, debt and assets respectively.

The after-tax cost of equity is to be estimated using the Capital Asset Pricing Model(CAPM) as follows:

Re = Rf + βe x MRP,

where Rf is the risk free rate of return (real), βe is the estimated equity beta and MRPis the market risk premium.

The cost of tax is to be treated separately to the cost of capital through a calculationof the tax wedge to be included in the required revenue as a cost.

8.5.1 Calculating WACC

In determining an appropriate value for the WACC to be used in deriving tariffs forthis Submission, AGLE has recognised that the estimation of the WACC has a largedegree of imprecision and uncertainty. This uncertainty arises because the CAPMcannot measure the costs of capital, but only estimate it on the basis of portfoliotheory. In addition, all of the variables to be used in the CAPM and WACC have adegree of measurement error, though some have a lot more than others. The mostproblematic variables are the MRP and the equity beta. There is also considerableuncertainty in determining the cost of debt, because debt margins are not readilyobservable.

In order to overcome the problem of measurement error, AGLE has adopted anapproach to estimating an appropriate WACC that applies a statistical methodology.This methodology recognises the probability distribution of variables that havematerial uncertainty, and combines them into a probability distribution using a MonteCarlo simulation.

The WACC variables used in the Monte Carlo simulation and the appropriate rangesand distribution characteristics are set out in Table 8.6.

37 WACC – Weighted Average Cost of Capital.


Table 8.6

WACC VARIABLES (%)Variable Value / Distribution

Real Risk Free Rate 2.79Market Risk Premium Mean: 6.0

Standard Deviation: 1.8Normal distribution

Equity Beta 0.9 – 1.0Uniform distribution

Gearing 60Debt Margin 1.51 – 1.71

Uniform distributionWACC (80th percentile of distribution) 6.7Gamma 30

The Monte Carlo simulation to determine the probability distribution of the WACCwas undertaken for AGLE by Strategic Finance Group Consulting (SFG). Variablevalues were determined based on the parameter value ranges recommended byKPMG and probability distributions were assigned to some variables. Furtherinformation on the choice of values and/or probability distributions is contained in theSFG Consulting and KPMG reports, which are in Appendices K, L and M.

The Monte Carlo simulation undertaken by SFG has produced a probabilitydistribution for the WACC with a median of 6.2%, a minimum of 4.8% and amaximum of 7.7%. SFG Consulting has identified a range of percentiles between the75th and 80th that it considers appropriate for the purposes of determining aregulatory WACC.

Based on the analysis by SFG Consulting in its report in Appendix L AGLE considersthis range as the most appropriate range.

As identified by the Productivity Commission in its reports on the National AccessRegime38, if the regulatory WACC is set too low, this will act as a deterrent to efficientinvestment. In this report, the Productivity Commission recommended that Part IIIA ofthe Trade Practices Act be amended to include pricing principles which would,among other things, state that regulated access prices should be:

• set so as to generate expected revenue across a facilities regulated services thatis at least sufficient to meet the long-run costs of providing access to thoseservices; and

• include a return on investment commensurate with the regulatory and commercialrisks involved.

Substantially the same pricing principles (which have been endorsed by theCommonwealth Government) are repeated in the Productivity Commission’s reporton the Gas Access Regime. The National Access Regime report explains therationale behind these principles39 as being to “set a relatively clear floor to revenueallowed within the access regime to facilitate investment in the essential service”. Inaddition, revenue should be related to costs, “but in a way which provided headroomfor revenue and prices to be above costs provided that this did not significantlyimpede efficient use of the service.” The underlying understanding behind theseprinciples is that there is much more to be lost by any under-estimate of costs than

38Productivity Commission (2002) “Review of the National Access Regime” September 2002, page 338.39 Ibid, page 330.


an over-estimate. Use of a WACC estimate between the 75th and 80th percentiles inestablishing the regulated cost of capital is consistent with these principles. The useof the median or 50 percentile provides only a 50 percent chance that the regulatedallowance will be sufficient to enable AGLE to meet its actual cost of capital. AGLEsubmits that given the economic risks this probability is too low.

Research described in the SFG Consulting Group (Appendix L) report providesstrong evidence that corporations set their hurdle rates for investments at asignificant margin above their cost of capital. The use of a regulatory cost of capital,which provides a better than even chance of it being high enough to cover thebusiness’ true cost of capital is consistent with corporate practices for investment.More importantly, it will also provide better incentives for efficient investment.

While the exact point on the distribution that is the appropriate landing is open todebate, AGLE has adopted the 80th percentile in the distribution as the appropriateWACC value (ie 6.7%). This results in a WACC that is not overly different to the2001 Price Determination and takes account of the unusually low prevailing risk freerates. This WACC means that there is an 80% chance that AGLE’s WACC will notbe underestimated. Conversely there is a 20% chance that it will be underestimated.

The individual parameters are discussed in the remainder of this Section.

8.5.2 Real Risk Free Rate

The Commission (like a number of regulators) has in the past determined the riskfree rate by reference to the yield on ten year Commonwealth Index Linked Bonds,averaged over a 20 day sampling window. AGLE has adopted the same practice forthis Submission. The current benchmark 10 year nominal government bond isrepresented by the April 2015 government bond. As there is no equivalent IndexLinked Bond maturing on the same date, AGLE has interpolated a range using theAugust 2010 and August 2015 Index Linked Bonds. The resulting average yield forthe twenty-day period ending 30 September 2004 is 2.79%.

AGLE notes that as the date of the final calculation of the twenty-day average willprobably be in August or September 2005 this value will change from the 30September 2004 value. Furthermore, the Determination will not take effect until 1January 2006 and the risk free rate will have varied between the date of calculationand the date of application of new prices. This will leave the distribution businessesexposed to the risk of volatility in the risk free rate between the date of the FinalDetermination and its implementation.

Because this risk is symmetric the appropriate treatment in relation to the cost ofequity is not clear. However, in the case of the cost of debt it is reasonable toconsider that an efficient business would seek to hedge against this risk, particularlyin the light of the current historically low values for the risk free rate and its rapiddecline over recent months. As a minimum the appropriate mechanism to deal withthis need for risk protection is to include an allowance for the cost of forward hedgingon debt. AGLE has not sought to estimate this forward hedge cost, but believes thatthe debt margin (discussed below) should properly include some allowance for thiscost to AGLE.


8.5.3 Market Risk Premium

AGLE believes that historically based estimates of the MRP, particularly thosespanning long time periods, are the most appropriate and relevant proxy for theforward–looking market risk premium that is to be taken into account in the CAPM.The majority of historic studies of the MRP (see KPMG report in Appendix K) providestrong support for a range of 6.0% to 8.0% (being the mean estimates) as beingrepresentative, AGLE has adopted an MRP with a mean of 6.0% and a normaldistribution with a standard deviation of 1.8%. While a mean of 6% is at the bottomend of the historical end of the range observed by KPMG and a higher value can bejustified, this mean has been adopted principally to maintain consistency with theMRP adopted by a majority of Australian regulators to date. In adopting this valueregulators have apparently been taking into account MRP estimates which have useddata over periods that are both of shorter duration and that are more recent, andhave also taken into account the more problematic evidence of future lookingmethods. On the historical evidence about MRP a mean estimate of up to 8% couldbe supported, but a mean estimate below 6% would present considerable risk ofunder estimating the MRP.

8.5.4 Equity Beta

AGLE recognises the significant issues with accurate estimation of equity Betas forelectricity distribution businesses. Beta estimates are subject to considerablemeasurement error and have been the subject of extensive recent debate. Theattached reports by SFG and KPMG review the estimates of equity beta. Based onthe evidence available, recent regulatory practice and uncertainties associated withmeasuring Beta, AGLE considers that the appropriate equity Beta for its business lieswithin a range of 0.9 and 1.1, with all points within the range uniformly distributed.

8.5.5 Gearing

AGLE has adopted a benchmark gearing of 60%, (debt/debt+equity), which is thevalue generally adopted by regulators in Australia for energy utility assets. Theproposed equity beta and debt margin have been based on this gearing level.

8.5.6 Debt Margin

A number of Australian regulators (including the Commission) have adopted thepractice of using the CBA Spectrum service, which estimates the spread betweenCommonwealth Bonds and corporate debt for a range of credit ratings, as the basisfor determining applicable debt margins in calculating the cost of debt. AGLEbelieves that while the CBA Spectrum estimates may represent a useful source ofinformation for determining an appropriate debt margin, its limitations must berecognised. As highlighted in KPMG’s report, the CBA Spectrum spread estimatesare derived using econometric techniques based on market debt raisings, and thatthere is sparse data on debt raisings with BBB and BBB+ ratings. Recently,questions have been raised as to whether CBA Spectrum yields are understated.(See Appendix K).

AGLE has concerns about the risks of the sole reliance on the CBA Spectrumservice. AGLE believes the Commission should consider whether other evidenceregarding debt margins should be considered. At this point AGLE has not been ableto source alternatives and has applied the CBA Spectrum values as the only estimatecurrently available, but reserves its position and may propose alternative estimates ifbetter information is available.


Use of the CBA Spectrum data also relies on an assumption about the appropriatecredit rating to be applied. The appropriate benchmark credit rating for an electricitydistribution business is not easily determined because of the paucity of comparablebusinesses, which are purely in electricity distribution, that have credit ratings. Otherreasonably close comparables are gas network businesses. A majority ofcomparable gas and electricity businesses have credit ratings in the range BBB- toBBB+ with the largest proportion at BBB. Comparisons with this group are difficultbecause many of the businesses have associated retail/wholesale businesses andlower levels of gearing. The Australian Competition Tribunal confirmed that theappropriate credit rating benchmark for the Moomba-Sydney Pipeline was BBB.AGLE believes that the appropriate credit rating is between BBB and BBB+, with theweight of evidence being toward BBB. AGLE has recognised the uncertaintysurrounding the appropriate credit rating by adopting a credit risk margin rangingfrom 1.01 to 1.11 and assuming that all points within the range are uniformlydistributed. This range reflects the 20 day averages (ending 30 September 2004) ofthe CBA Spectrum estimates for BBB+ and BBB credit ratings respectively.

In determining the debt margin, an allowance for debt raising costs is also necessary.A range of sources indicate that an allowance for debt issuance costs of up to fiftybasis points may be appropriate40. As the Australian Competition Tribunal acceptedan allowance of twenty-five basis points in the case of GasNet’s Access Arrangementin December 2003, AGLE believes an allowance of twenty-five basis points isapplicable.

The approach to calculating the cost of debt by the Commission as a margin over theyield on indexed bonds implies that an efficiently financed distribution business willraise debt in the index bond markets. AGLE considers that this benchmarkassumption is not realistic as the market for indexed bonds at BBB and BBB+ creditratings is highly unlikely to have sufficient capacity to absorb the bond raisingsnecessitated by the needs of the Victorian electricity businesses, or at the minimum,will only absorb the supply if offered at a more attractive yield.

Given these limitations, AGLE believes that the Commission should allow for thepossibility that an efficiently financed distribution business would have to enter intoalternative financing arrangements to index-linked financing such as raising long termnominal debt say, through bonds, and using swaps to offset the inflation risk.

In either case, businesses will incur an additional cost either in the form of highercosts than indicated by the indexed bond rate that would normally be applicable todebt due to lack of demand relative to supply, or in the form of the cost of inflationhedges associated with raising long term nominal debt. AGLE has included anallowance of 0.25% – 0.35% to cover the costs associated with raising long terminflation hedged debt.

Taking into account estimates of debt spreads, cost of debt issuance and the costsassociated with raising long term inflation hedged debt, AGLE has estimated a debtmargin for its distribution business of 1.51% - 1.71%. As identified in Section 8.5.2,AGLE has not included an allowance for the cost of hedging for the time gapbetween the Commission’s decision and 1 January 2006 when it will take effect,although this might reasonably be included. AGLE requests the Commission giveconsideration to this matter during the course of the Review.

40 Key contentions on WACC components of ACCC MSP decision by NECG, page 19.


8.6 Taxation

The Commission’s approach of using an after tax return on capital requires anestimation of the tax liability AGLE will incur. This tax liability is called the ‘tax wedge’and is included as an element in the Required Revenue calculation (see Section 9).

The calculation of the tax liability for the Current Regulatory Obligations and theSafety Management Scenario is shown in Tables 8.7A and 8.7B respectively.

Table 8.7A

FORECAST TAX LIABILITY – CURRENT REGULATORY OBLIGATIONS ($M)2006 2007 2008 2009 2010 TOTAL


Table 8.7B

FORECAST TAX LIABILITY – SAFETY MANAGEMENT SCENARIO ($M)2006 2007 2008 2009 2010 TOTAL


8.6.1 Variables for Tax Calculation

The variables used to calculate the benchmark tax are:

• Revenue requirement;• Customer contributions;• Operating and maintenance expenditure;• Tax depreciation;• Interest;• Tax losses brought forward;• After tax net income;• Cost of tax; and• Franking benefit.

A major component of the tax liability calculation is tax depreciation. The taxdepreciation rates applicable to capital expenditure (2006 to 2010) by asset class areas detailed in Table 8.8.

Table 8.8

POST RALPH TAX DEPRECIATION ON ADDITIONS 2006-2010 (%)Asset Class Tax Depreciation Rate - Declining Balance

Demand related capital expenditure 3.00Replacement expenditure (Group 1) 3.20Replacement expenditure (Group 2) 3.20Replacement expenditure (Group 3) 3.20Environment, safety and legal 3.20SCADA/Network control 7.70Non-network general assets - IT 32.50Non-network general assets - Other 8.60


These rates are the weighted average of current tax depreciation rates by assetclass, as applicable to the asset classes listed.

8.6.2 Franking Benefit

AGLE notes that the Commission and other Australian regulators have adopted avalue for franking benefits (gamma) of 50%. The attached reports from KPMG andSFG Consulting (Appendices K and M) reanalyse the information sources previouslyconsidered by regulators, including recalculating and correcting the interpretation ofthat information. They also introduce a more recent study by Cannavan, Finn andGray (2004) that has been peer reviewed and published in an international journal.

When examined together it is clear that the evidence contained in these reportsincluding the appropriate weight to be given to various studies and reports nowavailable, points to a value of gamma in the vicinity of zero and that continuing toadopt a gamma of 50% is difficult to sustain. Moreover, there is reasonable, if notentirely conclusive evidence, for accepting zero.

AGLE believes that the best evidence available does not allow the continuedadoption of a gamma of 50%. While the evidence suggests that a gamma of zero isdefensible, use of a gamma of zero would be a significant move away fromregulatory practice over the last six years. Accordingly AGLE proposes a modestreduction of gamma to 30% as this is consistent with the evidence.

Section 8 of the SFG Consulting report (Appendix M) highlights that reliance on thestudy by Cannavan, Finn and Gray (2004) is warranted based on a number ofimportant criteria, while other empirical studies on the value of imputation credits failmany of the criteria.

In the event that the Commission should consider the same evidence, but arrive at adifferent conclusion, AGLE requests that the Commission address each of theclarification points set out in Section 8 of the SFG Consulting Report.

The tax liability calculations for the Current Regulatory Obligations and the SafetyManagement Scenario are shown in Tables 8.9A and 8.9B respectively.

Table 8.9A

TAX LIABILITY CALCULATION (MOD) – CURRENT REGULATORY OBLIGATIONS ($M)2006 2007 2008 2009 2010

Revenue requirement 147.0 159.5 173.2 187.0 201.3Customer contributions 4.8 5.0 4.9 5.2 6.3Operating and maintenance expenditure 65.3 67.7 70.0 72.4 75.4Tax depreciation 33.1 34.9 37.4 39.5 42.0Interest 27.5 31.6 35.9 40.3 44.9Tax losses brought forward 0.0 0.0 0.0 0.0 0.0After tax net income 25.9 30.3 34.8 39.9 45.2Cost of tax 9.8 11.5 13.2 15.2 17.2Franking benefit 2.9 3.5 4.0 4.5 5.2Forecast tax liability $m (MOD) 6.9 8.1 9.2 10.6 12.0


Table 8.9B

TAX LIABILITY CALCULATION (MOD) – SAFETY MANAGEMENT SCENARIO ($M)2006 2007 2008 2009 2010

Revenue requirement 139.2 146.9 155.7 164.2 173.0Customer contributions 4.8 5.0 4.9 5.2 6.3Operating and maintenance expenditure 59.7 61.9 64.0 66.3 69.2Tax depreciation 32.3 32.4 33.3 33.7 34.4Interest 26.4 28.2 30.2 32.1 34.1Tax losses brought forward 0.0 0.0 0.0 0.0 0.0After tax net income 25.6 29.4 33.0 37.3 41.6Cost of tax 9.7 11.1 12.5 14.2 15.8Franking benefit 2.9 3.3 3.8 4.2 4.7Forecast tax liability $m (MOD) 6.8 7.8 8.8 9.9 11.1


9. Revenue Requirements

The Required Revenue is made up of the sum of:

• The forecast return on assets, being the WACC times the average regulatoryasset base for each year (see Section 8.4 and Section 8.2.3);

• The forecast regulatory depreciation (see Section 8.3);• The forecast operating and maintenance expenditure (see Section 6);• The efficiency carryover amount (see Section 7); and• The forecast tax liability (see Section 8.5).

The calculation of the required revenue for the 2006 to 2010 period for the CurrentRegulatory Obligations and the Safety Management Scenario is shown in Tables9.1A and 9.1B respectively.

Table 9.1A

PRESCRIBED SERVICES REVENUE REQUIREMENT - CURRENT SAFETY REGULATIONS ($M)2006 2007 2008 2009 2010 TOTAL


Table 9.1B

PRESCRIBED SERVICES REVENUE REQUIREMENT – SAFETY MANAGEMENT SCENARIO ($M)2006 2007 2008 2009 2010 TOTAL




10. PRICE CONTROLS AND TARIFFS

10.1 Introduction

The distribution tariffs proposed are based on the best information currently availableto AGLE. However, during the review process, changes to a number of inputs mayresult in change to the final price levels. For example, a change to AGLE’s requiredrevenue would result in changes to distribution tariffs.

Transmission tariffs form part of the network tariffs and hence would impact on thefinal price paid by the customer. However, AGLE’s Submission only includesproposed distribution tariffs. Details of the forecast transmission related costs arecontained in Section 6.5.

The distribution tariffs proposed by AGLE are structured around AGLE’s current 2004tariffs.

10.2 Proposed Price Path

The factors that go to determine the Price Path (P0 and X) are:

• Required revenue (under the Current Regulatory Obligations and under theSafety Management Scenario) as detailed in Section 9;

• Forecast growth, as detailed in Section 4;• Any proposed changes to prices (as discussed in this Section); and• Forecast or proposed changes to customer mix (as discussed in this Section).

Based on AGLE’s forecasts and proposals on these matters, as detailed in thisSubmission, AGLE’s proposed price path is shown in Table 10.1.

Table 10.1

PROPOSED PRICE PATH (%)CURRENT REGULATORY

OBLIGATIONSSAFETY MANAGEMENT

SCENARIOPo -16.9 -7.8X -2.0 -1.0

In the case of the Current Regulatory Obligations, AGLE is proposing an X of –2.0%so as to have a smoothing effect on the required price increases over time. AGLErecognises the issue of possible price volatility at subsequent price resets that mayoccur if X is too large. However, this should be balanced against the effect of largeprice movements at the start of this period. For the Safety Management Scenario,the P0 is -7.8% and a smaller value of –1.0% is proposed for X.

10.3 Customer Movements

AGLE engaged NIEIR to develop projections of customer numbers and energyforecasts for each of AGLE’s main network tariffs (see Section 4). While AGLE doesnot propose to introduce new tariffs during the 2006 to 2010 period, the quantitiesforecast reflect customer movements as described in the Sections below.


10.3.1 Re-Assignment of Customers to the Appropriate Tariffs

AGLE has determined that some of its distribution customers’ load characteristicshave changed such that it is appropriate to review the distribution tariff to which thesecustomers are currently assigned. AGLE proposes to reassign customers wheretheir load and connection characteristics are such that they should be on a differenttariff and where the reassignment would lead to a lower total network charge. AGLEis proposing to do this on 1 January 2006.

Table N.1 in Appendix N shows customer number and total energy projections withrespect to these customers’ movements from their currently assigned tariffs to theappropriate tariffs.

10.3.2 Movement to the multiple supply tariffs

AGLE has assumed that over a period of time, all customers who are eligible willmove to a multiple supply tariff.

Table N.2 in Appendix N shows customer number and total energy projections withrespect to these customers’ movements from their currently assigned tariffs to themultiple supply tariffs.

10.3.3 Reassignment of residential customers resulting from the IMRO

As detailed in Section 12.2, AGLE will be installing interval meters in accordance withthe IMRO and AGLE’s plan.

One of the stated benefits of the IMRO is:41

“Provide distributors with the capability and incentive to introduce more efficientpricing to retailers. Interval meters allow price structures that more accuratelyreflect the underlying costs of operating a distribution network, applied throughnetwork use-of-system charges. With interval meters, distributors would havethe flexibility to match their prices to the costs associated with narrowing gapsbetween capacity and peak demand in networks.”

In order for distributors to be able to obtain this benefit, it is necessary for customersto move to a more cost reflective tariff once an interval meter is installed. It is notsufficient for customers to be given the option to move to cost reflective tariffsbecause the customers who will elect to change tariffs will not be the customers whoare contributing to the “gap between capacity and peak demand.” In order forinterval meters to provide any benefit in reducing future network investment, it will benecessary to mandate that when a customer has an interval meter installed, theyimmediately move to a time of use tariff. AGLE believes it is appropriate to make thisstructural change in conjunction with the rollout.

Table N.3 in Appendix N shows customer number and total energy projections withrespect to re-assigning residential customers to time of use tariffs when an intervalmeter is installed.

41 Essential Services Commission (2004) “Mandatory Rollout of Interval Meters for Electricity Customers– Final Decision” July 2004 page 11.


10.4 Tariff proposals for the 2006 to 2010 period

For the purposes of this Submission, AGLE has not undertaken any re-balancing ofdistribution tariff prices for the review period. The distribution tariffs in year ‘t’ havebeen produced by indexing distribution tariffs in year ‘t-1’ by the appropriate value ofPo or X.

10.5 Pass Through Provisions

There are some factors that are completely beyond the control of the distributor, arenot possible to predict and for which it is not acceptable for distributors to carry therisk of their occurrence. It is more appropriate to handle these situations by a ‘PassThrough’ mechanism that allows the distributor to pass the impacts of these eventsthrough to customers if and when they occur.

AGLE proposes pass through mechanisms for the following:

• Changes in taxes; and• Loss due to the financial failure of a retailer.

10.5.1 Changes in Taxes

The current price controls recognise ‘changes in taxes’ as a pass through event, anddetails a process to address this matter42. AGLE supports the continuation of thisprovision. AGLE also believes that this provision should be expanded to includematerial changes in costs that are caused by a change in taxes for a third party. Anexample of this was the increase in transmission charges that was caused by theimposition of land tax on transmission companies.

10.5.2 Financial Failure of a Retailer

In the previous Price Determination, distributors were not allowed any provision forlosses due to retailers not paying their network charges. However, it cannot beignored that at some time one or more retailers may experience financial difficulties,leaving unpaid network charges. AGLE believes that it is not acceptable fordistributors to bear the risk of these losses.

The Commission requires AGLE to offer services to all retailers under the terms of itsdefault Use of System Agreement (UoSA). The UoSA allows AGLE to obtain a bankguarantee of three months worth of distribution charges in certain circumstancesbased on credit rating and history of payment. However, this only provides limitedprotection because:

• It is possible that a retailer who was not required to provide credit supportexperiences financial difficulties; and

• It is possible that it will take more than three months for the situation to beresolved or for another retailer to take responsibility for the payment of networkcharges in respect of that retailer’s customers, under a retailer of last resortevent. During this time, AGLE would be required to continue to provide networkservices to the retailer’s customers even though the payment for these servicesare in doubt.

42 Office of the Regulator-General, Victoria (2000) “Electricity Distribution Price Determination 2001-2005 Volume II – Price Controls” September 2000 Clause 5.


This agreement constrains AGLE’s ability to manage risk by prescribing theparameters by which retailers credit worthiness must be assessed and by prescribingthe maximum limit of guarantees that can be required by AGLE. AGLE recognisesthat the Commission has prescribed these arrangements as a means to facilitateretail competition, and reduce barriers of entry for new retailers. Clearly thebeneficiaries of these prescribed arrangements are consumers, however AGLEcarries the risk that a retailer may default on network payments if the prescribedarrangements are in fact inadequate in certain circumstances. AGLE believes thatthis is an unacceptable arrangment.

AGLE proposes a pass through mechanism for any losses incurred due to a retailernot being able to pay its network charges where AGLE has dealt with the retailer inaccordance with the UoSA.


11. Excluded Services

11.1 Introduction

In accordance with clause 5.7 of the Tariff Order and clause 6 of Volume 2 of the2001 Determination, AGLE provides a number of services that are classified as“excluded services.” The prices charged for excluded services are not the subject ofthis review and AGLE is not applying for any changes in excluded service prices inthis Submission (with the exception of CPI adjustments).

AGLE may apply for revised excluded prices during the 2006 to 2010 period inaccordance with Guideline 1443. Additionally, AGLE will make an application for aprice for the excluded service relating to the connection of small embeddedgenerators, as described in Guideline 1544, in the near future.

In providing the requested information on excluded services, AGLE has adopted theCommission’s approach45 of classifying standard metering-related services to smallcustomers who consume less than 160 MWhs per annum as Monopoly ProvidedAncillary Services from January 2006. These services are to be regulated as aprescribed service through separate specific charges. The proposed charges forthese services and supporting information are detailed in Section 12 of thisSubmission.

This Section details:

• AGLE’s Excluded Services, including charges and policies;• Movements in Excluded Service prices over the 2006 to 2010 period; and• Other non-regulated services provided.

11.2 Excluded Services Provided

AGLE’s excluded services are:

• Connections;• Public Lighting Operations, Maintenance, Repair and Replacement;• Field Officer Visits;• Service Truck Visits;• Electrical Inspections;• Metering;• Provision of Switching Services;• Provision of Service Fuses;• Elective Underground Servicing;• Temporary Cover of Low Voltage Mains;• Service Cabled Pulled Down by High Loads;• Standard Charge for Connection of Small Generators; and• Meter Data Services (including Meter Reading) until December 2005.

43 Essential Service Commission (2004) “Guideline 14 – Provision of Services by Electricity Distributors– Issue 1” April 2004 clause 5.44 Essential Service Commission (2004) “Guideline 15 – Connection of Embedded Generation – Issue1” August 2004 clause 3.2.45 Guidance Paper page 119.


11.2.1 Connections

Connection services cover new premises, existing premises (reconnection andcustomer transfer) and temporary supplies as follows:

• New Connections - this service is for connecting residential and non-residentialcustomers via overhead or underground supply applies to all new premises, withthe exception of temporary supplies;

• Reconnection (fuse insertions-new customers) - this service typically coversreconnection of supply for a new customer at an existing address; and

• Temporary Supply - Overhead Supply Coincident Disconnection and PartialSupply in a Permanent Position - the services provided cover both overhead orunderground, single-phase or multi-phase supply.

AGLE’s prices for the provision of this service are shown in Table 11.1.

Table 11.1

CONNECTION PRICES (GST inclusive)New premises Normal Hours ($) After Hours ($)Residential 197.50 425.70Non Residential 311.60 584.90Existing premisesReconnection (Fuse Insertion – New Customer 23.00 133.80Customer Transfer 23.00 133.80Temporary SupplyOverhead Supply – Coincident Disconnection 204.10 396.00Partial Supply in Permanent Position 222.70 425.70

11.2.2 Public Lighting Operations, Maintenance, Repairs andReplacements

This excluded service relates to the provision of operations, maintenance, repairsand replacements for public lights for councils and VicRoads.

Defective public lighting lanterns are replaced in accordance with the Public LightingCode when their effective economic life has expired. As they fail, the remnants of250 W and 400 W Mercury Vapour (MV) main road lanterns will be replaced withmore energy efficient high-pressure sodium fittings. Any remaining fluorescentlanterns will be replaced with 80-Watt MV fittings.

In August 2004, the Commission released its final decision on the review of PublicLighting Excluded Service Charges46. This decision found that most of AGLE’sproposed prices were fair and reasonable. Subsequently, AGLE proposed revisedprices for the remaining light types, which have been approved.

AGLE’s prices for the provision of Public Lighting services are shown in Table 11.2.

AGLE also notes that in Section 4 of the Final Decision, the Commission has outlinedthe methodology for adjusting the charges over time for an increase in thedepreciation of the assets and the return on the assets. AGLE has incorporated thisapproach in the development of the forecast revenue.

46 Essential Service Commission (2004) “Final Decision – Review of Public Lighting Excluded ServiceCharges” August 2004.


Table 11.2

Public Lighting Type Annual Charge approved by the Commission(GST exclusive) ($)

Fluorescent 20 watt 30.57

Fluorescent 2 * 20 watt 30.57



Mercury Vapour 50 watt 30.57





Sodium Low Pressure 90 watt 53.45

Sodium High Pressure 100 watt 55.30



Sodium High Pressure 250 watt (24 hours) 79.49


Incandescent 100 watt 38.23

Incandescent 150 watt 47.75

Metal halide 70 watt 62.92



11.2.3 Field Officer Visits

The services provided cover work carried out by special meter readers, electricalinspectors and linesmen for reconnection after disconnection for non-payment, andfuse removals and insertions on behalf of electrical contractors.

The reconnection after disconnection for non payment service involves two visits tothe site. The first involves disconnecting supply (by removing a fuse) for non-payment and the other to reconnect (by reinserting the fuse) following payment of theaccount. Under the UoSA, AGLE is required to disconnect a customer whenrequested to do so by the customer’s retailer.

A fuse removal and subsequent insertion occurs when a customer is disconnectedand reconnected to the distribution system at their request.



Table 11.3

FIELD OFFICER VISITS (GST inclusive)Normal Hours ($) After Hours ($)

Collect overdue accounts 31.80 N/AReconnect after disconnection for non payment 53.70 164.60Adjust time switch (where customer benefits) 30.70 N/AFuse removal / Insertion for electrical contractor per visit(For fuses of less than 100 amp and total call lasting nomore than 15 minutes).

30.70 133.80

Special meter reading 23.00 133.80

11.2.4 Service Truck Visit

This service applies to all customer requested service truck visits that are not relatedto a fault and usually relate to servicing of equipment installed at the customer’spremises.


Table 11.4

SERVICE TRUCK VISIT (GST inclusive)Normal Hours ($) After Hours ($)

Truck Visit 196.40 246.90

This service applies to all customer and contractor requested service truck visitsexcept:

• Emergency and fault calls unless the customer is clearly at fault eg. Not checkedmain switch or safety switch has operated;

• The installation of a meter and time switch in a domestic premises because of theaddition of off-peak load; and

• All electrical inspection services.

11.2.5 Electrical Inspections

This service covers customer requested inspections / reinspections, and usuallyoccur as a result of customers requesting an inspection for safety or planningpurposes. Services such as connections and provision of temporary supplies alreadyinclude the cost of an electrical inspection in the original charge.


Table 11.5

ELECTRICAL INSPECTION (GST inclusive)Normal Hours ($) After Hours ($)

Re inspections (Defects – total job to be inspected) 167.90 222.70Customer requested inspections 167.90 219.50


11.2.6 Metering

As discussed in Section 11.1, the provision of standard metering services to smallcustomers will no longer be classified as an excluded service from 2006.

However, AGLE will continue to provide the following metering services as excludedservices:

• Low voltage meter conversions - this service involves the alteration of a meter toanother tariff and is performed at the customer’s request. The conversions canbe to time-of use, the installation of a 5 day electronic time switch or to the‘Winner’ tariff for new or existing meters;

• Meter equipment test - this excluded service is provided to customers who areseeking to have the accuracy of their meters verified. This service covers thetesting of four types of meters: single phase; single phase – each additionalmeter; multi-phase; multiphase – each additional meter. Note that the customerreceives a full refund where it is established that their meter is faulty;

• Provision of load profile - this service covers the measurement of a customer’sload profile to determine the potential benefit of a tariff change. The serviceinvolves the installation and eventual removal a magnetic tape recorder on acurrent transformer meter and the provision of one months load profile. A furthercharge applies where a customer requires an additional month’s load profile; and

• Load profile print-out from existing metering - this service covers customerrequests for a copy of the load profile data from an existing data cassetteinstalled for billing purposes.

AGLE’s prices for the provision of these services are shown in Tables 11.6, 11.7,11.8, and 11.9.

Table 11.6

LOW VOLTAGE METER CONVERSION (GST inclusive)Normal Hours ($) After Hours ($)

To WINNER, no qualifying off peak load (existinginstallation) 280.90 391.80

To Time of Use (Tariff D or WINNER) – existing installation 440.00 601.40Installation of 5-day electronic time switch 299.60 400.40

Table 11.7

METER EQUIPMENT TEST (GST inclusive)Normal Hours ($) After Hours ($)

Single phase 178.80 229.30Single phase (each additional meter) 66.90 85.60Multi phase 268.80 343.50Multi phase (each additional meter) 113.00 145.90

Table 11.8

PROVISION OF LOAD PROFILE TO CT METERING (GST inclusive)Normal Hours ($) After Hours ($)

Install and provide one load profile 407.00 RW*For each additional profile 203.00 RW*

* Recoverable Works47

47 Recoverable Works are initiated by customers.


Table 11.9

LOAD PROFILE PRINTOUT, EXISTING METERING (GST inclusive)Normal Hours ($) After Hours ($)

Load Profile Printout 77.90 N/A

11.2.7 Provision of a Switching Service

This charge is applied when a customer requires a load other than storage waterheating in a domestic installation to be synchronised to off-peak times. The chargecovers the cost of providing additional time switch contacts and fuses where theservice is being carried out in conjunction with other metering work. Where theservice is being carried out in isolation, a service truck visit charge is also applied.


Table 11.10

SWITCHING SERVICE (GST inclusive)Normal Hours ($) After Hours ($)

Switching Service 223.80 286.40

11.2.8 Provision of Service Fuses

This service covers the provision of hinged fuses (300Amp). This service is providedto customers as the service fuses are not readily available through commercialoutlets and it is important to maintain the standard of fuse used since these fuses arethe juncture between the customer’s installation and the distribution network.


Table 11.11

PROVISION OF SERVICE FUSES (GST inclusive)Normal Hours ($) After Hours ($)

Hinged Fuses: 300A Group of 3 256.80 306.20

11.2.9 Elective Underground Servicing

This service is provided to customers who want an existing overhead serviceconverted to an underground service. AGLE provides this service for supplybetween 100 Amp/Phase and 170/197 Amp/Phase.


Table 11.12

ELECTIVE UNDERGROUND SERVICINGNormal Hours ($) After Hours ($)

Existing Installations – Charge Plus Cost of Cable permeter(Cost of cable per meter: 2 wire, 3 wire or 4 wire and costof conduit per meter).

RW* RW*

Supply between 100A and 170A per phase(New and Existing Installations cost of cable per meter50mm2 and cost of conduit per meter)

RW* RW*

* Recoverable works


11.2.10 Temporary Cover of Low Voltage mains

AGLE provides this service to customers who require the LV mains that are neartheir premises to be covered to prevent contact with the bare lines. Additionalcharges apply for the rent of the covers if they are required for more than one month.


Table 11.13

TEMPORARY COVER OF LV MAINS (GST inclusive)Normal Hours ($) After Hours ($)

2 wire cover 727.60 878.00All wire cover 740.80 891.00Material rent for each additional month2 wire cover 52.60 N/AAll wire cover 65.80 N/AService cableProvide / remove cover plus one month rental 365.40 N/AMaterial rent for each additional month 65.80 N/A

11.2.11 Service Cable Pulled Down by High Loads

A charge is made to customers to restore supply cables that were pulled down by ahigh load but only where it can be established the height of the cable conformed tothe minimum height requirements that applied at the time when the service cable wasinstalled.


Table 11.14

SERVICE CABLE PULLED DOWN BY HIGH LOADSNormal Hours ($) After Hours ($)

Using aluminium service cableSingle phase RW* RW*Multi phase RW* RW*Using copper cableSingle phase RW* RW*Multi phase RW* RW*

*Recoverable Works

11.2.12 Standard Charge for Connection of Small Generators

AGLE will provide a service to customers to enable connection of embeddedgeneration to the distribution network. An application for approval of prices for thisservice will be submitted to the Commission at a future date.

11.2.13 Metering Services (type 5 or 6) for Large First Tier Customers

During the 2006 to 2010 period, metering services for large first tier customers (thatis, customers who consume more than 160 MWhs per annum) with type 5 or type 6meters are offered as excluded services. This includes the provision and installationof such meters and meter data services.


11.3 Movements in Prices

AGLE proposes that the charges for all excluded services, including Public Lightingreferred to in Section 11.2.2, be made subject to an annual adjustment on 1 Januaryeach year based on movements in the CPI as represented by the All GroupsConsumer Price Index – Average of the Eight Capital Cities.

The proposal for an annual indexation of the excluded service charges is based onthe existing charges, previously approved by the Commission, being a fair andreasonable charge for these services.

It is necessary for these approved prices to be escalated to maintain their value overtime.

This proposal does not preclude either the distributor or the Commission from havingprices reviewed in accordance with Guideline 14. In respect of the Public Lightingexcluded service charge, this adjustment would be in addition to the adjustmentproposed by the Commission to recognise the increasing asset base.

AGLE has prepared the revenue data in Template 19 on this basis, resulting in pricesremaining constant in 2004 dollars for the 2006 to 2010 period.

11.4 Other Non - Regulated Services

AGLE advises that the only other revenue it receives for services that utilise assetsfunded by electricity customers is the joint use of electricity poles by pay TVcompanies. These companies pay an annual charge based on a contractualagreement with AGLE that enables them to use AGLE’s poles.


12. Metering Services

12.1 Introduction

The Commission’s decision on interval meters confirmed the program for theinstallation of interval meters to all customers48.

The program is shown in Table 12.1.

Table 12.1

MANDATORY INTERVAL METER ROLLOUTCustomer

ConsumptionMetering

InstallationMeter

ChangeoverNew and

ReplacementCost Recovery

Method

> 160 MWh p.a. All Meters Completed by2008

From 2006 Excluded ServiceCharge

< 160 MWh p.a.and> 20MWh p.a.

CT ConnectedMulti Phase OffPeak Time of Use

Completed by2011

From 2006 SeparateRegulated MeterCharge

< 20 MWh p.a. CT ConnectedMulti Phase OffPeak Time of Use

Completed by2013

From 2006 SeparateRegulated MeterCharge

< 160 MWh p.a. All other types Not required From 2008 SeparateRegulated MeterCharge

The recovery of metering costs relating to customers consuming greater than 160MWh per annum is either through excluded services (for type 5 meters and type 6meters prior to 2008) or through commercial non-regulated charges (for types 1,2 3and 4 meters) and is thus not dealt with in this Section. Excluded services arediscussed in Section 11 while the costs and revenue relating to non-regulatedservices are not a matter for this review.

12.2 AGLE Interval Meter Rollout Plan

The AGLE IMRO Plan, shown in Table 12.2, has been developed to comply with theCommission’s requirements. The table shows the percentage of meters in eachcategory that AGLE plans to replace in each year under the Interval Meter RolloutProgram. AGLE does not intent to rollout interval meters earlier than is requried.

48 Essential Services Commission (2004) – Final Decision “Mandatory Rollout of Interval Meters forElectricity Customers” July 2004 page 25.


Table 12.2

This plan shows that:

• AGLE intends to continue to install accumulation meters where permitted underIMRO requirements, in 2006 and 2007. This will allow AGLE to exhaust itsexisting stock of accumulation meters and to fufil its existing purchase contracts;

• New and replacement meters shall be interval meters from the start of the yearspecified by the Commission; and

• AGLE will be replacing accumulation meters with interval towards the end of therequired periods.

The AGLE plan assumes that where there are multiple meters installed at a site inorder to measure time of use, those meters will be replaced by a single intervalmeter.

The estimating methodology used to predict the numbers of meters by category isbased on the statistical distribution of existing meters in July 2004. Estimates fornew, replacement, and rollout quantities were derived as follows:

New Connections - AGLE engaged NIEIR to forecast the new connections over thepricing period. The distribution of metering by category for new connections wasbased on the distribution as at July 2004.

• Replacement of Accumulation Meters Following Failure - The estimate for thenumber of meters to be replaced due to meter failure is 0.17%.

• Asset Replacement - The AGLE asset replacement program has planned for areplacement rate of 10,000 meters per year. This has been assumed andcounted in the IMRO estimates.

• Rollout - Additional accumulation meters to be replaced under the IMRO rulingare the balance of meters required to be replaced under the Commission’s rulingthat have not been already replaced at the time due to meter failure or under theasset replacement.

2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015LARGE Multiphase >160 New / Rep

Rollout - - - 100% - - - - -

Off-peak >160 New / RepRollout - - - 100% - - - - -

Single-phase > 160 New / RepRollout - - - 100% - - - - -

MEDIUM Multiphase 20-160 New / RepRollout - - - - 33% 33% 33% - -

Off-peak 20-160 New / RepRollout - - - - 33% 33% 33% - -

Single-phase 20-160 New / RepRollout - - - - - - - - -

SMALL Multiphase < 20 New / RepRollout - - - - - 25% 25% 25% 25%

Off-peak < 20 New / RepRollout - - - - - 25% 25% 25% 25%

Single-phase < 20 New / RepRollout - - - - - - - - -


The number of meters that are planned to be installed each year, by category, areshown in Table 12.3.

Table 12.3

12.3 Capital Costs

As shown in Table 12.1, the provision of metering (type 5 & 6) for large customers isto be treated as an excluded service, and the provision of standard metering for smallcustomers is to be treated as a prescribed service.The capital expenditure on metering service for large customers (excluded services)include:

• Meter provision and installation; and• Overhead costs

The largest proportion of the IMRO will be in regards to the provision of meteringservices to small customers.

Due to the large number of installations involved, it is expected that a number ofproblems will be encountered during the installation that will involve remedial work oradditional costs. Additionally, it will be necessary to incur project management andother related costs.

AGLE’s current IT systems are not capable of handling this increased number ofinterval meters and the increased amount of data from these meters. AGLE will needto incur expenditure on new and enhanced systems.

The Capital Expenditure required for the IMRO is shown in Table 12.4 and detailed inthe following Sections.

2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015LARGE Multiphase >160 New / Rep 12 12 11 12 12 12 12

Rollout - 60 - - - - -

Off-peak >160 New / Rep 16 17 16 16 17 17 16

Rollout - - - - - - -

Single-phase > 160 New / Rep 93 94 92 93 99 99 93

Rollout - - - - - - -

MEDIUM Multiphase 20-160 New / Rep 39 39 38 39 41 41 39

Rollout - - 196 201 204 - -

Off-peak 20-160 New / Rep 40 40 39 40 42 42 40

Rollout - - 276 282 288 - -

Single-phase 20-160 New / Rep 225 227 222 224 239 239 225

Rollout - - - - - - -

SMALL Multiphase < 20 New / Rep 2414 2439 2383 2414 2568 2565 2416

Rollout - - - 6645 6766 6942 7142

Off-peak < 20 New / Rep 2471 2496 2440 2471 2629 2626 2473

Rollout - - - 9358 9527 9775 10057

Single-phase < 20 New / Rep - - 13839 14015 14914 14895 14027

Rollout - - - - - - -

TOTAL 5310 5423 19553 35809 37347 37252 36539 - - -


Table 12.4

TOTAL CAPITAL EXPENDITURE FOR METERING ($000)Excluded Services 2006 2007 2008 2009 2010 TOTALMeter provision & Installation 92 93 91 92 98 466Overheads 6 6 5 6 6 29TOTAL 98 99 97 98 104 496Prescribed ServicesMeter provision & Installation 6,275 6,338 7,810 17,465 18,164 56,052IMRO Project Management 411 370 425 502 548 2,256Overheads 859 842 934 1,518 1,563 5,716TOTAL 7,545 7,550 9,169 19,485 20,275 64,024

IT CAPITAL EXPENDITURE(Metering) TOTAL 5,534 113 150 50 113 5,960

TOTAL METERING CAPITAL 13,177 7,762 9,416 19,633 20,492 70,480

12.3.1 Excluded Services

These are the costs associated with the provision of metering for large customers.

12.3.1.1 Meter Provision and Installation

This includes the cost of the meter and installation.

12.3.1.2 Overheads

These costs include the share of management overhead in support of metering forlarge customers.

12.3.2 Prescribed Services

These are the costs associated with the provision of metering for small sites(consuming less than 160MWh per annum.) and include the costs associated withthe provision of accumulation metering in 2006 and 2007 for sites consuming below20MWh per annum, and the costs of interval meters that are installed as part of therollout commencing in 2006.

12.3.2.1 Meter Provision & Installation

Meter Provision and Installation includes:

• Procurement and direct installation of meters;• Wiring Corrections – Additional costs associated with an expected 3% of sites

requiring meter installation wiring changes;• After-Hours loading – additional cost loading for anticipated after-hours work for

all business customers;


• Switchboard replacements (poor condition) – Provision for expected requirementto replace 1% of meterboards due to poor condition;

• Switchboard replacements (installation complexities) - Provision for thereplacement of 5% of all off-peak meterboards due to installation complexities;and

• Switchboard replacements (Asbestos) – A provision of $500 per affect site for theremoval and disposal of meterboards contaminated by asbestos. It is estimatedthat this will affect 30% of AGLE meter installations due to the AGLE networkcoverage of the older and original Melbourne greater metropolitan area.

12.3.2.2 Project Management

Project management of the interval meter rollout will include:

• Tendering – development and management of the service providers tenderingprocesses in 2006, 2008 and 2010;

• Contract Management – management of the service provider contracts;• Project Management – A full-time Project Manager for the duration of the IMRO

program;• Customer Communications – management of the customer communications that

will be required;• Customer Complaints (Ombudsman) – management of the increased number of

matters involving the Ombudsman;• Customer Complaints – management of the likely increase in customer

complaints;• Appointments – The arrangement of appointments for all business customers;

and• Multiple Visits – Allowance for 10% of installations that will require a return truck-

visits.

12.3.2.3 Overheads

• Training – Recurrent staff training throughout the IMRO period;• Network Tariff re-assignment – On-going costs to reassign customers from

existing tariff to new time-of-use tariff; and• Metering Management overheads.

In relation to switchboard replacement AGLE believes that it would be inappropriateto expect individual customers to pay for the replacement of their switchboard when,other than for the IMRO, their switchboard would not need to be replaced. It is moreappropriate for these costs to be ‘smeared’.


12.3.3 IT Capital Expenditure (Metering)

IT related capital includes upgrades of the meter data collection and meter readingsystems. The current ITRON MV90 system has a limitation on the number of intervalmeters that can be managed. This system will need to be upgraded to manage themeter reading process and to capture and convert the interval meter data uploadedfrom the meter reading devices.

Included in the metering capital estimates is the procurement and operation of a newMeter Data Management (MDM) system. The current MV90 system does notprovide a data warehouse facility, therefore data will need to be transferred from theMV90 system to the MDM system. Currently, Meter Data Management is providedby a combination of disparate IT systems, which are not suited to the volume andnature of interval meter data. The new MDM system is expected to be a purpose-built MDM application, and estimated costs include hardware, system software,application software and implementation. The implementation costs also include thedevelopment of interfaces to external systems.

12.4 Operating Costs

Metering services operating costs include meter reading and meter data processing.They also include IT operating costs that are directly related to the MDM IT system.

Metering Operating costs are shown in Table 12.5.

Table 12.5

TOTAL OPERATING AND MAINTENANCE EXPENDITURE FOR METERING ($000)Excluded Services 2006 2007 2008 2009 2010 TOTALMeter Data Services 98 99 97 98 104 496

Prescribed ServicesMeter ReadingScheduled Reads 1,547 1,583 2,069 2,868 3,421 11488Special Reads 229 235 235 235 235 1169Indirect Costs 340 340 340 340 340 1700TOTAL 2,117 2,158 2,644 3,443 3,996 14358

Meter Data ProcessingMDP 345 388 497 680 850 2760Indirect Costs 500 500 500 500 500 2500TOTAL 845 888 997 1,180 1,350 5260

Meter MaintenanceMeter Maintenance Accumulation 2,072 2,073 1,942 1,703 1,470 9260Meter Maintenance Interval 72 73 206 441 676 1468TOTAL 2,144 2,146 2,148 2,144 2,146 10728

IT Maintenance & Support 111 111 111 111 110 554TOTAL Metering Operating Costs 5,315 5,402 5,997 6,976 7,706 31,396


12.4.1 Meter Data Services

Meter Data Services encompasses Meter Reading and Meter Data Processing(MDP). For large sites these are excluded services and meter reading and meterdata processing are generally carried out together as a single service.

For small sites Meter Reading includes:

• Scheduled Reads;• Special Reads; and• Indirect Costs.

12.4.2 Meter Reading

Meter Reading costs includes the direct costs of contracted services to carry out thescheduled and special meter reading. It also includes the internal meteringmanagement costs that are not provided under the service provider contracts. Thesemeter reading costs do not include costs for meter reads carried out in the process oftime-switch adjustments, etc. as these have been counted elsewhere.

12.4.3 Meter Data Processing

Meter Data Processing costs include the direct costs of internal and contractedservices to carry out the regulatory MDP obligations. These obligations include thestorage and distribution of metering data to market participants and NEMMCO. MDPobligations are applicable to AGLE acting as LNSP for all tier-2 accumulationmetered NMIs and all interval metered NMIs. The operating costs for Meter DataProcessing also include the internal labour to monitor and correct meter readings asrequired.

12.4.4 Meter Maintenance

AGLE does not generally carry out repairs to meters, instead choosing to replacefaulty meters. Costs reported under this heading include the external testing andcertification procedures for regulatory compliance and the office staff administeringthis function.

12.4.5 IT Maintenance & Support

IT operating costs include the estimated costs of maintenance and supportagreements for the MDM software installed in support of the IMRO. The estimatehas been calculated at 20% of the capital cost of the software.

12.5 Required Revenue

The cost recovery for the provision of standard metering is to change for the 2006 to2010 period. From 2006 onward, a separate charge for standard metering will belevied. This charge will be based on the recovery of the following:

• A return on asset;• Regulatory depreciation;• O & M expenditure; and• Tax liability.


However, in transitioning from cost recovery within distribution charges to a separatemetering charge, it is not possible to remove the value of existing meters from the“distribution” asset base to the “metering” asset base. The metering asset base willstart at a value of zero in 2006 and increase as capital expenditure occurs. At thesame time, the distribution asset base will decline as the metering capital expenditureincurred prior to 2006 is depreciated.

The asset base for metering is shown in Table 12.6.

Table 12.6

REGULATED ASSET BASE - METERING ($000)2006 2007 2008 2009 2010 2011 2012

Opening asset base 0 12,075 17,271 22,990 36,858 48,724 57,984Capital expenditure (net ofcustomer contributions) 13,079 7,664 9,319 19,535 20,389 20,127 19,938

Disposals - - - - - - -Depreciation 1,004 2,469 3,600 5,667 8,523 10,867 13,166Closing asset base 12,075 17,271 22,990 36,858 48,724 57,984 64,756Average asset base 6,038 14,673 20,130 29,924 42,791 53,354 61,370

In order to recover the capital and non-capital costs attributable to installation andmaintenance of Interval Meters proposed by the Commission to be rolled out over thenext eight years, AGLE has used a building block method to calculate the requiredrevenue in each year to be included in this Submission.

The building block methodology includes a return on the asset each year, therecovery of regulatory depreciation, the recovery of non-capital costs for operatingand maintaining the interval meters and the associated tax liability.

This method is consistent with the building block approach used to determine thetotal required revenue for the AGLE network regulated assets.

Table 12.7 shows the required revenue.

Table 12.7

PRESCRIBED SERVICES REVENUE REQUIREMENT (METERING SERVICES) ($M)2006 2007 2008 2009 2010 TOTAL

Return on assets 0.40 0.98 1.35 2.00 2.87 7.61Regulatory depreciation 1.00 2.47 3.60 5.67 8.52 21.26O and M expenditure 5.22 5.31 5.91 6.88 7.61 30.93Forecast tax liability 0.00 0.00 0.28 0.82 1.37 2.47Total building blocks revenuerequirement - metering 6.63 8.76 11.13 15.38 20.37 62.27

12.6 Metering Prices

The proposed prices are developed on the basis that the revenue derived from themetering prices and the forecast quantities match the total revenue determined usingthe building block approach discussed in Section 12.5.


The pricing structure consists of a:

• Charge per Meter for metering provision. This recovers the return on asset,regulatory depreciation and the tax liability component associated with the cost ofinstalling an interval meter. The cost is recovered amongst all residential andsmall business network customers;

• Charge per NMI for metering data services. This recovers the operational andmaintenance costs and the tax liability component associated with meter dataservices. The cost is recovered amongst all customers with an interval meter andtier-2 customers with an accumulation meter; and

• Charge per light for public lighting. This recovers the operational andmaintenance costs and the tax liability component. The cost is recoveredamongst the total number of lights.

The following tables 12.8, 12.9, and 12.10 show the prices for the three components.

Table 12.8

METERING PRICES FOR THE PROVISION OF METERS - CHARGE PER METER ($ PER ANNUM)2006 2007 2008 2009 2010 2011 2012

Meter provision (single phasenon off peak meter) 2.74 6.62 14.85 18.53 27.73 34.79 40.93

Meter provision (single phaseoff peak meter) 2.74 6.62 14.85 18.53 27.73 34.79 40.93

Meter provision (three phasedirect connected meter) 26.10 62.94 43.62 117.07 170.96 213.71 256.92

Meter provision (three phaseCT connected meter) 1.32 3.19 2.01 1.49 2.31 2.91 3.34

Table 12.9

METERING PRICES FOR THE METER DATA SERVICES - CHARGE PER NMI ($ PER ANNUM)2006 2007 2008 2009 2010 2011 2012

Metering data services (type 5and 6) – monthly read 28.82 27.53 19.21 18.34 20.20 22.00 23.76

Metering data services (type 5and 6) – quarterly read 50.14 45.81 42.31 38.76 36.56 35.26 34.36

Table 12.10

METERING PRICES FOR PUBLIC LIGHTING - CHARGE PER LIGHT ($ PER ANNUM)2006 2007 2008 2009 2010 2011 2012

Metering data services (type 7) 0.09 0.09 0.10 0.10 0.10 6.37 6.10

12.7 Incentive Scheme

The Commission has proposed an incentive scheme for the rollout of interval meters.The Commission has said:49



“The Commission will consider the expenditure required for metering separatelyand apply an incentive mechanism to:• adjust the allowed revenue to account for the fact that the distributor has

reduced costs by not rolling out interval meters as forecast; and• provide a reward (or penalty) for cost efficiencies (or inefficiencies) in rolling

out the interval meters.”

In relation to the first point, AGLE strongly opposes such a scheme for manyreasons.

The proposed scheme is one sided. While it would impose penalties on distributorsfor delaying the installation of meters, it would not provide a reward for bringingforward their installation. Such a scheme clearly imposes an asymmetric risk ondistributors. Should such a scheme be implemented, it would be necessary to factorthis asymmetric risk into the return on assets applicable to the metering assets.

AGLE’s forecast program is for the installation of meters to be carried later in theallowed timeframe. It is not likely that AGLE could further delay the installation ofmeters and meet the required deadlines.

AGLE believes that it should be free to manage its own works program. During theperiod it is likely that situations will occur where it will need to adjust its expectedprogram to accommodate the peaks and trough of other work and to operateefficiently. AGLE should be free to do this with having its decision distorted by sucha mechanism.

AGLE believes that the deadlines in the Draft Decision for the installation of intervalmeters should be made a regulatory obligation, possibly in the Electricity CustomerMetering Code, and then the distributors should be left to carry out their plan.

In relation to the second point, AGLE has no concerns with a scheme similar to theEfficiency Carryover Mechanism to apply to the costs of installing meters, includingan adjustment for actual number of meters installed as compared to the forecast. Tothis end, AGLE’s forecast marginal capital cost of the interval meter rollout is $593.00per meter and its marginal operating cost is $19.70 per meter per annum.


Appendices


Appendix A

Prescribed Services Revenue and Cost Data Templates – Current RegulatoryObligations


Appendix B

Prescribed Services Network Data Templates – Current Regulatory Obligations


Appendix C

Excluded Services and Other Activities Templates – Current RegulatoryObligations


Appendix D

Distribution Tariff Templates – Current Regulatory Obligations


Appendix E

Prescribed Services Revenue and Cost Data Templates – Safety ManagementScenario


Appendix F

Prescribed Services Network Data Templates – Safety Management Scenario


Appendix G

Excluded Services and Other Activities Templates – Safety ManagementScenario


Appendix H

Distribution Tariff Templates – Safety Management Scenario


Appendix I

Safety Management Scenario – Assumptions


Appendix J

Description of PB Associates Asset Replacement Model


Appendix K

Weighted Average Cost of Capital, by KPMG


Appendix L

A Framework for Quantifying Estimation Error in Regulatory WACC, by SFGConsulting


Appendix M

The value of Imputation Franking Credits: Gamma, by SFG Consulting


Appendix N

Customer Re-assignments and Movements