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ECG energy consulting group

Review of AGLGN

Gas Access Arrangement For

Independent Pricing and Regulatory Tribunal

ECG

P.O. Box 350

Collins Street West

Melbourne 8007

Telephone 03 9527 4921

Independent Pricing and Regulatory Tribunal Review of AGLGN Gas Access Arrangement

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DISCLAIMER

ECG endeavours to provide accurate and reliable reports based on supplied data and information. ECG and its staff will not be liable for any claim by any party acting on or using the information supplied in this review.

Report prepared by Project Team Ken Firth, Alan Yule, Malcolm Young, Ross Calvert, Maurice Joyce, Sue Jones

Reviewed Ed Teoh


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TABLE of CONTENTS 1. Executive Summary ...............................................................................................1 2. Introduction............................................................................................................7

2.1 Background....................................................................................................7 2.2 Scope of Consultancy ....................................................................................7 2.3 Objectives of Consultancy .............................................................................7 2.4 General Approach ..........................................................................................7 2.5 Expenditure Assessment – January to December 2004 .................................9 2.6 Use of Inflation Factors .................................................................................9 2.7 AGLGN/Agility Relationship......................................................................10

3. Description of AGLGN Gas Network .................................................................11 3.1 General Overview ........................................................................................11

3.1.1 Receipt Points ......................................................................................12 3.1.2 High Pressure Systems.........................................................................15 3.1.3 Low and Medium Pressure Systems ....................................................15 3.1.4 Facilities...............................................................................................16 3.1.5 Pressure Control...................................................................................17 3.1.6 Meters and Services .............................................................................17 3.1.7 Customer Installations .........................................................................17

3.2 Condition of Assets......................................................................................17 3.2.1 Trunk Pipelines ....................................................................................17 3.2.2 Primary Mains......................................................................................17 3.2.3 Secondary Mains..................................................................................18 3.2.4 Medium and Low Pressure Mains .......................................................18 3.2.5 Trunk Receiving Stations.....................................................................18 3.2.6 Primary Reduction Stations .................................................................18 3.2.7 District Regulator Sets .........................................................................18 3.2.8 Residential Gas Meters ........................................................................18 3.2.9 Industrial and Commercial Meter Sets ................................................19 3.2.10 Residential Hot Water Meters..............................................................19

3.3 Redundant Assets.........................................................................................19 4. Asset Management...............................................................................................21

4.1 Asset Management Plans .............................................................................21 4.2 Safety and Operating Plan ...........................................................................22 4.3 Network Capacity Planning Process............................................................24

4.3.1 Peak Load Forecasting.........................................................................24 4.3.2 Network Performance Modelling ........................................................24 4.3.3 Network Performance Prediction.........................................................25

4.4 Capital Expenditure Process ........................................................................25 5. Stakeholder Consultation .....................................................................................28 6. Working Capital...................................................................................................29 7. Capital Expenditure Review 2000-2004..............................................................32

7.1 AGLGN Proposed Regulatory Capital Base................................................32 7.2 Depreciation.................................................................................................35 7.3 Comparison of Actual and Forecast Expenditure ........................................36 7.4 Market Expansion ........................................................................................38

7.4.1 Mains....................................................................................................39 7.4.2 Services ................................................................................................40 7.4.3 Meters ..................................................................................................41 7.4.4 Summary ..............................................................................................42


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7.5 System Reinforcement .................................................................................42 7.5.1 Review of Proposed Expenditure.........................................................43 7.5.2 Review of Material Projects.................................................................43 7.5.3 System Reinforcement Expenditure Summary....................................44

7.6 Renewal/Replacement..................................................................................44 7.6.1 Review of Actual Expenditure - M&LP Mains Rehabilitation Program and Ad Hoc Mains and Services..........................................................................45 7.6.2 Review of Actual Expenditure – Meter Replacement .........................46

7.7 Non System Assets ......................................................................................46 7.7.1 Land/Building/Leasehold.....................................................................47 7.7.2 Plant & Equipment...............................................................................47 7.7.3 Motor Vehicles.....................................................................................48 7.7.4 Information Technology (IT)...............................................................48 7.7.5 Access Arrangement ............................................................................50

7.8 Summary of Non System Assets Expenditure .............................................50 7.9 Disposals ......................................................................................................51 7.10 Capital Contribution.....................................................................................51 7.11 July to December 2004 ................................................................................52 7.12 Recommended Capital Expenditure 2000-04 ..............................................53

8. Capital Expenditure Forecast 2005-2010.............................................................54 8.1 AGLGN Forecast Capital Base....................................................................54 8.2 Forecast Expenditure ...................................................................................56 8.3 Growth – Market Expansion Plans ..............................................................57

8.3.1 Mains....................................................................................................58 8.3.2 Services ................................................................................................58 8.3.3 Meters ..................................................................................................59 8.3.4 Summary ..............................................................................................60

8.4 System Reinforcement .................................................................................60 8.4.1 Network Performance Assessment ......................................................60 8.4.2 Review of Proposed Expenditure.........................................................61 8.4.3 Review of Material Projects Expenditure ............................................61 8.4.4 System Reinforcement Expenditure Summary....................................65

8.5 Renewal/Replacement..................................................................................66 8.5.1 Review of Proposed Expenditure.........................................................67 8.5.2 Programmed Rehabilitation .................................................................67 8.5.3 Mains and Services ..............................................................................70 8.5.4 Meters ..................................................................................................75 8.5.5 Renewal/Replacement Expenditure Summary ....................................79

8.6 Non system Capital Expenditure .................................................................80 8.6.1 Information Technology (IT)...............................................................80 8.6.2 Vehicles................................................................................................82 8.6.3 Other Expenditure................................................................................82

8.7 Disposals ......................................................................................................83 8.8 Capital Contribution.....................................................................................83 8.9 Recommended Capital Expenditure 2005-2010 ..........................................84

9. Non Capital Costs 2000-2005..............................................................................85 9.1 Introduction..................................................................................................85 9.2 AGLGN 2000-04 Non Capital Costs...........................................................86

9.2.1 Analysis of the 2000-04 Non Capital Costs.........................................87 9.2.2 Operation and Maintenance Expenditure.............................................87


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9.2.3 Overheads ............................................................................................90 9.2.4 Marketing.............................................................................................90 9.2.5 Government Levies..............................................................................92 9.2.6 Retail Contestability.............................................................................92 9.2.7 Unaccounted for Gas (UAG) ...............................................................93

9.3 Recommendations for 2001-04 Non Capital Costs .....................................94 10. Non capital costs 2005-2010............................................................................96

10.1 AGLGN Forecast Expenditure ....................................................................96 10.1.1 Operating and Maintenance Expenditure.............................................96 10.1.2 Corporate Overheads ...........................................................................97 10.1.3 Marketing Expenditure ........................................................................97 10.1.4 Market Operations ...............................................................................98 10.1.5 Government Levies..............................................................................99 10.1.6 Retail Contestability.............................................................................99 10.1.7 Unaccounted for Gas..........................................................................100

10.2 Recommendations For Non Capital Costs for 2004-05 to 2009-10 ..........102 10.2.1 Operation and Maintenance ...............................................................102 10.2.2 Corporate Overheads .........................................................................102 10.2.3 Marketing...........................................................................................102 10.2.4 UAG...................................................................................................103 10.2.5 Retail Contestability...........................................................................103 10.2.6 Government Levies............................................................................103 10.2.7 Market Operations .............................................................................103 10.2.8 Summary of Recommendations.........................................................104

11. Asset Utilisation (Redundant Assets) ............................................................105 Appendices Appendix 1 Management Service Agreement Appendix 2 Stakeholders’ Comments Appendix 3 Land Management Discussion Paper Appendix 4 Expenditure Approval Levels (Maximum) – Guidelines Appendix 5 Reconciliation of Full Retail Contestability Costs for the current

Access Arrangement Period.


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List of Tables

Table 1-1 Capital Expenditure 2000 to 2004.................................................................2 Table 1-2 Recommended Capital Expenditure 2000 to 2004.......................................3 Table 1-3 Corporate IT Expenditure 2000 to 2004........................................................3 Table 1-4 Forecast Capital Expenditure 2005 to 2010 ..................................................3 Table 1-5 Recommended Capital Expenditure 2005 to 2010........................................4 Table 1-6 Submitted versus Recommended Net Working Capital ................................4 Table 1-7 Non Capital Costs 2005 to 2010....................................................................4 Table 1-8 Recommendation Non Capital Expenditure 2005 to 2010............................5 Table 2-1 Annual CPI ....................................................................................................9 Table 3-1 Details of AGLGN Network .......................................................................13 Table 4-1 Operating Pressure Table ............................................................................25 Table 6-1 Net Working Capital 2000 to 2004 .............................................................29 Table 6-2 Net Working Capital 2005 to 2010 .............................................................29 Table 6-3 Net Working Capital Components 2005 to 2010 ........................................30 Table 6-4 Net Working Capital Components 2005-2010 ............................................31 Table 7-1 Roll Forward Of Regulatory Capital Base from 1999-2004 .......................33 Table 7-2 Annual CPI ..................................................................................................34 Table 7-3 Roll Forward Of Capital Base – Wilton to Newcastle Transmission Pipeline......................................................................................................................................34 Table 7-4 Roll Forward Of Capital Base – Wilton to Wollongong Transmission Pipeline ........................................................................................................................34 Table 7-5 Roll Forward Of Capital Base – AGLGN Distribution System 1999 to 2004 (Nominal $ million) .....................................................................................................35 Table 7-6 Economic Asset Lives .................................................................................35 Table 7-7 Forecast Depreciation * ...............................................................................36 Table 7-8 Capital Expenditure 2000 to 2004...............................................................36 Table 7-9 AGLGN Actual Capital Expenditure 2000 to 2004 ....................................37 Table 7-10 AGLGN Market Expansion Capital Expenditure 2000 to 2004 .......38 Table 7-11 Market Expansion Capital Expenditure 2000 to 2004 ..............................39 Table 7-12 Mains Rate.................................................................................................40 Table 7-13 Service Rate...............................................................................................40 Table 7-14 Meter Cost .................................................................................................41 Table 7-15 Unit Cost for Medium/High Density Metering .........................................42 Table 7-16 AGLGN Recommended Market Expansion Capital Expenditure.............42 Table 7-17 AGLGN Recommended Market Expansion Capital Expenditure.............42 Table 7-18 Actual System Reinforcement Capital Expenditure 2000 to 2004............43 Table 7-19 Renewal/ Replacement Capital Expenditure 2000 to 2004.......................44 Table 7-20 Final Decision versus Actual Expenditure for M&LP Rehabilitation Program........................................................................................................................45 Table 7-21 Final Decision Capital Expenditure and Actual Expenditure....................46 Table 7-22 Comparison of Actual versus Final Decision for Non System Assets ......46 Table 7-23 Non System Assets Capex.........................................................................47 Table 7-24 Information Technology Expenditure .......................................................48 Table 7-25 Corporate IT Expenditure 2000 to 2004....................................................49 Table 7-26 Roll up table for Non System Assets Expenditure ....................................50 Table 7-27 Disposals for the Period from 1999-2004 .................................................51 Table 7-28 Roll Forward Of Regulatory Capital Base 2000 to 2004 ..........................51


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Table 7-29 AGLGN Forecast Capital Expenditure, July – December 2004 ...............52 Table 7-30 Recommended Capital Expenditure, July – December 2004....................53 Table 7-31 Recommended Capital Expenditure 2000 to 2004....................................53 Table 7-32 Corporate IT Expenditure 2000 to 20004..................................................53 Table 8-1 Roll Forward Of Regulatory Capital Base 2005 To 2010...........................54 Table 8-2 Roll Forward Of Capital Base .....................................................................55 Table 8-3 Roll Forward Of Capital Base .....................................................................55 Table 8-4 Roll Forward Of Capital Base....................................................................55 Table 8-5 Forecast Capital Expenditure 2005-2010 ....................................................56 Table 8-6 AGLGN Forecast Capital Expenditure 2005 - 2010 ...................................56 Table 8-7 AGLGN Forecast Market Expansion Capital Expenditure .........................57 Table 8-8 Mains Rate...................................................................................................58 Table 8-9 Meter Cost ...................................................................................................59 Table 8-10 Recommended Market Expansion Capital Expenditure............................60 Table 8-11 AGLGN Forecast System Reinforcement Capital Expenditure................61 Table 8-12 Recommended System Reinforcement Capital Expenditure ....................66 Table 8-13 Renewal/Replacement Forecast Expenditure, ...........................................66 Table 8-14 Details of Un-Rehabilitated Areas ...........................................................68 Table 8-15 Recommended Renewal Expenditure........................................................69 Table 8-16 Forecast Expenditure for Sydney Primary Main .......................................70 Table 8-17 Outage Consequences of an Incident ........................................................72 Table 8-18 Cost Associated with Disruption...............................................................72 Table 8-19 AGLGN Forecast Meter Capital Expenditure...........................................75 Table 8-20 Summary Table of Meter Program Detail .................................................75 Table 8-21 Recommended Forecast Renewal/Replacement Expenditure 2005-2010.79 Table 8-22 Forecast Non System Capital Expenditure 2005 to 2010..........................80 Table 8-23 Forecast IT costs 2005 to 2010..................................................................80 Table 8-24 Forecast Vehicle costs 2005 to 2010.........................................................82 Table 8-25 Forecast Other Costs 2005 to 2010 ...........................................................83 Table 8-26 Forecast Disposals 2005 to 2010...............................................................83 Table 8-27 Capital Expenditure 2005 to 2010.............................................................84 Table 9-1 Non Capital Costs 1999-00 to 2003-04 .......................................................87 Table 9-2 Operation and Maintenance Costs and Overheads......................................88 Table 9-3 Comparison of Actual and Adjusted Combined O&M and Overheads ......90 Table 9-4 Marketing Costs for 1999-00 to 2003-04 ....................................................91 Table 9-5 Comparison of Actual and Approved Government Levies Costs ...............92 Table 9-6 Actual FRC Costs 2001/02 to 2003/04........................................................93 Table 9-7 Details of Unaccounted-for Gas 2000-01 to 2003-04 .................................94 Table 9-8 Unaccounted for Gas Costs Retained by AGLGN......................................94 Table 9-9 Comparison of Actual and Adjusted Combined O&M and Overheads ......94 Table 10-1 Non Capital Costs.....................................................................................96 Table 10-2 Market Operations Costs ...........................................................................98 Table 10-3 Government Levies ...................................................................................99 Table 10-4 Retail Contestability Costs ......................................................................100 Table 10-5 Agility’s Cost for Retail Contestability. ..................................................100 Table 10-6 Details of Unaccounted for Gas 2004-05 to 2009-10..............................101 Table 10-7 Operation and Maintenance Costs...........................................................102 Table 10-8 Corporate Overheads Costs .....................................................................102 Table 10-9 Allowable UAG Costs 2004-2010...........................................................103 Table 10-10 Recommendations .................................................................................104


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Table 11-1 Wilton-Newcastle Demand Forecast.......................................................105 Table 11-2 Wilton-Wollongong Demand Forecast....................................................106

List of Figures

Figure 3-1 Map of AGLGN Network .........................................................................12 Figure 3-2 Map of Sydney, Newcastle and Wollongong Gas Networks.....................14 Figure 3-3 Schematic Diagram of Network.................................................................15 Figure 4-1Technical Management Framework............................................................21


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1. EXECUTIVE SUMMARY

Background The Independent Pricing and Regulatory Tribunal of NSW (the Tribunal) regulates prices for distribution businesses in NSW as part of the National Third Party Access Code for Natural Gas Pipeline Systems (the Code). The Tribunal is currently conducting a review of the proposed Access Arrangement for AGL Gas Networks (AGLGN) to apply from 2005 to 2010. As part of the review, the Tribunal is carrying out a capital and non capital cost study on the Access Arrangement submission provided by AGLGN in December 2003. To assist in this investigation, the Tribunal has engaged Energy Consulting Group (ECG) to advise on the efficient cost for capital and non capital expenditure. The primary objective of ECG’s consultancy is to apply Section 8 of the Code to:

• Make recommendations on actual and forecast capital expenditure undertaken in the course of the current Access Arrangement.

• Analyse capital expenditure forecast for the period of the proposed revised Access

Arrangement.

• Report on any possible capital redundancy in AGLGN assets. • Analyse AGLGN forecast non capital costs.

ECG had a number of discussions with AGLGN on the information in the Access Arrangement submission, its assumptions and the details behind the capital and non capital expenditure. ECG also discussed with various stakeholders their submissions including their comments about AGLGN’s costs. The results of the review are summarised below: Historical Capital Expenditure AGLGN actual/forecast capital expenditure in the 2000-04 Access Arrangement period is $55.9million (nominal) less than that allowed in the Access Arrangement Final Decision of July 2000. The Tribunal final decision (2000) amounts, the actual amounts and the variances are shown in the following table:


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Table 1-1 Capital Expenditure 2000 to 2004

(Nominal $ million)

1999/00 2000/01 2001/02 2002/03 2003/04 Total

Final Decision 2000

Market Expansion 52.4 38.5 38.9 39.2 38.1 207.1 System Reinforcement /Renewal/Replacement

14.5 42.6 28.5 22.0 23.1 130.7

Non System Assets 10.1 6.2 12.7 13.1 13.5 55.5

Total 77.0 87.3 80.1 74.3 74.7 393.3

Actual Actual Actual Actual Forecast Market Expansion 56.0 55.0 46.3 48.1 47.5 252.8 System Reinforcement /Renewal/Replacement

17.2 13.4 5.6 9.5 17.6 63.3

Non System Assets 5.3 2.2 5.8 2.7 5.2 21.3

Total 78.5 70.5 57.7 60.4 70.3 337.4 Variance

Market Expansion 3.6 16.5 7.3 9.0 9.4 45.7 System Reinforcement /Renewal/Replacement

2.7 (29.2) (22.9) (12.5) (5.50 (67.4)

Non System Assets (4.8) (4.0) (6.9) (10.4) (8.2) (34.3)

Total 1.5 (16.7) (22.4) (13.9) (4.3) (55.9) Following a detailed analysis, ECG has concluded the following:

• Market Expansion capital is higher than ECG’s estimate of efficient costs. • System Reinforcement/Renewal/ Replacement cost is considered reasonable.

The Sydney Primary Loop project has been deferred to the next Access Arrangement period.

• Following advice from AGLGN that it inadvertently excluded its corporate IT cost

of $24.9 million, ECG carried out a separate review on this cost. ECG considers this cost to be prudent.

The following table is the recommended expenditure for inclusion in the opening capital base for the next Access Arrangement period. The expenditure for July to December 2004 has been derived from the forecast capital expenditure as outlined in Section 7.11.


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Table 1-2 Recommended Capital Expenditure 2000 to 2004

(Nominal $ million)

1999/2000 2000/01 2001/02 2002/03 2003/04 July-Dec 04

Market Expansion 55.2 54.1 45.5 47.6 46.8 23.2 System Reinforcement/ Renewal/Replacement

17.1 13.4 5.6 9.5 15.6 15.8

System Reinforcement 1.5 0.5 2.5 6.7 3.5 2.8 Renewal/Replacement 15.6 12.9 3.1 2.8 12.1 13.0

Non System Assets 5.3 2.2 5.8 2.7 5.2 4.0 Total 77.6 69.7 56.9 59.8 67.6 43.0

Corporate IT costs not included in the above recommendation are shown in the table below:

Table 1-3 Corporate IT Expenditure 2000 to 2004 (Nominal $ million)

1999/00 2000/01 2001/02 2002/03 2003/04 Total Corporate IT 6.8 4.8 4.0 5.6 3.7 24.9

Forecast Capital Expenditure AGLGN forecast capital expenditure for the next Access Arrangement period (2005-10) is summarised in the following table. Note that expenditure in 2004-05 is for the period from 1 January 2005 to 30 June 2005.

Table 1-4 Forecast Capital Expenditure 2005 to 2010 (Real $ million 2005)

2004/051 2005/06 2006/07 2007/08 2008/09 2009/10 Forecast Market Expansion 24.5 51.7 50.3 48.7 48.5 48.4System Reinforcement /Renewal/Replacement

15.6 63.3 47.0 45.9 30.8 28.2

Non System Assets 6.4 13.0 9.9 8.0 8.2 10.9Total 46.5 128.0 107.2 102.6 87.5 87.5

Following the capital expenditure review, ECG has concluded the following:

• Market expansion capital expenditure is considered higher than what would be considered efficient.

• There is significant opportunity for cost savings in the system reinforcement/

renewal program. • There are opportunities for cost reductions in the non system assets category

especially in the IT projects.

1 Capital expenditure for 2004/05 represents the expenditure from January to June. The first half of the year has been included in the current Access Arrangement period.


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The table below provides details of the recommended expenditure:

Table 1-5 Recommended Capital Expenditure 2005 to 2010 (Real $ million 2005)

2004/052 2005/06 2006/07 2007/08 2008/09 2009/10 Market Expansion 23.2 49.0 47.4 45.9 45.6 45.4 System Reinforcement/ Renewal/Replacement

15.83 59.9 40.2 37.4 23.2 17.1

System Reinforcement 2.8 16.4 8.2 3.5 4.0 4.1 Renewal/Replacement 12.5 29.5 18.0 16.1 14.5 13 Sydney Primary Loop 0.5 14.0 14.0 17.8 4.7 0

Non System Assets 4.0 8.0 8.0 8.0 9.2 9.7 Total 43 116.9 95.6 91.3 78 72.2 Working Capital AGLGN has calculated net working capital for the 2005 to 2010 period assuming that debtors have 21 days to pay compared with14 days in the current Access Arrangement period. In addition creditors for capital expenditure are assumed to have 7 days terms instead of the 30 days taken in the current Arrangement. After discussions with AGLGN, ECG is recommending AGLGN’s cash flow timing for working capital purposes except for capital works creditors, where ECG believes that a 27.7 day period is appropriate The table below shows the submitted versus recommended net working capital.

Table 1-6 Submitted versus Recommended Net Working Capital (Nominal $ million)

2004/05 2005/06 2006/07 2007/08 2008/09 2009/10

Submitted 46.8 48.7 51.7 54.6 57.8 61.8Recommended 41.1 41.6 45.9 49.0 53.0 56.5 Non Capital Expenditure In its Access Arrangement Information for the forthcoming Access Arrangement period AGLGN notified the forecast costs for non capital expenditure set out in the table below:.

Table 1-7 Non Capital Costs 2005 to 2010 (Real $ million 2005)

Year Ending June 2004/05 2005/06 2006/07 2007/08 2008/09 2009/10 Controllable Costs Operation & Maintenance(O&M) 61.4 61.5 62.2 62.5 62.9 63.2Administration & Overheads 18.9 19.0 19.2 19.3 19.3 19.4

2 Capital expenditure for 2004/05 represents the expenditure from January to June. The first half of the year has been included in the current Access Arrangement period. 3 The expenditure is higher than in the Access Arrangement Information due to a reinforcement project in 2003/04 being deferred to 2004/05. Refer Table 8-12


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Year Ending June 2004/05 2005/06 2006/07 2007/08 2008/09 2009/10 Market Operations 4.3 4.3 4.3 4.3 4.3 4.3Marketing 16.5 16.5 16.5 16.5 16.5 16.5Real Controllable 101.1 101.3 102.2 102.6 103.0 103.4Other Costs Government Levies 3.9 3.9 3.9 3.9 3.9 3.9Retail Contestability 3.9 3.9 3.9 3.9 3.9 3.9UAG 9.1 9.1 9.3 9.3 9.4 9.5

Total 118.0 118.2 119.3 119.7 120.2 120.7

ECG reviewed the non capital cost for the current Access Arrangement period and based on its conclusion of the efficient costs for the current period, estimated the efficient costs for the forecast Access Arrangement period. The following conclusions were reached:

• Based on the productivity indicators, AGLGN’s proposed efficiency factor of 1.5% is considered to be reasonable.

• ECG believes that the efficient cost for O&M should be lower than the AGLGN

forecast.

• The marketing expenditure is considered reasonable taking into account AGLGN’s business case to target the hot water market in existing homes.

• Efficient Market operations expenditure should be less than forecast.

• Unaccounted for Gas (UAG) should be set at a lower rate than the forecast.

The table below provides details of the efficient expenditure:

Table 1-8 Recommendation Non Capital Expenditure 2005 to 2010 (Real $ million 2005)

2004/05 2005/06 2006/07 2007/08 2008/09 2009/10Controllable Costs Operation & Maintenance 61.4 61.5 62.2 62.5 62.9 63.2 Administration & Overheads 18.3 18.4 18.6 18.7 18.7 18.8 Market Operations 3.5 3.5 3.5 3.5 3.5 3.5 Marketing 16.5 16.5 16.5 16.5 16.5 16.5 Total controllable 99.7 99.9 100.8 101.2 101.6 102.0 Other Cost Government Levies 3.2 3.2 3.2 3.2 3.2 3.2 Retail Contestability 4 3.9 3.9 3.9 3.9 3.9 3.9 UAG 9.1 9.1 8.9 9.0 9.0 9.1 Total 115.9 116.1 116.8 117.3 117.7 118.2

Asset Utilisation

4 To be finalised following discussions with further AGLGN.


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As part of the consideration for identifying redundant assets, ECG has reviewed the utilisation of the two trunk pipelines: • Wilton to Newcastle • Wilton to Wollongong ECG concluded that the contract load reduction is in the order of 10% of the diversified MDQ on both pipelines.

Other recommendations • Data on the quantities of mains, meters and services, and their unit costs, for growth

– market expansion expenditure in the 2005 to 2010 period is collected and made available for analysis prior to the next period.

• A clear presentation of all options considered is provided in the future for system reinforcement projects.

• A review of peak hour and severe weather load factors is conducted at least once

every five years.


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2. INTRODUCTION

2.1 BACKGROUND

In December 2003, AGL Gas Networks (AGLGN) submitted its proposed Access Arrangement revisions relating to the natural gas distribution system in NSW to the Independent Pricing and Regulatory Tribunal of NSW (the Tribunal) for review under the National Third Party Access Code for Natural Gas Pipeline Systems (the Code). The Tribunal has engaged Energy Consulting Group (ECG) to conduct a review of AGLGN’s capital and non capital expenditure (together referred to as ‘total cost’) to assist the Tribunal in its assessment of the proposed Access Arrangements.

2.2 SCOPE OF CONSULTANCY

The focus of ECG’s review and this report is on providing an overall view of:

• Whether the proposed levels of capital and non capital expenditure are reasonable and efficient.

• The prudence of capital expenditure from the beginning of the current Access

Arrangement (1 October 2000). The review has taken into account the specific objectives and principles of the Code.

2.3 OBJECTIVES OF CONSULTANCY

The primary objective of ECG’s consultancy is to apply Section 8 of the Code to:

• Make recommendations on actual and forecast capital expenditure undertaken in the course of the current Access Arrangement.

• Analyse capital expenditure forecast for the period of the proposed revised Access

Arrangement.

• Report on any possible capital redundancy in AGLGN assets.

• Analyse AGLGN forecast non capital costs.

2.4 GENERAL APPROACH

In undertaking its study, ECG considered:

• Sections 8.16 to 8.19 of the Code which set out how the capital base of a pipeline can be increased by actual capital expenditure and sections 8.20 to 8.22 which deal with forecast capital expenditure.

• Sections 8.36 and 8.37 which define non capital costs and outline the criteria for acceptance.


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• Current demand and likely future demand as forecast by AGLGN. • AGLGN proposed Access Arrangements and Access Arrangement Information

(December 2003) and any further revisions to the Access Arrangement Information.

• AGLGN current Access Arrangement and Access Arrangement Information.

• Discussions with AGLGN and Agility (AGLGN’s asset management services

provider) staff and information provided. • Stakeholder submissions on the proposed Access Arrangement. • Discussions with stakeholders including AGLGN. • Other relevant studies and reports available to ECG. • Gas Supply Act 1996.

In assessing capital and non capital expenditure, ECG took into consideration the specific requirements of sections 8.16(a) and 8.37 of the Code that costs must not exceed the amount that would be invested by a prudent Service Provider acting efficiently, in accordance with accepted good industry practice, and to achieve the lowest sustainable cost of delivering Services and Reference Services. Achieving the lowest sustainable cost requires an optimum balance of capital and non capital expenditure. The majority of AGLGN’s network assets are long-life (up to 80 years) buried gas mains and services and the safety and integrity of these assets must be maintained in the long term. In its assessment of lowest sustainable costs for the current and forecast periods, ECG has endeavoured, as far as practicable, to take the life-cycle requirements of each asset category into account. The Code does not provide a prescriptive approach for a Regulator (in this case the Tribunal) to determine lowest sustainable costs of delivering Services and Reference Services. Consequently ECG has assessed the capital and non capital expenditure as outlined in sections 7.1 and 9.1 respectively. In applying the Code, ECG has considered the following as provided by the Tribunal:

• ‘Prudent’ as meaning discreet or cautious in managing one’s activities; practical and careful in providing for the future and exercising good judgement.

• ‘Efficient’ as meaning functioning or producing effectively and with the least waste

of effort. ECG also:

• Individually assessed capital expenditure projects which are material for the purposes of the total cost review.

• Examined the effect of capital expenditure decisions on the level and quality of

reticulation services. • Examined trade-offs between capital and non capital expenditure.

• Identified and segregated capital expenditure to which users may make capital

contributions.


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In its analysis of capital and non capital expenditure ECG, as far as possible, distinguished between:

• Different categories of customers, particularly contract customers and tariff customers.

• Different regions. • The low pressure, medium pressure and high pressure sections of the network.

2.5 EXPENDITURE ASSESSMENT – JANUARY TO DECEMBER 2004

The current Access Arrangement expected the new Access Arrangement to be effective from 1 July 2004. After considering AGLGN’s representations in February 2003, customer views and the requirements of the Code, the Tribunal agreed to vary the Revisions Submission Date to 31 December 2003 and the Revisions Commencement Date to 1 January 2005. The current price path was initially set with a Revisions Submission Date or expiry on 30 June 2004. AGLGN sought and the Tribunal agreed to an amendment to extend the Revisions Submission Date by six months and the current review will result in the Tribunal setting a revised price path to operate from 1 January 2005 until 30 June 2010. The efficiency of AGLGN’s estimates of capital and non capital expenditure proposed for the interim six month period is examined separately.

2.6 USE OF INFLATION FACTORS

In its Final Decision in 2000, the Tribunal allowed the capital base to be inflated using the CPI, All Groups index number for the weighted average of eight capital cities. The CPI figures to 2002-03 are shown in Table 2-1.

Table 2-1 Annual CPI Financial Year CPI %

1999 1.31 2000 2.38 2001 5.97* 2002 2.86 2003 3.09 2004 2.35

* GST Inclusive. 2.89% excluding GST Forecasts of CPI are necessary for the roll forward of the capital base. An accepted market based estimate of future inflation is provided by the implicit rate derived using the Fisher equation from the yield on long term Commonwealth Government bonds and the yield on Index linked Government bonds. This is the method preferred by the Tribunal. While this rate will vary with market conditions, it is currently 2.35% per annum. Most historical tables in this report are presented in nominal terms and forecast figures in 2004-05 constant prices. This will lead to small differences in 2003-04 where AGLGN has used an inflation rate of 2.75%. The actual CPI for 2003-04 will be available from the Australian Bureau of Statistics in July and all figures can then be adjusted for the actual value.


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2.7 AGLGN/AGILITY RELATIONSHIP

AGLGN formally entered into an agreement with Agility Management Pty Ltd (Agility) to provide services to AGLGN from 1 July 2002. The agreement is for a 10 year term and will expire on 30 June 2012. At the end of that period, the agreement will automatically be renewed for a further five years. Under the agreement, Agility is to provide all the services related to operating and maintaining the network. ECG’s observations are that Agility is performing all the services specified in the Management Services Agreement related to operating and maintaining the network. Details of the AGLGN/Agility relationship are considered confidential.


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3. DESCRIPTION OF AGLGN GAS NETWORK

3.1 GENERAL OVERVIEW

The AGLGN gas network is comprised of approximately 23,000 km of pipe in the trunk, high pressure, medium pressure and low pressure segments. The network covers the following:

• The trunk pipelines from Wilton to Wollongong, Wilton to Horsley Park, Horsley Park to Plumpton and Plumpton to Newcastle.

• Sydney metropolitan region. • Central Coast. • Newcastle and the Hunter region. • Wollongong and Shellharbour region. • Blue Mountains. • Bathurst, Orange, Lithgow, Oberon and smaller centres in the Central Tablelands. • Forbes, Parkes, Dubbo, Narromine, Wellington and smaller centres in the Central

West. • The Southern Highlands and South West Slopes centres of Young, Yass,

Goulburn, Marulan, Moss Vale, Mittagong and Picton. • Griffith, Leeton, Narrandera and smaller centres in the Riverina and

Murrumbidgee Irrigation Area.


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Figure 3-1shows the extent of the network.

Figure 3-1 Map of AGLGN Network 5

3.1.1 Receipt Points

There are numerous custody transfer points where natural gas is received into the AGLGN gas network:

• At Wilton, the Sydney City Gate, where the gas from the Moomba to Sydney Pipeline (MSP), owned by Australian Pipeline Trust (APT), joins the network. This gas is predominantly from the Cooper Basin.

• The Moomba to Sydney Pipeline System is interconnected with the Victorian

system, owned by GasNet, at Culcairn. Only small quantities of gas normally flow between the two systems at Culcairn.

• The following lateral pipelines in APT’s MSP transmission system deliver gas into

the AGLGN network:

o The Central West Pipeline to Forbes, Parkes, Dubbo and smaller centres. o The Northern Lateral from Young to Cowra, Blayney, Bathurst, Orange,

Lithgow and smaller centres. o The Southern Lateral from Young to Cootamundra and Wagga Wagga. o The Griffith Lateral from Junee to Narrandera, Leeton, Yanco, Griffith and

smaller centres.

• Local distribution systems at West Wyalong, Yass, Boorowa, Goulburn, Marulan, Moss Vale, Bowral, Mittagong, Picton and some smaller centres are supplied directly from the MSP.

5 Agility map of AGLGN’ coverage


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• At Horsley Park the Eastern Gas Pipeline (EGP), owned by Alinta, interconnects with the Sydney High Pressure Network. Gas from the EGP is sourced from the Gippsland Basin.

• At Wollongong, near the Bluescope Steel Works, a second interconnection with

the EGP delivers gas into the Wollongong High Pressure Network.

• At Camden to the west of Sydney relatively small quantities of coal seam methane supplied by Sydney Gas enter the distribution system. Larger quantities are expected to be supplied from this source in the future.

Table 3-1 shows the length of pipeline and mains in AGLGN network.

Table 3-1 Details of AGLGN Network km of pipeline or mains Trunk pipelines 298 Primary mains 109 Secondary mains 1409 Medium and low pressure mains 21,300

Figure 3-2 shows details of the network covering the Sydney, Newcastle and Wollongong regions. Figure 3-3 is a schematic diagram of the network.


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Figure 3-2 Map of Sydney, Newcastle and Wollongong Gas Networks6

6 Agility map of AGLGN’s coverage


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Figure 3-3 Schematic Diagram of Network7

Transmission PipelineGasField

MeterStation

TRS

Trunk Main (6895 kPa MAOP)

PRS

Primary Main(3400 kPa MAOP)

SRS SRS

MPRS

Meter Set

Meter Set

STEEL

PLASTIC

LargeIndustrialCustomers

IndustrialandCommercialCustomers

POTS

LargeIndustrialCustomers

Meter Set

Meter Set

Residential,IndustrialandCommercialCustomers

Meter Set

Residential,IndustrialandCommercialCustomers

POTS POTS

MeterStation

TRS

TRS

Secondary Main (1050 kPa MAOP)

Medium Pressure Mains (30, 100, 210, 300, 400 kPa MAOP)

Low Pressure Mains (2, 7 kPa MAOP)

Network Configuration

3.1.2 High Pressure Systems

The trunk pipelines (Wilton to Wollongong, Wilton to Horsley Park, Horsley Park to Plumpton and Plumpton to Newcastle) each operate at a maximum allowable operating pressure (MAOP) of 6895 kPa. The 51km Wilton to Horsley Park Pipeline is 864 mm outside diameter while the remaining 247 km of trunklines are 508 mm outside diameter. The Primary Mains System supplied by the trunk pipelines operates at a MAOP of 3400 kPa. All of the trunk system and the Primary Mains System are comprised of high tensile steel pipe which is cathodically protected to resist corrosion. There are 109 km of primary mains, ranging from 150 to 550 mm nominal bore. A small number of large contract customers are supplied directly from the primary mains. The Secondary Mains System is also comprised of cathodically protected steel pipe, the MAOP being 1050 kPa. A number of large customers are supplied directly from the secondary mains. There were 1409 km of secondary mains at June 2003 with 1809 secondary services supplied.

3.1.3 Low and Medium Pressure Systems

The majority of mains and services in the low and medium pressure system (approximately 95%) are plastic (mostly nylon with some polyethylene, mainly in feeder mains). Approximately 5% is cast iron, galvanised cast iron and unprotected steel. The low pressure system operates at either 2k Pa or 7 kPa. The medium pressure systems have a

7 Agility schematic on pressure levels.


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MAOP of 210, 300 or 400 kPa. Approximately 21,300 km of mains were in place in the low and medium pressure systems at June 2003. By July 2002 approximately 95% of the original ferrous mains had been renewed. Approximately 427 km of cast iron mains still exist, serving 24,730 end users. The rehabilitation program is continuing, with periodic reviews base on assessment of the safety, reliability and profitability risks.

3.1.4 Facilities

Gas regulating facilities comprise the following:

• Custody Transfer Stations (CTSs) and Trunk Receiving Stations (TRSs).

• Primary Regulating Stations (PRSs).

• Packaged Off-Take Stations (POTSs).

• District Regulator Sets (DRSs).

CTSs and TRSs filter and regulate gas received from the transmission pipelines (the Moomba to Sydney Pipeline and its various laterals and the EGP) to the primary high pressure network. They deliver gas at the appropriate pressure for the network (between 210 and 3,400 kPa). There are 27 TRSs in the network. Primary Regulating Stations (PRSs) filter gas and regulate pressure at each offtake from the primary high pressure network to the secondary high pressure network (i.e. from a MAOP of 3,400 kPa to a MAOP of 1,050 kPa. There are 11 PRSs, mostly located in Sydney (viz. Horsley Park, Auburn, Flemington, Mortlake, North Ryde, Willoughby, Haberfield, Tempe, Mascot and Banksmeadow). A POTS is a smaller modular version of a PRS which combines the functions of measurement, filtration and pressure reduction to the appropriate level (210 to 1050 KPa). There are 26 POTSs in the network. DRS is the generic term used to describe regulators that supply the medium and low pressure networks. There are three types:

• Secondary Regulator Sets (SRSs). • Medium Pressure Regulator Sets (MPRSs). • Low Pressure Regulator Sets (LPRSs).

SRSs are required at each offtake from the secondary high pressure networks to regulate pressure to the medium pressure distribution networks. They reduce the pressure from 1,050 kPa to 7, 30, 210 or 400 kPa. There are 476 SRSs in the network. MPRSs are required at each offtake from the medium pressure system to supply low pressure systems. They reduce the pressure from between 210 to 400 kPa to 7 or 2 kPa. There are 80 MPRSs. LPRSs operate at 7 kPa inlet pressure, reducing to 2 kPa to supply low pressure networks. There are 9 LPRSs. These facilities are purpose designed, technically complex and subject to stringent maintenance regimes to provide full operational redundancy to ensure that gas supply is maintained in the event of component malfunction or failure.


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3.1.5 Pressure Control

TRSs supplied from AGLGN’s trunk mains have metering facilities included while TRSs supplied from APT’s transmission system typically have APT meter stations immediately upstream. The TRSs are remotely controlled via the network SCADA system. POTSs are typically remotely monitored via the SCADA system. DRSs are not directly remotely monitored but their correct operation can be determined by the network SCADA system which monitors the pressure in the mains downstream.

3.1.6 Meters and Services

Each contract and tariff customer is supplied with a meter set for billing purposes. The meter set comprises a pressure regulator and a meter to measure customer consumption. All contract customer meters are linked via telephone lines to Agility’s Remote Billing System. Each meter set is connected to the gas main in the street via a customer service pipe. A service valve installed at the meter set enables gas to be turned off in the event of an emergency and for maintenance of the meter set and customer installations.

3.1.7 Customer Installations

Customer installations comprise customers’ appliances and associated pipe work supplying gas from the gas meter. Customer installations are not part of AGLGN’s gas network.

3.2 CONDITION OF ASSETS

From the information provided, ECG has reviewed the condition the condition of the assets. Details of the assessment are provided below:

3.2.1 Trunk Pipelines

The trunk pipelines are considered by ECG to be in good condition. They are 100% cathodically protected with protection levels in the desired range to minimise corrosion risk. Recent intelligent pigging runs have identified some metal loss locations. Identification and assessment of metal loss locations is part of an ongoing integrity management plan. No excavations carried out in the last reporting year required repairs other than coating replacement.

3.2.2 Primary Mains

The primary mains are considered by ECG as being in good condition. These mains were 97% cathodically protected and following commissioning of a new system in 2004 will be 100% protected with levels in the desired range. No significant metal loss due to corrosion has been detected to date on primary mains. There will be an increasing reliance on coating surveys, excavations and ensuring adequate CP levels to manage corrosion risk. Primary mains are not able to be pigged.


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3.2.3 Secondary Mains

The secondary mains networks are considered by ECG as being in generally good condition with most having an expected remaining life in excess of 50 years. Secondary mains integrity relies mainly on coating surveys and cathodic protection. CP protection will be restored from 99.5% to 100% in 2004. Past inspections of exposed secondary mains have shown corrosion incidents requiring only coating repair. No significant metal loss due to corrosion has been identified on buried secondary mains to date.

3.2.4 Medium and Low Pressure Mains

Under the Goldline Program extensive areas of medium and low pressure mains have been rehabilitated. Approximately 95% of the original ferrous networks have now been renewed. The highest priority areas have been completed and remaining areas are assessed on risk and economic criteria. Hence, with the exception of the 427 km of the remaining ferrous networks, the medium and low pressure mains are in good condition. Unaccounted for gas had been reduced to 2.1% by 2003-03. Publicly reported leaks per 1,000 customers for the same year was 12.0 which is well below the rate for similar Victorian operations8. Similarly, leaks detected per km of leakage survey were 0.122 for the same year, compared with 0.54 to 0.7 for the Victorian networks9.

3.2.5 Trunk Receiving Stations

The TRSs are assessed by ECG as being in generally good condition.

3.2.6 Primary Reduction Stations

The PRSs are considered by ECG as being in generally good condition. Noise levels arising from valves at five older PRSs need to be addressed as they do not meet Environmental Protection Agency and Occupational Health and Safety guidelines. Spare parts for the obsolete valves are also difficult to obtain.

3.2.7 District Regulator Sets

For safety and statutory reasons, an additional level of overpressure protection is to be installed on low pressure outlet DRSs in the period 2003 to 2006. Corrosion, wetness and unserviceable seals are regarded as significant interrelated problems. An integrity audit carried out by Agility in 2003-04 has indicated a need to improve ongoing field maintenance and integrity management of DRSs. ECG considers this to be a prudent initiative by AGLGN.

3.2.8 Residential Gas Meters

The AGLGN metering systems are assessed by ECG as generally being in good condition. Sampling of the meter population has shown that those meters that have been exposed to dry natural gas are sufficiently accurate to remain in service after 15 years. These meters are estimated to be able to remain in the field for an additional 10 years. However, meters that are exposed to wet gas are do met the performance criteria after 15 years and have to be removed from the field.

8 AGLGN Asset Management Plan 2004/05, p58. 9 AGLGN Asset Management Plan 2004/05, p58.


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AGLGN has advised that 30% of the meters installed in 1988 are sufficiently accurate to remain in service for a further 10 years.

3.2.9 Industrial and Commercial Meter Sets

Industrial and Commercial meter sets are assessed as being in generally good condition, based on the low level of unaccounted for gas and the low level of customer billing complaints and service-generated meter replacements.

3.2.10 Residential Hot Water Meters

The accuracy of residential hot water meters can deteriorate over time, particularly if the water has high levels of minerals or debris. Deterioration of rubber sealing glands and rings over time also creates the potential for indoor water leakage. AGLGN replaces these meters that have been reported as faulty. On average, meters are replaced when they have been in service for 20 years. ECG considers that this is consistent with the practice of service providers in other jurisdictions.

3.3 REDUNDANT ASSETS

A Capital Redundancy Mechanism is provided in AGLGN’s Access Arrangement Submission. With effect from the commencement of the subsequent Access Arrangement period, the Relevant Regulator may reduce the Capital Base by an amount representing:

• Any assets that in the reasonable opinion of the Relevant Regulator have ceased to contribute to the delivery of Services.

• Any assets that have been transferred by AGLGN or in relation to which AGLGN

has entered into a binding agreement for its transfer. • Any assets that in the reasonable opinion of the Relevant Regulator have

decreased in value because of a decrease in its utilisation resulting from a decline in the volume of sales of this Service.

In assessing the reduction in the Capital Base due to a decreased utilisation of assets resulting from a decline in the volume of sales of a Service, the Relevant Regulator may take into account any reduction in the depreciated optimum replacement cost of the assets, the cost to AGLGN of the reduction in Total Revenue and any possible increase in Tariffs paid by Users resulting from the decline in utilisation of assets. In its Access Arrangement submission, AGLGN included redundant assets as “Disposals”, which reduce the regulatory capital base. These include mains, services and meters which are scrapped and removed from the Fixed Asset Register, but do not include any under utilised assets. A number of stakeholders in their submissions consider there may be under utilised assets, which could be considered redundant. A review of these issues is undertaken in subsequent sections on Disposals and Asset Utilisation. The wording of the clause in the third bullet point above is an AGLGN proposal which deletes previous reference to “a likely decline in the volume of sales”. ECG considers the proposed change is not material to any issue raised in this report, provided that the remaining reference to “a decline in the volume of sales” does not preclude consideration


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of any decline in the volume of sales during the last years (in this case 2003/04) of the current period, but occurring after the initial submission (in this case in December 2003). However, it may have a material impact on future Access Arrangement depending on the particular circumstances of the forecast volume of sales at that time.


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4. ASSET MANAGEMENT

4.1 ASSET MANAGEMENT PLANS

Agility’s framework used for the technical management of AGLGN’s assets is illustrated in Figure 4-1.

Figure 4-1Technical Management Framework10

The asset management plans, in conjunction with the network Safety and Operating Plan and the Regional Gas Network Management Plans as well as other asset-specific plans, provide the strategic direction for management of AGLGN’s assets within New South Wales. The Asset Management Plan, New South Wales AGL Gas Network details service level targets, activities and capital projects planned for the assets for a five-year period and it is revised annually. The AGLGN’s assets covered by the plan include:

• Trunk Pipelines and Facilities. • Primary Mains, Facilities and services. • Secondary mains and services. • Low and medium pressure mains and services.

10 Gas Networks Management Plan 2003, Sydney North Draft

Client Contracts and Business plans

Target Service Levels

Asset Management Plans

Gas Network Management Plans

Safety and Operating Plans

Other Plans •Environment •Emergency

Technical Policies

•Documented Agility expertise at industry level

Work Method Statements

•Documented Agility expertise at activity/ task level

Activity /Project Specifications •Selected package of Agility know-how for.

•Specific activities /projects •Response to tenders •Documentation for external sub-contractors

Inputs Client specific Strategic plans Agility know-how Activity/ Project Specifications

Acts and Regulations

Licences

Australian Standards Asset Performance, Condition and Demand

AGL Corporate Policies

Asset Specific Manuals


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• Pressure regulating stations (all pressures). • SCADA, communications and monitoring. • Meter installations, including those for hot water.

Excluded from the plan are:

• Tariff and contracting price arrangements. • Agility equipment, buildings and materials. • AGL information technology assets. • Vehicles, plant and equipment.

The Asset Management Plan 2004/05 is a high level overview of the current and proposed strategies for the effective management of the AGLGN assets. It is a master document that summarises and references a number of sub plans and other documents that detail the management strategies and programmes. ECG has reviewed AGLGN’s/Agility’s Asset Management Plan 2004/5 Draft C as well as a number of the regional Gas Network Management Plans which cover: :

• Asset Descriptions and Asset Management Philosophy. • Asset Performance Targets. • Technical Regulatory Compliance Plan.

• Lifecycle asset plans for the various asset categories, eg. mains and services,

facilities, meters. • Technical Operating Plan. • Commercial Operating Plan.

Overall, ECG believes that the Asset Management Plan, together with the regional Gas Network Management Plans, provide a reasonable overview of the AGLGN assets, the asset management philosophy and the operational and maintenance needs of the assets over the next five years.

4.2 SAFETY AND OPERATING PLAN

AGLGN is the “Authorised Reticulator” for its gas network in NSW as defined in the Gas Supply Act 1996 (NSW). The Safety and Operating Plan for the NSW Distribution Network has been prepared for AGLGN by Agility to ensure the safe operation of the network in NSW. It has been written in accordance with the Gas Supply (Network Safety Management) Regulation 2002 made under the Gas Supply Act. It forms the basis by which AGLGN and Agility fulfil their legal obligations under the Act. ECG was provided with a copy of the Plan (Version 4 dated 1 March 2004) for the purposes of this report and has reviewed its contents. The Plan comprises the following:

• A statement of the objectives of the Plan.


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• A description of the organisation structure and responsibilities of key positions with approval authorities for the procedures and plans.

• A description of the gas network within each distribution district including suitable

maps showing the pipeline route and location of associated facilities. • Risk assessments including identified threats and the design, operational and

maintenance measures required to eliminate or reduce these threats to as low as reasonably practicable (ALARP).

• A summary of the policies and procedures which Agility follows in the design,

construction, operation and maintenance of the network. • A summary of the emergency response plans. • AGLGN’s requirements for gas quality and pressure standards, including odorant

levels, and the procedures which have been implemented to ensure that gas conveyed in the network meets those standards.

• A summary of the records management plan. • Reporting requirements through appropriate performance indicators by which the

Plan’s compliance with policies and procedures is confirmed.

The objectives of the Plan are to:

• Identify relevant hazards • Analyse the risks associated with those hazards. • Develop minimum standards for the identified hazards to prevent, protect and

mitigate those risks. • Document the standards as policies, specifications and procedures. • Periodically review and revise those policies, specifications and procedures. • Maintain a robust system for emergency or incident response. • Maintain appropriate records for the operation of the network. • Monitor and maintain the appropriate performance indicators relevant to those

objectives. Like the Asset Management Plan it is a master document that summarises and references a number of sub plans and other documents that detail the management strategies and programmes. The Plan states that independent periodic audits will be conducted and audit reports will be submitted to the NSW Technical Regulator in accordance with legislative requirements. It is considered that AGLGN’s Safety and Operating Plan is what would be expected from a prudent owner/operator as required under the General Principles of the Code, section 8.1(c) which states “A Reference Tariff and Reference Tariff Policy should be designed with a view to achieving the following objective – ensuring the safe and reliable operation of the Pipeline”


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4.3 NETWORK CAPACITY PLANNING PROCESS

Network Capacity Planning is a key function that underpins the capital expenditure program. It is fundamental to assessing the capability of gas networks to deliver gas loads to all customers prudently and efficiently, as required under section 8.16 of the National Third Party Access Code. Planning is conducted in accordance with the requirements of AGLGN technical procedure TPC.PROC.4.99.28, Gas Network Design Criteria and Performance Validation for Supply Reliability and Growth. The principal activities in the process include:

• Forecasting peak loads. • Modelling current network performance. • Predicting future network performance. • Determining timing for network augmentation. • Specifying projects for inclusion in the capital expenditure program.

4.3.1 Peak Load Forecasting

Forecasts of peak hour loads that are needed for developing gas network models are determined from annual sales forecasts for tariff and contract customers. A review of the annual sales forecasts is being undertaken separately by McLennan Magasanik Associates. Peak hour loads for contract customers (>10Tj pa sales) are determined from the MHQ loads defined in the contracts, and load diversities determined by network performance modelling and validation. Peak hour loads for industrial & commercial customers (<10Tj pa sales) are determined from annual sales forecasts, and load factors for the customer type determined by network performance modelling and validation. Peak hour loads for residential customers are estimated from the annual sales forecast for normal winter weather conditions, by applying peak hour load factors. Networks are planned to have sufficient capacity to supply the peak load, forecast to occur in less than 1 in 10 year severe winter weather conditions. The peak loads determined above are adjusted to those expected under severe weather conditions, by applying a severe winter peak load factor.

4.3.2 Network Performance Modelling

Network modelling is conducted using the internationally accepted Advantica Synergee software. Each of the gas networks is modelled in accordance with the above technical procedure, Gas Network Design Criteria and Performance Validation for Supply Reliability and Growth. Model validation is conducted and reported annually, based on a program of pressure measurements used to monitor network performance under winter high load conditions. Results from this program are used to establish current load conditions and diversities so that network model predictions closely match actual field performance, and therefore can be reliably used to predict network capacity and performance. The specification of pipes and loads in each network is manually updated in accordance with a defined annual review program.


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4.3.3 Network Performance Prediction

Future networks performance for each year are predicted from validated network models for the present year, and from forecast severe winter loads for each year, determined as above. These models are used to determine when network minimum pressures are predicted to fall below the allowable values specified in the AGLGN technical procedure referred to in Section 4.3, and therefore to determine the timing for completion of network reinforcement projects to ensure adequate network capacity. They are also used to predict the network performance after completion of reinforcement projects, as part of the process for planning these projects. The maximum and minimum pressures for the high, medium and low pressure networks are as given in the following table. They are critical in determining the size of pipes within each network, to ensure the network has sufficient capacity. They are also critical for assessing the capacity of the many regulator stations used to supply gas from higher pressure networks to lower pressure networks.

Table 4-1 Operating Pressure Table

System Maximum Allowable Operating

Pressure (MAOP) (kPa)

System Minimum Pressure (kPa)

Trunk NA NA High - Primary 3400 1700

High - Secondary 1050 525 Medium 400 70

300 70 210 70 100 40

Low 7 3.5 2 1.5

ECG considers the network planning process to be what would be expected from a prudent operator acting efficiently, consistent with good industry practice in accordance with the requirements of section 8.16 of the Code.

4.4 CAPITAL EXPENDITURE PROCESS

Under sections 8.16 and 8.17 of the National Third Party Access Code for Natural Gas Pipeline Systems, capital expenditure must be prudent and efficient to be accepted for inclusion in the Capital Base.

It must not exceed the amount that would be invested by a prudent service provider acting efficiently, in accordance with accepted good industry practice, and to achieve the lowest sustainable costs of delivering services. In addition it must satisfy one or more of the following conditions.


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1. The anticipated incremental revenue generated by the new facility exceeds the new facilities investment; or

2. The service provider and/or users satisfy the relevant regulator that the new

facility has system wide benefits that, in the relevant regulator’s opinion, justify the approval of a higher reference tariff for all users; or

3. The new facility is necessary to maintain the safety, integrity or contracted

capacity of services. AGLGN authorisation of capital expenditure is obtained in accordance with AGL’s procedure 11 which outlines expenditure approval levels and the procedure for administration of the acquisition and disposal of investments. This procedure has been prepared by AGL Corporate and applies to all AGL businesses and includes:

• Expenditure approval levels. Details of the approval levels are shown in Appendix 4. The procedure requires that any delegations of expenditure authority levels are provided to the Manager Group Audit Services and the Group General Manager Finance.

• Introduction with issues to be considered for financial evaluation and approval of

capital expenditure, including reasons for the expenditure and its timing.

• Details of information required for assessment including financial forecasts, term of evaluation, taxation, profit summary and cash flow.

• Description of the financial assessment process including financial rate of return and net present value calculations

Under the agreement between AGLGN and Agility, prior to the commencement of each financial year Agility provides a 5 year capital plan. In addition, a one year capital budget is prepared by Agility for AGLGN. This requires AGL Board approval as does any new supply project >$4 million. Following Board approval of the annual capital budget, each project must be approved by the appropriate manager within delegated authorisation levels. ECG’s review of documents provided and discussions with Agility Managers concluded that each Manager is fully aware of his expenditure delegation level and must work within these levels. In relation to any project that exceeds budget, additional expenditure must be approved by the appropriate senior manager including Group General Manager and the Managing Director. Appendix 4 shows approval expenditure levels. Whilst ECG has not had any discussions with the internal auditors on any compliance issues in relation to expenditure authorisation, it has not identified any issues of concern.

Agility operates a computer-based module, the RUGS system, to respond to day-to-day gas supply requests, obtain capital approval, and manage approved works. AGLGN advise that authorisation is provided for projects that have a return on investment at least equal to a hurdle rate which is significantly higher than the equivalent WACC of 7.85%pa pre tax real rate of return proposed by AGLGN for the total capital in the Access Arrangement period. This return is to be achieved with a 20 year project life for residential customers, and a 10 year project life for Industrial / commercial customers.

11 Acquisition and disposal of investment/subsidiaries and property, plant and equipment.


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ECG considers the capital expenditure process to be what would be expected from a prudent operator acting efficiently, consistent with good industry practice. ECG considers the hurdle rate used by AGLGN commercially acceptable for these types of projects, and in accordance with the requirements of Section 8.16 of the Code. AGLGN uses this high hurdle rate of return so that total expenditure over all projects can achieve an overall rate of return of at least 7.85%pa rate of return. This allows expenditure on projects essential for Capacity Development (System Reinforcement), Stay in Business (Renewals / Replacement / Security of Supply), and Non System Assets, consistent with above conditions 2 and 3, to proceed. Customer capital contributions are obtained if relevant and necessary to meet the hurdle rate.


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5. STAKEHOLDER CONSULTATION

A number of stakeholders made submissions to the Tribunal on the Access Arrangement proposals made by AGLGN. These submissions covered a wide range of issues, including comments on AGLGN’s current and proposed capital and operating costs. As part of its consideration of AGLGN’s total costs, ECG visited stakeholders who had made extensive comments on costs. These included:

• Orica.

• Energy Australia.

• Energy Advice, which prepared a submission from The Hunter Users Group as well as another submission representing a number of larger contract customers in New South Wales.

The main concerns of stakeholders with respect to capital and operating costs included: Capital Costs AGLGN has proposed significant increase in capital costs in the next Access period. This appears high especially given the relatively flat demand forecast.

• No allowance has been made by AGLGN for redundant capital.

• Metering capital and operating expenditure is projected to increase at a rate difficult to justify.

• Net working capital increases are too high in relation to total revenue growth.

Non capital Costs

• The efficiency savings factor of 3% pa was achievable and should be retained, particularly given AGLGN’s demonstrated capital expenditure on initiatives to improve operating efficiency.

• AGLGN’s marketing costs claims were excessive.

• AGLGN’s proposed UAG numbers should be benchmarked against industry best

practice.

• AGLGN’s proposed Market Operations costs were too high. Where appropriate, comments made by stakeholders are covered in the consideration of capital and operating costs in this report. A more detailed summary of the comments made by stakeholders on capital and operating costs is included in Appendix 2.


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6. WORKING CAPITAL

In its Final Decision in 2000 the Tribunal allowed AGLGN’s distribution revenues to contain a nominal return on its net working capital. This was calculated by deducting current liabilities (creditors) from current assets (debtors + unbilled gas + inventory + prepayment). The assumptions used in calculating the components of working capital were:

• Debtors 14 days’ sales. AGLGN required retailers to pay distribution charges within 14 days, which is equivalent to 3.8% of sales.

• Unbilled gas. 45 days sales for tariff customers. AGLGN’s billing cycle for tariff

customers is on a quarterly basis (90 days). On average, accrued unbilled gas is around 45 days, or 12.3% of tariff sales.

• Inventories. AGLGN’s inventories are generally associated with meters and

spares. The level of inventories for a network business is relatively low. In the final decision, inventories were assumed to remain at the 1998/99 level.

• Prepayment. This prepayment is related to the advancement payment of

AGLGN’s authorisation fee. It was assumed to remain at the 1998/99 level.

• Creditors 30 days. AGLGN’s had advised that its normal credit term was 30 days. On this basis AGLGN’s working capital through the Access Arrangement period was forecast as:

Table 6-1 Net Working Capital 2000 to 2004

Financial Year Nominal $ Million 2000 Forecast 24.5 2001 Forecast 25.4 2002 Forecast 26.3 2003 Forecast 27.4 2004 Forecast 27.8

In its Access Arrangement Information AGLGN has forecast significantly higher net working capital levels as shown in Table 6-2.

Table 6-2 Net Working Capital 2005 to 2010

Financial Year Nominal $ Million* 2005 Forecast 46.8 2006 Forecast 48.7 2007 Forecast 51.7 2008 Forecast 54.6 2009 Forecast 57.8 2010 Forecast 61.8

*Slightly higher than in AGLGN Access Arrangement Information because of rounding errors.


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The components of this are shown in Table 6-3

Table 6-3 Net Working Capital Components 2005 to 2010 Forecast (Nominal $ million)

2004/05 2005/06 2006/07 2007/08 2008/09 2009/10

Debtors Tariff 16.8 17.7 18.6 19.6 20.6 21.7 Debtors Contract 2.6 2.7 2.7 2.8 2.9 3.0 Accrued Revenue 35.9 37.9 39.9 42.0 44.2 46.5 Inventories 3.0 3.0 3.0 3.0 3.0 4.0 Creditors 11.5 12.5 12.5 12.8 12.9 13.3

Total 46.8 48.7 51.7 54.6 57.8 61.8

The main reasons for the increase in net working capital is that AGLGN has taken debtors at 21 days instead of 14 days and creditors for capital works at 7 days instead of 30 days. Unbilled Gas (now termed Accrued Revenue) is assumed to remain at an average 45 days for tariff customers. Following discussions with ECG, AGLGN has revised its calculations of regulatory working capital to allow 29 days for debtors, both tariff and contract, 41 days for accrued revenue, 45 days for operating cost creditors and 10.5 days for capital works creditors. AGLGN has provided the following rationale for these assumptions. • Accrued Revenue (unbilled gas) Tariff Customers meters are read on either a 91 day, or 30 day billing cycle. Accrued revenue represents revenue from the date gas is consumed to the date that the meter is read. If meters are read to schedule, at any point in time throughout the year there will be accrued revenue equivalent to 45.5 days of quarterly customers and 15 days of monthly customers. Monthly read customers represent 15 % of tariff revenue and quarterly read customers represent 85 % of tariff revenue. Therefore on average throughout the year accrued revenue should represent 41 days of tariff revenue. • Tariff Debtors Retailers are invoiced for tariff distribution services at the end of each month, and payment terms are 14 days. However, as meters are read throughout the month (and accrued revenue is only recognised up until the meter is read) there will be on average 15 days revenue in debtors between the date when the meter is read and the end of the month. There will therefore be on average 29 days of tariff distribution charges outstanding as debtors at any point in time throughout the year. • Contract Debtors Retailers are invoiced for contract distribution services at the end of each month, and payment terms are 14 days. Contract meters are read on the last day of each month. However no accrued revenue is recognised for contract customers and there will be on average 15 days revenue in debtors between the date when the gas is used and the end of the month. There will therefore be on average 29 days of contract distribution charges outstanding as debtors at any point in time throughout the year. • Creditors – Operating Costs AGLGN pays the majority of its creditors on 30 day trading terms. For various reasons some (eg government charges) are paid more promptly but the standard payment terms are 30 days. Like most businesses 30 day trading terms are taken to be 30 days from the


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end of the month when an invoice is received. As services are provided to AGLGN consistently throughout the month it is therefore reasonable to assume that creditors will be on average 45 days of operating costs. • Creditors – Capital Cost AGLGN pays for its capital works on seven day trading terms. This means that contractors are paid seven days after the end of the week when capital works are carried out. Therefore, on average contractors will be paid 10.5 days after work is carried out and it is therefore reasonable to assume that creditors will be on average 10.5 days of capital costs • Inventories AGLGN holds small quantities of inventories in store which average approximately $3m per year in 2004$. These stores comprise pipe and fittings for emergency purposes and as a supplementary source of supply for contractors. ECG has reviewed AGLGN’s assumptions and agrees that for tariff customers they reflect operational cash flows in a normal utility business, where meters are read progressively and customers are billed at the end of the month in arrears. Similarly for contract customers and operating cost creditors, AGLGN’s assumptions are valid. For capital works creditors, AGLGN has reduced payment terms allowed on capital expenditure from 30 days in the last Access Arrangement to 10.5 days. The reason for this is that AGLGN states that it pays contractors for capital works on 7 day terms at the end of the week in which the works are carried out. ECG accepts that AGLGN pays many of its contractors weekly and a 10.5 day credit term will be appropriate for such payments. However, purchases of capital machinery and equipment, which form a substantial part of total capital costs, will have longer payment terms. A service provider acting efficiently in accordance with accepted good industry standards will have terms for significant capital equipment purchases that are normally at least 30 days in the ordinary course of business. Large gas distribution companies, and indeed any large company, would not expect to provide terms of less than 30 days for large capital purchases and shorter terms would normally be by exception. Assuming such purchases of equipment are consistent throughout a month would mean an average payment time of 45 days. ECG has assumed an even split of capital expenditure between contractors and equipment, which results in an average 27.7 days of working capital on capital expenditure Table 6-4, shows the net working capital recommended as prudent by ECG. .

Table 6-4 Net Working Capital Components 2005-2010 Forecast (Nominal $ million)

2004/05 2005/06 2006/07 2007/08 2008/09 2009/10

22.7 24.2 25.5 26.8 28.2 29.73.8 3.7 3.8 3.9 4.0 4.1

32.2 34.2 36.0 37.9 39.9 42.03.2 3.3 3.3 3.4 3.5 3.6

20.7 23.8 22.7 23.1 22.7 22.9

41.1 41.6 45.9 49.0 53.0 56.5Total

Accrued Revenue Inventories Creditors

Debtors Tariff Debtors Contract

These calculations use AGLGN’s revenues and CPI assumptions. Use of the lower 2.3% pa CPI will reduce forecast figures by a small extent.


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7. CAPITAL EXPENDITURE REVIEW 2000-2004

7.1 AGLGN PROPOSED REGULATORY CAPITAL BASE

Section 8.9 of the Code generally provides for the regulatory capital base to reflect the initial capital base at the start of the access arrangement period, adjusted for capital expenditure (which passes the test in Section 8.16 of the Code), depreciation, redundant capital, asset revaluation, asset disposals and capital contributions. Section 8.16 of the Code enables capital expenditure in the Access Arrangement period to enter the regulatory capital base provided that:

• The amount does not exceed the amount that would be invested by a prudent service provider acting efficiently, in accordance with accepted good industry practice, and to achieve the lowest sustainable cost of delivering services.

• One of the following conditions is satisfied:

• The anticipated incremental revenue generated exceeds the cost.

• The regulator is satisfied that the capital expenditure has system-wide benefits that justify the approval of a higher reference tariff for all users.

• The capital expenditure is necessary to maintain the safety, integrity or contracted capacity of services.

The Code does not specifically outline the approach that has to be adopted to determine the efficient cost for a level of service. As such, ECG has assessed the capital costs in the following manner, by:

• Reviewing the capital expenditure in the Access Arrangement Information and taking into consideration the Tribunal’s decision in the 2000 Access Arrangement.

• Reviewing actual costs to assess trends, anomalies, differences in the various input categories.

• Analysing the input categories to determine the reasonableness of the costs for the service provided.

• Where possible, comparing overall costs in particular categories (e.g. market expansion costs) with other companies.

• Reviewing the AGLGN forecasts of costs and the methods, and the processes and data used to derive them.

• Concluding the efficient cost for the 2000-2004 Access Arrangement period after taking into account the various input factors.

Details of the assessment are provided in following sections of this review. AGLGN has set out its calculation of the Regulatory Capital Base as shown in the table below.


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Table 7-1 Roll Forward Of Regulatory Capital Base from 1999-2004 Combined Total (Nominal $ million)

1999/00 2000/01 2001/02 2002/03 2003/04 Opening Balance 1,609.0 1,648.1 1,691.1 1,785.7 1,830.4 Add Revaluation Of Assets 21.0 39.2 101.0 51.1 56.6 Add Capital Expenditure 78.5 70.5 57.7 60.4 70.3 Less Depreciation (57.3) (58.0) (60.9) (59.9) (63.8) Less Capital Contributions 0.0 (1.4) (0.5) (1.4) (0.9) Less Disposals (3.1) (7.3) (2.7) (5.5) (2.3) Closing Balance 1,648.1 1,691.1 1,785.7 1,830.4 1,890.3

In determining its regulatory asset base, AGLGN has advised 12that:

• The initial Capital Base was redetermined in the Final Decision 2000 as provided for under Section 9 of the NSW Code and Schedule 2 of the Gas Pipelines Access Law.

• The initial Capital Base (1 July 1996) was allocated to the Wilton- Newcastle

Trunk Section, Wilton-Wollongong Trunk Section, the Central West distribution system and the NSW distribution system in accordance with the Final Decision 2000. This applied the DORC valuation determined by the Relevant Regulator under the Final Decision 2000 to the Wilton-Newcastle Trunk Section and to the Wilton-Wollongong Trunk Section. The remainder of the initial Capital Base (after subtracting the values assigned to the Trunk Sections) was allocated to the combined Central West and NSW distribution systems.

• The initial Capital Base as allocated was rolled forward to 1 July 1999 as shown in

the Final Decision 2000 and then to June 2003 using actual capital expenditure, depreciation, escalation and disposals. Finally the Capital Base is rolled forward to June 2004 and subsequently June 2010 using forecast capital expenditure, depreciation, escalation and disposals.

• Separate asset values and costs are determined for the Trunk Sections to allocate

costs and revenues to contract and tariff customers using fully distributed costs.

• AGLGN has also advised13 that in determining the regulatory capital base, it has used:

Actual (2000 to 2003) and forecast (2004) capital contributions.

Economic asset lives and remaining asset lives as advised in the

following Section 7.2. Consumer price index (GST inclusive) as set out in the table below:

12AGLGN Access Arrangement Submission, December 2003 13 AGLGN Access Arrangement Information, December 2003


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Table 7-2 Annual CPI14

Financial Year CPI % (GST Inclusive) CPI % (GST Exclusive) 1999 Actual 1.31 1.31 2000 Actual 2.38 2.38 2001 Actual 5.97 2.89 2002 Actual 2.86 2.86 2003 Actual 3.09 3.09 2004 Forecast 2.75 2.75 Note: The CPI has been calculated in accordance with the requirements of the current Access Arrangement. AGLGN’s capital base consists of three groups of assets which are:

• The Wilton to Newcastle Transmission Pipeline.

• The Wilton to Wollongong Transmission Pipeline.

• The AGLGN Distribution System.

AGLGN’s proposed Regulatory Capital Base for each of these groups is given in the following three tables

Table 7-3 Roll Forward Of Capital Base – Wilton to Newcastle Transmission Pipeline 2000 to 2004 (Nominal $ million)

1999/2000 2000/01 2001/02 2002/03 2003/04 Opening Balance 111.7 111.3 112.0 116.6 117.8 Add Revaluation Of Assets 1.5 2.6 6.6 3.3 3.7 Add Capital Expenditure 0.0 0.0 0.0 0.0 0.7 Less Depreciation (1.9) (1.9) (2.0) (2.1) (2.2) Less Capital Contributions 0.0 0.0 0.0 0.0 0.0 Less Disposals 0.0 0.0 0.0 0.0 0.0 Closing Balance 111.3 112.0 116.6 117.8 120.0

Table 7-4 Roll Forward Of Capital Base – Wilton to Wollongong Transmission Pipeline 2000 to 2004 (Nominal $ million)

1999/2000 2000/01 2001/02 2002/03 2003/04 Opening Balance 9.6 9.6 9.6 10.0 10.1 Add Revaluation Of Assets 0.1 0.2 0.6 0.3 0.3 Add Capital Expenditure 0.0 0.0 0.0 0.0 0.9 Less Depreciation (0.1) (0.2) (0.2) (0.2) (0.2) Less Capital Contributions 0.0 0.0 0.0 0.0 0.0 Less Disposals 0.0 0.0 0.0 0.0 0.0 Closing Balance 9.6 9.6 10.0 10.1 11.1

14 AGLGN Access Arrangement Information, December 2003


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Table 7-5 Roll Forward Of Capital Base – AGLGN Distribution System

1999 to 2004 (Nominal $ million)

1999/2000 2000/01 2001/02 2002/03 2003/04 Opening Balance 1,487.7 1,527.3 1,569.5 1,659.1 1,702.5 Add Revaluation Of Assets 19.5 36.4 93.7 47.5 52.5 Add Capital Expenditure 78.5 70.5 57.7 60.4 68.7 Less Depreciation (55.3) (55.9) (58.7) (57.6) (61.4) Less Capital Contributions 0.0 (1.4) (0.5) (1.4) (0.9) Less Disposals (3.1) (7.4) (2.6) (5.5) (2.2) Closing Balance 1,527.3 1,569.5 1,659.1 1,702.5 1,759.2

7.2 DEPRECIATION

In accordance with the 2000 Final Decision, AGLGN has established a Regulatory Asset Register to list the assets included in its Capital Base used to calculate allowable revenue. This Asset Register is maintained as part of AGLGN’s SAP management system along with its accounting and taxation asset registers. AGLGN advised that the regulatory depreciation for the years up to 2003 is calculated from the asset register on a straight line basis using the same asset lives as in the 2000 Final Decision. In addition, the depreciation is also calculated on a current cost basis by revaluing the capital base in the Asset Register each year by the CPI as shown in Table 7-7. The asset lives used are shown in Table 7-6.

Table 7-6 Economic Asset Lives

Forecast depreciation for the years 2004 onwards are derived from a spreadsheet using the forecast capital expenditure with the capital base re valued for inflation each year. Forecast depreciation is shown in Table 7-7.

Asset Class Economic Asset Life (Years) System Assets Trunk Main 80 Primary Main 80 Secondary Network 80 Medium Pressure Network 50 Secondary Services 50 Medium/Low Pressure Services 50 Alb Valves 50 Trunk Receiving Stations/Packaged Off Take Stations 50 Primary Reduction Stations 50 Primary Valves 50 Secondary Reduction Stations 50 Meters - Contract 20 Meters - I&C Tariff 20 Meters - Domestic 20 Non System Assets To be consistent with the categories and lives adopted for financial reporting.


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Table 7-7 Forecast Depreciation * (Nominal $ million)

Wilton/Newcastle Wilton/Wollongong Distribution Network

Total

1999/2000 actual

1.9 0.1 55.3 57.3

2000/01 actual

1.9 0.2 55.9 58.0

2001/02 actual

2.0 0.2 58.7 60.9

2002/03 actual

2.1 0.2 57.6 59.9

2003/04 2.2 0.2 59.7 62.1

2004/05 2.2 0.2 61.0 63.4

2005/06 2.2 0.2 65.3 67.7

2006/07 2.2 0.2 70.6 73.0

2007/08 2.2 0.2 75.4 77.8

2008/09 2.2 0.2 80.0 82.4

2009/10 2.2 0.2 84.6 87.0

Note: AGLGN advised that the depreciation totals from 2004 onwards are slightly less than those shown in the

Access Arrangement Information because of duplication in escalation at 1 July 2003 in the spreadsheet calculations in the Information.

The figures in Table 7-7 are calculated using AGLGN’s assumed inflation rate of 2.75% per annum. Using a lower rate will reduce the depreciation values.

7.3 COMPARISON OF ACTUAL AND FORECAST EXPENDITURE

AGLGN actual/forecast capital expenditure in the 2000-04 Access Arrangement period is $55.9 million (nominal) less than that allowed in the Access Arrangement Final Decision of July 2000. The Tribunal final decision (2000) amounts, the actual amounts and the variances are shown in the following table:

Table 7-8 Capital Expenditure 2000 to 200415 (Nominal $ million)

1999/00 2000/01 2001/02 2002/03 2003/04 Total

Final Decision 2000 Market Expansion 52.4 38.5 38.9 39.2 38.1 207.1 System Reinforcement /Renewal/Replacement

14.5 42.6 28.5 22.0 23.1 130.7


Actual/Forecast Market Expansion 56.0 55.0 46.3 48.1 47.5 252.8 System Reinforcement /Renewal/Replacement

17.2 13.4 5.6 9.5 17.6 63.3

15 Access Arrangement Information December 2003


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1999/00 2000/01 2001/02 2002/03 2003/04 Total


Variance Market Expansion 3.6 16.5 7.3 9.0 9.4 45.7 System Reinforcement /Renewal/Replacement

2.7 (29.2) (22.9) (12.5) (5.50 (67.4)

Non System Assets (4.8) (4.0) (6.9) (10.4) (8.2) (34.3) Total 1.5 (16.7) (22.4) (13.9) (4.3) (55.9)

In accordance with Section 8.16 of the Code, the prudency of the expenditure in this Access Arrangement period is assessed in the following sections of the report for each of the AGLGN expenditure categories. The differences between the actual/forecast expenditure and that allowed by the final decision are also reviewed. Major contributors to these differences have been:

• Deferral of the Sydney Primary Main project. • Reduced levels of meter replacement. • Deferral of the Medium and Low Pressure rehabilitation program. • Reductions in non-system asset expenditure.

This has been partly offset by an increase in market expansion expenditure. A breakdown of the actual/forecast expenditure by expenditure category, as given in the following table, is also used in analysing the actual/forecast expenditure.

Table 7-9 AGLGN Actual Capital Expenditure 2000 to 200416 (Nominal $ million)

1999/00 2000/01 2001/02 2002/03 2003/04

Capex By Major Pipelines / Asset Category Trunk Wilton-Newcastle 0.0 0.0 0.0 0.0 0.7Trunk Wilton-Wollongong 0.0 0.0 0.0 0.0 0.0Country TRS 0.0 0.0 0.0 0.0 0.9Metering 14.7 14.4 13.4 19.9 21.2Local Network 63.8 56.1 44.3 40.5 47.5

Total 78.5 70.5 57.7 60.4 70.3Capex Split By Program Land/Building/Leasehold 2.1 0.1 0.1 0.0 0.0Plant & Equipment 0.9 0.9 0.2 0.1 1.0Office Furniture 0.1 0.1 0.0 0.0 0.0Motor Vehicles 2.0 1.0 1.2 1.6 1.7IT 0.2 0.0 4.3 0.0 0.8Access Arrangement 0.0 0.0 0.0 1.0 1.7Total Non-System Assets 5.3 2.2 5.8 2.7 5.2Mains 21.8 20.8 9.7 7.3 9.5

16 Access Arrangement Information December 2003


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1999/00 2000/01 2001/02 2002/03 2003/04 Services 23.4 23.5 23.8 23.1 23.2Meters 10.8 10.7 12.7 17.7 14.8Total Market Expansion 56.0 55.0 46.3 48.1 47.5Mains 3.2 0.9 2.5 6.7 10.7Services 0.6 0.4 0.0 0.0 0.5Programmed Rehabilitation 9.5 8.4 2.4 0.7 0.0Meters 3.9 3.7 0.7 2.2 6.4Total System Upgrade 17.2 13.4 5.6 9.5 17.6

Total 78.5 70.5 57.7 60.4 70.3

7.4 MARKET EXPANSION

AGLGN advised that the number of customers (residential and industrial/commercial) connected during the Access Arrangement period was 187,918, which is approximately 13% more than the forecast in the Tribunal Final Decision (2000). This has contributed to the actual/forecast expenditure of $252.8 million (nominal $) exceeding the final decision estimate of $207.1 million (nominal $) as shown in Table 7-8. The actual/forecast expenditure by asset type is shown in the following table. The actual/forecast numbers of new customers each year are also given.

Table 7-10 AGLGN Market Expansion Capital Expenditure 2000 to 200417 (Nominal $ million)

1999/00 Actual

2000/01 Actual

2001/02 Actual

2002/03 Actual

2003/04 Forecast

Mains 10.2 12.6 9.7 7.3 9.5 Major Mains 11.6 8.2 Services 23.4 23.5 23.8 23.1 23.2 Meters 10.8 10.7 12.7 17.7 14.8 Total Market Expansion 56.0 55.0 46.3 48.1 47.4 New Customers 41354 39990 36056 36863 33655

For effective analysis of the above data and comparison with other information it has been necessary to convert the nominal $ expenditures to real $ 2005, and the equivalent values are shown in the following table. All $ amounts presented in the following sections on mains, services and meters are in Real $ 2005.

17 Access Arrangement Information Table 5.5


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Table 7-11 Market Expansion Capital Expenditure 2000 to 2004

(Real $ million 2005)

1999/2000 Actual

2000/01 Actual

2001/02 Actual

2002/03 Actual

2003/04 Forecast

Mains 11.7 14.0 10.5 7.6 9.7 Major Mains 13.2 9.1 Services 26.7 26.0 25.7 24.2 23.8 Meters 12.3 11.9 13.7 18.5 15.1 Total Market Expansion 63.9 61.0 49.9 50.3 48.6 New Customers 41354 39990 36056 36863 33655 Mains ($ per customer) 283 350 291 206 288 Services ($ per customer) 646 651 713 656 707 Meters ($ per customer) 297 297 380 502 449 Total ($ per customer) 1226 1298 1384 1364 1444

Mains projects for years 2000 and 2001 include $22.3 million for major mains supplying areas including Blue Mountains, Central West and Singleton. These large mains only supply discrete areas and as such create a distortion in terms of reviewing the costs associated with a typical supply for market expansion. Residential customers are not generally directly connected to such mains. Excluding the expenditure for these mains shows the actual/forecast expenditures (real $ 2005) averaged over all customers are:

• Mains $285 per customer. • Services $673 per customer. • Meters $380 per customer.

AGLGN has been unable to provide further details of actual market expansion cost by asset type and customer type (Residential E-G, new homes-built up, new homes-new estate, medium density, industrial / commercial) for years 2000 to 2003, but has provided details of forecast expenditure by customer type for the year 2004 and beyond. In the absence of this detailed actual cost information, ECG has based its analysis on the average costs per customer for the five year period as shown above.

7.4.1 Mains

The average mains cost for the period 2000 to 2004 is $285 per customer as shown in section 7.4 . The average cost per customer for is derived from the average length of new mains required to connect each type of customer and the unit cost for this main. As mentioned in section 7.4, AGLGN was unable to provide cost by asset type and customer type for 2000 to 2003. This cost information was available for 2004 and ECG has used it to determine an efficient unit cost for the period 2000 to 2004. The 2004 unit cost for each customer type provided by AGLGN is shown in the Table 7-12.


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Table 7-12 Mains Rate18 (Real $ 2005)

Customer Type Unit cost $/m E-G 102 New Homes-Built Up 102 New Homes –New Estate 38 Medium/High Density 77 I&C 102

Based on its industry knowledge, ECG considers that the average length of mains used to derive the unit costs shown in the above table are comparable with other States as are the mains unit costs for new estates, medium/high density and I&C. The unit rate for new estates reflects that the construction of the gas mains is carried out in conjunction with other civil works and does not generally require the reinstatement of roads, footpaths and nature strips. However, AGLGN’s unit cost for laying mains in established areas (E-G, New Homes-Built up) is more than two and half times the cost in new estates. While it is recognised that the cost for laying mains in established areas exceeds that of new areas, ECG’s industry knowledge suggests that the established area rate should not be more than twice that for a new area. Consistent with section 8.16 of the Code, ECG therefore recommends a unit cost of $76 per metre for laying mains in established areas. Based on this unit cost, ECG has calculated the average cost per customer to be $264 compared to AGLGN’s $285. ECG therefore recommends that the expenditure accepted for inclusion in the opening capital base for the 2005-10 Access Arrangement period be based on its estimate of $264 per customer. This has the effect of reducing the AGLGN total mains allowance for 2000 to 2004 by $3.9 million, from $75.8 million to $71.9 million, including provision for new major mains.

7.4.2 Services

The average service cost for the period 2000 to 2004 is $673 per customer as shown in section 7.4 Given that the only detailed cost information by customer type is available for 2004, ECG has applied the same rationale as outlined for mains in section 7.4.1 to determine an efficient unit services cost for the period 2000 to 2004. The unit cost for the different customer type is shown in the Table 7-13.

Table 7-13 Service Rate19

Customer Type Unit cost $/customer E-G 1305 New Homes-Built Up 1305 New Homes –New Estate 731 Medium/High Density 1242 I&C 1305

18 AGLGN Market Expansion Capex and Unit Rate spreadsheet 19 AGLGN Market Expansion Capex and Unit Rate spreadsheet


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Note: The service cost for medium/ High Density is for 12.8 customers derived from AGLGN’s spreadsheet.

Based on its industry knowledge and experience, ECG considers that the 2004 unit costs shown in the Table 7-13 are consistent with those that would be incurred by a prudent service provider, acting efficiently in accordance with good industry practice. Using the 2004 data in Table 7-13, ECG has calculated the weighted average service cost per customer to be $684 which is comparable to the average of $673 for the 2000 to 2004 period. In accordance with section 8.16 of the Code, ECG therefore recommends the AGLGN expenditure of $126.4 million for these services is accepted for inclusion in the opening capital base for the 2005-10 Access Arrangement period.

7.4.3 Meters

The average meter cost for the period 2000 to 2004 is $380 per customer as shown in section 7.4 ECG has used the 2004 data to analyse the cost of meters for the same reasons as outlined in sections 7.4.1 and 7.4.2. The unit meter cost provided by AGLGN for the different customer types is shown in Table 7-14.

Table 7-14 Meter Cost20


AGLGN advised that the unit cost of $195 includes large meters for use with spas, central heating and continuous hot water units and is based on the following mix of meter types;

• 96% small meters. • 3.5% large meters. • 0.5% very large meters.

AGLGN has advised that the costs of handling, storage and overheads have also been incorporated into the unit cost. Based on its industry knowledge, ECG considers that the cost of $195 for the mix of meter types is what would be incurred by a prudent service provider. However, ECG believes that the unit cost of $699 is higher than what would be considered efficient. ECG considers that the cost should be within the range of $550 to $600 based on the following breakdown:

20 AGLGN Market Expansion Capex and Unit Rate spreadsheet


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Table 7-15 Unit Cost for Medium/High Density Metering

Unit cost $ Cost of gas metering 300 Hot water metering plus remote device 200 Overheads 50-100 Total 550-600

As there is some uncertainty in relation to the level of overhead, ECG has used $600 for its calculation of efficient expenditure. Using the unit costs of $195 and $600 from above, ECG has calculated the average unit cost for all customer types as shown in Table 7-14 to be $401. Therefore ECG considers the overall AGLGN total expenditure for meters, averaging $380 per customer for years 2000 to 2004, to be consistent with that incurred by a prudent service provider acting efficiently. Consistent with section 8.16 of the Code, ECG therefore recommends the AGLGN expenditure of $71.5million for these meters be accepted for inclusion in the opening capital base for the 2005-10 Access Arrangement period.

7.4.4 Summary

A summary of the recommended market expansion expenditure to be accepted for inclusion in the opening capital base for the next period (2005-2010) is given in the following table.

Table 7-16 AGLGN Recommended Market Expansion Capital Expenditure (Real $ million 2005)

1999/00 2000/01 2001/02 2002/03 2003/04 Mains 24.0 22.1 9.7 7.1 9.0 Services 26.7 26.0 25.7 24.2 23.8 Meters 12.3 11.9 13.7 18.5 15.1 Total Market Expansion 63.0 60.0 49.1 49.8 47.9

Expressed in nominal $, the recommended market reinforcement capital expenditure is as shown in the following table.

Table 7-17 AGLGN Recommended Market Expansion Capital Expenditure (Nominal $ million)

1999/00 2000/01 2001/02 2002/03 2003/04 Total Market Expansion 55.2 54.1 45.5 47.6 46.8

7.5 SYSTEM REINFORCEMENT

System reinforcement projects are generally due to market expansion and organic growth of the customer demands. ECG has reviewed specific reinforcement projects. Details of the review are covered in the following sections.


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7.5.1 Review of Proposed Expenditure

The Final Decision (2000) allowed expenditure was $49.0 million (nominal $), including an allowance of $32.5 million for the primary loop pipeline which is a major security of supply project. The project was subsequently deferred (A full assessment of this project is given in Section 8.5.3.1 ). This provided an expenditure allowance of $16.5 million for typical minor reinforcement projects. AGLGN actual/forecast expenditure was $16.7 million21 including $5.5 million forecast for year 2003/04. However the forecast expenditure in year 2004 was subsequently reduced to $3.5 million22 due to deferral of Roberts Road and Glenmore Park secondary mains from 2004 until 2005. This reduced the actual/forecast expenditure for the 2000 to 2004 period to $14.7 million, about 90% of that allowed in the year 2000 Final Decision as shown in the following table.

Table 7-18 Actual System Reinforcement Capital Expenditure 2000 to 2004 (Nominal $ million)

1999/00 2000/01 2001/02 2002/03 2003/04 Penrith 1.0 4.2 City 0.5 Unanderra 0.9 Gosford Erina 1.0 1.2 Other Projects 1.0 0.5 1.5 1.5 1.4 Total Capacity Development 1.5 0.5 2.5 6.7 3.5

7.5.2 Review of Material Projects

Four material projects were completed during this Access Arrangement period, and an assessment of three of these follows: 1. Plumpton - Blue Mountains (Penrith)

This project, consisting of a primary main extension to reinforce supply via the secondary system to the Blue Mountains, was completed in 2003 at an actual cost of $4.9 million (nominal 2002/03). It proceeded after five other options were considered and evaluated. The current Access Arrangement allowed expenditure of $3.9 million (nominal 1998/99) for this project. The increase to $4.9 million was due to cost escalation and to a justified change in scope during the project planning phase that required inclusion of an additional regulating station. This project is considered to have been completed prudently and efficiently. 2. City (Rocks) The current Access Arrangement allowed expenditure of $0.6 million for this project. The project was completed for $0.5 million and is considered to have been completed prudently and efficiently. 3. Unanderra This consists of 1.4km of 150mm secondary mains before winter 2004 at an estimated cost of $0.9 million. AGLGN have advised this project has been completed and it was selected after a risk assessment examined 5 alternatives. It is considered to be a prudent and efficient project.

21 AGLGN Capital Expenditure Analysis Spreadsheet 22 AGLGN email, 11 June 2004, in response to question 3.4


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7.5.3 System Reinforcement Expenditure Summary

Two major projects forecast included in the expenditure allowed by the Final Decision (2000) were deferred. These were the primary extension to North Turramurra estimated at about $7 million and the North Ryde-Willoughby project estimated at about $4 million. Due to forecasting uncertainty over the five year Access Arrangement period, it is normal for changes to the timing and scope of system reinforcement projects to occur. In addition, during the forecast period, projects not initially identified can also be carried out. These changes indicate that the process for annual performance monitoring is being effectively implemented to review the scope and timing of reinforcement projects. A review of network validation reports for some areas in which reinforcements took place confirms the timing of these projects has been prudently identified. Also network modelling shows the scope of planned projects is effective in overcoming capacity limitation due to low network pressures. In some cases, a risk assessment of alternatives was conducted to determine the best option. It is considered that this approach should be extended to all projects, to clearly show that all realistic options have been assessed and the best option chosen. It is concluded that actual projects for this Access Arrangement period have been prudently planned, but it is also recommended that a clear presentation of all options considered is provided in future for all reinforcement projects. The actual capital was $2.0 million (real $ 2005) less than that allowed by the Final Decision (2000) and the actual reinforcement expenditure was $91 per new customer compared with the forecast $117. AGLGN’s actions in only performing work necessary to maintain the capacity and security of the network are what would be expected of a prudent network operator acting efficiently, consistent with accepted good industry practice. This is in accordance with the requirements of Section 8.16 of the Code. ECG therefore recommends that the actual costs of $14.7 million (nominal) shown in the above Table 7-18 be used for the purposes of establishing the opening capital base for the 2005 Access Arrangement period.

7.6 RENEWAL/REPLACEMENT

Renewal/replacement capital expenditure shown in Table 7-19 is derived from the Final Decision 2000 and AGLGN’s Access Arrangement Information (December 2003). Renewal/replacement activities include the Medium and Low Pressure (M&LP) mains rehabilitation program, ad hoc mains and services renewal and meter/regulator/filter replacement.

Table 7-19 Renewal/ Replacement Capital Expenditure 2000 to 2004 (Nominal $ million)

1999/00 2000/01 2001/02 2002/03 2003/04 Total

Final Decision 2000 Renewal/Replacement 13 25.8 9.75 15.3 17.6 81.45Actual/Forecast Renewal/Replacement 15.7 12.9 3.1 2.8 12.1 46.8


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AGLGN advised23 that actual expenditure below that forecast in the Final Decision 2000 is primarily due to:

• Deferral of the M&LP mains rehabilitation program.

• Reduced levels of meter replacement following a meter life extension by the Department of Fair Trading (DFT). The Gas Supply (Gas Meters) Regulation 2002 provides for meter life extension for identified families of meters subject to the ongoing testing of meter accuracy in accordance with an approved sampling plan.

7.6.1 Review of Actual Expenditure - M&LP Mains Rehabilitation Program and Ad Hoc Mains and Services

AGLGN underspent on the M&LP mains rehabilitation program. The table below shows the difference between the Final Decision and the actual expenditure: Table 7-20 Final Decision versus Actual Expenditure for M&LP Rehabilitation Program

(Nominal $ million)

1999/00 2000/01 2001/02 2002/03 2003/04 Final Decision 9.4 9.2 8.9 8.7 8.5 Actual Expenditure Rehabilitation 9.5 8.4 2.4 0.7 0 Mains expenditure 1.7 0.4 0 0 5.2 Total 11.2 8.8 2.4 0.7 5.2

During the first three years of period the rehabilitation program renewed 275 kilometres of main supplying 12,790 consumers across the areas of Newcastle, Blacktown, Cessnock and Warringah24. Total expenditure was $21 million (nominal). The M&LP mains rehabilitation program was subsequently deferred, “largely due to reallocation of available capital to growth sections of the capital expenditure program to cope with higher than expected growth related to the housing boom in Sydney”25. The deferral of this work was offered by AGLGN as one of the contributing reasons for the underspending during the period. The quantity of the deferral equated to approximately 240 kilometres of mains supplying 11,400 consumers with an approximate value of $16.4 million26 (nominal). The average cost per metre of main achieved during the period, including customer service and regulator, was $76.40 (nominal). This compares favourably with the ESC Final Determination in Victoria where the range of costs were $86 to $116 per metre allowing for the particular circumstances in NSW (e.g. 95% of the network has been rehabilitated). Actual expenditure includes $7.3 million (nominal) for ad hoc mains and services. In discussion with AGLGN/Agility and in emails27 the expenditure that could be identified totalled $5.9 million (nominal) with various works listed as upgrade of facilities associated with mains (eg regulator sets, valves, cathodic protection). ECG concluded that the expenditure associated with the activity is prudent.

23 AGLGN’s Access Arrangement Information (December 2003) 24 Email 1 June 2004 in response to AY004040531. 25 Email 1 June AY004040531. 26 Email 2 June Quantities calculated from Capital Forecast. 27 Email AY018 and email AY022


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AGLGN’s actions in only performing work necessary to maintain the safety and integrity of the network are what would be expected of a prudent network operator acting efficiently and is consistent with accepted good industry practice. This is in accordance with the requirements of Section 8.16 of the Code and ECG therefore recommends that the actual costs of $28.3 million (nominal) be used for the purposes of establishing the opening capital base for the 2005 Access Arrangement period.

7.6.2 Review of Actual Expenditure – Meter Replacement

AGLGN underspent on meter replacement as shown in the following table:

Table 7-21 Final Decision Capital Expenditure and Actual Expenditure28 (Nominal $ million)

1999/00 2000/01 2001/02 2002/03 2003/04 Final Decision Meters/regulators/filters

0.5 16.1 1.1 8.5 5.8

Actual Expenditure29 3.9 3.7 0.7 2.2 6.4 AGLGN advised that the field life extension program for residential meters has contributed to the $15million underspending in meter replacement but it is unclear in which year the program was introduced and to what extent it contributed to the underspending. AGLGN was unable to provide the annual quantities of residential, commercial and industrial meters replaced and the cost per meter type for ECG to confirm the prudency of the expenditure. ECG accepts that the bulk of the underspending is due to the introduction of the field life extension program for residential meters and it is immaterial when this occurred. AGLGN’s decision to implement the DFT approved field life extension program is consistent with a prudent network operator acting efficiently which is in accordance with the requirements of Section 8.16 of the Code. ECG therefore recommends including the actual costs into the opening capital base for the 2005 Access Arrangement period

7.7 NON SYSTEM ASSETS

AGLGN actual expenditure for the non-system assets was substantially less than that allowed under the Final Decision 2000 as shown in the following table.

Table 7-2230 Comparison of Actual versus Final Decision for Non System Assets (Nominal $ million)

Final Decision 2000

1999/00 2000/01 2001/02 2002/03 2003/04 Total

Non System Assets

10.1 6.2 12.7 13.1 13.5 55.5

Actual/Forecast Non System Assets

5.3 2.2 5.8 2.7 5.2 21.3

Actual costs were broken down into the following categories by AGLGN as shown in Table 7-23:

28 Access Arrangement Information 29 Access Arrangement Information. 30 Table 5.4 Capital Expenditure 1999/00 to 2003/04 AAI (December 2003).


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Table 7-2331 Non System Assets Capex

(Nominal $ million) Capex Split By Program 1999/2000 2000/01 2001/02 2002/03 2003/04 Land/Building/Leasehold 2.1 0.1 0.1 0.0 0.0 Plant & Equipment 0.9 0.9 0.2 0.1 1.0 Office Furniture 0.1 0.1 0.0 0.0 0.0 Motor Vehicles 2.0 1.0 1.2 1.6 1.7 IT 0.2 0.0 4.3 0.0 0.8 Access Arrangement 0.0 0.0 0.0 1.0 1.7 Total Non-System Assets 5.3 2.2 5.8 2.7 5.2

In the Access Arrangement Information, the main reasons provided by AGLGN for the $34.2 million underspending shown in Table 7-22 are:

• Deferral of IT system replacement and upgrade projects. • The decision to lease much of the vehicle fleet. 32

Results of the review carried out by ECG are detailed below.

7.7.1 Land/Building/Leasehold

The bulk of the expenditure ($2.1 million) occurred in 1999/2000 and is associated with leaseholds at Alexandria, Frenchs Forest, Regents Park Training Centre and North Parramatta Control Centre33. These were one-off set up costs for the buildings at these locations. From the information provided by AGLGN, ECG considers that the set-up costs are what would be incurred by a prudent service provider acting efficiently in accordance with section 8.16 of the Code. ECG therefore recommends that the actual cost of $2.3 million (nominal) be include into the opening capital base for the 2005 Access Arrangement period.

7.7.2 Plant & Equipment

A list of Plant & Equipment for a single year, 2004 was supplied by AGLGN34 . The list includes such items as gas detectors, standby batteries, data loggers, pressure gauges and mobile radios. ECG believes that it is usual for a gas distribution business to have such equipment and the list is typical of the other years. ECG considers that the AGLGN’s expenditure for plant and equipment is what would be incurred by a service provider acting efficiently in accordance with good industry practice. Consistent with the section 8.16 of the Code, ECG recommends including the actual costs into the opening capital base for the 2005 Access Arrangement period.

31 Table 7.5 Actual Capital Expenditure AAI. 32 Capital Expenditure 1999/00 to 2003/04 AAI. 33 Email response to questions AY013 040608 & AY021 040614. 34 Attachment to email response to questionAY011 040606.


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7.7.3 Motor Vehicles

Table 7-23 showed the expenditure profile for motor vehicles. AGLGN/Agility35 advised that the purchase of Motor Vehicles is usually very cyclical in nature with their replacement generally based on a 4 year or 100,000 km policy. However this policy is varied for larger vehicles such as trucks and vans which often have a longer useful life depending on their use. These vehicles are not always replaced as per the forecast. AGLGN provided a list36 of vehicles that ranged from executive and work place cars to commercial vans and trucks. The total number of vehicles is in the order of 350. Assumptions made by AGLGN for vehicles include cost of sedan at $27,000 and costs of a truck at $60,000. ECG believes these assumptions are reasonable. AGLGN’s policy of vehicle replacement outlined above is consistent with the action of a prudent service provider acting efficiently. In accordance with section 8.36 of the Code, ECG recommends the actual expenditure for vehicle of $7.5 million (nominal) be used for the purpose of establishing the opening capital base for the 2005 Access Arrangement period.

7.7.4 Information Technology (IT)

The Access Arrangement Information includes IT costs of $5.3 million for the current period as shown in Table 7-24.

Table 7-24 Information Technology Expenditure (Nominal $ million)

1999/00 2000/01 2001/02 2002/03 2003/04 Total Information Technology

0.2 0.0 4.3 0.0 0.8 5.3

AGLGN advised that $3.9 million of the $4.3 million in 2002 is associated with FRC. This is the net amount that has been capitalised and depreciated over the current Access Arrangement period. The reconciliation of this amount is shown in Appendix 5. As the capital expenditure for FRC has been part of the review carried out by Deloittes, ECG recommends accepting this expenditure. The remaining cost of $1.4m for the current period is for development work on various IT projects. This includes the initial $0.8 million in 2004 for the initial work in developing the scope for the replacement of its SCADA system. ECG’s review on the SCADA project carried out in 8.6.1 recommends the project as prudent. As such, ECG is also recommending the acceptance of the development cost of $0.8 million. The remaining $0.6million for the development of various IT projects and ECG also recommends accepting these costs as prudent. ECG therefore recommends acceptance of the $5.3 million of IT expenditure as prudent. AGLGN also advised that it inadvertently omitted the allocated costs from its corporate IT. As a separate exercise, ECG reviewed the $24.9 million corporate IT costs. The actual costs submitted covered expenditure on more than 50 projects ranging in value from $6,000 to $4.1 million37. The expenditure profile for the corporate IT costs is shown in the table below:

35 Email AY 013 received on 8th June. 36 Spreadsheet provided by Agility Motor Vehicles and P&E forecast for ECG 06 37 Gas Network IT Capital Expenditure 2000-04.xls


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Table 7-25 Corporate IT Expenditure 2000 to 200438

(Nominal $ million)


AGLGN advised39 that the expenditure excludes investments related to operations outside NSW. Corporate projects have been allocated to AGLGN on the percentage of funds employed into AGLGN. The percentage used for AGLGN by Corporate IT is 28% of the project cost. Where a project is solely for the network business, AGLGN is allocated 100% of the cost. “Funds employed” is one of a number of methods employed by organisations to allocate corporate costs to various business units. Other methodologies include using operating costs or staff numbers per business unit. ECG is of the view that it is appropriate for AGLGN to allocate capital expenditure on IT using funds employed. However, AGLGN did not offer any further information in support of its cost allocation. ECG believes that without carrying out a cost allocation review, it is difficult to be definitive about the appropriateness of the percentage allocation. Equally based on its experience, ECG would consider an allocation of 28% of Corporate IT costs would be within the range expected from an infrastructure business such as AGLGN. For the purpose of this review, ECG has accepted the cost allocation and reviewed the prudence of a number of the material projects and in particular those that have been fully costed to AGLGN. The projects reviewed include:

1. Contract Administration & Billing System (CABS), The CABS system incorporated operational balancing and integration with the tariff allocation in addition to providing invoicing and contract management functions. This development was for AGLGN and hence the full cost of $1.08 million was allocated.

2. GASS – general enhancements. Expenditure of $3.1 million over the 5 year

period, with 100% allocation to Gas Networks. The enhancements consist of a range of necessary changes to ensure ongoing efficient operations. These changes were due to

• Modification to technology and internal business processes, • System changes to improve efficiency. • Corrective actions resulting from incident or risk reviews.40

3. IT Infrastructure (hardware – NSW) at a cost to AGLGN of $4.1 million. The

expenditure was for generic hardware and software supporting the ongoing functions of AGLGN. It included Local Area Networks, Wide Area Networks, email, internet and intranet servers and software, desktop PCs and operating environments, and mainframe and data storage. The work was generally of a replacement nature, or upgrading to meet business continuity and disaster recovery requirements.

4. Software License expenditure ($2.3 million) is an allocation of the total AGL

expenditure on software licences and includes the upgrade costs for core supporting software such as databases, peripherals and standard desktop applications such as word, excel, antivirus, etc. The expenditure excludes non-generic licences relating to other business activities such as Retail billing software.

38 Gas Network IT Capital Expenditure 2000-04.xls 39 Gas Networks IT Expenditure Q&A.doc 40 Gas Networks IT Expenditure Q&A.doc


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AGLGN’s expenditure on IT projects, from the information provided, is consistent with the level and type of expenditure that would be expected of a prudent service provider acting efficiently in accordance with good industry practice. Consistent with section 8.16 of the Code, ECG considers the cost of $24.9 million (nominal) to be prudent.

7.7.5 Access Arrangement

AGLGN advised41 that the expenditure of $2.7 million for 2002/03 ($1.0 million actual) and 2003/04 ($1.7 million forecast) relates to the project costs associated with the preparation of the revised Access Arrangement. These costs are treated as deferred expenditure and will be amortised over the period of the new Access Arrangement (from 2005 to 2010). AGLGN was unable to provide details of this expenditure (e.g. legal and consultants costs). As such, ECG is not in a position to confirm whether the cost is prudent and efficient. However, ECG does recognise that a prudent service provider will incur costs associated with the preparation of the Access Arrangement. For the purpose of this report, ECG has therefore included the cost in the recommended non system asset expenditure.

7.8 SUMMARY OF NON SYSTEM ASSETS EXPENDITURE

The recommended costs for non system assets are summarised below.

Table 7-26 Roll up table for Non System Assets Expenditure (Nominal $ million)

1999/00 2000/01 2001/02 2002/03 2003/04 Total

Final Decision 2000

Non System Assets

10.1 6.2 12.7 13.1 13.5 55.5

Recommended Non System Assets

5.3 2.2 5.8 2.7 5.2 21.1

Expenditure in the non network area is underspent by $34.4 million (nominal). In accordance with the section 8.16 of the Code, ECG recommends that the actual costs of $21.1 million (nominal) be used for the purposes of establishing the opening capital base for the 2005 Access Arrangement period.

41 Email response to Question AY021 040614.


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7.9 DISPOSALS

AGLGN advised that disposals cover replacement or scrapping of aging and redundant capital42.

Table 7-27 Disposals for the Period from 1999-2004 (Nominal $ million)

1999/00 2000/01 2001/02 2002/03 2003/04

Disposals (3.1) (7.3) (2.7) (5.5) (2.3)

The disposals in 2001 included the sale of South West Slopes assets (includes Culcairn, Walla Walla and Henry Township) to Country Energy. The Written Down Value (WDV) of the disposal was $4.05 million43. The disposals in 2003 included the sale of surplus property held in Gas Networks books (Steel St in Newcastle). The WDV of the disposal was $2.39 million. After allowing for these aberrations in 2001 and 2003, the average disposal amount for the years 2000 to 2003 and forecast 2004 is $3.0 million44. AGLGN advised45 that when the major asset sales are excluded, the balance of disposals comprise the sale of motor vehicles (approximately $400K each year) and asset scrappings including mains, services, valves, regulator equipment and meters of unspecified quantities. ECG considers based on the above and its industry knowledge that the disposals have been determined in a manner expected from a prudent operator acting efficiently, consistent with good industry practice, and in accordance with the requirements of section 8.16 of the code. ECG therefore recommends the disposals advised by AGLGN be accepted for inclusion in calculation of the Regulatory Capital Base.

7.10 CAPITAL CONTRIBUTION

The regulatory capital base includes a negative adjustment for capital contributions made by customers to the expenditure required in providing gas supply. No allowance was made for these in the Access Arrangement Final Decision (2000). However contributions have been recorded and are summarised in the following table.

Table 7-28 Roll Forward Of Regulatory Capital Base 2000 to 2004 Combined Total (Nominal $ million)

1999/00 2000/01 2001/02 2002/03 2003/04

Capital Contributions 0.0 (1.4) (0.5) (1.4) (0.9)

42 Email in response to Question AY 020 040614. 43 Email in response to Question AY 020 040614. 44 Email in response to Question AY 020 040614. 45 Email in response to Question AY 020 040614.


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AGLGN has advised that contributions have been determined in accordance with an Australian Accounting Policy, Developer and Customer Contributions in Price Regulated Industries, issued in May 199846. AGLGN also advised that these contributions have been recorded in accordance with the AGLGN Access Arrangement submission of December 200347. It confirmed that it will maintain, during the Access Arrangement period, a database that records the following information in relation to Capital Contributions made to AGLGN:

a) The amount of a Capital Contribution made by a User in respect of a New Facility. b) The amount of any charge paid by a User which exceeds the Charge that would

apply under a Reference Tariff for a Reference Service (or in relation to another Service under the Equivalent Tariff) where the excess is paid by the User in relation to the funding of a New Facility.

c) The date that the Capital Contribution is made under paragraph (a) or the charge

is paid under paragraph (b). d) The name of the User and the User’s contact details. e) A description of the New Facility in relation to which the Capital Contribution is

made under paragraph (a) or the charge is paid under paragraph (b). AGLGN has provided a copy of the database named “Customer Contribution”48. ECG has reviewed the database and confirmed that the database contains all the necessary information as listed above. ECG considers the capital contributions have been determined in a manner expected from a prudent operator acting efficiently, consistent with good industry practice, and in accordance with the requirements of section 8.16 of the code. ECG therefore recommends the capital contributions advised by AGLGN be accepted for inclusion in calculation of the Regulatory Capital Base.

7.11 JULY TO DECEMBER 2004

Due to the agreement to extend the current Access Arrangement period to include the period from July to December 2004, the forecast 2005 expenditure has been divided evenly between July to December 2004 and January to June 2005. The forecast expenditure for July-December 2004 is shown below.

Table 7-29 AGLGN Forecast Capital Expenditure, July – December 2004


Forecast Expenditure Market Expansion 24.5 System Reinforcement/ Renewal/Replacement 15.6 Non System Assets 6.4 Total 46.5

46 Australian Accounting Policy, Developer and Customer Contributions in Price Regulated Industries, May 1998. 47 Access Arrangement for NSW Networks December 2003 Section 9. 48 AGLGN Database, Customer Contribution A006 from 1 July 2002 to 30 June 2003.


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Assessment of the prudency and efficiency for the forecast July to December 2004 period expenditure is identical to that for the corresponding forecast January 2005 - June 2010 expenditure, fully reviewed and summarised in Section 8. The table below is the recommended expenditure for July to December 2004.

Table 7-30 Recommended Capital Expenditure, July – December 2004 (Nominal $ million)

Forecast Expenditure Market Expansion 23.2 System Reinforcement/ Renewal/Replacement 15.8 Non System Assets 4.0 Total 43.0

7.12 RECOMMENDED CAPITAL EXPENDITURE 2000-04

It is proposed that the capital expenditure from 2000 to 2004 shown in the following table be allowed for inclusion in the opening capital base for the Access Arrangement period from 2005 to 2010. Note that for purposes of comparison with the AGLGN proposal, system reinforcement and renewal/replacement items have been aggregated to a single category.

Table 7-31 Recommended Capital Expenditure 2000 to 2004 (Nominal $ million)

1999/00 2000/01 2001/02 2002/03 2003/04 July-Dec 04

Market Expansion 55.2 54.1 45.5 47.6 46.8 23.2 System Reinforcement/ Renewal/Replacement

17.1 13.4 5.6 9.5 15.6 15.8

System Reinforcement 1.5 0.5 2.5 6.7 3.5 2.8 Renewal/Replacement 15.6 12.9 3.1 2.8 12.1 13.0


Corporate IT costs not included in the above recommendation are shown in the table below:

Table 7-32 Corporate IT Expenditure 2000 to 20004 (Nominal $ million)



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8. CAPITAL EXPENDITURE FORECAST 2005-2010

8.1 AGLGN FORECAST CAPITAL BASE

Section 8.20 of the Code enables reference tariffs to be determined on the basis of forecast capital expenditure, provided that the capital expenditure is reasonably expected to pass the requirements of Section 8.16 of the Code. Section 8.32 enables reference tariffs to reflect forecast depreciation over the Access Arrangement period. Section 8.33 requires depreciation to reflect the economic life of the asset group in question. The Code does not specifically outline the approach that has to be adopted to determine the efficient cost for a level of service. As such, ECG proposes to assess the capital costs as outlined in Section 7. AGLGN has set out its calculation of the Regulatory Capital Base as shown in the table below.

Table 8-1 Roll Forward Of Regulatory Capital Base 2005 To 201049 Combined Total – (Nominal $ million)

2004/05 2005/06 2006/07 2007/08 2008/09 2009/10

Opening Balance 1,890.3 1,967.3 2,080.7 2,173.6 2,262.3 2,335.0

Add Revaluation Of Assets 52.0 54.2 57.2 59.7 62.2 64.3

Add Capital Expenditure 92.9 131.5 113.2 111.3 97.5 100.2

Less Depreciation (65.0) (69.4) (74.6) (79.4) (84.1) (88.7)

Less Capital Contributions (0.9) (0.9) (0.9) (0.9) (0.9) (0.9)

Less Disposals (2.0) (2.0) (2.0) (2.0) (2.0) (2.0)

Closing Balance 1,967.3 2,080.7 2,173.6 2,262.3 2,335.0 2,407.9

AGLGN’s capital base consists of three groups of assets which are:

• The Wilton to Newcastle Transmission Pipeline

• The Wilton to Wollongong Transmission Pipeline

• The AGLGN Distribution System AGLGN’s proposed Regulatory Capital Base for each of these groups is given in the following three tables. 49 Table 5.15 Access Arrangement Information (Dec 2003)


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Table 8-2 Roll Forward Of Capital Base Wilton to Newcastle Transmission Pipeline

2005 to 201050 – (Nominal $ million)

2004/05 2005/06 2006/07 2007/08 2008/09 2009/10

Opening Balance 120.0 127.5 132.3 133.8 136.0 138.5




Less Capital Contributions 0.0 0.0 0.0 0.0 0.0 0.0

Less Disposals 0.0 0.0 0.0 0.0 0.0 0.0

Closing Balance 127.5 132.3 133.8 136.0 138.5 140.2

Table 8-3 Roll Forward Of Capital Base Wilton to Wollongong Transmission Pipeline

2005 to 2010 – (Nominal $ million)

2004/05 2005/06 2006/07 2007/08 2008/09 2009/10

Opening Balance 11.1 11.4 12.6 12.7 12.8 12.9




Less Capital Contributions 0.0 0.0 0.0 0.0 0.0 0.0

Less Disposals 0.0 0.0 0.0 0.0 0.0 0.0

Closing Balance 11.4 12.6 12.7 12.8 12.9 13.1

Table 8-4 Roll Forward Of Capital Base AGLGN Distribution System

2004 To 201051 – (Nominal $ million)

2004/05 2005/06 2006/07 2007/08 2008/09 2009/10

Opening Balance 1,759.2 1,824.4 1,935.9 2,027.1 2,113.4 2,183.4




Less Capital Contributions (0.9) (0.9) (0.9) (0.9) (0.9) (0.9)

Less Disposals (2.0) (2.0) (2.0) (2.0) (2.0) (2.0)

Closing Balance 1,828.4 1,935.9 2,027.1 2,113.4 2,183.4 2,254.5

50 Table 5.15 Access Arrangement Information (December 20003). 51 Table 5.15 Access Arrangement Information (December 20003).


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8.2 FORECAST EXPENDITURE

AGLGN forecast capital expenditure for the next Access Arrangement period (2005-10) is summarised in the following table

Table 8-5 Forecast Capital Expenditure 2005-2010 (Real $ million 2005)

2004/05 2005/06 2006/07 2007/08 2008/09 2009/10 Forecast Market Expansion 49.0 51.7 50.3 48.7 48.5 48.4System Reinforcement /Renewal/Replacement

31.2 63.3 47.0 45.9 30.8 28.2

Non System Assets 12.7 13.0 9.9 8.0 8.2 10.9Total 92.9 128.0 107.2 102.6 87.5 87.5

In accordance with Section 8.16 of the Code, the prudency of the expenditure in this Access Arrangement period is assessed in the following sections of the report for each of the AGLGN expenditure categories. Main items included are:

• The primary pipeline loop which was deferred from the previous Access Arrangement period. It is included as a Renewal/Replacement item, not a System Reinforcement item as previously. Its prime justification is for security of supply, not for capacity growth.

• New mains and services to provide supply to about 35000 new customers per

annum. • Major system reinforcement items including the North Ryde-Turramurra primary

main extension deferred from the previous Access Arrangement period. A breakdown of this forecast expenditure into categories, as given in the following table, is also used in analysing the forecast expenditure.

Table 8-6 AGLGN Forecast Capital Expenditure 2005 - 201052 (Real $ million 2005)

2004/05 2005/06 2006/07 2007/08 2008/09 2009/10 Capex By Major Pipelines / Asset Category Trunk Wilton-Newcastle 6.4 3.3 0.1 0.7 0.9 0.1Trunk Wilton-Wollongong 0.2 1.0 0.0 0.0 0.0 0.0Country TRS 1.7 0.1 0.3 0.1 0.1 0.1Metering 24.2 23.8 27.0 24.2 26.9 25.6Local Network 60.4 99.8 79.8 77.6 59.6 61.7

Total 92.9 128.0 107.2 102.6 87.5 87.5Capex Split By Program Plant & Equipment 1.0 1.0 1.0 1.0 1.0 1.0Motor Vehicles 2.6 1.6 3.2 3.1 2.6 1.6IT 9.1 10.4 5.7 3.9 3.4 6.6Access Arrangement Costs 0.0 0.0 0.0 0.0 1.2 1.7Total Non-System Assets 12.7 13.0 9.9 8.0 8.2 10.9Mains 9.9 11.9 11.1 9.6 9.5 9.4 Services 23.3 23.8 23.2 23.1 23.0 22.9 Meters 15.8 16.0 16.0 16.0 16.0 16.1 Total Market Expansion 49.0 51.7 50.3 48.7 48.5 48.4 52 Table 5.7 Access Arrangement Information (December 20003).


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Mains 15.4 41.6 26.5 26.8 10.9 11.3 Services 0.4 0.9 1.0 0.7 0.3 0.3 Programmed Rehabilitation 2.6 9.9 6.6 8.3 6.8 5.2 Meters 8.4 7.8 11.0 8.2 10.9 9.5 Fixed Plant 4.4 3.1 1.9 1.9 1.9 1.9 Total System Upgrades 31.2 63.3 47.0 45.9 30.8 28.2

Total 92.9 128.0 107.2 102.6 87.5 87.5 For analysis purposes, ECG has separated the system upgrade expenditure into two sections, one for each of two different types of expenditure, system reinforcement and renewal/replacement. These are reviewed separately in Sections 8.4 and 8.5. Market expansion expenditure is reviewed in Section 8.3, and non system assets in Section 8.6. A major project for security of supply, the Sydney Primary Loop, is reviewed in Section 8.5.3.1.

8.3 GROWTH – MARKET EXPANSION PLANS

AGLGN advise that the forecast number of customers to be supplied is about 35,000 p.a, and that the forecast capital expenditure to extend supply to these customers is as outlined in the table below. Expenditure is required for mains, services and meters, and the actual/forecast costs in each of these categories are given in the following table. The forecast numbers of new customers each year are also given.

Table 8-7 AGLGN Forecast Market Expansion Capital Expenditure (Real $ million 2005)53

2004/0554

2005/06 2006/07 2007/08 2008/09 2009/10

Mains 4.9 11.9 11.1 9.6 9.5 9.4 Services 11.7 23.8 23.2 23.1 23.0 22.9 Meters 7.9 16.0 16.0 16.0 16.0 16.1 Total Market Expansion 24.5 51.7 50.3 48.7 48.5 48.4New Customers 17669 36089 35437 35405 35326 35317Mains ($ per customer) 277 331 313 270 268 265Services ($ per customer) 662 658 656 654 652 650Meters ($ per customer) 447 444 450 452 453 455Total 1386 1433 1419 1376 1373 1370

This data shows the forecast number of customers is 195,243 and the forecast expenditure averaged over all customers is $1394 (real $ 2005), and comprises:

• Mains $289 per customer. • Services $655 per customer. • Meters $451 per customer.

This average expenditure per customer is more than that for the previous Access Arrangement period, due to the changing mix of domestic customer types with more high/medium density units, fewer new homes in new estates and more new homes in built up areas.

53 Derived from Table 5.7 Access Arrangement Information (December 20003). 54 Note that data for 2004/05 is from January to June.


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Analysis of each expenditure category is given in the following sections.

8.3.1 Mains

In comparison to the 2000-04 Access Arrangement period, capital for mains is forecast to increase from an average of $285 per customer to $289 per customer. The forecast expenditure has been calculated using the length of mains for each customer type and the average unit cost for these mains. AGLGN has provided detailed information on customer type and the unit cost for constructing gas pipes for each customer type. Using real $ 2005, the unit cost is constant over the five year forecast Access Arrangement period as shown in the following table.

Table 8-8 Mains Rate55 (Real $ 2005)

Customer Type Unit cost $/m E-G 102 New Homes-Built Up 102 New Homes –New Estate 38 Medium/High Density 77 I&C 102

As discussed in Section 7.4.1, ECG considers that the forecast unit costs ($ per metre) for mains to supply new homes in built up areas, and for E-G customers, are high. From ECG’s industry knowledge and experience, the unit cost that would be incurred by a prudent service provider acting efficiently should be less than twice the rate for new estates. Based on the analysis already carried out in Section 7.4.1, the unit costs for other customer types are considered prudent and efficient. Therefore applying the revised rate of $76 per metre to supply new homes and for E-G in build up areas derived in Section 7.4.1 and the other rates provided from Table 8-8, ECG has calculated the revised unit cost for market expansion. The average unit cost for the five years is $261 per customer. ECG has also reviewed the project to supply Singleton and considers the project to be prudent and consistent with 8.16 of the Code. ECG therefore recommends including the cost into the overall market expansion. In accordance with section 8.16 of the Code, ECG recommends the forecast expenditure accepted for inclusion in the capital base for the 2005-10 Access Arrangement period be based on its estimate of $261 per customer plus $3.7 million for Singleton main. This has the effect of reducing the AGLGN total mains allowance for 2005-2010 by $5.5 million, from $56.4 million to $50.9 million.

8.3.2 Services

AGLGN average service cost per customer for the period 2005 to 2010 ranges from $650 to $65856 (Real 2005$) with an average cost of $655 over the five years. The variation in the unit cost is due to the differences in customer mix.

55 AGLGN Market Expansion Capex and Unit Rate spreadsheet 56 AGLGN Market Expansion Capex and Unit Rate spreadsheet


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Allowing for variation in customer mix, the $655 unit cost is comparable with the 2004 figure of $684 derived in section 7.4.2. ECG considers the AGLGN forecast expenditure on these services to be consistent with those that would be incurred by a prudent operator acting efficiently. ECG therefore recommends that AGLGN’s forecast expenditure of $127.8 million is accepted for inclusion in the capital base for 2005 to 2010 Access Arrangement period.

8.3.3 Meters

AGLGN average meter cost per customer for the period 2005 to 2010 ranges from $444 to $45557 (Real 2005$) as shown in Table 8-7. This equates to an average cost of $451 over the five years. The average unit cost for the five years is based on the unit costs for the various customer types as shown in the table below:

Table 8-9 Meter Cost


While ECG accepts the average unit cost of $195 for residential customers for the current period, it considers a lower average unit cost should apply for the forecast period. Medium size meters, suitable for larger than average residential loads are available at a lower cost than those currently used by AGLGN. These meters have been used in other States for the past three to four years. AGLGN estimates that 3.5%58 of its residential meter requirement is for large meters. Based on its industry experience, ECG considers that approximately two thirds or 2% of this requirement would suit the category of medium size meters. Based on an installed unit cost of $300 for a medium size meter, in lieu of AGLGN’s cost for a large size meter of $116859, ECG has calculated the average domestic meter cost to be $180. ECG therefore recommends that the average unit cost for domestic customers should be $180. In addition, ECG also considers the unit cost for medium/high density meters should be $600 for reasons outlined in section 7.4.3. Using the unit cost of $180 and $600 from above, ECG has calculated the average unit cost for all customer types as shown in Table 8-9 to be $399. ECG therefore recommends that the forecast expenditure accepted for inclusion in the capital base for the 2005-10 Access Arrangement period is based on its calculated efficient average unit cost of $399 per customer. This has the effect of reducing the

57 AGLGN Market Expansion Capex and Unit Rate spreadsheet 58 Email from AGLGN dated 020804 Average Cost per Residential Meters. 59 Email from AGLGN dated 020804 Average Cost per Residential Meters.


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AGLGN total meters allowance for 2005-2010 by $10.1 million, from $88.0 million to $77.9 million.

8.3.4 Summary

A summary of the recommended market expansion expenditure for inclusion in the capital base during this period (2005-2010) is given in the following table:

Table 8-10 Recommended Market Expansion Capital Expenditure


2004/0560 2005/06 2006/07 2007/08 2008/09 2009/10

Mains 4.5 11.0 10.1 8.6 8.4 8.3Services 11.7 23.8 23.2 23.1 23.0 22.9Meters 7.0 14.2 14.1 14.2 14.2 14.2Total Market Expansion 23.2 49.0 47.4 45.9 45.6 45.4

8.4 SYSTEM REINFORCEMENT

8.4.1 Network Performance Assessment

The network capacity planning process outlined previously underpins the planning of system reinforcement projects. Assessment of its key features is that: • Using load factors and load diversities to determine peak hour loads is common gas

industry practice, and the methods used for determining these factors are appropriate.

• Peak hour load factors have been prudently determined from a specific program monitoring flows to a group of residential customers and individual customers, conducted about ten years ago61.

• Planning for capacity to supply the peak load forecast to occur in a 1 in 10 year severe winter is appropriate. AGLGN analysis of historical data in New South Wales has shown there is little significant difference between this load factor and that for a 1 in 20 year severe winter which is often used in the gas industry.

• The severe weather load factor is prudently determined from an analysis of the effect of temperature on peak loads in various regions of New South Wales62.

• The method for predicting the timing of future reinforcement projects is appropriate. However forecasting uncertainty means that predictions beyond a short term period can be in error and need to be regularly reviewed. The annual performance validation reports which include predictions for a ten year period are appropriate for this review.

AGLGN does not regularly review the peak hour and severe weather load factors, although it does review load diversities as part of each network validation. The load factors should be reviewed to ensure that up to date information is used, reflective of current trends in gas consumption profiles for existing and new types of customer. This would minimise the risk of providing for unnecessary network capacity.

60 Note that data for 2004/05 is from January to June. 61 AGL Report, Gas Distribution Profile for Domestic Market, April 1994 62 Agility Report, Design and Planning, Gas, February 2003


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It is suggested that a review of each of these be conducted at least once every five year Access Arrangement period. In particular the peak hour load factor should be reviewed as it has not been measured for ten years.


AGLGN advise63 that the forecast expenditure for system reinforcement projects is $48.9 million as per the following table.

Table 8-11 AGLGN Forecast System Reinforcement Capital Expenditure (Real $ million 2005)

2004/0564 2005/06 2006/07 2007/08 2008/09 2009/10

North Turramurra Primary Mains 10.9 North Narrabeen Secondary Mains 3.4 Wollongong Secondary Mains 5.4 Plumpton-Sutherland Secondary 2.5 Castle Hill-Dural Medium 2.5 Rouse Hill Medium 2.2 Beverley Hills PRS 1.5 Other Projects 4.0 3.9 3.2 3.9 2.0 3.5 Total Capacity Development Projects

4.0 17.0 9.1 5.4 4.5 8.9

A review of a number of network validation reports, including those for eight areas in which material reinforcements (>$0.5 million) are proposed, shows the timing of these projects has been prudently identified in accordance with the Network Capacity Planning Process (refer Section 4.3). Network modelling shows the scope of planned projects is effective in overcoming capacity limitations due to low network pressures. These projects are as predicted based on current network performance, but are subject to an annual review that could affect their scope and timing. They will proceed only if authorised in accordance with the Capital Expenditure process (refer Section 4.4). About 70 reinforcement projects have been proposed by AGLGN65 for the next Access Arrangement period. The majority of these require <$0.5 million. Eight of the thirteen major projects proposed have been reviewed and are assessed below.

8.4.3 Review of Material Projects Expenditure

1 North Ryde-Willoughby Secondary 1.1 North Ryde-North Turramurra This project consists of 11km of 250mm primary main from North Ryde to North Turramurra, and a new Pressure Regulating Station (PRS) at Turramurra, in 2005/06 at an estimated cost of $10.9 million (real $ 2005). It is required to reinforce the North Ryde-Willoughby secondary network by introducing a new supply point, and is part of the project selected from 6 alternatives after a thorough cost analysis of the options.

63 AGLGN Capital Expenditure Analysis Spreadsheet 64 Note: 2004/05 is shown as the cost for a full year fro ease of assessment. 65 AGLGN Capacity Development Capital Forecast Summary Table


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It was previously approved for completion during the current Access Arrangement period (2000-04) in which it had been included at an estimated cost of $6.9 million (nominal $), but was subsequently deferred as network performance monitoring showed it was not needed until later than originally forecast. Its estimated cost has increased due to:

• New route due to new motorway (M2) bridge crossing. • Crossing national park area due to route alteration. • Reduced productivity due to need to guarantee no more than 24 hour residential

access restriction. • More difficult traffic flow management in widened Mona Vale Road, including extra

night work. • CPI increases.

Alternatives were reconsidered after these cost increases were determined, and this proposal is considered to be the best option. It was previously, and is still, considered to be a prudent project in accordance with section 8.16 of the Code. 1.2. Ingleside-North Narrabeen This consists of 4.5km of 200mm secondary main from Ingleside to North Narrabeen, in 2006/07 at an estimated cost of $3.4 million (real $ 2005). It is required to reinforce the North Ryde-Willoughby secondary network, and is part of the project selected from 6 alternatives after a thorough cost analysis of the options (refer item 1.1 above). It was previously approved for completion during the current Access Arrangement period (2000-04) in which it had been included at an estimated cost of $3.9 million (nominal $), but was subsequently deferred as network performance monitoring showed it was not needed until later than originally forecast. In deciding on the scope and timing of the project, AGLGN had gone through a process of considering options and the appropriateness of the timing. ECG has concluded that AGLGN had reached the most prudent decision based on its asset management process. As such, ECG considers this to be a prudent project in accordance with section 8.16 of the Code. 2. Wollongong Secondary This consists of 9.5km of 150mm main from Kemblawarra to Barrack Heights, in 2010 at an estimated cost of $5.4 million (real $ 2005). AGLGN has identified a need to reinforce the Shellharbour region due to increasing gas demand and the proposed project would have an additional benefit of improving the security of supply. AGLGN selected this option after considering three alternatives. ECG considers that one of the other options may be more appropriate. This option consist of a five stage development between 2010 and 2022 and its total cost for 13.5kms of 150mm main has been estimated by AGLGN66 to be $7.2 million (real $ 2005) spread over 12 years. This has been calculated by ECG to have a net present value of $4.4 million based on the AGLGN’s required rate of return. Whilst the scheme provides a lower level of security of supply than AGLGN’s preferred scheme, ECG considers that the higher level proposed by ALGN does not justify the additional expenditure of $1 million ($5.4 million minus $4.4 million).

66 Agility report, Wollongong Secondary Mains Capacity Development project, December 2003.


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ECG considers that the current level of security of supply to Shellharbour is consistent with good industry practice and it does not warrant an additional expenditure of $1 million to increase this level of security. ECG believes that a prudent operator acting efficiently in accordance with good industry practice would have a preference to the alternative considered by ECG. The preferred scheme has the following advantages:

• It has the ability to be completed in stages, providing scope for deferral of future stages should the forecast load not eventuate.

• ECG estimates the approximate expenditure for the first stage (about 3km of

150mm main) to be about $2 million67. Consistent with section 8.16 of the Code, ECG recommends the capital accepted for this scheme in 2010 be reduced by $3.4 million to $2.0 million. Note: Given that this project is planned for 2010, there is a possibility that it may not be required at all during the 2005-2010 Access Arrangement Period. 3. Newcastle Secondary Proposed works consist of: 3.1 - 4.5km of 200mm main along Cessnock Rd to Kurri Kurri, 2007, $0.8 million 3.2 - 3.5km of 150mm main through Maitland to Rutherford, 2009, $0.9 million. They are required to increase capacity to supply forecast load growth in areas near Maitland. Whilst AGLGN has not provided any information on alternatives considered or any risk assessment undertaken, ECG after reviewing the timing and scope of the proposed project believes that they are prudent and consistent with section 8.16 of the Code. 4. Plumpton-Sutherland Secondary Proposed works consist of: 4.1 – 0.9km of 250mm secondary main in Strathfield, 2005, $1.0 million. 4.2 – 1.2km of 150mm secondary main in Seven Hills, 2007, $0.7 million. 4.3 – 4.3km of 200mm secondary main to Castle Hill, 2009, $2.5 million. 4.4 – A PRS at Beverley Hills, subject to completion of the Primary Loop security of supply project, 2007/08, $1.5 million. The first three projects are required to provide capacity to supply forecast load growth in the affected areas. Two options were considered for each of projects 4.2 and 4.3, but no risk assessment has been provided. The timing and scope for project 4.1 have been reviewed and are considered by ECG to be prudent. The high unit cost for this main is due to its construction along a major road, which also requires working at night. There is also a need to avoid fibre optic cables and a service station. The cost estimate is considered reasonable taking into account these factors.

67 ECG’s recommended option is 13.5 kms long and cost $ 7.2 million. Stage 1 in 2010 is 3 kms which equates to approximately $2 million.


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The timing and scope of projects 4.2 and 4.3 were reviewed and are considered by ECG to be prudent and efficient in accordance with section 8.16 of the Code. Project 4.4 is required for security of supply and its justification is linked with that for the primary loop. ECG therefore believes that it would be appropriate to transfer the $1.5 million cost of this project to the primary loop project expenditure estimate. 5. Castle Hill-Dural Medium Pressure This consists of: 5.1 – 1.85km of 150mm secondary standard main in Castle Hill, 2005, $0.9 million. 5.2 – 5.7km of 150mm steel main in Dural, and a regulator, 2009, $2.5 million. The Castle Hill-Dural project is required to provide capacity to supply forecast load growth in the affected areas. Information on the scope and timing of the project was provided. Based on the review of this information, ECG considers the project to be prudent and efficient in accordance with section 8.16 of the Code. 6. Narellan-Camden Medium Pressure This consists of 2.27km of 150mm steel main in Smeaton Grange, and 0.48km of 110mm PE main crossing Camden Valley Way, 2010, $1.0 million. This project is required to provide capacity to supply forecast load growth in the affected areas, including various new housing estates. Alternatives were considered, and a risk assessment undertaken. ECG believes that a prudent service provider acting efficiently would include the project in its capital program. However, it would consider deferring the project an additional year based on good industry practice. This is supported by the minimum pressures predicted by network modelling to be comfortably above the system minimum in year 2010. Consistent with section 8.16 of the Code, ECG recommends that this project should be deferred to a later year and not be included in the 2005 to 2010 Access Arrangement period. 7. Orange Medium Pressure This consists of 0.78km of 150mm steel main and a regulating station in 2007 at a total cost of $0.4 million. The project is required to provide capacity to supply forecast load growth. Alternatives were considered, and a risk assessment undertaken. ECG believes that the project would be considered prudent consistent with section 8.16 of the Code. It therefore recommends that the cost be included in forecast expenditure for the next Access Arrangement period.


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8. Griffith Medium Pressure This consists of 1.06km of 160mm PE main and a regulating station in 2005 at a total cost of $0.5 million. This cost takes into account that rail, canal and gantry crossings are necessary. This project is required to provide capacity to supply forecast load growth. After reviewing the proposal, ECG considers the timing, scope and cost to be would be accepted by a prudent service provider acting in accordance with good industry practice. ECG therefore recommends accepting the cost as forecast expenditure for the next Access Arrangement period.

8.4.4 System Reinforcement Expenditure Summary

From Table 8-5, the forecast total reinforcement cost for the six year period is $48.9 million (real $ 2005) to support a forecast growth of 213,000 customers. This equates to an average cost of $230 per customer. For the period 2000 to 2004, the forecast average cost was $124 per customer compared with an actual of $91.

ECG makes the following observations based on its assessment of the 8 out of 13 projects:

• Forecast costs for individual projects are considered by ECG to be consistent with section 8.16 of the Code.

• Options have been considered and risk assessments undertaken in about half the

proposed projects which are what would be expected from a prudent service provider acting in accordance with good industry practice.

• The timing of projects is considered prudent, except in one case where a deferral

is considered appropriate. • One project should be listed as a security of supply item, not a reinforcement item.

ECG also observed that during the first Access Arrangement period, AGLGN spent only 90% of its forecast capital expenditure for typical non major projects. This net reduction accounted for deferral of some proposed projects, and included new projects not previously forecast. Below forecast expenditure is typical and is primarily due to forecasting uncertainties. ECG has also observed similar cost differences in other states. ECG considers that the AGLGN forecast system reinforcement expenditure should be determined after prudently accounting for historical differences between forecast and actual expenditure. It therefore believes that a prudent service provider acting efficiently would consider reducing the forecast expenditure on typical non major projects by 10%. In accordance with section 8.16 of the Code, ECG recommends the following changes to the AGLGN forecast capital expenditure

• Reduce expenditure in year 2009/10 for the Wollongong secondary mains project from $5.4million to $2.0million (refer project 2)

• Reduce expenditure in year 2009/10 for Other projects from $3.5million to $2.5million (refer project 6: Narellan – Camden medium pressure main)

• Reduce expenditure in year 2007/08 by $1.5million, by transferring the Beverley Hills PRS to the primary loop security of supply project (refer project 4.4)

This reduces the AGLGN forecast expenditure from $48.9million to $43.0million. The revised forecast includes $10.9million for a major project in North Turramurra, deferred from the previous Access Arrangement period, and $32.1million for typical non major


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projects. ECG recommends this should be reduced by $3.2million. The reduction each year should be proportional to the value of the non major projects in each year, and is applied as a reduction in the value of “other projects” category in each year. In addition to the above changes, ECG recommends the inclusion of $2.0 million in year 2005 for two projects deferred from 2004 as outlined in Section 7.5.1. These are not included from the AGLGN forecast expenditure for 2005. ECG therefore recommends that the forecast expenditure proposed by AGLGN for system reinforcement projects for capacity development purposes be reduced, and that the expenditure accepted for inclusion in the capital base for the 2005-10 period be based on that shown in the following table for the six years 2005 to 2010. The overall effect reduces AGLGN’s proposed system reinforcement expenditure for 2005 to 2010 by $7.1 million, and transfers $1.5 million to the primary loop project.

Table 8-12 Recommended System Reinforcement Capital Expenditure (Real $ million 2005)

2004/0568 2005/06 2006/07 2007/08 2008/09 2009/10Projects deferred from 2003 2 North Turramurra Primary Mains 10.9 North Narrabeen Secondary Mains 3.4 Wollongong Secondary Mains 2.0 Plumpton-Sutherland Secondary 2.5 Castle Hill-Dural Medium 2.5 Rouse Hill Medium 2.2 Beverley Hills PRS 0.0 Other projects 3.6 3.3 2.3 3.5 1.5 2.1 Total Capacity Development Projects

5.6 16.4 8.2 3.5 4.0 4.1

8.5 RENEWAL/REPLACEMENT

Table 8-13 is derived from AGLGN’s Access Arrangement Information (December 2003) table 5.7 Renewal/replacement activities. It includes mains (including the Sydney Primary Main proposal) and services, the Medium and Low Pressure (M&LP) mains rehabilitation program, meter/regulator/filter and fixed plant replacement.

Table 8-13 Renewal/Replacement Forecast Expenditure69, (Real $ million 2005)

2004/0570 2005/06 2006/07 2007/08 2008/09 2009/10

Mains71 (includes Sydney Primary Loop Project)

11.4 24.6 17.4 21.4 6.4 2.4

Services 0.4 0.9 1.0 0.7 0.3 0.3 Programmed Rehabilitation 2.6 9.9 6.6 8.3 6.8 5.2 Meters 8.4 7.8 11.0 8.2 10.9 9.5 Fixed Plant 4.4 3.1 1.9 1.9 1.9 1.9 Total System Upgrades 27.2 46.3 37.9 40.5 26.3 19.3

68 The expenditure for this 2004/05 is for a full year. 69 Table 8.7 AGLGN Actual Capital Expenditure 70 The expenditure for 2004/05 is for a full year. 71 Expenditure for system reinforcement has been deducted from this line item.


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AGLGN has advised72 that the major renewal/replacement items include:

• A project to improve security of supply to Sydney which will replace the earlier Sydney Primary Main proposal which had been planned to be completed in the previous Access Arrangement period. Total capital expenditure is now forecast at $50 million (real 2005).

• A continuation of the programmed renewal of networks reaching the end of their

economic lives at a forecast cost of $39 million (Real 2005).

• A continuation of the aged meter replacement program, assuming an extension of the current agreement with the Department of Fair Trading (DFT) at a forecast cost of $55 million (real 2005).

• The replacement of key IT functionality that is operating on aging legacy systems

which no longer meet operating requirements at a forecast cost of $39 million (Real 2005).

In meetings with AGLGN/Agility, ECG was advised that:

• Only new meters are used for the residential aged meter replacement program. It is not clear to ECG why AGLGN has adopted a policy of only using new meters and has not considered a meter repair program. Use of repaired meters offers an opportunity for cost reduction and ECG recommends that this matter is further investigated prior to the next Access Arrangement Review.

• Residential service regulators are changed in conjunction with each aged meter

replacement.

• The I&C meter change program contains an allowance for the change of regulators. I&C meters are repaired where possible.


The review has taken into consideration AGLGN Systems Upgrade Capital Plan 2004/05 – 2009/10, AGLGN/Agility Asset Management Plan 2004/05 and the AGLGN/Agility Integrity Assessment Report – Programmed Mains and Services Renewal Review (Version 2 - July 2004).

8.5.2 Programmed Rehabilitation

AGLGN forecast expenditure is $39.4 million (real $2005) for the programmed rehabilitation of the low and medium pressure networks. From the Asset Management Plan 2004/05, (AMP 2005) there are approximately 427 kilometres of old ferrous network mains remaining to be rehabilitated which supply approximately 24,730 end users. Section 6.5.1.4 of the AMP 2005 states that 95% of the original ferrous networks have been renewed. The highest priority areas have now been completed and the remaining areas are assessed on risk and economic terms. Therefore, apart from the isolated sections of older ferrous mains, the low and medium pressure mains are considered by ECG to be in good condition. This condition assessment is supported by the following:

72 Access Arrangement Information Dec 2003


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• Unaccounted for gas (UAG) for AGLGN for 2003 was 2.1%. This level is comparable

with other Australian gas companies and indicates that the overall assets are in good condition.

• Publicly reported leaks per 1,000 customers across AGLGN for 2003 was 12.0. This

is well below the rate for Victorian gas distributors (between 16 and 24). • Leaks detected per km of mains systematically surveyed for 2003 was 0.122. This is

less than the Victorian gas distributors (between 0.54 and 0.7 leaks per surveyed km of main).

Forecast expenditure covers all the remaining cast iron areas as per Table 8-14 below.

Table 8-14 Details of Un-Rehabilitated Areas73 Network area End users Length of

main74 Forecast Renewal

Cost75

Warringah/Pittwater 4,800 62.7 3.5 Smithfield/Fairfield/Liverpool

4,630 136.7 6.0

Bathurst 2,250 48 5.2 Bowral 1,200 25 2.5 Maitland 550 12 1.3 Randwick (includes Daceyville & Kingsford)

7,050 83 12.4

Stockton 1,250 26 3.1 Kurri Kurri 3,000 39 5.2 Total 24,730 432.4 39.2 As noted in section 7.6.1, AGLGN deferred the mains rehabilitation program in 2002 largely due to reallocation of available capital to growth sections of the capital expenditure program. AGLGN continued to manage the condition of the asset through ad-hoc renewal. AGLGN conducted a high level review of the risk and financial impacts associated with the operation of the un-rehabilitated networks. The Integrity Assessment Report (Report) made a number of recommendations including:

• A more detailed assessment be carried out in the next twelve months to confirm the long- term strategy and associated renewal plan for the low and medium pressure networks.

• A strategy is developed to renew the remaining un-rehabilitated networks over the

next five years taking into account resource and budgetary constraints. ECG concurs with the need to develop an optimal rehabilitation strategy which prioritises and provides a timeframe for rehabilitation of the remaining networks. At this stage ECG

73 AGLGN Asset Management Plan 2004/05 table 6.19 74 Data from AGLGN SIB Capital Forecast Summary 75 Real $ million 2005


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believes insufficient analysis has been done to justify completion of the rehabilitation program during the forthcoming Access Arrangement period. The risk analysis carried out in the Report is of a generic nature over a 10 year time frame and has not identified any specific risk relating to any of the remaining un-rehabilitated networks. The Report while identifying a number of integrity issues has not provided any details. Although the cast iron and galvanised steel mains in question are long-term assets and are considered by AGLGN to be more than 50 years old, the condition of such mains does not normally suddenly deteriorate. Integrity issues are generally managed through maintenance while a long-term strategy is developed. In addition, there are no asset condition key performance indicators to show trends over time eg. 5-year moving average of survey leaks/km which may justify an accelerated replacement program. Notwithstanding the above, ECG agrees that a prudent service provider would progress the rehabilitation program while its long-term strategy is being developed. AGLGN is expecting to finalise this strategy within twelve months. Progressive replacement of old cast and galvanised steel mains is also consistent with gas industry practice. Based on the data provided, ECG considers a prudent service provider acting efficiently would make provision for a level of expenditure equivalent to the estimated renewal costs for the areas shown in the table following table. ECG recognises that the development of the replacement strategy may result in priority being given to other areas. In view of these circumstances, it is recommended that any expenditure is subject to a prudency check consistent with the Code at the next Access Arrangement review and only the approved amounts are rolled into the asset base

Table 8-15 Recommended Renewal Expenditure (Real $ million 2005)

Renewal Area Length of Mains

km Renewal Cost

Warringah/Pittwater 62.7 3.5 Smithfield/Fairfield/ Liverpool

136.7 6.0

Bathurst 48 5.2 Bowral 25 2.5 Total 272.4 17.2

The recommended expenditure for renewal of mains and services is $17.2 million (real $ 2005) for approximately 272 km of mains. The unit cost for each area ranges from about $44/m to $108/m which equates to an average of $63/m. This is lower than the current Access Arrangement period and compares favourably with the ESC 2002 Final Decision in Victoria where the range was $86 to $116 per metre. In the circumstances described, ECG considers that the forecast expenditure for Warringah/Pittwater, Smithfield/Fairfield/ Liverpool, Bathurst and Bowral is consistent with that of a service provider acting efficiently in accordance with section 8.16 of the Code. Consistent with Attachment A, Category 2 of the Code, ECG recommends that AGLGN provides more detailed information about the projects at the next Access Arrangement review.


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8.5.3 Mains and Services

Forecast expenditure covers:

• Sydney Primary Loop Project. • Trunk Facilities upgrades. • Trunk pipeline (Mine Subsidence). • Supply main upgrades. • Ad hoc rehabilitation.

• Fixed Plant.

• Government Authority Works.

8.5.3.1 Sydney primary loop project

This project is to replace the previously deferred Sydney Primary Main Project which had an estimated cost of $32.5 million (nominal $2001), equivalent to about $35.6 million (real $2005). Provision was made in the Final Decision 2000 for this project. The forecast expenditure for the now proposed project is $51.6 million (real $2005) as shown in the following table.

Table 8-16 Forecast Expenditure for Sydney Primary Main76 (Real $million 2005)

2004/05 2005/06 2006/07 2007/08 2008/09 2009/10 Total Sydney Primary Loop

1.06 14.04 14.04 17.77 4.67 0 51.6

AGLGN advised77 it was assumed that the main would be constructed within the M5 motorway corridor utilising the proposed extension to the M5. Following a number of changes to the M5 project, the construction of the Primary Main in this corridor was not feasible. The project involves laying 30 km of 550 diameter pipeline to provide a second supply route of 100% capacity to most of Sydney. Trunk Receiving Station and Primary Receiving Station facilities are also included. Expenditure is forecast to begin in 2004/05 and continue through until 2008/09. This project is purely a risk mitigation project aimed at reducing the high risk of a large scale loss of supply for Sydney in the event of an incident, to a low level of risk. Documents reviewed for this project include:

• Agility Document - Design Brief for Sydney Primary Loop Project. • Agility Document - Primary Network 2003 – Validation Report.

76 AGLGN SIB v1.3.xls 77 Access Arrangement Information Dec 2003


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• Agility Document - Primary System Network – Validation and Performance Forecast.

• Consultant’s Report – Primary Main Gas Pipeline Risk and Reliability Assessment. • Agility Document – Cost Estimate Primary Failure.

This Sydney Primary Main Looping project was deferred because the selected route became unsuitable when design changes to the M5 motorway occurred. Since this event, there have been two new route investigations undertaken. The first of the routes selected was rejected when HV underground cables were found to be along some sections of the route. The route that is currently under investigation has resulted in the estimated expenditure for the project to be increased by approximately $15.5 million (real $ 2005). The increased forecast costs are due to:

• An extra 3 km of main. • Higher reinstatement costs due to laying the main in a road reserve.

• The route travelling through a higher percentage of main roads. • The laying rate on average for the project has decreased from 150 metres per day

to 50 metres per day due to laying through built-up areas. • Other factors that have also contributed include:

• Uncertainties of local routes due to easement acquisition difficulties. • Cost of traffic management during construction. • Longer directional drills required. • Cost increases for suspension of main on RTA bridges.

The need for the Primary Main Looping, as mentioned above, is to mitigate the high risk of customer outage and economic loss to AGLGN and NSW in the event of an incident that causes the shutdown of the pipeline. Such an incident could be caused by third party impact, loss of pipeline integrity due to corrosion or even an operational mistake such as erroneously closing a line valve during maintenance. In considering the current single feed to the Sydney area by the Primary Main, a comparison was drawn to Victoria’s supply in 1998 when the Longford incident resulted in the curtailment of supply to most of Victoria’s 1.4 million consumers. Since 1998, Victoria has installed about $200 million worth of infrastructure to ensure security of supply to metropolitan Melbourne and most country areas. Victoria already had a relatively small capacity interconnection with NSW and a LNG storage and vaporisation facility at Dandenong. These facilities enabled emergency supply to be maintained to some customers and prevented a possible state wide outage which could have taken several months to restore supply. In addition, the ring main configuration of Melbourne’s primary pipelines is such that each section has full or partial back up in case of a failure. Currently, there is no such backup main for Sydney and there is no storage facility. In the event of an incident resulting in the closure of one or more line valves on the Primary Main, Sydney area consumers would lose gas supply within an hour78.

78 AGLGN Cost Estimate Primary Failure.doc


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8.5.3.2 Consequences of Primary Main Failure

Further discussion on this issue is considered confidential. Table 8-17 Outage Consequences of an Incident

Confidential Table 8-18 Cost Associated with Disruption

Confidential Conclusion The proposal for a 550mm pipeline provides 100% backup capability for the existing Horsley Park to Tempe section of primary pipeline. ECG is of the view that the implementation of this project would achieve a level of security for Sydney comparable to that currently available in Victoria. ECG therefore believes that a service provider acting efficiently, in accordance with accepted good industry practice would implement this project. The project is necessary to maintain safety and integrity of the system which is consistent with section 8.16 of the Code. As such, ECG recommends the acceptance of the project for the next Access Arrangement period.

8.5.3.3 Trunk Facilities Upgrades

The proposed expenditure is associated with facilities upgrade and replacement on the trunk pipelines and includes upgrading of aged telemetry equipment, capital site works at Trunk Receiving Stations, cathodic protection equipment replacement, the provision of pigging facilities and the pigging of licensed pipelines. This work is associated with maintaining the integrity of the trunk system and its operations to provide a safe supply of gas. AGLGN plan to meet the extensive program management needs by engaging contract resources as required. AGLGN’s forecast expenditure of $8.7 million (real $2005) for the upgrading of Trunk Facilities is necessary to maintain the integrity and security of supply. In addition, the expenditure is consistent with the amount that would be invested by a prudent service provider acting efficiently. As such, in accordance with section 8.16 of the Code, ECG recommends acceptance of the forecast expenditure for the next Access Arrangement period.

8.5.3.4 Trunk Pipelines (Mine Subsidence)

A condition known as “Mine Subsidence” is affecting the Trunk Pipeline at Appin. Due to the ground movement resulting from deep mining, excessive stress is being placed on the pipe and could in time lead to failure. There are currently five sites where the mining has


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either affected the pipeline or will progressively affect the pipeline over the next three years. At two sites, physical mitigation work has been undertaken. It is expected that further work will be required at these two sites. Further discussion on the issue is confidential.

8.5.3.5 Supply Mains Upgrades

Forecast expenditure of $3.9 million is for six supply main replacement in Newcastle, Sydney Nth Metro and Sydney West including the completion of the upgrade to 7kPa of the Wollongong Low Pressure network. AGLGN advised that these upgrades are needed to reduce leakage from various sections of main. The forecast expenditure for Wollongong project is approximately $2 million. AGLGN advised that the benefits of this project are reduced leakage and the ability to operate the network at 7kPa. The project includes the insertion of 14.7 kilometres of main, upgrading of supply to 800 customers and the installation of four secondary regulator sets, all to be completed by 2007. The average unit rate for this work equates to $150 per metre of main. This is comparable to the ESC’s 2002 Determination of $120 per metre direct cost plus overheads. ECG considers that the average unit rate of $150/metre is consistent with the amount that would be invested by a prudent service provider acting efficiently. As the other projects are of a similar nature, ECG has concluded that the forecast expenditure is consistent with the amount that would be invested by a prudent Service Provider acting efficiently in accordance with section 8.16 of the Code. ECG therefore recommends the acceptance of the forecast expenditure of $3.9 million (real $2005) for the next Access Arrangement period.

8.5.3.6 Ad hoc Rehabilitation

Ad hoc rehabilitation of mains and services is generally associated with unforeseen work required to address localised safety issues and supply problems. A nominal allowance of $0.5 million (real $2005) per year for ad hoc rehabilitation has been included based on historical levels. During the current Access Arrangement period, AGLGN rehabilitated 275 kilometres of Medium/Low Pressure mains as part of the rehabilitation program leaving approximately 427 kilometres to be completed. The need for ad hoc rehabilitation should be diminishing as 95% of the cast iron mains have now been rehabilitated. Ad hoc rehabilitation is only required for gas pipes that have not been identified as being in poor condition and included as part of the programmed rehabilitation. It is therefore not appropriate to set the nominal allowance at the historic level. As such, ECG considers that AGLGN’s forecast expenditure is greater than the amount that would be invested by a prudent network operator acting efficiently in accordance with accepted good industry. Consistent with section 8.16 of the Code, ECG believes that a forecast level should be set in the range of 20% to 80% of the historic costs. ECG recommends 50% of the history costs ($0.25 million p.a.) as the amount that would be invested by a prudent service provider.

8.5.3.7 Fixed Plant

The proposed expenditure applies to the primary and secondary distribution systems and includes security upgrades at key facilities, replacement of obsolete equipment at pressure reduction stations, upgrading of aged telemetry equipment, security works at trunk


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receiving stations, capital sites work at primary receiving stations, cathodic protection equipment replacement and the installation of additional line valves. The majority of the work specified in this section of the capital forecast is associated with maintaining the integrity of the network and its operations and/or a safe reliable supply of gas. This section represents a large quantity of work with a forecast expenditure of $15.2 million. ECG has reservation in relation to the availability of sufficient experienced and skilled resources to carry out this type of work. However in discussions with AGLGN/Agility it was stated that there were adequate resources to meet the needs of this program within the gas industry in NSW. AGLGN/Agility plan to meet their program management needs by contracting in the additional engineering and project management resources. The two major projects are the upgrade of a PRS every year at a total cost of $2.5 million and the programmed replacement of remote terminal units (RTU) associated with the control room SCADA equipment at a total cost of $1.1 million. The upgrade for each PRS is $395,000. The expenditure is considered by ECG to be consistent with the amount that would be invested by a prudent service provider acting efficiently. The replacement of the RTU’s ranges from $29,000 to $34,000 per unit. The expenditure is considered by ECG to be consistent with the amount that would be invested by a prudent service provider acting efficiently. The remainder of the projects range in value from $50,000 to $600,000. The expenditure is considered by ECG to be consistent with the amount that would be invested by a prudent service provider acting efficiently. As such, ECG recommends acceptance of the forecast expenditure of $15.2 million for fixed plant for the next Access Arrangement period.

8.5.3.8 Government Authority Work

Within the Primary and Secondary Mains systems at various locations, the assets are required to be altered or removed to facilitate Government Authority Work. The assets at these locations are located on Third Party land without an easement (as advised by AGLGN)79 and as such have to be altered/removed at AGLGN expense. Historically, AGLGN has incurred costs of about $0.5 million per year. More recently however, AGLGN advise that the costs associated with this work have increased significantly and are expected to escalate over the forecast period. Forecast expenditure for the period is $15.3 million (real $2005). This is a large increase from the historic position. However a single project involving relocation of the Breakfast Point Primary Main accounts for $3.7 million. AGLGN has also provided a document titled “Land Management Discussion Paper” in support of this increase. This paper is included in Appendix 2. Excluding the $3.7 million Breakfast Point Primary Mains project, the total forecast expenditure is $11.6 million. This equates to $1.9 million per annum on average. ECG has reviewed the information supplied including the Land Management Discussion Paper. It is recognised that there will be an increased level of activity over the next forecast period. However, ECG considers that the AGLGN’s forecast expenditure for

79 email in response to question AY018 040610


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Government Authority Work is higher than the amount that a would be invested by a prudent Network Operator acting efficiently in accordance with accepted good industry practice. Given the high degree of uncertainty in relation to specific projects, ECG believes that an increase of about two to three times the current level of expenditure may be more consistent with section 8.16 of the Code. For the purpose of this report, ECG considers that the prudent and efficient expenditure is 2.5 times the current level. This equates to an average of $1.3 million per annum. The total recommended expenditure is therefore $11.5 million80 including the Breakfast Point Primary Mains project.

8.5.4 Meters

Forecast meter renewal and upgrade expenditure is shown in the following table81.

Table 8-19 AGLGN Forecast Meter Capital Expenditure (Real $ million 2005)

2004/05 2005/06 2006/07 2007/08 2008/09 2009/10 Total Meters 8.4 7.8 11.0 8.2 10.9 9.5 55.8 As advised by AGLGN in the Access Arrangement Information, forecast expenditure includes $55m (real 2005) for continuation of the aged meter replacement program, assuming an extension of the current agreement with the Department of Fair Trading (DFT) AGLGN’s Stay In Business Capital Plan82 outlines the forecast meter renewal and upgrade volumes and cost by asset class as summarised in the Table 8-20. In accordance with section 8.16 of the Code, ECG has carried out an assessment of the renew/replacement program for each asset class. The results of the review are detailed below. Following its analysis, ECG has included in Table 8-20 the expenditure considered to be the amount that would be invested by a prudent service provider.

Table 8-20 Summary Table of Meter Program Detail (Real $ million 2005)

Asset Class Project/program name Forecast total AGLGN

Unit Cost $

ECG’s Recommendation

Volume Cost I&C Meters83 I&C aged meter

replacement 4915 8.6 1742 8.6

80 $11.5 million consist of $7.8 million of nominal expenditure and $3.7 million for Breakfast Point project. 81 Access Arrangement Information Dec 2003 82 Email dated 7/6/04 83 I&C Meters stand for Industrial and Commercial Meters


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Asset Class Project/program name Forecast total AGLGN Unit Cost

$

ECG’s Recommendation

I&C Meters I&C defective meter replacement

N/A 0.35 0.35

I&C Meters I&C Metretek renewal and upgrade

N/A 1.34 1.34

I&C Meters I&C Meter capacity upgrades

N/A 0.78 0.78

I&C Meters I&C Regulator replacement

4915 4.3 875 1.3

Residential Meters

Residential aged meter replacement populations

193901 26.5 137 26.5

Residential Meters

Residential gas meter statistical sampling program

7800 1.34 172 1.06

Residential Meters

Residential defective gas meter replacement

21000 2.9 137 2.9

Residential Meters

Residential homed84 gas meter replacement

2100 0.29 137 0.29

Residential Meters

Residential regulator replacement

201701 6.7 34 4.9

Residential Meters

Residential water meter replacement

10446 2.2 209 2.2

Residential Meters

Residential defective water meter replacement

2400 0.5 211 0.5

Total 55.8 50.7

8.5.4.1 I&C Aged Meter Replacement

Periodic replacement of I&C meters is necessary in order to comply with statutory requirements. The forecast unit cost of $1742/meter is considered reasonable for AGLGN’s planned mix of repaired and new meters85 and is comparable with the ESC 2002 Final Decision in Victoria of $870 - $1770/meter. ECG therefore considers that the forecast expenditure is consistent with the amount that would be invested by a prudent service provider acting efficiently. In accordance with section 8.16 of the Code, ECG recommends accepting the expenditure for the next Access Arrangement period.

8.5.4.2 I&C Defective Meter Replacement

Meters that become defective during normal service must be replaced. The expenditure is a nominal annual allowance based on a defect rate of 1.5% of the total population of I&C meters. From its industry experience, ECG considers that AGLGN’s forecast expenditure is consistent with the amount that would be invested by a prudent service provider acting efficiently.

84 “Homed” means Incorrectly Installed 85 Email dated 2/6/04


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In accordance with section 8.16 of the Code, ECG recommends accepting the expenditure for the next Access Arrangement period.

8.5.4.3 I&C Metretek Renewal and Upgrading

Forecast expenditure is associated with instrumentation fitted to large consumer meters for electronic meter reading purposes. From its industry experience, ECG considers that AGLGN’s forecast expenditure is consistent with the amount that would be invested by a prudent service provider acting efficiently. In accordance with section 8.16 of the Code, ECG recommends accepting the expenditure for the next Access Arrangement period.

8.5.4.4 I&C Meter Capacity Upgrades

Forecast expenditure is for the replacement or upgrade of meters due to customer requests associated with load changes. ECG understands that the expenditure is based on historical data. From its industry experience, ECG considers that AGLGN’s forecast expenditure is consistent with the amount that would be invested by a prudent service provider acting efficiently. In accordance with section 8.16 of the Code, ECG recommends accepting the expenditure for the next Access Arrangement period.

8.5.4.5 I&C Regulator Replacement

Forecast expenditure is based on annual quantities equal to the number of aged meter replacement. This cost makes up to 50% of the total I&C meter replacement expenditure. I&C regulators are subject to a rigorous maintenance regime as detailed in AGLGN’s Asset Management Plan 2004-2005. Maintenance of these regulators is common industry practice and any problems are normally resolved during planned or re-active maintenance While, it is also acknowledged that some regulators are subject to age related problems and may be obsolete or unserviceable. I&C regulators are not normally replaced on a periodic basis. ECG therefore believes that the AGLGN’s expenditure would not satisfy the requirement that the expenditure does not exceed the amount that would be invested by a prudent service provider acting efficiently, in accordance with accepted good industry practice. ECG has estimated that the number of regulators that may need to be replaced with the I&C meter change programme is in the range of 10% to 20%. As there is a variety of regulators in the field, the unit cost of the regulators could vary widely. ECG has therefore used the range of 10% to 20% in estimating the recommended cost. For the purpose of estimating the amount that would be invested by a prudent service provider, ECG has used the mid point i.e. 15% of the $8.6 million I&C meter change cost. This equates to $1.3 million. In accordance with Attachment A, Category 2 of the Code, ECG recommends that data gathering on regulator devices be performed during scheduled maintenance and the data used to construct actual forecasts rather than using allowance based forecasts for the next Access Arrangement review.


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8.5.4.6 Residential Aged Gas Meter Replacement

Periodic replacement or replacement of residential meters after field life extension as approved by the Department of Fair Trading (DFT) is necessary in order to comply with statutory requirements. AGLGN’s capital plan allows a total of 193,896 meters to be replaced over the period compared with a total population reaching the 15 year periodic changeover age limit of 292,667, i.e. 33% life extension. The forecast unit cost of $137/meter is based on all aged meters being replaced with a new meter. It is not clear why all residential meters are non-repairable and it is recommended that this be investigated prior to the next review. Taking this factor into account and based on an assessment of the breakdown of the $137/meter provided by AGLGN86, the forecast expenditure is considered to not exceed the amount that would be invested by a prudent service provider acting efficiently in accordance with accepted good industry practice. Consistent with section 8.16 of the Code, ECG recommends acceptance of the forecast expenditure for periodic replacement of residential meters for the next Access Arrangement period.

8.5.4.7 Residential Gas Meter Statistical Sampling Program, Defective and “Homed87” Gas Meters

This section covers the removal of meters as a result of various programs. ECG has reviewed the forecast nominal quantities and considers the quantities to be consistent with the practices of a prudent service provider. The unit cost for the statistical sampling program is $172 as compared to $137 for the other activities. No reason was provided for this difference. Based on its experience, ECG believes that there should not be any difference in the unit cost and the prudent unit cost for all activities would be $137. Consistent with section 8.16 of the Code, ECG recommends the following:

• Expenditure for Statistical Sampling Program would not satisfy the requirement that be invested by a prudent service provider. The expenditure should therefore be adjusted to reflect the unit cost of $137.

• Acceptance of the forecast expenditure for the other programs as prudent and

efficient.

8.5.4.8 Residential Regulator Replacement

Forecast expenditure in the Access Arrangement Information is based on annual quantities equal to the number of aged residential meter replacements plus the number of DFT statistical sampling program meters. It is not general gas industry practice to systematically replace all residential regulators at the time of aged meter replacement; however AGLGN has identified technical issues related to some residential regulators supplied from its Medium Pressure systems. A draft AGLGN/Agility report “Engineering Assessment: Residential Service Regulators” 88 outlines the technical issues and risk assessments conducted, and recommends further action to minimise problems and costs arising from malfunctioning regulators.

86 Email 31/5/04 87 Incorrectly Installed 88 Version 1.3 dated 11 August 2004


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The Engineering Assessment indicates that the design of regulators purchased prior to 1996 allowed water to enter or condense within the pressure control mechanism which can freeze in extended cold climate ambient temperatures and also cause corrosion of critical pressure control components. Loss of gas supply or over pressurisation of customer installations can result from either of these conditions. At about that time, a new design regulator was introduced. As such, in 1996 and 1997, all regulators installed in colder climates were replaced with the new design regulator. The Engineering Assessment indicates that while the older design (about 70% of the residential meter population) continues to remain in service in the milder climate NSW coastal zone, it is still prone to corrosion, particularly in highly corrosive environments such as beachside suburbs. AGLGN’s/Agility’s recommended action, based on its technical assessment and economic evaluation of three options, is to simultaneously replace the 70% target regulators and aged meters as part of a single program which would take 18 years to complete. Based on the information provided, ECG believes that the targeted replacement of service regulators by aligning them with the planned aged meter replacement program is a prudent action in accordance with the Code. The estimated number of regulators that require changing per year is approximately 70% of the forecast quantity of age replacement meters at the unit cost of $34 per regulator. This unit cost is the incremental cost of replacing a target regulator at the same time as the aged meter change and is considered efficient in accordance with the Code. ECG therefore recommends that the forecast expenditure of $6.7m (based on annual quantities of regulators equal to the number of aged residential meter replacements) be reduced to $4.9 million (based on a targeted program) for the next Access Arrangement period. It is further recommended that, as per Attachment A, Category 2 of the Code, AGLGN continues to record detailed information on the extent of the technical problems and this data be available for the next Access Arrangement review.

8.5.4.9 Residential Defective and Planned Water Meter Replacement

Forecast expenditure is based on 20 year replacement or when in-service faults occur. There is no programmed maintenance for hot water meters which is consistent with practices adopted by network providers in other jurisdictions. Based on a review of the breakdown of the unit cost of $209/m provided by AGLGN89, ECG considers that AGLGN’s forecast expenditure is consistent with the amount that would be invested by a prudent service provider acting efficiently. In accordance with section 8.16 of the Code, ECG recommends accepting the expenditure for the next Access Arrangement period.

8.5.5 Renewal/Replacement Expenditure Summary

The table below shows the recommended forecast renewal/replacement expenditure.

Table 8-21 Recommended Forecast Renewal/Replacement Expenditure 2005-2010 (Real $ million 2005)

2004/0590 2005/06 2006/07 2007/08 2008/09 2009/10

89 Email 31/5/04


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Mains91 (includes Sydney Primary Loop Project)

11.2 24.7 17.1 21.3 7.4 2.5

Programmed Rehabilitation 2.6 8.6 2.8 3.2 0 0 Meters 7.8 7.1 10.0 7.4 9.8 8.6 Fixed Plant 4.4 3.1 1.9 1.9 1.9 1.9 Total System Upgrades 26.0 43.5 31.8 33.8 19.1 13.0

8.6 NON SYSTEM CAPITAL EXPENDITURE

Details of the non system capital expenditure are provided in the table below.

Table 8-22 Forecast Non System Capital Expenditure 2005 to 201092 (Real $ million 2005)

2004/05 2005/06 2006/07 2007/08 2008/09 2009/10

Plant & Equipment 1.0 1.0 1.0 1.0 1.0 1.0 Motor Vehicles 2.6 1.6 3.2 3.1 2.6 1.6 IT 9.1 10.4 5.7 3.9 3.4 6.6 Access Arrangement Costs 0.0 0.0 0.0 0.0 1.2 1.7 Total Non-System Assets 12.7 13.0 9.9 8.0 8.2 10.9

8.6.1 Information Technology (IT)

The expenditure forecast is shown in the Table 8-23. AGLGN advised93 that the FRC costs has also been included in this capital expenditure and should be deducted.

Table 8-23 Forecast IT costs94 2005 to 2010 (Real $million 2005)

2004/05 2005/06 2006/07 2007/08 2008/09 2009/10 Total IT 9.1 10.4 5.7 3.9 3.4 6.6 39.1 IT capex to be deducted

0.24 0.63 0.26 0.75 0.24 0.2 2.32

Total 8.86 9.77 5.44 3.15 3.16 6.4 36.78 AGLGN advised95 that major items included in the forecast are the replacement of key IT functionality that is operating on aging legacy systems which no longer meet operating requirements.

90 The expenditure for 2004/05 is for a full year. 91 Expenditure for system reinforcement has not been included. Forecast services costs have been included. 92 Table 5.7 Access Arrangement Information (December 2003). 93 Email – 16 June 2004. 94 Access Arrangement Information Dec 2003 95 Access Arrangement Information Dec 2003


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The proposed projects96 include:

• Asset Database Management which includes a Document Management System and Geographical Information System (GIS) – total expenditure $3.2 million.

• Asset Performance and Monitoring which cover SCADA/telemetry systems – total

expenditure $4.6 million.

• Engineering design and load profiling tools- total expenditure $1.8 million. • Field Work Management, providing for work dispatching, remote work

management and emergency response- total expenditure $3.2 million. • Meter Management, covering meter reading and meter data management

systems-total expenditure $4.3 million. • IT & Systems Infrastructure, providing systems enhancement and hardware

replacement, business continuity Plan and Corporate Systems Architecture and Strategic Development – total $11.2 million.

AGLGN advised that the replacement of the SCADA host system is due to the software no longer being supportable by the IT industry. ECG has considered the business case and concurs that the SCADA system used by AGLGN is dated and requires replacement. ECG also believes that the expenditure is consistent with the amount that would be incurred by a service provider acting efficiently. In accordance with section 8.16 of the Code, ECG recommends accepting this expenditure for the next Access Arrangement period. By 2007, AGLGN is expected to be able to supply the “Sydney One Call” system with electronic plans. As such, AGLGN has to implement a GIS to be able to meet this requirement. ECG has reviewed the expenditure for this project and considers that the amount is consistent with what would be invested by a service provider acting efficiently. In accordance with section 8.16 of the Code, ECG recommends accepting this expenditure for the next Access Arrangement period. In a number of cases the proposals are driven by the need to replace legacy systems, such as GASS (Gas Accounting and Services System). This system is custom built and is becoming increasingly difficult to support. ECG has reviewed the expenditure for this project and considers that the amount is consistent with what would be invested by a service provider acting efficiently. In accordance with section 8.16 of the Code, ECG recommends accepting this expenditure for the next Access Arrangement period. In relation to other projects not listed above, AGLGN advised that the expenditure estimation can only occur when project scope and functional specification are defined in detail. Development costs are difficult to predict with certainty because of the various possibilities of using implementation outsourcing, consultation and support arrangements. Therefore the business systems capital expenditures are based on a history of development cost and expenditures. AGLGN advised that it had estimated its project expenditure using historical costs for similar projects and applied a contingency to cover any uncertainty. ECG recognises the need to replace aging legacy systems and to introduce new asset management systems. However there is insufficient information to justify the significant increase in forecast expenditure compared to the current period (from about $26.4 million to $37 million). Currently there are no business plans being prepared for a number of projects nor are there any clear offsets in the operating and maintenance expenditure

96 AGL Energy Networks 5 Year Capital Plan 2003/04-2009/10, Business Systems (Gas Networks)


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justifying the significant increase in IT expenditure. As such, ECG believes that the forecast expenditure would not satisfy the requirement that the amount does not exceed the amount that would be invested by a prudent service provider acting efficiently. As such, in accordance with section 8.16 of the Code, ECG recommends an expenditure level for projects that have already identified business needs with a small contingency for ad hoc system enhancements. This expenditure should not exceed what was the historical spending for this period. The total project cost listed above is $23.7 million. ECG therefore recommends an expenditure of $30 million which means that AGLGN has on average over $1.2 million p.a. for system enhancement. This is less AGLGN expenditure for system enhancement in the current period. However, given that the cost recommended includes the replacement of legacy system, ECG believes this is adequate for normal business operations.

8.6.2 Vehicles

As advised by AGLGN/Agility97, the purchase of Motor Vehicles is usually very cyclical in nature with their replacement generally based on a 4 year and/or 100,000 km policy. However this policy is varied for larger vehicles such as trucks and vans which often have a longer useful life depending on their use. These vehicles are not always replaced as per the forecast.

Table 8-24 Forecast Vehicle costs 2005 to 2010 (Real $ million 2005)

2004/05 2005/06 2006/07 2007/08 2008/09 2009/10 Total

Motor Vehicles 1.3 1.6 3.2 3.1 2.6 1.6 13.4 In reviewing the details of AGLGN vehicles, ECG noted that many vehicles are retained longer than the forecast four years. In particular, trucks are generally used as work platforms and driven to work sites during the day and are parked on site for most of the day. As such, these trucks are not driven long distances and would not accumulate 100,000 kms in 4 years. This situation also applies to some vans. In addition, AGLGN advised that there is no material change to current work practice, polices and quantity of vehicles proposed for the forecast period as compared to the current Access Arrangement period. ECG therefore concludes that there is no justification to increase the efficient historical cost. Based on the above, ECG believes that the proposed expenditure does not satisfy the requirement that the amount does not exceed the amount that would be invested by a service provider acting efficiently. In considering the historical costs incurred by AGLGN on vehicles, data was drawn from table 7.2 in the Final Decision 2000 and from table 5.5 in the AGLGN Access Arrangement Information. The average expenditure over the past eight years was calculated to be $1.95 million per annum. The historical expenditure of $1.95 million per annum equates to a total of $11.7 million (2005 $). In accordance with section 8.16 of the Code, ECG therefore recommends a forecast expenditure of $11.7 million for the next Access Arrangement period.

8.6.3 Other Expenditure

The two remaining items of forecast expenditure are shown below.

97 email AY 013 received on 8th June.


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Table 8-25 Forecast Other Costs 2005 to 2010 (Real $ million 2005)

2004/05 2005/06 2006/07 2007/08 2008/09 2009/10 Plant & Equipment 1.0 1.0 1.0 1.0 1.0 1.0 Access Arrangement Costs

0.0 0.0 0.0 0.0 1.2 1.7

AGLGN has forecast nominal annual expenditure for replacement of plant and equipment A list of Plant & Equipment for a 2004/05 was supplied by AGLGN98 and appeared to be typical of the items of equipment for a Gas Distribution Business. Some examples of equipment were replacement Druck pressure gauges, portable gas detectors, portable GC gas analyses equipment, etc. From the information provided by AGLGN, ECG considers that the forecast expenditure is what would be incurred by a prudent service provider acting efficiently in accordance with section 8.16 of the Code. ECG therefore recommends that the forecast expenditure be accepted for the forecast Access Arrangement period. As outlined for the current period, ECG is not in a position to confirm the prudency of AGLGN Access Arrangement costs. AGLGN advise these costs are treated as deferred expenditure and will be amortised over the period of the next Access Arrangement.

8.7 DISPOSALS

The forecast for disposals shown in the following table comprises the sale of motor vehicles (approximately $400,000 each year) and asset scrappings99.

Table 8-26 Forecast Disposals 2005 to 2010 (Real $ million 2005)

2004/05 2005/06 2006/07 2007/08 2008/09 2009/10

Disposals (2.1) (2.1) (2.1) (2.1) (2.1) (2.1)

The scrapping of assets includes mains, services, valves, regulator equipment and meters. The quantities of assets per year cannot be predicted with certainty and therefore the forecast expenditure is a nominal allowance. ECG considers based on the above and its industry knowledge that the forecast disposals have been determined in a manner expected from a prudent operator acting efficiently, consistent with good industry practice, and in accordance with the requirements of section 8.16 of the code. ECG therefore recommends the forecast disposals advised by AGLGN be accepted for inclusion in the forecast expenditure for the next Access Arrangement.

8.8 CAPITAL CONTRIBUTION

AGLGN forecast capital contributions for this period are $0.9 million pa (real $, 2005), which is the same as that forecast for 2004 in the previous Access Arrangement period. No reason has been given to why the capital contributions should be set at the 2004 level only. To reflect the fact that in other years the recovery has been in excess of the $0.9 million, ECG believes that a prudent service provider acting efficiently would use the

98 attachment to email response to questionAY011 040606 99 Email response to question AY 020 received on 16th June.


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average for the period from 2001 to 2004. ECG has calculated the average to be $1.1 million p.a. in real $ 2005. In accordance with the Code, CG therefore recommends the capital contributions accepted for inclusion in the capital base for the 2005-10 Access Arrangement period be its estimate of $1.1million pa.

8.9 RECOMMENDED CAPITAL EXPENDITURE 2005-2010

It is proposed that the capital expenditure from 2005 -2010 shown in the following table be allowed for inclusion in the initial capital base for the Access Arrangement period from 2005 – 2010. Note that for purposes of comparison with the AGLGN proposal, the system reinforcement, renewal/replacement and Sydney Primary Loop items have been aggregated to a single category. Note: Due to the extension of the current Access Arrangement period to include the period from July to December 2004, the forecast 2004/05 expenditure has been divided evenly between July to December 2004 and January to June 2005. Only the expenditure for the period January to June 2005 is included below

Table 8-27 Capital Expenditure 2005 to 2010 (Real $ million 2005)

Jan-June 05 2005/06 2006/07 2007/08 2008/09 2009/10 Market Expansion 23.2 49.0 47.4 45.9 45.6 45.4 System Reinforcement/ Renewal/Replacement

15.8100 59.9 40.2 37.4 23.2 17.1

System Reinforcement 2.8 16.4 8.2 3.5 4.0 4.1 Renewal/Replacement 12.5 29.5 18.0 16.1 14.5 13 Sydney Primary Loop 0.5 14.0 14.0 17.8 4.7 0

Non System Assets101 4.0 8.0 8.0 8.0 9.2 9.7 Total 43 116.9 95.6 91.3 78 72.2

100 The expenditure is higher than in the Access Arrangement Information due to a reinforcement project in 2003/04 being deferred to 2004/05. Refer Table 8-12. 101 FRC Costs of $2.32 million for IT has not been included as advised by AGLGN.


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9. NON CAPITAL COSTS 2000-2005

9.1 INTRODUCTION

Operating, maintenance and other non capital costs are also significant components of the revenue requirement for AGLGN. Sections 8.36 and 8.37 of the Gas Code cover the provisions related to recovery of non capital costs.

• Section 8.36 defines non capital costs as the operating, maintenance and other costs incurred in the delivery of a reference service.

• Section 8.37 states that reference tariffs may provide for the recovery of all non-

capital costs except for any costs that would not be incurred by a prudent service provider, acting efficiently in accordance with good industry practice, and to achieve the lowest sustainable cost of delivering the reference services.

The Code does not specifically outline the approach that has to be adopted to determine the efficient cost for a level of service. A possible approach would involve benchmarking AGLGN’s cost performance against that for other Australian gas distributors. A benchmarking study (Review of AGL Gas Networks Capital and Operating Expenditure, December 2003) conducted on behalf of AGLGN by Parsons Brinckerhoff and provided to the Tribunal in the context of the current Access Arrangement Review was considered by ECG as part of the process of reviewing AGLGN’s operating expenditure. The Parsons Brinckerhoff study, whilst useful for providing insight into AGLGN’s operations, was a high level review and not sufficiently detailed for the purposes of this review. For a benchmarking approach to provide the level of scrutiny demanded by this review, it would have been necessary to obtain much more detailed costing information on AGLGN’s non capital costs so that a comparison with other service providers could be made. An alternative approach would be to carry out a detailed scrutiny of the various activities associated with AGLGN’s operations to assess the prudence of operating expenditure. This would have necessitated a much more intrusive process than was possible for this review. As discussed in Section 2.7 of this report and in Appendix 1, AGLGN entered into a Management Services Agreement with Agility Management Pty Limited which commenced in July 2002. A copy of that agreement was provided to ECG for the purposes of this review. The agreement is for a 10 year term to 2012 with provision for an automatic extension of 5 years. In broad terms, it requires Agility to:

• Manage and operate the gas network as the agent of AGLGN. • Ensure compliance with all of AGLGN’s statutory and contractual obligations. • Exercise good commercial and technical practice. • Report at specified intervals on its performance. • Achieve performance targets agreed from time to time.

More information about the relationship between AGLGN and Agility is provided in Appendix 1 of this report. In accordance with the terms of that agreement, AGLGN is not provided with detailed costing information by Agility. Instead, Agility must comply with its agreed performance targets. Payment is in accordance with a schedule to the agreement which provides for specified amounts in 2002-03 and 2003-04 and for adjustment in


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subsequent years according to customer sites, volume of gas transported and an efficiency factor. The agreement also provides for a review of the scope in the event of material change and also for payment for volume changes in additional services. This means that information on the quantity of work and unit cost associated with each activity is not available. Consequently ECG assessed the non capital costs in the following manner:

• The Tribunal’s decision in the 2000 Access Arrangement was used as the starting basis for the non capital expenditure.

• Actual costs during the 2000-04 Access Arrangement period were reviewed to assess trends, anomalies and differences in the various categories.

• Categories of non capital expenditure were analysed to determine the reasonableness of the costs for the service provided.

• Where possible, costs in particular categories were compared (e.g. total operating costs) with those of other gas distribution companies in Australia.

• AGLGN’s own forecasts of costs were reviewed, together with the methods, processes and data used to derive them.

• Conclusions were then drawn about the efficient cost for the 2004 Access Arrangement period after taking into account the various components of non capital expenditure. This cost will be the starting point for establishing the non capital expenditure for 2005 to 2010.

Details of the review are provided in the sections below.

9.2 AGLGN 2000-04 NON CAPITAL COSTS

The cost reductions required in the Tribunal’s 2000 Final Decision were equivalent to 3% per annum for operation and maintenance and corporate overheads and 19% per annum for marketing. The Tribunal did not mandate to AGLGN how non capital costs should be apportioned between operation and maintenance, corporate overheads and marketing. Rather, the document set out total non capital costs to be included in the calculation of reference tariffs and identified cost categories where savings could be made. Marketing in particular was identified as an area where substantial reductions could be made. AGLGN was therefore able to spend more or less on any of the cost categories provided that the total of non capital costs was not exceeded. For the purposes of this review it was nevertheless necessary to assess the various categories of non capital costs individually because the allowable levels of expenditure in each category provided a basis for what was considered previously by the Tribunal to represent prudent expenditure. The Final Decision distinguished between “controllable” non capital costs and those which are not (or only partially) within AGLGN’s control. The latter are comprised of:

• Unaccounted for gas (UAG). • Retail Contestability costs. • Government levies.

For those cost categories not classified as controllable, mechanisms were established to allow variations in these costs to pass through to reference tariffs.


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9.2.1 Analysis of the 2000-04 Non Capital Costs

AGLGN’s actual non capital costs for 1999-2000 to 2002-03 and those forecast for 2003-04 (in nominal dollars) are set out in Table 9-1as well as those allowed in the Tribunal’s Final Decision in 2000.

Table 9-1 Non Capital Costs 1999-00 to 2003-04 (Nominal $ million)

Year Ending June 1999/2000

Actual 2000/01 Actual

2001/02 Actual

2002/03 Actual

2003/04 Forecast

Controllable Costs Operation & Maintenance 54.1 57.3 61.4 60.7 65.2Administration & Overheads 17.0 18.4 17.8 17.9 18.2Marketing 23.3 17.1 12.4 13.1 13.1Controllable Opex 94.4 92.8 91.6 91.7 96.5Other Costs Government Levies 6.4 5.3 4.4 3.8 3.8Retail Contestability 0.0 0.0 4.5 4.7 4.7UAG 10.2 8.1 6.8 7.7 8.3

Total Opex 111.0 106.2 107.3 107.9 113.3

Allowable Costs in Final Decision 2000

Controllable Costs 97.4 94.4 90.9 90.6 90.0

Total Costs 112.4 109.9 112.6 112.9 111.9

Variation of Actual Costs from Final Decision

Controllable Costs 3.0 1.6 (0.7) (1.1) (6.5)Total Costs 1.4 3.7 5.3 5.0 (1.4)

9.2.2 Operation and Maintenance Expenditure

AGLGN has stated that the distinction between operation and maintenance expenditure and corporate overheads has blurred over the years due to changes in the company structure. (i.e. AGLN and Agility) It also advised that it is not meaningful to consider time series of the two categories of expenditure because the scope of activities covered under the two categories has changed. The company has, however, provided an activity based costing analysis (ABC) for the year 2003-04 and supporting descriptive material about the individual activities. Because of the limited costing information available for this review, as discussed in Section 9.1, it has not been possible to provide an assessment of the efficiency of the absolute levels of expenditure for each activity involved. A further complication in carrying out comparative analysis of operation and maintenance expenditure is that many activities previously handled in-house are now contracted out. Table 9-2 lists the operation and maintenance and corporate overheads expenditure by year presented by AGLGN in the Access Arrangement Information converted to real 2005 dollars.


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Table 9-2 Operation and Maintenance Costs and Overheads


Year Ending June 1999/00 Actual

2000/01 Actual

2001/02 Actual

2002/03 Actual

2003/04 Forecast

Operations & Maintenance

61.8 63.6 66.2 63.5 66.7

Overheads 19.4 20.4 19.2 18.7 18.6

Total 81.2 84.0 85.4 82.3 85.3

A real increase of $4.9 million or 7.9% in costs reported under operations and maintenance (O&M) over the four years from 1999-2000 is noted. At the same time costs reported under the overheads category decreased in real terms by $0.8 million or 4.1%. The combined total increased by $4.1 million or 5%. In the same period customer numbers increased by approximately 135,000 or 17% (compared with the forecast customer increase of 14%102). A significant increase in reported O&M costs is noted between 1999- 2000 and 2001-02. A decrease occurred in 2002-03, followed by an increase in 2003-04. AGLGN has advised that costs in 2003 were approximately $2 million below normal due to some accounting adjustments including the reversal of provisions and the recognition of sundry income under-accrued in previous years ($0.6 million). The reversals relate to provisions concerning an option by Sydney Gas Company to purchase a pipeline asset ($1.0 million) and a water bath heater ($0.4 million). As AGLGN stated that it was unable, due to the nature of its contract with Agility, to provide information on the increased expenditure and the volume of work and the unit costs, ECG sought to understand the company’s current operations and maintenance practices and to make a judgement in relation to the costs associated with these activities. Some of the activities discussed with Agility were:

• Response time to emergency situations. • Backlog of planned maintenance. • Ratio of planned versus unplanned activities. • Leakage survey intervals. • Maintenance of ancillary equipment.

The information provided enabled ECG to assess how much of the work is linked to standards and how much discretion was available to Agility in aspects such as changing frequency of activities and hence the associated costs. Agility also advised that in the current period, it was meeting its response time standards and there were no material changes in activities. AGLGN provided substantial documentation relating to the management and operation of the gas network assets. For example, Agility is required under the terms of the

102 Increase in customer numbers deduced from the Final Decision 2000 Access Arrangement page 34


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Management Services Agreement to provide annually an Asset Management Plan which includes detailed operational plans. The comprehensive written information was supplemented by information provided in several discussion sessions at which Agility managers provided verbal briefing and responses to detailed questions from ECG. Another factor that was taken into consideration was the cost related to the “Gas Market Operation”. In the 2000 Access Arrangement decision, the Tribunal carried out a benchmarking comparison with distributors in other jurisdictions to form its view on the operating expenditure. AGLGN noted that it performs gas market operations in NSW whereas in Victoria, these activities are carried out by VENCorp and the Office of Gas Safety and not the gas distributors. AGLGN stated that this aspect was overlooked in the Tribunal’s 2000 Final Decision. Comparison with Victorian distributors would therefore not have considered the costs associated with the “Gas Market Operation”. AGLGN provided an estimate of $4.3 million to cover the cost of various activities it considered to fall within the scope of “Gas Market Operation”. This issue is discussed in more detail in Section 10.1.4. ECG also noted that the Parsons Brinckerhoff report showed that AGLGN’s performance to be comparable with other jurisdictions but not necessarily better than its Victorian counterparts. This is particularly relevant in relation to the following service indicators:

• Unplanned outages affecting more than 5 customers per 1000 customers. • Customers’ hours off supply. • Response to customer calls within 60 minutes.

Based on the factors outlined above and the written and verbal information provided by AGLGN/Agility, ECG believes that the gas network is operated in a safe and competent manner. To assess whether AGLGN had achieve the efficiency improvement in the Tribunal’s final decision and recognising that there is difficulty separating the costs between O&M and corporate overheads, ECG proposes to review the combined costs for these two categories. Consistent with the approach adopted by the Tribunal in the Final Decision for the current Access Arrangement, ECG believes that the impact of the increased customer numbers and demand over the forecast should be taken into consideration in the review. In order to assess the efficient level of O&M costs for the period, ECG used the methodology outlined below: The base level for 1999-00 was escalated at a rate based on actual levels of growth in customer numbers and volume of gas delivered to the tariff and contract market in each year. The escalation rate was calculated as half the average growth rate, weighted at 50% for customer numbers and 50% for load. ECG considers that using this methodology to determine incremental costs before applying an annual 3% efficiency factor meets the Code requirements (section 8.37) of establishing an efficient cost. The O&M and Overheads expenditure, adjusted for growth and productivity in accordance with the Final Decision is set out in Table 9-3.


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Table 9-3 Comparison of Actual and Adjusted Combined O&M and Overheads (Real $ million 2005)

Year ended June

2000 2001 2002 2003 2004 Total

Actual 81.2 84.0 85.4 82.3 85.3 418.2 Adjusted103 86.3 83.5 81.6 80.8 80.2 412.4 Variance -5.1 0.5 3.8 1.5 5.1

Comparing the actual to the adjusted expenditure, ECG notes that AGLGN’s actual expenditure has exceeded the adjusted amount in all but the first year. The impact of Gas Market Operations is analysed in Section 10.1.4 of this report and ECG has concluded that $3.5 million per year (real 2005) is a reasonable cost for that category. When allowance is made for the additional costs of Gas Market Operations, ECG concludes that the expenditure for O&M and Overheads is reasonable in accordance with clause 8.37 of the Code.

9.2.3 Overheads

As discussed in the previous sub-section of this report, AGLGN has stated that the distinction between operation and maintenance expenditure and corporate overheads has blurred with time. Thus, reference should also be made to Section 9.2.2 in considering this item. Insurance costs have increased markedly in recent years with factors such as the HIH collapse and the 11 September 2001 terrorist attacks having a major impact. AGLGN has provided details of actual insurance premiums paid in the years 2000-01 to 2002-03 and forecast for 2003-04. In the two years to 2002-03 the company’s total insurance expense increased by 55% from approximately $0.9 million to approximately $1.4 million. The forecast for 2003-04 prepared in late 2003 for the Access Arrangement Information anticipated a further increase to approximately $1.9 million. That forecast has subsequently been revised downwards to $1.3 million for the years 2003-04 and $2004-05. AGLGN has advised that it proposes to incorporate the revised cost in its Access Arrangement. ECG therefore considers that to reflect the lower expected insurance premiums, a more reasonable expenditure level for 2003-04 is $18.0 million (in real 2005 dollars) rather than the $18.6 million in AGLGN’s Access Arrangement Information. This is a significant reduction, representing approximately 0.5% of total non capital costs. The reduction is important because it generates a lower starting point for estimating overheads expenditure for the new Access Arrangement Period.

9.2.4 Marketing

The issue of marketing costs was extremely controversial in the process leading to the approval of AGLGN’s Access Arrangement for the current period. A number of stakeholders argued that AGLGN’s marketing costs were excessive and the Final Decision required the company to effect non capital cost reductions (inter alia) by the equivalent of 19% of marketing costs per year. The Tribunal noted that AGLGN’s marketing costs exceeded industry benchmarks. Marketing costs for the Access Arrangement Period were as set out in Table 9-4.

103 Adjusted expenditure from the final decision for increased growth and demand.


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Table 9-4 Marketing Costs for 1999-00 to 2003-04

Year ending June 1999/00 2000/01 2001/02 2002/03 2003/04 Nominal ($ m) 23.3 17.1 12.4 13.1 13.11 Real ($ m 2005) 26.6 19.0 13.4 13.7 13.41

1 Forecast It is worthy of note that the bulk of AGLGN’s marketing costs (around three-quarters) comprises incentive payments paid to gas retailers. It is up to the retailers whether these incentives are passed on to developers or end users. Some stakeholders have argued that because AGL Energy Sales and Marketing is the dominant gas retailer in NSW, such marketing costs are effectively a cross-subsidy paid to an affiliated company of the AGL group. Notably those stakeholders included organisations whose major retail focus at present is in electricity. AGLGN has argued that all customers benefit from the higher utilisation of the network that arises from the payment of these incentive payments. Each year it distributes to retailers its Marketing Rebate Policy for the coming year. A key focus of the policy is on achieving a high percentage of connections to new homes where the appliance installation costs are generally lower than for an existing home. If a new home is connected, the additional gas load is generally available for the life of the appliances and beyond because in most cases new gas appliances replace old gas appliances. A further benefit to AGLGN of connecting a new home is that the costs of reinstatement tend to be considerably lower for new homes because installation of mains and services can occur before gardens, driveways etc. are established. The role of incentive payments in achieving an acceptable level of market penetration is much more critical in the major population centres of Sydney, Newcastle, Wollongong and the Central Coast because their coastal location and consequent mild climate mean that gas is very much a discretionary fuel. Gas appliances have a higher installed cost than their electric equivalents so that the householder typically faces expenses of several hundred extra dollars if gas is to be installed (typically in the range $200-$800). Moreover, the new home market is very price sensitive. By contrast, climatic conditions and more attractive price relativities in centres such as Melbourne and Adelaide have traditionally made gas the fuel of choice for space heating and water heating. The result is that the consumer gas culture which exists in Victoria and South Australia is much weaker in NSW. In inland areas of NSW where the space heating load is greater, gas tends to be more favourably perceived by consumers, however, the barrier imposed by the higher installed cost of gas appliance remains. Incentive payments also play an important role where natural gas is connected to new areas by inducing a higher initial level of utilisation of the gas network. This important influence has been recognised in policy considerations relating to new networks proposed in Victoria where expansion had been significantly reduced in the new gas market environment. Following discussions with AGLGN about its marketing strategy and policies, ECG concluded that the provision of incentive payments is an appropriate mechanism for assisting the growth of the gas market in NSW. Initiatives aimed at cost effectively increasing network utilisation are in accordance with the Code requirements (section 8.37) for a service provider to act efficiently and minimise the average cost of gas to all consumers. AGLGN in support of its incentive payment provided its current and past rebate policy showing how the scheme has changed, making more effective use of the incentives. Upon request, AGLGN also provided detailed business case information which supported its contention that current levels of incentive payments should be maintained. The internal


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rate of return is significantly higher than that embodied in the Tribunal’s 2000 Final Decision. The level of $13.1 million (real 2005$) for marketing incentive expenditure was one of the assumptions used in AGLGN’s business case for market expansion in the new Access Arrangement period. The business case calculates cashflows which are based on the following: Further details are confidential From the information provided, the cost of the incentive payment per new customer in 2003 was approximately $320104 ($2005) and the total marketing cost per new customer is $423 per customer. ECG’s experience in other states suggests this is a prudent level of expenditure consistent with the Code requirements for a service provider to act efficiently.

9.2.5 Government Levies

Table 9-5 below compares actual government levies with those approved in the Final Decision for the previous Access Arrangement period.

Table 9-5 Comparison of Actual and Approved Government Levies Costs (Nominal $ million)

Year ended June 2000 2001 2002 2003 2004 Final Decision 6.5 6.5 6.5 6.5 6.5 Actual 6.4 5.3 4.4 3.8 3.8 Difference -0.1 -1.2 -2.1 -2.7 -2.7

The difference in the case of Government Levies is not material because it is a passthrough item and a corrective mechanism ensures that reference tariffs reflect the actual levies paid.

9.2.6 Retail Contestability

Full retail contestability was originally scheduled to commence in NSW on 1 July 2000 but was delayed until 1 January 2002. Because of uncertainty at the time of the Tribunal’s Final Decision in 2000 about how and what level of retail contestability costs should be included, these costs were removed from AGLGN’s forecasts and an automatic adjustment mechanism was provided in the decision to allow for these costs. The Final Decision stated that AGLGN may only recover through reference tariffs only those retail contestability costs:

i. that are permitted by any law relating to retail contestability in the gas industry in NSW or its implementation; and/or

104 Incentive payment cost from the ABC costing provided by AGLGN divided by the actual number of new customers.


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ii. stipulated (consistent with the Code) in a direction of the Minister for the purposes of the Access Arrangement; and/or

iii. stipulated (consistent with the Code) by any person or group of people appointed by Government or industry to inquire into or implement retail contestability in the gas industry in NSW, other than those costs, if any, that have been permitted or stipulated under (i)and (ii); and/or

iv. as verified by an independent person appointed by AGLGN as being those costs that may properly be recoverable under the Code, other than those costs, if any, that have been permitted or stipulated under (i),(ii) and (iii),

and that have not already been recovered under the Access Arrangement or otherwise. Actual costs in this category (in nominal $ million) that were incurred in the Access Arrangement period are set out in Table 9-6.

Table 9-6 Actual FRC Costs 2001/02 to 2003/04105 (Nominal $million)

2001/02 2002/03 2003/04 Total

Actual 4.544 4.733 4.6881 13.965 1 Forecast.

The cost of $13.965 million is the total FRC costs of $13.9 million shown in table 6.1 of the AAI. Appendix 5 provides details of the $13.9 million. This cost is less than the AGLGN’s forecast expenditure for the current period. A major contributor to the lower cost is because AGLGN experienced a lower churn than anticipated. As the amount is less than the audited forecast provided by AGLGN, ECG recommends accepting the cost.

9.2.7 Unaccounted for Gas (UAG)

UAG is the difference between the quantity of gas injected into the network and the total quantity withdrawn from the network over a given period. There are a number of factors that affect the quantity of UAG in a gas network, including metering accuracy, timing of meter reading and leakages through the system. In its Final Decision for the previous Access Arrangement period the Tribunal required that:

• The price paid for UAG be determined each year by means of a competitive tender.

• The allowable level of UAG is set at 2.3% of network gas throughput until 2000-01

and 2.2% thereafter. • An adjustment mechanism be included to allow for:

• Cost recovery not to exceed the allowable level for each year set by the Final Decision.

• Retention of any benefit by AGLGN where it achieves a lower UAG level than the amount set by the Final decision for each year of the Access Arrangement period.

105 Information provided by Agility


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In accordance with the Tribunal’s Final Decision, the UAG for each year has been verified by an independent auditor. AGLGN has supplied copies of the audit reports for verification of these costs. Table 9-7 below sets out details of UAG for the years 2000-01 to 2003-04.

Table 9-7 Details of Unaccounted-for Gas 2000-01 to 2003-04

(Nominal $million) Year Actual

UAG (TJ) UAG

Allowed (%)

UAG Charged

(TJ)

Price per GJ $

UAG Cost Recovered

2000-01 2081 2.3 2359 3.62 8.1 2001-02 2099 2.2 2185 3.50 (Wilton zone)

3.20 (other zones) 6.8

2002-03 2119 2.2 2173 3.78 7.7 2003-04 n.a. 2.2 n.a. 4.12 (Apr-Sep 2003)

3.87 (Oct-Jun 2004) 8.31

1 Forecast The actual UAG as a percentage of that allowable in each year of the previous Access Arrangement period for which figures are available and the amounts retained by AGLGN for UAG for the years 2000-01 to 2002-03 are displayed in Table 9-8.

Table 9-8 Unaccounted for Gas Costs Retained by AGLGN (Nominal $ million)

Year Actual as pc of

Allowable Amount retained

2000-01 88.2 1.0 2001-02 96.1 0.3 2002-03 97.5 0.2

9.3 RECOMMENDATIONS FOR 2001-04 NON CAPITAL COSTS

Non capital costs not in the controllable categories (viz. UAG, Government Levies and FRC) are recoverable on a pass-through basis, subject to independent verification procedures. ECG considers the expenditure for UAG, FRC and Government levies to be prudent in accordance with section 8.37 of the Code and recommends their acceptance for the current Access Arrangement period. ECG noted and accepted that the various Gas Market Operation functions included in AGLGN’s controllable costs were performed by VENCorp and the Office of Gas Safety in Victoria and not by gas distributors. With regard to total controllable costs, ECG noted that AGLGN had complied to date with the requirements of the 2000 Final Decision ECG therefore makes the following recommendations:

• AGLGN’s combined expenditure for O&M and Overheads should be accepted as reasonable when allowance is made for the cost of Gas Market Operations. The adjusted expenditure is the operating expenditure in the current Access Arrangement adjusted for actual growth and demand. The table below shows the actual versus adjusted expenditure.

Table 9-9 Comparison of Actual and Adjusted Combined O&M and Overheads


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Year ended June

2000 2001 2002 2003 2004 Total

Actual 81.2 84.0 85.4 82.3 85.3 418.2 Adjusted106 86.3 83.5 81.6 80.8 80.2 412.4 Variance -5.1 0.5 3.8 1.5 5.1

• Due to the reduced cost for insurance, the cost estimates for overheads in 2003-04 should be reduced from $18.2 million (nominal) to $17.6 million. This is the recommended baseline for assessing forecast costs for the period 2004-05 to 2009-10.

• Given the nature of the NSW market, and following the substantial reductions in

marketing costs that have occurred in the current Access Arrangement period, it is considered that the marketing expenditure is at an efficient level.

• Acceptance of actual expenditure for UAG and Government levies for the current

Access Arrangement period.

• AGLGN’s FRC costs should be accepted.

106 Adjusted expenditure from the final decision for increased growth and demand.


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10. NON CAPITAL COSTS 2005-2010

10.1 AGLGN FORECAST EXPENDITURE

In its Access Arrangement Information for the forthcoming Access Arrangement period AGLGN notified the forecast costs for non capital expenditure set out in Table 10-1.

Table 10-1 Non Capital Costs (Real $ million 2005)

Year Ending June 2004/05 2005/06 2006/07 2007/08 2008/09 2009/10 Controllable Costs Operation & Maintenance 61.4 61.5 62.2 62.5 62.9 63.2Administration & Overheads 18.9 19.0 19.2 19.3 19.3 19.4Market Operations 4.3 4.3 4.3 4.3 4.3 4.3Marketing 16.5 16.5 16.5 16.5 16.5 16.5Real Controllable Opex 101.1 101.3 102.2 102.6 103.0 103.4Other Costs Government Levies 3.9 3.9 3.9 3.9 3.9 3.9Retail Contestability 3.9 3.9 3.9 3.9 3.9 3.9UAG 9.1 9.1 9.3 9.3 9.4 9.5

Total Opex 118.0 118.2 119.3 119.7 120.2 120.7

10.1.1 Operating and Maintenance Expenditure

AGLGN’s forecast operation and maintenance expenditure in Table 10-1 is relatively flat over the Access Arrangement period, exhibiting an increase of $1.8 million over the five years from $61.4 million to $63.2 million. This is equivalent to a real annual increase of approximately 0.6%. On the issue of further productivity gains, ECG believes that organizations such as AGLGN and Agility (through the Management Services Agreement between the two parties) should be able to achieve continuous improvement through use of modern technology and better systems and processes. The issue is what can be considered a reasonable productivity improvement. The multifactor productivity for the Electricity, Gas and Water sector was 1.8% per annum for the period 1993-94 to 1998-99 which was a six full cycle107. In the three years following 1998-99 it has averaged -2.7% per annum over only part of the cycle108. As the recent data represents only part of the cycle, it must be used with some caution. However, the trend has some significance. It provides evidence that the major productivity gains by the gas industry in recent years have slowed dramatically and suggests that the efficiency dividend of 3% per annum required in the Final Decision 2000 cannot be sustained. Nevertheless some factors specific to AGLGN’s situation need to be considered. ECG notes that customer numbers are forecast to rise by approximately 20% from around 923,000 in 2003-04 to approximately 1.1 million by the end of 2009-10 and that this will

107 Australian Bureau of Statistics 108 Productivity Commission


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marginally increase O&M expenditure as provided for in the agreement with Agility. However, some reduction in costs is expected to arise from the continuation of the mains renewal program. This should reduce the need to pump water from mains due to in-leakage and hence reduce the number of gas leak incidents reported and requiring investigation. Similarly, the forecast major increase in residential meter replacement can be expected to substantially reduce the reported incidence of gas leaks and customer complaints. ECG also notes the major investment in upgraded IT systems which AGLGN proposes to make over the next few years. This investment should give rise to productivity improvements. Current projects include implementation of a single management system for engineering and commercial documents and implementation of a system to track and manage gas meters more effectively throughout their lifecycle. Other projects being considered include:

• Upgrading of the SAP system which covers a number of administrative areas including human resource management and budget control;

• Upgrading of systems for data validation and billing;

• Increased automation of FRC processes;

• A geographical information system;

• Upgrading of supply chain management; and

• Upgrading of financial and management reporting

Consistent with section 8.37 of the Code and taking the above factors into account ECG recommends a real cost reduction of 1.5% per annum after allowing for growth.

10.1.2 Corporate Overheads

It will be noted that the forecast administration and overheads expenditure in Table 10-1 is also relatively flat over the Access Arrangement period, exhibiting an increase of $0.5 million over the five years from $18.9 million to $19.4 million. This is equivalent to a real annual increase of approximately 0.5%. Insurance and regulation are two areas where there have been upward pressures on overhead costs over the past few years. There is now some evidence that the dramatic escalation in insurance premiums in recent years has subsided. Uncertainties arising from the HIH collapse have eased. Major initiatives against terrorism have been, and continue to be implemented, in Australia and around the world. Furthermore, the regulatory environment has stabilised somewhat over the past five years. Based on the draft report of the Productivity Commission on the Access Regime, there are strong grounds for anticipating that gas distributors’ costs associated with implementation of the pipeline access regime will reduce over the next few years. Rather than a real increase in overhead costs in the years of the forthcoming Access Arrangement period, ECG considers that in these circumstances a real reduction of 1.5% per annum is consistent with section 8.37 of the Code. ECG therefore recommends a real reduction of 1.5% per annum after allowance for the marginal increase in overheads to be expected from the forecast 20% rise in customer numbers and the growth in load.

10.1.3 Marketing Expenditure

Marketing expenditure is forecast by AGLGN to remain flat at $16.5 million in real 2005 dollars over the Access Arrangement period. This is $3.4 million above the 2002-03 level.


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A business case, requested by ECG and provided by AGLGN, demonstrated that the rationale for AGLGN’s scheme for encouraging existing gas users to switch to gas water heating. The $3 million annual cost associated with the new scheme has been included by AGLGN in the marketing cost for the forthcoming Access Arrangement period. Around 34% of existing gas customers is estimated to have non-gas hot water systems. The incentive scheme involves payment of $300 to each of the first 10,000 customers each year in this category who install gas hot water. The scheme seeks to persuade the significant proportion of the target customers who normally replace an old electric hot water system with a new electric unit to choose gas instead. Having reviewed the business case, ECG considers the assumptions to be reasonable and concludes that the forecast expenditure is prudent and efficient in accordance with section 8.37 of the Code. The business case demonstrates that the extra revenue gained from the higher throughput for the target customers significantly exceeds the initial outlay. The internal rate of return (IRR) generated is higher than the 7.85% pa pre-tax real rate of return proposed by AGLGN for the new Access Arrangement period. Further details are confidential. AGLGN successfully sought the Tribunal’s authority to use $1.3 million of funds from the Gas Customers Reserve Account to fund the scheme in winter 2004. In doing so AGLGN estimated that all tariff customers would benefit by an estimated $1.2 million through lower tariffs arising from the additional gas throughput generated.

10.1.4 Market Operations

In its Access Arrangement Information AGLGN states that it performs certain ” Gas Market Operation” functions of the type provided by VENCorp and the Office of Gas Safety in Victoria (i.e. not by the Victorian gas distributors). These activities include:

• management of load shedding; • monitoring of gas quality; • gas balancing; and • type B (industrial and commercial) appliance approvals.

The company considers that these costs were overlooked when the Tribunal established the efficient level of non capital costs in the Final Decision in 2000. The cost for Gas Market Operation is $4.3 million (real 2005$) for each year of the new Access Arrangement period. AGLGN has provided the following cost breakdown for this activity:

Table 10-2 Market Operations Costs (Real $ million 2005)

Confidential There is insufficient information available for ECG to be able to comment on the efficient costs of these various activities. However based on its industry experience, ECG


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considers the cost allocation for the Control Centre to be high and above that of a prudent service provider as required by section 8.37of the Code. AGLGN has indicated above that the two major activities not accounted for are essentially the monitoring of the gas quality and the daily nominations and balancing process. To allocate 70% of the Control Centre cost to these activities seems excessive. AGLGN does not control gas quality and can only monitor it and advise customers where any deviations from specified gas quality range may affect their operations. Liaison with transmission pipeline operators and gas producers would also be required when such excursions occur. In these circumstances, it can be expected that the gas quality monitoring would be covered by SCADA monitoring and automatically alarmed during emergency. Whilst there is more staff intervention in gas balancing, it seems unlikely that both activities would constitute 70% of the total cost of the Control Centre. ECG considers that a 50% allocation to the above activities is more appropriate with the remaining 50% allocated to activities involved in the routine operation of the networks such as monitoring of pressures and weather conditions, liaison with producers, transmission pipeline operators, major customers, and dispatching of service calls. Using 50% allocation for the control room will result in an annual operating cost of $3.5 million rather than $4.3 million. In accordance with section 8.37 of the Code, ECG recommends using $3.5 million per annum as the prudent and efficient cost for this activity.


Details of Government levies assumed in the Access Arrangement Information have been adjusted following advice from AGLGN. The Authorisation Fees have been reduced to reflect actual recent fees paid whereas the Access Arrangement Information assumed that these fees would amount to $1.7 million per year. The revised details are set out in Table 10-3 below.

Table 10-3 Government Levies (Real $ million 2005)

Year 2004/05 2005/06 2006/07 2007/08 2008/09 2009/10

Authorisation Fees 1.0 1.0 1.0 1.0 1.0 1.0 Mains Tax 2.2 2.2 2.2 2.2 2.2 2.2 Total Government Levies 3.2 3.2 3.2 3.2 3.2 3.2 Note: Authorisation Fees have been rounded.

In 1998 the NSW Government passed legislation to repeal mains tax but has not yet proceeded to make that change effective. Should this legislation be enacted, AGLGN has stated in the Access Arrangement Information that reference tariffs will fall by an amount equal to the mains tax assumed payable. In any event the item Government levies is a passthrough cost.


Table 10-4 sets out AGLGN’s forecast Retail Contestability costs109 for the years in the new Access Arrangement period.

109 FRC costs can be considered as part of operating expenditure. Given the difficulty in identifying the various cost components, it may be prudent to keep this cost separate for at least the next Access Arrangement period.


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Table 10-4 Retail Contestability Costs (Real $ million 2005)

2004/05 2005/06 2006/07 2007/08 2008/09 2009/10

Retail Contestability Costs 3.9 3.9 3.9 3.9 3.9 3.9

The above forecast of costs is based on the assumption that there will be no major changes to market rules or regulatory requirements throughout the period. AGLGN has advised that it does not provide for the further development or standardisation of B2B systems that may be required as those requirements are not yet clear. The costs of $3.9m per annum are for costs from Agility and the Corporate IT group. Agility’s cost is $2.9m and the cost for Corporate IT group is $1m. Agility’s cost can be categorised as follows:

Table 10-5 Agility’s Cost for Retail Contestability110.

(Real $ 2005)

Activity Costs ($000) Gas Balancing 183

Delivery Point Management 351 Network Billing 390

Communication and Other 663 Connections/Disconnections 702

Incremental Workload 468 Business Rules Management 114

Total 2,871

AGLGN provided detailed information regarding hours worked and cost per hour for each category. ECG considers the hourly rate charged to the work is reasonable for the type of work involved. In relation to the Corporate IT group costs, information on the percentage allocation to Network and Retail was provided. To the extent possible, ECG has reviewed the allocation and considers the allocation appropriate. ECG has also compared the above costs to the information provided to the Tribunal in making its decision on the Retail Contestability costs for the current period and believes that the cost falls within the general scope of works listed for the current period. An activity called “Gas Balancing” has also been identified in the Market Operations cost as well as FRC cost. AGLGN has advised that the cost allowance under the FRC item is due to the additional complexity of gas balancing under FRC and is additional to the cost provided for in the Market Operations item. ECG believes that there are reasonable grounds to accept the costs of $3.9 million per annum presented in the AGLGN Access Arrangement Information as being an efficient cost in accordance with the Code.

10.1.7 Unaccounted for Gas

For the forthcoming Access Arrangement AGLGN has assumed that the allowable percentage of deliveries into the network for UAG will remain at 2.2%. The amounts

110 Spreadsheet provided by Agility.


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provided for in AGLGN’s Access Arrangement Information for the period are set out in Table 10-6.

Table 10-6 Details of Unaccounted for Gas 2004-05 to 2009-10

Year UAG Cost (Real $2005

M)

UAG Assumed

(TJ)

Forecast Demand (TJ)

Implied Gas Price

(Real $2005/GJ) 2004-05 9.1 1,970 98,519 4.53 2005-06 9.1 1,974 98,690 4.52 2006-07 9.3 2,015 100,769 4.52 2007-08 9.3 2,031 101,560 4.49 2008-09 9.4 2,051 102,561 4.49 2009-10 9.5 2,073 103,674 4.49

In its Asset Management Plan AGLGN provided details of a number of further mains renewal and rehabilitation plans for the remaining 5 percent of its network which is still cast iron or unprotected steel. The relevant areas comprise:

• Warringah/Pittwater; • Smithfield/Fairfield/Liverpool; • Bathurst; • Bowral; • Maitland; • Randwick (including Daceyville & Kingsford); • Stockton; and • Kurri Kurri.

This report recommends111 that the mains renewal projects in Bathurst, Warringah/Pittwater, Smithfield /Fairfield /Liverpool and Bowral be approved as prudent expenditure in accordance with the Code. Completion of these projects will reduce a high proportion of the remaining ferrous network during the forthcoming Access Arrangement. period. This should reduce the quantity of gas leakage. As such, UAG will be largely due the timing, inaccuracies of meter readings and customer mix between contracts and domestic. ECG considers that the UAG level should be 2.2% for 2004-05 to 2005-06 and 2.1% for 2006-07 to 2009-10. In addition, ECG considers that the implied UAG gas price in the order of $4.50/GJ for the forecast Access Arrangement period is high. ECG notes the gradual increase in the number of gas producers in south-eastern Australia. It considers that the implied gas prices underlying AGLGN’s estimated UAG costs for the period to 2009-10 are somewhat higher than would be expected from a prudent service provider. ECG expects that the tendered price for UAG will be lower than that assumed lower than AGLGN due to the number of potential sources for such gas. This should result in a more competitive price. In accordance with section 8.37 of the Code, ECG recommends a price of $4.20/GJ (real 2005) to reflect the more competitive market environment.

111 See section 8.5.2


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10.2 RECOMMENDATIONS FOR NON CAPITAL COSTS FOR 2004-05 TO 2009-10

10.2.1 Operation and Maintenance

Table 10-7 sets out the levels of O&M expenditure for the period to 2009-10 which ECG considers to be prudent and efficient in accordance with section 8.37 of the Code. In determining these levels, ECG has made the following allowances to adjust for growth and productivity:

• An increase equivalent to half the average percentage increase in customer numbers and gas volumes transported.

• An efficiency improvement of 1.5% per annum.

Table 10-7 Operation and Maintenance Costs (Real $ million 2005)

2004/05 2005/06 2006/07 2007/08 2008/09 2009/10

Operation and Maintenance 61.4 61.5 62.2 62.5 62.9 63.2

10.2.2 Corporate Overheads

Table 10-8 sets out the levels of Corporate Overheads expenditure for the period to 2009-10 which ECG recommends as prudent and efficient in accordance with section 8.37 of the Code. In determining these recommended allowable costs, ECG has made the following allowances to adjust for growth and productivity: • An increase equivalent to half the average percentage increase in customer numbers

and gas volumes transported. • An efficiency improvement of 1.5% per annum.

The amounts are proposed by AGLGN in its Access Arrangement Information have been reduced by $0.6 million per year to reflect the lower insurance premiums now forecast.

Table 10-8 Corporate Overheads Costs (Real $ million 2005)

2004/05 2005/06 2006/07 2007/08 2008/09 2009/10

Corporate Overheads 18.3 18.4 18.6 18.7 18.7 18.8

10.2.3 Marketing

ECG recommends that an allowance for marketing expenditure of $16.5 million (real 2005 dollars) be provided for each year of the new Access Arrangement period. As outlined in section 10.1.3, ECG considers this level of expenditure to be efficient in accordance with section 8.37 of the Code. This is based on a continuation of the current levels of expenditure, excluding the use of the $1.3 million of funds from the Gas Customers Reserve Account but including an additional $3 million per year to finance the electricity to gas hot water incentive scheme.


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10.2.4 UAG

AGLGN historical UAG is essentially less than the 2.2% allowed for in the current Access Arrangement period. ECG believes that there is insufficient evidence to justify the UAG continuing at the current level. In addition, further improvement to the conditions of the mains, regulators and meters will improve the UAG level. Consistent with industry standards, it can be expected that the UAG should at least drop slightly. ECG therefore recommends that an allowable UAG costs should be based upon 2.1% as set out in Table 10-9 below. ECG considers this meets the efficient cost requirements of the Code (section 8.37) and further recommends that the existing passthrough mechanism be retained with AGLGN required to call tenders for the supply of UAG each year.

Table 10-9 Allowable UAG Costs 2004-2010 Year UAG

Allowable (%)

Forecast Demand

(TJ)

UAG Allowable

(TJ)

Assumed Gas Price

(Real $2005/GJ)

Allowable UAG Cost

(Real $2005M)

2004-05 2.2 98,519 2167 4.20 9.1 2005-06 2.2 98,690 2171 4.20 9.1 2006-07 2.1 100,769 2116 4.20 8.9 2007-08 2.1 101,560 2133 4.20 9.0 2008-09 2.1 102,561 2154 4.20 9.0 2009-10 2.1 103,674 2177 4.20 9.1


ECG recommends that FRC costs of $3.9 million p.a. be accepted in accordance with clause 8.37 of the Code.


ECG recommends that AGLGN’s forecast level of Government Levies costs as set out in Table 10-3 (i.e. $3.2 million p.a.) be allowed as these are passthrough costs. In the event that the NSW Government implements the legislated repeal of mains tax before the release of the Final Decision, it is recommended that the approved costs be adjusted to reflect the full reduction.

10.2.7 Market Operations

ECG recommends that an expenditure level of $3.5 million per annum (real 2005 dollars) be provided for Gas Market Operations which is consistent with a prudent service provider acting efficiently in accordance with section 8.37 of the Code.


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10.2.8 Summary of Recommendations

Table 10-10 below provides a summary of ECG’s recommendations for allowable non capital costs for the period to 2009-10.

Table 10-10 Recommendations (Real $ million 2005)

2005 2006 2007 2008 2009 2010 O&M 61.4 61.5 62.2 62.5 62.9 63.2 Overheads 18.3 18.4 18.6 18.7 18.7 18.8 Marketing 16.5 16.5 16.5 16.5 16.5 16.5 Market Ops 3.5 3.5 3.5 3.5 3.5 3.5 Total controllable 99.7 99.9 100.8 101.2 101.6 102.0 UAG 9.1 9.1 8.9 9.0 9.0 9.1 Govt levies 3.2 3.2 3.2 3.2 3.2 3.2 FRC 3.9 3.9 3.9 3.9 3.9 3.9 Total 115.9 116.1 116.8 117.3 117.7 118.2


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11. ASSET UTILISATION (REDUNDANT ASSETS)

ECG has assessed the utilisation of trunk pipelines to determine if there are grounds for reducing the capital base due to any decrease in the utilisation of pipeline assets. This is an issue of concern that has been raised by a number of stakeholders. As outlined in Section 3.3, with effect from the commencement of the subsequent Access Arrangement period, the Relevant Regulator may reduce the Capital Base by an amount representing, among other items, any assets that in the reasonable opinion of the Relevant Regulator have decreased in value because of a decrease in its utilisation resulting from a decline in the volume of sales of this Service. The Wilton-Newcastle trunk contains four pricing zones, two in Sydney plus Central Coast and Newcastle, and the Wilton-Wollongong trunk is one pricing zone. The key driver for assessing utilisation of these assets is diversified MDQ for contract and tariff loads. The contract booked MDQ’s for each pricing zone are shown in the following tables, based on forecast information in the Final Decision (2000) for year 2004 and in the Access Arrangement Information (December 2003) for years 2005-10. In Newcastle these bookings show an 8% increase in the forecast of contract MDQ from 2004, the final year of the current Access Arrangement period, to 2010, the final year for the next period. However in Wollongong the bookings show a 54% reduction in the forecast of contract MDQ over the same period.

Table 11-1 Wilton-Newcastle Demand Forecast

2003/04 2004/05 2005/06 2006/07 2007/08 2008/09 2009/10

Contract Zone A: MDQ (Booked) (GJ)

217,926 224,869 225,883 226,306 226,741 227,204 227,683

Zone B: MDQ (Booked) (GJ)

65,275 69,388 70,084 70,181 70,279 70,381 70,495

Zone C: MDQ (Booked) (GJ)

62,237 67,192 67,835 67,879 67,924 67,973 68,033

Zone D: MDQ (Booked) (GJ)

58,902 63,473 64,073 64,073 64,074 64,077 64,082

Total Customer Sites 418 398 398 398 398 398 398

Tariff

ACQ (TJ) 27,720 27,882 28,595 29,320 30,055 30,798 31,579

Customer Sites 781,364 843,320 871,389 898,424 925,337 952,086 978,748


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Table 11-2 Wilton-Wollongong Demand Forecast

This forecast information does not account for changes in contract load during 2004. AGLGN advised112 that customers have reduced or ceased to take load in the Newcastle and Wollongong areas. Therefore the contract MDQ has fallen since the preparation of the above forecast. This reduction in contract MDQ in the Newcastle area has been calculated by ECG to be about 14% of contract MDQ for zone D on the Wilton-Newcastle pipeline. The reduction in the Wollongong area is about 47% of the contract MDQ for this pipeline. The cost allocation methodology requires the asset value to be apportioned based on diversified MDQ for tariff and contract customers. No information is available to ECG on the diversified MDQ for these classes of customer. For tariff customers based on year 2010 forecasts of about 70,000 customers in each of the Newcastle and Wollongong areas, ECG has calculated this to be about 18,000 GJ/D in each location. Therefore the contract load reduction is likely to be about 10% of diversified MDQ on both pipelines.

112 Emails from Agility 10 and 11 June 2004

2003/04 2004/05 2005/06 2006/07 2007/08 2008/09 2009/10

Contract

Zone E: MDQ (Booked) (GJ)

7,908 3,824 3,786 3,749 3,713 3,677 3,642

Customer Numbers 16 19 19 19 19 19 19

Tariff

ACQ (TJ) 1,482 1,971 2,019 2,065 2,111 2,156 2,194

Customer Numbers 53,291 60,038 62,323 64,886 67,439 69,981 72,505


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Appendices


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Appendix 1

Management Services Agreement between AGL Gas Networks Ltd and Agility Management Pty Ltd113

This section is confidential

113 Management Services Agreement provided by AGLGN


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APPENDIX 2

Stakeholder Comments on cost in the AGLGN Proposals

The comments below are extracted from submissions and relate to cost issues. Submissions covered a range of other issues relating to the Access Arrangements. ENERGY MARKETS REFORM FORUM (EMRF) Summary The EMRF recommends that IPART assesses very carefully the obviously excessive capex claims for the period 2004/10. The EMRF considers that AGLGN’s proposed opex cost claims are excessive and should be reduced and that the efficiency savings factor of 3% be maintained. The EMRF considers that AGLGN’s marketing cost claims are excessive and should be subject to benchmarking against industry best practice. The EMRF recommends that AGLGN’s proposed UAG be subject to benchmarking against industry best practice. The EMRF agrees with the proposed AGLGN cost allocation methodology as it will reverse the cross subsidy provided by the contract market to the tariff market which resulted from the IPART 2000 Determination. The EMRF considers that the proposed reduction in the Sydney trunk zones, should be based on cost reflective pricing and not impede inter-basin gas competition. The EMRF recommends that metering cost claims for the contract market be required to be substantiated. IPART should investigate and seek justification for the proposed gas swap transaction charge. The EMRF makes the following observations regarding the “significant outcomes” for 2000/04 identified by AGLGN:- Despite the 13.9% increase in net customer site growth, reflecting the effects of the Sydney housing boom, capital expenditure had declined by 14.2% ($55.9 million) with the reason (according to AGLGN) being the deferral of systems upgrade and reinforcement projects. This begs the question why the relevant expenditure was deferred and whether the earlier Tribunal capex decision was excessive in the first place. This issue needs to be assessed against the background of a very substantial proposed capital expenditure claim over the next regulatory period. The decline of 2.5% in total non-capital costs is noted but surprisingly appears rather insignificant considering the very large decline in capex (of 14.2%). IPART would need to investigate why the decline in total non-capital costs is not considerably greater than 2.5% and therefore the ‘benefit’ passed back to customers.


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Capital Costs Regulatory Asset Base The EMRF has the following questions or observations relating to the proposed Regulatory Asset Base for 2005 to 2010:- The opening balance of $1.890 billion does not appear to take into account of the capex unspent in the current regulatory period. No allowance appears to have been made for redundant capital. The EMRF (which has several members in the Newcastle area) are aware of the termination of the former BHP Newcastle Steel Works and the Pasminco Cockle Creek plant in the current regulatory period. The very large proposed capex programme of $646.6 million is some 91% above the actual capex in the current regulatory period (albeit with an addition year’s data) and also sits uneasily when compared with a capex unspent of $55.9 million. Moreover, it is especially surprising (i.e. it appears excessive) given that AGLGN’s demand growth forecasts are relatively flat for both residential and business customers (the EMRF is aware of IPART’s consultant’s report on AGLGN’s demand forecasts and looks forward to revisions from AGLGN). There appears to be an absence of substantiation (other than mere listing) of the very large proposed capex programme of $646.6 million, let alone justification that the programme is prudent and efficient. Whilst it is presumed that the significant proposed increases for 2004/05 and 2005/06 are a result of the deferral of earlier projects, no substantiation appears to have been provided or even linked to the actual capex outcomes in the current regulatory period. The EMRF presumes that IPART’s consultants will be investigating these issues. Operating Costs Operating Expenditure AGLGN is proposing to reduce the 3% efficiency savings in the 2000 IPART Final Decision to 1.5% for the 2004/05 to 2009/10 period. The only justification appears to be that “it is not realistic to assume that an efficient service provider can achieve further 3% annual efficiency savings indefinitely” (AGLGN, AAI, page 36). AGLGN has made this claim notwithstanding that it is proposing a 91% increase in capex, especially in projects such as network renewals and replacement of ageing IT equipment, which if implemented would be expected to raise productivity and efficiency. Moreover, with the potential productivity gains, it would also be expected that proposed opex claims would be substantially lower than the total claimed opex of $716.5 million (or total controllable opex of $613.6 million). It is somewhat surprising that for a capital intensive business the ratio of controllable opex to capex in AGLGN’s proposed Revisions is 94.89% The EMRF considers that AGLGN’s proposed opex claims are excessive and should be reduced and that the efficiency savings factor of 3% be maintained. Marketing Costs AGLGN is proposing marketing costs of $16.5 million annually (i.e. at the 2004 level of $13.1 million plus $3 million annually for marketing promotion to convert existing gas customers to use gas for water heating). The EMRF recalls that IPART’s 2000 Final Decision significantly reduced AGLGN’s marketing costs as they were considered to be in excess of industry best practice benchmarks.


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There are serious questions as to whether AGLGN requires such large marketing costs to convert gas customers to use gas for heating. Should it not be left for gas retailers to do the promotion? Providing AGLGN with large marketing costs (16.13% of total controllable opex) effectively cross subsidises its affiliate, AGL Energy Sales and Marketing, the dominant gas retailer in NSW. The EMRF considers that AGLGN’s marketing cost claims are excessive and should be subject to benchmarking against industry best practice. Unaccounted For Gas (UAG) AGLGN is proposing UAG of $65 million or 91% of total capex costs, not an insignificant proportion of non capital costs. Again, this item should be considered against industry best practice standards. The EMRF recommends that AGLGN’s proposed UAG be subject to benchmarking against industry best practice. Metering Costs AGLGN is proposing to raise metering charges for contract customers and to reduce them for tariff customers. Metering costs have consistently increased in the current regulatory period and are again to be carried into the next regulatory period. There needs to be substantiation for such cost increases for contract customers. How is the allocation of costs between customer segments undertaken? The EMRF recommends that metering cost claims for the contract market be required to be substantiated. Market Operations AGLGN is proposing a new gas swap service to manage its gas portfolio for multiple sources/receipt points. We presume the cost of the service is $4.3 million per annum (itemized under “Market Operations”). We agree that AGLGN needs to manage its gas portfolio from multiple sources, but we have been unable to see justification for the amounts sought by AGLGN. The swap transaction charge of $0.0385/GJ appears rather high. Tribunal should investigate and seek justification for the proposed gas swap transaction charge. ORICA Capital Expenditure The capital expenditure on Metering has significantly increased every year in the current Access Arrangement. The increased costs have been carried over into the proposed Access Arrangement. The Tribunal is requested to investigate in the requirements and prudence of the proposed capital expenditure. AGLGN Net Working Capital shown in Table 5.19 forecast the working capital increasing every year from 2005 to 2010. Why is the forecast working capital growing at a faster rate compared with the forecast growth in Total Revenue?


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AGLGN is requested to provide details of the Capital Expenditure proposed for the Wilton to Newcastle Trunk. During the new Access Period a value of 11.5 million has been proposed compared to an actual of 0.7 million for the current Access Period. Where is this additional capital used and is the proposed expenditure prudent? Redundant Capital In the determination of the Regulatory Capital Base AGLGN have made no allowances for Redundant Capital for the whole AGLGN network. In any large organization you would expect some level of Redundant Capital. Orica request IPART to further investigates the Redundant Capital component of the Regulatory Capital base. In the Newcastle area there has been significant gas users such as BHP (Newcastle Steel Works) and Pasminco at Cockle Creek terminating their operations. What effect does the shutdown of these large gas users have on the Regulatory Capital Base for the Sydney to Newcastle Trunk line? If there is significant over capacity in the Sydney to Newcastle Trunk Line and this additional capacity is not forecast to be used in the proposed access arrangement, can this capacity be classified as Redundant Capital. Operating Cost The Tribunal should continue with the target of minimum 3% efficiency saving for every year of the new Access Arrangement. AGLGN have demonstrated this target was achieved in the current Access Arrangement. Additionally productivity saving opportunities must result from the proposed introduction of replacement key IT functionality at a capital cost of $39 million. AGLGN have proposed an additional operating cost of 4.3 million dollars in 2004/2005 for so called “Market Operations”, these activities are clearly part to the functions of a gas network operator. The Tribunal is requested to oppose the addition of Market Operation costs in the Operating Cost matrix. AGLGN is proposing a significant increase in Total Operating Cost for the new Access Arrangement compared to the current. IPART is requested to investigate in detail if the proposed additional spend is prudent. Unaccounted for Gas forms a significant percentage of the annual non capital costs, AGLGN have allocation $1.3 million for the Contract Segment. What is AGLGN allocation for UAG in the Sydney to Newcastle Trunk line and is this cost formulated from “activity based costing”? How is Unaccounted for Gas lost in a main high-pressure distribution line? The proposed new service Gas Swap Transaction should increase the flexibility of the network. AGLGN has been able to provide a cost for this new service but they may not have estimated the volumes and included the income in their revenue projections. ENERGY AUSTRALIA Concerns with respect to cost include significant increases in capital expenditure without any significant increases in forecast demand, nor offsetting reductions in operating expenditure; high levels of marketing expenditure compared with other distribution businesses and significant increases in metering costs for contract customers.


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Capital Expenditure In real 2004-05 dollars, capital expenditure is forecast to increase by 21% in 2004-05 and 37.7% in 2005-06, compared to a reduction of actual capital expenditure in the 2000-04 regulatory period. The capital underspend in the current regulatory period has been justified in the 2003 Access Arrangement by the deferral of a number of projects (such as the Sydney Primary Main project), reduced meter replacement and deferral of IT system replacement. However, EnergyAustralia notes that the demand forecasts for new residential customer connections and average gas usage per customer do not show a substantial increase. Therefore, IPART should be satisfied that the additional capital expenditure foreshadowed by AGLGN can be fully justified by the deferred capital expenditure. Operating Expenditure AGLGN has proposed a reduction in the assumed annual efficiency factor for controllable costs (excluding marketing) from the 3% in the Final Decision 2000 to 1.5%. This reduction was on the basis that it was not considered realistic to achieve 3% annual efficiency savings indefinitely. However, AGLGN has proposed strong growth in capital expenditure in the next regulatory period, particularly in 2004-05 and 2005-06, primarily as a result of the deferral of previous projects. Given the substantial additional capital expenditure allocated to the deferred primary main proposal ($50 million), the renewal of networks reaching the end of their economic lives ($39 million) and replacement of ageing IT equipment ($39 million), it is expected that there would be a significant offsetting reduction in maintenance expenditure associated with these assets. However, this reduction does not seem apparent in the operating expenditure figures that are forecast to increase over the next regulatory period in real terms. Marketing Costs AGLGN has proposed that marketing costs be retained at the 2004 level in real dollars (ie. $13.1 million) plus the addition of $3 million per annum to promote the conversion of existing gas customers, who do not use gas for water heating, to the use of gas water heating appliances. EnergyAustralia is concerned that this may reverse the objectives of the 2000 Final Decision, where AGLGN’s marketing expenditure was substantially reduced on the basis that it was significantly higher than industry benchmarks. Based on the proposed AGLGN figures, marketing expenditure in 2004-05 ($16.5 million in total) will represent 14% of total operating expenditure. By comparison, EnergyAustralia’s electricity network business expenditure in 2004-05 is forecast at $1.8 million, which represents 0.6% of total operating expenditure. This is a considerable difference, even if it is acknowledged that gas distribution businesses may need to promote more energy efficient appliances. As AGLGN’s gas distribution network was built before the electricity distribution network, the argument that substantial distribution marketing expenditure is necessary to entice customers away from electricity is questionable. If gas distribution network costs are substantially higher than benchmark costs for electricity distribution networks, this disparity will result in a regulatory imposed skewing of electricity and gas competition in the residential energy market.


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EnergyAustralia understands that a large proportion of AGLGN’s marketing expenditure is used to provide customer rebates for new connections to the distribution network. This expenditure may be justified by AGLGN on the grounds that the rebate is available to all retailers in the market on a non-discriminatory basis. However, the reality is that AGL Energy Sales & Marketing has been virtually the sole beneficiary to date, and is likely to remain the dominant beneficiary for the next regulatory period. Thus this high level of marketing expenditure is effectively a cross subsidy for AGLGN’s associated retail business. Therefore, EnergyAustralia believes that allowable marketing expenditure that is to be used to encourage new connections to the distribution network should be reduced significantly from the 2003-04 benchmark level of marketing costs. However, other marketing expenditure that is specifically targeted at the development/installation of new technologies that are beneficial from an environmental and/or energy efficiency perspective (such as gas chillers) should be allowable and should be a significant amount ($8 to 10 million). This would encourage greater utilisation of the existing asset in an environmentally beneficial way rather than simply encouraging expansion of the asset in a way which benefits both AGLGN and its associated retail entity. HUNTER GAS USERS GROUP Are there any costs related to stranded assets or capped or decrement customers being borne by Trunk Service customers applicable to any of transmission zones? How does AGLGN explain the proposed trunk charges into the Newcastle zone given the varying influences of decrease in forecast demand, increased contract users and the reduction in Local Network charges? ENERGY ADVICE Provision of Basic Metering Services The “Addendum to AGL Gas Networks Access Arrangement for NSW – Schedule of Prices in 2004/2005 Dollars” documented on page 10 sets out the metering equipment charges from January 2005 to June 2010. The charge rates included in the table for the period 1 January 2005 – 30 June 2005 propose a 12.8% increase on those applicable to 31 December 2004. At the 19 February 2004 presentation, AGLGN, in replying to questions regarding the large increase in Metering Charges, commented to the effect that they had to recover a block of revenue from their customers but as customer numbers had decreased, the charges had to rise to the remaining customers. The Access Arrangement Information for NSW Network – September 2000 on page 53 gives the total number of customers with an annual usage of over 10TJ as 500, while the Access Arrangement Information for NSW Network – December 2003 on page 67 advises that this customer group has dropped to 465, a decrease in customer numbers of 7%, which is roughly consistent with the statements made by AGLGN on 19 February 2004. IPART, in its Final Decision of July 2000 on pages 113-117, discusses the issue of capital redundancy and required AGLGN to maintain an asset register. IPART stated that: “In its Access Arrangement, AGLGN must include in its Reference Tariff Policy a capital redundancy mechanism that permits the Relevant Regulator, with effect from the commencement of the next Access Arrangement period, to reduce the Capital Base by an amount representing: (a) any assets that in the reasonable opinion of the relevant Regulator have ceased to contribute to the delivery of Services; …..”


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This paper contends that on the basis of AGLGN’s comments on 19 February 2004 that some of AGLGN contract customer meter stock has obviously become redundant and therefore the capital base should be reduced. The 2000 Final Decision further stated that “In assessing the reduction in the Capital Base to decreased utilisation of assets resulting from a decline in the volume of sales of a Service, the Relevant Regulator may take into account the reduction in Total Revenue and any possible increase in Tariff paid by Users resulting from the decline in utilisation of assets.” The large increase in metering charges clearly suggests that IPART needs to examine the appropriateness of retaining redundant metering assets in the capital base.


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Appendix 3

AGLGN/Agility Land Management Discussion Paper



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Appendix 4

Expenditure Approval Level (Maximum) –Guidelines (1) (2)



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Appendix 5

Reconciliation of Full Retail Contestability Costs for the Current Access Arrangement

Period Full Retail Contestability (FRC) was introduced in NSW in January 2002. At the time of the final decision for the current period, the cost for FRC was unknown and as such, the cost for FRC was excluded from the tariff and a mechanism for cost recovery was included into the final decision. In 2001, as part of the cost recovery process, AGLGN prepared a forecast capital and operating expenditure totally $21.2 million for period up to 2004. This expenditure was audited by Deloitte and then submitted to the Tribunal. Details of the capital expenditure are shown in the table below:

Nominal $ million

Up to June 2001

2001-02 2002-03 2003-04 Total

Capital 2.4 3.2 1.6 0.3 7.5 Operating 0.7 4.4 4.2 4.4 13.7 Total 3.0 7.6 5.8 4.7 21.2

The cost above included $0.74 million which had already been recovered from customers and $0.44 million for capitalisation interest. AGLGN advised that these costs were excluded from the amount that was to be recovered through the reference tariffs. The forecast expenditure that had to be recovered was therefore $20.0 million. In addition, AGLGN and the Tribunal agreed that $9.5 million from the Gas Customer Reserve Account (GCRA) will offset a proportion of the cost. A summary of the reconciliation of the cost is shown below:

$m Capital Operating Total Gross amount to be recovered

7.0 13.0 20.0

GCRA 3.3 6.2 9.5 Net amount to be recovered

3.8 6.7 10.5

However, due to the lower rate of churn, the actual FRC cost was less than that expected in 2001. Actual FRC costs incurred are as follows:

$m Capital Operating Total Actual Expenditure 7.1 10.7 17.8 GCRA 3.3 6.2 9.5 Net amount that should be recovered

3.8 4.5 8.3

From a cost perspective, the Access Arrangement Information (AAI) table 6.1 shows a non capital cost of $13.9 million. This is made up of $10.7 million in the operating expenditure and $3.2 million (shown as $3.3 million in the table above due to rounding differences). The remaining $3.8 million from the table above is shown in the AAI table 5.5 as IT expenditure. AGLGN advised that the above costs have been expensed in the current Access Arrangement period.