asset management plan (aa4) 2014-2019

Asset Management Plan (AA4) 2014-2019

DDooccuummeenntt CCooddee:: AASSTT PPLL0000001188

This document is controlled within the EIM Document Management System.

Please refer to the electronic version on EIM to confirm you have the latest version.

Title Name Date

Owner: Asset Planning Manager Tim Davies

Reviewer: Asset Services Manager Mas Marsuki 14/03/2014

Approver: Chief Operating Officer Pat Donovan 14/03/2014

DDooccuummeenntt HHiissttoorryy

Revision Date Amended By Details of Amendment

0 25/06/2012 Tim Davies New Document Created

1 31/09/2013 Tim Davies Updated with 2014 Business Plan approved projects

2 1/11/2013 Tim Davies Removed Non-RAB detail for Access Arrangement submission

3 14/03/2014 Tim Davies Finalised for Access Arrangement submission

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EEXXEECCUUTTIIVVEE SSUUMMMMAARRYY ATCO Gas Australia (AGA) owns, operates and maintains the largest reticulated natural gas infrastructure in Western Australia. The gas reticulation networks serve Geraldton, Bunbury, Busselton, Harvey, Pinjarra, Brunswick Junction, Capel and the Perth greater metropolitan area, including Mandurah. These combined networks extend greater than 13,000km, connecting about 683,000 end users to natural gas.

ATCO Gas Australia’s Gas Distribution System (GDS), covered by the Access Arrangement, operates in the Coastal gas supply areas under the conditions defined in Gas Distribution Licence 8 (GDL8). Natural Gas (NG) is distributed through the GDS from the Dampier Bunbury Natural Gas Pipeline (DBNGP) and APA Group’s (APA) Parmelia gas transmission pipeline via gate stations and Pressure Regulation Stations (PRS), designed to limit pressures in the GDS to within the Maximum Allowable Operating Pressures (MAOP) for each section of the various lower pressure networks.

AGA must provide for management of safety on the GDS via a Safety Case as required by the Gas Standards Act 1972 and Gas Standards (Gas Supply and System Safety) Regulations 2000. The safety case has been prepared to comply with the requirements of AS/NZS 4645.1: 2008 Gas Distribution Networks Part 1: Network Management and where the requirements of the following standards apply to the GDS, compliance to:

• AS2885.1: 2007 Pipelines – Gas and liquid petroleum Part 1: Design and construction • AS2885.3: 2001 Pipelines – Gas and liquid petroleum Part 3: Operations and maintenance

AGA operates and maintains its growing GDS in accordance with the Safety Case, accepted by Energy Safety, to provide safe, reliable, cost competitive, environmentally sustainable and customer friendly natural gas delivery service to AGA customers.

To enable implementation of the Safety Case this Asset Management Plan (AMP) sets out the plans, programs and strategies for the management of the network assets, presented by asset class, to meet the strategic objectives of AGA. The plan is designed to manage network assets throughout their lifecycle to deliver current and future service levels and performance targets, and to provide assurance that AGA investment in the network is prudent, efficient and appropriate to manage the risks associated with owning and operating the asset.

Levels of service to be provided by AGA in operating the GDS are grouped into those affecting customer requirements and expectations, legislative compliance, organisational and strategic objectives and the Asset Management System (AMS). Metrics are tracked to monitor the performance of these service levels and reported at appropriate intervals to the relevant interested parties. The targets for these metrics are expected to be reviewed during this reporting period along with an initiative to move towards using the KPIs suggested in AS/NZS 4645.

Demand drivers affecting the residential, commercial and industrial market segments in WA are based within two categories; new customer connections drivers and customer consumption drivers. Particular drivers for new residential connections are population and housing growth, interest rates and building codes for homes. Whereas for new industrial and commercial connections the primary driver is delivered energy cost as compared to nearest alternative. Drivers for residential consumption are weather, retail gas price, microeconomic factors, appliance efficiency and alternative energy appliances. Drivers for commercial and industrial consumption are retail gas price, micro- and macro-economic factors and appliance efficiency.

AGA is experiencing a decline in average consumption per customer, which is similar to the experience of most natural gas utilities worldwide. Also of note is that, on average, customers on the AGA Network consume less gas than those on most other Australian gas distribution networks and their usage continues to decline. The decline in usage results partly from Customers choosing competitor products, especially electricity, in greater numbers due to the:

• reduced marketing focus of gas retailers as a result of many of those gas retailers also being electricity retailers

• erosion of the natural gas space heating market share and benefits of gas given the penetration of reverse cycle air conditions in the residential market

• ongoing subsidisation of electricity prices, which the State Government has confirmed is $554 million annually

Population growth rates since 2001-02 have ranged from 1.4% to 3.3% with an average of 2.2%. Investment in major resource projects has slowed, but many projects will move into an operational phase providing stable

Document No.: AST PL00018 of 114 Revision: 3 Issue Date: 14/03/2014


medium to longer term employment. Growth is being inhibited by high living costs and poor housing affordability. Connection rates have steadily improved since the last half of 2012 and are expected to increase until June 2014 when expansion will slow to long term population growth rates of less than 2% a year.

Lifecycle management of the GDS has been divided into logical asset classes based on functional requirements, technical specifications and risk profile. Each of these major asset groups contains detailed information about the lifecycle management strategies and plans with their associated forecast capital expenditures summarised in Table 1.

Table 1: Summary of ATCO Gas Australia Network Capital Expenditure by Regulatory Asset Class

Asset Class Growth Sustaining Total ($'000s)

Gate Stations $18,961 $18,961

High Pressure Polyethylene Pipelines $1,860 $11,031 $12,891

High Pressure Steel Pipelines $62,362 $91,559 $153,921

Medium & Low Pressure Mains $52,753 $99,984 $152,737

Metering & Service Pipes $108,619 $76,568 $185,186

Regulating Facilities $2,942 $8,136 $11,079

Telemetry & Monitoring $5,051 $5,051

Total ($'000s) $228,537 $311,289 $539,827

The growth capital expenditure forecast in the table above will provide service to more than an additional 101,000 end use customers over the five and a half year Access Arrangement period. It also includes high pressure extensions to the network to ensure the secure, long term natural gas supply to the expanding North West metropolitan, Peel, Baldivis and Busselton regions as well as Elizabeth Quay.

The sustaining capital expenditure forecast is required to ensure network safety and reliability in accordance with the accepted Safety Case, and includes replacing the remaining 224km of cast iron and unprotected metallic mains and services, replacing GDS infrastructure within multistorey buildings, installing 33km of main to reinforce its GDS as well as interdependency and interconnections with transmission suppliers, to ensure sufficient and appropriate hydraulic capacity exists for reliable natural gas distribution service. In recognition of the increased risk of encroachment to buildings of public occupancy in the CBD, the Company shall reduce the operating pressure of the network in this area to mitigate the consequences of pipeline rupture.

To meet regulatory obligations, AGA will replace approximately 150,000 domestic meters that have reached their end of life over the Access Arrangement period. In addition, the Company proposes to use that routine meter change opportunity to replace non-temperature compensated meters with temperature compensated meters as part of its overall strategy to improve metering accuracy for customers and to focus efforts to reduce unaccounted for gas (UAFG). The total cost of the routine meter change program is forecast at $30M and the incremental cost of installing temperature compensated meters with this program is approximately $575,000.

Table 2 summarises the forecast capital growth and sustaining expenditure. 2014 has been split into halves due to the change from fiscal year reporting to calendar year reporting in the upcoming Access Arrangement so that the second half of 2014 can be added to the upcoming five and a half year access arrangement.

Table 2: Summary of ATCO Gas Australia Network Capital Expenditure by Category

CAPEX Category 2H 2014 2015 2016 2017 2018 2019 Total ($'000s) GROWTH CAPEX $18,715 $39,203 $51,814 $42,645 $41,457 $34,704 $228,537

Customer Initiated $15,677 $28,724 $27,766 $27,742 $28,173 $28,232 $156,314

Demand $3,038 $10,479 $24,048 $14,903 $13,283 $6,472 $72,224

SUSTAINING CAPEX $17,718 $42,007 $51,532 $64,149 $63,295 $72,589 $311,289

Asset Replacement $15,182 $33,025 $29,101 $29,872 $35,398 $35,110 $177,687

Network Safety and Performance $2,536 $8,982 $22,431 $34,277 $27,897 $37,479 $133,603

Total ($'000s) $36,433 $81,210 $103,346 $106,794 $104,752 $107,292 $539,827



Table 3 below shows the forecast operating expenditures for the Access Arrangement period. “Projects – non-recoverable” reflects forecast project expenditures for the operations, maintenance and inspection of the AGA’s reticulated natural gas network in accordance with its Safety Case and its AMP. Examples of activities included in the cost category would be inline inspections of high pressure pipelines, vegetation clearance, safety awareness and Dial Before You Dig (DBYD) Programs and includes other support type costs including communications, fleet, property, training and health, safety and environment. The “Variable volume” category reflects forecast expenditures for operations and maintenance activities that result from routine maintenance and inspection, and customer requests and notifications. Examples of activities included in this cost category are leak survey, asset inspections, associated maintenance, leak repairs, customer requests, no gas calls, reported gas escapes, etc.

AGA routinely conducts formal safety assessments in accordance with its Safety Case, on various elements of its network. Formal safety assessments have identified additional network operating requirements including:

• Increased leak survey frequency, documentation and categorisation.

• Updated work procedures and documentation to ensure and document compliance and safe operation.

• Increased inspection of prescribed activity on the GDS.

• Comprehensive training on updated work procedures and documentation including field assessment.

• Additional resources to address growth and network footprint, and end use network connections.

• In-line-inspection of high pressure steel pipelines to assure safe, reliable operating condition.

• Provision of natural gas safety information to the public.

• Improved condition assessment of AGA’s buried plastic gas mains and services.

Table 3: Summary of ATCO Gas Australia Operational Expenditure

OPEX Category 2H 2014 2015 2016 2017 2018 2019 Total ($'000s)

Projects - non recoverable $1,194 $2,304 $2,126 $2,038 $1,935 $1,908 $11,504

Variable volume activities $4,365 $8,533 $8,824 $9,386 $9,596 $9,765 $50,468

TOTAL ($'000s) $5,559 $10,837 $10,950 $11,424 $11,531 $11,673 $61,972

While AGA’s AMS and AMP are robust, all systems, plans and approaches are reviewed for continuous improvement. Due to the complexity of and risk associated with the GDS, AGA requires a strategic asset management framework that supports the safe, reliable, efficient and effective delivery of natural gas service in the long term interests of customers. Standards for asset management are ever evolving, particularly in 2014 with the release of the ISO 5500X suite, that specify the requirements of an asset management system. With the alignment of its AMS to ISO 55001, the Company intends to achieve its strategic objectives through processes that promote improvements to the safe, effective and efficient management of its assets.

To realise the full benefits of this standard through prudent investment in the network in the long term interest of customers and through the implementation of its Safety Case, areas of improvement have been identified for implementation over the 2014-2019 AA period. In the Company’s forecast it has identified data refinement and systems required to optimise the sustainable management of GDS assets, whilst minimising overhead expenses to achieve this objective.



TTAABBLLEE OOFF CCOONNTTEENNTTSS

1. Introduction ................................................................................................ 11

1.1 Background ........................................................................................................... 11

1.1.1 Purpose of the Plan ........................................................................................................ 11

1.1.2 Relationship with other Planning Documents ............................................................. 12

1.1.3 Infrastructure Assets Included in the Plan .................................................................. 12

1.1.4 Infrastructure Asset Classes Included in the Plan ...................................................... 13 1.1.5 Network Physical Parameters ....................................................................................... 15

1.1.6 Key Interested Parties in the Plan ................................................................................. 22

1.1.7 Organisation Structure................................................................................................... 23

1.2 Goals and Objectives of Asset Ownership ......................................................... 25

1.3 Plan Framework .................................................................................................... 26

2. Levels of Service ........................................................................................ 28

2.1 Customer Research and Expectations................................................................ 28

2.2 Legislative Requirements ..................................................................................... 29

2.3 Strategic and Corporate Goals ............................................................................ 30

2.4 Asset Management System .................................................................................. 31

2.5 Asset Programs to Improve Levels of Service ................................................... 33

3. Future Demand ........................................................................................... 35

3.1 Demand Drivers .................................................................................................... 35

3.1.1 Alternative Technologies ............................................................................................... 35

3.1.2 Climatic Conditions ........................................................................................................ 36

3.1.3 Population Growth .......................................................................................................... 38

3.2 Demand Forecasts ................................................................................................ 38

3.2.1 Population Growth .......................................................................................................... 38 3.2.2 Housing Design and Appliance Technology ............................................................... 38

3.2.3 New Connections Forecast ........................................................................................... 39

3.2.4 Residential Lot Activity .................................................................................................. 39

3.3 Demand Impact on Assets ................................................................................... 41

3.4 Demand Management Plan .................................................................................. 43

3.4.1 Planning Objectives ....................................................................................................... 43

3.4.2 Network Planning Assumptions ................................................................................... 44

3.4.3 Domestic Diversified Unit Load .................................................................................... 44 3.4.4 Localised Load Allocation ............................................................................................. 45

3.4.5 Peak Winter Modelling ................................................................................................... 45

3.5 Asset Programs to Generate and Meet Future Demand .................................... 45

3.5.1 Operational Depots and Training Centre ..................................................................... 45



3.5.2 Forecast fleet capital expenditure ................................................................................ 48

3.5.3 Plant and equipment ...................................................................................................... 49 3.5.4 Jandakot Warehouse Redevelopment .......................................................................... 50

3.5.5 Natural Gas Refuelling Infrastructure and Vehicles ................................................... 50

3.5.6 ATCO Natural Gas Kitchen ............................................................................................ 51

3.5.7 Growth Financial Forecast for Non-Network Capital Expenditure ............................ 52

4. Lifecycle Management Plan ...................................................................... 53

4.1 Pipelines, Mains and Services Lifecycle Management Plan ............................. 53

4.1.1 Future Demand ............................................................................................................... 53

4.1.2 Operations and Maintenance ........................................................................................ 60

4.1.3 Renewal/Replacement .................................................................................................... 60 4.1.4 Network Safety and Performance Improvement ......................................................... 65

4.1.5 Asset Class Financial Forecast ..................................................................................... 67

4.2 Pressure Regulating Facilities Lifecycle Management Plan ............................. 70

4.2.1 Future Demand ............................................................................................................... 70


4.2.3 Renewal/Replacement .................................................................................................... 72

4.2.4 Network Safety and Performance Improvement ......................................................... 72 4.2.5 Asset Class Financial Forecast ..................................................................................... 75

4.3 Metering Facilities Lifecycle Management Plan ................................................. 76

4.3.1 Future Demand ............................................................................................................... 76



4.3.4 Network Safety and Performance Improvement ......................................................... 78 4.3.5 Asset Class Financial Forecast ..................................................................................... 79

4.4 Cathodic Protection Systems Lifecycle Management Plan ............................... 80

4.4.1 Future Demand ............................................................................................................... 80



4.4.4 Network Safety and Performance Improvement ......................................................... 81


4.5 Telemetry Equipment Lifecycle Management Plan ............................................ 82

4.5.1 Future Demand ............................................................................................................... 82



4.5.4 Network Safety and Performance Improvement ......................................................... 83


5. Forecast Summary ..................................................................................... 86

5.1 Financial Projections ............................................................................................ 86



5.1.1 Capital Expenditure ........................................................................................................ 86

5.1.2 Operational Expenditure ................................................................................................ 87

5.2 Key Assumptions Made in Financial Forecasts ................................................. 89

6. Plan Improvement and Monitoring ........................................................... 90

6.1 Monitoring and Review Procedures .................................................................... 90

6.2 Implementation Plan ............................................................................................. 90

6.2.1 Information and Communication Technology Improvements ................................... 91

7. Definitions .................................................................................................. 98

8. References .................................................................................................. 99

9. Appendices ............................................................................................... 101

9.1 Appendix A – Geographical Locations of Gas Distribution Networks ........... 101

9.2 Appendix B – GDL8 Licence Performance Reporting Indicators and Trends 105

9.2.1 Customer Connections ................................................................................................ 106

9.2.2 Gas Consumption ......................................................................................................... 107

9.2.3 Leaks .............................................................................................................................. 107 9.2.4 Network Reliability ........................................................................................................ 108

9.2.5 Complaints .................................................................................................................... 108

9.2.6 Call Centre Performance .............................................................................................. 109

9.2.7 Network Construction .................................................................................................. 109

9.2.8 Guaranteed Service Level (GSL) Payments ............................................................... 110

9.3 Appendix C – Network CAPEX Projects ............................................................ 111



TTAABBLLEE OOFF FFIIGGUURREESS Figure 1: Supporting Documents for Asset Management Plan ................................................................................. 12

Figure 2: Overview of GDS Asset Classes ................................................................................................................ 14

Figure 3: Age Profile of Mains by Material Type ........................................................................................................ 19

Figure 4: ATCO Gas Australia's Upper Level Organisational Structure .................................................................... 23 Figure 5: ATCO Gas Australia's Network Infrastructure Organisational Structure .................................................... 24

Figure 6: The Asset Management Plan Framework .................................................................................................. 27

Figure 7: 2013 Metropolitan Peak Load Profile ......................................................................................................... 37

Figure 8: EDD Weather Variation .............................................................................................................................. 38

Figure 9: ATCO Gas Australia Network Throughput ................................................................................................. 42

Figure 10: Proposed location of the new depots ....................................................................................................... 46 Figure 11: Classroom delivery hours ......................................................................................................................... 48

Figure 12: Two Rocks Spurline.................................................................................................................................. 55

Figure 13: Peel Spurline ............................................................................................................................................ 56

Figure 14: Baldivis Spurline ....................................................................................................................................... 57

Figure 15: Capel to Busselton Reinforcement ........................................................................................................... 58

Figure 16: Elizabeth Quay and CBD Risk Reduction ................................................................................................ 59 Figure 17: Remaining Lengths of Mains in Service during Metallic Mains Replacement Program ........................... 62

Figure 18: Coastal North Metropolitan Distribution Network Map ........................................................................... 101

Figure 19: Coastal South Metropolitan Distribution Network Map ........................................................................... 102

Figure 20: Coastal Northern and Goldfields Distribution Network Map ................................................................... 103

Figure 21: South West Distribution Network Map .................................................................................................... 104



TTAABBLLEE OOFF TTAABBLLEESS Table 1: Summary of ATCO Gas Australia Network Capital Expenditure by Regulatory Asset Class ........................3

Table 2: Summary of ATCO Gas Australia Network Capital Expenditure by Category ...............................................3

Table 3: Summary of ATCO Gas Australia Operational Expenditure ...........................................................................4

Table 4: Sub-networks of the GDS Coastal Supply Area .......................................................................................... 13 Table 5: ATCO Gas Australia HP Sub-Networks ...................................................................................................... 15

Table 6: GDS Pipe Materials and Pressure Ratings ................................................................................................. 16

Table 7: Operating Pressure Ranges for Network System ....................................................................................... 17

Table 8: Pipelines, Mains and Services Physical Parameters (Excluding Albany and Kalgoorlie Network) ............. 17

Table 9: Key Interested Parties in the Asset Management Plan ............................................................................... 22

Table 10: Strategic Objectives Levels of Service ...................................................................................................... 30 Table 11: Performance Measures for Network Level AMS Levels of Service ........................................................... 32

Table 12: Asset Projects to Improve Health & Safety................................................................................................ 33

Table 13: Asset Projects to Improve UAFG Performance ......................................................................................... 34

Table 14: Asset Projects to Improve SAIFI ................................................................................................................ 34

Table 15: Asset Projects to Improve KPI-11 - Isolation Valves not Operational ....................................................... 34

Table 16: New Connections Forecast from Economics Consulting Services ........................................................... 39 Table 17: Developer land release intentions in 2014 ................................................................................................ 40

Table 18: Forecast Lots to be released by Developers over Next Ten Years ........................................................... 40

Table 19: Weather Adjusted A1 Gas Usage .............................................................................................................. 43

Table 20: Cockburn Cement Natural Gas Usage ...................................................................................................... 43

Table 21: Diversified Unit Load on Severe Winter Using 2012 Peak Winter Actuals................................................ 45 Table 22: Forecast capital expenditure on operational depots and training centre: 2014 to 2019 .......................... 46

Table 23: Forecast fleet capital expenditure .............................................................................................................. 49

Table 24: Forecast of fleet by type ............................................................................................................................ 49

Table 25: Forecast plant and equipment capital expenditure .................................................................................... 50

Table 26: Fleet, Plant and Equipment Required to meet Demand ............................................................................ 52

Table 27: New Services Costs ................................................................................................................................... 54 Table 28: New Mains Costs ....................................................................................................................................... 54

Table 29: Replacement Quantities for Metallic Mains Replacement Program .......................................................... 61

Table 30: Critical HPRs Requiring Support ............................................................................................................... 66

Table 31: Summary of Pipelines, Mains and Services Expenditure .......................................................................... 67

Table 32: Regulator Sets to be Upgraded ................................................................................................................. 70

Table 33: Set Pressure Upgrades ............................................................................................................................. 71 Table 34: Forecast Capital Expenditure - Regulating Facilities ................................................................................. 75

Table 35: Quantities of Meters to be replaced under RMC Program ........................................................................ 76

Table 36: Quantities of Meters to be replaced under CMC Program ........................................................................ 77

Table 37: Quantities of Meters to be replaced under M6WA Meters with Plugs Program ........................................ 77

Table 38: Forecast Capital Expenditure - Metering Facilities .................................................................................... 79

Table 39: Summary of Telemetry Equipment Expenditure ........................................................................................ 85



Table 40: Capital Expenditure Summary by Category .............................................................................................. 86

Table 41: Capital Expenditure Summary by Asset Class .......................................................................................... 87 Table 42: Operational Projects Expenditure Summary ............................................................................................. 88

Table 43: Variable Volume Operational Expenditure ................................................................................................ 88

Table 44: OPEX Projects ........................................................................................................................................... 88

Table 45: Technology Projects Required to Support Asset Management Systems .................................................. 96

Table 46: Reference Documentation Affecting the Asset Management Plan ........................................................... 99

Table 47: Performance Measures for ERA Licence Performance Levels of Service .............................................. 105 Table 48: ERA Licence Performance Reporting - Customer Connections.............................................................. 107

Table 49: ERA Licence Performance Reporting - Gas Consumption ..................................................................... 107

Table 50: ERA Licence Performance Reporting - Leaks ......................................................................................... 108

Table 51: ERA Licence Performance Reporting – Network Reliability 1 ................................................................. 108

Table 52: ERA Licence Performance Reporting - Complaints ................................................................................ 108

Table 53: ERA Licence Performance Reporting - Call Centre Performance .......................................................... 109 Table 54: ERA Licence Performance Reporting - Network Construction ................................................................ 109

Table 55: ERA Licence Performance Reporting - Guaranteed Service Level Payments ....................................... 110



1. Introduction This Asset Management Plan (AMP) provides an overview of the major elements of the network assets within the ATCO Gas Australia’s (AGA) Gas Distribution System (GDS) and is supported by its Asset Management System (AMS).

1.1 Background

1.1.1 Purpose of the Plan

This AMP sets out the plans, programs and strategies for the management of the network assets, presented by asset class, to meet the requirements of the National Gas Law (NGL), National Gas Regulations (NGR) and the provision of efficient, safe, reliable, natural gas distribution service in the long term interest of customers. The plan is designed to demonstrate the suitability of network assets for current and future service levels and performance targets, and to provide assurance that ATCO Gas Australia’s investment in the network is prudent and appropriate to manage the risks associated with owning and operating the asset.

The AMP documents the asset management practices for each major asset class and is utilised as part of an overall lifecycle management strategy for ATCO Gas Australia’s GDS. ATCO Gas Australia’s Network Management strategic objective is “to plan, construct, operate and maintain a reliable network for the long term” and is underpinned by sound safety and risk management principles.

Maximising asset utilisation and minimising life cycle costs through well-managed maintenance and capital investment programs contributes to achieving this objective. Implementation of the GDS Safety Cases continues to enhance safe management of these assets.

The overall objective of the AMP is to document how ATCO Gas Australia intends:

To manage ATCO Gas Australia’s gas distribution system for the long term by planning, constructing, operating and maintaining the assets so as to provide a reliable system, delivering gas safely, efficiently and economically to agreed service levels, complying with regulatory requirements while achieving sustainable returns for shareholders.

In addressing this objective, the AMP:

• identifies the levels of service required for the network

• sets network-level lifecycle asset management objectives, strategies and targets that promote continual improvement in the delivery of safe, reliable and efficient gas supply to customers in a manner compliant with the accepted Safety Case and relevant legislative and regulatory requirements

• outlines activities, action plans and works programs, optimised and prioritised by risk, to deliver the objectives and targets

• describes risk management practices for the ongoing identification and assessment of asset management related risks and to identify and implement appropriate control measures

• ensures investment in lifecycle activities are prudent and efficient based on a whole of life approach

• monitors and measures the performance and condition of the assets and the implementation of the AMP

This plan looks ahead for five years over the next Access Arrangement period and has regard to where assets are within their lifecycle. Based on the long term trends and depending on consumer demand growth, it is likely that new projects will be added and some planned projects will change over the five year period of the plan.



1.1.2 Relationship with other Planning Documents

ATCO Gas Australia maintains an extensive list of internal documents that collectively support ATCO Gas Australia’s holistic approach to managing its assets, which is described in its Asset Management System. A map illustrating the documents/document parts that support the AMP is shown in Figure 1.

Figure 1: Supporting Documents for Asset Management Plan

ATCO Gas Australia has developed an annually reviewed Asset Management Policy in alignment with the requirements of ISO 55001. AMS documents have also been developed and/or revised to implement the Policy.

1.1.3 Infrastructure Assets Included in the Plan

ATCO Gas Australia’s GDS covered by the Access Arrangement, operates in the Coastal gas supply areas under the conditions defined in Gas Distribution Licence 8 (GDL8). Natural Gas (NG) is distributed through the GDS from the Dampier Bunbury Natural Gas Pipeline (DBNGP) and APA Group’s (APA) Parmelia gas transmission pipeline via gate stations and Pressure Regulation Stations (PRS), designed to limit pressures in the GDS to within the Maximum Allowable Operating Pressures (MAOP) for each section of the various lower pressure networks. An overview of the configuration of the GDS is shown in Figure 2.

The GDS covers the following geographical areas:

• Covered Pipelines:

• Perth metropolitan area (including Barter Road, Ellenbrook, Mandurah and Rockingham)

• Muchea, Eneabba and Geraldton

• Pinjarra, Harvey, Kemerton, Bunbury and Busselton

Geographical representations of the networks are illustrated in Appendix A – Geographical Locations of Gas Distribution Networks.

Levels of Service

Legislative Requirements

Lifecycle Management Planning

ACP – Pipelines, Mains and Services

Corporate Business Plan

Asset Management Policy

Demand Analysis

Asset Management Plan

Network Performance Review

Seasonal Load Factor Review

Domestic Diversified Load Study

Asset Replacement Strategy

Network Maintenance Strategy

Network Planning Strategy Network Operating Strategy

Network Monitoring Strategy

Operational Business Plan

ACP – Metering Facilities

ACP – Pressure Regulating Facilities

ACP – Cathodic Protection Facilities

ACP – Telemetry Equipment

Customer Research

Financial Management Planning

AMS/AMP Improvement Planning

CAPEX Works Programme

OPEX Works Programme

AMS Audit Reports

Strategic Targets

New Mains/Connections Forecast



1.1.3.1 Coastal Supply Area

NG from the DBNGP and the Parmelia gas transmission pipeline are metered through gate stations owned and operated by DBP and APA respectively. The custody transfer points mark the commencement of the GDS where responsibility is assumed for safety and reliability of its downstream distribution systems by ATCO Gas Australia. The GDS distributes NG to supply domestic, commercial and industrial consumers, throughout the Perth metropolitan area and various town centres.

The coastal supply area also covers a number of discrete sub-networks, extending from Geraldton in the north, to Busselton in the south as listed in Table 4. These sub-networks are not necessarily continuous or interconnected, but each is associated with at least one physical gate point marking the boundary between the GDS and either the DBNGP or APA pipeline.

Table 4: Sub-networks of the GDS Coastal Supply Area

Metropolitan Sub-networks Non-metropolitan Sub-networks

Ellenbrook Geraldton

North Metropolitan Eneabba

South Metropolitan Muchea

Barter Road Pinjarra

Rockingham Harvey

Kemerton

Bunbury (Clifton Road) including Busselton

The Mandurah Gas Lateral (MGL) PL83, consists primarily of a buried HP gas pipeline located in the Mandurah region, south of Perth, Western Australia. The MGL pipeline route commences at an underground tie-in point on the downstream outlet of a new DBNGP gate station near the intersection of Hopeland Road and Readheads Road, North Dandalup and terminates at PRS015. The PRS is located within a fenced compound, at kilometre point KP7.05 south of Readheads Road in an area subdivided from the Murrayfield Airport, in Nambeelup.

1.1.4 Infrastructure Asset Classes Included in the Plan

The GDS has been divided into logical asset classes, of which an overview is illustrated in Figure 2. These asset classes are based on asset class functional requirements, technical specifications and risk profile.



Figure 2: Overview of GDS Asset Classes

The GDS in each of these areas has been divided into major asset classes that include:

• Distribution Pipelines, Mains and Services

• Steel Pipelines with MAOP’s between 3,600 and 10,200kPa (Class 600 High Pressure)


• Steel Pipelines with MAOP’s of 1,920kPa (Class 150 High Pressure)

• Steel Pipelines with MAOP’s of 700kPa (Class 125 High Pressure)

• Steel Mains with MAOP’s of 350kPa (Class 125 City High Pressure)



• Polyethylene Pipelines with MAOP of 500 – 700kPa (HP PE)

• Polyethylene Mains and Services with MAOP of 350kPa (PEHP)

• Mains and Services with MAOP of 100kPa (Medium Pressure (MP))

• Mains and Services with MAOP of 7kPa (Medium-Low Pressure (MLP))

• Pressure Reduction Facilities

• Pressure Reducing Stations (PRS)

• High Pressure Regulator (HPR) sets

• Medium Pressure (MP) regulator sets

• Metering Facilities

• High Pressure meter sets

• Low pressure meter sets

• Domestic metering facilities

• Telemetry Equipment

• Cathodic Protection

1.1.5 Network Physical Parameters

The HP GDS is supplied from the Dampier to Bunbury Natural Gas Pipeline (DBNGP) and Parmelia gas transmission pipeline through various gate stations as listed in Table 5. Through PRSs, the pressure is reduced to the Class 150 pressure system to provide supply to HP system, Fremantle HP (FHP) system, Polyethylene High Pressure (PEHP) systems, Medium Pressure (MP) systems and the City High Pressure (CHP) system.

Table 5: ATCO Gas Australia HP Sub-Networks

HP Sub- Network Supplying Gate Stations

Metro HP Caversham Gate Station (DBP)

Della Rd Gate Station (DBP)

Harrow Rd Gate Station (DBP)

Harrow Rd Gate Station (APA)

Welshpool Gate Station (DBP)

Forrestdale Gate Station (DBP)

Russell Rd Gate Station (DBP)

Rockingham HP Rockingham Gate Station (DBP)

Mandurah Gate Station (DBP)

Pinjarra HP Pinjarra Gate Station (DBP)

Barter Rd HP Barter Rd Gate Station (DBP)

Harvey HP Harvey Gate Station (DBP)

Bunbury HP Clifton Rd Gate Station (DBP)

Geraldton HP Nangetty Gate Station (DBP)



HP Sub- Network Supplying Gate Stations

Eneabba HP Eneabba Gate Station (DBP)

Kemerton HP Kemerton Gate Station (DBP)

Ellenbrook HP Ellenbrook Gate Station (DBP)

Kalgoorlie PEHP Kalgoorlie Gate Station (APA)

In general, the types of facilities used in each network (and sub-network) are organised according to:

• pressure rating

• materials of construction

• gas feed type (i.e. NG or LPG)

The nominal operating pressures of pipelines, their MAOPs and their materials of construction are provided in Table 6.

Table 6: GDS Pipe Materials and Pressure Ratings

Material Type Specification Current Maximum

Allowable Operating Pressure (MAOP) [kPa]

Normal operating pressure range [kPa]

High Carbon Steel

Class 600

3,600

1,800 - 4,000

5,700

6,900

8,480

10,200

Class 300 3,600

1,800 - 4,000 5,010

Steel Class 150 1,920 1800 - 1900

Class 125 700 150 - 700

High Density Polyethylene (HDPE)

PE100 SDR11 700 150 - 700

PE100 SDR 13.6/ 17/ 17.6 350 2 - 350

PE63 350 2 - 350

Medium Density Polyethylene (MDPE)

PE80 SDR11 650 350 - 650

PE80 SDR13.6/ 17/ 17.6 350 2 - 350

unplasticised Poly-Vinyl Chloride (uPVC) AS 1464 Type 2 100 2 - 60

Galvanised Iron Class 125 7 2 - 7

Cast Iron Class 125 5 2 - 5



The nominal operating pressures of the various pressure categories within the GDS are provided in Table 7.

Table 7: Operating Pressure Ranges for Network System

Pressure Category Operating Pressure [kPa]

TP Transmission pressure 1800 - 4000

HP High Pressure 350 - 1900

HP PE High Pressure PE 350 - 700

CHP City High Pressure 160 - 200

PEHP PE High Pressure 60 - 350

MP Medium Pressure 15 - 601

MLP Medium Low Pressure 4 - 7

LP Low-pressure 2 - 5

Table 8: Pipelines, Mains and Services Physical Parameters (Excluding Albany and Kalgoorlie Network)

Type Operating MAOP

Length [km] Material Length [km] [kPa]

Transmission Class 300 / 600 HP 3,600 - 10,200 163 Steel 163

HP Pipelines Class 150 1920

673 Steel 570

Class 125 700 HP PE100

700 PE 103 SDR11 Pipeline

Distribution Mains

CHP 350 56 Steel 17 PE 39

PE HP 350 1,223 PE 1,223

MP Main 100 7,184

PVC 5,859 PE 1,257

Steel 68 Galvanised

0.15 Iron

MLP Main 7 3,670 PVC 3,541 Steel 65 PE 60

1 Limited by bagging off equipment for sizes 155mm PVC and above.



Type Operating MAOP Length [km] Material Length [km]

Galvanised 2

Iron Cast Iron 2

LP Main 1.5 185

PVC 78 Steel 48

Cast Iron 27 Galvanised

22 Iron PE 10

Total 13,154

1.1.5.1 Mains Age Profile

The age profile of ATCO Gas Australia’s pipelines, mains and services are shown in Figure 3. The age profile of the network ranges from 0 to 98 years old with an average network age of around 25 years. The age profile for Galvanised Iron (GI), Cast Iron (CI), Unprotected steel (STU) and Poly-vinyl chloride (PVC) pipes were estimated by trending growth suburbs between 1915 and 1995 using maps from WA Department of Planning and suburbs historical information from WA Land Information Authority2. Using this historical information, the earliest mains installation period by suburbs was estimated. Cast iron, galvanised iron and unprotected steel (either bare or coated) were used up to and including the 1960s. PVC was used extensively from 1960s to 1995 and was gradually reduced by introduction of PE from 1995 onwards. The age profile of Polyethylene (PE) was based on installation dates from ArcFM/GNIS while Protected Steel age profile was based on date of completion (approximate) contained in the physical parameters register for HP steel pipelines.

2 Reference:- 1. Perth River Front map 1930

2. Supply Services -Service Areas map 1955

3. Supply Services - Mains and Installation 1955

4. Urban Land Availability map 1955 – 1970

5. Land for Urban (Residential) Use 1955-1989

6. Metropolitan Regional Scheme 2000

7. Western Australian Land Information Authority. "History of metropolitan suburb names".



Figure 3: Age Profile of Mains by Material Type

1.1.5.2 Steel Pipelines with MAOP’s between 5,010 and 10,200kPa (Class 600 High Pressure)

The GDS includes sections of steel pipelines with a MAOP of greater than 5,010kPa and, for the current configuration of the GDS, up to 10,200kPa (Class 600 HP). NG is fed from various physical gate stations connected to the DBNGP, Parmelia gas transmission pipeline or GGP through Pipeline ‘laterals’ to either an end use consumer, or to other Mains and Services via PRSs. There are approximately 151km of these coated steel pipelines ranging in diameter from 50 - 350mm.

1.1.5.3 Steel Pipelines with MAOP’s between 1,920 and 5,010kPa (Class 300 High Pressure)

The GDS includes steel pipelines with a MAOP of greater than 1,920kPa and, for the current configuration of the GDS, up to 5,010kPa (Class 300 HP). NG is fed to these sections of the GDS from various physical gate stations connected to the DBNGP, Parmelia gas transmission pipeline or GGP through ‘laterals’ to either an end use consumer, or to other Mains and Services via PRSs. There are approximately 12km of these coated steel pipelines ranging in diameter from 100 - 150mm.

1.1.5.4 Steel Pipelines with MAOP’s of 1,920kPa (Class 150 High Pressure)

These include all sections of the GDS of steel construction designed with a MAOP of 1,920kPa (Class 150 HP). There are approximately 524km of these coated steel pipelines ranging in diameter from 50 - 350mm.

1.1.5.5 Pipelines with MAOP’s of 700kPa (Class 125 High Pressure)

These include all sections of the GDS of steel construction designed with a MAOP of 700kPa (Class 125 HP).

The ATCO Gas Australia FHP Network is a section of the South Metropolitan sub-network of the GDS with a MAOP of 700kPa which feeds the Fremantle Business District and an area extending from North Fremantle to Spearwood in the south, and east to Booragoon. The



FHP network consists of approximately 40km of predominantly coated steel pipelines, in diameters ranging from 80 - 450mm with some 160 and 225mm Polyethylene (PE).

In total there are approximately 569km of coated steel pipelines with MAOPs of 700 or 1,920kPa operating in the GDS, ranging in diameter from 50 - 350mm, and fed via laterals and PRSs, to end use consumers and/or regulators sets.

1.1.5.6 Mains with MAOP’s of 350kPa (Class 125 City High Pressure)

The ATCO Gas Australia CHP network is a section of the North Metropolitan sub-network of the GDS which feeds the Perth Central Business District (CBD), West Perth, East Perth, Northbridge and Highgate areas. It has a MAOP of 350kPa and currently operates via several regulator sets at pressures between 160 - 200kPa. The City Block section consists of approximately 39km of mains of predominantly coated steel construction in diameters ranging from 80 - 150mm, and some 63mm and 110mm diameter PE. Services connected to these mains are a mix of steel, stainless steel and PE. The North Perth and Northbridge sections consist of approximately 56km of PE and steel mains of diameter varying from 40 - 110mm. Services connected to these mains are predominantly PE.

1.1.5.7 Polyethylene Pipelines with MAOP of 500 – 700kPa (HP PE)

PE pipelines also operate in parts of the GDS with a design MAOP of 650 or 700kPa (HP PE). There are approximately 83km of PE100 pipelines feeding regulator sets supplying gas to PE mains.

1.1.5.8 Polyethylene Mains and Services with MAOP of 350kPa (PEHP)

There are various PE sections of the GDS which operate between 100 - 350kPa, fed from either regulator sets or PRSs to end use consumers. These include the Ellenbrook and Busselton sub-networks and several other smaller areas. The GDS has a total of approximately 1158km of these mains and services in diameters ranging from 18 - 225mm. These pipes are either PE80 or PE100 with SDR 11/ 13.6/ 17 or 17.6.

1.1.5.9 Mains and Services with MAOP of 100kPa (Medium Pressure (MP))

Sections of the GDS are fed from one or more regulator sets at an operating pressure of between 15 – 40kPa. There are approximately 7,140km of these mains and services ranging in diameter from 18 – 635mm. These mains and services are predominantly of uPVC construction (~82%) with some steel (~1%), and PE (~17%), mains and services also operated at these pressures.

1.1.5.10 Mains and Services with MAOP of 7kPa (Medium-Low Pressure (MLP))

Sections of the GDS are fed from one or more regulator sets operating at pressures between 2 - 7kPa. There are approximately 3,676km of these mains and services, constructed almost entirely uPVC (~96%), with diameters ranging from 18 – 330mm. There are also some PE sections.

1.1.5.11 Mains and Services with MAOP of 1.5kPa (Low Pressure (LP))

Sections of the GDS are fed from one or more regulator sets operating at a pressure of 1.5kPa. There are less than 184km of these mains and services with diameters ranging from 18 - 330mm, and constructed from: PVC (~42%), steel (~27%), cast iron (~15%), galvanised iron (~12%) and PE80 SDR17 (~4%). A large amount of the cast iron and galvanised iron currently operating at this pressure is being replaced as part of the Cast Iron Relay Program.

1.1.5.12 Isolation Valves

Isolation valves are installed on High Pressure (HP) and Low Pressure /Medium Pressure (LP/MP) pipelines and mains to stop the flow of gas for maintenance or safety purposes. Operationally reliable isolation valves are critical to facilitate effective means of isolation



during an emergency and mitigate the risks associated with leaks. An isolation valve and associated fittings shall be fit for purpose in providing sectional isolation as described in AS4645 Gas Distribution Networks Part 1: Network Management 4.9.2.

There are approximately 2,498 main isolation valves in the GDS, of which 851 are on HP mains while 1,647 are on LP/MP mains. The GDS consists of various sizes of HP main isolation valves ranging from 50mm to 250mm. In the event of pipeline emergency, sections of the network may require isolation in order to rectify the problem while minimising the potential impact to safety, network integrity and continuity of gas supply to the lower pressure networks. LP/MP main isolation valves in the network ranges from 40mm to 225mm in sizes.

Out of 851 HP main isolation valves, 256 are for line use while 595 are either for branch or blowdown uses. HP main isolation valves in the GDS are predominantly of steel material (90%). The 1,647 LP/MP main isolation valves consist mainly of PVC type valves totalling 804 (50%) and steel type valves totalling 359 (20%).

1.1.5.13 Service Valves

Service valves are installed on mains off-take to stop the flow of gas to the connected consumer’s service for maintenance or safety purposes. The service valve and associated fittings shall be fit for purpose in providing isolation of services as described in AS4645 Gas Distribution Networks Part 1: Network Management 4.8.7.

There are approximately 15,588 services valves in ATCO Gas Australia’s GDS, of which 5,357 are plastic service valves. Plastic service valves have been extensively used in the gas distribution network since the introduction of Poly-Vinyl Chloride (PVC) pipes in 1965.

1.1.5.14 Metering Facilities

HP meter sets provide gas flows within prescribed pressure range and metering accuracy generally to industrial consumers. They facilitate pressure regulation and the measurement of the supply of gas to a consumer from a HP network. HP meter sets have an inlet pressure greater than 350kPa. Most high pressure meter sets are not critical assets. A HP meter set typically consists of a working and a stand-by stream comprising of pipework, spool pieces, valves, filters, regulators and meter. The meters are generally of diaphragm, rotary and turbine type construction. All HP meter sets have over pressure protection and are progressing towards all including a slam shut valve.

LP meter sets provide gas flows within prescribed pressure range and metering accuracy generally to all commercial consumers and to some small and medium size industrial consumers. They facilitate pressure regulation from inlet pressure less than 350kPa and the measurement of the supply of gas to a consumer from the lower pressure networks. Low pressure meter sets are not critical assets. For the purpose of this plan, meter sets are those with diaphragm meters larger than AL30. A LP meter set typically consists of a working and bypass stream comprising of pipework, spool pieces, valves, filters, regulators and meter. The bypass stream is locked closed and only operated and monitored when the working stream is being serviced. The meters are generally of diaphragm and rotary type construction. LP meter sets with inlet pressure above 7kPa have over pressure protection in the form of active monitor regulator configuration as well as regulator with in-built over pressure shut off valve.

The GDS contains more than 670,000 domestic metering facilities with a standard domestic meter. These facilities supply gas from the PEHP, MP, MLP and LP networks to consumers. The majority of domestic meters installed on the GDS are 2 litre cyclic capacity diaphragm meters. They have been proven through empirical results and demonstrated by their longevity, accuracy retention and in-service performance to have a life of 25 years. Domestic meters are not critical assets.

Due to the large quantities of meters in service, a listing has not been made in this document. NMIS maintains the current list and is considered the “database of truth” for meters and meter sets.



1.1.5.15 Regulating Facilities

PRS are critical assets that allow the safe pressure regulation of gas from a higher variable inlet, to a lower set outlet pressure, controlled within a specified pressure interval for the full design flow range. They are supplied from the various laterals and transmission pipelines with an outlet pressure greater than 1,000kPa supplying gas to the high pressure networks.

A PRS will typically consist of a filter, inlet and outlet isolation valve, and a single active regulating stream with active monitor regulators and associated pressure sensing equipment. All PRS have a standby stream identical to the active stream. PRS are also often fitted with pressure relief devices and over pressure protection, which is either incorporated in the regulator design or performed by separate safety elements.

The GDS has 16 PRS supplying gas into the high pressure distribution networks. Some of these PRS are monitored for flow and pressure data via telemetry. The average age of the PRS is 18 years.

These PRS are distributed across the network and located above ground in secured compounds with cyclone mesh fencing and locked access gates. To avoid unauthorised valve closures, which can lead to loss of gas supply to large number of consumers, all important valves are locked in the required position.

HPR sets allow safe pressure regulation of gas from a higher variable inlet to a lower set outlet pressure generally with an inlet pressure greater than 500kPa and an outlet pressure greater than 15kPa, with a few sets with an outlet pressure greater than 5kPa. They are supplied from the HP network to supply gas into the PEHP, MP and MLP distribution networks. Some HPR, especially those supplying gas to discrete networks are critical assets.

A HPR typically consists of a filter, inlet and outlet isolation valve, and an active regulating stream with a regulator and associated pressure sensing equipment. Some regulator sets are also fitted with pressure relief devices and over pressure protection, which is either incorporated in the regulator design or performed by separate safety elements. All HPR sets have twin streams, with the majority on a twin stream active monitor configuration for reliability and to facilitate maintenance.

MP regulator sets are used for pressure regulation from PEHP and MP networks to supply gas into the MLP distribution network. MP regulator sets have an outlet pressure less than 7kPa and an inlet pressure less than 350kPa. MP regulator sets are not critical assets.

A MP regulator set typically consists of inlet and outlet isolation valve, and a single working regulating stream with active monitor regulator and associated pressure sensing equipment. MP regulator sets are predominantly smaller units that are installed in underground pits. The majority of these sets are of single stream active monitor configuration in integrated networks and can be shut down during maintenance. The newer sets have a filter with a single active regulator and slam shut valve.

1.1.6 Key Interested Parties in the Plan

The plan recognises the following key interested parties:

Table 9: Key Interested Parties in the Asset Management Plan

Interested Party

Key Responsibilities within Plan

Retailers ATCO Gas Australia customers are gas retailers Alinta Sales Pty Ltd, Premier Power, Synergy, APT, Kleenheat and other new entrant retailers. The gas retailer’s domestic, commercial and industrial customers are in turn the ‘gas users’. Gas retailers require efficient and reliable gas supply along with efficient processes for interfacing with ATCO Gas Australia.

Gas consumers Gas consumers demand economical, reliable and safe gas supply. The plan has a focus on maintaining customer satisfaction and levels of service.

Employees Employees require a safe working environment, a sense of identity with the asset they work on, fair pay and conditions and engaging work that adds value.



Interested Party

Key Responsibilities within Plan

Regulators The key regulators are the Economic Regulation Authority, EnergySafety and Department of Mines and Petroleum. Regulators require economic efficiency and prudent investment in the network along with safe management of the network delivering high levels of service to end users in compliance with all applicable legislative requirements.

Shareholders The Board of Directors approve the Asset Management Plan as part of the Business Plan and Budget each year. Shareholders require a sustainable return on investment while ensuring the risks of the asset and business are managed resulting in a reliable gas distribution network delivering gas safely and efficiently to the community.

Other Parties Contractors, suppliers and third parties require a safe network to work on or in the vicinity of, clear scopes of work or specifications and fair contractual terms.

1.1.7 Organisation Structure

ATCO Gas Australia has an effective organisational structure in place to execute the Asset Management Plan as illustrated in Figure 4. Network Infrastructure organisational structure is illustrated in Figure 5.

Figure 4: ATCO Gas Australia's Upper Level Organisational Structure

The organisation is divided into the following departments:

• Regulatory Affairs is engaged in economic regulatory compliance activities, quality and strategic risk management

• Marketing & Business Development is engaged in commercial contracts, corporate and strategic planning, land management, retailer billing, gas haulage, generic gas marketing and management of customer relationships



• Human Resources is engaged in recruitment, personnel and industrial relations activities and management of HR policies and procedures

• Finance engages in financial management functions

• Commercial Services provides legal support and expertise to help ATCO Gas Australia ensure regulatory and operational objectives are carried out in compliance with the law

• Information Technology develops and delivers ATCO Gas Australia’s IT strategy, and manages the delivery of IT services from an external provider ATCO I-Tek

Figure 5: ATCO Gas Australia's Network Infrastructure Organisational Structure

• Network Infrastructure is accountable for the following activities:

• providing strategic direction for the ATCO Gas Australia’s GDS expansion, reinforcement, operation and maintenance

• providing operational engineering and technical support, project planning and administrative functions, together with engineering management

• designing ATCO Gas Australia’s GDS extensions and relocations



• day-to-day construction, control, operation and maintenance of the ATCO Gas Australia’s GDS

• pursuing compliance with technical regulatory requirements

• development and monitoring of the Safety Case, auditing of performance of systems and processes, and compliance with legislative requirements

• emergency response management

1.2 Goals and Objectives of Asset Ownership The ATCO Gas Australia Business Strategy has been set across functional areas based on a critical analysis of the needs of the Company and its pathway into the future. The strategy document is available in the Corporate Affairs section of the Intranet.

Our Vision – “To provide a safe, reliable, cost competitive, sustainable, customer friendly, natural gas service.

Our Purpose – “To provide natural gas delivery service as effectively and efficiently as possible in the long term interests of our customers and shareowners.”

Our Guiding Principles:

• Excellence – “Going far beyond the call of duty. Doing more than others expect. This is what excellence is all about. It comes from striving, maintaining the highest standards, looking after the smallest detail and going the extra mile. Excellence means caring. It means making a special effort to do more.”

• Safety is a core value and fundamental to our business

• Our decision-making approach is underpinned by sound risk management, information integrity and compliance

Our Values:

• Integrity - We are honest and ethical, and treat others with fairness, dignity and respect.

• Transparency - We are clear about our intentions and communicate openly.

• Collaboration - We work together, share ideas, and recognise the contribution of others.

• Accountability - We make good decisions, take personal ownership of tasks, are responsible for our actions, and deliver on our commitments.

• Perseverance - We persevere in the face of adversity with courage, a positive attitude, and a fierce determination to succeed.

• Entrepreneurship - We are creative, innovative, and take a measured approach to opportunities, balanced with long term perspective.

• Caring - We care about the safety and wellbeing of our customers, our employees and their families, our communities and the environment.

Our Objectives:

Network Infrastructure - “We plan, construct, operate and maintain a reliable network for the long term.”

• Enable timely decisions on asset replacement



• Ensure expansion investment is viable

• Drive maximum performance of the asset

• Manage operational risk

Financial Sustainability - “We manage our business and invest in our assets to achieve sustainable returns to meet shareholder expectations and deliver cost competitive natural gas service in the long term interests of our customers.”

• Profitable management of the day-to-day operations

• Operating sustainably within our regulatory framework

• Value adding, cost competitive natural gas delivery services to end use customers

People - “We have the right people in the right jobs, at the right time, focused on the right priorities.”

• Workforce planning

• Guaranteed skills pipeline

• Employer differentiation

• Establish good corporate reputation

• Provide good customer service

Growth - “Defend and grow the throughput of gas across the network.”

• Expanding existing natural gas technologies

• Introducing new applications of gas fuelled technologies to WA

• Marketing gas solutions

1.3 Plan Framework This AMP describes the common factors and issues, such as strategic direction, growth/demand factors, and asset management activities affecting the GDS as a whole. The key elements of the AMP include:

• Description of the GDS

• GDS levels of service

• Future demand

• Asset lifecycle summaries

• Financial summary

• Plan for improvement and monitoring

A visual representation of the key elements of the AMP is illustrated in Figure 6.



Figure 6: The Asset Management Plan Framework

Due to the complexity of the network, individual lifecycle management plans have been developed to document in detail each of the asset classes’ lifecycle activities. The key elements include:

• Asset class description

• Asset class risk management plan

• Asset class routine operations and maintenance plans

• Asset class renewal/replacement plan

• Asset class disposal plan

Organisational Drivers & Objectives

Interested Parties Wants & Needs

Safety Case Requirements

Levels of Service

Regulatory and Formal Safety Assessments

Performance Measures

Physical Parameters, Cost, Performance and Asset Condition Data

Maintenance & Operations Engineering / Projects

Financial Assessment

Defines measures and targets

Informs Consequences Com

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2. Levels of Service The main purpose of this section is to clearly define the levels of service that are proposed and confirm the basis of the levels of service to be provided.

2.1 Customer Research and Expectations Market research is conducted to identify consumer perceptions and expectations across a number of various targeted demographics and market segments. The market research methods used include, but are not limited to, dedicated focus groups, telephone flash polls and online surveys. The research provides both a baseline of the current consumer understanding on the various topics, but also a measurement of the efficacy of marketing communications and promotions undertaken by ATCO Gas Australia.

The main objectives covered by such market research include consumer perceptions on the following:

• Basic attitudes and understanding of Gas vs. Electricity

• Other sources of Energy / Green Energy

• The role of gas in the overall energy mix

• The benefits of gas

• The appeal of an all gas household

• Inhibitors to connecting to natural gas versus other options

• Drivers for consumers to switch to natural gas

• Types of incentives that would attract customers to connect to natural gas

• Rising energy costs and impacts on gas usage

• Developments in the energy market

• The appeal and evaluation of both new gas appliance technologies, such as gas air conditioning, local power generation from gas fuel cells, as well as mature technologies that are underutilised in WA such as gas dryers and gas ovens

• Awareness of ATCO Gas Australia

• Understanding of consumer gas safety messages

• General costing platforms for Gas (volume discounts, maintenance fees)

The results of these focus groups are used to inform marketing strategies and other corporate decisions.

The primary customers for ATCO Gas Australia are the gas retailers, but direct contact with end use gas consumers is still made. To ensure quality of service with the end use gas consumers at an operational level, consumer satisfaction surveys are undertaken on a weekly basis to monitor customer satisfaction and the reasons for any dissatisfaction with the levels of services provided to customers. The Call Centre conducts these surveys and consumers are selected randomly.

As part of ensuring that ATCO Gas Australia has provided a satisfactory level of service, an internal customer satisfaction survey for faults is also carried out on a weekly basis. The aim of this survey is to identify any issues or concerns that consumers may have encountered, either when getting the gas connected or after reporting a fault. As a result of this feedback, the necessary improvement processes are initiated to address any negative comments to maintain and/or improve ATCO Gas Australia's level of service to customers. The survey results are distributed on a weekly basis to the Stakeholder Relations Coordinator and reported monthly to Management. Results are maintained within the Asset Management System KPI suite.

The ATCO Gas Australia Call Centre was awarded the Silver Medal – Outstanding Customer Service Excellence in the Small Enterprise or Division of Business at the 2013 National Customer Service Excellence Awards. Maintaining this high level of service is desired to continue in the Call Centre’s strive for Excellence.



2.2 Legislative Requirements Third party access to gas infrastructure is regulated in Australia under the National Gas Law (NGL). In Western Australia, the NGL has been adopted as uniform legislation with some specific amendments to accommodate local circumstances. The amended NGL is applied in Western Australia (WA) under the National Gas Access (WA) Act 2009 (NGA). The NGA also provides for the following subsidiary legislation in Western Australia:

• The National Gas Access (WA) (Part 2) Regulations 2009

• The National Gas Access (WA) (Local Provisions) Regulations 2009

• The National Gas Rules (NGR)

As the Mid-West and South-West Gas Distribution Network is a covered pipeline under the NGL, ATCO Gas Australia must submit an Access Arrangement for the pipeline services and certain ancillary services to the Economic Regulation Authority (ERA). The ERA is responsible for the economic regulation of the gas transmission and distribution networks and enforcing the NGL and NGR in Western Australia.

A Gas Distribution Licence (GDL8) has been issued by the ERA under the licensing scheme in the Energy Coordination Act 1994 for the operation of ATCO Gas Australia’s GDS. This licence requires ATCO Gas Australia to comply with a range of obligations prescribed by this Act and its associated regulations and codes:

• Energy Coordination (Customer Contracts) Regulations 2004

• Energy Coordination (General) Regulations 1995

• Energy Coordination (Higher Heating Value) Regulations 2008

• Energy Coordination (Last Resort Supply) Regulations 2005

• Energy Coordination (Licensing Fees) Regulations 1999

• Energy Coordination (Ombudsman Scheme) Regulations 2004

• Energy Coordination (Retail Market Schemes) Regulations 2004

• Energy Coordination Regulations 2004

• Gas Marketing Code of Conduct 2008

A licence requirement of GDL8 is to provide to the ERA specified information in relation to the licence. In accordance with this requirement, the ERA requires annual performance reporting of the indicators identified in section 16.2 of the ERA Gas Compliance Reporting Manual. This manual sets out the reporting categories to monitor the required level of service of the operation of the gas network. These categories are:

• Customer Connections

• Gas Consumption

• Leaks

• Network Reliability

• Complaints

• Call Centre Performance

• Network Construction

Table 47 describes the indicators required for licensing purposes by the ERA and trends of these performance measures are shown in Appendix B – GDL8 Licence Performance Reporting Indicators and Trends.

EnergySafety operates within the WA Government Department of Commerce and carries out technical and safety regulation of gas activities throughout Western Australia, including the activities of gas distribution



licence holders. The Gas Standards Act 1972 and the Gas Standards (Gas Supply and System Safety) Regulations 2000 is the legislation governing gas distribution and includes the requirement for ATCO Gas Australia to operate within a Safety Case regime. Gas installation work is principally regulated by the Gas Standards (Gasfitting and Consumer Gas installations) Regulations 1999, which provides for licensing of gas fitters and authorisation holders. Authorisations meet the requirements of the Gas Standards Act 1972 by licensing supervising gas fitters to be responsible for supervised gas fitters who may not be licensed and are frequently people such as electricians or coded welders.

All gas work must be carried out in accordance with the requirements of the Gas Standards Act 1972 and supporting Regulations, which are:

• Gas Standards (Gas Supply and System Safety) Regulations 2000

• Gas Standards (Gasfitting and Consumer Gas Installations) Regulations 1999

A requirement of this Act is that AGA must provide for management of safety on the GDS via a Safety Case. As per the requirements of the regulations, the Safety Case identifies:

• The measures necessary to “prevent hazardous events identified in the safety case from occurring”

• The measures necessary “to protect consumers, the public, employees, plant, equipment and the environment, should such events occur”.

• “The training and equipment requirements necessary for personnel to be able to implement the various procedures set out in it”.

The safety case has been prepared to comply with the requirements of AS/NZS 4645.1: 2008 Gas Distribution Networks Part 1: Network Management and where the requirements of the following standards apply to the GDS, compliance to:

• AS2885.1: 2007 Pipelines – Gas and liquid petroleum Part 1: Design and construction

• AS2885.3: 2001 Pipelines – Gas and liquid petroleum Part 3: Operations and maintenance

Each year, the ERA publishes the Annual Performance Report for Gas Distributors, which provides transparency to the public of the legislative levels of service provided.

There are no targets set by the ERA for these indicators. The results are used for benchmarking purposes only.

All projects identified in this AMP are designed to maintain compliance to or increase implementation performance of the Safety Cases.

2.3 Strategic and Corporate Goals Table 10 indicates the performance measures for the levels of service prescribed by several of the key strategic objectives. Currently, not all strategic objectives are measured and are to be revised as the sophistication of the AMP increases.

Table 10: Strategic Objectives Levels of Service

Strategic Objective Activity Measure Current

Target Desired Target 2009 2010 2011 2012 2013

Accurately measure consumption and allocate cost of the network

UAFG UAFG Rolling 12 Months % (4mths lag)

<2.9% <2.9% 2.94% 3.08% 2.78% 2.89% 2.60%

Back Office / Market Interface

% reads collected on time

>98.0% >98.0% 99.70% 99.90% 99.60% 99.90% 99.98%

Minimise Operational

Health & Safety

LTI (ATCO Only) 0 0 1 1 3 4 2



Strategic Objective Activity Measure Current

Target Desired Target 2009 2010 2011 2012 2013

Risk LTI: Contractors <1 0 2 1 0 0 2

Lost Days: (ATCO Only) 0 0 6 10 8 121 159

Lost Days: Contractors <12 <12 3 2 0 0 3

LTIFR 0 0 7.0 3.8 3.3 6.2 5.6

Public Safety

Network Incidents <27 <27 22 23 10 20 16

Notifications or Directives from ESD

0 0 0 0 0 0 1

Network Integrity

Network Performance

Breaks Response >95.0% >98.0% 99.9% 99.7% 99.7% 99.7% 99.6%

Number of Broken Mains per 100km main (rolling 12 months)

<2.5 per 100km main

<2.5 per 100km main

1.35 1.46 0.90 1.03 1.00

Number of Broken Services per 100 consumers (rolling 12 months)

<0.25 per 100 consumers

<0.25 per 100 consumers

0.21 0.21 0.18 0.18 0.17

Leaks per km (rolling 12 months)

<0.1 <0.1 0.042 0.066 0.050 0.079 0.072

Public Reported Escapes per 100km main (rolling 12 months)

<1 per km main

<1 per km main 0.64 0.74 0.72 0.70 0.65

SAIFI <0.003 <0.003 0.0040 0.0033 0.0034 0.0039 0.0050

Customer Service

Customer Complaints <50 <50 36 37 35 30 25

Ombudsman Cases <1 <1 0 4 0 0 1

% Customer Satisfaction >97.0% >98.0% 99.1% 99.4% 99.0% 99.1% 98.5%

New Connections established on time

>92.0% >98.0% 98.6% 99.5% 99.8% 99.3% 100%

From a continuous improvement perspective, these targets will be updated during the course of the upcoming Access Arrangement.

2.4 Asset Management System Performance measures defined in the AMS are used to monitor the service levels of the assets within the GDS and are shown in Table 11. Current trends indicate the GDS is robust and performing well.



Table 11: Performance Measures for Network Level AMS Levels of Service

KPI KPI Title Parameters Current Target

Desired Target 2009 2010 2011 2012 2013

Pipelines

1 Damage to a HP pipeline

Instances per 100km of main <1 <1 0 0 1 2 0

2 Damage to a MP/LP Pipeline

Instances per 100km of main <3 <3 2.70 1.47 0.64 1.11 1.14

3 Main Defects Defects per 100km of mains <20 <10 6.50 7.41 6.10 8.04 7.16

4 Damaged Warning Signs % of signs damaged <5% <5% 2.00% 3.37% 2.60% 1.50% 0.22%

5 CP Test Points Voltage Potential

% of test point voltage potential’s higher than -0.85V potential

<5% <5% 1.00% 1.11% 1.53% 0.38% 0.78%

Regulator Sets / PRS 6 PRS Failures % of PRS failures <2% 0 0.00% 0.00% 0.00% 0.00% 0.00%

7 HP Regulator Set Failures

% of HP regulator set failures <2% 0 0.60% 0.00% 0.54% 0.00% 0.00%

8 MP Regulator Set Failures

% of MP regulator set failures <5% <1% 0.00% 0.00% 0.33% 0.32% 0.00%

Meter Sets 9 Meter Set Failures % of meter set failures <2% <1% 0.70% 0.00% 0.13% 0.00% 0.16%

10 Meter Set Meter Accuracy

% of meters found operating outside prescribed meter accuracy of 3%

<5% <1% 0.00% 0.26% 0.63% 0.00% 0.00%

Isolation Valves

11 Isolation Valves not Operational

% of isolation valves not operational <5% <2% 0.00% 0.00% 0.00% 0.00% 0.41%

Domestic and Commercial Meter

12 Domestic Meter Defects % of defects reported on domestic meter installations

<2% <2% 1.00% 1.57% 1.71% 1.29% 1.06%

13 Small Commercial Meter Defects

% of defects reported on small commercial meter installations

<8% <8% 5.20% 5.00% 6.00% 3.81% 2.87%

14 Meter Installations Damaged

% of meter installations damaged <1% <1% 0.01% 0.00% 0.00% 0.01% 0.01%

Design and Planning

15 No of "Low Pressure Alarm" Instances Total No. <10 <10 1 1 0 0 0

16 No of "Operating Outside Expected Range" Instances

Total No. <20 <20 1 7 13 21 19

Commissioning

17 High Pressure Pipelines Data Report received within 90 days 100% 100% - 100% 100% 100% 100%

Operations Major Events and Incidents 18 No. of Broken Mains No. per 100 km main <2.5 <2.5 1.4 1.5 0.9 1.0 1.0

19 No. of Broken Services No. per 100 installations <0.25 <0.25 0.20 0.21 0.18 0.18 0.17

Operations System Performance

20 Unaccounted for Gas (REMCO)

% of network throughput <2.9% <2.9% 2.94% 3.08% 2.78% 2.89% 2.54%

21 Customer Minutes off Supply

SAIDI - Customer Minutes off Supply / Average No Customer

<0.66 <0.66 0.5 0.4 0.3 0.3 1.9

22 Supply Interruptions Supply interruption per connected customer <0.0060 <0.0060 0.0040 0.0039 0.0033 0.0035 0.0050



KPI KPI Title Parameters Current Target

Desired Target 2009 2010 2011 2012 2013

Decommissioning

23 Demolitions % completed within 10 days >95% >95% 99.6% 99.8% 99.9% 100% 97.0%

Auditing

24 Progress of Internal Quality Audit Program No. Audits per quarter >6 >6 8 4 6 13 6

Customer Service Standards

25 Customer Connection Time

% of Services Connected to established LOM within 7 days

>95% >95% 98.7% 99.2% 98.9% 99.4% 100%

26 Attendance to Broken Mains and Services

% of Faults attended to within 1 Hour >95% >98% 99.9% 99.7% 99.7% 99.7% 99.6%

27 Attendance to Gas Smells in a Public Area

% attended to within 2 Hours >95% >98% 99.2% 100% 100% 100% 100%

28 Attendance to Gas Smells at Meter – Standard Response

% attended to within 48 Hours >95% >98% 98.7% 99.5% 99.9% 99.9% 99.5%

29 Attendance to No Gas (Commercial)

% attended to within 2 Hours >95% >98% 99.9% 100% 100% 99.2% 100%

30 Attendance to No Gas (Domestic)

% attended to within 3 Hours >95% >98% 99.5% 99.5% 100% 100% 100%

From a continuous improvement perspective, these targets will be updated during the course of the upcoming Access Arrangement.

An initiative has commenced to investigate the KPIs suggested for use in AS4645. This Standard contains recommended performance measures for a gas distribution network. AGA intends to replace the existing AMS KPIs with those suggested in AS4645. To enable the measurement of these KPIs, several changes to business processes and modifications to IT systems are required. IT project AGA-18 – Strategic Asset Management, described in Section 6.2.2, has been established with part of its project scope to implement this requirement.

2.5 Asset Programs to Improve Levels of Service Improvement in several areas has been identified and specific asset projects that will improve these areas are listed in the tables below. Areas of improvement include:

• Health & Safety

• Unaccounted for Gas

• SAIFI

• Isolation Valves not Operational

Table 12: Asset Projects to Improve Health & Safety

Project Description 2H 2014 2015 2016 2017 2018 2019 Total ($'000s) SUSTAINING CAPEX $36 $211 $96 $96 $97 $97 $633

Network Safety and Performance $36 $211 $96 $96 $97 $97 $633

EOL Replacement - HP Reg Pit Lids $21 $21 $21 $21 $21 $105

Facility Upgrade - Confined Space Signs $113 $113

Facility Upgrade - Insulation Joints & Surge Protectors $18 $18 $18 $18 $18 $18 $109

Facility Upgrade - Security & Danger Signs $18 $18

Facility Upgrade - Step Touch Mitigation $58 $57 $57 $58 $58 $288

Total ($'000s) $36 $211 $96 $96 $97 $97 $633



Table 13: Asset Projects to Improve UAFG Performance and Mains defects

Project Description 2H 2014 2015 2016 2017 2018 2019 Total ($'000s) SUSTAINING CAPEX $8,606 $17,115 $17,593 $17,562 $20,163 $20,108 $101,148


EOL Replacement - Cast Iron $2,596 $4,840 $5,151 $5,139 $4,806 $22,533

EOL Replacement - Mains (AH) $200 $341 $335 $334 $338 $338 $1,885

EOL Replacement - Odd Size Steel Maylands $852 $852

EOL Replacement - Odd Size Unprotected Steel $1,512 $1,705 $1,673 $1,666 $1,686 $1,010 $9,253

EOL Replacement - PVC Mains & Services $239 $2,384 $2,338 $2,328 $2,355 $2,351 $11,994

EOL Replacement - Service Valves $245 $368 $362 $362 $368 $369 $2,075

EOL Replacement - Unprotected Metallic Mains $2,885 $7,171 $7,380 $7,361 $10,170 $15,599 $50,566

Network Safety and Performance $77 $306 $355 $371 $441 $440 $1,990

R&D - Isolation of a Network for UAFG Investigation $306 $105 $105 $106 $106 $728

Replacement - Oversized Turbine Meters $77 $77

Temperature Compensated Meters $250 $267 $335 $334 $1,185

Total ($'000s) $8,606 $17,115 $17,593 $17,562 $20,163 $20,108 $101,148

Table 14: Asset Projects to Improve SAIFI

Project Description 2H 2014 2015 2016 2017 2018 2019 Total ($'000s) SUSTAINING CAPEX $8,025 $14,013 $14,495 $14,457 $16,974 $16,923 $84,887



EOL replacement - HPR $163 $162 $160 $159 $162 $162 $968

EOL Replacement - MP Pits $17 $134 $131 $131 $133 $133 $679



EOL Replacement - TRU $18 $18 $37


Total ($'000s) $8,025 $14,013 $14,495 $14,457 $16,974 $16,923 $84,887

Table 15: Asset Projects to Improve KPI-11 - Isolation Valves not Operational

Project Description 2H 2014 2015 2016 2017 2018 2019 Total ($'000s) SUSTAINING CAPEX $70 $141 $69 $70 $71 $71 $492

Asset Replacement $70 $141 $69 $70 $71 $71 $492

EOL Replacement - Isolation Valves $70 $141 $69 $70 $71 $71 $492

Total ($'000s) $70 $141 $69 $70 $71 $71 $492

These projects are described in more detail in Section 4 for each of the applicable asset classes.



3. Future Demand This section provides details of demand drivers and growth forecasts that affect the management and utilisation of the GDS.

3.1 Demand Drivers Demand drivers are factors that influence demand, with different demand drivers for connections to gas compared to gas consumption (i.e. throughput). There can be different drivers for the Residential segment compared to the Commercial and Industrial segments.

A summary of demand drivers affecting AGA are listed below:

• Residential:

• Consumption Demand drivers:

• Weather

• Retail Gas Price

• Microeconomic factors

• Appliance Efficiency

• Alternative Energy Appliances

• Subsidisation of competing energy prices

• Connections Drivers:

• Population and associated housing growth

• Interest rates

• Building Codes for homes

• Appliance obsolescence

• Industrial & Commercial:

• Consumption Demand drivers:

• Retail Gas Price

• Micro and Macro economic factors

• Appliance Efficiency

• Production process technology improvements

• Connections Drivers:

3.1.1 Alternative Technologies

There are numerous technologies that can influence the use of gas in Western Australia. Australian Bureau of Statistics (ABS) Studies, 4656.5 Household choices related to water and energy (October 2009) and 4602.0.55.001 Environmental Issues: Energy Use and Conservation (March 2011), collected data on dwelling access to energy, space cooling and heating and water heating.

Key findings of these studies were:

• Almost all dwellings in WA had access to electricity. Other sources of energy include:

• Mains gas – connected to 84% of dwellings in the Perth metro area and 25% in the remainder of WA

• Solar energy – used in 20% of Perth dwellings and 33% in the remainder of WA. In the Perth metro area 15% had solar hot water, 3% had solar electricity and 2% both.



• LPG bottled gas – used by 56% of dwellings outside the metropolitan area.

• Insulation was installed in 660,720 (74%) dwellings.

• 680,900 (83%) dwellings in the Perth metro area had some form of air cooling system.

• Reverse cycle split systems and evaporative ducted air conditioning systems accounted for 50% of all main air conditioners.

• 566,900 (86%) dwellings had some form of space heating in the Perth metro area.

• Non-ducted unflued gas heaters (30% of WA dwellings) and non-ducted reverse cycle air conditioners were the most common forms of heating (15% of WA dwellings).

• 23% of WA dwellings used electricity and 17% used solar energy for water heating.

• 56% of WA hot water systems were storage tanks, while 39% were instantaneous water heaters in the Perth metro area.

Complementing technologies to increase energy market share of gas include:

• Gas clothes dryers

• Gas Ovens and BBQs

• Pool and Spa Gas Heaters

• Gas fired air conditioning

• Distributed gas fired electricity generation

• Natural gas vehicles

Substitute technologies that reduce energy market share of natural gas include:

• Electric Reverse cycle air-conditioning

• Electric Heat pump hot water systems

• Electric induction hot plates

• Solar hot water systems

• Solar electricity panels

• Wood heaters

• Bottled LPG

3.1.2 Climatic Conditions

The use of gas appliances is heavily influenced by their availability, cost and the weather conditions end users face in WA. In the residential home market, hot water heating makes up the majority of gas usage utilising on average 70% of the gas used.

During the year, higher peak loads occur during the winter months as compared with those in the summer months. This is predominantly due to the use of gas for space heating, but also due to increase thermal loading on water heaters from the lower ambient and ground temperatures.



Figure 7 indicates the daily gas consumption for the Perth metropolitan area and shows that winter daily peak loads are approximately double those of the summer months.

Figure 7: 2013 Metropolitan Peak Load Profile

As the system peak load is sensitive to extremes of cold weather, gas consumption varies annually due to the severity of the winter. This is measured through the variability of Effective Degree Days (EDD). EDD’s measure the variance in average daily temperature from 22.36˚C, factoring in wind chill, sunshine hours and seasonality.

The network is planned and designed to ensure the continued supply of gas in a severe, 1 in 20 year winter. Currently, the 1998 winter is used as the basis for a severe winter, due to its high domestic unit load as a result of a high gas throughput that can be related to a prolonged period of low temperatures over consecutive days.



Figure 8: EDD Weather Variation

3.1.3 Population Growth

Residential gas connections are driven by the number of new dwellings completed that have chosen to connect to the GDS and the number of established houses converting to NG from bottled LPG and other forms of energy. ATCO Gas Australia trends the relationship between residential connections and house completions, and consistently between 85% and 90% of dwelling completions will have a gas connection if there is gas mains infrastructure within the street.

The Economics Consulting Services (ECS) group provides an expert report that is used each year to provide statistics and forecasts for the number of dwelling starts, and associated mains, in WA. The historical number of dwelling starts over the last twenty-five years has been an average of approximately 18,000 per annum.

3.2 Demand Forecasts The ability to predict future demand for services enables ATCO Gas Australia to plan ahead and identify the best way to meet that demand. This section identifies factors and trends influencing demand for natural gas.

3.2.1 Population Growth

Described in the expert 2013 report received from ECS, population growth rates since 2001-02 have ranged from 1.4% to 3.3% with an average of 2.2%. Investment in major resource projects has slowed but many projects will move into an operational phase providing stable medium to longer term employment. Growth is being inhibited by high living costs and poor housing affordability. Connections improved since the last half of 2012 and are expected to increase until June 2014 when expansion will slow to long term population growth rates of less than 2% a year.

3.2.2 Housing Design and Appliance Technology

The evolution of housing design to cater for a smaller land footprint, combined with the demand for higher energy efficiency from both residential and commercial buildings is changing the shape of gas demand. Whilst the demand for the gas service remains, the average gas consumption is



decreasing. Hot Water remains the primary source of gas demand, however the need for gas space heating is being challenged by other technologies and solutions.

Furthermore, the energy efficiency of gas consumer appliances is continually improving. As the fleet of gas appliances in residential homes throughout the GDS is gradually replaced newer model appliances are installed that use less gas to achieve the same result thus reducing the overall demand for gas.

3.2.3 New Connections Forecast

Domestic meter connections can be separated into new and established dwellings and then into domestic B3 connections and into feeder connections. Domestic B3 connections primarily relate to houses while feeder connections primarily relate to other dwellings including apartments and flats, medium density developments and aged care estates. Table 16 indicates the forecast of new connections and mains extensions for this reporting period.

Table 16: New Connections Forecast from Economics Consulting Services

2H 2012 1H 2013 2H 2013 1H 2014 2H 2014 2015 2016 2017 2018 2019

Customer Connections

B3 connections 6057 5937 7370 6585 6,994 13,430 13,450 13,450 13,450 13,450

Cluster connections 1416 1563 1774 2035 2,152 4,260 4,260 4,260 4,260 4,260

B2 Connections 281 251 273 275 199 370 405 440 475 510

Mains Extensions

Mains and Feeders [km] 115 112 119 137 147 262 252 252 252 252

New pipe installations include infill work in older suburbs and new subdivisions. The latter make up most of the open trench work and hence the cost of servicing new customers. Installations are classified as “mains extensions”, “open trench mains extensions” and “open trench gas feeders”. The length of extensions is variable as new subdivisions can be close to an existing network or located at some distance from existing pipes.

3.2.4 Residential Lot Activity

Developers surveyed by the UDIA reflect the changing pattern of Perth development with the number of lots to be released in the next year dominated by North West and South West Metro areas. Wanneroo and Rockingham local government areas are expected to provide 50% of the developer lot releases. Table 17 has been sourced from the 2013 ECS report and summarises the number of lots expected to be released in 2014 by developers.

In addition to the continued expansion to more outlying areas of the greater Perth Metropolitan areas, the Department of Planning is progressing the development of suburban infill areas as outlined within its Directons 2031 document. These infill areas represent both traditional land development but also increasing urban density of these zones.

While the majority of growth in the outer sub-regions is focused on greenfield development, the contribution of infill development and redevelopment will change such that the proportion of new dwellings in existing urban areas will increase over time.



Table 17: Developer land release intentions in 2014

Local Government Area Lots Share

Wanneroo 1,971 34%

Rockingham 1,003 17%

Armadale 828 14%

Swan 688 12%

Kwinana 535 9%

Mandurah 346 6%

Joondalup 172 3%

Murray 112 2%

Cockburn 88 2%

Other 40 1%

Total 5,783 100%

Lots expected to be released by developers over the next ten years are summarised in Table 18.

Table 18: Forecast Lots to be released by Developers over Next Ten Years

Name of Estate Total No. of lots Completion (all lots sold)

Satterley Property Group Satterley is by far the largest developer in Western Australia. Currently Satterley have over 30,000 lots coming on line over the next 5-10 years and they are predominant in the affordable land releases both North and South of the Perth Metro area. Beaumaris 2000 5-10 yrs

Catalina 2310 5-10 yrs

Eglinton 1500 5-10 yrs

Brighton 6500 5-10 yrs

Harrisdale 1400 5-10 yrs

Evermore 4000 5-10 yrs

Secret Harbour 2985 5-10 yrs

Austin Lakes 3000 7 yrs

New Kwinana 300 3 yrs

Honeywood 1700 5 yrs

Dalyellup 3300 5-10 yrs

Provence 1600 5-10 yrs

Stockland

Stockland are the 2nd largest residential developer in Western Australia with almost 20,000 lots available or planned projects.

Amberton 2368 5-10 yrs

Whiteman Edge 1227 5-10 yrs

Vale 4500 5-10 yrs

Sienna Woods 3000 5-10 yrs

Wungong Reach 2768 5-10 yrs

Newhaven 1997 5-10 yrs

Banjup 1703 5-10 yrs



Name of Estate Total No. of lots Completion (all lots sold)

Settlers Hills 2152 5-10 yrs

LWP

Ellenbrook is Perth's largest master planned community with over half of the project area currently developed and an additional 10,000+ lots still remaining. LWP has been awarded numerous awards for their style of community development and are highly regarded in the development community Ellenbrook 10451 8 yrs

The Glades 3575 5-10 yrs

The Reserve 388 5-10 yrs

The Retreat 205 5-10 yrs

Woburn Park 312 5-10 yrs

Trinity 2777 4 yrs

PEET

PEET have been very active in providing affordable, residential subdivisions in the Perth Metro areas for numerous years. With 17,500+ lots online and planned, PEET are Perth's 4th largest Property Developer for residential land. Burns Beach Estate 1467 5-10 yrs

Carramar Golf Course Estate 3000 5-10 yrs

Yanchep Golf Estate 1500 5-10 yrs

Shorehaven at Alkimos 2900 5-10 yrs

The Village at Wellard 2700 5-10 yrs

Avon Ridge Estate 216 5-10 yrs

Oakford/Forresdale 1700 5-10 yrs

Golden Bay 1750 5-10 yrs

Lakelands Private Estate 2439 5-10 yrs

PRM Property Group

Banksia Grove 3600 3 yrs

Meve at Beeliar 1600 3 yrs

Lend Lease

Partnership with Landcorp

Alkimos 2688 8 yrs

Spatial Property Group

Spires 1500 5 yrs

South Baldivis 1000 5yrs

LandCorp

LandCorp have adopted a strategy of partnering with larger developers in the Perth Metro area. LandCorp are focused on the North of W.A and they are developing over 7,500 lots in and around Karratha and Port Hedland. Perry Lakes 700 3 yrs

Harvest Lakes 1200 3 yrs

Mirvac Properties

Meadow Springs 1600 5-10 yrs

Australind

Jindowie 1303 3 yrs

Total Lots Forecast 100,881

3.3 Demand Impact on Assets



The demand for new gas connections is primarily within new housing developments as the majority (84%) of the Perth metropolitan area is already connected to gas. Within these established areas opportunity for additional connections exist especially when there is gas mains infrastructure within the street. This opportunity will likely only occur when the home owner is either renovating the home or existing appliances have failed and replacements are required.

The demand on gas consumption is influenced by a number of factors as outlined earlier, with overall average residential gas demand trending downwards. These factors have also influenced peak conditions, but are remaining relatively constant when trending the domestic unit loads applied to the annual hydraulic modelling of the network.

Figure 9: ATCO Gas Australia Network Throughput

Whilst the overall average residential consumption has declined over recent years, the continued strong demand for gas connections associated with the housing growth within Western Australia is such that when the residential consumption (i.e. B3 reference service) is considered in aggregate, there has been a slight increase in total throughput in recent years as shown in Table 20 below.

Table 20: Weather Adjusted B3 Gas Usage

B3 2007 2008 2009 2010 2011 2012 2013

Total (TJ) 10,081 10,277 10,506 10,229 9,648 9,938 9,960

However the overall throughput of the GDS has declined in the last 5 years (Figure 9). The principal cause for the drop in throughput is attributable to a single A1 reference service customer, Cockburn Cement, changing the fuel source for their large rotary kilns from natural gas to coal due to the increase of wholesale gas prices. The individual usage profile for Cockburn Cement is outlined below in Table 22.

The customer demographic of the A1 Reference Service users includes a relatively small number of very high consumption users (A1 usage is depicted within Table 21). Due to this high consumption, the behaviour



of a few of these customers can high a significant impact on the total throughput of the GDS. For other example, other large scale users such as Iluka Resources and Astral Bricks have reduced usage due to changing business drivers (such as economic conditions and commodity export prices) in recent years.

These three customers represent isolated examples in a network of over 680,000 end use connections. Compensating this reduction has been a significant market push towards embedded or distributed gas generation resulting in a number of new A1 Reference Service customers forecast to connect to the GDS in future years. This interest in distributed generation solutions is from both land developers and local government, specifically in areas where the existing electricity network infrastructure is constrained. Each of the parties is seeking to avoid perceived excessive additional costs, and therefore barriers, to their particular development.

Due to the long lead time required for the construction of both the facilities as well as the infrastructure for those facilities, the impact of the additional consumption is not seen until later years yet the design and changes to the GDS are required well in advance of the eventual connection.

Table 19: Weather Adjusted A1 Gas Usage

A1 2007 2008 2009 2010 2011 2012 2013

Total (TJ) 15,591 12,333 12,466 12,561 11,861 12,188 11, 528

Table 20: Cockburn Cement Natural Gas Usage

Cockburn Cement

2004 2005 2006 2007 2008 2009 2010 2011 2012 2013

Total (TJ) 5277 5347 4867 5080 2371 2373 2200 1860 1848 1416

This change in usage by a single customer is the major cause of the drop in total network throughput, but as this customer had a dedicated supply directly from Russel Rd gate station, it does not indicate spare capacity in the rest of network.

3.4 Demand Management Plan The expansion of the network and requirement to have sufficient capacity to supply gas during the peak period is modelled using SynerGEE gas simulation software. SynerGEE is a well-accepted hydraulic simulation tool that can generate geographically accurate models of gas network flow. This functionality has been achieved through the implementation of a Geographical Information System (GIS) extraction process.

Through this process, each asset on the network, distribution mains, pressure regulators, pressure monitoring devices, valves, are extracted from GIS and linked to an individual record that contains information about its size, material, roughness and location on the network. All 130 distribution gas networks are extracted from the GIS software and imported into SynerGEE to model the network gas flow dynamics using flow data from monitored, interval meter sets and diversified unit load calculated for each domestic customer. The model’s accuracy is verified against actual pressures from pressure monitoring devices on the GDS as part of the Network Data visualisation solution.

3.4.1 Planning Objectives

Adequate capacity in the gas network and all its components is defined as the capacity to meet peak hour loads that may occur for a weather probability of 1 in 20 years when the network is operated under normal operating pressures. Additional planning objectives are:

• Provide a safe, reliable and cost effective gas supply to consumers throughout its lifecycle and throughout the range of anticipated demand profiles including winter peaks.

• Minimise the risk of loss of supply due to capacity limitation.

• Ensure continuity of supplies by operating the network prudently.



• Ensure compliance with the requirements of Licences, Regulations and relevant codes and standards.

3.4.2 Network Planning Assumptions

The entire gas network is separated into seven geographical regions with their individually applied domestic diversified unit load. Peak domestic unit load is the average gas load consumed by an individual consumer during the peak winter period. Each year, the domestic unit load is calculated using the peak demand of the previous winter. The peak demand is the highest hourly throughput that is usually in the evening between 6 – 9 pm. The peak demand coincides with the lowest gas pressures experienced in the region.

Every year, peak and severe winter modelling is carried out to anticipate the behaviour of the gas network. The peak winter models are created to represent last year’s peak winter. The results are used to analyse the performance of the gas network.

The severe winter models are created to identify future reinforcements to maintain a robust gas network and ensure integrity of supply. The representation of a severe winter load used in these models was based on the following assumptions:

• Dedicated regulator sets are set to the designed network pressures with considerations given to the drooping effect under peak winter conditions.

• Regulator sets capacity to maintain the supply pressures have been modelled based on minimum pressure at the inlet of the regulator.

• The network and customer data obtained from GIS with the Gas Model tool correctly reflects the physical assets.

The peak winter model results are compared with the actual flow and pressure data for that winter condition. Any major discrepancies are investigated to determine the cause of the variation and remedied where warranted.

New connections are forecast using an average actual historical growth over 7 years and the new connection forecast developed by ECS. The forecast of new connections determines the reinforcement requirements on the network in order to maintain integrity and continuity of gas supply.

The forecast new connections are based on the ECS report issued in June 2013. The ECS forecast outlines total domestic connections for ATCO Gas Australia’s network catchment areas, but does not include growth by suburb. ECS applies a conservative 65% on connections of new domestic connections and 75% on cluster connections.

In accordance to AGA’s Network Planning Standard, gas network designs consider 100% connection rate to allow for future customer connections and individual customer load growth.

3.4.3 Domestic Diversified Unit Load

A crucial element of the development of the peak and severe winter network models is the domestic unit load for each of the 7 geographical regions. The domestic unit load is determined by the highest hourly throughput using actual data from the previous winter for each network so that each individual network has its own unit load. The peak domestic unit load is applied to the SynerGEE models to develop a peak winter model that is validated by information captured from pressure monitoring devices on the GDS via the Network Data Visualisation solution. Analysis performed has shown that the modelled pressures have an average ±2kPa discrepancy when compared with actual pressure from the network, which demonstrates the high degree of accuracy of the models.

The peak domestic unit load is then escalated to represent a 1 in 20 year severe winter. The most severe winter experienced in this period was in 1998. The severe winter domestic unit load is applied to develop severe winter models that are used to forecast and identify projects to reinforce the gas network to ensure network integrity in the event of a severe winter.



Table 21: Diversified Unit Load on Severe Winter Using 2012 Peak Winter Actuals

Location Diversified Unit Load [m3/hr]

Ellenbrook 0.347

Metro 0.361

Pinjarra 0.349

Rockingham 0.371

Geraldton 0.354

Bunbury 0.417

Busselton 0.315

3.4.4 Localised Load Allocation

Topographical conditions limit the expansion of some networks and determine the direction of its expansion. In instances where this is identified in a mature developed network, a localised load is applied at the appropriate section of the network rather than over the whole network. This ensures that the potentially stressed section of the network is capable of supplying gas and maintaining integrity. This is the situation for example with the Drummond Cove development in Geraldton.

3.4.5 Peak Winter Modelling

Peak winter models are created to verify the performance of the network. Network peak load is very sensitive to extremes of cold weather and can vary from year to year due to the severity of the winter. The average winter peak load has been approximately 80% of a severe winter load. Network modelling is conducted to enable the network to support a severe winter occurrence and identify future reinforcements to maintain integrity and continuity of gas supply.

3.5 Asset Programs to Generate and Meet Future Demand AGA’s network has experienced a decline in the average consumption per customer over recent years, which is a similar experience to most natural gas utilities worldwide. It is in the long term interest of customers to promote both connections to the network and average usage per customer, otherwise this declining trend will result in increased unit costs per customer. With an understanding of growth and future demand trends, and the impacts on levels of service and cost to customers, decisions on how to address future deficiencies or shortfalls in service have been made. Programs and projects developed to generate and meet future demand that are not part of the network asset classes described in Section 4, are summarised below.

3.5.1 Operational Depots and Training Centre

ATCO Gas Australia will own and operate six operational depots plus the Jandakot operational base. These include Bunbury, Busselton, Yanchep, Geraldton, Osborne Park and Mandurah. This model is proposed to enable compliance with the Safety Case by meeting emergency response time service levels. The move away from four existing short term lease agreements to an own-and-operate model will also allow the business to provide services as lowest sustainable cost.

ATCO Gas Australia’s aim is to locate resources, both personnel and equipment, in areas where it can serve customers more efficiently throughout the entire Network. Having equipment available locally to incidents will also minimise response times, allowing work crews to respond to broken mains and services within one hour.



Table 22: Forecast capital expenditure on operational depots and training centre: 2014 to 2019

$ million real at 30 June 2014 2H 2014 2015 2016 2017 2018 2019 Total

Operational depots and training centre 1.0 14.3 1.2 0.8 - - 17.3

The new facilities will be designed to meet AGA’s current and future operational requirements and will include:

• Secure yard areas to store trailers, compressors and other heavy equipment

• Vehicle bays to store, maintain, inspect, and re-stock vehicles and equipment

• A secured materials area

• A waiting area for customers

• A change area for crews

• Meeting rooms

• Office space for employees

Operating depots shall be designed to be energy efficient and provide appropriate access for staff and visitors with a disability.

With regard to the new depot locations, ATCO Gas Australia proposes to split the northern and southern metro areas into three zones and the Bunbury/Busselton district into two zones. This split will ensure the one hour emergency response coverage can be maintained. The maps below show the proposed location of the new depots.

Figure 10: Proposed location of the new depots

The proposed depot locations takes into account forecast network growth and the WA Department of Planning’s Directions 2031 vision.



3.5.1.1 North

ATCO Gas Australia currently leases an operational depot in Wangara. The lease arrangement is due for re-negotiation during 2014. ATCO Gas Australia proposes to own an operational depot in Osborne Park and Joondalup. The Wangara depot leasing arrangement will be retired.

Osborne Park offers excellent access to main arterial roads and mass transit infrastructure for the north metro area as well as optimal lot sizes for operational needs. Osborne Park provides good access to building industry stakeholders and marketplace exposure that would align to ATCO Gas Australia’s customer growth strategies. Joondalup offers superior access to main arterial roads and mass transit infrastructure as well as optimal lot sizes for AGA operational needs compared to Neerabup and provides emergency response coverage to the high growth north west metropolitan area.

The existing Geraldton Depot lease is due for re-negotiation in 2015. Though the current site is appropriately located for the township and lateral network activity, ATCO Gas Australia considers construction of a purpose-designed depot will provide more cost effective long term solution for providing services to customers.

3.5.1.2 South

ATCO Gas Australia currently leases operational depots in Mandurah and Bunbury. The leases are due for re-negotiation in 2014 and 2015 respectively. The Mandurah lease will not be renewed and a depot is forecast to be purchased during AA3, although specific timing of the purchase will be dependent on suitable stock becoming available. Similarly the Bunbury depot lease will not be renewed and ATCO Gas Australia will purchase its own depot facilities in Bunbury and Busselton to properly service the network footprint.

Mandurah offers excellent access to main arterial roads and mass transit infrastructure as well as optimal lot sizes for ATCO Gas Australia operational needs. The current leased facility does not meet operational needs as growth in the region has resulted in a lack of parking, hardstand, office and store facilities to meet requirements. The site is also shared with other tenants, which introduces risks of third party vehicles and operating practices around the working area. Addressing current safety concerns would be expensive and provide a short term benefit given the lease arrangements. Establishing a new site enables the safety and operational requirements of ATCO Gas Australia to provide benefits over a longer period of time.

Bunbury offers excellent access to main arterial roads and is well located for access to Bunbury and surrounding areas. The existing facility is adequate for current operations, however, projected growth means relocation is required during the access arrangement period.

Busselton requires a dedicated satellite operation due the forecast network growth in the region and emerging limitations, such as higher density traffic conditions in reach from Bunbury to cover emergency response.

3.5.1.3 Training Facility Redevelopment

To comply with the Gas Standards (Gas Supply and System Safety) Regulations 2000 (GSSSR 2000) ATCO Gas Australia must ensure, so far as is reasonable and practicable, that any employee or contractor engaged in carrying out a prescribed activity is given instruction and training, and tested for competence, in how to safely apply and use those standards, procedures and practices.

ATCO Gas Australia has an in-house dedicated training and assessment team to instruct, train and assess employees and contractors. Implementation of the Safety Case has resulted in significant changes to operational procedures, which has driven a corresponding increase to the volume and complexity of training activities.

To meet Safety Case obligations the existing training facility in Jandakot will need to be re-developed to accommodate the increased training requirements. The redevelopment will provide sufficient capacity, classroom facilities, practical training and assessment areas. It



will achieve the lowest sustainable cost by mitigating the expense of using third party facilities.

The proposed redevelopment will provide the following facilities:

1. External raised training area - used for locating, proving and protecting the asset, manual excavation, use of an excavator, excavator spotter, installation of mains, services and meter boxes, testing and commissioning of mains and services, leak survey, trench padding and compaction, back filling and pipe marking. The current fire training pit will need to be relocated due to its proximity to site buildings.

2. Assessment centre – allowing independent personal competency assessments to be carried out in a realistic, simulated and controlled environment. Differing faults can be applied to a range of scenarios enabling trainers to assess operatives’ competence.

3. Research and development laboratory - required for testing new tools, equipment and network elements before field trials. If accredited to National Association of Testing Authorities (NATA) level, a calibration resource and adequate facilities will allow ATCO Gas Australia to reduce costs of testing and calibration of instruments, tools and equipment.

Accounting for growth in the number of competent personnel required to safely apply and use standards, procedures and practices, Figure 11 shows forecast classroom contact hours compared to maximum capacity of current facilities.

Figure 11: Classroom delivery hours

External and more costly classroom alternatives will need to be sourced in the short term until the facility is redeveloped.

3.5.2 Forecast Fleet Capital Expenditure

ATCO Gas Australia’s fleet is comprised of vans, utilities, trucks, motorbikes, trailers, compressors, excavators and passenger vehicles. Table 23 shows forecast capital expenditure on fleet during the AA4 period.



Table 23: Forecast fleet capital expenditure


Fleet 2.1 1.2 0.8 1.4 4.6 4.4 14.5

ATCO Gas Australia’s fleet ownership strategy was implemented during 2013. The majority of fleet was replaced over the year, all of which had reached their end of useful life. There will be a corresponding expenditure peak in 2018 as these vehicles reach their five-year replacement cycle. This aligns to the Motor Vehicle Policy that prescribes replacement timeframes and kilometres.

Fleet ownership and management achieves the lowest sustainable cost of providing services over the longer term.

Ownership creates efficiencies in vehicle usage through the interchange of vehicles made possible by the use of common purpose-built vehicle types. Fleet ownership also reduces the risk of increasing lease costs, inertia costs and ‘over kilometre’ costs when leased vehicles are not replaced in a timely manner.

A summary of the different vehicles types within the fleet and their forecast timings are outlined in Table 24.

Table 24: Forecast of fleet by type

Forecast units for fleet

Vehicle Type Approximate Base Unit Cost 2H 2014 2015 2016 2017 2018 2019

Truck $200,000 5 2 2 4 4 5

Bobcat $80,000 1

Utility $60,000 13 7 2 4 28 31

Van $60,000 1 1 2 17

Wagon $55,500 4 2 5 34 6

Sedan $45,000 2

Excavator $35,000 6 2 2 6 7

Trailer $15,000 4 3

Motorbike $7,500 1

Total 30 17 10 15 75 66

3.5.3 Plant and Equipment

Plant and equipment is critical to safely undertake planned and reactive operational activities. Typical plant and equipment is high and low pressure flow-stopping equipment used in emergency response scenarios to safely isolate gas supply and control the release of gas. This equipment is also used for planned flow stopping and new main connections.

Other equipment includes underground services detection equipment for third party damage prevention, gas detectors and polyethylene welding equipment. Table 25 shows forecast capital expenditure for plant and equipment during the AA4 period.



Table 25: Forecast plant and equipment capital expenditure


Plant and equipment 0.6 1.2 1.5 1.3 1.0 1.0 6.6

1. Flow stopping – This equipment is used to safely stop the flow of gas when isolating a section of gas mains for such things as connecting new subdivisions to grow the network, to accommodate network alterations and to isolate the supply of gas in the event of an emergency. It encompasses a variety of equipment to flow stop the different material types such as metallic, PVC and Polyethylene mains across the different pressure ranges on the network.

2. Underground asset detection – Consistent with good industry practice this equipment is used to assist in the prevention of damage to underground infrastructure by identifying and locating underground assets prior to, and during, excavation activities. Prevention of underground damage is essential to mitigate the risks to personnel and the general public and underground asset strikes, as well as prevent interruptions to supply of other underground asset owners and their customers.

3. Gas detector units – These units are essential to ensure successful commissioning and decommissioning activities by accurately reading gas levels, and therefore preventing an uncontrolled gas and air mixture that could potentially be explosive. Units are also used in locating and classifying gas leaks on the asset and are key tool in safe guarding both people and property.

4. Polyethylene welding and fusion – Consistent with good industry practice the new gas network is predominantly constructed using polyethylene. To ensure that joining new pipes together, or welding on fittings to facilitate operational activities, this equipment is essential.

5. Pressure testing – To ensure compliance with AS/NZS 4645 and AS 2885 testing requirements, assets are pressure tested to ensure they are fit for purpose. The different operating pressures of the network require different equipment to ensure compliance to these requirements.

6. Fleet fit out – After the purchase of new fleet vehicles they must have all necessary equipment to ensure it is operationally ready and fit for purpose before being utilised by personnel.

3.5.4 Jandakot Warehouse Redevelopment

Following on from the corporate Jandakot head office re-development project the remaining operational facilities, including warehouse, gas testing and stores areas are to be rationalised and upgraded to ensure compliance to occupational health and safety requirements and all current building regulations. The upgraded facilities will be designed to be energy efficient and provide appropriate access for staff and visitors with a disability. The facilities will be designed for employees to reduce manual handling of materials, safely maintain vehicles, store equipment and secure materials.

3.5.5 Natural Gas Refuelling Infrastructure and Vehicles

ATCO Gas Australia has investigated various options that will help market Compressed Natural Gas (CNG) to potential users identified as having the largest potential uptake, being businesses with large return to base fleets. One of the key issues identified has been the lack of infrastructure to support CNG. ATCO Gas Australia will be developing additional refuelling infrastructure and further expanding its own natural gas vehicle fleet, benefiting the Company through reduced operating costs and an ability to market CNG. This project aims to develop the utilisation of natural gas through the installation of CNG refuelling infrastructure in Western Australia and entails two components:

• Large scale refuelling station – Expand the existing CNG refuelling station at the Jandakot depot. This involves installation of multiple bowsers that can support a large proportion of



the Jandakot fleet. This project also incorporates the additional cost of the natural gas vehicles conversion or OEM premium.

• Multiple small scale refuelling stations – Construct and install one small scale CNG refuelling station at the ATCO Gas Australia depot in the northern suburbs. This involves the installation of a small compressor unit, with CNG refuelling post and storage to support the vehicles based at these depots. This project also incorporates the additional cost of the natural gas vehicles conversion or OEM premium.

The benefit to ATCO Gas Australia will be in the OPEX savings from reduced fuel costs, and help promote natural gas as a vehicle fuel in Western Australia. The business will expect this project to have a positive Net Present Value in alignment with Rule 79 (2) (b).

3.5.6 ATCO Natural Gas Kitchen

This project is forecast to run in parallel with the Osborne Park operational depot due to the proximity to building industry stakeholders. The ATCO Natural Gas Kitchen is an extension of the original Blue Flame Kitchen that was established in Canada in 1930 to help homemakers get the best results when using natural gas. Although much has changed today, the underlying role of the Blue Flame kitchen remains essentially the same – To drive usage and awareness of natural gas and its benefits.

The kitchen concept will be used as the vehicle to commence conversations and demonstrations as to the cost and environmental benefits of using natural gas throughout the home. Safety will also feature heavily through all communication covering natural gas, appliances, what to do in set circumstances and the steps AGA takes to ensure the safe and continual supply of natural gas.

The initial Natural Gas Kitchen has been built and launched in Jandakot as part of the new headquarters for ATCO Gas, in 2014. The concept will be extended to the northern suburbs through the introduction of a second café style kitchen to be based at the company’s new northern depot that is proposed for Osborne Park.

The project costs for this phase will cover:

• Construction of a commercial grade kitchen, including:

• Outside Alfresco

• Conference facilities

• Supporting, preparation area

• Recruitment of the necessary resource to:

• Lead the overall management of the day-to-day operations at the premises

• Co-ordinate functions and events

• Develop the roll out program including supporting collateral that includes messaging on safety with regard the use of natural gas, appliances and steps to take in certain situations

The primary objectives of the ATCO Natural Gas Kitchen are:

• Creating a source of knowledge for Western Australians on the safe, reliable and economic use of natural gas

• Raising overall awareness of the benefits of natural gas to all classes of consumers

• The importance of safety when using natural gas appliances and how to respond in certain situations

• Modernise the image and promote innovation in the use of natural gas

• Raising overall awareness of the role AGA plays in the delivery of natural gas



Secondary benefits of the AGA NGK include:

• Increasing the average annual customer consumption in key tariff classes, which will ultimately drive down charges

• Maximising the number of connected customers and connected appliances in Western Australia

• Influence the purchasing decisions of consumers, home builders, home renovators, commercial business owners and industrial customers toward natural gas use

The café style kitchen in the company’s new north depot will enable the business to better service the Perth metro area and reach a wider audience.

3.5.7 Growth Financial Forecast for Non-Network Capital Expenditure

ATCO Gas Australia forecasts $38.4 million of capital expenditure on structures and equipment for the AA4 period. This expenditure covers the costs associated with owning and operating depots, fleet, plant and equipment. Expenditure includes:

• Operational depots and training centre: expenditure required to redevelop the training centre and warehouse at the Jandakot site and also to establish new depots to enable emergency response times to be met and to properly house the growing workforce, fleet and emergency equipment

• Fleet: expenditure on, vans, utilities, trucks, motorbikes, trailers, compressors, excavators and passenger vehicles

• Plant and equipment: expenditure on plant and equipment such as high and low pressure flow-stopping equipment, underground services detection equipment, gas detectors and polyethylene welding equipment

Table 26 summarises forecast capital expenditure for structure and equipment for each category to meet forecast demand.

Table 26: Fleet, Plant and Equipment required to meet Demand

Project Description 2H 2014 2015 2016 2017 2018 2019 Total ($’000)

Operational Depots & Training Centre 1,000 14,300 1,200 800

17,300

Fleet 2,100 1,200 800 1,400 4,600 4,400 14,500

Plant and Equipment 600 1,200 1,500 1,300 1,000 1,000 6,600

Total ($’000) 3,700 16,700 3,500 3,500 5,600 5,500 38,400

To deliver a safe and reliable service to its customers ATCO Gas Australia will own and operate purpose designed operational depots, fleet and supporting equipment. This will help to ensure it meets Safety Case obligations for a timely and effective response to network events over a growing network footprint and customer numbers over the long term. Through a financial assessment, it was determined that the lowest sustainable cost is achieved through a prudent long term ownership strategy, which means lower costs to customers due to reduced operational expenditure. Ownership and efficient operation of plant and fleet allows ATCO Gas Australia to deliver value to customers while providing the flexibility to adapt to changing customer and operational demands.

ATCO Gas Australia’s investment proposal in structure and equipment is driven by this AMP, which includes the requirements for depots, fleet, training facilities designed to meet Safety Case obligations.



4. Lifecycle Management Plan Lifecycle management plans have been developed to provide sound justification for owning and operating the network and to provide an overview of the lifecycle activities at the asset class level. Linkages to the AMP are used where appropriate, but the lifecycle management plan, financial summary and improvement and monitoring plan are discussed at the asset class level.

4.1 Pipelines, Mains and Services Lifecycle Management Plan The asset class described in this section are pipelines, mains and services covering the high pressure, medium pressure and medium/low pressure networks for material types Galvanised Iron, Cast Iron, Protected and Unprotected steel, Polyethylene (PE) and Poly-Vinyl Chloride (PVC).

Assets included are pipelines, mains and services used within the GDS to distribute natural gas. These are divided into sub-classes including:



• Steel Pipelines with MAOP’s of 1,920kPa (Class 150 High Pressure)

• Steel Pipelines with MAOP’s of 700kPa (Class 125 High Pressure)

• Steel Mains with MAOP’s of 350kPa (Class 125 City High Pressure)

• Polyethylene Pipelines with MAOP of 600 – 700kPa (HP PE)

• Polyethylene Mains and Services with MAOP of 350kPa (PEHP)

• Mains and Services with MAOP of 100kPa (Medium Pressure (MP))

• Mains and Services with MAOP of 20kPa (Albany MP)

• Mains and Services with MAOP of 7kPa (Medium-Low Pressure (MLP))

The lifecycle management plan outlines key areas of how the asset is managed throughout its lifecycle stages from conception through planning, design, construction, operation, maintenance and replacement/disposal. This plan has been developed in accordance with key service objectives in accordance with the Company’s Safety Case. Key projects and activities for these lifecycle stages are listed in the sections below.

4.1.1 Future Demand

All new demand projects for the pipelines, mains and services asset class are constructed in PE or steel.

4.1.1.1 Mains and Services – Customer Initiated Capital

New mains and services are demand based customer initiated capital expenditure. The Gas Distribution Licence GDL 8 requires that the Network Operator must offer to connect any service that is on line of gas main with up to 20 metres of service line, and accompanying gas meter incorporated, as the “Service Connection”. This is an automated process with connection requests being made via the retailer before being verified and allocated for construction to subcontractors.

Forecast mains and services for new connections influence a significant proportion of the total network capital expenditure. From the Economics Consulting Services forecast each year for the number of dwelling starts in WA, new connections are divided into three connection types: (1) new developments, covering greenfield subdivisions; (2) infill, covering brownfields developments in existing suburbs, and (3) new family units, which cover clusters of new connections, typically in existing suburbs. A summary of the quantities of each of these major connection types and their associated costs are summarised in Table 27.



Table 27: New Services Costs New Developments (SN3) Infill/Established (SN2) New Family Units (SNG, SNH)

Services Units [#] Rate [$/#] Total Cost Units [#] Rate [$/#] Total

Cost Units [#] Rate [$/#] Total Cost

Actual 2011 13,061 $824 $10,766 930 $1,381 $1,284 4,679 $445 $2,083

Actual 2012 10,595 $840 $8,897 752 $1,635 $1,230 2,938 $480 $1,410

Actual 2013 12,738 $860 $10,960 845 $1,757 $1,485 3,295 $525 $1,730

2014 12,450 $890 $11,081 965 $1,808 $1,745 4,200 $369 $1,552

2015 12,613 $888 $11,199 817 $1,874 $1,531 4,260 $367 $1,565

2016 12,632 $870 $10,994 818 $1,832 $1,499 4,260 $357 $1,522

2017 12,632 $866 $10,944 818 $1,824 $1,493 4,260 $355 $1,513

2018 12,632 $876 $11,067 818 $1,850 $1,514 4,260 $360 $1,535

2019 12,632 $875 $11,049 818 $1,848 $1,512 4,260 $360 $1,532

TOTAL 111,984 $96,957 7,582 $13,293 36,412 $14,441

Connecting the new services to the GDS requires new mains to be constructed, which are classified into three types: (1) open trench, which is used for greenfields developments, (2) feeders, which are used to identify mains required for new family units, and (3) mains extensions, which are used to supply gas to non-reticulated areas of existing developments. Table 28 summarises the quantities and costs for installing these mains.

Table 28: New Mains Costs

New Developments (Open Trench) New Family Units (Feeders) Gas Mains Extensions

Mains Units [m] Rate [$/m]

Total Cost Units [m] Rate

[$/m] Total Cost Units [m] Rate

[$/m] Total Cost

Actual 2011 168,845 $36 $6,095 84,620 $39 $3,319 2,514 $212 $533

Actual 2012 139,148 $37 $5,092 67,907 $46 $3,124 3,135 $162 $508

Actual 2013 173,973 $40 $6,923 76,544 $50 $3,791 4,841 $195 $946

2014 185,016 $49 $8,981 95,899 $51 $4,873 5,182 $143 $741

2015 170,883 $48 $8,268 88,574 $50 $4,470 4,786 $140 $672

2016 164,459 $47 $7,808 85,244 $49 $4,216 4,606 $138 $634

2017 164,459 $47 $7,780 85,244 $49 $4,196 4,606 $137 $632

2018 164,459 $48 $7,874 85,244 $50 $4,242 4,606 $139 $641

2019 164,459 $48 $7,868 85,244 $50 $4,234 4,606 $139 $641

Total 1,495,699 $66,690 754,519 $36,464 38,882 $5,948

These tables are used to derive the total expenditure required to meet the future demand for new connections.

4.1.1.2 Spurline – Two Rocks

The North Metro HP network currently provides gas supply to more than 390,000 consumers. The North Metro HP network is supplied by three Pressure Reducing Stations (PRS) at Pinjar, Neaves Rd; Ballajura, Marshall Rd and East Perth, Summers Street. In the event of gas outage from Neaves Rd, Ballajura PRS is only capable of supplying gas into the North Metro HP network up to Ocean Reef Rd. This will cause the pressure within the northern part of the North Metro HP network to drop below the level that will not support the high pressure regulators (HPR), which supply gas to the medium pressure networks. At this condition, the pressure within the medium pressure and medium-low pressure networks will deteriorate rapidly unless consumer gas supplies are curtailed. The effectiveness of the curtailment will determine the survival of the medium and medium-low pressure networks



and the extent of the networks being maintained above minimum operating pressures. The curtailment will result in more than 60,000 consumers to be without gas supply.

Reinstating gas supply to these consumers will involve widespread purging of consumer’s pipework and may also include purging sections of the medium and medium-low pressure networks that are below positive pressure resulting in air becoming entrained in the networks. Gas supply reinstatements and consumer relights will result in many consumers having an extended outage of gas supply. The interconnected networks will also present logistic and safety issues for the purging activities causing further delays in gas being able to be reintroduced into the network. This risk is assessed as catastrophic using the AGA risk model for both loss of supply and financial impact.

To ensure continuity of gas supply, it is proposed to construct a 44km steel pipeline comprising of 20km DN250 lateral with MAOP of 6900kPa from the transmission supplier, Dampier to Bunbury Pipeline, and 24km DN300 with MAOP of 1900kPa and install a PRS. The Class 150 DN300 steel pipeline will be tied-in to the existing Class 150 pipeline at the junction of Wanneroo Rd and Hester Ave. The proposal will also accommodate potential consumers from developments in the North West Region, predicted to be a high growth area over the next 20 years, as identified in the WA Department of Planning reports.

The construction of this pipeline will provide a security of gas supply to North Metro HP network, will accommodate Greenfield developments in the North West Region area and mitigate the business’ catastrophic consequence in terms of loss of supply and financial.

Figure 12: Two Rocks Spurline



4.1.1.3 Spurline - Peel Region

The Peel Region is expecting significant growth in greenfield residential and commercial developments. AGA forecasts $32.3 million is required in 2018 to 2019 to maintain security of supply for 29,000 customers in the event of an interruption to the Mandurah Gas Lateral pipeline.

The first stage of the proposed pipeline (7.1km x DN150 ST CL150) will connect the Rockingham steel high pressure pipeline to the high pressure PE pipeline in South Yunderup through a HPR. This will provide gas supply to the entire Austin Lakes development. The pipeline will allow the Austin Lakes development to be operated at a Polyethylene High Pressure (PEHP) pressure and support more growth in the surrounding areas.

Network modelling indicates the Pinjarra high pressure network will be under-capacity by winter 2017. As part of this project, 3.2km of DN150 CL150 HP steel main will be constructed in 2016 from the outlet of Pinjarra Gate to the tee before HS016. The Pinjarra CL150 reinforcement is an important aspect of the Peel region long term strategy to ensure supply to existing customers and increase capacity to facilitate the connection of new customers.

The final stage (15.6km x DN150 ST) connects to the CL150 ST pipeline Pinjarra high pressure network at HS016. This will reinforce the Pinjarra network and ensure security of supply to the medium pressure Pinjarra distribution network. This pipeline is essential to economically grow the gas network and has the capacity to supply gas to future domestic and commercial developments in the Peel region. Directions 2031 forecasts the Peel region will grow by an additional 10,750 residential dwellings and several industrial sites in West Pinjarra, Greenlands and Waroona. The route of the proposed pipeline has been selected to accommodate these greenfield developments.

In addition to the total 25.9km of DN150 CL150 ST spurline a new gate station is required on the DBNGP transmission pipeline.

Figure 13: Peel Spurline



4.1.1.4 Spurline - Baldivis

The Baldivis/South-Keralup region is located approximately 4km east of ATCO Gas Australia’s steel pipeline with MAOP of 1900kPa in Rockingham. This region aspires to include sustainable Activity Centres that attracts investment and provide for the full range of a resident’s needs that includes shopping leisure and employment. The district structure plans suggest that this region will contain more than 63,000 people and be serviced by an integrated transport network.

The “Vision for Keralup” document by the City of Rockingham has indicated that the Department of Housing has set a target of commencing development in 2014. However, a decision to commit to the development of Keralup is yet to be made by the State Government. In September 2012, an approval was given to the Keralup development to move from Rural to Urban Deferred zoning. Along with 5000 other lots in the wider Baldivis South area, the Keralup development awaits the lifting of the deferment.

To facilitate proper and efficient expansion of the network, it is proposed to construct a steel pipeline with MAOP of 1900kPa which will support the above developments. The pipeline will provide the ability to grow the network efficiently as well as ensuring the capacity to connect developments growing around the pipeline. It is also more cost effective to construct the pipeline in a Greenfields project than to wait for the developments in the area.

As the staging of the Baldivis South-Keralup development is to be finalised. The rezoning of this region was recently approved and a review of the economic model will be required as this project approaches its anticipated commencement date in 2018. On the proviso that the overall economic value of the expenditure is positive, this project will conform to the National Gas Rules 79.

Figure 14: Baldivis Spurline

4.1.1.5 Network Reinforcement Program



As described in the Demand Management Plan above, ATCO Gas Australia utilise industry accepted SynerGEE Gas software to model the network under current and forecast-loading scenarios. The severe winter models are used to identify all network reinforcement projects. These reinforcements ensure that the various networks under peak winter condition will continue to facilitate growth of the area, operate above the minimum allowable pressure and maintain continuity of gas supply to consumers’ appliances for safe operation.

Providing capacity for future connections and continuity of gas supply avoids the risks associated with loss of supply as well as the need for consumer curtailment and subsequent de-pressurisation, network purging and consumer relights.

Without these projects, forecast growth in the areas could not be accommodated and the issue of low pressure events exists that would cause consumers to lose supply intermittently in the immediate term to frequent supply loss in future years, along with increased operating expenditure of associated relight costs.

Further impacts, due to lack of system pressure/capacity, would be such things as negative publicity as a result of gas outage, potential claims from consumers and increased scrutiny from the Regulator will not be addressed.

4.1.1.6 Capel to Busselton reinforcement

Busselton is forecast to have a population growth of 3.1%, which is above the state average for the South West region. By 2026, it is expected to have a population greater than 55,000.

Gas is currently being supplied by a PE pipeline from Capel operating at an MAOP of 600kPa. This pipeline is limited in capacity and without this high pressure reinforcement project, the HPR in Busselton will not have sufficient pressure and capacity to connect new customers to grow the network or maintain supply gas demands to the area.

Potential low pressure condition exists within Busselton region that would cause consumers to lose supply intermittently in the immediate term to frequent supply loss in future years, along with increased operating expenditure of associated relight costs. Implementing this project will address this lack of capacity and facilitate the growth in new connections.

Figure 15 below shows the location of the Capel to Busselton reinforcement.

Figure 15: Capel to Busselton Reinforcement



4.1.1.7 Elizabeth Quay and Perth CBD Risk Reduction

A $14.2 million investment is proposed between 2014 and 2016 to reinforce and rationalise the Perth CBD network. Perth’s Metropolitan Redevelopment Authority (MRA) is initiating a requirement for 5-Star Green Star certification for two current major projects: Perth City Link and Elizabeth Quay. Historically, the MRA only required new developments to be equivalent to the 4-Star Green Star benchmarks. A method of achieving a 5-Star rating is to utilise tri-generation technology where natural gas is used to produce electricity on site, while capturing any waste heat to provide heating and air conditioning. Perth City Link involves the development of 19 lots and Elizabeth Quay involves the development of 9 lots that may potentially use tri-generation technology. Construction for both of these developments has commenced and as such, execution of this project may be required in 2014 to coincide with existing excavation activities to reduce significant reinstatement costs and public disruption.

Figure 16: Elizabeth Quay and CBD Risk Reduction

The City High Pressure (CHP) network is currently operating at 200kPa and fed through four HP regulator sets (HPR) from the 1900kPa High Pressure network on Wellington St. This portion of the High Pressure network is the oldest stock of high pressure pipeline having been constructed in the 1970s. ATCO Gas Australia manages its assets so as to minimise the whole of life asset cost while managing risks to As Low as Reasonably Practicable (ALARP). To reduce the risk of this high pressure asset within the CBD, it is proposed to reduce the operating pressure of the High Pressure network from 1900kPa to 700kPa. This involves downgrading the 1900kPa high pressure running through Wellington St and Palmerston St, to operate at 700kPa and the installation of a 3 HPRs to support the network.

The likelihood of a network event on the HP 1900kPa pipelines is reduced through controls such as pipeline patrol, high pressure spotters and the dial before you dig services, however the likelihood of an event cannot be eliminated. Evidence of minor strikes that have led to coating damage and corrosion has been identified through pipeline condition assessments.



As a prudent operator, it is proposed to reduce the operating pressure and thereby consequence of a network incident occurring in this highly populated and sensitive location within the Central Business District.

Current modelling indicates that the CHP network has sufficient pressure and capacity to supply gas to the Perth City Link project; however, for the Elizabeth Quay project, the existing CHP network does not have the capacity to supply the assumed tri-generation gas loads without a 2km mains extension, operating at 700kPa. The recommended route for this mains extension from the High Pressure main on Wellington St is along Barnett St and Riverside Drive.

To ensure security of supply to Elizabeth Quay and the wider CBD area an additional 3km main, operating at 700kPa, is required. The recommended route for this main is along St Georges Tce, Milligan St and Wellington St. The route requires installation of a HPR on the corner of Wellington St and Loftus St. In addition, there are existing mains following this proposed route.

In summary, this project requires 5km of DN 150ST (MAOP 700kPa) and a HPR to connect the tri-generation load from Elizabeth Quay. This option also involves downgrading the 1900kPa high pressure main running through Wellington St and Palmerston St, to operate at 700kPa and requires an additional 3 HPR’s.

4.1.2 Operations and Maintenance

Maintenance on the pipelines, mains and services are scheduled in SAP Maintenance Plans. A summary of the key maintenance activities are:

• MAOP Reviews

• Inspection of Exposed Pipes

• Bridge Crossing Inspections

• Leakage Surveys

• Pipeline Patrol

• Isolation Valve Maintenance

• Pipeline Inline Inspections

• Gas Sampling

4.1.2.1 Leak Survey

The requirement of performing leak surveys on high pressure pipelines operating at greater than 1050kPa is outlined in AS2885.3-2001. The high pressure GDS is leak surveyed to align with those pipelines scheduled for MAOP review. The survey ensures that every part of the network is surveyed at intervals not exceeding 5 years.

AS 4645-2005 (section 6.2.5) outlines a leak survey, that includes the immediate area surrounding a HP valve and regulating facility with exposed pipe work and fittings, which is to be conducted in conjunction with facility maintenance activities. This standard also requires high risk locations to be surveyed at more frequent intervals than other locations as confirmed in the FSA. The additional high risk leak survey has required further resources due to the 780 currently identified locations, leading to a step change in operating costs.

4.1.3 Renewal/Replacement

Asset renewal strategies have been established to ensure AGA’s assets function within the requirements of the Safety Case and are based on information from condition and performance assessment, monitoring and modelling. The FSA has established the requirements for replacement programs to reduce the risk of loss of containment and leak tracking into a building to ALARP. Pipeline replacement decisions require an assessment of the safety risk along with the trade-off between a current capital cost and likely ongoing operations and maintenance (O&M) expenses. While the replacement of mains requires a substantial capital outlay, the continued presence of older mains and services contributes to higher O&M costs associated with more frequent inspections and



responding to suspected gas leaks. The pipe vintage, material and overall condition of surrounding facilities dictate the particular strategy that is likely to be most cost effective. The occurrence of leaks along a particular section of pipe is initially addressed through repair and subsequent monitoring. However, the number and severity of leaks along pipe segments typically accelerates over time. As a consequence, replacement eventually becomes more cost-effective than continued repair.

The Pipeline and Hazardous Materials Safety Administration (PHMSA) of the U.S. Department of Transportation is urging action on repairing older, more leak-prone systems. U.S. PHMSA, March 2012, advises natural gas owners and operators to conduct a comprehensive review of their cast iron distribution pipelines and replacement programs; and accelerate pipeline repair, rehabilitation and replacement of high-risk pipelines. It also requests state agencies to consider enhancements to cast iron replacement plans and programs.

Learning from international incidents and advisories, AGA has developed an accelerated replacement program of pipelines considered higher risk due to their age, maintenance history and location in populated areas. An accelerated replacement program will provide AGA with the capability to replace and upgrade older system components on a broader and faster scope. It will enhance system safety, as well as reduce emissions through leak-prone systems.

The advantages of an accelerated replacement program are:

• Alignment and compliance with the requirements of Safety Case including the reduction of risks associated with these assets to ALARP in accordance with the requirements determined as part of the FSA

• Replacement of aging and more leak-prone infrastructure in a more comprehensive and timely manner

• Reduction of leaks on a broader scale rather than more piecemeal approach

• Reduction of methane emissions from more leak-prone system components (i.e., older bare steel and cast-iron segments)

• Elimination of lag between when the capital investment is made and recovery in rates

• Increase in system integrity

• Increase in system safety

• Increase in jobs for work crews resulting from capital commitment and work scope

• Better utilization of operations and maintenance funds and cost stabilization

• Achievement of safety and reliability benefits more rapidly

• Cost savings resulting from increased scale through comprehensive planning, geographically-focused replacement efforts and the efficient use of outside contractor services

• Less disruption and improved coordination with affected municipalities

• Efficient deployment of capital for safety and reliability through a reduction in emergency repair efforts

Table 29: Replacement Quantities for Metallic Mains Replacement Program

Replacement Program 2H 2014 2015 2016 2017 2018 2019 Total [km] Odd size steel 5 5 5 5 5 8 33 Unprotected metallic mains 5 21 22 22 28 38 133 Cast iron 8 12 13 13 12 - 58 TOTAL [km] 16 38 40 40 45 46 224



Additionally, current economic and natural gas market conditions support the acceleration of pipeline replacement activities while natural gas commodity costs are low and job creation is a national and local priority.

Metallic mains replacement program includes the replacement of cast iron, odd-sized steel and unprotected metallic mains. The replacement of these materials is planned to follow the quantities described in Table 29 with the remaining quantities in the GDS being illustrated by Figure 17.

Figure 17: Remaining Lengths of Mains in Service during Metallic Mains Replacement Program

4.1.3.1 Metallic Mains and Services

Metallic mains included in this replacement program are either non anti-corrosion coated or not protected by cathodic protection systems, and were installed between circa 1915 and the 1960’s. The mean annual leak rate for unprotected steel mains is more than ten times the average leak rate for the balance of the Company’s network.

Due to their age, the coating on many of these pipes is disintegrating and ineffective, leading to aggressive crevice corrosion and pitting resulting in perforated leaks. With non-existing or deteriorating coating systems these pipes will continue to deteriorate, thereby increasing the likelihood, and therefore risk, of gas escapes and associated reactive maintenance. The risk associated with these assets is not ALARP due to the risk of loss of containment and leak tracking into a building.

The Galvanised Iron (GI) pipes were coated with zinc to protect from corrosion and these pipes were commonly manufactured with screwed ends and their joints have gradually deteriorated resulting in increased risk of leaks and reactive maintenance.

Most of these ageing mains were also used to transport manufactured gas prior to the introduction of natural gas to the Perth metropolitan areas. This ‘wet’ gas had high water content that has resulted in internal corrosion and “residue” collecting along the mains, causing partial or full blockages. The full extent of blockages on these mains is unknown, but has led to increased risk due to inability to flow stop effectively and efficiently in the event of a network emergency and has consequently increased the risk of supply interruption to consumers.



4.1.3.2 Odd-Sized Steel Mains and Services

ATCO Gas Australia identified the risk associated with odd size unprotected steel mains as not being ALARP, due to the inability to isolate a localized section with standard flow stopping equipment, particularly in the case of emergency repairs.

Odd size steel pipes to be included in this replacement program range from 230mm to 635mm in diameter and were generally used as trunk mains that support a wide distribution area. Without the ability to use standard flow stopping equipment, isolating these mains disrupts the continuity of gas supply to a far greater number of consumers. These consumers are affected by all network activities on these mains that require isolation, such as altering alignment and sectional replacement, as well as emergency repairs.

In addition to the above operational risk, the majority of the existing odd size steel trunk mains were constructed between 1960 and 1970 with no cathodic protection as they were manufactured with coal tar enamel coating. Due to their age, the coating on many of these pipes is disintegrating and ineffective, leading to aggressive crevice corrosion and pitting.

4.1.3.3 Cast Iron Mains and Services

ATCO Gas Australia operates cast iron with embedded unprotected steel within the Fremantle area. Gas mains in this area date back to the late 19th century when they were used to supply manufactured town gas. In order to meet growth in demand the operating pressure was previously increased from 1.5kPa to 5kPa. Network modelling on the current network indicates that it will not support the forecasted gas requirements. Increased operating pressure has resulted in a greater number of leaks, leading to increased reactive maintenance costs and UAFG. Low pressure leaks do not disperse easily and tend to accumulate close to the ground, increasing the risk of gas tracking into buildings.

To improve security of supply and to improve the safety and integrity of gas mains and services, a replacement program has been implemented. This program has been staged to replace approximately 7kms of cast iron and 6km of embedded unprotected steel mains each year, with completion forecast in AA4.

The replacement program includes the installation of medium pressure regulators at each meter so the area can be upgraded to medium pressure. This is a long term solution that ensures network integrity, continuity of supply to customers and capacity to accommodate increasing demand.

4.1.3.4 PVC Mains and Services

PVC was first introduced into the network in 1963 and became the material of choice for mains and services. In 1993, polyethylene (PE) mains and services were introduced and in 2003 PE became the material of choice.

The dominant failure modes causing leaks on the PVC network are: (1) deteriorated rubber O-rings used by mechanical fittings, such as service tees, tapping bands and compression couplings, and (2) pipe brittleness for some of the older mains. Further investigation has indicated increased fault rates for mains with a diameter 100mm and greater and PVC faults contribute to more than 80% of the annual reactive maintenance cost on mains. Replacing PVC mains and services with PE removes these dominant failure modes and provides a fully fused solution, increasing network integrity and safety.

A network FSA was conducted as part of AGA’s Safety Case and it identified locations with elevated consequences from leakage from the PVC network. The FSA identified the need to address faults for mains where gas escapes could track into buildings in locations within high community use areas as defined in AS4645 and recommended a targeted replacement program of old uPVC pipes with high fault rates and located in high density community use areas. The replacement plan is to replace 17km of uPVC pipes greater than 100mm diameter during AA4.



As part of the targeted replacement, pipe samples will be taken and physical testing will be carried out on these pipes to determine the remaining anticipated operational life. This will be a key input in improving the reliability model for PVC mains, which will inform future replacement programs.

4.1.3.5 End of Life Replacement - Isolation Valves

The dominant failure mode on steel type main isolation valves are gear or stem seizures due to corrosion. Corrosion on valve gears and stems can cause difficulty in valve operation where high torque is required to turn the valve. In severe corrosion condition, valves can be completely seized and cannot be closed. The second common failure mode is valves leaking due to gasket or O-ring failure. O-rings are installed on valve steams while gaskets are installed on valve flange joints. These sealing materials are made of rubbers that tend to degrade over time. Degradation of rubber O-rings and gaskets can be accelerated by contaminants. Some of these valves are located in pits within high water table areas resulting in a damp and corrosive environment, which increases the rate of corrosion.

A condition based replacement strategy has been established to develop a risk ranked replacement program for main isolation valves. Identified valves are inspected on a yearly basis and assessed in terms of valve functionality, grade of corrosion and leaks. During inspections, valves are tested for correct functionality and graded as either being seized, tight or in good operating condition.

4.1.3.6 End of Life Replacement - Service Valve

Based on results from leak surveys and Smell-of-Gas (SOG) repair data on PVC mains, there are high leak rates on plastic service valves located in older suburbs. Leaks on plastic service valves are mainly caused by a degraded rubber O-ring over time. These O-rings are found at the valve spindle as well as the inlet and outlet joints. Using maintenance history data from SAP, the characteristic life for plastic service valve was calculated to be 20 years, which indicates that these valves have a high likelihood to leak after 20 years in service.

The older suburbs have a larger population of plastic service valves aged more than 20 years, resulting in a higher valve failure rate compared to relatively newer suburbs. To mitigate the risk associated with gas leaks and to facilitate effective means of isolation in an emergency, the project recommends that the aged service valves be replaced with new brass forged-body valves. The brass valves have a longer service life and improved reliability compared to plastic service valves.

4.1.3.7 End of Life Replacement - Mains (AH)

Due to limited accessibility to condition assessment information on buried low pressure pipelines, not all replacement activities can be accomplished on a planned basis. While some sections of pipe are addressed immediately to resolve a critical safety or reliability concern, opportune condition assessments are performed during these remedial actions. The project entails the increase in scope of the planned replacement programs with the replacement of sections of mains that are in poor condition that were unforeseen at the time of adding mains to planned replacement programs and is considered prudent and efficient to be replaced before the following year’s planned replacement program. This project is required to reduce public hazard, maintain employee safety and ensure supply continuity. This project has estimated 1km of main to be replaced annually.



4.1.4 Network Safety and Performance Improvement

There are several major improvements for network safety and performance being targeted for this period. These are the:

• inclusion of inline inspections (pigging) for high pressure pipelines

• development of a formalised program for impact testing PVC mains

• implementing various data management enhancements to SAP

• implementing various data management enhancements to GNIS

• implementing enhancements to AWB models

• adoption of AS4645.1 KPIs to monitor network performance

These improvements will lead to a better understanding of failures and their respective root causes, leading to better information for decision-making that will allow maintenance and replacement strategies to be continually improved.

4.1.4.1 Security of Supply - Transmission Interconnections

Transmission gate station interconnections provide the only gas supply points into the GDS. Currently there are 14 gate stations supporting approximately 683,000 customers. Thirteen of these gate stations supply gas from the Dampier to Bunbury Natural Gas Pipeline (DBNGP) while the remaining one, supplies gas from APA Group’s (APA) Parmelia Pipeline.

During the Varanus Island outage, gas supplies in the DBNGP were restricted by 30%, which lead to curtailment of customers on the GDS. Since the outage, APA have commissioned Mondarra storage facility and further expanded it in 2013. In the event of a future supply interruption on the DBNGP and in order to safeguard supplies to residential customers, it is prudent to establish interconnects to the Parmelia pipeline to enable access to this gas available within the Mondarra storage facility.

ATCO Gas Australia proposes to install six additional gate station interconnects to the Parmelia Pipeline within the Perth metropolitan area to ensure security of supply under its AS/NZS4645 obligations.

4.1.4.2 Security of Supply - Interdependency

In accordance with AS/NZS4645.1 the Network must be designed and constructed to ensure security of supply to customers. Using industry standard modelling software, a network study identified critical high pressure regulators (HPRs) where the interruption to such HPRs may result in loss of supply to more than 25,000 customers. Loss of supply to 25,000 customers is considered a catastrophic event in accordance with ATCO Gas Australia’s risk matrix (consistent with the risk matrix prescribed in AS/NZS 4645).

Ten high pressure mains affecting 17 pressure reduction facilities must be constructed to reduce the risk of loss of gas supply to greater than 25,000 consumers during a network event on a high pressure pipeline or existing HPR to as low as reasonably practicable. Constructing these high pressure pipelines will facilitate an optimum HPR supply arrangement by positioning the HPRs at appropriate locations to supply gas to lower pressure distribution networks reliably.

This project will mitigate the risks associated with loss of supply such as:

• Air entering the network resulting in a potentially explosive gas and air mix

• Network isolation and de-pressurisation

• Consumer curtailment

• Network purging

• Consumer relights



Table 30: Critical HPRs Requiring Support

Project Name Proposed Reinforcement HPR No. of

customers affected

AS4645 Interdependency - Hillarys Marmion Loop, 13.2 x DN200 ST HP (MAOP 1900kPa)

Install 1 new HPR and 2 isolation valves

HN043

HN061

HN051

27200

50400

50400

AS4645 Interdependency - Canning Vale

7km x DN 150 ST (MAOP 1900kPa)

1.5km x DN160 PE MP (MAOP 70kPa) along Fraser Rd


HS080

HS038

HS037

24700

42000

24700

AS4645 Interdependency - Kingsley 6km x DN 150 ST HP (MAOP 1900kPa) along Hepburn Ave

6km x DN 225 PE MP (MAOP 70kPa) along Hepburn Ave

HN026

HN065

22000

25100

AS4645 Interdependency - Armadale 1.8km x DN 225 PE MP (MAOP 70kPa)


HS005

HS070

24485

23515

AS4645 Interdependency - Murdoch 1.1km x DN160 PE MP (MAOP 70kPa) mains extension HS008 25000

AS4645 Interdependency - Lathlain 5km x DN 150 ST mains extension HP (MAOP 1900kPa)

Install 2 New HPRs and 4 isolation valves

HN020

HS082

40000

26000

AS4645 Interdependency - Fremantle 2.5km x DN160 PE MP (MAOP 70kPa) HS054 28000

AS4645 Interdependency - Subiaco Install 1 New HPR and 2 isolation valves HN055 25100

AS4645 Interdependency - Melville 2.5km x DN160 PE MP (MAOP 70kPa) HS063 21532

AS4645 Interdependency - Scarborough 1.5km x DN160 PE MP (MAOP 70kPa)

Install 1 New HPR and 2 isolation valves HN050 24853

4.1.4.3 Pipeline In-Line Inspections

High pressure gas steel pipelines operating above 1050kPa are operated and maintained in accordance with AS2885.3 Pipelines – Gas and liquid petroleum Part3: Operation and maintenance.

All of ATCO Gas Australia’s HP steel pipelines (all pressure classes and locations) currently operate below the AS2885 maximum allowable hoop stress limit of 30% SMYS in populated areas (refer to AS2885.1:2012 Section 4.7.2).

Remaining life review assessments must be conducted at maximum 10-year intervals in accordance with AS2885.3:2012 Section 10.3 requirements. In-Line-Inspection (“Intelligent Pigging”) or metal loss defect examinations are essential for HP steel pipeline reliability assessments and are regarded as good industry practice for pipeline integrity management and safety.

An In-Line-Inspection (ILI) program will provide a baseline of internal corrosion, unidentified external damage and enable pipeline assessment in areas not previously accessible to surface dig-up inspections, such as water course and major road/rail crossings, thereby ensuring integrity of all parts of the high pressure gas pipeline network.

The pipelines listed for inspection under this category are prioritised in accordance with their age, operating pressure and risk, based on area classifications (proximity to sensitive areas).

4.1.4.4 R&D - Isolation of a Network for UAFG Investigation

Gases are compressible and change volume when placed under pressure, heated or cooled. A volume of gas under one set of pressure and temperature conditions is not equivalent to the same gas under different conditions. Measurement of natural gas contains errors due to the various conditions such as temperature, pressure, equipment accuracy and human error. Improving measurement provides higher accuracy and reductions in Unaccounted for Gas



(UAFG). UAFG is the difference between metered gas injected at various gate points into the gas distribution network and the allocated gas at customer delivery points within the network.

An opportunity exists to introduce a trial network for research and development by isolating a given area to reduce unknown variables thus reducing unknown errors and increase the ability to identify measurement improvements that can be applied to the overall network. Measurement improvements have been discussed with the technical regulator for the ERA - EnergySafety and researching measurement initiatives will benefit all parties through greater accuracy of gas measured per customer, reducing UAFG and providing valuable data for future improvements.

The trial would be based on approximately 1000 customers and the project would be split into four phases to identify baselines and measure improvements. The phases will include isolation of a section of the current metropolitan network; ability to measure inflows and consumption at high frequencies; meter changes and automation, and leak survey and repair.

4.1.4.5 Isolation Valves - Northbridge Isolation

Northbridge is currently not included in the Perth CBD emergency isolation plan. Due to the close proximity to Perth CBD and high population density in the area, the addition of Northbridge has been identified as prudent to increase network safety and efficiency in isolation in case of an emergency. With the installation of two isolation valves, this project will enable Northbridge to be isolated as part of this plan.

4.1.4.6 Facility Upgrade - Security & Danger Signs

To increase safety to the public, adequate warnings about the danger of entering a high pressure facility are required. This project is necessary to install facility signage (security and danger signs) at 20 PRS sites where signs are missing, damaged or illegible.

4.1.4.7 AS2885 HP Signs - Compliance to New Requirements

This project is required to ensure compliance with AS 2885.1 by the installation of warning and prohibition signs at facility compounds on all fences as well as intervisible warning signs along high pressure pipelines.

This capital project will also reduce the risk of loss of containment arising from potential third party damage, assist in protecting ATCO Gas Australia assets and public by providing additional warning signage for high pressure gas assets.

4.1.5 Asset Class Financial Forecast

Forecast expenditure for the forecast period is summarised in Table 31 below.

Table 31: Summary of Pipelines, Mains and Services Expenditure

Project Description 2H 2014 2015 2016 2017 2018 2019 Total ($'000s) GROWTH CAPEX $7,801 $18,782 $31,944 $22,805 $21,280 $14,364 $116,976


Variable Volume Mains - Growth $5,096 $8,940 $8,442 $8,412 $8,515 $8,509 $47,915

Demand $2,705 $9,842 $23,502 $14,393 $12,765 $5,856 $69,062

Elizabeth Quay & Perth CBD Risk Reduction Project - Growth 60% $1,960 $3,112 $4,200 $9,271

Reinforcement - Albany Hwy, Vic Park $23 $23

Reinforcement - Amelia St, Balcatta $59 $59

Reinforcement - Bolton Ave $262 $262

Reinforcement - Capel to Busselton $5,209 $5,209

Reinforcement - Centre Rd, Kelmscott $268 $268

Reinforcement - Fisher St, Belmont $200 $200



Project Description 2H 2014 2015 2016 2017 2018 2019 Total ($'000s) Reinforcement - Gay St to Southern River Rd $296 $296

Reinforcement - Gay St to Warton Rd $34 $34

Reinforcement - Gerald St to Elizabeth St $296 $296

Reinforcement - Gildercliffe Rd, Scarborough $9 $9

Reinforcement - Hepburn Ave to Mirrabooka Ave, Alexander Heights $599 $599

Reinforcement - Karel Ave to Brockman $274 $274

Reinforcement - Karrinyup Rd, Innaloo $3,874 $3,874

Reinforcement - North West Coastal Hwy, Geraldton $854 $854

Reinforcement - Odin Rd to Mimillya St $155 $155

Reinforcement - Orlando St, Kelmscott $108 $108

Reinforcement - Pinjar Rd, Carramar $65 $65

Reinforcement - Pinjarra $5,378 $5,378

Reinforcement - Ranford Rd and Warton Rd $646 $646

Reinforcement - Ravenswood Rd $260 $260

Reinforcement - Secret Harbour $290 $290

Reinforcement - South Perth $502 $502

Reinforcement - Station St to Luger Ave, East Cannington $175 $175

Reinforcement - Tyre Ave, Riverton $152 $152

Reinforcement - Vasse New Town $215 $215

Reinforcement - Warton Rd, Huntingdale $152 $152

Spurline - Baldivis $5,417 $5,417

Spurline - Peel - Growth $5,994 $5,994

Reinforcement - Drummond Cove $804 $804

Spurline - Two Rocks - Growth 60% $13,638 $13,579 $27,218



EOL Replacement - Anodes $18 $18 $18 $18 $19 $19 $110


EOL Replacement - Isolation Valves $70 $141 $69 $70 $71 $71 $492

EOL Replacement - Mains (AH) $200 $341 $335 $334 $338 $338 $1,885



EOL Replacement - PVC Mains & Services $239 $2,384 $2,338 $2,328 $2,355 $2,351 $11,994

EOL Replacement - Service Valves $245 $368 $362 $362 $368 $369 $2,075

EOL Replacement - TRU $18 $18 $37


Replacement - HP014, Bibra Lake $3,192 $3,192

Network Safety and Performance $587 $5,478 $16,009 $24,391 $22,095 $31,025 $99,585

AS2885 HP Signs - Compliance to New Requirements $532 $532

AS2885 Pigging Infrastructure - East Perth $1,615 $1,615

AS2885 Pigging Infrastructure - Harrow St $1,247 $378 $1,625

AS4645 Interdependency - Armadale $1,173 $1,173

AS4645 Interdependency - Canning Vale $9,409 $9,409

AS4645 Interdependency - Fremantle $779 $779

AS4645 Interdependency - Hillarys $6,619 $9,885 $16,505

AS4645 Interdependency - Kingsley $10,208 $10,208

AS4645 Interdependency - Lathlain $6,772 $6,772

AS4645 Interdependency - Melville $778 $778

AS4645 Interdependency - Murdoch $427 $427

AS4645 Interdependency - Scarborough $879 $879

Elizabeth Quay & Perth CBD Risk Reduction Project - Sustaining 40% $2,111 $2,800 $4,910

Facility Upgrade - CP Test Points $7 $7



Project Description 2H 2014 2015 2016 2017 2018 2019 Total ($'000s) Facility Upgrade - Insulation Joints & Surge Protectors $18 $18 $18 $18 $18 $18 $109

Facility Upgrade - Resistance Probes $19 $19 $19 $19 $19 $19 $114

Facility Upgrade - Security & Danger Signs $18 $18

Facility Upgrade - Step Touch Mitigation $58 $57 $57 $58 $58 $288

Isolation Valves - Northbridge Isolation $98 $98

R&D - Isolation of a Network for UAFG Investigation $306 $105 $105 $106 $106 $728

Spurline - Peel - Sustaining $10,473 $10,456 $20,929

Spurline - Two Rocks - Sustaining 40% $5,503 $12,627 $18,130

AS2885 Inline Inspection - HP107 $509 $509



AS2885 Inline Inspection - HP091 $1,730 $1,730

Total ($'000s) $17,006 $44,421 $65,279 $64,475 $63,204 $65,165 $319,549



4.2 Pressure Regulating Facilities Lifecycle Management Plan The asset class described in this section comprises of Pressure Regulating Facilities that include Gate Stations (GS), Pressure Reducing Stations (PRS), High Pressure Regulator (HPR) sets and Medium Pressure (MP) Regulator sets. These assets comprise a regulator to reduce a higher variable inlet pressure, to a lower outlet pressure that is controlled within a specified range. All GS and PRS are located in secure compounds. Majority of HPR sets are typically located in pits with larger sets having pneumatically actuated lids while some above ground HPR sets are housed in cabinets. Majority of MP regulator sets are located in pits.


4.2.1 Future Demand

Although the general medium pressure networks in the metro area are robust, with the increase in unit load, several major reinforcements and capacity upgrades for the regulating facilities asset class have been identified through network modelling.

Demand CAPEX reinforcements for these networks are conducted either by installing new mains to provide additional links within the network or by installing a new regulator set to provide a new source. Demand forecasting described above has identified upgrades to existing regulator sets and additional regulator sets required to reinforce the network to meet additional demand for natural gas. These projects are identified in Table 32.

Capacity upgrades on HPRs usually results in partial upgrade or replacement of components, whereas capacity upgrades on MP regulator sets always results in a replacement of the existing set due to the increase in pipe diameter. Occasionally, HPR or MP regulator sets are identified during scheduled maintenance activities to be replaced due to their deteriorating condition.

4.2.1.1 Regulating Facility Reinforcement and Capacity Upgrade Program

As described in the Demand Management Plan above, AGA utilise industry accepted SynerGEE Gas software to model the network under current and forecast loading scenarios. The severe winter models are used to identify all network reinforcement projects. These reinforcements ensure that the various networks under peak winter condition will operate above the minimum allowable pressure and maintain continuity of gas supply to consumers’ appliances for safe operation.

Table 32: Regulator Sets to be Upgraded

2014 2015 2016 2017 2018 2019

MS094 MN198 MN144 MS104 MN021 MS025

MS101 MS096 MS044 MS043 MN058 MN035

MS021 MN206 MS008 MN173 MN062 MN054

MS016 MN197 MS118 MN052 MS123 MN146

MS041 MN018 MN090 MS046 MN129 MN156 MS082 MS022 MN135 MS002 MN143

Providing continuity of gas supply avoids the risks associated with loss of supply as well as the need for consumer curtailment and subsequent de-pressurisation, network purging and consumer relights

Without these projects, the issue of potential low pressure events exists within the various networks that would cause consumers to lose supply intermittently in the immediate term to frequently in future years, along with increased safety risk and operating expenditure of associated relight costs. Further impacts, such as the inability to provide for future



connections due to lack of system pressure/capacity, negative publicity as a result of gas outage and potential claims from consumers will not be addressed.

Table 33: Set Pressure Upgrades

Location Pressure Upgrade Description

2014

Atwell PEHP New regset at pipeline 118 Tapper Rd and Bartram Rd to 200kPa and Pipeline 118 to operate as HP MAOP 700kPa

Banjup PEHP Increase set pressure of HS087 to 140kPa

Baldivis PEHP Increase set pressure of HS116A to 120kPa

Busselton install new regset and HS075 170kPa, new 120kPa

Ellenbrook PEHP Increase set pressure of HN041 to 190kPa

2015



Ellenbrook PEHP Increase set pressure of HN041 to 210kPa

Kalgoorlie PEHP Increase set pressure of GS020 to 230kPa

2016


Australind PEHP Increase set pressure of HS088 to 90kPa


Busselton Increase set pressure of HS075 190kPa, upgrade new 2014 regset to 130kPa

Ellenbrook PEHP Increase set pressure of HN041 to 240kPa HN083 to 180kPa

Kalgoorlie PEHP Increase set pressure of GS020 to 240kPa

2017



2018

Baldivis PEHP Increase set pressure of HS087 to 220kPa

4.2.1.2 New Supply - BD HPRs

The ability for rural land to be rezoned for residential development has led to many developers developing their tracts of land ahead of the reticulated gas distribution network front. These developments consequently jumped the expanding reticulated network where gas supply cannot be provided through mains within the distribution network. In most cases, these developments require a new initial supply through a HPR to supply gas at lower pressure.

This project is to install dedicated HPRs for new development that have jumped the normal gas distribution front. Eventually, as more developments occur within the surrounding areas and with the growing reticulated network, alternative supplies are provided through the network.




Fault data analysis demonstrates that 4 month inspections are required for ensuring the safe and reliable operation of pressure regulation facilities with inlet pressure above 350kPa (high pressure sets), while 18 months is suitable with inlet pressure below 350kPa. When the regulators are inspected and serviced, operational checks and lock-up tests are carried out.


Asset renewal strategies have been established to ensure AGA’s assets function within the requirements of the Safety Case and are based on information from condition and performance assessment, monitoring and modelling. Replacement of these facilities is considered when spare parts become obsolete, or the regulator set does not meet operational requirements. Regulator sets are subjected to a condition based renewal strategy of the components that make up the facility, typically determined by reported number of faults, operability and asset component conditions.

There is no renewal plan for any of the PRS and HPR however; there is a project to retrofit over pressure protection devices on these assets. This increased protection will reduce the potential risk of over pressurisation damage to the downstream network. The project is based around seeking compliance of the GDS to AS/NZS 4645 and AS 2885. Project evaluation meets regulatory considerations, in particular National Gas Rule 79(2)(c)(ii) integrity of assets.

4.2.3.1 End of Life Replacement - MP Pits

The AGA MLP distribution network consists of several regulators sets at various locations along the MP network that feed the MLP networks. These regulators are regularly maintained, but events occur, such as vandalism or damage caused by vehicle parking over the pit, where unplanned replacement of a regulator pit is required. This project is a provisional budget for the replacement of MP regulator pits to mitigate public hazard, ensuring employee safety and supply continuity.

4.2.3.2 End of Life Replacement – HPR

The AGA HP network consists of several HPR at various locations that feed the lower pressure networks. These HPR are regularly maintained, but events occur, such as vandalism or damage, where unplanned replacement of the HPR is required. This project is a provisional budget for the replacement of HPR to mitigate public hazard, ensuring employee safety and supply continuity.


Improvement activities for network safety and performance for pressure regulation equipment are summarised as being:

• overpressure protection

• protection against third party damage

• system monitoring

• confined space signage

• asset condition improvement

• SAP maintenance implementation

• development of a formalised renewals strategy

• optimisation of the maintenance strategy

• development of lifecycle costing models.

4.2.4.1 Facility Upgrade - OPSO Safety Devices

The previous network design, where active-monitor pressure regulators are used at pressure regulation points, did not provide full protection of downstream piping from overpressure



excursions. There is the potential for a common failure mode to affect both regulators and consequently over pressurise sections of the network.

This project is to install OPSO devices that will increase the protection of the GDS in line with the requirements of AS/NZ 4645 and AS/NZ 2885 and to comply with instructions received from EnergySafety. This increased protection will reduce the potential risk of over pressurisation damage to the downstream network.

4.2.4.2 Facility Upgrade - HPR Vehicle Protection

All new HPR sets are located below ground in pits. However, some of the older HPRs are contained in above ground kiosks. Apart from those that are in a compound owned by AGA, these HPR are usually located in the road verges. Over time, as developments grew in the vicinity of the HPR, some roads built to service these developments have become major roads. The new traffic environment poses a risk to these HPR from passing vehicle impacting with them. This may cause uncontrolled gas escape presenting a hazard to the public. It may also affect network integrity and continuity of gas supply resulting in loss of customers.

This project is to install protective barrier against vehicle collision mitigating the above risks at those identified HPR locations. Installing barriers will also provide a safe working environment and protect AGA personnel from accidental vehicle impact during scheduled maintenance.

4.2.4.3 Facility Upgrade - HPR Monitoring

The ability to provide a safe, reliable and economic gas supply to consumers is dependent on operating and maintaining the integrity of the GDS throughout the range of anticipated demand profiles including winter peaks. Monitoring the distribution system within safe operating parameters as part of operating the system will ensure continuous supply of gas to consumers within the specifications prescribed in the Gas Standards (Gas Supply and System Safety) Regulations 2000.

Data from these sites is used to validate the gas model for severe peak modelling by showing load profiles for sections on the network (metered gas volumes) delivery pressures to the network to ensure the security of supply. Upon installation of telemetry, all logged parameters can be alerted including inlet and outlet pressure, OPSO condition and flow levels.

This “HPR Monitoring” project involves the installation of flow monitoring equipment at HPR locations to ensure accurate network flow modelling. Monitoring of these sites will include alarming through current up-to-date servers and software that is reliable and removes out-dated hardware allowing AGA to deliver safe and reliable gas supply. Monitoring the outlet pressures and inlet pressures at these locations will also result in a greater understanding of the network performance in relation to the gas model for the support of expansion and integrity of the networks.

4.2.4.4 Facility Upgrade - Confined Space Signs

There are some assets within the GDS that are located below ground in pits. Some of these pits have pneumatically operated lids while others have gatic lids that require manual gatic lifters to open the pit. The size and volume of these pits presents a potentially hazardous, confined space working environment. AGA has developed a Safe Work Instruction (SWI) for personnel working on assets located in confined spaces. AGA has identified these pits and has appropriately signed them as “Confined Space”.

A review on the assessment of confined spaces has identified additional locations to be classified as confined space. This project is to install “Confined Space” signs on all newly identified locations.

4.2.4.5 Replacement - HP Regulator Pit Lids

A provisional budget for the in-part replacement of HPR sets to ensure the safe and continued operation of the assets. The type of work includes, but is not limited to, the



replacement of deteriorated regulator pit lids due to age, modification to the sense line pipework to improve accessibility and mitigation of confined space conditions by elevating the floor level to address the issue of storm water accumulating in the pit. This project is required to mitigate hazards to the public, ensuring employee safety and supply continuity.

4.2.4.6 Capacity Upgrade - PRS03 Geraldton

The existing PRS site at Geraldton consists of two pressure reduction units. The first unit supplies gas to the Geraldton Network through 1" regulators that are beginning to restrict flow to the network. The second unit was installed to provide gas to the Geraldton power station, but has been mothballed for some time as the power station was relocated. The infrastructure on this second unit is suitably sized to accommodate the increase in demand to the Geraldton area, but due to the age and time mothballed, a complete replacement of the instrumentation and removal of the existing unit is required.

4.2.4.7 Capacity Upgrade – Transmission Gate Stations

As part of the network modelling process and to ensure the integrity of the GDS, AGA relies on DBP gate station capacity to validate the outcome of the models. Five gate stations have been identified to be under or close to under capacity during a peak or severe winter condition. Harrow and Pinjarra gate stations are under capacity on a peak winter condition while Caversham, Clifton and Russell Rd gate stations will be under or close to under capacity during a severe winter condition.

Gate stations, as a source of gas supply, must have the capacity to meet network demand. The total demand from the network is compared to the capacity of the gate station supplying the particular network and an under capacity gate station will result in pressure drop within the HP system and during a prolonged period, will drop to a level where it will not support the high pressure regulators that support the medium pressure networks.

At this condition, the pressure within the medium pressure and medium-low pressure networks will deteriorate rapidly unless consumer gas supplies are curtailed. The effectiveness of the curtailment will determine the survival of the medium and medium-low pressure networks and the extent of the networks being maintained above positive pressure.

Reinstating gas supply to these consumers will involve widespread purging of consumer’s pipework and may also include purging sections of the medium and medium-low pressure networks that are below positive pressure resulting in air being entrained into the networks.

Gas supply reinstatements and consumer relights will result in many consumers having an extended outage of gas supply. The interconnected networks will also presents logistic issues for the purging activities causing further delays in gas being able to be reintroduce into the network.

AGA will also be inhibited to implement its business strategy of growing throughput and reducing the overall cost to customers, due to its inability to connect new commercial and industrial customers. To ensure continuity of gas supply and continue safe operation of the GDS, it is proposed to upgrade the identified gate stations.

AGA will fund the investment to deliver the infrastructure required, with DBNGP continuing to own and operate. This approach has been applied successfully during AA3 for the Mandurah Gas Lateral Station.




Forecast expenditure for this period is summarised in Table 34.

Table 34: Forecast Capital Expenditure - Regulating Facilities

Project Description 2H 2014 2015 2016 2017 2018 2019 Total ($'000s) GROWTH CAPEX $313 $601 $509 $470 $477 $572 $2,942

Demand $313 $601 $509 $470 $477 $572 $2,942

Capacity Upgrade - MP Regulator Sets $134 $301 $296 $295 $300 $300 $1,625

New Supply - BD HPRs $179 $179 $175 $175 $177 $177 $1,062

Reinforcement - Camborne Pkwy, Butler $95 $95

Reinforcement - Lyall St, Redcliffe $38 $38

Reinforcement - Atwell $122 $122


Asset Replacement $179 $296 $291 $291 $295 $295 $1,646

EOL replacement - HPR $163 $162 $160 $159 $162 $162 $968

EOL Replacement - MP Pits $17 $134 $131 $131 $133 $133 $679


AS4645 Interdependency - Subiaco $355 $355

Capacity Upgrade - PRS03 Geraldton $130 $130

Replacement - HP Reg Pit Lids $21 $21 $21 $21 $21 $105

Facility Upgrade - Confined Space Signs $113 $113

Facility Upgrade - HPR Monitoring $471 $464 $463 $471 $472 $2,340

Facility Upgrade - HPR Vehicle Protection $238 $234 $234 $238 $238 $1,183

Facility Upgrade - OPSO Safety Devices $1,021 $1,104 $2,125

Replacement - HPR HS087 $138 $138

PGP Interconnection - Old West Rd, Bullsbrook $3,354 $3,354

PGP Interconnection - Harrow St, West Swan $1,391 $1,391

PGP Interconnection - Caversham $4,380 $4,380

PGP Interconnection - Welshpool Rd, Wattle Grove $2,685 $2,685

PGP Interconnection - Russell Rd, Wattleup $2,712 $2,712

PGP Interconnection - Readhead Rd, Nambeelup $3,377 $3,377

Transmission Gate Station Capacity Upgrades $570 $492 $1,061

Total ($'000s) $1,782 $2,844 $5,443 $9,036 $4,878 $6,056 $30,039



4.3 Metering Facilities Lifecycle Management Plan The asset class described in this section are the HP meter sets, MP meter sets and domestic metering facilities. Meters used in large commercial sets range in flow rate capacity from an American AL40 diaphragm meter to an American GT8 turbine meter. Medium sized meter sets have meters ranging from an American AL40 to AL150 diaphragm meter, or a Dresser Roots DR85 to DR200 rotary meter.


4.3.1 Future Demand

Future demand for metering facilities is based from the forecast quantity of new connections described in Section 3.2.3.


Meter set maintenance involves a set pressure check and a “lock up” check on the pressure regulation equipment to ensure its effective operation. Spin checks and Differential Pressure (DP) checks are also conducted on all turbine and rotary meters respectively. These checks are conducted on an annual basis for HP meter sets and an 18 month cycle for MP meter sets. Engineering Services and Asset Services are advised of any non-compliant differential pressure or spin checks to determine whether the meter needs to be replaced.


Asset renewal strategies have been established to ensure AGA’s assets function within the requirements of the Safety Case and are based on information from condition and performance assessment, monitoring and modelling. Replacement of these facilities is considered when spare parts become obsolete, or the meter set does not meet operational requirements. Meter sets are subjected to a condition based renewal strategy of the components that make up the facility, typically determined by reported number of faults, operability and asset component conditions.

4.3.3.1 Routine Meter Change Program

Domestic meters are replaced on a calendar based replacement schedule as determined by regulatory requirements specified in AGA’s Safety Case. The Routine Meter Change (RMC) program ensures that the domestic gas meter accuracy is within tolerances identified in the GSSR 2000 by replacing the meters with new meters at the end of their regulatory defined in-service lives. Table 35 summarises the quantities of meters to be replaced under this program.

Table 35: Quantities of Meters to be replaced under RMC Program

Meter Replacement Program 2H 2014 2015 2016 2017 2018 2019 Grand Total

Routine Meter Change (RMC) 6821 22163 20686 24150 36854 36677 147351

4.3.3.1 Commercial Meter Change Program

Commercial meters are refurbished on a calendar based schedule as determined by regulatory requirements specified in AGA’s Safety Case. The Commercial Meter Change (CMC) program ensures that the commercial gas meter accuracy is within tolerances identified in the GSSR 2000 by replacing the meters with refurbished meters at the end of their regulatory defined in-service lives. Table 36 summarises the quantities of meters to be replaced under this program.



Table 36: Quantities of Meters to be replaced under CMC Program


Commercial Meter Change (CMC) 256 572 594 930 775 599 3726

4.3.3.2 M6WA Meters with Plugs

This project involves replacing a population of M6WA domestic gas meters with plugs. These meters were installed in the AGA GDS during the period December 1994 to June 1998 with a population of 65,830 currently remaining in service. The plastic plug was designed to provide access to the tangent for adjusting the accuracy of the meter when meters were refurbished. This practice is no longer conducted.

In summer during low or no flow conditions, these meters can be subjected to high ambient temperatures causing the trapped gas pressure in the meter to increase. This can cause the plug to leak, resulting in uncontrollable loss of containment at a dwelling. Fault analysis on leaking meters indicated a rising trend of leaking plugs from 16 years onwards. The condition of these plastic plugs is expected to deteriorate further over time, increasing the likelihood of leaking plugs and the associated risks. Replacing these meters will eliminate the risk.

The Network Safety Case Formal Safety Assessment (FSA) identified a non ‘As Low As Reasonably Practicable’ (ALARP) risk of a plug failure on a M6WA domestic gas meter resulting in uncontrolled loss of containment at meter. This scenario can have major consequences due to potential gas entering the dwelling leading to fire and/or explosion causing damage to the property, serious injuries and/or fatalities. The non ALARP risk and consequences associated with loss of containment within multi dwellings and multi storey buildings is higher than a meter located at a single dwelling.

To ensure the strategic objectives of this project are attained, a risk based replacement program has been established so that all meters with higher non ALARP risk and consequences are replaced first, to continue to ensure a safe and reliable network with the risk level reduced to ALARP. Thereafter the program prioritises the replacement of oldest meters with plugs located within multi dwellings and multi storey buildings followed by meters located in single dwellings, with quantities summarised in Table 37.

Table 37: Quantities of Meters to be replaced under M6WA Meters with Plugs Program


M6WA Meters with Plugs 4693 7339 8169 8172 8245 8243 44861

4.3.3.3 Multi-Storey Dwellings

These distribution assets are a legacy from AGA predecessors that implemented a connection policy of removing boundary master meters and converting sub-meters to billing meters, thereby ‘inheriting’ downstream installations to form part of the distribution network. This policy is no longer practiced. Based on the limited knowledge of the condition of this inherited ageing infrastructure, a FSA required as part of AGA’s Safety Case, identified the risk associated with this AGA infrastructure as not being ALARP. The likelihood and risk of gas escapes and associated safety impact will increase, as compared to reducing the risk to ALARP.

AGA engaged with the safety regulator, EnergySafety, to develop a solution that would reduce the risks associated with these assets and the service to end use customers to ALARP. Based on the engagement with EnergySafety the Company identified multistorey buildings containing AGA infrastructure that required replacement or upgrade to reduce the risk to ALARP.



A risk based approach has been used to prioritise the upgrade of AGA infrastructure throughout all buildings currently identified. The program, which is forecast to be completed by 2019, has been divided into three areas of focus as follows:

• AGA infrastructure within multistorey buildings greater than or equal to 3 storeys.

• AGA infrastructure within multi-occupancy buildings (2 storey).

• AGA ground level metering infrastructure within multi-occupancy buildings.


Further improvement activities for meters and meter sets are summarised as:

• Metering accuracy.

• Enhancements in SAP maintenance implementation.

• Improved maintenance and replacement strategies through reliability modelling for critical facilities.

4.3.4.1 Temperature Compensated Meters

Correcting meter reads for both gas temperature and pressure are key components to accurately measure the energy consumed at a consumer’s delivery point. For approximately 670,000 domestic and small commercial delivery points the current billing system, via the Pressure Correction Factor (PCF), retrospectively corrects for the delivered gas temperature based on a flow weighted 9am ambient temperature correction factor, in addition to correcting for other environmental factors such as supply pressure, atmospheric pressure and meter elevation.

Measurement at residential and small commercial end use connection points utilises standard pressure measurement that is not temperature compensated. For this measurement, AGA has a process in place that utilises a correction to adjust the measured volume to standard reference conditions of pressure and temperature. Australian Standards for natural gas measurement require that all volumes of gas measured be adjusted to a pressure of 101.325kPa (absolute) and a temperature of 15°C. For all residential and small commercial customers AGA has equipment in place that records the volume at delivery pressures and utilises a known correction factor to adjust to standard pressure, but utilises an estimated correction factor to adjust the volumes to standard temperature.

An opportunity exists to correct meter reads for gas temperature at the point of metering using Temperature Compensating Meters (TC Meters), and therefore more accurately measure natural gas consumption at each customer’s delivery point. TC Meters will increase the accuracy of billing to the consumer thereby removing the requirement for a fixed Temperature Correction Factor. This will ensure customers only pay for the energy they consume as any component of under or over billing currently attributed to having a fixed temperature correction factor will be removed from the UAFG figure, which is recovered via the tariff applied across all non-interval customers and allocated to the customer actually consuming the gas.

TC Meters cost an extra $4.25 each over a standard meter which itself costs $83.

4.3.4.2 Replacement - Oversized Turbine Meters

This project is to improve metering accuracy of industrial gas users to ensure compliance to regulations. Replacement of these identified oversized turbine meters with load specific rotary meters will allow for more accurate measurement of natural gas delivery.

4.3.4.3 Meter Compliance

Approximately 8,500 meters are installed within commercial and residential dwellings, which are deemed non-compliant with AS/NZS4645 and AS/NZS5601, nor ALARP as per the FSA conducted as part of the Safety Case implementation, These meters will be assessed on an



individual basis and either relocated externally to the premises or vented such that all relevant standards are met.

This project also targets meter sets where a potential risk of ignition of vented gas exists to protect AGA assets and the public by relocating discharge vent points of gas to safe locations.

Planned works include the design, modification of enclosures and/or installation of vent pipes from pressure control devices where asset location environments may have changed causing the current vent points to be no longer compliant with the AS/NZS 4645 and AS/NZS 5601 requirements for exclusion from ignition sources.



Table 38: Forecast Capital Expenditure - Metering Facilities

Project Description 2H 2014 2015 2016 2017 2018 2019 Total ($'000s) GROWTH CAPEX $10,601 $19,820 $19,362 $19,369 $19,700 $19,767 $108,619


Variable Volume Meters and Service Pipes - Customer Initiated $10,580 $19,783 $19,324 $19,330 $19,658 $19,723 $108,399

Demand $21 $37 $38 $39 $42 $44 $220

Variable Volume Meters and Service Pipes - Demand $21 $37 $38 $39 $42 $44 $220



Multistorey Risk Reduction - Multi-Occupancy Buildings $3,194 $3,241 $3,290 $3,298 $13,022

Multistorey Risk Reduction - Multistorey Buildings (≥ 3 stories) $2,677 $4,348 $7,026

Replacement - M6WA Meters with Plugs $1,146 $1,586 $1,733 $1,727 $1,764 $1,762 $9,717

Routine Meter Change Programme (RMC) $1,624 $4,790 $4,387 $5,104 $7,883 $7,839 $31,628

Variable Volume Meters and Service Pipes - Replacement $789 $1,598 $1,631 $1,690 $1,778 $1,848 $9,334

Network Safety and Performance $158 $912 $1,144 $1,157 $1,236 $1,233 $5,841

Meters Compliance Project $82 $912 $895 $891 $900 $899 $4,579

Replacement - Oversized Turbine Meters $77 $77

Temperature Compensated Meters $250 $267 $335 $334 $1,185

Total ($'000s) $16,996 $33,055 $31,451 $32,288 $35,650 $35,747 $185,186



4.4 Cathodic Protection Systems Lifecycle Management Plan The asset class described in this section comprise the Cathodic Protection (CP) systems used to protect the underground steel pipelines in the AGA GDS from external corrosion. CP systems can either be a sacrificial type, utilising magnesium anodes, or impressed current type, utilising a Transformer Rectifier Unit (TRU). The systems consist of sacrificial anodes, TRUs, polarisation cells, surge protectors, insulation joints, interference test points, general test points and earthing. Both types of CP systems are used in the GDS, with the sacrificial CP system installed on the majority of the high pressure pipelines, as well as a number of steel medium pressure pipelines and road/rail crossings. CP systems are not critical assets.


4.4.1 Future Demand

Future demand for cathodic protection systems is based from the forecast of new high pressure pipelines. The cathodic protection costs for these pipelines have been included in the pipeline construction costs described in the pipelines, mains and services section.


The maintenance strategy includes: CP potential survey, impressed current systems inspections, inspection of pipe work, earthing checks, foreign structure crossings and coating surveys (DCVG). An annual works program is established for implementation and execution to achieve the maintenance strategy. The works program is used to monitor and track the progress of CP activities. SAP measuring points have been established against each relevant Functional Location to monitor the condition and performance of the assets, by recording data as SAP measurement documents and details of inspections and any resulting work (if any) as notifications in SAP or reports in EIM.


Asset renewal strategies have been established to ensure AGA’s assets function within the requirements of the Safety Case and are based on information from condition and performance assessment, monitoring and modelling. Replacement of these facilities is considered when spare parts become obsolete, or the TRU does not meet operational requirements. TRUs are subjected to a condition based renewal strategy of the components that make up the facility, typically determined by reported number of faults, operability and asset component conditions. Anode replacements are completed when anode performance is insufficient.

4.4.3.1 End of Life Replacement – Anodes

CP is used as part of the HP pipeline integrity management strategy to ensure effective corrosion protection of these assets. Many of the HP pipelines use sacrificial anodes to provide protection and replacing depleting anodes is part of maintaining an effective CP system. CP is necessary to ensure the integrity of the HP steel pipelines over the pipelines full life. The scope is to replace 15 sacrificial anode sites per year that are almost fully depleted to maintain effective CP.

4.4.3.2 End of Life Replacement – TRU

ATCO Gas Australia’s strategy to ensure the integrity of HP pipelines is by providing adequate and effective corrosion protection to these assets. Some of these HP pipelines are protected by impressed current system through a TRU. Adequate and effective CP will prevent corrosion occurring on the pipeline and mitigate high pressure gas escape or pipeline rupture that can be caused by corrosion. This project is required to replace aged TRU that have reached their end of life where spares are unavailable from and unsupported by the supplier. Continuous operation of a TRU to provide the required level of CP is essential to an effective CP system. Replacing an ageing TRU is part of maintaining an



effective CP system. An effective CP will ensure the integrity of the HP steel pipelines and thus maintain reliability of gas supply to the lower pressure networks.


Improvement activities for CP equipment are summarised as being improvements in SAP maintenance implementation, development of a formalised renewals strategy and improvements to the maintenance strategy. These improvement activities are required to enhance the performance of the CP systems protecting the Company’s steel pipelines, to ensure they remain safe and reliable for the long term, which in turn decreases lifecycle costs for the pipeline assets, in the long term interest of consumers. Improvement activities required to increase the safety and performance of the CP systems are listed below.

4.4.4.1 Facility Upgrade - CP Test Points

CP is used as part of the HP pipeline integrity management strategy to ensure effective corrosion protection of these assets. The CP systems are maintained annually through pipeline potential survey readings at the test points. These test points are, on occasion, subjected to vandalism and once exposed may present a hazard to the public during a fault and affects the ability to maintain the CP system, resulting in inadequate and ineffective CP. The scope is to encase 10 CP test points within cured die cast aluminium boxes that contain remote access terminals for taking measurements.

4.4.4.2 Facility Upgrade - Resistance Probes

To maintain HP system integrity, the installation of resistance probes is required along HP pipeline asset locations where the pipeline is assessed as having poor cathodic protection levels and evidence of pitting has been observed on the pipeline being protected. This will enhance the protection of the assets by determining the effectiveness of the cathodic protection system.

4.4.4.3 Facility Upgrade - Step Touch Mitigation

EnergySafety has issued a Corrective Action Request (CAR) to mitigate the risk of personnel being exposed to induced voltages whilst working on high pressure pipelines. This risk can be mitigated by these equipotential earthing facilities that distribute the soil potential equally around above ground assets, providing a safer working environment. The scope of this project involves the installation of an equipotential facility at 5 above ground HP facilities.

4.4.4.4 Facility Upgrade – Insulation Joints & Surge Protectors

All HP steel pipelines are protected either with sacrificial anodes or impressed current CP systems. To facilitate the management of CP or third party interference, a HP pipeline needs to be electrically isolated from one section to the other. This is achieved by sectionalising the pipeline in discrete sections with inline welded insulation joints (IJ). These IJs are installed during the construction of the pipelines. IJs can be damaged by induced voltages and lightning strikes. Damaged IJs are difficult to replace and requires interrupting the flow of the pipeline. This is costly, labour intensive and may impact the integrity of the network.

This project is to install surge protectors across the IJs to protect the equipment from voltage spikes, as they limit the voltage by shorting to ground any unwanted voltages above a safe threshold and mitigate the risk of damaging the IJs.


Cathodic protection related expenses are incorporated into the pipelines, mains and services asset class.



4.5 Telemetry Equipment Lifecycle Management Plan The asset class described in this section is the telemetry equipment used to measure key process variables and industrial loads from the field. Flow computing, data logging, pressure monitoring and telemetry equipment is used for measuring, recording, calculating and transmitting electronic data such as gas pressures, differential pressures, temperatures, consumption and flow rates. These devices are used on four facility types in the AGA GDS: Pressure Monitoring Device (PMD), High Pressure Regulator (HPR) set monitoring, Pressure Reducing Stations (PRS) monitoring and Industrial meter set monitoring (IND).


4.5.1 Future Demand

Future demand for telemetry equipment is based from the forecast of new HP regulating facilities, or industrial/large commercial metering facilities.


Maintenance inspections are carried out on all telemetry equipment every six months typically in March to May and again in September to November each year and are completed over a period of approximately four months. During each inspection, all sensing devices, data logging devices and power supplies are checked for condition and operation.

Accuracy Verification Tests (AVT) on the gas measurement equipment is also carried out every six months. AVTs are carried out at all AGA locations to ensure the accuracy of flow measurements and monitored variables. Accuracy verification witness tests are also carried out at approximately six weekly intervals at the CMS Harrow Rd gate station. These are to accurately measure the volume of natural gas into the GDS for validation of inflows which relates to:

• Unaccounted for Gas (UAFG) calculations

• Gas Transportation determinations

• Validation of inputs to the network

The instruments that are checked during each AVT are:

• pressure transmitters

• Resistive Temperature Devices (RTD) and temperature transmitters

• turbine meters

• flow computers


To assist with providing a safe, reliable network for consumers, telemetry equipment is used to provide early warnings for signs of degradation in network performance before consumers are affected. Replacement of end-of-life telemetry equipment is critical to ensure this early warning system remains active.

4.5.3.1 End of Life Replacement - Telemetry

The renewal/replacement strategy currently in practice for telemetry equipment is a time-based replacement strategy. The equipment lifetimes considered industry practice are used and can vary from manufacturer recommendations. Replaced units still in good operational condition may be retained as emergency spares, due to the increased failure rate of the aging items and the potential long procurement lead times. Items that are not replaced on a fixed interval are replaced on a staggered, 8-year replacement program to provide a more



levelled approach to capital expenditure. During a replacement program, if the failure rate of that item increases, the program period will be reduced to lower the risk of further failures. Low cost items, such as batteries, are replaced on a fixed time basis.

Equipment within each of the replacement programs is prioritised by age and criticality. Most equipment greater than 15 years old will be replaced as a priority. When the replacement programs are complete, scheduled annual replacement plans will be established to manage ongoing replacements as per their industry recommended replacement age.

4.5.3.2 Facility Upgrade - 2G Network Modems

ATCO Gas Australia currently owns and operates 799 telemetry devices of which 362 devices are on the Telstra 3G network and 537 are only capable of operating on the 2G mobile network. If the 2G network is discontinued, the devices that operate on this network will no longer function and these sites will no longer be able to communicate to the appropriate AGA servers and deliver the interval or monitoring flows pressures and alarms required to meet operational and retail market obligations. With the introduction of the 3G and 4G networks, this has resulted in the 2G network no longer being as high a priority for Telstra to develop and support. The bandwidth of the 2G network will need to be reduced with the growth of the 3G & 4G systems. This has been identified by some fringe 2G device locations failing with the only remedy being the replacement with a 3G modem.

These 2G network devices are nearing end-of-life and will eventually be discontinued. Telstra are reluctant at this stage to confirm if or when the 2G will be discontinued, however as these make up a significant section of our communication devices for industrial billing, critical alarms, network performance and expansion calculations, it is considered prudent to bring forward the replacement of these devices. This project will ensure that when the Telstra announcement is made, AGA are not in an position to replace all of these items in a short timeframe where resources are limited, as a larger capital expense would be required to replace these in a shortened period.


Telemetry is used on the network to allow AGA to proactively monitor system pressures and respond to developing circumstances before they result in outages. It is also a critical component of providing interval metering data to the marked each day in accordance with REMCo Market rules for which penalties may apply for inability to provide the data by the daily deadline. With ever increasing numbers of consumers, increasing the numbers of facilities that include telemetry is of growing importance.

Other improvement activities for telemetry equipment are summarised as being improvements in SAP maintenance implementation, development of a formalised renewals strategy and improvement of the maintenance strategy.

Key projects in improving network safety and performance include the following projects.

4.5.4.1 R&D - Remote Pressure Control at Selected HPR Sites

Due to the dynamics of the GDS, there are certain HPRs that have a higher influence on the network. They also tend to ‘grab’ load from other HPR during a broken main incident. These HPR tend to work harder and supply more gas to the network.

This project is to install pressure control at these HPR capable of pressure setting adjustment remotely. Enabling pressure adjustment remotely allows easy intervention of performance requirement from these HPR. Depending on the network demand, the HPR can then be set to minimum pressure to maintain network integrity and adjusted accordingly as network requirement calls for. Operating HPR under this condition will reduce gas escapes from leaks and third party broken mains. This mitigates the risk of escaping gas to the public and personnel working on site. It will also facilitate management of UAFG.



4.5.4.2 PMD Data Visualisation (Project DV)

The objective of this project is to provide better network information to allow for an improved response to operational and emergency situations. This will be achieved by populating the distribution network with PMDs, which will allow for wider monitoring coverage to achieve increased visibility and a better understanding of network performance. This, in conjunction with the improved modelling processes will also promote optimal network utilisation. This project will also increase the security of gas supply through "near" real time monitoring of the network pressure status caused by equipment failure and third party damages.

4.5.4.3 Facility Upgrade - PRS Monitoring & Alarming

This project involves the installation of metering and alarming functionality on HP regulating equipment. Analysis of current network alarm capabilities identified that some PRSs do not have alarm functionality. This project will facilitate alarm and monitoring schemes that meet operational needs, ensuring that gas flow and regulating equipment can be utilized for optimising network performance and to help facilitate prudent asset management decisions.

4.5.4.4 Facility Upgrade - Metering & Telemetry Capel PRS

Capel PRS supplies gas to Busselton polyethylene distribution network via the 225mm high pressure polyethylene (HPPE) pipeline. A HPR at the end of the HPPE pipeline in Busselton reduces the pressure to reticulate Busselton polyethylene (PEHP) network, MAOP of 350kPa.

Currently flow and both inlet and outlet pressure data at the PRS is monitored by telemetry. These data are utilised for network modelling of the Busselton network. The outcome from modelling determines reinforcement requirements to ensure integrity and continuity of gas supply. However, these monitored data at the HPR cannot be verified as the input parameters to the HPR are unknown.

This project is to install metering and telemetry at Capel PRS. A Formal Safety Assessment identified the installation of this equipment as a risk management action plan. Data from the site will be used for verification of the Busselton model at the HPR. This will ensure a better modelling outcome resulting in an informed decision for reinforcements to the Busselton network.

4.5.4.5 Facility Upgrade - Alarm Capability at Critical Locations

The ability to provide a safe, reliable and economic gas supply to consumers is dependent on operating and maintaining the integrity of the distribution system throughout the range of anticipated demand profiles including winter peaks. Monitoring the distribution system within safe operating parameters as part of operating the system will ensure continuous supply of gas to consumers within the specifications prescribed in the Gas Standards (Gas Supply and System Safety) Regulations 2000.

Thirty-nine (39) sites have been identified as "critical supplies" to the network by Asset Services. Eight (8) sites are already monitored, but form part of this project as these sites require upgrading of their alarm capability to the current operational design and interface to the Network Data Visualisation project. Critical sites are based on the following selection criteria:

• Network modelling indicates a flow greater than 1500scm/h during a severe winter

• HPR failure has a potential loss of at least 500 consumers

• Feed HP PE pipelines.

Data from these sites is used to validate the gas model for peak winter modelling by showing load profiles for sections on the network (metered gas volumes) delivery pressures to the network to ensure the security of supply. Upon installation of telemetry, all logged parameters can be alerted including inlet and outlet pressure, OPSO condition and flow levels.



Out of the 39 critical sites, 8 already have basic telemetry that is still based on the dial-up telephony network. Without monitoring of critical HPR sites there is a greater risk of losing a customer base of greater than 500 customers during peak loads as the condition of the HPR will be unknown. Not monitoring critical HPR sites could have a severe operational cost if a network lost supply due to a HPR fault that is not mitigated.



Table 39: Summary of Telemetry Equipment Expenditure

Project Description 2H 2014 2015 2016 2017 2018 2019 Total ($'000s) SUSTAINING CAPEX $649 $889 $1,174 $996 $1,020 $324 $5,051

Asset Replacement $147 $245 $539 $543 $559 $292 $2,325

EOL Replacement - Telemetry $147 $245 $272 $277 $290 $292 $1,524

Facility Upgrade - 2G Network Modems $267 $266 $269 $801

Network Safety and Performance $502 $644 $635 $453 $461 $33 $2,727

Facility Upgrade - Alarm Capability at Critical Locations $372 $373 $368 $368 $374 $1,855

Facility Upgrade - Metering & Telemetry Capel PRS $34 $34

Facility Upgrade - PRS Monitoring & Alarming $239 $235 $473

Project DV $95 $33 $32 $32 $33 $33 $257

R&D - Remote Pressure Control at Selected HPR Sites $53 $54 $107

Total ($'000s) $649 $889 $1,174 $996 $1,020 $324 $5,051



5. Forecast Summary This section contains the financial requirements resulting from all the information presented in previous sections. As the AMP improves each year, various levels of service/cost scenarios may be included.

5.1 Financial Projections Funding requirements for managing the network are classified into four categories: (1) variable volume (Customer Initiated) CAPEX, which covers the costs incurred for new connections; (2) variable volume OPEX, which covers maintenance activities; (3) CAPEX projects, to cover demand, performance and replacement projects, and (4) OPEX projects, to cover projects that cannot be classified as CAPEX or maintenance activities.

All expenditure, unless noted, is expressed as real 2014 dollars.

5.1.1 Capital Expenditure

AGA assesses not only its operating practices, but also the lifecycle of the assets utilised to deliver natural gas service. The Company identifies assets for replacement, upgrading and improvement that are necessary and in the long term interests of customers.

Through a Project Governance process, including the development of business cases, which is described in ENS MA00001 Project Management Manual, and the implementation of COM PO00001 Procurement Policy, the Company demonstrates that expenditures incurred are prudent and efficient and in accordance with accepted good industry practice. They are designed to achieve the lowest sustainable cost of providing a safe, reliable, cost competitive natural gas delivery service.

Growth CAPEX is that used for the economic expansion of AGA’s reticulated network to provide service to new end use connections. New Mains and Services are Customer Initiated CAPEX (CIC). AGA’s Gas Distribution Licence GDL 8 requires that the Network Operator must offer to connect any service that is on line of gas main with up to 20 metres of service line, and accompanying gas meter incorporated, as the “Service Connection”. Demand CAPEX is that assigned to developing spurlines or reinforcing the network to address increased demand for natural gas.

Sustaining CAPEX is that used to ensure the existing network infrastructure remains safe and reliable so that it can sustain the functions for which it was designed. Performance CAPEX represents expenditures to upgrade, enhance, or improve network assets or operations to improve safety, reliability or cost effectiveness. Examples of performance CAPEX are enhancements to the HP pipeline network to accommodate inline inspections of such assets consistent with Australian Standard AS2885; installation of supply connections and associated pressure reduction and mains infrastructure to provide supply security and reliability, and the installation of concrete slabbing to protect high pressure pipelines in certain population usage areas (schools, hospitals and other buildings of public occupancy) from excavation strikes.

Replacement CAPEX represents expenditure to replace network assets that are at the end of their useful safe operating life to ensure they remain safe and reliable. Examples of replacement CAPEX are replacement of unprotected, buried metallic mains; replacement of distribution assets within multistorey buildings and natural gas meters that have reached regulated end of life.

Table 40 summarises the capital projects for the forecast period by CAPEX category.

Table 40: Capital Expenditure Summary by Category

CAPEX Category 2H 2014 2015 2016 2017 2018 2019 Total ($'000s) GROWTH CAPEX $18,715 $39,203 $51,814 $42,645 $41,457 $34,704 $228,537


Demand $3,038 $10,479 $24,048 $14,903 $13,283 $6,472 $72,224




Total ($'000s) $36,433 $81,210 $103,346 $106,794 $104,752 $107,292 $539,827



Understanding capital expenditures for each asset class allows for AGA to refine asset lifecycle strategies to sustainably reduce the total cost of ownership for its assets in the long term interest of consumers. CAPEX summarised by asset class is shown in Table 41.

Table 41: Capital Expenditure Summary by Asset Class

Asset Class Growth Sustaining Total ($'000s) Gate Stations $18,961 $18,961 High Pressure Polyethylene Pipelines $1,860 $11,031 $12,891 High Pressure Steel Pipelines $62,362 $91,559 $153,921 Medium & Low Pressure Mains $52,753 $99,984 $152,737 Metering & Service Pipes $108,619 $76,568 $185,186 Regulating Facilities $2,942 $8,136 $11,079 Telemetry & Monitoring $5,051 $5,051 Total ($'000s) $228,537 $311,289 $539,827

5.1.2 Operational Expenditure

In accordance with National Gas Rules, operating expenditure must be such as would be incurred by a prudent service provider acting efficiently, in accordance with accepted good industry practice, to achieve the lowest sustainable cost of delivering pipeline services. Projects and activities have been prepared to ensure all operational expenditure conforms to this requirement and to those in AGA’s Safety Case.

The table below shows the forecast expenditures for the Access Arrangement period. “Projects – non recoverable” reflects forecast expenditures for the operations, maintenance and inspection of the AGA’s reticulated natural gas network in accordance with its Safety Case. An example of activities included in the cost category would be inline inspections of HP pipelines, vegetation clearance and includes other support type costs including communications, fleet, property, training and health, safety and environment. The “Variable volume” category reflects forecast expenditures for operations and maintenance activities that result from routine maintenance and inspection and customer requests and notifications. Examples of activities included in this cost category are annual leak survey and leak repair, no gas calls, reported gas escapes, etc.

The formal safety assessments undertaken as part of the AGA Safety Case have identified further network operating requirements that include:

• Increased leak survey frequency, documentation and categorisation.

• Updated work procedures and documentation to ensure and document compliance and safe operation.

• Increased inspection of prescribed activity on the GDS.

• Comprehensive training on updated work procedures and documentation including field assessment.

• Additional resources to address growth and network footprint and end use network connections.

• In-line-inspection of high pressure steel pipelines to assure safe reliable operating condition.

• Provision of natural gas safety information to the public.

• Improved condition assessment of AGA’s buried plastic gas mains and services.

Table 42 summarises the total operational costs for the forecast period.



Table 42: Operational Projects Expenditure Summary

OPEX Category 2H 2014 2015 2016 2017 2018 2019 Total ($'000s)

Projects - non recoverable $1,194 $2,304 $2,126 $2,038 $1,935 $1,908 $11,504

Variable volume activities $4,365 $8,533 $8,824 $9,386 $9,596 $9,765 $50,468

TOTAL ($'000s) $5,559 $10,837 $10,950 $11,424 $11,531 $11,673 $61,972

Table 43 summarises the forecast operational expenditure required to maintain the existing network and covers both planned and unplanned maintenance activities. Planned and proactive maintenance activities increase the safety and reliability of the network, and are more efficient and cost effective than reactive fault management.

Table 43: Variable Volume Operational Expenditure

Activity Type 2H 2014 2015 2016 2017 2018 2019 Total ($'000s)

Routine Maintenance (SM) $872 $1,882 $1,961 $2,034 $2,110 $2,187 $11,046

Corrective Maintenance (SP) $1,620 $3,227 $3,319 $3,683 $3,677 $3,622 $19,147

Fault Management (SF) $1,873 $3,424 $3,544 $3,669 $3,808 $3,956 $20,275

TOTAL ($'000s) $4,365 $8,533 $8,824 $9,386 $9,596 $9,765 $50,468

As part of AGA’s commitment to continuous improvement, projects have been identified to increase the number of routine maintenance inspections that drive corrective maintenance under planned conditions so that the number of reactive tasks are reduced. Table 44 summarises the total costs for operational projects for the forecast period to achieve these improvements.

Table 44: OPEX Projects

OPEX Project 2H 2014 2015 2016 2017 2018 2019 Total ($'000s) MGL Pigging $77

$77

Meterset Painting $50 $100 $100 $100 $100 $100 $550

Review each PRS site for vehicle impact protection.

$15 $0 $0 $0 $0 $0 $15

Shallow HP Pipelines (South Fremantle) $25 $0 $0 $0 $0 $0 $25

Pipeline remedial works $100 $100 $100 $100 $100 $100 $600

AS2885 Vegetation Clearing $15 $30 $30 $30 $30 $30 $165

Identify or complete a study on the impact of acid sulphate soil on concrete pipe coatings (e.g. concrete pipeline encasement used as a buoyancy mitigation in wetland areas) to assess possible deterioration of concrete for HP105 AS 2885 Safety Management Study.

$15

$0 $0 $0 $15

Evaluate all above ground high pressure reg sets greater than 500 kPa for traffic protection and security.

$0 $0 $0 $0 $0 $0 $0

Quantify and document tree sizes surrounding Pressure Reduction Station No. 12 (PRS012) and document schedule to remove trees threatening to fall upon PRS012 as they may damage above ground pipework and facilities. Trim or remove trees as required

$0 $0 $0 $0 $0 $0 $0

Alarm all PMDs for high operating pressure within the GDS

$0 $0 $0 $0 $0 $0 $0



OPEX Project 2H 2014 2015 2016 2017 2018 2019 Total ($'000s) DBYD $138 $352 $394 $441 $494 $553 $2,371

O&M of Mandurah Gate station $36 $72 $72 $72 $72 $72 $396

ATCO pipeline bridge inspections $30 $60 $60 $60 $60 $0 $271

AS2885 Depth of Cover Assessment on Laterals $0 $0 $0 $0 $0 $0 $0

Installation and removal of MP signs $5 $13 $13 $3 $0 $0 $33

Preliminary works for Lateral enhancement to facilitate intelligent pigging (launches & receivers) - investigation

$0 $0 $0 $0 $0 $0 $0

OPEX AS2885 In-Line-Inspection of CL600 Pipeline - HP093, HP102, HP106, HP107

$0

$137 $137 $137 $167 $577

Pig EPL and HP028 $104 $350 $0 $0 $0 $0 $454

5 year replacement of network stickers on signage $0 $32 $32 $32 $32

$127

Internal meters study $81

$81

PVC studies $0 $131 $131

$262

Bridge Crossing Data Acquisition (OPEX) $20

$20

Bridge Crossing Remediation (total of 20 crossings)

$15 $30 $30 $30 $30

$135

Hazardous Area Compliance at PRSs 5 & 10 $38

$38

Isolation Instructions $0

$0

Water in the Main Non-recoverable $125 $255 $260 $265 $271 $276 $1,452

Proving $55 $110 $110 $110 $110 $110 $605

Safety Awareness $250 $500 $500 $500 $500 $500 $2,750

Pressure Vessel Inspection at PRSs $0 $158 $158 $158

$473

Narngulu & Bootenal PRS Review $0 $12

$12

Total ($'000s) $1,194 $2,304 $2,126 $2,038 $1,935 $1,908 $11,504

5.2 Key Assumptions Made in Financial Forecasts In accordance with the Procurement Policy the cost of services provided to the Company have been and shall continue to be market tested, ensuring the lowest rates are achieved to deliver business objectives. Forecast costs are also derived and validated using historic trending and validated with year to date figures.

Projects are delivered using a balance of internal and sub-contracting workforce to ensure an efficient and sustainable level of resourcing is maintained over the long term. Supervised contract resources are utilised to ensure the Company can manage peaks and troughs of the works program whilst still maintaining in-house knowledge and skills. This approach maximises competition between external suppliers and supports internal processes to ensure the delivery method is efficient. This approach ensures the Company retains visibility and control of the works delivery program to enable AGA to scope projects and manage contracts effectively.

All major projects are subject to a tender process after which a contract is put in place with the successful proponent. The assessment criteria include the contractor’s experience, ability to carry out the project and the contractor’s quality management system.

Unit rates for activities have typically increased due to procedural changes that reflect the Formal Safety Assessment undertaken as part of the Safety Case, which reduce the risk to personnel and general public, but inherently increase reinstatement and traffic management requirements.



6. Plan Improvement and Monitoring As part of ATCO Gas Australia’s Gas Distribution Licence GDL 8 conditions, an independent third party auditor acceptable to the ERA audits the effectiveness of the AMS every 2 years the most recent audit was completed in 2011. The Audit Report has been issued to ATCO Gas Australia and indicated that the AMS effectiveness, which is measured out of a score of 5, has increased from the previous audit to 4.58. The following extract from the Executive Summary refers:

“In summary, the control environment for ATCO Gas Australia distribution asset management system was reviewed for all 12 areas of review as required by the Guidelines and the average rating has increased to 4.58, from 4.4 in 2009.”

Action items that were identified in the audit that require expenditure this planning period are:

1. “It is recommended that the initiatives and studies into the underlying factors contributing to UAFG, which are being discussed with EnergySafety and UAFG trends continue to be monitored in conjunction with Energy Safety Division (ESD).

2. “It is recommended that intelligent pigging of the Class 600 pipelines be considered.”

6.1 Monitoring and Review Procedures Management has established a review process of the management system to ensure its continuing suitability and effectiveness in satisfying the Company’s policy and objectives and the interested parties’ needs and expectations. The review is conducted annually and is considered broad enough in scope to address the implications of all activities, products and services provided by the organisation, including their performance on the organisation.

The annual management review includes:

• Evaluation of the suitability of the management policies

• Review of objectives, targets and performance

• Findings of the management system audits

• Review of incident investigations

• Review status of current improvement projects

• Review of the effectiveness of previous corrective, preventive and predictive actions

• Review of internal and external communications

6.2 Implementation Plan While AGA’s AMS and AMP are robust, all systems, plans and approaches are still open for continuous improvement. Due to the complexity of and risk associated with the GDS, AGA requires a strategic asset management framework that supports the safe, reliable, efficient and effective delivery of natural gas in the long term interests of customers. Standards for asset management are ever evolving, particularly in 2014 with the release of the ISO 5500X suite, that specify the requirements of an asset management system. With the alignment of its AMS to ISO 55001, the Company intends to achieve its strategic objectives through processes that promote improvements to the safe, effective and efficient management of its assets. The application of an asset management system using this international standard provides increased assurance that a safe, reliable, cost effective, environmentally sustainable, customer friendly natural gas service can be achieved consistently and



sustainably over time. To realise the full benefits of this standard through prudent investment in the network in the long term interest of customers and through the implementation of its Safety Case, areas of improvement have been identified for implementation over the 2014-2019 AA period. In the Company’s forecast it has identified data refinement and systems required to optimise the sustainable management of GDS assets, whilst minimising overhead expenses to achieve this objective.

Work has commenced on the development and implementation of a Strategic Asset Management System that will align with the asset management system standard ISO 55001:2014. This standard aligns with the ISO management systems framework.

The new integrated Business Management System (iBMS) will integrate the core management system components, such as policy management, risk assessment, training and competence, communication, document control, audit program and management review processes (along with several others), into the existing integrated management system used by the Company.

The requirements of ISO 55001 are to be adopted to provide an optimised return on asset investment, to increase confidence and performance in long term planning and to provide a clear line of sight for the implementation of corporate objectives through the organisational structure.

6.2.1 Information and Communication Technology Improvements

These projects have been described in more detail in the Information and Communication Technology Asset Management Plan and hence, budget and resource requirements for these projects are included there.

1. AGA-03 Data management continuous improvement (2014-2019) - The Data Management Continuous Improvements project aims to provide funds for what is primarily a collection of reporting and analysis tools to assist with a better understanding of areas including Unaccounted for Gas, Gas Monitoring data, Leak Survey, Gas Quality and Pressure Correction Factor Calculations.

The Data Management application suite comprises of the following applications/tools:

• Gas Monitoring Data (GMD) - application used to collect and process gas monitoring metering data and gas quality. Critical application storing data on AGA’s network performance. Interfaces to Network Data Visualisation application to provide a real time view of the Gas Distribution Network.

• Pressure Correction Factor (PCF) Tool – tool used to calculate the PCF factor required for NMIS billing. Methodology and application frequency of the PCF is being investigated within Access Arrangement 4.

• Leak Survey – recently implemented solution interfacing to Gas Network Information System (GNIS) and using high resolution GPS tracking devices to ensure AGA’s Safety Case leak survey requirements are met.

In the 2014-2019 period, a number of improvements have been identified to further utilise and refine existing tools and reports. Additionally, it is anticipated that further reporting requirements will be identified during this period to satisfy both AGA management, and for regulatory purposes.

2. AGA-04 Network Data Visualisation continuous improvement (2014-2019) - The NDV (Network Data Visualisation) initiative was initiated in 2010 and provides a near-real-time representation of the hydraulic performance of the GDS.

There are two basic streams to NDV:

• Network Visualization. Primarily used by AGA’s Control Room for the following:

• Efficient allocation of vehicles to faults

• Efficient resource management

• Ability to meet network monitoring KPIs

• Seamless Control Room business process overview and display



• User friendly display of real-time information

• Improved Emergency management (Alarms & Faults)

• Network Modelling. Used by Asset Services to perform near-real-time capacity modelling of the GDS and uses up-to-date gate point inflow data sourced by AGA’s System Monitoring system GIMS (Gas Inflows Management System), to streamline the process taken to produce the models.

• Ability to extract assets for network modelling

• Ability to work with current data for near real time hydro-graphic modelling simulations

• Faster and more efficient network modelling process through tools automation

• Improved network model accuracy

The NDV continuous improvement project aims to build on the investment to date deliver further required improvements to both the modelling and visualisation streams. By enhancing the modelling stream, this will benefit the area of network emergency response management. This is achieved by providing the Company with the ability to integrate near-real-time data with simulated network activities to deliver a holistic decision making solution. Further developing schematics for High, Medium and Medium Low Pressure networks will benefit Control Room Operations in particular during curtailment and emergency response scenarios.

3. AGA-05 Field mobility continuous improvement (2014-2019) - ATCO Gas Australia embarked on a Field Mobility project in 2011 with the aim to streamline field operations through the introduction of a rugged, tablet-based, mobile solution that integrated with existing Works and Asset Management Systems (SAP). This solution brought together Yambay’s mDrover product suite, Panasonic’s H2 tablet and Telstra’s Next G communications network.

The Field Mobility project was well-defined, designed, built and comprehensively tested before the first release was successfully deployed to Customer Service personnel on the 1st May 2013. The second and final release of the project was deployed on the 28th November 2013 and in its test phase with Facilities Maintenance with a proposed rollout to Maintenance in January 2014.

It was anticipated that enhancements would be required once the initial phases of the Field Mobility solution was implemented to fine tune existing functionality and to add new enhancements to further streamline business processes from a Network Operations perspective.

The enhancements scheduled for the 2014 – 2019 period aim to leverage AGA’s Field Mobility Projects to apply continued improvements to its Field Mobility solution and provide further integration to other AGA core systems (Network Data Visualisation (NDV), EHS & R system, SAP) to further streamline business processes.

4. AGA-11 Business Process Standardisation and Integration (2015-2019) - This initiative aims to implement ATCO Gas Australia’s integrated Business Management System (iBMS) to effectively manage activities associated with owning and operating the Gas Distribution System. The iBMS combines asset, health and safety, environment and quality management requirements and outlines policies, standards and procedures that that have been developed and will be adopted to meet the requirements of ISO 55001:2014, AS/NZS 4804:2001, ISO 14001:2004 and ISO 9001:2008. Implementation of this project will improve efficiency by providing a structured and integrated approach aligned with international standards to work processes within the Company to reduce work duplication. Integrated processes will enable a platform to improve data capture consistency and accuracy to inform decision-making processes. This initiative includes the following:

• Implement AGA’s integrated Business Management System (iBMS) processes and procedures to ensure that the organisation can fulfil all tasks required to meet its legislative and strategic objectives.



• Formalise and communicate the iBMS, to provide an overview of how it integrates each of the individual management systems.

• Enhancements to IT business systems to assist in the implementation of the iBMS.

• Development of interfaces between IT business systems to assist in the implementation of the iBMS.

5. AGA-14 Management Information System (2014-2019) – The Management Information System proposed in this project mandate is the enabling of the SAP Business Warehouse (SAP BW) capability, the implementation of a compatible reporting tool software (to be determined through a detailed analysis and procurement process), the assessment and confirmation of the data structure and architecture in AGA’s databases, and the connection of the bespoke linkages already developed as part of the implementation of AGA’s key systems in an effort to create a single source of truth/single view of asset.

This is a new system whose overall project is required to consolidate data into one location from multiple users to ensure that all reporting and analysis utilises the most accurate, verifiable and up to date data. MIS requires the following:

• The Management Information System is required to ensure any technical improvements are sustainable, scalable and capable of delivering business benefit;

• Finance planning, budgeting and reporting; and

• The Asset Management Single View of the Asset (SVA) and reporting.

These will require the implementation of SAP BW, Reporting and Dashboarding. This initiative aims to address the following:

• Consolidate the disparate data currently generated by the core AGA applications;

• Remove the need for Access Databases as created by users which is currently not supported;

• Remove laborious manual manipulation of data sheets currently being performed by users across multiple AGA business units;

• Provide a Single View of the Asset (SVA) for higher data integrity; and

• Provide the ability for users to generate their own reports thereby allowing for greater turnaround time.

6. AGA-15 SAP EHS&R Stage 2.2 - Risk Assessment (2014-2019) - AGA operates in a highly regulated environment, in particular, in the area of Environmental, Health and Safety where there are statutory and regulatory obligations for AGA to provide safe, reliable and efficient supply of gas to customers through its network, to provide safe and healthy workplace for its employees, and to protect the environment.

To support AGA’s compliance with these obligations, it is critical that AGA has an efficient and effective Environmental, Health and Safety system in place that meets its operational requirements.

The JASPER system will replaced by the SAP EHS&R system in 2014. The scope of Stage 2.1 SAP EHS is Incident Management and ERP System Integration.

The EHS&R Stage 2.2 - Risk Assessment initiative covers the HSE and technical hazard and risk assessment conducted by the HSE team, and the technical compliance team. This project including the following phases:

• Realisation - Implementation of business processes as defined in the Blueprint. The solution is configured, developed, tested and documented.

• Final Preparation - Completion of cutover activities (including technical and load testing, end user training, system management and cutover rehearsal activities) to finalise the readiness to go-live.



Each of the following types of register will be represented by a different risk assessment type allowing for different process steps, separate reporting, role assignment and location structure:

• Management of the Environmental Health and Safety SWI (Safe Work Instruction) Hazard Register items

• Management of HSE Environmental Aspects and Impacts Register

• Management of FSA (Formal Safety Assessment) for Safety Management Study (AS2885) and Network Risk Assessment (AS4645)

There will be the following sub-processes for each process above:

• Risk Assessment Initiation

• Assess Risk

• Risk Control and Reduction

• Risk Master Data Administration

• Assurance of Controls

7. AGA-16 SAP EHS&R Stage 2.3 – GRC (2016-2019) - AGA operates in a highly regulated environment, in particular, in the area of Environmental, Health and Safety where there are statutory and regulatory obligations for AGA to provide safe, reliable and efficient supply of gas to customers through its network, to provide safe and healthy workplace for its employees, and to protect the environment.

To support AGA’s compliance with these obligations, it is critical that AGA has an efficient and effective Environmental, Health and Safety system in place that meets its operational requirements.

The JASPER system will replaced by the SAP EHS&R system in 2014.

Stage 2.3 SAP GRC and Process Control covers the corporate risk assessments conducted by the Risk and Compliance Team, and the management of compliance obligations relevant to AGA.

The EHS Incident Management module does not cover these activities, and SAP has a separate module called “Governance, Risk and Compliance” (GRC), which is specifically designed for corporate risk and compliance.

8. AGA-18 Strategic Asset Management (2015-2019) – To enable safe, reliable and prudent Asset Management decision making, AGA require a solution to be able to clearly identify asset health, performance and condition for aging assets. To provide the information required to make these decisions, various business processes and SAP architecture re-engineering is required. With these redeveloped business processes, AGA will be able to better target areas requiring asset replacement and deliver more efficient allocation of maintenance expenses to allow for reduced lifecycle costs.

In 2013, SAP Consultants Total Asset Management Solutions (TAMS) was engaged to conduct a conceptual study of AGA’s current SAP landscape and provide recommendations for the SAP roadmap going forward. TAMS are a reputable SAP Service Partner - niche consulting company – specialising in solutions and services for Asset Management – From Strategy to Maintain and Operate.

Using the recommendations provided from the TAMS Conceptual Study, this project will entail the re-engineering of the SAP technical asset register, along with the associated Master Data and will include asset creation, replacement and disposal processes that are validated with AGA accounting practices. It will also establish business processes for asset lifecycle management, particularly maintenance planning, scheduling, execution and close-out of maintenance activity transactional data for network assets. This will include areas such as



Materials Management, Task-lists, Maintenance strategies and tactics, Rotable Assets, Warranty information and Work Permits. This functionality will enable a reporting structure for predictive maintenance analysis, maintenance cost budgeting and capital replacement programming within the SAP environment to provide full transparency and traceability for optimised lifecycle asset management within a single source of truth.

9. AGA-22 Project Portfolio Management (2015-2019) – The total capital expenditure proposed for ATCO Gas Australia (AGA) is divided into two portfolios:

• Network Infrastructure – > $600 million comprised of approximately 160 projects; and

• Information Technology - $27 million comprised of 28 projects.

The forecast capital expenditure program for the Access Arrangement 4 regulatory period is required to achieve the following:

• Deliver the requirements of the Safety Case;

• Facilitate new connects as a result of customer initiated activity and extensions and expansions to maintain system integrity and support new residential developments;

• Support business growth and functions through information technology, depots, plant and equipment.

Both portfolios are currently being managed via disparate, non-integrated solutions ranging between Excel spreadsheets, Microsoft Project, MS Word and Enterprise Information Management (EIM) (AGA’s document management system).

AGA require a solution that provides a near real-time view of the overall status and performance of projects and offers a collaborative mechanism where all Business Units can effectively and efficiently communicate and share information to plan, review and approve programmes of work.

This mandate outlines a project to introduce a Project Portfolio Management (PPM) tool for AGA. A PPM tool is an integrated solution that gives users a near real-time view of information at a project, program, or portfolio level. It empowers AGA Managers to improve investment decision-making and enhances collaboration between all parties.

A PPM toolset will enable greater efficiency in resource planning, allocation, project cost control and project related procurement at both a strategic and tactical level. The tool will interface seamlessly with the SAP financial system to track actual and budget figures for these portfolios.

10. AGA-26 SAP Functional Enhancements (2014-2019) – SAP is a fully integrated ERP (Enterprise Resource Planning) system. SAP is part of AGA’s Information Technology Strategy Plan and is critical to support the following business areas:

• Finance

• Human Resources

• Plant Maintenance

• Project Systems

• Materials Management and Sales Distribution.

Network Operations use SAP to manage the maintenance and repair of AGA’s distribution assets, and the construction of new assets via the following modules: Asset Accounting (AA); Project Systems (PS); Plant Maintenance modules (PM); and Materials Management (MM). SAP maintains AGA’s asset register and manages work orders – capturing data for work that is carried out to an asset.



SAP is tightly integrated with the following core AGA systems:

• Network Metering Information System (NMIS) – AGA’s core billing system;

• Gas Network Information System (GNIS) – system providing a graphical representation of AGA’s distribution assets and legal / cadastral land parcels ;

• Field Mobility – solution involving the deployment of mobile devices to Network Operations field staff enabling electronic despatch of work that can be easily monitored;

• Network Data Visualisation (NDV) – Provides near-real-time visual representation of the GDS’ performance and vehicle tracking; and enables near-real-time representation of the hydraulic performance of the GDS network for operational and strategic purposes and is used to assist in the event of an emergency critical scenario.

In 2013, AGA engaged a SAP Service Partner vendor to conduct a conceptual study of AGA’s current SAP landscape and provide recommendations for the SAP roadmap going forward. The recommendations from the study included a re-engineering exercise of the SAP technical register, along with the associated SAP Master Data and will include asset creation, replacement and disposal processes that are validated with AGA accounting practices.

The SAP Continuous Improvements mandate has been created for two main streams:

• To ensure that the operational capability of the application suite is maintained, to meet necessary regulatory requirements, safety and changing business needs.

• To allocate funding for tasks to assist in the SAP re-engineering exercise. Recommended actions were identified in the SAP PM Data Master Configuration Report.

Table 45: Technology Projects Required to Support Asset Management Systems

Initiative Name Project/RFE Description CAPEX/ OPEX 2014 2015 2016 2017 2018 2019 Total

('000s) AGA-03 Data Management System Continuous Improvements

Summary of RFEs covering the following: GMD, PCF Tools, and other reporting requirements CAPEX 10 85 70 140 150 150 605

Dashboard for weekly and daily bulletin CAPEX 10 0 0 0 0 0 10

GMD Interface for PCF calculation CAPEX 0 50 0 0 0 0 50

Facilities - Add Cathodic Protection Transformer Rectifier Unit (TRU) measurement docs to SAP to produce CP reports from SAP

CAPEX 0 0 50 0 0 0 50

PCF Tool for monthly reporting CAPEX 0 0 20 0 0 0 20 UAFG Investigations CAPEX 0 35 0 0 0 0 35 Leak Survey solution

enhancements CAPEX 0 0 0 40 0 0 40

Gas Quality odorant solution CAPEX 0 0 0 40 0 0 40 Other CAPEX 0 0 0 60 150 150 360 AGA-04 NDV Continuous Improvements

Summary of RFEs related to NDV CAPEX 83 300 250 200 200 200 1,233

Functional Enhancements CAPEX 83 225 250 200 200 200 1,158 Infrastructure Enhancements CAPEX 0 75 0 0 0 0 75 AGA-05 Field Mobility Continuous Improvements

Summary of RFEs related to Field Mobility CAPEX 246 300 300 450 450 450 2,196

Toughbook map navigation CAPEX 0 50 0 0 0 0 50 Hazard Integration with SAP CAPEX 246 0 0 0 0 0 246 Incident Reporting integration CAPEX 0 48 0 0 0 0 48



SAP Qualifications integration CAPEX 0 130 0 0 0 0 130 GIS View Integration CAPEX 0 48 0 0 0 0 48 HSE, Training Assessments,

Inspections to SAP CAPEX 0 25 0 0 0 0 25

Other Functional Enhancements CAPEX 0 0 300 450 450 450 1,650 AGA-11 Business Process Standardisation

Investigate, report and modify AGA business systems to align to ISO-55000 standard.

CAPEX 0 466 412 410 410 450 2,147

Analysis of existing systems to meet AGA Integrated Management System (iBMS) Framework

CAPEX 0 136 0 0 0 0 136

Apply business process changes CAPEX 0 80 160 160 160 160 720 Application changes CAPEX 0 150 152 150 150 190 792 Develop interfaces CAPEX 0 100 100 100 100 100 500 AGA-14 MIS Summary of Initiatives relating to

the Management Information System

CAPEX 240 111 567 782 894 820 3,414

Blueprint Phase CAPEX 144 0 0 0 0 0 144 Contract Negotiation CAPEX 96 0 0 0 0 0 96 Business Case CAPEX 0 20 0 0 0 0 20 Reports CAPEX 0 0 0 50 50 50 150 Design and Implementation OPEX 0 91 532 490 448 407 1969 MIS Phase 2 OPEX 0 0 35 206 190 174 605 MIS Phase 3 OPEX 0 0 0 35 206 190 431 AGA-15 SAP EHS&R Stage 2.2 - Risk Assessment

Implementation of Stage 2.2 Activities OPEX 10 110 101 93 84 0 398

AGA-16 SAP EHS&R Stage 2.3 - GRC

Implementation of Stage 2.3 Activities OPEX 0 0 42 48 44 40 175

AGA-18 Strategic Asset Management

Asset Performance Management Feasibility Study CAPEX 0 680 720 641 1020 670 3,731

Plant Maintenance (PM) / Finance Control (FI) Alignment CAPEX 0 0 0 441 600 250 1,291

Other CAPEX 0 680 720 200 420 420 2,440 AGA-22 Project Portfolio Management

Summary of Initiatives Relating to PPM OPEX 0 64 92 84 77 30 347

Implement PPM OPEX 0 64 92 84 77 30 347 AGA-26 SAP Functional Continuous Improvements

Summary of Initiatives relating to the SAP ERP System OPEX 72 238 345 343 332 340 1,671

Project Allocation OPEX 72 238 345 343 332 340 1,671

Network IT CAPEX Total ($'000s) 1,157 3,792 4,071 4,513 5,404 4,710 23,647

Network IT OPEX Total ($'000s) 155 804 1,585 1,728 1,791 1,549 7,613



7. Definitions Term / Acronym

Definition Term / Acronym

Definition

ABS Australian Bureau of Statistics IND Industrial Metering facility ACP Asset Class Plan IT Information Technology AMP Asset Management Plan KPI Key Performance Indicators AMS Asset Management System LOM Line of Main APA APA Group LP Low Pressure AS Australian Standard LPG Liquid Petroleum Gas CAIDI Customer Average Interruption Duration

Index LTI Lost Time Injury

CAPEX Capital Expenditure LTIFR Lost Time Injury Frequency Rate CI Cast Iron MAOP Maximum Allowable Operating Pressure CP Cathodic Protection MDPE Medium Density Polyethylene DBNGP Dampier to Bunbury Natural Gas Pipeline MGL Mandurah Gas Lateral DBP Dampier to Bunbury Pipeline MLV Main Line Valve DCVG Direct Current Voltage Gradient MP Medium Pressure DoCC Department of Climate Change NA Not Applicable DRC Depreciated Replacement Cost NGL National Gas Law ECS Economics Consulting Services NGR National Gas Rules EnergySafety Technical Consultants representing ERA ODM Optimised Decision Making ERA Economic Regulation Authority OPEX Operating Expenditure ERP Enterprise Resource Planning P&E Plant and Equipment FMEA Failure Modes and Effects Analysis PE Polyethylene FMECA Failure Modes, Effects and Criticality

Analysis PEHP Polyethylene High Pressure

FSA Formal Safety Assessment PMD Pressure Monitoring Device GDL8 Gas Distribution Licence 8 PRS Pressure Regulation Station GDS Gas Distribution System RCA Root Cause Analysis GGTP Goldfields Gas Transmission Pipeline SAIDI Safety Average Interruption Duration Index GI Galvanised Iron SAIFI Safety Average Interruption Frequency Index GSL Guaranteed Service Level SAP Systems Application Products GSSSR2000 Gas Standards (Gas Supply and System

Safety) Regulations 2000 TRU Transformer/Rectifier Unit

HP High Pressure UAFG Unaccounted for Gas HPR High Pressure Regulator uPVC Unplasticised Polyvinylchloride HR Human Resources WA Western Australia HSEQ Health, Safety, Environment and Quality IIMM International Infrastructure Management

Manual



8. References

Document Number Document Title

AST PO00001 Asset Management Policy

WAGN PO 0001 Corporate Risk Management Policy

WAGN PO 002 WAGN Risk Management Policy

WAGN CHTR 001 Customer Service Charter

WAGN CHTR 002 WAGN Economic Regulatory Compliance Committee Charter

WAGN CHTR 003 WAGN HSEQ Operational Compliance Committee Charter

WAGN CHTR 004 WAGN Operational Compliance Committee Charter

WAGN CHTR 005 WAGN Technical Regulatory Compliance Committee Charter

WAGN CHTR 006 GD HSE Committee Charter 2009 2011

WAGN CHTR 007 Gas Distribution Inspection and Audit Team Charter

Multiple Documents Asset Class Plans

WAGN G 010 Contractor Management

WAGN G 0001 Risk Management Guidelines

WAGN G 003 WAGN Risk Management Guideline

GD PL 0140 Albany LPG Storage Facility Safety Case

GD PL 0130 GDS Safety Case

GD PL 0150 MGL Safety Case

GD PR 0041 Management of Change Presentation

GD PR 0041 Management of Change

WNE PR 0310 Management Review

WAGN R 0001 Gas Distribution WAGN Audit Schedule

GD WI 0400 WAGN Contractual and Operational KPI Reporting

GDW WI 5090 Recordkeeping Practices for Inspection & Audit Group

GD ST 0070 Asset Replacement Strategy

GDW RP 0200 Description of WA Gas Network Gas Distribution Network

AST ST00001 Network Asset Replacement Strategy

AST ST00002 Network Maintenance Strategy

AST ST00003 Network Planning Strategy

AST ST00004 Network Operating Strategy

ENS ST00001 Network Design and Construction Strategy

ANS-BP-AM013 Seasonal Load Factor Review

Multiple Documents Design Guidelines and Engineering Standards

Table 46: Reference Documentation Affecting the Asset Management Plan



Gas Energy Attitudes Focus Groups, (November 2009), Patterson Market Research

4656.5 Household Choices Related to Water and Energy, (October 2009), Australian Bureau of Statistics, [online], Accessed 12/03/2012,

http://www.ausstats.abs.gov.au/ausstats/subscriber.nsf/0/33DDF4E11D6FE823CA257743001A9855/$File/46565_october%202009.pdf

Natural Gas Networks: Vision to 2050 Modelling and Scenario Analysis, (December 2011), Core Energy Group





9. Appendices

9.1 Appendix A – Geographical Locations of Gas Distribution Networks

Figure 18: Coastal North Metropolitan Distribution Network Map



Figure 19: Coastal South Metropolitan Distribution Network Map



Figure 20: Coastal Northern and Goldfields Distribution Network Map



Figure 21: South West Distribution Network Map



9.2 Appendix B – GDL8 Licence Performance Reporting Indicators and Trends Table 47: Performance Measures for ERA Licence Performance Levels of Service

No. Indicators

Customer Connections

DA 1 Total number of connections provided

DA 2 Total number of connections that were not provided on or before the agreed date

DA 3 Total number of reconnections provided

DA4 Total number of reconnections that were not provided within the prescribed timeframe

DA5 Total number of delivery points on the distributor’s network

Gas Consumption

DB 1 Gas consumption - residential delivery points (GJ)

DB 2 Gas consumption - non-residential delivery points (GJ)

DB 3 Unaccounted for gas (GJ)

Leaks

DC 1 Number of leak repairs to HP, MP and LP mains

DC 2 Number of leak repairs to HP, MP and LP service connections

DC 3 Number of leak repairs to HP, MP and LP meters

Network Reliability

DD 1 Number of customer delivery points that have been interrupted for more than 12 hours continuously during the reporting period

DD 2 Number of customer delivery points that have been affected by 5 or more unplanned interruptions during the reporting period

DD 3 The average percentage of time that gas has been supplied to customer premises during the reporting year

Complaints

DE 1 Total number of complaints received

DE 2 Number of the complaints that relate to administrative process or customer service complaints

DE 3 Number of other complaints

DE 4 Number of connection and augmentation complaints

DE 5 Number of reliability of supply complaints

DE 6 Number of quality of supply complaints

DE 7 Number of network charges and costs complaints

DE8 Number of complaints from customers concluded within 15 business days

DE9 Percentage of complaints from customers concluded within 15 business days

DE10 Number of complaints from customers concluded within 20 business days



DE11 Percentage of complaints from customers concluded within 20 business days

Call Centre Performance

DF 1 Total number of telephone calls to a call centre operator

DF 2 Total number of telephone calls to a call centre answered by a call centre operator within 30 seconds

DF 3 Percentage of telephone calls to a call centre answered by a call centre operator within 30 seconds

DF 4 Average duration (in seconds) before a is call answered by a call centre operator

DF 5 Total number of the calls that are unanswered

DF6 Percentage of the calls that are unanswered

Network Construction

Length of gas distribution mains constructed from (km) High Pressure Medium Pressure Low Pressure

DG 1 Cast iron

DG 2 Unprotected steel

DG 3 Protected steel

DG 4 PVC

DG 5 Polyethylene

DG 6 Other

DG 7 Total length of all distribution mains installed and in service

DG 8 Number of service connections per kilometre of gas mains

Guaranteed Service Level Payments

AA 1 Total number of GSL payments for late arrival for a gas fault or emergency appointment

AA 2 Total amount of GSL payments for late arrival for a gas fault or emergency appointment

AA 3 Total number of GSL payments for late establishment of a gas service

AA 4 Total amount of GSL payments for late establishment of a gas service

AA 5 Total number of GSL payments for more than 4 unplanned interruptions in a calendar year

AA 6 Total amount of GSL payments for more than 4 unplanned interruptions in a calendar year

AA 7 Total number of GSL payments for unplanned interruptions greater than 12 hours continuously

AA 8 Total amount of GSL payments for unplanned interruptions greater than 12 hours continuously

9.2.1 Customer Connections

The purpose of this measure is to report the number of small use customer connections supplied by the GDS. This measure is trending upwards as per the future demand indicated in the new connections forecast and has a difference between forecast and actual of about 10%.



Table 48: ERA Licence Performance Reporting - Customer Connections

A Customers and Customer Connections Unit 2010 2011 2012 2013

DA 1 Total number of connections provided # 16,911 19,611 NA NA

DA 2 The total number of connections not provided on or before the agreed date

# 6 7 NA NA

DA 3 Total number of customers who are connected to the distributor's network

# 627,205 636,323 NA NA

Note: Reporting requirement changed for section A in 2012

DA 1 Total number of connections provided # NA NA 14,752 15,423

DA 2 Total number of connections that were not provided on or before the agreed date

# NA NA 3 2

DA 3 Total number of reconnections provided # NA 2,655 2,727 3,692

DA 4 Total number of reconnections that were not provided within the prescribed timeframe

# NA NA NA 22

DA 5 Total number of delivery points on the distributor’s network # NA NA 652,808 673,878

9.2.2 Gas Consumption

The purpose of this measure is to report on the amount of gas supplied through the GDS to small use customers and the level of unaccounted for gas.

Table 49: ERA Licence Performance Reporting - Gas Consumption

ID Gas Consumption Unit 2010 2011 2012 2013

DB 1 Gas consumption - residential (GJ) # 10,806,658 10,563,707 9,528,366 NA

DB 2 Gas consumption - residential percentage change from previous year

% 1.8 -2.2 -9.8

DB 3 Gas consumption non-residential (GJ) # 17,231,682 17,397,626 NA

DB 4 Gas consumption - non-residential percentage change from previous year

% 0.2 1.0 -4.4

DB 5 Peak gas demand (GJ/hour) # 8,960 9,758 NA

DB 6 Unaccounted for gas (GJ) # 866,667 920,371 NA

Note: Reporting requirement changed for section A in 2012

DB 1 Gas consumption - residential delivery points (GJ)

# NA NA NA 10,017,511

DB 2 Gas consumption - non-residential delivery points (GJ)

# NA NA 16,633,141 1,241,075

DB 3 Unaccounted for gas (GJ) # NA NA 783,640 813,898

9.2.3 Leaks

The purpose of this measure is to report on the number of loss of containment events on the GDS.

High pressure (HP) means the parts of the distribution system operating at a pressure in the range 210 to 1050kPa. This also includes any parts of the distribution system operated at a pressure in excess of 1050kPa that have been designated as part of the distribution system.



Medium pressure (MP) means the parts of the distribution system operating at a pressure in the range 7 to 210kPa.

Low pressure (LP) means the parts of the distribution system operating at a pressure of up to 7kPa.

Table 50: ERA Licence Performance Reporting - Leaks

2010 No. of Leak Repairs 2011 No. of Leak Repairs

Location of Leak

LP MP HP Location of Leak

LP MP HP

Mains 320 593 3 Mains 235 354 11

Services 2,329 3,882 270 Services 2,188 3,492 323

Meters 447 602 30 Meters 404 539 65

Totals 3,096 5,077 303 Totals 2,827 4,385 399

2012 No. of Leak Repairs 2013 No. of Leak Repairs

Location of Leak

LP MP HP Location of Leak

LP MP HP

Mains 270 548 12 Mains 233 595 7

Services 1,784 3,631 242 Services 2,128 4,264 222

Meters 258 538 20 Meters 240 236 10

Totals 2,312 4,717 274 Totals ,2601 5,095 239

9.2.4 Network Reliability

The purpose of this measure is to report on the frequency and duration of interruptions to supply experienced by customers on the GDS during the reporting year.

Table 51: ERA Licence Performance Reporting – Network Reliability 1

ID Network Reliability Unit 2010 2011 2012 2013

DD 1 Number of customer connections that have been interrupted for more than 12 hours continuously during the reporting period

# 0 0 0 640

DD 2 Number of customer connections that have been affected by 5 or more unplanned interruptions during the reporting period

# 0 0 0 0

DD 3 The average percentage of time that gas has been supplied to customer premises

% 100.0 99.999 99.999 99.9996

9.2.5 Complaints

The purpose of this measure is to report on the level of satisfaction with the distribution service and to provide information about the level of customer complaints against the defined categories.

Table 52: ERA Licence Performance Reporting - Complaints

ID Complaints 2010 2011 2012 2013

DE 1 Total number of complaints received # 38 35 36 25

DE 2 Number of administrative processes or customer service complaints

# 1 2 5 6

DE 3 Number of other complaints # 15 18 13 10

DE 4 Number of connection and augmentation complaints received # 8 4 4 4



DE 5 Number of reliability of supply complaints # 11 8 11 2

DE 6 Number of quality of supply complaints # 2 2 3 3

DE 7 Number of network charges and costs complaints # 1 1 0 0

DE 8 Number of complaints from customers concluded within 15 business days

# NA NA NA 23

DE 9 Percentage of complaints from customers concluded within 15 business days

% NA NA NA 92

DE 10 Number of complaints from customers concluded within 20 business days

# NA NA NA 0

DE 11 Percentage of complaints from customers concluded within 20 business days

% NA NA NA 0

9.2.6 Call Centre Performance

The purpose of this measure is to report on the level of service provided to customers who contact the ATCO Gas Australia by telephone.

Table 53: ERA Licence Performance Reporting - Call Centre Performance

F Call Centre Performance 2010 2011 2012 2013

DF 1 Total number of telephone calls to an operator # 41,132 37,391 36,824 66,933

DF 2 Total number of telephone calls to a call centre answered by a call centre operator within 30 seconds

# 36,752 32,794 32,468 52,966

DF 3 Percentage of telephone calls to a call centre answered by a call centre operator within 30 seconds

% 89.4 87.7 88.2 79.1

DF 4 Average duration (in seconds) before a is call answered by a call centre operator

# 16 10 9 31.4

DF 5 Total Number of the calls that are unanswered # 670 550 567 2,117

DF 6 Percentage of the calls that are unanswered % 1.6 1.5 1.5 3.2

9.2.7 Network Construction

The purpose of this measure is to report on the construction materials used in the distribution system and the relative density of service connections.

Table 54: ERA Licence Performance Reporting - Network Construction

2010 In-service Length [km] 2011 In-service Length [km]

Construction Material LP MP HP Construction

Material LP MP HP

Cast Iron 38.3 - - Cast Iron 36.4 - -

Unprotected Steel 134.1 84.1 - Unprotected Steel 130.9 80.0 -

Protected Steel - 10.6 741.6 Protected Steel - 14.4 758.4

PVC 3,652.6 5,993.9 - PVC 3,634.8 6,010.5 -

Polyethylene (PE) 47.2 1,518.9 558.6 Polyethylene (PE) 45.3 1,678.7 576.7

Other 39.1 30.5 5.9 Other 32.9 50.0 0.2

Totals 3,911.3 7,638.0 1,306.2 Totals 3,880.4 7,833.6 1,335.3



2012 In-service Length [km] 2013 In-service Length [km]

Construction Material LP MP HP LP Construction

Material LP MP HP

Cast Iron 27.9 0.0 0.0 Cast Iron 27.9 0.0 0.0

Unprotected Steel 117.1 60.0 0.0 Unprotected Steel 117.1 60.0 0.0

Protected Steel 0.0 56.1 732.4 Protected Steel 0.0 56.1 732.4

PVC 3619.6 6007.7 0.0 PVC 3619.6 6007.7 0.0

Polyethylene (PE) 65.4 2269.6 373.3 Polyethylene (PE) 65.4 2269.6 373.3

Other 26.3 12.1 0.0 Other 26.3 12.1 0.0

Totals 3856.3 8405.5 1105.7 Totals 3856.4 8405.5 1105.7

9.2.8 Guaranteed Service Level (GSL) Payments

The purpose of this measure is to report on the number and amounts of GSL payments under the Access Arrangement.

Table 55: ERA Licence Performance Reporting - Guaranteed Service Level Payments

H Guaranteed Service Level Payments 2010 2011 2012 2013

AA 1 Total number of GSL payments for late arrival for a gas fault or emergency appointment

# 0 0 0 0

AA 2 Total amount of GSL payments for late arrival for a gas fault or emergency appointment

$ 0 0 0 0

AA 3 Total number of GSL payments for late establishment of a gas service

# 7 0 3 2

AA 4 Total amount of GSL payments for late establishment of a gas service

$ 680 0 120 120

AA 5 Total number of GSL payments for more than 4 unplanned interruptions in a calendar year

# 0 0 0 0

AA 6 Total amount of GSL payments for more than 4 unplanned interruptions in a calendar year

$ 0 0 0 0

AA 7 Total number of GSL payments for unplanned interruptions greater than 12 hours continuously

# 0 0 0 0

AA 8 Total amount of GSL payments for unplanned interruptions greater than 12 hours continuously

$ 0 0 0 0



9.3 Appendix C – Network CAPEX Projects Project Description 2H 2014 2015 2016 2017 2018 2019 Total ($'000s) NGR Rule GROWTH CAPEX $18,715 $39,203 $51,814 $42,645 $41,457 $34,704 $228,537 Customer Initiated $15,677 $28,724 $27,766 $27,742 $28,173 $28,232 $156,314 Medium & Low Pressure Mains $5,096 $8,940 $8,442 $8,412 $8,515 $8,509 $47,915

Variable Volume Mains - Growth $5,096 $8,940 $8,442 $8,412 $8,515 $8,509 $47,915 Rule 79 (1)(a), (2)(c)(i)(ii)

Metering & Service Pipes $10,580 $19,783 $19,324 $19,330 $19,658 $19,723 $108,399

Variable Volume Meters and Service Pipes - Customer Initiated $10,580 $19,783 $19,324 $19,330 $19,658 $19,723 $108,399 Rule 79 (1)(a), (2)(a)

Demand $3,038 $10,479 $24,048 $14,903 $13,283 $6,472 $72,224 High Pressure Polyethylene Pipelines $215 $502 $1,144 $1,860

Reinforcement - North West Coastal Hwy, Geraldton $854 $854 Rule 79 (1)(a), (2)(c)(ii)

Reinforcement - Secret Harbour $290 $290 Rule 79 (1)(a), (2)(c)(ii)

Reinforcement - South Perth $502 $502 Rule 79 (1)(a), (2)(c)(ii)

Reinforcement - Vasse New Town $215 $215 Rule 79 (1)(a), (2)(c)(ii)

High Pressure Steel Pipelines $1,960 $8,490 $21,713 $13,579 $11,411 $5,209 $62,362

Elizabeth Quay & Perth CBD Risk Reduction Project - Growth 60% $1,960 $3,112 $4,200 $9,271 Rule 79 (1)(a), (2)(a)

Reinforcement - Capel to Busselton $5,209 $5,209 Rule 79 (1)(a), (2)(c)(ii)

Reinforcement - Karrinyup Rd, Innaloo $3,874 $3,874 Rule 79 (1)(a), (2)(c)(ii)

Reinforcement - Pinjarra $5,378 $5,378 Rule 79 (1)(a), (2)(c)(ii)

Spurline - Baldivis $5,417 $5,417 Rule 79 (1)(a), (2)(a)

Spurline - Peel - Growth $5,994 $5,994 Rule 79 (1)(a), (2)(a)

Spurline - Two Rocks - Growth 60% $13,638 $13,579 $27,218 Rule 79 (1)(a), (2)(a)

Medium & Low Pressure Mains $530 $850 $1,789 $813 $210 $646 $4,839

Reinforcement - Albany Hwy, Vic Park $23 $23 Rule 79 (1)(a), (2)(c)(ii)

Reinforcement - Amelia St, Balcatta $59 $59 Rule 79 (1)(a), (2)(c)(ii)

Reinforcement - Bolton Ave $262 $262 Rule 79 (1)(a), (2)(c)(ii)

Reinforcement - Centre Rd, Kelmscott $268 $268 Rule 79 (1)(a), (2)(c)(ii)

Reinforcement - Fisher St, Belmont $200 $200 Rule 79 (1)(a), (2)(c)(ii)

Reinforcement - Gay St to Southern River Rd $296 $296 Rule 79 (1)(a), (2)(c)(ii)

Reinforcement - Gay St to Warton Rd $34 $34 Rule 79 (1)(a), (2)(c)(ii)

Reinforcement - Gerald St to Elizabeth St $296 $296 Rule 79 (1)(a), (2)(c)(ii)

Reinforcement - Gildercliffe Rd, Scarborough $9 $9 Rule 79 (1)(a), (2)(c)(ii)

Reinforcement - Hepburn Ave to Mirrabooka Ave, Alexander Heights $599 $599 Rule 79 (1)(a), (2)(c)(ii)

Reinforcement - Karel Ave to Brockman $274 $274 Rule 79 (1)(a), (2)(c)(ii)

Reinforcement - Odin Rd to Mimillya St $155 $155 Rule 79 (1)(a), (2)(c)(ii)

Reinforcement - Orlando St, Kelmscott $108 $108 Rule 79 (1)(a), (2)(c)(ii)


Asset Management Plan (AA4) 2014-2019 Project Description 2H 2014 2015 2016 2017 2018 2019 Total ($'000s) NGR Rule Reinforcement - Pinjar Rd, Carramar $65 $65 Rule 79 (1)(a), (2)(c)(ii)

Reinforcement - Ranford Rd and Warton Rd $646 $646 Rule 79 (1)(a), (2)(c)(ii)

Reinforcement - Ravenswood Rd $260 $260 Rule 79 (1)(a), (2)(c)(ii)

Reinforcement - Station St to Luger Ave, East Cannington $175 $175 Rule 79 (1)(a), (2)(c)(ii)

Reinforcement - Tyre Ave, Riverton $152 $152 Rule 79 (1)(a), (2)(c)(ii)

Reinforcement - Warton Rd, Huntingdale $152 $152 Rule 79 (1)(a), (2)(c)(ii)

Reinforcement - Drummond Cove $804 $804 Rule 79 (1)(a), (2)(a)

Metering & Service Pipes $21 $37 $38 $39 $42 $44 $220

Variable Volume Meters and Service Pipes - Demand $21 $37 $38 $39 $42 $44 $220 Rule 79 (1)(a), (2)(a)

Regulating Facilities $313 $601 $509 $470 $477 $572 $2,942

Capacity Upgrade - MP Regulator Sets $134 $301 $296 $295 $300 $300 $1,625 Rule 79 (1)(a), (2)(c)(iv)

New Supply - BD HPRs $179 $179 $175 $175 $177 $177 $1,062 Rule 79 (1)(a), (2)(a)

Reinforcement - Camborne Pkwy, Butler $95 $95 Rule 79 (1)(a), (2)(c)(ii)

Reinforcement - Lyall St, Redcliffe $38 $38 Rule 79 (1)(a), (2)(c)(ii)

Reinforcement - Atwell $122 $122 Rule 79 (1)(a), (2)(c)(ii)

SUSTAINING CAPEX $17,718 $42,007 $51,532 $64,149 $63,295 $72,589 $311,289 Asset Replacement $15,182 $33,025 $29,101 $29,872 $35,398 $35,110 $177,687 High Pressure Steel Pipelines $89 $3,351 $88 $88 $108 $108 $3,831

EOL Replacement - Anodes $18 $18 $18 $18 $19 $19 $110 Rule 79 (1)(a), (2)(c)(ii)

EOL Replacement - Isolation Valves $70 $141 $69 $70 $71 $71 $492 Rule 79 (1)(a), (2)(c)(i)(ii)

EOL Replacement - TRU $18 $18 $37 Rule 79 (1)(a), (2)(c)(ii)

Replacement - HP014, Bibra Lake $3,192 $3,192 Rule 79 (1)(a), (2)(c)(i)(ii)

Medium & Low Pressure Mains $8,529 $16,810 $17,238 $17,190 $19,722 $19,668 $99,158

EOL Replacement - Cast Iron $2,596 $4,840 $5,151 $5,139 $4,806 $22,533 Rule 79 (1)(a), (2)(c)(i)(ii)

EOL Replacement - Mains (AH) $200 $341 $335 $334 $338 $338 $1,885 Rule 79 (1)(a), (2)(c)(i)(ii)

EOL Replacement - Odd Size Steel Maylands $852 $852 Rule 79 (1)(a), (2)(c)(i)(ii)

EOL Replacement - Odd Size Unprotected Steel $1,512 $1,705 $1,673 $1,666 $1,686 $1,010 $9,253 Rule 79 (1)(a), (2)(c)(i)(ii)

EOL Replacement - PVC Mains & Services $239 $2,384 $2,338 $2,328 $2,355 $2,351 $11,994 Rule 79 (1)(a), (2)(c)(i)(ii)

EOL Replacement - Service Valves $245 $368 $362 $362 $368 $369 $2,075 Rule 79 (1)(a), (2)(c)(i)(ii)

EOL Replacement - Unprotected Metallic Mains $2,885 $7,171 $7,380 $7,361 $10,170 $15,599 $50,566 Rule 79 (1)(a), (2)(c)(i)(ii)

Metering & Service Pipes $6,237 $12,323 $10,944 $11,761 $14,714 $14,747 $70,727

Multistorey Risk Reduction - Multi-Occupancy Buildings $3,194 $3,241 $3,290 $3,298 $13,022 Rule 79 (1)(a), (2)(c)(i)(ii)

Multistorey Risk Reduction - Multistorey Buildings (≥ 3 stories) $2,677 $4,348 $7,026 Rule 79 (1)(a), (2)(c)(i)(ii)

Replacement - M6WA Meters with Plugs $1,146 $1,586 $1,733 $1,727 $1,764 $1,762 $9,717 Rule 79 (1)(a), (2)(c)(i)

Routine Meter Change Programme (RMC) $1,624 $4,790 $4,387 $5,104 $7,883 $7,839 $31,628 Rule 79 (1)(a), (2)(c)(iii)

Variable Volume Meters and Service Pipes - Replacement $789 $1,598 $1,631 $1,690 $1,778 $1,848 $9,334 Rule 79 (1)(a), (2)(a)


Asset Management Plan (AA4) 2014-2019 Project Description 2H 2014 2015 2016 2017 2018 2019 Total ($'000s) NGR Rule Regulating Facilities $179 $296 $291 $291 $295 $295 $1,646

EOL replacement - HPR $163 $162 $160 $159 $162 $162 $968 Rule 79 (1)(a), (2)(c)(ii)

EOL Replacement - MP Pits $17 $134 $131 $131 $133 $133 $679 Rule 79 (1)(a), (2)(c)(ii)

Telemetry & Monitoring $147 $245 $539 $543 $559 $292 $2,325

EOL Replacement - Telemetry $147 $245 $272 $277 $290 $292 $1,524 Rule 79 (1)(a), (2)(c)(i)(ii)

Facility Upgrade - 2G Network Modems $267 $266 $269 $801 Rule 79 (1)(a), (2)(c)(ii)

Network Safety and Performance $2,536 $8,982 $22,431 $34,277 $27,897 $37,479 $133,603 Gate Stations $3,924 $7,556 $3,377 $4,103 $18,961

PGP Interconnection - Old West Rd, Bullsbrook $3,354 $3,354 Rule 79 (1)(a), (2)(c)(ii)

PGP Interconnection - Harrow St, West Swan $1,391 $1,391 Rule 79 (1)(a), (2)(c)(ii)

PGP Interconnection - Caversham $4,380 $4,380 Rule 79 (1)(a), (2)(c)(ii)

PGP Interconnection - Welshpool Rd, Wattle Grove $2,685 $2,685 Rule 79 (1)(a), (2)(c)(ii)

PGP Interconnection - Russell Rd, Wattleup $2,712 $2,712 Rule 79 (1)(a), (2)(c)(ii)

PGP Interconnection - Readhead Rd, Nambeelup $3,377 $3,377 Rule 79 (1)(a), (2)(c)(ii)

Transmission Gate Station Capacity Upgrades $570 $492 $1,061 Rule 79 (1)(a), (2)(c)(ii)

High Pressure Polyethylene Pipelines $9 $1,173 $3,088 $6,760 $11,031

AS4645 Interdependency - Armadale $1,173 $1,173 Rule 79 (1)(a), (2)(c)(ii)(iii)

AS4645 Interdependency - Canning Vale $1,882 $1,882 Rule 79 (1)(a), (2)(c)(ii)(iii)

AS4645 Interdependency - Fremantle $779 $779 Rule 79 (1)(a), (2)(c)(ii)(iii)

AS4645 Interdependency - Kingsley $5,104 $5,104 Rule 79 (1)(a), (2)(c)(ii)(iii)

AS4645 Interdependency - Melville $778 $778 Rule 79 (1)(a), (2)(c)(ii)(iii)

AS4645 Interdependency - Murdoch $427 $427 Rule 79 (1)(a), (2)(c)(ii)(iii)

AS4645 Interdependency - Scarborough $879 $879 Rule 79 (1)(a), (2)(c)(ii)(iii)

Facility Upgrade - Security & Danger Signs $9 $9 Rule 79 (1)(a), (2)(c)(i)(iii)

High Pressure Steel Pipelines $578 $5,075 $15,904 $23,113 $18,900 $24,158 $87,728

AS2885 HP Signs - Compliance to New Requirements $532 $532 Rule 79 (1)(a), (2)(c)(i)(iii)

AS2885 Pigging Infrastructure - East Perth $1,615 $1,615 Rule 79 (1)(a), (2)(c)(ii)(iii)

AS2885 Pigging Infrastructure - Harrow St $1,247 $378 $1,625 Rule 79 (1)(a), (2)(c)(ii)(iii)

AS4645 Interdependency - Canning Vale $7,528 $7,528 Rule 79 (1)(a), (2)(c)(ii)(iii)

AS4645 Interdependency - Hillarys $6,619 $9,885 $16,505 Rule 79 (1)(a), (2)(c)(ii)(iii)

AS4645 Interdependency - Kingsley $5,104 $5,104 Rule 79 (1)(a), (2)(c)(ii)(iii)

AS4645 Interdependency - Lathlain $6,772 $6,772 Rule 79 (1)(a), (2)(c)(ii)(iii)

Elizabeth Quay & Perth CBD Risk Reduction Project - Sustaining 40% $2,111 $2,800 $4,910 Rule 79 (1)(a), (2)(c)(ii)

Facility Upgrade - CP Test Points $7 $7 Rule 79 (1)(a), (2)(c)(ii)

Facility Upgrade - Insulation Joints & Surge Protectors $18 $18 $18 $18 $18 $18 $109 Rule 79 (1)(a), (2)(c)(ii)

Facility Upgrade - Resistance Probes $19 $19 $19 $19 $19 $19 $114 Rule 79 (1)(a), (2)(c)(ii)


Asset Management Plan (AA4) 2014-2019 Project Description 2H 2014 2015 2016 2017 2018 2019 Total ($'000s) NGR Rule Facility Upgrade - Security & Danger Signs $9 $9 Rule 79 (1)(a), (2)(c)(i)(iii)

Facility Upgrade - Step Touch Mitigation $58 $57 $57 $58 $58 $288 Rule 79 (1)(a), (2)(c)(i)(iii)

Spurline - Peel - Sustaining $10,473 $10,456 $20,929 Rule 79 (1)(a), (2)(c)(ii)

Spurline - Two Rocks - Sustaining 40% $5,503 $12,627 $18,130 Rule 79 (1)(a), (2)(c)(ii)

AS2885 Inline Inspection - HP107 $509 $509 Rule 79 (1)(a), (2)(c)(ii)(iii)



AS2885 Inline Inspection - HP091 $1,730 $1,730 Rule 79 (1)(a), (2)(c)(ii)(iii)

Medium & Low Pressure Mains $403 $105 $105 $106 $106 $826

Isolation Valves - Northbridge Isolation $98 $98 Rule 79 (1)(a), (2)(c)(i)

R&D - Isolation of a Network for UAFG Investigation $306 $105 $105 $106 $106 $728 Rule 79 (1)(a), (2)(c)(ii)

Metering & Service Pipes $158 $912 $1,144 $1,157 $1,236 $1,233 $5,841

Meters Compliance Project $82 $912 $895 $891 $900 $899 $4,579 Rule 79 (1)(a), (2)(c)(i)(iii)

Replacement - Oversized Turbine Meters $77 $77 Rule 79 (1)(a), (2)(c)(ii)

Temperature Compensated Meters $250 $267 $335 $334 $1,185 Rule 79 (1)(a), (2)(c)(ii)

Regulating Facilities $1,290 $1,947 $719 $718 $729 $1,086 $6,490

AS4645 Interdependency - Subiaco $355 $355 Rule 79 (1)(a), (2)(c)(ii)(iii)

Capacity Upgrade - PRS03 Geraldton $130 $130 Rule 79 (1)(a), (2)(c)(ii)

EOL Replacement - HP Reg Pit Lids $21 $21 $21 $21 $21 $105 Rule 79 (1)(a), (2)(c)(i)

Facility Upgrade - Confined Space Signs $113 $113 Rule 79 (1)(a), (2)(c)(i)

Facility Upgrade - HPR Monitoring $471 $464 $463 $471 $472 $2,340 Rule 79 (1)(a), (2)(c)(i)(ii)

Facility Upgrade - HPR Vehicle Protection $238 $234 $234 $238 $238 $1,183 Rule 79 (1)(a), (2)(c)(i)(ii)

Facility Upgrade - OPSO Safety Devices $1,021 $1,104 $2,125 Rule 79 (1)(a), (2)(c)(i)(ii)(iii)

Replacement - HPR HS087 $138 $138 Rule 79 (1)(a), (2)(c)(ii)

Telemetry & Monitoring $502 $644 $635 $453 $461 $33 $2,727

Facility Upgrade - Alarm Capability at Critical Locations $372 $373 $368 $368 $374 $1,855 Rule 79 (1)(a), (2)(c)(ii)

Facility Upgrade - Metering & Telemetry Capel PRS $34 $34 Rule 79 (1)(a), (2)(c)(i)(ii)

Facility Upgrade - PRS Monitoring & Alarming $239 $235 $473 Rule 79 (1)(a), (2)(c)(i)(ii)

Project DV $95 $33 $32 $32 $33 $33 $257 Rule 79 (1)(a), (2)(c)(i)(ii)

R&D - Remote Pressure Control at Selected HPR Sites $53 $54 $107 Rule 79 (1)(a), (2)(c)(i)(ii)

Total ($'000s) $36,433 $81,210 $103,346 $106,794 $104,752 $107,292 $539,827
