Study on the Australian Domestic Gas Market · PDF fileStudy on the Australian Domestic Gas...

GAS MARKET STUDY 2013

Intelligent Energy Systems

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Study on the Australian Domestic Gas Market

Department of Industry, and Bureau of Resources and

Energy Economics 28 Nov 2013



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Disclaimer

This report has been prepared by IES Advisory (IES) for the Department of Industry and

Bureau of Resources and Energy Economics Gas Market Study Task Force.

This report is supplied in good faith and reflects the knowledge, expertise and

experience of the consultants involved. In conducting the analysis for this report IES has

endeavoured to use what it considers is the best information available at the date of

publication. IES makes no representations or warranties as to the accuracy of the

assumptions or estimates on which the forecasts and calculations are based.

The degree of reliance placed upon the projections in this report is a matter for that

reader’s own commercial judgement and IES accepts no responsibility whatsoever for

any loss occasioned by any person acting or refraining from action as a result of reliance

on the report.

Authors

This report was developed through cooperation between IES Advisory (Jamie Summons,

Philip Travill, and Patrick Wang) and Resource and Land Management Services

(Grahame Baker).



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Table of Contents

1 Executive Summary ................................................................................................ 13

2 Introduction ........................................................................................................... 18

2.1 Background ............................................................................................... 18

2.2 Terms of reference .................................................................................... 18

3 Overview of the east coast gas market ................................................................... 21

3.1 History of the gas markets ........................................................................ 21

3.2 Gas market trends and developments ...................................................... 22

3.3 Transmission pipelines .............................................................................. 23

3.4 Gas production by basin ............................................................................ 25

3.5 Gas production for LNG requirements ...................................................... 26

3.6 Domestic gas demand ............................................................................... 26

3.7 Gas demand for LNG projects ................................................................... 30

4 East coast gas reserves ........................................................................................... 31

4.1 Gas reserve and resource classifications ................................................... 31

4.2 Conventional gas ....................................................................................... 33

4.3 Unconventional gas – coal seam gas ......................................................... 34

4.4 Development of coal seam gas reserves ................................................... 37

4.5 Unconventional gas ................................................................................... 40

5 Cost of east coast gas production ........................................................................... 41

5.1 Factors in the cost of developing and supplying CSG ................................ 41

5.2 Cost components and scenario range ....................................................... 42

5.3 Development of CSG supply cost curve ..................................................... 43

5.4 Conventional gas ....................................................................................... 44

6 East coast gas market supply .................................................................................. 45

6.1 AGL Energy ................................................................................................ 46

6.2 APLNG ....................................................................................................... 46

6.3 Origin Energy ............................................................................................ 47

6.4 Arrow Energy ............................................................................................ 48

6.5 Beach Energy ............................................................................................ 49

6.6 Queensland Gas Corporation .................................................................... 49

6.7 Santos ....................................................................................................... 50



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6.8 BHP Billiton and Esso Australia .................................................................. 50

6.9 Nexus Energy ............................................................................................ 51

6.10 Smaller suppliers ....................................................................................... 51

6.11 Supply to Queensland from the southern states ....................................... 52

6.12 Longer term QLD gas suppliers .................................................................. 53

7 QLD LNG developments .......................................................................................... 54

7.1 Implementation progress of existing projects ........................................... 56

7.2 Reserves .................................................................................................... 60

7.3 LNG cost of supply and competitiveness ................................................... 61

7.4 Scenario range of LNG developments ....................................................... 62

8 Overview of gas contracting ................................................................................... 64

8.1 Domestic prices based on production costs .............................................. 65

8.2 Domestic prices based on international prices .......................................... 66

8.3 LNG netback pricing .................................................................................. 66

8.4 Recent gas pricing points .......................................................................... 68

9 Spot gas market ...................................................................................................... 70

9.1 Victorian Declared Wholesale Gas Market ................................................ 70

9.2 Short-Term Trading Market....................................................................... 71

9.3 Relevance to long-term contracting arrangements ................................... 72

10 Modelling the eastern Australia gas market ....................................................... 73

10.1 Overview of modelling approach .............................................................. 73

10.2 Price outcome modelling .......................................................................... 75

10.3 Specific model runs ................................................................................... 75

10.4 Modelling scenarios .................................................................................. 77

10.5 Key variables ............................................................................................. 78

10.6 Modelling assumptions overview .............................................................. 86

11 Gas Market Study modelling results ................................................................... 87

11.1 Summary of results ................................................................................... 88

11.2 Reference scenario ................................................................................... 88

11.3 Scenario gas prices by region .................................................................... 94

11.4 Gas demand across scenarios by region .................................................... 98

11.5 Gas supply across scenarios .................................................................... 102



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11.6 Potential shortfalls and constraints ......................................................... 107

12 Key findings and conclusion .............................................................................. 109

12.1 Prices across the east coast ..................................................................... 109

12.2 Basin supply outlook ............................................................................... 109

12.3 Domestic gas demand outlook ................................................................ 110

12.4 Potential supply constraints .................................................................... 110

13 Western Australia gas market .......................................................................... 111

13.1 Overview of the market .......................................................................... 112

13.2 LNG production ....................................................................................... 113

13.3 Gas reserves and resources ..................................................................... 114

13.4 Gas processing facilities .......................................................................... 115

13.5 Gas transmission pipelines ...................................................................... 116

13.6 Gas pricing .............................................................................................. 118

13.7 Projected gas demands ........................................................................... 118

13.8 Western Australia gas reservation policy ................................................ 119



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Appendix

Appendix A Gas reserve tables ............................................................................... 121

Appendix B Longer-term QLD suppliers ................................................................. 123

Appendix C Gas market modelling ......................................................................... 126

Appendix D Modelling assumptions ....................................................................... 129

Appendix E Major gas pipelines ............................................................................. 132

Appendix F Factors influencing CSG supply costs .................................................. 147

Appendix G International LNG pricing .................................................................... 149

Appendix H LNG development requirements ......................................................... 151

Appendix I Ramp gas management ....................................................................... 152

Appendix J Specific ownership interest ................................................................. 156

IES Advisory Capability ................................................................................................. 159



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List of Tables

Table 3-1 Major gas pipeline summary (National Market Gas Bulletin Board) .......... 24

Table 3-2 Eastern Australian gas basins by type (RLMS, Dec 2012) ........................... 25

Table 3-3 Committed LNG trains during study period ............................................... 30

Table 4-1 Eastern Australia CSG reserves by company - PJ (RLMS, Dec 2012) ........... 36

Table 4-2 Example of reserve conversion ................................................................. 38

Table 5-1 Estimated production costs for pipeline quality CSG - $/GJ (RLMS) ........... 42

Table 7-1 Announced and proposed LNG developments at Gladstone (RLMS) ......... 55

Table 7-2 LNG proponent reserves - PJ (RLMS, Dec 2012) ........................................ 60

Table 7-3 Eastern Australia LNG supply capability and number of trains .................. 63

Table 10-1 Summary of scenarios and key variables ................................................... 77

Table 10-2 Key variables for GMS modelling ............................................................... 78

Table 10-3 Base LNG train timing (8 trains by 2023) ................................................... 79

Table 10-4 Low LNG train timing (6 trains by 2023) .................................................... 79

Table 10-5 High LNG train timing (13 trains by 2023) ................................................. 79

Table 10-6 Efficiency of conversion factors................................................................. 80

Table 10-7 Conversion time assumptions ................................................................... 80

Table 10-8 Base demands - PJ (GSOO, Gladstone adjusted) ........................................ 83

Table 10-9 Low demands - PJ (GSOO, Gladstone adjusted) ......................................... 83

Table 10-10 High demands - PJ (calculated by IES) ................................................... 84

Table 10-11 Additional domestic supply sources (RLMS) .......................................... 84

Table 10-12 Future pipeline commissioning date assumptions ................................ 85

Table 11-1 Reference scenario prices - $/GJ (Production Cost & LNG Netback run) ... 90

Table 13-1 WA conventional gas reserves - PJ .......................................................... 114

Table 13-2 WA domestic gas processing facilities ..................................................... 116

Table 13-3 WA major gas transmission pipelines ...................................................... 117

Table 13-4 Conventional 2P reserves by basin (RLMS, Dec 2012) ............................. 121

Table 13-5 Conventional gas reserves by company (RLMS, Dec 2012) ...................... 121

Table 13-6 Reserves by basin and type - PJ ............................................................... 129

Table 13-7 Maximum production capacity – TJ/day .................................................. 129

Table 13-8 Production costs by basin and type - $/GJ ............................................... 130

Table 13-9 Pipeline capacities and tariff – TJ/day and $/GJ ...................................... 131



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List of Figures

Figure 3-1 Eastern Australia gas basins and gas pipeline network (RLMS).................. 22

Figure 3-2 Major transmission pipeline gas flows - PJ/year (GBB) .............................. 24

Figure 3-3 2013 production and capacity* - TJ/day (GBB and GSOO 2012) ................ 25

Figure 3-4 Mass market and large industrial demand (Planning case, GSOO) ............ 27

Figure 3-5 Gas share of total generation in the NEM – GWh (IES) .............................. 29

Figure 4-1 Gas basins by 2P reserves - PJ (RLMS, Dec 2012) ....................................... 32

Figure 4-2 Conventional 2P reserves by basin (RLMS, Dec 2012) ............................... 33

Figure 4-3 Conventional 2P reserves (PJ) by company (RLMS, Dec 2012) ................... 34

Figure 4-4 Eastern Australia CSG reserves by basin (RLMS, Dec 2012) ....................... 35

Figure 4-5 2P CSG reserves by company* (RLMS, Dec 2012) ...................................... 35

Figure 4-6 Gas reserves and resources by activity – PJ (RLMS, Dec 2012) .................. 37

Figure 4-7 Historical development of 2P CSG reserves – PJ (RLMS, Dec 2012) ........... 38

Figure 4-8 Reserves development rates and 2P requirements – PJ ............................ 39

Figure 5-1 CSG and unconventional gas supply cost – $/GJ (RLMS, Dec 2012) ........... 44

Figure 7-1 Proposed Curtis Island LNG developments ................................................ 55

Figure 7-2 LNG proponent gas reserves in the Bowen-Surat basins - PJ ..................... 60

Figure 7-3 Break-even landed costs in Japan - $US/MMBtu (McKinsey & Co) ............ 62

Figure 7-4 Eastern Australia LNG gas requirements – PJ ............................................ 63

Figure 8-1 LNG netback price as function of JCC - $/GJ .............................................. 68

Figure 9-1 Map of the declared transmission system (AEMO) ................................... 70

Figure 9-2 VIC spot 30-day rolling average prices (MIBB) ........................................... 71

Figure 9-3 STTM 30-day rolling average prices in SYD, ADE & BRI - $/GJ (GBB) .......... 71

Figure 10-1 Representation of the modelled gas system ......................................... 74

Figure 10-2 LNG netback prices (at Gladstone, $/GJ) ............................................... 81

Figure 10-3 JCC price forecasts - $US/bbl (Base price from Barcap, Sep 2013) ........ 82

Figure 11-1 Reference scenario – $/GJ (Production Cost run) .................................. 88

Figure 11-2 Reference scenario – $/GJ (LNG Netback run) ...................................... 90

Figure 11-3 Reference scenario supply - PJ (LNG Netback run) ................................ 91

Figure 11-4 Reference scenario total demand excluding LNG* - PJ .......................... 92

Figure 11-5 Reference scenario GPG demand - PJ (LNG Netback run) ..................... 93

Figure 11-6 Sydney gas prices - $/GJ (Production Cost and LNG Netback run) ......... 95

Figure 11-7 Melbourne gas prices - $/GJ (Production Cost and LNG Netback run) ... 96

Figure 11-8 Brisbane gas prices - $/GJ (Production Cost and LNG Netback run) ...... 96

Figure 11-9 Adelaide gas prices - $/GJ (Production Cost and LNG Netback run) ...... 98

Figure 11-10 NSW domestic gas demand - PJ/year (LNG Netback run) ...................... 99

Figure 11-11 VIC domestic gas demand (PJ/year – LNG Netback run) ........................ 99

Figure 11-12 QLD domestic gas demand (PJ/year – LNG Netback run) .................... 100

Figure 11-13 SA domestic gas demand (PJ/year – LNG Netback run) ....................... 101

Figure 11-14 LNG export gas demand (PJ/year – LNG Netback Run) ........................ 101

Figure 11-15 Reference scenario remaining 2P reserves* – PJ ................................. 102

Figure 11-16 Reference scenario aggregated gas supply* – PJ/year ........................ 103



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Figure 11-17 Change in gas production (Low Supply – Reference)* – PJ/year ......... 104

Figure 11-18 Change in gas production (High Infrastructure – Reference)* ............ 105

Figure 11-19 Change in gas production (LNG Low - Reference)* – PJ/year .............. 105

Figure 11-20 Change in gas production (LNG High - Reference)* – PJ/year ............. 106

Figure 11-21 Change in gas production (High Growth - Reference)* – PJ/year ........ 107

Figure 12-1 Average gas prices - $/GJ (Production Cost and LNG Netback)............ 109

Figure 13-1 DTS injections - PJ/day (AEMO) ........................................................... 132

Figure 13-2 Annual VIC gas demand (MIBB) ........................................................... 133

Figure 13-3 Monthly VIC gas-fired generation - GWh (IES) .................................... 134

Figure 13-4 Average daily quantity offered by participant – FY2013 (MIBB) .......... 135

Figure 13-5 Flows into Sydney split by pipeline – TJ/day (GBB) ............................. 135

Figure 13-6 Monthly NSW gas-fired generation - GWh (IES) .................................. 137

Figure 13-7 Flows into Adelaide split by pipeline – TJ/d (GBB)............................... 138

Figure 13-8 Monthly SA gas-fired generation (GWh, IES) ....................................... 138

Figure 13-9 Monthly QLD gas-fired generation - GWh (IES) ................................... 139

Figure 13-10 Flows on the RBP – TJ/d (GBB) ............................................................ 140

Figure 13-11 Flows on the QGP – TJ/day (GBB) ....................................................... 140

Figure 13-12 Flows on the SWQP – TJ/day (GBB) ..................................................... 142

Figure 13-13 Flows on the CGP – TJ/day (GBB) ........................................................ 142



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Glossary

AEMO Australian Energy Market Operator

AGL AGL Energy

APA APA Group

APLNG Australia Pacific LNG

AUD Australian dollar

bcf Billion cubic feet of gas

bbl Blue Barrel = 159 Litres

BG British Gas Group

BREE Bureau of Resources and Energy Economics

CBJV Cooper Basin Joint Venture

CSG Coal seam gas

CCGT Combined cycle gas turbine

DOI Department of Industry

DBNGP Dampier to Bunbury Natural Gas Pipeline

EGP Eastern Gas Pipeline

FID Final Investment Decision

FEED Front End Engineering and Design

FOB Free on Board

FY Financial year

GBB National Gas Market Bulletin Board

GGP Goldfields Gas Pipeline

GJ Gigajoule (109

Joules)

GLNG Santos GLNG

GMS Gas Market Study

GPG Gas Powered Generation

GSA Gas Sale Agreement

GSOO Gas Statement of Opportunities 2012

HDD Heating Degree Day

IES Intelligent Energy Systems



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IGEM Integrated Gas and Electricity Model

IMOWA WA Independent Market Operator

JCC Japan Customs-cleared Crude

JV Joint Venture

LNG Liquefied Natural Gas

MAPS Moomba to Adelaide Pipeline System

MDQ Maximum Daily Quantity

MIBB Market Information Bulletin Board

MMBtu Million British Thermal Units

MSP Moomba to Sydney Pipeline

Mt Million Tonnes

Mtpa Millions Tonnes per annum

NEM National Electricity Market

NSW New South Wales

NWSJV North West Shelf Joint Venture

ORG Origin Energy

PJ Petajoule (1015 Joules)

PRMS Petroleum Resource Management System

QCLNG Queensland Curtis LNG

QGP Queensland Gas Pipeline

QGC Queensland Gas Corporation

QIC Queensland Investment Corporation

QLD Queensland

QSN Queensland to South Australia/New South Wales pipeline

RBP Roma to Brisbane Pipeline

RLMS Resource and Land Management Services

SA South Australia

SEAGas South East Australia Gas Pipeline

SWQP South West Queensland Pipeline

TAS Tasmania

TGP Tasmanian Gas Pipeline



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TJ Terajoule (1012 Joules)

USD US dollar

VIC Victoria

WA Western Australia



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Notes to this report

Gas reserves

The definition of gas reserves and resources used in this report are those meeting the

criteria of the Petroleum Resource Management System (PRMS) of the Society of

Petroleum Engineers Inc. Reserves are reported in petajoules (PJ) while gas flows are in

terajoules (TJ).

Gas reserves are reported under the PRMS system as Proven (1P – 90% certainty of an

economic resource), Proven plus Probable (2P – 50% certainty of an economic resource)

and Proven plus Probable plus Possible (3P – 10% certainty of an economic resource). In

the case where natural gas is present in known accumulations but has not been

confirmed as commercially recoverable, the resource is classified as being Contingent.

A Prospective resource is that potentially recoverable from undiscovered accumulations

by the application of future projects or exploration activities.

Conventional gas

Conventional natural gas is that recovered from sandstone, carbonate or shale

reservoirs either as methane and ethane with associated heavier hydrocarbons or as a

co-product recovered from liquid petroleum production. The natural gas is normally

treated to recover ethane, LPG and condensates as well as for the removal of sulphur

compounds and inert gases, such as carbon dioxide and sometimes nitrogen.

Conventional natural gas does not include methane recovered from coal measures such

as coal seam gas or coal mine methane or other forms of unconventional gas such as

tight gas from conventional reservoirs.

Units and dollars

Unless otherwise specified:

Dollars in the report are in AUD and in December 2012 real dollars;

All years refer to the financial year starting July and ending in June;

Gas energy units are quoted in PJ, TJ and Gigajoules (GJ); and

Oil prices are quoted in US dollars (USD).



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1 Executive Summary

1.1 Purpose

IES, in partnership with RLMS, was commissioned for the joint study being undertaken

by the Commonwealth Department of Industry and the Bureau of Resources and Energy

Economics (BREE) to model gas reserves, gas supply and gas demand for the eastern

Australia gas market for the period 2013/14 to 2022/23. For the purpose of this work,

the eastern Australian gas market covers the interconnected gas networks of

Queensland, New South Wales, Victoria, South Australia and Tasmania.

The purpose of the modelling is to:

Determine if gas reserves and production are sufficient to meet demand;

Determine if gas transmission pipelines and processing facilities are sufficient

to meet demand and deliver new gas production; and

Model gas prices.

The requirement for this modelling was driven by the transition of the Eastern

Australian gas market, over the next few years, from a purely domestic focused market

to one which will be internationally linked for the first time via the development of a

liquefied natural gas (LNG) export industry in Queensland. This period is particularly

important as it coincides with major large-customer contract roll-offs and the resetting

of prices considerably higher than historical levels. The marked shift in demand and

supply dynamics has led to uncertainty regarding the tightening of domestic supply and

the price at which gas will be offered to the wider economy.

While individual company portfolios and drivers will have a bearing on the dynamics of

the demand and supply outlook, modelling provides a platform to explain what is likely

to happen with physical gas flows and, in turn, the pricing available to the domestic

market, and helps build a picture of overall market dynamics and relative price

outcomes.

1.2 Modelling approach

This work was undertaken using IES’s Integrated Gas and Electricity Model. This is a

least cost model that assumes a perfectly competitive market and optimises outcomes

over the study period. While the term “gas prices” is used to refer to model outputs

below, gas prices are actually the outcomes of what are primarily long term contract

negotiations. Prices would be expected to rise above least cost solutions at times of

limited supply options, towards the price of alternative supply, the maximum of what

the market might bear, or the opportunity cost, which is essentially the alternative LNG

netback price.



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Six supply and demand scenarios were modelled. The reference case, considered most

likely to occur, assumes: 8 LNG trains come on-line in Queensland; 60% of Coal Seam

Gas (CSG) 3P (possible) reserves are developed to 2P (probable) level; domestic gas

demand excluding gas power generation grows 1.4% pa from 479 PJ to 524 PJ pa; NSW

CSG fields and associated pipelines are developed and supply NSW; and transport

capacity is expanded on some pipelines and new pipelines are built to meet in demand

growth.

The five other scenarios consider: low LNG production in Queensland; high LNG

production in Queensland; low gas production due to supply constraints; strong

domestic gas demand growth and associated supply growth; and gas infrastructure

expansions to meet expected demand growth.

Each scenario has a base, low or high setting for the variables of domestic supply,

domestic demand, infrastructure, LNG export timing, CSG reserves and international

LNG demand.

Key inputs include gas basin reserves, maximum production rates, cost of gas

production, pipeline tariffs, pipeline capacity limits, domestic and LNG demand, new

pipeline developments, the rate that fields are developed to produce gas, and LNG

netback prices.

For the six scenarios, the model has three runs based on: the costs of production

representing the lower bound of gas prices; LNG netback prices at Wallumbilla and

Moomba representing an upper bound of gas prices and a more probable market; and

maximum daily demand.

Data was provided primarily by RLMS and IES, and supported by interviews with a

number stakeholders conducted by the Department of Industry and IES.

1.3 Key findings

1.3.1 Gas pricing

Traditional cheap gas has been depleted and the price of gas is moving up the supply

cost curve. Cost increases have been primarily driven by the depletion of more

accessible and productive CSG fields and the reduction of hydrocarbon liquids recovered

from conventional gas production.

Cost of gas supply has increased from $3-4/GJ a few years back and now sits between

$4.4-5.6/GJ for CSG in the Bowen-Surat basins and $4.5/GJ from the Gippsland and

Otway basins and $6/GJ from the Cooper-Eromanga basins.

The model’s cost of production run Reference scenario shows a gradual increase of the

least-cost price ranging from roughly $5.4/GJ in Melbourne and Sydney to $6.2/GJ in

Adelaide by 2022/23 (all prices real 2012). Only the gas price at the Sydney hub eases,



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approximately 3% between 2019 and 2021, and this is attributed to new gas production

commencing from the Gunnedah and Gloucester basins in NSW.

The LNG netback run shows a large variation in price paths with Adelaide and Brisbane

prices rising to around $11/GJ in 2023 for the Reference scenario. Adelaide experiences

a sharp increase in prices from 2015 to 2016 of around $3/GJ as a direct result of the

reverse of the flow of South West Queensland Pipeline i.e. gas flows from Moomba to

the east to supply gas for LNG export. This results in the price of gas from the Cooper-

Eromanga basins moving to LNG netback prices.

The effect of netback pricing at the Cooper-Eromanga basins is also experienced at the

Sydney hub with a price increase of around $1.3/GJ from 2015 to 2016. However, the

gas price at the Sydney hub is projected to peak at $7.5 in 2018 and then ease between

2019 and 2020 due to new gas production commencing from the Gunnedah and

Gloucester basins.

Melbourne is the exception with prices not linked to LNG netback prices, and showing a

flat, gradual rise to $6/GJ by 2023. This is attributed to a steady gas supply from the

Gippsland, Otway and Bass basins and the physical constraints of transporting gas from

these basins to Gladstone for LNG export.

A caveat to these findings is the model does not account for tight market situations,

such as where there is limited supply, in which case gas contract prices could be

expected to rise above this upper bound.

1.3.2 Reserves

Central and eastern Australia has significant gas reserves. At the end of 2012 these

totalled 51,401 PJ of 2P reserves consisting of 44,442 PJ of CSG reserves and 6,959 PJ of

conventional reserves. Approximately 38,000 PJ (86%) of CSG 2P reserves and 1,000 PJ

(14%) of 2P conventional reserves are committed to the four major LNG projects, most

of which will be used for LNG production.

Modelling shows there are sufficient 2P CSG reserves and 3P conventional gas reserves

to meet demand over the 2013/14 to 2022/23 study period. The 2P conventional gas

reserves from the Otway and Bass basins are depleted by 2021-2022 and gas production

from these basins will draw from 2C resources from 2021. New gas supply coming on

line from 2021 in from the CSG reserves in the Gloucester and Gunnedah basins,

supplying 43 PJ or a third of NSW demand, would increase the life-span of 2P

conventional gas reserves in Victoria but new pipeline and processing infrastructure

would be required to bring this gas to market.

1.3.3 Supply and demand

The LNG supply situation has 6 committed trains with potential for additional trains

provided the correct investment signals are present. This represents 1,500 PJ/year of

additional demand from the start of 2016 supplied out of the Bowen/Surat basin . This



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effectively triples total east coast gas demand, which increases to 2,000 PJ/year by the

end of 2023 based on an 8 train outlook (reference scenario).

The Arrow LNG Project will reach FID in early 2014 however remains uncertain given

considerable cost increases at existing sanctioned projects and an uncertain LNG

outlook, presenting real risks to further investment and making possible cooperation

amongst the LNG proponents more likely.

Modelling shows there is sufficient supply to meet expected domestic demand and the

demand of eight LNG trains over the study period. This is based on the assumed timely

development of conventional gas resources and the efficient conversion of 2C CSG

resources to production (a 5 year conversion time is used).

Gas supply is generally flat across the study period with the exception of the

Bowen/Surat basins, which will supply the majority of gas for LNG production and are

expected to see production increase from 217 PJ in 2014 to 2,250 PJ in 2023.

Demand from gas powered generation (GPG) in the NEM is expected to decrease 44%

from 191 PJ in 2014 to 108 PJ by 2023 due to higher gas prices as a result of LNG

netback pricing. It is expected the decreases by 2023 will mainly come from QLD (40

PJ/year) as gas volumes are redirected to LNG terminals, and SA (22 PJ/year) due to its

large GPG demand.

The overall domestic gas demand profile stays relatively flat as mass market and

industrial gas demand growth are offset by the reduction in GPG demand.

1.3.4 Pipeline and processing infrastructure capacity

Modelling shows current and planned upgrades to transmission pipeline and gas

processing capacity are sufficient to meet annual demand over the study period, though

the market’s ability to meet demand may be reduced if some of these upgrades do not

proceed.

Pipeline expansions assumed to proceed in the study period are: the Queensland Gas

Pipeline (Wallumbilla to Gladstone); the South West Queensland Pipeline changing to a

west to east flow (Moomba to Wallumbilla); and the South West Pipeline (Port Campbell

to Melbourne). Pipelines assumed to be built in the study period are: the Queensland

to Hunter Pipeline (Wallumbilla to Gunnedah to Newcastle); the Stratford to Hexham

Pipeline; and the Lions Way Pipeline (Casino (Clarence Moreton Basin) to Ipswich).

Maximum daily demand modelling highlights potential peak-day constraints occurring in

Queensland within the next ten years on the Carpentaria (Ballera to Mt Isa) Gas Pipeline

and North Queensland (Moranbah to Townsville) Gas Pipeline, if the capacity on these

pipelines is not increased, noting modelling does not factor in gas management options

such as storage and line-pack optimisation.



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1.3.5 Conclusions

Overall, our modelling of the eastern Australian gas market shows there are enough

conventional and coal seam gas resources, and there is likely to be enough gas

production, to meet domestic gas demand and the gas demand of eight LNG trains from

2013/14 to 2022/23. Key to this finding is the assumption that gas reserves continue to

be developed and brought into production in a timely manner and investment continues

in gas pipeline capacity and processing facilities. The price of this gas will be above

historical prices due to the costs of production moving up the supply cost curve and the

influence of LNG netback pricing in the domestic market.



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2 Introduction

This chapter introduces the study and presents the objective and deliverables of the Gas

Market Study and its component sections. The structure of the report is reviewed and

definitions, units and conversion rates listed for reference.

In particular, scenario modelling is used to provide a picture of the demand and supply

situation and pricing outcomes in the Eastern Australian gas market over the FY period

2014-2023.

The purpose of this modelling is to answer whether production, current reserves and

future development, and gas transmission are sufficient to meet on-going demand. The

modelling also provides an indication of wholesale gas prices and potential physical

bottlenecks over the study period.

2.1 Background

The Gas Market Study (GMS) is a joint project between the Department of Industry

(formerly the Department of Resources, Energy and Tourism) and the Bureau of

Resources and Energy Economics (GMS Task Force) to produce a comprehensive report

on the state of Australia’s gas markets with the objective of informing Government and

the wider public.

The aim of the GMS is to identify market trends to provide a clear picture of the

demand and supply situation across Eastern Australia, identifying and quantifying any

constraints potentially impacting on gas supply availability, gas market development,

security of supply and likely wholesale gas price outcomes across the broader Eastern

Australia gas market. The study also covers the detached Western Australian market for

a further contextual overview.

The GMS Task Force has commissioned IES Advisory (IES) in conjunction with Resource

and Land Management Services (RLMS) to undertake the comprehensive review and gas

market modelling and analysis. The terms of reference of the study are described in

below in Section 2.2. Additional background information is included in the appendices.

2.2 Terms of reference

The requirements of the GMS as outlined by the GMS Task Force are set out as follows.

2.2.1 Modelling

IES was engaged to model gas market trends for the financial years 2013/14 to 2022/23.

Scenarios should provide a clear picture of the demand-supply situation and pricing

outcomes in the eastern Australian gas market over the 10 year period with a particular

emphasis on the period of 2015-2020.



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The purpose of the modelling is to:

Determine if gas reserves and production are sufficient to meet demand;

Determine if gas transmission pipelines, storage and processing facilities are

sufficient to meet demand and deliver new production; and

Model wholesale (delivered) market gas price forecasts over the modelling

period.

Western Australia has not been expressly modelled and only a qualitative assessment of

similar issues is provided in Section 13.

2.2.2 Scenarios

The forecasts are based on 6 scenarios provided by the GMS Task Force. The scenarios

cover possible impacts of gas supply and gas prices on the eastern Australian domestic

gas market and to determine whether:

Prices at each major demand hub are expected to increase materially;

Production is sufficient to meet demand in the study period;

Transmission is sufficient to meet demand and bring on new production; and

Reserves are sufficient to meet demand in the longer term.

2.2.3 Analysis and discussion

Analysis is to be supported by discussion of the following:

Gas reserves, including relevant matters such as resource to reserves

conversion rates; the location of reserves and potential reserves relative to

demand, the need for new or expanded infrastructure to enable market

development;

Well-head (ex-field) gas production costs;

Barriers to growth of the eastern Australia gas market as a whole and/or, any

market segment, including discussion of potential bottlenecks and system

constraints;

Customer demand and drivers for demand growth, covering all market

segments; and

The timing and size of any future supply, demand and reserves imbalances.

2.2.4 Stakeholder engagement

Stakeholder engagement was undertaken in close consultation with the GMS Task Force

and included all major segments of the gas market. The information derived from these



20

consultations was used to confirm model inputs and assumptions and provide context

to the modelling results.



21

3 Overview of the east coast gas market

This chapter briefly reviews the physical and market structure and operation of the

eastern Australia gas supply system, major gas pipelines and basins. It establishes the

context in which this study is undertaken and highlights the gas market trends and

developments key to the study.

Projections of gas demands are presented in terms of state gas demands developed by

AEMO (excluding gas powered generation), and current committed LNG gas demands in

Queensland.

3.1 History of the gas markets

Over the past fifteen years, a number of developments have resulted in a physically

integrated Eastern Australian gas market with pipelines connecting the major demand

hubs allowing inter-basin transfers of gas. These developments have included:

Reform to the gas supply industry in Victoria which involved the privatisation of

the State’s gas distribution and retail businesses, the establishment of a gas

spot market, and pursuit of supply diversity through interconnection with the

Moomba to Sydney Pipeline (MSP) at Culcairn, and the construction of the Iona

Gas Plant and storage facilities near Port Campbell;

The construction of the Eastern Gas Pipeline (EGP) allowing Gippsland Basin gas

to compete with Cooper-Eromanga basin gas to supply customers in NSW from

2000;

The construction of the Tasmanian Gas Pipeline (TGP) to provide natural gas to

Tasmania in 2002;

The development of the Otway and Bass basins and construction of the SEA Gas

Pipeline (SEA Gas) connecting the Iona Gas Plant in VIC to Adelaide in 2004; and

The development of Queensland coal-seam methane reserves, originally

stimulated in part by the commencement of the Queensland Gas Scheme from

2005 (a subsidy to favour gas-fired power generation), which has been

superseded by the carbon tax.

Figure 3-1 presents a map of the interconnected Eastern Australian pipeline system and

all gas supply basins.



22

Figure 3-1 Eastern Australia gas basins and gas pipeline network (RLMS)

3.2 Gas market trends and developments

An abundance of coal seam gas reserves and the prospect of higher margins selling LNG

into the Asian market have led to the establishment of an LNG export industry

comprising of 3 committed projects on Curtis Island near Gladstone. The 3 committed

projects – Asia Pacific LNG (APLNG), Queensland Curtis LNG (QCLNG) and Gladstone LNG

(GLNG) - will ramp towards 25 Mtpa (1,370 PJ/year) of LNG production by 2016 and

potentially 33 Mtpa (1,810 PJ/year) by 2018 should the Arrow LNG project be

sanctioned, effectively tripling current east coast gas demand. The ramp period of the



23

LNG projects also coincide with significant large-user contract roll-offs suggesting

possible tightness of supply that has placed additional upward pressure on domestic gas

prices.

On a forward basis there are also other significant developments impacting the

domestic gas supply and demand balance. These are summarised below:

The investment and speed at which producers can develop existing reserves

and further exploration to bring additional supply to the market over the longer

term;

The potential for large-scale gas demand destruction due to price levels and

potentially onerous contractual terms and conditions forced upon large

consumers. The roll-off of large-user contracts coinciding with the ramp up in

LNG demand is of significant concern;

Possible development of new sources of gas, including the Gunnedah, Clarence-

Moreton and Gloucester basins, and supporting supply infrastructure over the

study period to compete with existing sources supplying the Queensland and

New South Wales markets.

The likely removal of the carbon tax, which will reduce the competitiveness of

gas-fired power generation (GPG) relative to coal noting the considerable

amount of coal-fired mothballing which has already occurred as a direct result

of the carbon tax impost and declining electricity demand; and

There is a shortage of renewable energy projects relative to the scale-up of the

Renewable Energy Target trajectory, which has the potential to drive

considerable investment in large-scale renewable capacity and displace GPG.

3.3 Transmission pipelines

Table 3-1 lists the major gas transmission pipelines, their regulatory status (full

regulation, light regulation, no regulation), average capacity factor and capacity

(forward/reverse). It should be noted that not all pipelines serve demand centres, for

example the QSN and South West Queensland Pipeline provide transmission capacity

between other pipelines.

Future pipeline development information can be found in Section 10.5.6 and

descriptions of existing pipelines can be found in the Appendix D .



24

Table 3-1 Major gas pipeline summary (National Market Gas Bulletin Board)

Pipeline name

Owner Regulation Capacity factor (2011-2013)

Capacity

(TJ/day)

Queensland Gas Pipeline Jemena None 83% 142

Carpentaria Pipeline APA Light 84% 119

Roma - Brisbane Pipeline APA Full 73% 240

South West Queensland Pipeline APA None 32% 385

Moomba to Sydney Pipeline System APA Light 39% 439

Moomba to Adelaide Pipeline System QIC None 51% 253

SEA Gas Pipeline APA (50%) None 61% 314

Eastern Gas Pipeline Jemena None 73% 268

NSW - Victoria Interconnector APA Full 37% 90/73

Longford to Melbourne APA Full 48% 1030

Tasmania Gas Pipeline TGP None 35% 129

Volumes of gas generally flow in one particular direction on each gas pipeline because

of the location of gas supply relative to demand hubs. Figure 3-2 shows limited

variability in annual flow volumes. Variance can be attributed to weather and economic

factors and would be unlikely to change significantly without structural changes to the

market.

Flows on EGP in 2013 were up almost 10 PJ with a 4 PJ drop from the MSP most likely

the result of a decrease in reliance from Moomba for swing gas and preference for

flatter production out of the Cooper-Eromanga basins. QGP volume into Gladstone is

up 6 PJ since 2010 coinciding with the commissioning of the Yarwun refinery co-

generation plant. The NSW-VIC Interconnect has increased over the previous year as a

result of Origin Energy’s portfolio strategy and is likely to continue as a result of Origin

Energy’s new gas deal with BHP/Esso.

Figure 3-2 Major transmission pipeline gas flows - PJ/year (GBB)



25

3.4 Gas production by basin

Figure 3-1 lists the main geological basins in Eastern Australia having gas reserves and

resources. Most of these are currently supplying the Eastern Australia gas market. The

few that are not currently supplying to the gas market have the potential to do so within

the study period. While most basins are restricted to either conventional natural gas,

coal seam gas (CSG) or unconventional gas, there are basins that have multiple gas

types.

Table 3-2 Eastern Australian gas basins by type (RLMS, Dec 2012)

Basin Producing? Conventional Coal Seam Gas

Adavale n y n

Bass y y n

Bowen Y y y

Clarence-Moreton n n y

Cooper-Eromanga y y n

Galilee n n n

Gippsland y y n

Gloucester n n y

Gunnedah n y y

Otway y y n

Surat y y y

Sydney y n y

Figure 3-3 presents the average gas production by basin for the financial year ending

December 2012. The coloured bars indicate the average daily production in TJ/day

while the grey bars represent the total capacity of production facilities.

Figure 3-3 2013 production and capacity* - TJ/day (GBB and GSOO 2012)



26

* Maximum production capacity out of the Otway Basin includes the Iona Gas Plant of 500TJ per day which is not always available at this level throughout the year.

The average capacity utilisation across all basins is around 50%. Queensland and Victoria

have the greatest potential to increase production from existing facilities with capacity

for an additional 515 TJ/day and 1,015 TJ/day respectively.

3.5 Gas production for LNG requirements

New upstream gas processing and pipeline facilities intended to service six LNG

processing trains are presently under construction. This infrastructure will have a

collective capacity of 4,160 TJ per day (1,518 PJ/year). While this infrastructure will

effectively operate independently from the existing gas market, it will be

interconnected to the domestic gas market supply system, raising the question of the

ability of the LNG proponents to extract gas from the domestic gas market. While

specific details on the LNG infrastructure capability is not available, it is understood that

existing gas treatment plants supplying the domestic market will be able to divert their

output towards the LNG export terminals.

3.6 Domestic gas demand

Gas demand is composed of the mass market (commercial, small industrial and

households), large industrial users and GPG. Demand not included in this definition

relates to gas volumes required for the LNG export industry.

3.6.1 Mass market demand

AEMO provides projections of mass market and large industrial gas demand by state

under a range of economic scenarios in its annual Gas Statement of Opportunities

(GSOO) publication. These AEMO outlooks form the basis of the economic outlook

scenarios developed in the GMS. Note Gladstone demand was slightly adjusted to

reflect current demands and RLMS expectations (see Section 10.5.4).

The mass market and large industrial demand by state for the Base growth scenario

used in this report is shown in Figure 3-4. Total gas demand for this segment across the

entire east coast was 474 PJ in 2011 and 486 PJ in 2012 (source: GSOO).



27

Figure 3-4 Mass market and large industrial demand (Planning case, GSOO)

The average annual growth rate in mass market and large industrial gas use across the

Eastern Australia gas market is approximately 1.5% pa over the study period with the

High and Low demand growth trajectories 0.3% p.a. higher and lower respectively. The

growth in mass market and larger industrial demand is projected by AEMO to increase

slightly over the 10 years by 50-80 PJ across the east coast. Figure 3-4 shows relatively

flat profiles for all segments with the exception of load at Gladstone. The Gladstone

load assumes an additional 17 PJ of load as a result of expansions at QAL and Yarwun in

2017 and 2019. Note this is an IES and RLMS assumption of current and expected

demand levels in the area and is different from the GSOO.

3.6.2 Queensland large industrial demand

Queensland large industrial demand is an important factor in the eastern Australia gas

story as it is competing directly with the LNG projects for gas, however QLD large

industrial demand has lower priority than demand from LNG projects due to the

historically cheap price levels it pays relative to international LNG export prices, and the

common ownership of the LNG projects and gas supply.

The large industrial customers in Queensland comprise over 65% of Queensland’s gas

demand, excluding GPG and future LNG exports. The significant gas consumers include

the alumina refineries in Gladstone, four ammonia/ammonium nitrate and fertiliser

plants, and mineral processing facilities in Gladstone, Mount Isa, Rockhampton and

Townsville.

Our key findings from discussions with gas producers and large industrial customers in

Queensland are as follows:

Under the current gas market conditions, some producers have indicated they

are willing to consider negotiating gas contracts with gas users subject to the

less favourable terms and conditions compared to previous contracts. The



28

amount of gas that could be provided by the smaller gas producers is relatively

small;

The viability of additional trains to the six trains already committed in

Gladstone is uncertain, and depends on a number of factors including

international LNG demand. This uncertainty has directly impacted large gas

consumers and has been primarily being driven by GLNG and Arrow. In the

case of GLNG it is well documented this project is short of gas relative to the

project’s economic life. There is uncertainty how the gap will be filled or

whether Santos, the project’s large stakeholder, will continue to sell portfolio

gas to GLNG, diverting gas away from the domestic market. Additionally it is

well documented, and Arrow have constantly highlighted, the costs and thin

margins associated with their own project. It would seem logical, given Arrow’s

tenement proximity to the other three LNG proponent permit areas and the

size of Arrow’s reserves, some meaningful relationship may transpire leaving

the total export capacity on the east coast at 6 trains and provide more than

enough gas to meet domestic demand;

If the current gas market dynamics continue where producers, retailers and

large customers face high volume, price and contractual terms risks, it is likely

to inhibit all parties from entering long-term contracts. This may result in a

move to more frequent short-term contracts in order to transition through the

LNG ramp-period. As has been mentioned previously, the gas market lacks

both liquidity and transparency at the best of times let alone when it is moving

towards such a dramatic increase in demand.

3.6.3 Gas-powered generation

Historically the uptake of gas for power generation has been slow as a result of the

availability of low-cost coal in QLD, NSW and VIC. However, GPG has had a relatively

higher share in SA due to a lack of supply of coal, an abundant supply of gas and a

higher electricity retail customer margin.

On average 12.5% of electricity in the National Electricity Market (NEM) was generated

by gas in the years 2009 to 2013. Figure 3-5 shows the share of gas-fired generation in

the NEM has been relatively flat. The last 4 quarters (through 2013) from which the

carbon tax of $23/t applied has not materially shifted the role of GPG in the NEM (an

increase of approximately 1 GWh) most likely because of the downward trend in

electricity demand and growth in solar rooftop PV. Gas consumption for electricity

generation over the last 12 months to June 2013 increased from 194 PJ to 203 PJ.



29

Figure 3-5 Gas share of total generation in the NEM – GWh (IES)

The outlook for GPG in the NEM has moderated due to an envisaged low price on

carbon emissions and a reduction in projected electricity demand growth. Another

factor impacting the future development of GPG is the issue of securing gas. Bilateral

purchasing of gas is unlikely to provide enough price certainty in the current

environment given implicit international price linkages associated with future price

reviews and consequently will add risk to investment in GPG. Parties that cannot

mitigate this risk, for example by taking an upstream stake, may therefore be unwilling

to invest in GPG. GPG is already at the margin in the NEM and any uncertainty and cost

pressures (generally at contract roll-off) will lead to reduced gas powered electricity

generation.

Notwithstanding this, there are synergies associated with GPG that may result in such

generation being developed in the future for participants that have upstream gas

interests. These synergies result from the integration of generation with other stages of

the energy supply chain, from gas production through to selling electricity. Business

synergies and risk mitigation are greatest for a party with the following characteristics:

Has own low cost gas located near electricity transmission/demand;

Has a captive electricity market; and

Has a captive gas market.

Origin Energy is in the strongest position with respect to the above characteristics while

AGL and Energy Australia have similar characteristics but to a lesser extent. Origin

Energy’s Darling Downs and Mortlake power stations were unlikely to have attracted

the required investment without these additional benefits.

Natural gas supplied for GPG from on field or nearby gas fields does not require the

extent of processing (dehydration) and compression needed for gas transmission

pipelines. This saves costs, typically $0.50/GJ. Specific cases are Daandine (30 MW),

German Creek (32 MW), Moranbah (12 MW) and Moranbah North (45 MW). Origin



30

Energy uses its Darling Downs system (DDPS, Roma PS) as a seasonal float using gas in

its GPGs during a Queensland summer to meet its retail loads while sending/swapping

gas in winter to meet southern states’ heating loads. This also applies to non-NEM GPG

such as at Mount Isa and Cannington.

Another synergy is conferred by an electricity demand and demand for low/medium

pressure steam located in close proximity to each other. This may render cogeneration

viable as is apparently the case at the Rio Yarwun alumina plant (165 MW) and the

Qenos Altona petrochemical plant (20 MW).

3.7 Gas demand for LNG projects

The LNG developments assumed committed in this study are described in Table 3-3.

Table 3-3 Committed LNG trains during study period

Project No. committed LNG trains

Estimated project gas use per year (PJ/year)

Scheduled start date (FY)

Australia Pacific LNG (APLNG) 2 540 2016

Gladstone LNG (GLNG) 2 468 2015

Queensland Curtis LNG (QCLNG) 2 510 2015

By the end of 2016 the six LNG trains currently under construction on Curtis Island near

Gladstone, are expected to be in operation with a total gas consumption of 1,518 PJ per

year. This compares to the total Queensland gas consumption, including GPG, of

around 252 PJ per year, and a total eastern Australia gas consumption including GPG of

about 740 PJ during 2012. The LNG export industry will effectively triple eastern

Australia gas demand. As a result, LNG is the dominant issue in the Queensland and

eastern Australian gas market in terms of gas pricing because of the linkage to

international gas prices and availability.

Based on current reserves there is sufficient gas in the Bowen-Surat basins to

collectively support a 6 train LNG export complex for 20 years. More detailed

information on the LNG projects can be found in Section 7.



31

4 East coast gas reserves

This chapter presents the current level of gas reserves for conventional and coal seam

gas across eastern Australia on a company, activity and basin basis.

It highlights the supply concentration and discusses the development of CSG reserves,

historically and going forward, relative to the requirements of the LNG projects.

Information on unconventional gas is also provided.

The 2P gas reserves in Eastern Australia at 31 December 2012 totalled 51,293 PJ

comprising 44,442 PJ of CSG (86.6%) and 6,851 PJ of conventional gas (13.4%). The

ownership of the natural gas reserves is highly concentrated with the LNG project

groups and their associated participating partners controlling 74.6% of the 2P gas

reserves. Esso Australia, BHP Billiton and AGL control a further 11.4% with the

remaining 14.0% (3,300 PJ) being controlled by a number of major domestic companies,

international groups and smaller producers and explorers. The smaller independent

production and exploration companies hold 3.3% of the total 2P gas reserves.

The gas market is highly illiquid with many of the international groups having market

agreements with existing major producers or power generators. Many of the

independent small gas reserve holders have joint venture or farm-in agreements with

the market dominant gas reserve holders.

Figure 4-1 shows the total 2P reserves by basin, type and location in the gas system.

Most of this gas is concentrated in the Gippsland and Bowen and Surat basins in Victoria

and Queensland respectively.

4.1 Gas reserve and resource classifications

1P, 2P and 3P represent respectively the amount of gas that will be recovered with a

probability of at least 90%, 50% and 10%. Most companies as well as Government

agencies only report conventional gas reserves as 2P (proved plus probable) reserves.

There is generally limited public information available on 1P and 3P reserves and

contingent resources. Where they are published, they have been included in this

document.

RLMS has provided IES with an update on the conventional natural gas reserves and

resources for eastern Australia as at 31 December 2012. The information on the gas

reserves and resources has been sourced from ASX releases by companies, company

presentations, publications, brochures and information provided by Government

agencies.



32

Figure 4-1 Gas basins by 2P reserves - PJ (RLMS, Dec 2012)



33

4.2 Conventional gas

Current estimates of the 2P reserves of natural gas within conventional gas reservoirs by

state and by basin are presented in Figure 4-1. Both onshore and offshore gas reserves

and resources are covered and gas reserves in the south west Queensland section of the

Cooper-Eromanga basins have been included.

Figure 4-2 Conventional 2P reserves by basin (RLMS, Dec 2012)

Victoria has the largest conventional gas reserves of all the eastern Australian states

concentrated in the Gippsland Basin followed by South Australia in the Copper-

Eromanga basins. Queensland has only a very small quantity of conventional gas

reserves. Conventional 2P reserves total 6,851 PJ with 80% of this concentrated in the

Gippsland and Cooper-Eromanga basins.

Figure 4-3 present the current estimates of the 2P reserves of natural gas within

conventional gas reservoirs by company (covering both onshore and offshore gas

reserves and resources). The main players are BHP Billiton and Esso Australia (Esso

BHP), the JV partners in the Gippsland Basin in Victoria, and Santos in the Cooper-

Eromanga basins. Together they hold more than 75% of total conventional 2P gas across

eastern Australia.



34

Figure 4-3 Conventional 2P reserves (PJ) by company (RLMS, Dec 2012)

4.3 Unconventional gas – coal seam gas

There is a significant unconventional gas resource in Eastern Australia. Unconventional

gas includes CSG, coal mine methane, tight and shale gas, CSG from deep, low

permeability coals and biogas. At present, only CSG is commercially produced on a

significant scale though some biogas from landfill operations and waste treatment

plants are also used as a localised energy source. Likewise only CSG has independently

audited reserves. Some preliminary unconventional gas reserves have been booked by

Santos in the Cooper Basin.

4.3.1 Estimated CSG reserves and resources

Many companies only report 2P gas reserve figures and do not report specific 1P or 3P

reserves and contingent or prospective gas resources. Accordingly, the reported 1P and

3P reserves and contingent resources in this report in general underestimate the actual

level of natural gas reserves and resources known to exist. In addition, many companies

do not provide any details of gas by field or by basin other than aggregated 2P reserves.

In many cases even the 2P reserves are only reported by broad geographical areas.

However utilisation of information available from Government agencies responsible for

administering the relevant petroleum activities enables the 2P reserves to be derived on

a basin by basin basis.

Figure 4-4 presents the 2P CSG reserves on a basin basis. It can be noted that over 93%

of the 2P reserves of CSG are located within the Bowen and Surat basins in Queensland.

Likewise 89% of the 3P reserves of CSG are within these same two basins. The Bowen

and Surat basins are the two sedimentary basins with the longest period of CSG

Esso Australia



35

development and have extensive gas pipeline gathering and transmission systems.

Much of this gas infrastructure was in place before the development of the CSG

industry.

Figure 4-4 Eastern Australia CSG 2P reserves (PJ) by basin (RLMS, Dec 2012)

Figure 4-5 shows potential 2P reserves by company, ordered from highest to lowest

level of reserves, and illustrates the tiered nature of CSG reserve ownership. Noting

that these are not grouped by LNG proponents, QGC has by far the largest holding of

reserves which is more than twice the next tier consisting of Arrow Energy, Origin

Energy, Conoco Philips and Santos. All of these companies, as highlighted in the darker

red bars, have an LNG export focus and comprise of 86% of the total 2P CSG reserves.

Figure 4-5 2P CSG reserves by company* (RLMS, Dec 2012)

* Red bars indicate companies with an LNG export focus



36

Many of the companies with smaller holdings also have aspirations of an LNG focus

(such as Metgasco), or are not in a position to supply gas for some time due to location

(such as Blue Energy). It is also important to consider the fragmented nature of the

uncommitted gas holdings. This fragmentation of the remaining uncommitted

tenements complicates the transport and sale of gas from these sites to the Queensland

and the New South Wales domestic markets.

Table 4-1 shows the entire CSG reserves across all categories by company. The

ownership of CSG gas reserves and resources is highly concentrated with the LNG

proponent groups holding 86% of the 2P reserves and 80% of the 3P reserves.

Table 4-1 Eastern Australia CSG reserves by company - PJ (RLMS, Dec 2012)

Company 1P 2P 3P 2C 3C

AGL Energy 2,170 3,961 130 545

Arrow Energy 669 9,494 13,970 2,521 2,521

Blue Energy 50 180 820 3,481

Clarence Moreton Resources 12 266 440

Comet Ridge 260 2,731

ConocoPhillips 4,895 5,990 1,434 3,686

Dart Energy 542 1,484

Energy Australia 285 285 692 692

ERM Power 2 38 63

Galilee Energy 129 545

Harcourt Petroleum 24 343 824 594 594

KOGAS 270 807 1,024 246 246

Metgasco 3 428 2,542 2,511 2,511

Mitsui Group 57 505 1,265 301 301

Origin Energy 5,073 6,871 1,434 3,686

PETRONAS 494 1,478 1,876 450 450

QGC 3,096 10,326 18,876 13,700 13,700

Red Sky 3 76 126

Santos 539 3,061 3,495 4,442 4,442

Senex 157 358 240 240

Sinopec 3,263 3,993 957 2,457

Stanwell 143 143 55

Total 494 1,478 1,876 450 450

Toyota Tsusho 122 122

WestSide 47 347 885

Total 5,693 44,442 68,916 31,853 45,446

Figure 4-6 presents the CSG reserves and resources by activity groupings including LNG

projects, power generators and utilities, international groups and independents. The

small independents only hold 2.2% of the 2P reserves and 6.3% of the 3P reserves.

Figures are based on Origin Energy and Santos CSG reserves held outside of APLNG and

GLNG respectively, and international ownership in addition to offshore ownership in

LNG projects and Energy Australia.



37

Figure 4-6 CSG reserves and resources by activity – PJ (RLMS, Dec 2012)

4.4 Development of coal seam gas reserves

Future reserve levels are determined by the current level of reserves, the quantity of

reserves exhausted in supplying gas to the market, the rate at which additional reserves

are developed and the rate of investment in exploration. The reserve development rate

is a critical issue moving forward, particularly as the LNG proponents develop reserves

to support their LNG projects.

4.4.1 Historical development of CSG 2P reserves

Figure 4-7 presents the level of 2P CSG reserves since 1996 and the annual rate at which

these reserves have increased. From this chart, it can be seen that the level of CSG

reserves have undergone a significant increase since early last decade with the largest

annual increase of 14,933 PJ occurring in 2010. This has been followed by much smaller

increments since 2011. The slowdown in CSG reserve growth is a consequence of the

LNG proponent groups refocusing their development strategies to gas production once

they established a sufficient reserve base to support the initial phase of their LNG

projects. The drop in reserve development in 2011 was also impacted by the severe

weather events in the Bowen and Surat basins during early 2011.



38

Figure 4-7 Historical development of 2P CSG reserves – PJ (RLMS, Dec 2012)

4.4.2 Reserve conversion efficiency and conversion rate

Looking forward an assessment of the expected and potential variation in the rates at

which 2P reserves will be developed is important to LNG export development schedules.

Two definitions are introduced here in order to consider both the quantity and time rate

of reserve conversion:

Conversion efficiency: The proportion of a higher classification of reserves and

resources (e.g. 2C resources) that will realise into certifiable 2P reserves; and

Conversion time: The time taken for higher classification reserves and

resources to be fully converted to certifiable 2P reserves.

For instance, assume a portfolio owns a 2C resource of 100 PJ with a conversion

efficiency of 80% and a conversion time of five years. The portfolio holdings after one,

two and five years (assuming no gas production takes place) is shown in Table 4-2.

Table 4-2 Example of reserve conversion

Time (years) Volume 2P reserves Volume 2C resources

0 0 100 PJ

1 80% x 1/5 x 100 = 16 PJ 100 – (1/5 x 100) = 80 PJ

2 80% x 2/5 x 100 = 32 PJ 100 – (2/5 x 100) = 60 PJ

5 80% x 5/5 x 100 = 80 PJ 100 – (5/5 x 100) = 0 PJ



39

Factors which influence conversion efficiency and conversion time include well

productivity, drilling rates and evolving technology as they impact the rate at which

wells are developed1. Below target performance in either drilling rates or well

productivity could impact the ability of LNG proponents to reach their final investment

decision and gas suppliers to provide long term contracts to domestic users.

We use an example to show how these factors will determine the size and speed of

additional LNG train developments. Using assumed conversion efficiencies (see Section

0) and a static conversion time of 4 years for all cases, the corresponding increase of 2P

reserves is around 3,500 to 9,000 PJ per year assuming no further exploration is

undertaken. The resulting development trajectories of 2P reserves development in

Queensland are shown in Figure 4-8. Also shown are the total reserves required for 6, 8

and 12 LNG trains (notionally a 250 PJ/year requirement for each train for 20 years).

This chart illustrates there are sufficient reserves for the 6 committed trains and that

the reserve development rate will strongly influence the LNG proponents ability to meet

their required reserve levels for their LNG projects particularly for higher numbers of

LNG trains. Note this graph does not include the exhaustion of reserves as gas is

produced. Around 1,500 PJ of 2P reserves would be depleted annually in order to

supply six LNG trains as well as committed reserves towards domestic gas demand.

Once a sufficient number of LNG trains are operational, reasonable rates of reserves

development would be required in order for the overall level of 2P reserves to continue

to be maintained or increased.

Figure 4-8 Reserves development rates and 2P requirements – PJ

1 In defining “drilling rate” we exclude gas treatment facilities, compressor and gathering systems as they have separate schedules and are impacted differently by external events such as flooding.



40

4.5 Unconventional gas

Some of the producers in the Cooper-Eromanga basins, including Santos and Beach

Energy, are now reporting contingent resources for unconventional gas. These

resources are mainly from known gas reservoirs with very low permeability, for which

up to now gas recovery has been uneconomic. In addition the advent of directional

drilling and multi stage hydraulic fracturing (fraccing) has enabled some gas resources

from carbonaceous shale and deep coal seams to be established.

The Cooper Basin has huge unconventional gas potential. Tight gas occurs widely across

the Cooper Basin in conventional sandstone reservoirs. Shale gas is found in very tight

(exceedingly low permeability) shales and with up to 5% total organic carbon.

Formations of the Permian–Triassic aged strata up to several hundred metres thick have

been identified in the major troughs across the Cooper Basin. These have good gas

contents and in many cases, low carbon dioxide contents. The unconventional gas

resource is very large but exploration is at an early stage and detailed appraisal is just

commencing. There is general agreement across the industry that it will be at least five

years, and probably not before 2020, before shale gas is commercially available. With

the host strata being at considerable depth (around 2,500 m) there will be need for in-

seam drilling and significant fraccing facilities. The cost of producing this gas is

estimated to be a minimum $6/GJ and is a further example of the production cost

pressures currently present in the market.

In the Cooper-Eromanga basins, the major exploration groups targeting unconventional

gas estimate that the in situ gas resource exceeds 300,000 PJ which alone translates to

over 30,000 PJ of sales gas at an overall recovery rate of 10%.

Unconventional gas which comprises conventional gas in low permeability reservoirs,

deep gassy coals, usually of Permian age and gas contained in fine grained

carbonaceous shales (shale gas), is a significant resource in many of the existing

sedimentary basins across Eastern Australia. The most significant unconventional gas

resource in Australia is in the Cooper-Eromanga basins where active exploration and

appraisal drilling programs are being undertaken by a number of companies. The

Cooper-Eromanga basins have been estimated to hold in excess of 310,000 PJ of

unconventional gas resources2.

Recovery of unconventional gas requires the use of newer technologies, including

surface to inseam drilling and extensive fraccing, making this tight gas more expensive

to produce than conventional gas circa $5-$6/GJ. The high carbon dioxide content in the

range of 15-20% in some of the unconventional gas also adds to gas processing and end

user costs.

2 RLMS estimate based gas resource estimates made by the va rious groups currently undertaking exploration and appraisal of the unconventional gas resource in the Cooper-Eromanga basins



41

5 Cost of east coast gas production

There are many factors that impact the cost of CSG production including but not limited

to the nature and characteristics of the coals, coal thickness and the regional geological

setting. This review found CSG costs to be currently in the range $4.4/GJ to $5.6/GJ.

Moving forward, the costs are expected to increase to around $7/GJ at reserve levels of

80,000 PJ as less easily accessible and tight gas is recovered.

This chapter presents an assessment of the factors that contribute to the cost of

supplying gas (ex-field), the components of costs and the range of supply costs. A

supply cost curve is developed for CSG based on these factors and information publicly

available. The cost of conventional gas production is also addressed.

5.1 Factors in the cost of developing and supplying CSG

This section presents a brief overview of the factors that influence the cost of

developing and supplying CSG. This discussion illustrates that there is no standard cost

for the production of CSG. The production costs of CSG vary from field to field and

across a given gas field, depending on many factors, such as:

The nature of the coals (depth of the coal seams, orientation of cleats and

fractures);

Coal seam thickness including aggregate thickness;

Regional coal formation geology; and

The characteristics of the coal such as gas content and composition, degree of

water saturation, formation water quality and permeability.

These factors determine the type of well drilled and the well completion methods.

Coals of moderate gas permeability with simple vertical wells are at the low end of the

cost scale. In contrast, low permeability coals which require in seam well configurations

and possible hydraulic fraccing are at the high end of the cost curve. The variation in

the cost of gas processing, water treatment and disposal can be significant. These costs

can vary across a gas field as well as from gas field to gas field across basins.

The cost of producing and supplying CSG also depends on the nature and market for the

gas. This determines the amount of processing that needs to be undertaken on the raw

gas. Gas that is produced for distant markets and transported by way of a high pressure

gas transmission pipeline or through a reticulated system is required to be treated to

meet gas transmission pipeline standards. This involves dehydration and compression

and may also involve some gas conditioning such as CO2 removal.

Gas produced and utilised for on, or near field use, such as power generation normally

only requires limited processing and compression.



42

5.2 Cost components and scenario range

As described above, the costs of supplying gas reflect regional cost differences across

CSG fields, and to some degree, the well productivity and configuration. Noting the

variation in costs across different fields, estimated gas supply costs related to producing

CSG and treating it to pipeline quality3 are given in Table 5-1 for a Low and High

scenario4. The cost components are categorised as:

Capital costs;

Well operating costs; and

Other costs such as exploration, taxes and royalties.

Table 5-1 Estimated production costs for pipeline quality CSG - $/GJ (RLMS)

Component Low (AUD/GJ) High (AUD/GJ)

Well Operating Costs

Total well operating costs 1.30 1.60

Total gas and water processing costs 0.88 1.10

Sub-total 2.18 2.70

Capital Costs

Field development 0.79 1.23

Gas and water treatment 0.90 1.15

Sub-total 1.69 2.38

Other Costs

Exploration and Development 0.09 0.10

Royalties 0.30 0.35

Taxation 0.16 0.20

Sub-total 0.55 0.65

Total costs ex-field 4.42 5.63

The costs listed above do not occur in the year the gas supply is delivered but rather in

the years prior to delivery. These cost ranges do not include the impact of exchange

rate, although this is largely confined to drilling rig costs and is thus not normally a

significant factor. These costs also do not include carbon charges and do not factor in

future efficiency gains. The exact distribution of costs and exchange rate impact can

vary over time. In this study we have assumed that expenditure occurs over a four year

3 Pipeline quality gas is fully treated and compressed to 15.3 Mtpa for introduction to a gas transmission pipeline.

4 These costs have been developed by RLMS through its understanding of CSG developed through a long and close

association with the upstream gas industry. This has been supported by a significant amount of anecdotal data within the industry relating to the cost components of producing CSG from specific gas fields. The cost estimates have been developed for a notional CSG field delivering 60 TJ per day (21 PJ/year) for 15 years. The gas will be processed to deliver pipeline quality sales gas at a pressure of 15.3 MPa in to a gas transmission line. It is assumed that 100 production wells will be required with each well producing on average 600 GJ per day (575,000 cfd). It is also assumed that an additional ten wells are under work over operations while there are ten shallow monitoring wells.



43

period and that exchange rate impacts less than 20% of costs. A discount rate of 10%

real was assumed.

5.3 Development of CSG supply cost curve

The previous section provided low and high estimates of production costs of CSG. The

high cost level is based on the marginal costs of current fields (2P reserve level of

44,442 PJ), while the low estimate is based on the currently producing fields, noting that

many uncertainties exist as discussed earlier. As fields continue to be developed, costs

would be expected to increase due to the more easily accessible and productive fields

being developed first.

Production costs in the Bowen-Surat basins range from low to high depending on the

quality of the individual field. In the Gunnedah Basin, simple verticals have been found

to be inappropriate due to the geological structure of the coal formation, resulting in

the need to use surface to in seam wells with associated higher costs.

On the basis that the current cost trend continues and that shale gas is in the economic

mix post 2020 (by which time the volume of 2P reserves is likely to have increased to

over 60,000 PJ) a supply cost curve is presented in Figure 5-1 below. The basis of the

cost is consistent with that presented in Table 5-15. This cost curve accounts for the

timing of expenditures and the mix of gas fields. We conclude this section by reminding

the reader that many uncertainties exist in the cost of CSG and shale gas looking

forward.

5 Note that the production costs shown in Table 5-1 do not include the impact of exchange rate, carbon or future efficiency gains.



44

Figure 5-1 CSG and unconventional gas supply cost – $/GJ (RLMS, Dec 2012)

5.4 Conventional gas

The development and economics of conventional gas production is very different to that

of CSG. The main conventional gas resources are located offshore in Gippsland, Bass

and Otway basins and onshore in the Cooper-Eromanga basins. There are no ramp-up

gas issues. The economics of conventional gas can be highly influenced by the gas

composition and the value of the hydrocarbon liquids recovered. This may be

significantly more than that of the associated gas obtained.

In the case of gas composition, many of the conventional gas fields in Eastern Australia

contain significant quantities of CO2 and trace amounts of sulphur and mercury

compounds which have to be removed. The cost of gas treatment plant can be

significant.

The cost structure of conventional gas is thus dependent on many issues, and a detailed

assessment, which includes the impact of factors associated with any hydrocarbon

liquids recovered must include some uncertainties. We assess the supply cost to be

around $4.5/GJ from the Gippsland, Bass and Otway basins and in the order of $6.0/GJ

from the Cooper-Eromanga basins.

Notwithstanding the barriers to entry discussed in Section 6.11, it may become

economic for these gas resources to supply QLD demand under conditions of high QLD

wholesale gas prices. This could occur in the case of high netback prices under buoyant

oil price levels, or if the cost of non-conventional gas supply were to increase

significantly above conventional gas supply costs.



45

6 East coast gas market supply

This chapter presents a review of the upstream gas suppliers participating or who have

the potential to participate in the Eastern Australian domestic gas market. These include

AGL, Arrow, Beach Energy, BHP Billiton, Esso Australia, Origin Energy, QGC and Santos.

The capability and constraints of supplying gas to Queensland from the southern states

are discussed, with the conclusion that the gas pipeline limitations and costs present an

economic hurdle to Victorian gas competing for wholesale sales in Queensland.

At the present time, gas is supplied to the Eastern Australian market by various parties.

A short summary is provided with additional information further below:

BHP Billiton and Esso Australia are the major reserve holders and suppliers of

conventional natural gas in VIC, NSW and TAS sourcing gas from the Gippsland

and Otway basins, while Santos is the major supplier in SA and complements

Gippsland Basin gas in NSW through sourcing gas from the Cooper-Eromanga

basins. Santos also is a significant producer of gas from the Otway basin. Nexus

operates the Longtom offshore field in the Gippsland Basin where gas is

processed in Santos’ Orbost gas plant.

Origin is a major producer of conventionally sourced gas in the Cooper-

Eromanga basins where it is part of the Cooper Basin Joint Venture (CBJV). It

also acquires gas in these basins from Beach Energy who are a participant in

the CBJV. Origin is also the operator of the offshore Bass Gas and Otway Gas

projects which supply gas into the Victorian gas supply system.

AGL is the sole producer of gas in New South Wales where small quantities of

CSG are produced in the Camden Project. AGL is also a significant gas supplier

into the QLD domestic gas market with gas acquired under long term contract

from QGC.

The major gas suppliers into the QLD market are in the Bowen and Surat basins

and include major CSG producers APLNG, Arrow Energy, QGC for QCLNG and

Santos for GLNG. Origin is the operator for APLNG. Westside Corporation is

operator of the Meridian Project in the Dawson Valley which supplies small

quantities of gas to the Moura ammonium nitrate plant and some industrial

markets in Gladstone and Rockhampton.



46

6.1 AGL Energy

AGL is currently the largest gas retailer in Australia with some 164 PJ of volume (FY12)

that it sells to its mass market, commercial & industrial, and wholesale customers (29%

of domestic market) and holds significant GPG interest in the NEM.

AGL’s gas book is currently underpinned by the Gippsland basin contract that expires in

2017 for 100 PJ/year. AGL is a net purchaser of gas for retail sales and this situation is

expected to continue as AGL’s gas reserves, although large, are currently insufficient to

meet its long term retail market and power generation requirements. Furthermore, a

significant part of AGL’s 2P gas reserves are stranded reserves located in the northern

Bowen Basin which is currently not physically connected to the eastern Australian gas

system.

AGL holds Gas Supply Agreements (GSAs) for CSG from QGC and for

conventional gas from the Santos-operated CBJV;

AGL’s major reserves in Queensland are around the Moranbah area where it

supplies a net 24 TJ/day to Townsville. AGL recently entered into a long term

contract with Xstrata to supply gas to the 242 MW Diamantina power station

and to Xstrata’s Mount Isa mine operations, committing 138 PJ of reserves to

the agreement. The gas under this contract is provided to AGL by QGC under a

long term 740 PJ contract expiring in 2028;

While a significant increase in gas reserves within the Arrow/AGL joint venture

permits in the northern part of the Bowen basin is expected, it is understood

that Arrow Energy has a first option on those reserves not being used by AGL.

Furthermore, the location of these assets is such that they are not presently

connected to the southern or central Queensland market, with Arrow’s

proposed Bowen pipeline not planned to be commissioned before 2017;

AGL has an exploration and appraisal program for CSG in the Galilee basin

where it has booked its first contingent gas resource. Commercial production of

CSG from the Glenaris Project is not expected before 2020; and

AGL’s proposals to develop further its CSG resources in New South Wales are

being constrained by land use restrictions though it has applied for approvals to

bring its Gloucester Basin project into production by late 2017 at an initial rate

of 80 TJ/day.

6.2 APLNG

Australia Pacific LNG (APLNG) is a JV between ConocoPhillips (37.5%), Origin Energy

(37.5%) and Sinopec (25%). APLNG is a major provider of domestic gas through its

upstream operator Origin Energy. Virtually all the GSA’s into which Origin Energy

entered before the finalisation of APLNG are now supplied by gas reserves transferred

to APLNG. APLNG is a major supplier of CSG into the QLD market operating in the



47

commercial and industrial markets as well as supplying retail customers. Origin Energy is

also a major gas consumer in its wholly owned Darling Downs and Roma gas fired power

stations. Origin Energy also sells gas from its own reserves which are not part of the

APLNG JV.

APLNG currently supplies 40% of Queensland gas, with customer contracts

being legacy Origin customers transferred to APLNG. Existing contracts include

supply to the RTA Yarwun alumina refinery, QAL alumina refinery and the

Boyne Island aluminium smelter, all in the Gladstone Region;

Origin operates APLNG’s Peat, Spring Gully and Talinga gas fields supplying the

domestic gas market. In addition it has significant equity interests in the

Fairview Gas Project operated by Santos and in a number of CSG production

fields on the Central Walloon Fairway which are operated by QGC. APLNG has

a number of gas contract agreements with QGC and Santos based on gas swaps

around its equity interests;

Origin operates the Denison Trough conventional gas fields on behalf of the

APLNG/Santos JV. Gas from these facilities, currently about 4 PJ/year is

transported to Gladstone through the QGP operated by Jemena;

In addition to developing a number of new CSG gas fields on behalf of APLNG,

Origin is in the early stages of the development of the Ironbark CSG field in the

Surat Basin in which it has 100% interest. Ironbark is being developed to supply

either or both of the domestic and export markets;

Looking forward, APLNG has sufficient 2P (13,090 PJ) and 3P (16,026 PJ)

reserves of mostly CSG to support 20 years of operations of its two train, 9

Mtpa LNG plant being built on Curtis Island. The project is on target to deliver

LNG by mid-2015. The project is virtually fully contracted with publically stated

sales to 7.5 Mtpa to Sinopec and 1.0 Mtpa to Kansai Electric. APLNG has

approvals to add up to a further two LNG processing trains, although under the

current international demand dynamics and domestic cost structures, further

expansion seems unlikely in the near term. Future gas availability to the

domestic market will depend on its reserve position and LNG export

expectations at the time.

6.3 Origin Energy

Origin Energy has interests in both the domestic gas market (where it is a major supplier

of gas) and in the LNG export market (where Origin Energy currently holds a 37.5%

share of the APLNG project). Origin Energy is the upstream operator for APLNG.

The bulk of Origin Energy’s CSG reserves and resources were transferred to the APLNG

project upon its formation in 2008. Notwithstanding this, Origin Energy holds a

portfolio of gas reserves in its own right. This includes a small portfolio of conventional

gas reserves in the Surat Basin and the recently announced Ironbark CSG project.



48

Ironbark is expected to supply a total of 1,600 PJ over 40 years at a rate of 120 TJ/day

starting from late 2015. Origin Energy has stated that gas from Ironbark will be directed

mostly towards the domestic market including power generation, but has not ruled out

some gas supply to LNG if it attracts a superior return.

In addition, Origin Energy has conventional gas reserves in the Cooper-

Eromanga basins which are already connected to the Wallumbilla gas hub via

the QSN/SWQP. The company also has significant conventional gas reserves

and resources in the Bass and Otway basins off the Victorian coast;

Origin Energy is continuing with its exploration and appraisal program for CSG

in the Galilee Basin. However the Galilee program is not expected to reach

commercial status until after 2020;

Origin Energy has the potential to increase its supply of gas to the domestic

market in the future, noting that any such agreements will need to be

competitive against Origin’s (substantial) internal requirements for power

generation and its commitment to LNG; and

Origin Energy has an agreement with GLNG to supply 365 PJ for 10 years (100

TJ/day) from 2015.

6.4 Arrow Energy

Arrow Energy, a JV between Royal Dutch Shell and PetroChina, is undertaking FEED

studies into the establishment of a four train 16 Mtpa LNG facility on Curtis Island. An

investment decision on the construction of the first two trains is expected in early 2014.

Arrow Energy has sufficient 2P gas reserves to support a two train LNG operation for 20

years. However, Arrow’s gas reserves are split between the Surat basin (78%) and the

north Bowen Basin (22%). Should Arrow Energy decide to proceed with its LNG project,

it is expected that it will initially operate on CSG from its Surat basin permits where it

has 15 years of gas reserves for its proposed two train operation, and bring the northern

Bowen Basin gas reserves into production at a later stage. This phase of the project will

require the construction of the proposed Bowen Gas Pipeline.

Bow Energy was acquired by Arrow Energy in early 2012 after consideration by the ACCC

of competition impact issues. Bow Energy holds a number of permits in the Bowen

Basin as well as having interests in the Surat and Cooper-Eromanga basins. It is

estimated that Bow Energy has the potential to supply up to 3,500 PJ of gas from these

blocks.

Arrow Energy, which currently supplies approximately 50 PJ/year into the domestic gas

market, holds a number of existing contracts with customers such as Ergon Energy and

the Swanbank E and Braemar 2 power stations. The Moranbah Gas Project, in which

Arrow has a 50% interest with AGL, provides some 50 TJ/day to Townsville with

approximately 15 TJ/day used by the 230 MW Yabulu CCGT power station. The 500 MW



49

Braemar 2 OCGT power plant is owned by Arrow Energy, which also owns the 30 MW

Daandine facility.

6.5 Beach Energy

Beach Energy has approximately a 20% interest in the CBJV operated by Santos. In

addition it has considerable acreage in the Cooper-Eromanga basins outside of the CBJV

where it produces oil, condensates and gas. Most of its gas production is tolled through

the CBJV plant at Moomba. Beach Energy is mostly the operator of its non-CBJV permits.

In addition to its 345 PJ of conventional gas, Beach Energy is a pioneer in evaluating

unconventional gas in the deep troughs of the Cooper Basin. It has already established

2,333 PJ of 2C contingent resources and has an active appraisal program under way in

both the QLD and SA sections of the Cooper-Eromanga basins. It has a major JV with

Chevron to appraise the unconventional gas in the Cooper-Eromanga basins.

In April 2013 Beach Energy entered into a gas supply agreement with Origin Energy to

provide up to 139 PJ over 8 years from its Cooper Basin portfolio with the potential for a

two year extension that could lift the total sales to 173 PJ. Gas deliveries are scheduled

to commence at Moomba between July 2014 and June 2015. The gas price has been

reported to incorporate a combination of an oil-linked curve and other parameters.

6.6 Queensland Gas Corporation

QGC is the most progressed of all the LNG projects with their first train on track to

accept commissioning gas by the end of 2013. Some pre-commissioning of equipment

has commenced. They expect to have their first gas shipment underway at the

beginning of H2 2014. QGC has significant CSG reserves (2P – 10,350 PJ) in its Surat and

Bowen Basin permit areas to support a two train operation for 20 years. As QGC do not

have a portfolio of gas reserves outside its existing tenements, they have entered into

some gas supply contracts with Origin Energy to minimise potential ramp up issues

during the early operations of the Curtis Island project. Much of the agreements with

Origin have been based on gas swaps where QGC and Origin Energy have JV operations

around the Central Walloons Fairway.

In addition to its agreement with Origin Energy concerning the management of

initial gas supplies, QGC has an agreement with AGL based on the conversion of

the depleted Silver Springs gas field into a gas storage facility. This gas storage

unit is now operational;

Of the two trains 94% of the output is contracted. BG (owner of QGC) trade and

market their LNG on a global portfolio wide basis which is centralised in

Houston, Dallas USA. This approach means they have multiple supply and sale

options with economic proximity being a major driver of cargo economics. This

means there is no Australian project specific delivery delay risk to BG because



50

of equity gas arrangements and a global portfolio with alternative supply

production and supply points; and

Currently BG supply approximately 20% of the QLD market with customer

contracts out as long as 2027. QGC holds a number of existing contracts with

customers including Incitec Pivot, AGL and the Swanbank E, Braemar 1 and

Condamine power stations.

6.7 Santos

Santos currently supplies around 17% of the Eastern Australia domestic market and is

the project leader and has a 30% equity interest in the GLNG project. GLNG, which by

itself does not yet have sufficient certified 2P gas reserves for a two train operation for

a full 20 years, has a contract for Santos to supply 750 PJ of portfolio gas for 15 years

commencing 2016. The bulk of this gas is expected to come from the Cooper-Eromanga

basins. GLNG has also entered into a 10 year agreement with Origin Energy for the

supply of 365 PJ of gas at a price linked to international crude oil prices. Santos also has

a gas swap agreement with Origin Energy between Combabula and Fairview which will

deliver a further 25 TJ/day to GLNG.

Major supply contracts held by Santos include the customers Incitec Pivot,

Xstrata and the Swanbank E and Braemar 1 power stations. Santos has a

majority share of a gas swap contract between Moomba and Wallumbilla with

Origin Energy;

Outside of GLNG, Santos holds significant gas reserves and resources in Eastern

Australia. These are located in the Surat, Cooper-Eromanga basins, Gunnedah

and Otway basins;

While noting that GLNG is currently a two train project, it has been reported

that until GLNG has secured sufficient gas reserves for a three train LNG

operation, Santos, as the major gas supplier to and participant in GLNG, is

unlikely to enter into new domestic gas supply arrangements or renew existing

agreements unless prices are linked to the international crude oil price.

6.8 BHP Billiton and Esso Australia

The BHP Esso JV (Gippsland Basin Joint Venture - GBJV) is a major producer of oil,

condensates and natural gas and is the major supplier of natural gas and ethane to the

Victorian market. It also supplies a significant quantity of gas to the Sydney market

through Jemena’s Eastern Gas Pipeline:

The GBJV, which is operated by Esso Australia, has a major gas processing plant

at Longford in Gippsland with a notional capacity of 1,100 TJ/day. This project is

being upgraded to enable it to handle higher CO2 content gas associated with

the new Kipper-Tuna-Turrum developments as well as new reservoirs



51

associated with some existing operating fields, however the notional capacity

of 1,100 TJ/day will remain unchanged;

The Kipper development is scheduled to be brought into production in 2016 at

a rate of 80 PJ/year. Santos has a 35% interest in Kipper;

While the posted 2P gas reserves in the Gippsland basin are 3,890 PJ, the

overall gas resource is considered to exceed 10,000 PJ; and

Long-term contracts include 825 PJ to EnergyAustralia (14 years to 2017),

983 PJ to AGL (14 years to 2017) and 250 PJ to Origin Energy (11 years to 2019).

6.9 Nexus Energy

Nexus Energy operates the offshore Longtom conventional gas project in the Gippsland

basin. During 2012, Longtom produced 15 PJ of gas which was processed through

Santo’s gas processing plant at Orbost. The gas output goes into the Eastern Gas

Pipeline supplying the Sydney market. Longtom has 122 PJ of 2P gas reserves with a

further 102 PJ of 2C contingent resources.

6.10 Smaller suppliers

Westside Corporation, Mitsui E&P and Harcourt Petroleum currently supply small

quantities of gas in Queensland (around 1.5% of the market). Westside Corporation and

Harcourt operate adjacent tenements in the Dawson Valley near Moura, with Mitsui

E&P having interest in both tenements. The Dawson Valley region is currently

producing 14 TJ/day, and is planning to ramp up production to 25 TJ/day by 2015 to

meet existing domestic contracts with AGL.

Harcourt Petroleum, a wholly owned subsidiary of PetroChina, acquired the Dawson

Valley CSG interests of Molopo Energy in 2012.

Looking forward, production from the Dawson Valley operation is expected to increase

to around 60 TJ/day by 2020 and total uncontracted reserves are estimated to be

around 1,200 PJ, noting that 25 TJ/day of production is already reserved for an existing

contract with AGL.



52

6.11 Supply to Queensland from the southern states

This section discusses the capability and competitiveness of BHP Billiton and Esso

Australia to supply gas to the wholesale market in Queensland.

As 2P reserves in the Gippsland Basin are more than adequate to meet Victorian

demand for the next twenty years or so, gas from the southern states might be assumed

to be offered by BHP Billiton and Esso Australia (who by far have the greatest reserves

in the southern states) into Queensland on a competitive basis.

However there are substantial barriers to any significant gas transfers from Victoria to

Queensland, these being cost comparisons, distance and the understanding of gas

development positions of the LNG proponents:

The ex-plant price for Gippsland gas would have to be substantially lower than

that in Queensland due to the large transport tariffs involved. The possible

impact on prices for Victorian sales would also have to be considered;

Preliminary estimates of the cost to deliver substantial quantities of gas from

Longford in Victoria to Gladstone via Wallumbilla in a new pipeline give a

transportation tariff of $3.5/GJ with the Longford to Wallumbilla tariff at

$3.0/GJ;

Supply of additional Gippsland gas in substantial quantities at a reasonably high

capacity factor (low swing) would require substantial additional investment in

production and processing facilities, and would be at a higher cost than existing

supplies. However some small gas swaps may be possible;

The QLD LNG proponents are aiming to be self-sufficient in gas primarily

sourced from Queensland and perhaps the Cooper-Eromanga basins. They are

likely to achieve this by a combination of increasing their reserves, managing

drilling rates, well turn down technology and not committing to more LNG plant

capacity than can be served by their proven reserves;

Pipeline capacity is currently not available to physically transfer gas between

QLD and the southern states. The QSN link is fully contracted to three major

parties (AGL, Origin Energy and Santos) and has directional flows from

Queensland to the southern states. The flow is expected to reverse in 2015

with APA installing additional compression capacity at Moomba to increase

eastward transmission up to 360 TJ/day, with capacity to increase to 600 TJ/day

with additional compression. Capacity of 600 TJ/day would be sufficient gas for

a 4 Mtpa (220 PJ) LNG plant. Santos has entered into commercial

arrangements to access the compression capacity installed. This will be used in



53

part by Santos to supply its 750 PJ portfolio gas commitment to GLNG for 15

years commencing in 2016;

Significant gas swaps6 between QLD and the southern states between

companies are considered unlikely7 though some internal gas swaps where

companies have gas reserves and resources in geographically diverse basins

may occur; and

Santos has significant uncontracted CSG reserves and resources in the

Gunnedah Basin. Supplying this gas to Queensland will require the construction

of the northern section of the Queensland Hunter Gas Pipeline between

Narrabri and Wallumbilla. Alternatively Santos may use its Gunnedah basin gas

reserves to supply the Sydney market with an internal gas swap to free up gas

in the Cooper Basin for use by GLNG.

In conclusion, it is our opinion that pipeline capacity limitations and pipeline

transportation costs present an economic hurdle to BHP Billiton and Esso Australia

(GBJV) competing for sales in QLD. With similar supply costs for Gippsland basin gas

(estimated to be $4.50/GJ – see Section 5.4) and QLD CSG (estimated at $4.40 - $5.60/

GJ – see Section 5.2), and significant pipeline transportation costs between Victoria and

Queensland (in the order of $3/GJ), we consider substantial gas transfers from Victoria

to Queensland would be unlikely.

6.12 Longer term QLD gas suppliers

Several companies hold reserves in QLD and northern NSW but are unlikely to be in a

position to supply the domestic market for at least the next five years. These include

Blue Energy, Icon Energy, Senex, Toyota Tsusho, Metgasco and ERM Power. The

positions of these companies are summarised in Appendix B .

6 Gas swaps are a means of avoiding the physical transport of gas from source to markets. For example, a party with surplus gas in one region and wishing to have gas in a second region may swap with another party in the reverse position or at least having surplus g as in the second region. A pipeline need not link the two regions. This allows pipeline charges to be avoided. Two willing parties are, of course, required. An exchange of money may be part of the arrangement to account for differences in the value of gas in the two regions. 7 Most of the major southern gas resource holders are not long in Queensland and have nothing to swap. The only companies with gas resources right across eastern Australia are Origin, Santos and to a small degree AGL which is long at Moranbah. Both Origin and Santos are using internal gas swaps.



54

7 QLD LNG developments

This chapter and accompanying appendices discuss the LNG projects being developed in

Queensland at Gladstone.

There are currently three 2 train LNG projects under construction on Curtis Island near

Gladstone – APLNG, GLNG and QCLNG - along with associated upstream production

wells, gas and water processing plants, and pipelines. Arrow Energy is finalising its

detailed feasibility studies into a two train project, also on Curtis Island, with Final

Investment Decision (FID) expected to be made early in 2014.

Collectively there are sufficient 2P reserves to support all of these projects, including

that of Arrow Energy, as a two LNG train facility, 8 trains in total. APLNG and QCLNG

have enough reserves to support an additional LNG train each while GLNG is dependent

on some additional portfolio and third party gas reserve purchases to meet its two train

requirements.

The LNG projects in Queensland have been subject to a number of cost pressures since

sanction including the recent high Australian dollar and high wage costs, though these

pressures are starting to reduce. These factors may be a major influence on whether the

Arrow LNG project will be sanctioned in the short term.

The total number of LNG trains which will eventually be constructed in Queensland will

be dependent on a number of factors including LNG market growth, international oil

prices, the linkage between international oil prices and LNG prices, level of gas reserves

to underwrite additional LNG trains and the international cost competitiveness of

establishing new LNG processing capacity in Australia.

This chapter presents the status of the Gladstone based LNG projects, their reserve

position and their drivers as influenced by the world LNG trade and relative economics.

Australia has particular advantages that aided Final Investment Decisions (FID) being

reached on three LNG projects at Gladstone (APLNG, QCLNG and GLNG). These projects

have a combined capacity of approximately 25 Mtpa of LNG (1,400 PJ/year). This

represents approximately a quarter of global LNG supply presently under construction.

Should the Arrow LNG project achieve FID, the aggregate LNG productive capacity

installed on Curtis Island will reach 33 Mtpa (1,800 PJ/year) by 2020.

Details of the Gladstone-based LNG developments are summarised in Table 7-1 below.

The Arrow Energy LNG Project is expected to be considered for FID by the project

partners in late 2013 or early 2014.



55

Table 7-1 Announced and proposed LNG developments at Gladstone (RLMS)

Project Proponent

LNG train Capacity (Mtpa)

Initial No. of Trains

Project size (Mtpa)

Gas per year (PJ/year)8

Scheduled Start-up

APLNG Origin, Sinopec ConocoPhillips

4.5 2 18.0 540 Q2-2015

GLNG Santos, KOGAS PETRONAS, Total

3.9 2 12.0 464 Q1-2015

QCLNG QGC, CNOOC

Tokyo Gas

4.25 2 13.5 510 Q2-2014

Arrow LNG

Shell, PetroChina 4.0 2 16.0 480 Q2-2017

Figure 7-1 outlines the location of the LNG liquefaction plants of each of the four

proponents located on Curtis Island. The ability of the Arrow LNG development to

progress to Final Investment Decisions by early 2014 to meet a planned 2017 first

shipment schedule will mostly be influenced by the cost pressures on the project

compared to those other projects in Shell and PetroChina’s international portfolio of

development projects. It is understood that marketing of the output from the proposed

Arrow project is not a constraint as it will be absorbed into the LNG portfolios of both

Shell and PetroChina.

Figure 7-1 Proposed Curtis Island LNG developments

Source: Interfax Global Energy Services

8 I Tonne of LNG contain 55 GJ of energy and require an additional 5 GJ at the LNG plant to condition the input gas,

liquefy it and drive the plant utilities. Thus 60 GJ of feed gas is need ed to produce 1 tonne LNG product, that is 60 PJ per million tonnes of LNG product.



56

In the early development of the QLD LNG projects, it was considered that the long lead

times to generally bring CSG wells and fields into production would lead to considerable

quantities of ramp gas being available over a 2-3 year time period from 2013 at

relatively low cost. This expectation by the market had an influence on the gas

purchasing strategies by some major gas consumers, many of which factored in their

ability to utilise ramp gas into their negotiations with gas suppliers, with the expectation

that they would be able to roll over existing, or negotiate new gas supply agreements on

favourable terms.

However, the ability of the upstream gas industry to internally manage ramp up gas

through a combination of: well management enabling gas fields to be significantly shut

in and restarted; use of gas storage; diversion to GPG; and internal and inter proponent

gas swaps; has seen only limited ramp gas become available on the market impacting

the gas market strategies of both suppliers and purchasers.

Discussion on the management of ramp up gas is provided in the Appendix I .

7.1 Implementation progress of existing projects

Before describing each of the LNG projects and their status, this section introduces

some issues that have impacted LNG project developments in recent times.

The extreme wet weather across the Bowen and Surat basins in the 2010-2011

and 2011-2012 summers, after ten years of dry and near drought conditions,

has had a major impact on the appraisal and development activities planned for

new CSG gas fields. In addition to limited access to land due to flooded roads,

mostly over short periods, the major constraints have been due to

unfavourable ground conditions. This has delayed drilling and hindered the

establishment and operation of multi-well pilot facilities, in part due to the

inability to handle and process co-produced water during a period when most

water storage dams were full;

Uncertainty in the formulation of Government regulatory regimes, particularly

in regard to land access and water disposal, along with delays in issuing the

necessary environmental and planning approvals, has also resulted in the

planned upstream gas field developments falling behind schedule; and

The LNG project proponents responded to these issues by increasing the

number of drilling rigs, particularly production drilling units, introducing single

pad and directional drilling processes, re-programming field development

schedules, and entering into some early phase gas swapping arrangements with

those with slightly later start-up schedules. As a consequence all the projects

are at an advanced stage (>50% completed) with some upstream facilities in

the commissioning phase. All the projects appear to be on schedule with

upstream production, major gas gathering and transmission pipelines, and the

LNG plants.



57

7.1.1 Australian Pacific LNG

APLNG is a joint venture between ConocoPhillips (37.5%), Origin Energy (37.5%), and

Sinopec (25%). APLNG is constructing a two train LNG plant on Curtis Island. Each LNG

train has a LNG production capacity of 4.5 Mtpa (250 PJ/year). Origin Energy is

responsible for the operation of the upstream component of APLNG while

ConocoPhillips will be the operator of the LNG liquefaction plant on Curtis Island.

The APLNG project has been planned to accommodate up to four LNG trains, with a

collective output of up to 18 MTPA (990 PJ/year). Train 1 is on schedule to ship its first

LNG cargo during mid-2015, while Train 2 is planned to be commissioned in early 2016.

After delays in the development of the upstream gas fields, primarily as a consequence

of the severe weather events across the 2010-11 and 2011-12 summers, an accelerated

drilling program with the addition of some automated rigs has enabled the drilling

program to again be on schedule. Construction for rest of the project, including gas

treatment and water handling facilities, the main gas transmission pipeline and the

Curtis Island LNG plant and associated infrastructure are on schedule for initial

commission and first product shipment around mid-2015.

APLNG has total 2P gas reserves of 13,090 PJ which includes 38 PJ of conventional gas in

the Denison Trough in the Bowen Basin. The 3P gas reserves are 16,026 PJ with a further

3,825 PJ of 2C contingent resources. APLNG has more than sufficient gas reserves to

support its two train 9 Mtpa (495 PJ/year) project which will require 10,800 PJ for 20

years of operations.

7.1.2 Queensland Curtis LNG

QCLNG is being developed by QGC, a wholly owned subsidiary of the BG Group. CNOOC

and Tokyo Gas have interests in different components of the project. CNOOC have a

50% interest in QCLNG Train 1 and a 25% interest in the reserves and resources in

certain tenements operated by QGC. CNOOC is also committed to take 8.6 Mtpa (472

PJ/year) of LNG for 20 years from the two train QCLNG project. For Train 2, QGC has a

97.5% interest with Tokyo Gas having the balance. Tokyo Gas has a 1.5% interest in

some of QGC’s Surat Basin permits.

The project, which is in an advanced stage of construction, comprises two LNG

liquefaction trains, each with an annual capacity of 4.25 Mtpa (235 PJ/year). The

project has plans for the future installation of a third LNG train of comparable capacity.

The project is on schedule to ship its first LNG cargo early 2015.

While BG has advised it has no immediate plans to proceed with a third LNG train citing

gas reserve, cost and market issues to be resolved, BG is ramping-up exploration for

additional gas. This includes tight and conventional gas in the Bowen Basin, additional

CSG in the Bowen and Surat basins and in unconventional gas in the Cooper-Eromanga

basins. The unconventional gas exploration program that has just commenced is a JV

with Drillsearch Energy.



58

QCLNG has gross total 2P gas reserves of 10,326 PJ, sufficient for its initial two train LNG

project for 20 years which will require 10,200 PJ. In addition QCLNG has 3P gas reserves

of 18,876 PJ and a 2C contingent gas resource of 13,700 PJ.

7.1.3 Gladstone LNG

GLNG is being managed by Santos on behalf of the joint venture partners Santos (30%),

PETRONAS (27.5%), Total (27.5%) and KOGAS (15%). Apart from overall project

responsibility, Santos is managing the upstream exploration and development activities

of the project. The Curtis Island LNG plant is designed around an eventual three

3.9 Mtpa (215 PJ/year) LNG processing trains.

GLNG is well advanced in the construction in both the upstream aspects as well as for

the two train liquefaction facility on Curtis Island. First LNG shipment is scheduled for

mid-2015, with the second LNG train planned for commissioning mid-2016.

The GLNG project will require 9,360 PJ of gas for 20 years of operation. Currently GLNG

is short of gas in its own right having 2P gas reserves of 5,376 PJ or 11.5 years supply at

full production. The project has 3P gas reserves of 6,823 PJ and 2C contingent gas

resources of 1,638 PJ. Santos has agreed to supply 750 PJ over 15 years (140 TJ/day)

from its portfolio gas commencing 2016. The bulk of this gas is expected to be sourced

from the Cooper-Eromanga basins with some of it being unconventional gas from 2020.

GLNG has also entered into agreements with Origin Energy for the supply of 365 PJ of

gas at Wallumbilla over 10 years (100 TJ/day) commencing 2016. GLNG also has entered

into a small gas supply agreement with Origin Energy for a supply 25 TJ/day at Fairview

based on a gas swap arrangement for a similar amount of gas at Combabula. Origin

Energy and Santos each have interests in Fairview and Combabula.

GLNG will need to procure additional gas to cover post 14 years of its operations. To this

end it has a significant exploration program underway in the Cooper-Eromanga basins

and secured agreement with APA group to transport up to 600 TJ/day from Moomba to

Wallumbilla via the QSN/SWQP9. This is sufficient gas to operate one of GLNG’s

processing trains at 90% capacity (3.5 Mtpa).

7.1.4 Arrow LNG Project

The Arrow LNG project is a joint venture between Royal Dutch Shell (50%) and

PetroChina (50%). Shell is the operator. The project is based on establishing up to four

4 Mtpa (220 PJ/year) LNG trains.

9 The APA Group is installing additional compression at Moomba [est. cost $125 million] to increase the capacity of

the QSN/SWQP to transport natural gas from Moomba to Wal lumbilla. to 360 TJ/day. This is scheduled to be available from 2016. The pipeline’s west to east capacity could be expanded up to 600 TJ/d with additional compression.



59

Arrow has completed its FEED studies for an initial investment in a two train project to

ship out 8 Mtpa (440 PJ/year) of LNG commencing as early as mid-2017. Arrow is now

finalising its investment funds request to its principals. The project is also subject to

receiving its final environmental approvals from the Federal Government. A FID on the

project is expected very late in 2013 or early in 2014.

The major concern within Arrow Energy is that the cost pressures faced by Australian

resource projects over the past three years have impacted on its competitiveness

compared with other projects in the Shell/PetroChina development portfolio. The

lessening of the cost pressures since early 2013 may help the project viability.

Arrow has 2P gas reserves of 9,494 PJ. This is just sufficient for 20 years operation of an

8 million Mtpa (440 PJ/year) LNG facility. Arrow has 3P gas reserves of 13,970 PJ and a

2C contingent gas resource of 2,521 PJ. Approximately 80% of Arrow’s gas reserves are

in the Surat Basin with the remainder in the northern Bowen Basin. The development of

the Bowen Basin gas reserves and resources will require the construction of the

proposed Arrow Bowen Pipeline to link the resource to Gladstone.

Should the Arrow LNG project not be approved as a stand-alone project or an FID

decision be deferred for some years, Arrow Energy could emerge as a potential gas

supplier to the other LNG projects. Another alternative is for Arrow Energy to joint

venture with one of the existing projects to construct a third LNG train using Arrow

Energy gas or even come to some tolling arrangement. Shell has indicated that as part of

its FID decision making process with the Arrow LNG project, it was looking at some of

these options.

Should the Arrow Energy project not proceed in the initial time frames, it is in a strong

position to supply additional gas directly into the domestic gas market or enter into

some long term gas swap arrangements with major gas reserve holders.

7.1.5 Fisherman’s Landing

Liquefied Natural Gas Limited (LNG Limited) is proposing to build and operate a mid-

scale LNG project at Fisherman’s Landing at Gladstone using its own liquefaction

technology. The LNG project is based on two LNG trains each with a capacity of up to

1.8 Mtpa (100 PJ/year).

Initially, the project was to be supplied with CSG from the Surat basin under an

arrangement with Arrow Energy. However, the gas supply arrangements lapsed

following the acquisition of Arrow Energy by the Shell/PetroChina consortium in mid-

2010. Since this time, LNG Limited has been endeavouring to secure a source of gas for

the project that would require 215 PJ/year for a two train facility or 4,320 PJ over the

project life of 20 years.

LNG Limited recently made a bid to acquire WestSide Corporation Limited which

operates the Meridian Seam Gas Project in the Dawson Valley near Moura. Meridian is

connected to the Queensland Gas Pipeline, supplying natural gas to industry in



60

Gladstone, however the acquisition proposal subsequently lapsed. LNG Limited

currently has a series of agreements and arrangements with China Huanqui Contracting

and Engineering Corporation (HQC). HQC a subsidiary of PetroChina’s holding company

is the largest shareholder in LNG limited (19.9%). Should the Arrow LNG project not

proceed or be delayed, it is possible that PetroChina might supply part of it portfolio gas

holdings in the Arrow Energy JV to the Fisherman’s Landing project of LNG Limited.

PetroChina’s share of the 2P gas reserves in the Arrow Energy JV with Shell is sufficient

to sustain the LNG Limited Fisherman’s Landing project for 20 years.

Because of all of the uncertainties with the LNG Limited development it has been

assumed this project is unlikely to proceed during the study period.

7.2 Reserves

The reserve positions of the LNG proponents as discussed above are summarised in

Table 7-2. A graphical representation illustrating the requirements for various LNG train

developments is shown in Figure 7-2. Gas demand from LNG trains is estimated over a

20 year lifetime assuming a gas requirement of 250 PJ/year, and reserves do not include

3rd

party contracts and conversion losses. APLNG reserves include 37 PJ of 2P and 53 PJ

of 3P conventional gas reserves from Denison Trough.

Table 7-2 LNG proponent reserves - PJ (RLMS, Dec 2012)

Proponent 2P reserves 3P reserves 2C resources 3C resources

APLNG 13,090 16,026 3,825 9,829

QCLNG 10,326 18,876 13,700 13,700

GLNG 5,376 6,823 1,638 1,638

Arrow 9,494 13,970 2,521 2,521

Total 38,286 55,695 21,684 27,688

Figure 7-2 LNG proponent gas reserves in the Bowen-Surat basins - PJ



61

From the above we can note the following:

APLNG has sufficient reserves to support the development of three LNG trains.

Thus this proponent appears to be in a position to sell reserves if it desires. The

media release by Origin Energy on 2 May 2012 for the supply of 365 PJ to GLNG

(100 TJ/day over 10 years at Wallumbilla) is consistent with this position. The

gas price is partially linked to international oil prices;

QCLNG has sufficient reserves to meet its announced two train operation and

sufficient for a future third train;

GLNG has an apparent shortage of reserves within the JV. The purchase of

750 PJ of 2P portfolio gas reserves from Santos and 365 PJ of 2P reserves from

APLNG supports this position; and

Arrow has sufficient 2P reserves for a two train development.

Overall the position of the LNG proponents is they collectively have sufficient 2P

reserves to support two train LNG operations for 20 years. The LNG proponents groups

all have varying joint venture interests in most producing gas fields and developing

permits. In many cases they have entered into gas swaps to better align their interests

both geographically and in timing to provide a smoother and consistent gas flows during

the ramp up periods of each LNG train. Also the three proponents have agreed to

integrate parts of their gas supply systems to ensure consistent and stable gas supply to

Curtis Island.

7.3 LNG cost of supply and competitiveness

To date there is little evidence of the cost of supply being a significant determinant used

in the selection of suppliers by buyers, particularly in Asia. Discussed in Appendix G ,

LNG pricing in the Asian market tends to be based on the price of crude oil rather than

on the actual cost of LNG supply.

All supply projects have been required to be economic at that prevailing crude oil price

to enable commitment to supply. Over recent years prevailing high oil prices have

provided high LNG prices, allowing even high cost LNG projects to commit to

construction. North American LNG exports appear to be a major competitive threat to

new Australian exports, and here the cost of supply may become a critical

differentiating factor for securing market in a future where supply potential may exceed

demand.

Figure 7-3 provides indicative break-even costs for a generic yet-to-be sanctioned LNG

project in Canada and in Eastern Australia as estimated by McKinsey & Co (Extending

the LNG Boom, May 2013). Whilst a generic Gladstone project may have been

competitively advantaged over the generic Canadian project in previous years, recent

reports of cost increases at all of the 3 committed Gladstone projects support the break -

even cost of supply for a generic project at Gladstone is now higher than in Canada by



62

up to 30% (although actual project economics may vary considerably). This cost

increase presents uncertainty to committing additional trains, and Arrow Energy’s final

investment decision.

Figure 7-3 Break-even landed costs in Japan - $US/MMBtu (McKinsey & Co)

7.4 Scenario range of LNG developments

Given the huge capital commitments required for LNG projects investment decisions are

made very carefully. Many participants have exposure to existing LNG projects (ei ther

under construction and/or operational) and may have, in addition, alternative

investment opportunities (LNG or other). LNG projects often have shared ownership,

and owners may have different objectives or timing imperatives. These characteristics

arise in several of the Gladstone-based potential supply projects discussed in this

report.

On current indications, it appears unlikely that any new QLD greenfield LNG projects

(other than the Arrow LNG Project, which appears to be progressing towards an FID

decision) will be developed within the next ten years, given the high concentration of

gas reserves and resources held by the current participants in the Gladstone-based

projects and the required scale of the projects. Additionally, evidence of successful

implementation of the LNG projects currently under construction at Gladstone may be a

pre-condition for the further expansion of these existing projects, particularly given the

LNG proponents’ needs to establish additional gas reserves and maintain their

international cost competitiveness.



63

Table 7-3 and Figure 7-4 sets out outlooks of the Eastern Australia LNG supply capacity

under a Base, Low and High case as used in the modelling for this study.

Table 7-3 Eastern Australia LNG supply capability and number of trains

Case Forecast Eastern States LNG trains 2016 2020 2023

Low Capacity (PJ/year)

Number of Trains

1,518

6

1,518

6

1,518

6

Medium Capacity (PJ/year)

Number of Trains

1,518

6

2,028

8

2,028

8

High Capacity (PJ/year)

Number of Trains

1,518

6

2,523

10

2,997

12

Figure 7-4 Eastern Australia LNG gas requirements – PJ



64

8 Overview of gas contracting

This chapter discusses the traditional gas contracting context and additional factors that

will influence the price of domestic market long term gas supply contracts moving

forward. The key factors identified include the level of supply competition, supply costs

and the opportunity cost associated with LNG gas exports.

This chapter discusses the two methods for setting price based on either production

costs or LNG netback pricing. The principles of LNG netback pricing are introduced and

netback price as a function of oil price is presented with example ranges provided. This

chapter also refers to recent long-term contracts with price ranges relative to LNG

netback pricing.

Natural gas prices in Eastern Australia have been insulated from changes in

international energy prices due to abundant gas reserves committed solely to the

domestic market. These reserves had low price economics, supported by associated

liquids with no physical linkage to international markets. Traditional GSA’s were

characterised by:

Gas markets that did not have a highly competitive structure10

;

A gas market with all gas sales under long-term contracts between few

suppliers and a limited number of large purchasers;

Few spot transactions and a completely non-liquid short-term market where

price has little relevance to setting contract prices;

Gas prices negotiated between the buyers and sellers were based on

production costs (cost-plus) historically been in the range of $3-$4/GJ; and

Gas had to compete with low cost thermal coal in the power generation and

large industry sectors where the thermal coal sector was also domestically

orientated.

The advent of LNG export industry will connect domestic gas prices to internationally

traded LNG. The influence of such a dynamic was felt by the gas market in Western

Australia where gas prices ex-field moved from about $2.5/GJ to more than $6.0/GJ

over a very short period of time. However, it is recognised that there are a number of

factors that have influenced WA gas prices. These include the long term contractual

nature and low liquidity of the WA market due to relatively few gas suppliers, as well as

the concentrated and lumpy nature of demand due to a small number of very large

customers. The WA system is discussed in Section 13.

10 A perfectly competitive market is characterised by an infinite number of suppliers, homogeneous product, costless entry and exist and perfect information to all parties.



65

In the Eastern Australia gas market, discussions with industry participants and press

announcements from suppliers have confirmed the price formation process is currently

moving from a cost-plus basis towards export opportunity value, or LNG netback pricing.

LNG netback pricing is based on the price of LNG sold ex-Gladstone less the costs

associated with liquefaction and transportation. These price formations provide an

indication of the price bounds Eastern Australia is about/currently experiencing.

8.1 Domestic prices based on production costs

Under market conditions where the level of LNG exports is fixed with no expected

increase, and sufficient reserves have been developed and set-aside for that purpose,

additional domestic sales would not be expected to be impacted by LNG export sales.

Under these conditions, the LNG sector would be effectively ring-fenced from the

domestic market and domestic prices would be formed on the basis of cost and the level

of competition. The presence of the LNG industry would only influence prices to the

extent that it results in users being forced to purchase gas from further up the supply

cost curve, and hence are exposed to higher prices than they would otherwise be.

However, supply costs over recent years have also risen quicker than historical real price

increases. The arguments put forward to justify increased gas prices include:

Recovery of increased costs of exploration and drilling;

Appraisal and development under a far more complex regulatory system;

The general increase in overall costs of development of conventional gas fields;

The greatly increased requirements associated with the handling; and

Processing of CSG water and the much higher costs associated with the

recovery of unconventional or tight gas much of which is characterized with

having high CO2 contents.

Unconventional gas is generally more expensive to extract than conventional gas

because of the need for more complex drilling (the need for close infield and surface to

inseam drilling) and extensive fraccing. As discussed in Section 5, new technological

developments enabling tight gas to be recovered have resulted in increased gas

reserves and significant growth in gas resources. For example, over the last two years

there has been an increase in gas reserves in the Cooper Basin following some 20 years

of depletion where gas production has exceeded net additions to reserves. However,

these additional reserves have seen an increasing cost of extraction, frequently without

liquid credits, from $3-4/GJ to approximately $5-6/GJ, with some sources arguing costs

above $6/GJ. The argument is that, due to higher production costs, the world scale

unconventional gas resource in Eastern Australia cannot be developed without a

significant and sustained increase in gas prices.



66

8.2 Domestic prices based on international prices

Under market conditions where LNG proponents are developing reserves to support an

increasing level of LNG exports, additional domestic sales (accompanied by the

allocation of reserves to support long-term contracts) would impact the investment

timing of an LNG export facility or the ability to enter into long-term LNG supply

contracts. Under such conditions, all gas would have been considered to have an LNG

export opportunity cost and there would likely be a close link between domestic prices

and LNG netback prices.

In the event of the LNG developers being unsure of the economics and likelihood of

additional LNG export trains, they may pursue a medium-term strategy of stockpiling

reserves pending a future decision on LNG. This could be described as domestic prices

being loosely internationally linked. The determinants of LNG netback prices are

discussed below.

8.3 LNG netback pricing

Netback price (to the ex-field location) is determined as the LNG Free On Board (FOB)

export price less the costs of liquefaction and transportation. These prices and costs are

presented below.

8.3.1 Relationship between gas prices and oil prices

The LNG export price has traditionally moved in tandem with oil prices as LNG contracts

have contained oil-linked pricing clauses. While the formal foundation for this form of

price linkage – the inter-fuel competition of gas with oil in power generation – has

eroded in most LNG import markets, the oil price linkage remains.

In the United Kingdom and the United States, contracts linking LNG prices to the price of

other energy commodities, such as the Henry Hub price, have emerged. However, these

contracts show some significant disadvantages to the traditional contracts linked to oil

prices. For example, linking the LNG price to the Henry Hub links it to the same gas

market the LNG is delivered to. This means the buyer can always resell the LNG cargo in

the local market and the seller assumes all the risk in the contract.

In Japan and much of Asia, LNG prices remain linked to the oil price (in Japan’s case -

‘Japanese Customs-cleared Crude’). Unlike the European and American markets, the

Asian markets lack alternative gas supplies, domestic output or interconnecting

pipelines. In order for this linkage to be broken, a liquid regional gas trade would have

to be established. Given Japan’s geographical position, the establishment of pipelines

linking the Japanese market to other Asian market seems unlikely.

In our modelling we have assumed the linkage of LNG prices to the oil price will remain

the basis for long-term LNG contracts in the Asia-Pacific region. Our assumptions about

oil prices and the AUD/USD exchange rate are largely responsible for determining the



67

LNG netback price. Our assumptions about these two macroeconomic variables are

included in the following section.

8.3.2 LNG export prices

In Asia, term contract LNG is priced according to a formula, usually indexed to oil.

Normally, such a price formula will appear as P = a x JCC + b

Where:

P = the price of the LNG, usually expressed as USD per MMBtu;

JCC = the price expressed as USD per bbl of a basket of crude oil imported into

Japan. (Note, while JCC is the predominant index, others have been used,

including Indonesian crude exports and Brent crude);

a = represents the linkage to crude oil, and expressed as a decimal (where the

price of LNG is expressed as USD per MMBtu; and

b = is a constant, usually expressed in USD per MMBtu, and may reflect some

minimum cost recovery requirements and/or shipping cost considerations

(where a sale is on a delivered basis).

Other features of Asian contract pricing sometimes include an ‘S-Curve’ mechanism,

which introduces a lower ‘a’ value to apply when crude prices are in a low or high

range, protecting sellers at low crude oil prices, and buyers at high crude oil prices ( ‘kink

points’) or ceiling or floor constraints usually linked to crude oil prices.

New term contracts to Asian buyers over the last several years have displayed the

following elements within the traditional formula:

Values for Slope in the range 0.12 to 0.154;

Values for “b” reflecting shipping costs for delivered sales or c lose to zero for

FOB sales; and

Increasing adoption of “S-Curves” (but not in all cases).

In summary the format of the current formulae will be retained including linkage to JCC

or Brent oil prices. The value of the Slope is likely to stay within a range of 0.12 to 0.15

due to supply-demand dynamics. This is put into context below assuming FOB and no

‘S’ curve (noting one MMBtu equals 1.055 GJ):

0.12 equates to approximately $US 9.8/MMBtu at USD 90/bbl crude and $US

16.8/MMBtu at USD 140/bbl crude; and

0.15 equates to approximately $US 13.5/MMBtu at USD 90/bbl crude and $US

21/MMBtu at USD 140/bbl crude.

Appendix G describes the contract pricing structures for LNG transactions in

Europe and the USA.



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8.3.3 LNG processing costs

The costs of liquefaction and transportation can vary depending on many factors such as

plant size, economies of scale, location and exchange rate. We have assumed, for a

generic Gladstone LNG project, a combined cost for liquefaction and transportation of

$6/GJ.

Based on a slope factor of 0.12 to 0.15 (including the MMBtu to GJ conversion) the

resulting range of LNG netback prices is shown in Figure 8-1.

Figure 8-1 LNG netback price as function of JCC - $/GJ

8.4 Recent gas pricing points

The influence of the LNG joint ventures in the upstream sector in Eastern Australian gas

industry is reflected in the significant price increases in the contracting of gas over the

past 3 years, where they have risen from approximately $3-4/GJ to between $6-8/GJ for

new contracts based ex-major gas supply hubs such as Moomba, Longford and

Wallumbilla.

New contracts based on these higher gas prices are being locked in due to the

concentration of gas reserves and gas processing infrastructure with a few major gas

suppliers, many of which are major participants in the QLD LNG projects. The

concentration of gas reserve ownership and the lack of any real liquidity in the market,

coinciding with contract roll-offs, have resulted in major gas users having little market

bargaining leverage.

Recently reported gas contract prices (analyst, press quotes and as estimated by

IES/RLMS) include:

$7.25/GJ - Santos supply to AGL/APA for the 242 MW Carpentaria Power

Station at Mount Isa;



69

$7.00/GJ - Recent AGL and STO arbitration relating to a long-term supply

contract;

$7.00/GJ – Beach Energy supply of 138 PJ over 8 years to Origin Energy;

$7.00/GJ – Esso/BHP sales ex-Longford to Lumo Energy. The agreement is for

22 PJ of gas over three years starting in 2015;

The CEO of Adelaide Brighton recently stated that he was hopeful he could

negotiate prices at A$7- 7.5/GJ, a similar level to that which Santos is believed

to be supplying gas to GLNG in its 2010 deal;

The 2010 Santos deal with GLNG for delivery of 750 PJ is oil-linked and is

believed to be settled around $7-8/GJ;

Origin Energy purchased up to 432 PJ from Esso/BHP via Longford starting in

2014. Annual contract volumes will increase over the 9 year period with

delivery points at both Sydney and Longford. Price indexation initially reflects

current pricing arrangements in the market and transitions to an oil-linked

price;

Nexus has re-contracted with Santos to supply 83 PJ over 5.5 years from

Longtom. Some industry reports say the gas price is about $7.50/GJ with Santos

taking the condensate credits;

Origin Energy’s recent deal with Beach Energy for gas from the Cooper Basin is

rumoured to be higher still, closer to $8-9/GJ and is oil-linked. We believe this

gas may be destined for the domestic market in an attempt to set a new

benchmark; and

Industry sources indicate the price levels are generally in line with actuals.

All these data points (and discussions with market participants) support the trend of

new contract prices moving towards international price linkages as a result of the LNG

export story. As gas prices move higher this will result in price signals for increases in

gas reserves.



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9 Spot gas market

This chapter briefly discusses the spot markets covering eastern Australia, general price

trends and their significance in a long-term gas contracting context.

9.1 Victorian Declared Wholesale Gas Market

The Declared Wholesale Gas Market (DWGM) is the spot gas market operating in

Victoria and accounts for approximately 10-20% of all gas traded in that state (net

market). Almost all gas consumed in Victoria is transported by the Declared

Transmission System (DTS) spanning from Longford in the east to the Iona gas plant in

the west and Culcairn in NSW. The DTS moves approximately 220 PJ each year with gas

primarily sourced from the Gippsland basin at Longford.

Figure 9-1 Map of the declared transmission system (AEMO)

9.1.1 General demand and price trends

The VIC market has seen a gradual ramp up of spot prices from an average $3/GJ during

the drought period, $2/GJ through 2009 and 2010 in subdued conditions, to a sustained

$4/GJ and trending upwards. IES attribute this to increasing cost of production and to

some extent the start of a shift away from cost-plus pricing to one reflective of LNG

netback. We understand most producers are unwilling to sign new long-term contracts



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or agree to prices below $6/GJ for any significant duration. Given the numerous reports

on this issue, as discussed previously, the trend is likely to continue as old contracts

expire over the next few years, which will spill into the VIC spot market pricing and offer

stacks.

Figure 9-2 VIC spot 30-day rolling average prices (MIBB)

9.2 Short-Term Trading Market

The Short Term Trading Market (STTM) was set up to allow gas trades at the wholesale

level, promoting price transparency and increasing security of supply covering all of the

major hubs and pipelines on the East Coast. The market is based on day-ahead

schedules using bids and offers submitted by pipeline operators and shippers.

Figure 9-3 STTM 30-day rolling average prices in SYD, ADE & BRI - $/GJ (GBB)

Prices at Sydney (Figure 9-3) show a gradual increase from $3/GJ in 2011 to $4-$5/GJ to

what we are seeing currently. These levels roughly represent a $4/GJ gas price ex-

Longford (EGP firm transport is approximately $1.2/GJ into Sydney) and is consistent



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with the upward trend in the DWGM, which is also supplied by the Gippsland basin. As

mentioned above, this increase reflects the increasing supply costs and a move towards

LNG netback pricing (ESSO/BHP can potentially access these levels by way of a physical

gas swap) and contracts coming rolling off (current AGL contracts expire by 2016/2017).

AGL’s submission to IPART for the most recent gas price determinations in NSW indicate

a wholesale cost of $8/GJ into Sydney (excluding distribution) for FY2014, with

uncertainty thereafter. IES expect this to be the case with high gas prices flowing

through to the domestic markets even with delays in LNG development.

Prices at the Queensland hub are consistent with the VIC and NSW except price levels

are $1-$2/GJ higher. This is expected given the hub’s proximity to LNG developments

and direct competition with these facilities, giving producers a stronger case for higher

gas prices at this node. IES do not expect the price trajectory to subside.

Prices in Adelaide have been generally within $1/GJ of Sydney. The Moomba to Adelaide

Pipeline System is still significant given its share of supply to Adelaide and its traditional

pricing signals from Moomba for other hubs along the East Coast. Over the past 12

months we have seen STTM prices at Adelaide moving towards $4/GJ.

9.3 Relevance to long-term contracting arrangements

The short-term trading markets are generally there to allow participants to trade around

existing portfolio imbalances on a day-by-day basis and the volumes that go through

may give an indication of existing contract prices at those nodes. From the charts above

it is clear there is an upward trend in spot gas prices however these spot markets do not

drive long-term pricing and therefore too much importance should not be placed on

spot market outcomes.

On a forward basis regarding the LNG export story, global macroeconomic factors and

the domestic supply situation are expected to drive long-term contract prices with

pricing to flow through to the spot markets on a lagged basis.

Also worth noting is that prices are based entirely on the delivered commodity whereas

long-term gas arrangements for any significant volume also include a premium for

flexibility in the contract in terms of Maximum Daily Quantity (MDQ), take-or-pay

restrictions and banking of gas clauses. As costs of extraction go up, IES expect the

premium for flexible contract terms to also go up corresponding to the increased costs

for storage and the preference for producers to sell flatter profiles. Contract terms,

frequency of market reviews and the pricing mechanism (traditionally CPI adjusted

production cost, or the trend towards LNG netback) are also a major factor in

determining the contract price.



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10 Modelling the eastern Australia gas market

This chapter presents an overview of the modelling approach.

The model uses 6 market scenarios that consider domestic demand, domestic supply,

infrastructure capacity, LNG export timing, CSG reserves and international LNG demand.

The aim of the modelling is to provide an indication of east coast gas demand and

supply for 2013 to 2023, indicative pricing levels, and to highlight any potential reserve

shortfalls and infrastructure constraints.

Economic modelling of the Eastern Australian gas market was undertaken using the IES

Integrated Gas and Electricity Model (IGEM). The IGEM uses the TIMES framework (see

Appendix C ). The model assumes a perfectly competitive market and no stockpiling of

reserves for LNG projects.

The model includes new pipelines, new basin development, gas usage for electricity

generation, and the resulting economic costs of gas supply at the various locations in

the market. The key inputs are reserves by gas type and geological basin, maximum

production rates by geological basin, cost of gas production by gas type, pipeline limits

and tariffs, average domestic gas demand (mass-market and industrial), LNG demand,

new pipeline and basin developments, and assumed LNG netback prices. See Appendix

C for further information.

The model is based on a least-cost approach that optimises outcomes over the entire

study period. The gas market is solved annually for supply and demand for cost of

production and LNG net back price runs, and a daily maximum daily quantity run. The

model outputs are:

Gas prices by major nodes across the Eastern seaboard based Production Cost

and LNG Netback at the Moomba and Wallumbilla hubs;

Gas demand by state including LNG and GPG;

Gas supply by basin, split by reserve type (2P/3P/Contingent and Prospective);

and

Potential shortfalls/constraints.

10.1 Overview of modelling approach

The map below is a graphical representation of the modelled systems (Figure 10-1). It

includes all the major geological basins (beige polygons), major gas transmission

pipelines (solid lines), proposed major gas transmission pipelines (dashed lines) and

supply-demand hubs (blue circles).



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The model is set up as follows:

Geological basins, reserves/resources and types of gas (conventional and CSG)

are modelled separately;

LNG gas demands are aggregated at the Gladstone hub and connect directly to

the Bowen-Surat basins. Production capacity is assumed to increase with

commissioning schedules;

Bilateral contracting details are not considered;

Gas storage, line-pack and other nuances of the gas market is not modelled as

the market is modelled on an annual basis;

Price elasticity of demand is not considered;

CSG reserve development as per the assumptions provided in Section 0 relating

to conversion efficiency and lead times; and

GPG gas costs are assumed to be flat for the first 3 years, representing fixed

long-term gas contracts, and then gradually roll-off over a 3 year period,

exposing GPG to the modelled gas prices.

Figure 10-1 Representation of the modelled gas system

Cooper-Eromanga



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10.2 Price outcome modelling

Prices from the IGEM, which are based on a least-cost modelling approach, reflect the

cost of production and transportation to the various nodes.

The least-cost modelling approach assumes a perfectly competitive market and by

default does not take into account the market power of participants.

As mentioned previously, there are two possible price outcomes that are representative

of a lower and upper bound for potential price outcomes:

Prices going forward can be expected to be determined by the cost of supply

across all nodes representing basic Production Cost principles in a perfectly

competitive environment; or

Prices can reflect the opportunity cost of selling gas into the international LNG

market, which commands higher prices dependant on global macroeconomic

factors. This is called LNG Netback pricing.

This modelling attempts to model both price trajectories to provide a context of price

ranges, rather than specific price points. The results from this price modelling exercise

will not accurately reflect contract prices (whether current or future and certainly not

historical) as long-term contract prices are not transparent and are affected by the

myriad of variables embedded in GSA’s (term, volume, flexibility, frequency of resets

etc.). The ranges are only to provide an indication under the modelled scenarios.

10.3 Specific model runs

IES have run the model three times based on: Production Costs, LNG Netback prices,

and Maximum Daily Demand. The rationale for the three separate runs follows.

10.3.1 Production cost

This run of the model uses RLMS costs of production specified at each basin for

conventional gas and CSG across the different categories of reserves and resources (2P,

3P, contingent and prospective), see Appendix D for basin costs. Model results relate to

a perfectly competitive market where gas is sold ex-field at exactly the cost to extract

and transport that unit of gas to the demand hub. This essentially provides a lower

bound for gas prices across the east coast based on Production Costs (proxy for the cost

of gas commodity as per a traditional GSA with no flex). Prices are modelled at each

demand hub.

10.3.2 LNG netback

In this run of the model the Cooper-Eromanga and Bowen-Surat basins supply costs for

all reserve categories and gas types are replaced with the international LNG netback

price minus the cost of transport to the Gladstone export terminal.



76

The rationale behind this run is to assess how market power may be exercised at these

nodes. This market power results from a small number of sellers in the domestic market

who have complete control over pricing and can set prices at international LNG netback

prices. This situation is assumed to impact the rest of the Eastern Australian gas market

(Sydney, Adelaide and Melbourne).

Although there is potential for market power at the Gippsland basin, IES have elected

not to replace the cost of production at Gippsland basin with an LNG netback price, to

assess how higher QLD prices would flow through to VIC under the assumption of

perfectly competitive markets elsewhere. The simplification of market power dynamics

can provide useful information on how the LNG Netback pricing effect cascades through

the Eastern Australian gas system.

10.3.3 Maximum demand (mass-market and industrial)

This run of the model uses forecast maximum daily gas mass market, industrial and GPG

demand at each node to test for potential pipeline and gas processing infrastructure

bottlenecks in the system.

Maximum demands were estimated by:

Modelling coincident maximum demands across all regions. This presents a

conservative scenario as normally when maximum demand occurs in Victoria

(largest maximum demand) other regions are at 75-85% of their maximum

demand; and

GPG demands are based on high generation days on a power station basis.

The maximum demand run should highlight potential constraints in the system as a

result of demand growth and/or supply constraints related to the growth of LNG export.

The model is based on a single day and does not consider consecutive high demand

days. Price data from this run was not extracted given the point of the MD run is to

highlight volumetric constraints.

The model does not consider the options available to gas market participants

(optimising line pack, imbalances, over-runs, usage of storage etc.) when faced with

high gas demand conditions.



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10.4 Modelling scenarios

Six scenarios are modelled. These are summarised in Table 10-1 and described below.

Table 10-1 Summary of scenarios and key variables

Scenarios

Variables

LNG Export Timing

CSG Reserve Development

International LNG Netback Price

Domestic Demand

Domestic Supply

Infrastructure Development

Reference Case

Base Base Base Base Base Base

LNG Low

Low Base Low Base Base Base

LNG High

High High High Base Low Low

Low Supply

Base Low Base Low Low Low

High Growth

Base High Base High High High

High Infrastructure

Base High Base Base High High

10.4.1 Reference case

The scenario is the combination of assumptions and variables that are expected to most

likely occur. The reference case is based on 8 LNG trains by the end of the 10 year study

period.

10.4.2 LNG Low

Represents the scenario where international LNG demand has slowed down leading to a

decline in global LNG prices. Only 6 LNG trains come online in the study period and the

development of uncommitted LNG trains is delayed, including Arrow Energy’s proposal.

10.4.3 LNG High

The scenario represents higher LNG netback prices as a result of global macroeconomic

factors and brings forward commissioning of LNG trains to a total of 12 across 4 LNG

joint ventures during the study period. Additional investment in CSG reserve

development also increases reserve efficiency and conversion time. Domestic gas supply

and infrastructure development is delayed.

10.4.4 Low Supply

This scenario represents a slow-down of CSG reserve development, slowing domestic

gas demand and a delay in investment to bring additional gas fields and associated

pipeline infrastructure online.



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10.4.5 High Growth

This scenario represents the opposite of the Low Supply scenario, whereby the domestic

economy experiences higher gas demand growth, facilitated by additional gas supply

and associated infrastructure being brought online in a timely manner. CSG reserve

development is also faster than the Reference case.

10.4.6 High Infrastructure

In this scenario additional gas fields, associated infrastructure, and CSG reserve

development has occurred earlier than the Reference case. All other demand variables

are as per the Reference case.

10.5 Key variables

A summary of the key variables is provided in Table 10-2. Additional detail is provided

below.

Table 10-2 Key variables for GMS modelling

Variable Base Low High LNG Timing 6 trains increasing to 8:

APLNG (3), QCLNG (2), GLNG (2), Arrow (1)

6 committed trains: APLNG (2), QCLNG (2), GLNG (2), Arrow (0)

6 trains increasing to 12: APLNG (3), QCLNG (3), GLNG (3), Arrow (3)

CSG Development

3P > 2P (60%, 3 years) Contingent > 2P (50%, 5 years) Prospective >2p (40%, 10 years)



LNG Netback Prices

2014: $11.0/GJ 2017: $9.8/GJ 2023: $11.4/GJ

2014: $11.5/GJ 2017: $7.4/GJ 2023: $10.0/GJ

2014: $11.4/GJ 2017: $10.9/GJ 2023: $12.8/GJ

Domestic Demand (MM, C&I)

479 PJ (2014) increasing to 542 PJ (2023), 1.4% growth pa



New Basin Development

Gunnedah: 2020 (100 TJ/d) Clarence-Moreton: 2021 (100 TJ/day) Gloucester: 2021 (90 TJ/day)

Gunnedah: n/a Clarence-Moreton: n/a Gloucester: n/a

Gunnedah: 2018 (100 TJ/d) Clarence-Moreton: 2020 (100 TJ/day) Gloucester: 2019 (90 TJ/day)

New Pipeline Development

QHGP: 2020 (230 TJ/day, Nar > Syd) QHGP exp: n/a CQGP: n/a NQGP: n/a Lions Way: 2021 (74 TJ/day)

QHGP: n/a QHGP exp: n/a CQGP: n/a NQGP: n/a Lions Way: n/a

QHGP: 2018 (230 TJ/day, Nar > Syd) QHGP exp: 2021 (230 TJ/day, Nar > Wal) CQGP: 2019 (100 TJ/day) NQGP: 2018 (100 TJ/day) Lions Way: 2020 (74 TJ/day)

10.5.1 LNG train timing

The determinants of LNG economics are primarily the macroeconomic factors that

describe the various scenarios. The main issues concerning future LNG development are

the uncertainty in global LNG demand, the response by LNG proponents in terms of



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developments in Australia and worldwide, and LNG export prices as influenced by

international oil prices.

Commissioning dates of LNG trains within the study period for the Base, Low and High

schedules are outlined in Table 10-3 to Table 10-5 with dates in bold representing

committed trains (Energy Quest, 2013). The ramping up of LNG gas demand (60% of

train capacity) is assumed to occur six months prior to the commissioning date.

Table 10-3 Base LNG train timing (8 trains by 2023)

LNG Proponent Gas per train PJ/year Train #1 Train #2 Train #3 Train #4

QCLNG 255.0 Jul-14 Jul-15 - -

APLNG 270.0 Jul-15 Jan-16 Jul-18 -

Arrow Energy 240.0 Jan-20 - - -

GLNG 234.0 Mar-15 Dec-15 - -

IES believe 8 trains to be on the high side over the next 10 years as current efforts have

focused on developing existing reserves rather than investment into exploration

programs. The increasing gas supply costs and the domestic gas cost pressures

combined with the uncertainty of the global LNG outlook over this period also support

this case. However, to ensure the scenarios cover a wide spectrum, the Base LNG train

timetable is based on eight LNG trains, and the Low schedule is based on six LNG trains

with timing consistent with the currently committed LNG trains, and the High LNG train

schedule is based on 13 LNG trains.

Table 10-4 Low LNG train timing (6 trains by 2023)


QCLNG 255.0 Jul-14 Jul-15 - -

APLNG 270.0 Jul-15 Jan-16 - -

Arrow Energy 240.0 - - - -

GLNG 234.0 Mar-15 Dec-15 - -

Table 10-5 High LNG train timing (13 trains by 2023)


QCLNG 255.0 Jul-14 Jul-15 Jan-20 -

APLNG 270.0 Jul-15 Jan-16 Dec-19 Dec-23

Arrow Energy 240.0 Jan-18 Jan-19 Dec-22 Dec-24

GLNG 234.0 Mar-15 Dec-15 Dec-20 -



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10.5.2 CSG reserve development

An assessment was made of the expected and potential variation in the rates at which

2P CSG reserves will be developed based on RLMS’s experience. Two definitions are

introduced here in order to consider both the quantity and time rate of reserve

conversion:

Conversion efficiency: The proportion of a higher classification of reserves and

resources (e.g. 2C resources) that will realise certifiable 2P reserves and

production; and

Conversion time: The time taken for higher classification reserves and

resources to be fully converted to certifiable 2P reserves and production.

The possible impact of weather has been taken into account in the estimated time taken

for the conversions to occur. In this study it is assumed that expected weather

conditions result in a conversion period of five years for 2C resources to 2P reserves.

More advantageous or disadvantageous weather conditions result in the conversion

period being shortened or lengthened by one year respectively.

Table 10-6 Efficiency of conversion factors

Development Rates Efficiency

From To Low Base High

2P Production 70% 80% 90%

3P 2P 40% 60% 80%

2C 2P 60% 80% 95%

Prospective 2P 30% 40% 50%

Table 10-7 Conversion time assumptions

Development Rates Conversion (years)

From To Low Base High

2P Production 0 0 0

3P 2P 4 3 2

2C 2P 6 5 4

Prospective 2P 12 10 8

Factors which influence conversion efficiency and conversion time include well

productivity and drilling rates as they impact the rate at which wells are developed.11

Below target performance in either drilling rates or well productivity could impact the

11 In defining “drilling rate” we exclude gas treatment facilities, compressor and gathering systems as they have separate schedules and are impacted differently by external events such as flooding.



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ability of LNG proponents to reach their FID and gas suppliers to provide long-term

contracts to users.

10.5.3 International LNG netback prices

International LNG prices are assumed to be based on the ‘S’-curve structure as follows:

LNG pricing structure: Price = a x JCC + b + 'S - Curve'

Where

a = Slope (generally in range between 0.1 and 0.15), this factor reflects the

energy content of gas against energy a barrel of oil (roughly 1/6) and

demand for LNG. Our slope assumptions include the MMBtu to GJ

conversion;

JCC = Index representing the average monthly price of a basket of various crude

oils imported into Japan;

b = Constant which may reflect minimum cost requirements and/or shipping

considerations (for delivered basis). We assume it to be 0 here; and

'S' Curve = Triggers at high/low JCC levels to minimise the slope coefficient (assumed

to be USD$125 and USD$85 per bbl and a slope offset of 0.1).

Figure 10-2 charts the LNG netback price trajectory assuming a forward AUD/USD long-

term exchange rate of 0.9USD/AUD and a $6/GJ cost of liquefaction and transport. The

netback prices here provide the model at Gladstone and Moomba (minus transport)

with an opportunity cost or what would be deemed the upper bound for forecast gas

prices for the rest of the domestic economy.

Figure 10-2 LNG netback prices (at Gladstone, $/GJ)



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The LNG netback price trajectory is also linked to the oil price, which is assumed to be

on average 0.14 (across the LNG proponents) based on estimates of LNG sales contracts.

Indicative ranges for the slope include12

:

Kansai Electric with APLNG: 0.1425-0.1450

Sinopec with APLNG: 0.1385-0.1400

CNOOC with QCLNG: 0.1450-0.1500

The level and shape of the overall LNG netback price trajectory are highly dependent on

the underlying oil price as seen in Figure 10-3. Base prices are from Barclays Capital

Commodities Research13

and high and low prices are IES estimates.

Figure 10-3 JCC price forecasts - $US/bbl (Base price from Barcap, Sep 2013)

10.5.4 Domestic demand (mass-market and industrial)

Domestic demand here refers specifically to the mass-market and industrial sector and

excludes GPG. Domestic gas demand is based on AEMO’s 2012 Gas Statement of

Opportunities where the base case reflects the Planning scenario, and the low case

reflects the Slow Rate of Change scenario. As no equivalent High case demands were

provided in AEMO’s 2012 Gas Statement of Opportunities, IES derived the High case

demands by applying the percentage difference between the Base and Low cases to the

Base case.

12 Australian Coal Seam Gas 2013: All Aboard the LNG Train, Energy Quest 13

Commodities: on the growth borderline, Barclays Capital, Sep 2013



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Table 10-8 Base demands - PJ (GSOO, Gladstone adjusted)

Year SA VIC TAS NSW/ACT QLD

2014 35.37 198.67 5.08 104.01 135.51

2015 35.62 197.94 5.20 104.08 137.57

2016 35.79 197.97 5.32 105.80 139.50

2017 36.19 199.13 5.45 108.16 148.67

2018 36.73 200.94 5.58 110.62 151.14

2019 37.36 202.95 5.72 112.38 160.68

2020 37.98 205.08 5.88 113.82 163.85

2021 38.51 206.94 6.04 115.22 166.73

2022 38.94 208.16 6.20 116.15 169.41

2023 39.20 208.96 6.32 116.37 171.88

2024 39.36 209.89 6.40 116.11 174.70

Demands are modelled at the nodal level but have been summarised in Table 10-8 to

Table 10-10, with QLD demand referring to Mt Isa, Townsville, Brisbane and Gladstone

hubs. Demands at the Gladstone hub were adjusted in accordance with RLMS’s

understanding of major industrial loads increases at QAL and Yarwun (2014 loads

adjusted to 45 PJ from 60 PJ in the GSOO, with 8.5 PJ increases in 2017 and 2019) with

demand initially decreasing at the Gladstone hub and subsequently increasing over

time.

Table 10-9 Low demands - PJ (GSOO, Gladstone adjusted)


2014 34.85 197.68 4.73 102.91 134.00

2015 34.97 196.54 4.85 102.60 135.00

2016 35.00 196.53 4.98 103.96 135.89

2017 35.20 198.05 5.10 105.98 144.80

2018 35.59 200.28 5.21 108.13 146.18

2019 36.04 202.30 5.33 109.52 155.48

2020 36.48 204.11 5.47 110.63 156.94

2021 36.83 205.48 5.62 111.74 158.01

2022 37.07 206.25 5.77 112.35 158.86

2023 37.15 206.66 5.87 112.20 159.87

2024 37.13 207.19 5.94 111.57 161.20



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Table 10-10 High demands - PJ (calculated by IES)


2014 35.90 199.67 5.45 105.12 137.03

2015 36.28 199.36 5.57 105.58 140.20

2016 36.61 199.43 5.69 107.67 143.24

2017 37.21 200.23 5.83 110.38 152.65

2018 37.92 201.61 5.98 113.17 156.31

2019 38.74 203.60 6.15 115.31 166.08

2020 39.54 206.07 6.32 117.10 171.13

2021 40.27 208.41 6.49 118.80 176.05

2022 40.90 210.08 6.66 120.09 180.84

2023 41.37 211.29 6.80 120.71 185.04

2024 41.72 212.61 6.90 120.84 189.65

10.5.5 Domestic supply

This variable relates to new field developments which may contribute towards the

domestic gas market supply. Dates provided are based on minimum lead times for CSG

development of four years and the current progress to date. Fields are brought online

in conjunction with pipeline infrastructure (see next section). Fields coming online

within the study horizon are shaded grey. New conventional gas field developments are

considered by the model by assuming that these come online as economic conditions

favour the development.

Table 10-11 Additional domestic supply sources (RLMS)

Source Type Base Low High Production (TJ/day)

Gunnedah CSG Jul-19 - Jan-18 100

Clarence Moreton CSG Jan-21 - Jul-19 100

Gloucester CSG Jul-20 - Jan-19 90

Galilee CSG - - - 50

The CSG resources in the Galilee Basin are assumed not to come online during the study

period as it is currently in very early stages of progress. Due to its isolation (i.e. lack of

infrastructure) and long lead times needed to confirm reserves and approve pipelines

and other developments.

10.5.6 Infrastructure development

Infrastructure development assumptions are based on RLMS understanding of the

current project progress along with required lead times and actual requirement in the

market to meet demand.



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Table 10-12 Future pipeline commissioning date assumptions

Gas Pipeline Base Low High Capacity ( TJ/day) Tariff $/GJ

QLD Hunter Jul-19 - Jan-18 230 1.5

QLD Hunter (Expansion) - - Jul-20 230 1.5

Central Queensland - - Jul-18 100 0.7

NQP Upgrade - - Jul-17 100 1.42

Lions Way Jan-21 - Jul-19 74 0.5

SWP Jan-15 Jan-15 Jan-15 429 0.27

SWQP Jul-15 Jul-15 Jul-15 700 1.04

SWQPR Jul-14 Jul-14 Jul-14 330/600 1.04

Queensland Gas Pipeline Jul-16 Jul-16 Jul-16 213, + 0.87

Stratford to Hexham Pipeline Jul-20 - Jan-19 100 0.35

Galilee Basin - - - 50 0.7

QLD Hunter – Connects the Gunnedah basin to Sydney via Newcastle. The QLD Hunter

expansion connects the Gunnedah basin to Wallumbilla (High case).

Central Queensland – Connects Moranbah to Gladstone in the High case. This pipeline

is dependent on Arrow Energy’s position.

Lions Way - Assumed to come online when the gas resources in the Clarence-Moreton

Basin are developed and connects to Brisbane.

Stratford to Hexham Pipeline- Is developed with the gas resources in the Gloucester

Basin and connects to Sydney.

NQP Upgrade - Moranbah to Townsville line upgraded to reflect higher loads in the area

(High case).

SWP Upgrade - from Iona to Melbourne (additional compressor, Taurus 60).

SWQP Upgrade - South West Queensland compression upgrade.

SWQPR Upgrade - Bi-directional pipeline (upgrade in 2015 to 600 TJ/day).

QGP Upgrade – this is assumed to be upgraded with increased demand at the Gladstone

hub (from 2017).

Galilee Basin pipeline- assumed not to be developed in the study period.



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10.6 Modelling assumptions overview

For a comprehensive list of assumptions used in the GMS modelling component please

see Appendix D . The below is a quick overview of the other inputs used in the

modelling process:

Maximum production rates from each basin;

Reserves and resources by basin (2P, 3P, 2C and prospective) and gas type;

Production costs (and LNG Netback prices) by basin and gas type;

Existing gas pipeline capacity and tariffs;

New pipeline and CSG developments; and

Gas demands (LNG and domestic demand excluding GPG).



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11 Gas Market Study modelling results

In order to understand the likely contract gas prices, available duration and overall

supply we must not only focus on physical supply and demand, we have to make an

assessment of the likely strategies of the more influential incumbent’s abilities to

exercise portfolio optimisation through to market power. Consideration for individual

company portfolios and behaviours are not part of the project scope however the

modelling can still be used to formulate a starting view which will help explain what is

likely to happen in the contract market and in turn the pricing available to the domestic

market.

The least cost modelling is a very useful base from which to build a picture of overall

market dynamics, rather than absolute price outcome. It provides a lower bound

(production cost) in order to get gas to market as gas extraction gets tighter and

legitimately more expensive to extract. The shadow prices at major price hubs become

very useful when trying to understand how the LNG price ex-Gladstone will cascade

back through the east coast system accounting for constraints, location and capacity

charges.

This section presents the modelling results for six scenarios, representing a range of

outcomes that may prevail over the study period of finance years 2013/13 to 2022/23.

Results are given for both the Production Cost and LNG Netback runs, representing

lower and upper bounds respectively, of gas prices.

The results for the Reference scenario are discussed, and then the other scenarios are

discussed with respect to the Reference scenario. Results from the Maximum Demand

are then discussed in terms of potential infrastructure bottlenecks.

In the following discussion and figures:

The year 2014 refers to financial year 2013/14.

Volume and flow results are from the LNG Netback run unless otherwise stated,

as these represent the upper bounds of gas prices.

For the price charts, firm lines represent the LNG Netback run. Dotted lines

represent the Production Cost run.

The LNG Netback run is meant to reflect a more realistic market scenario with costs at

the Cooper-Eromanga and Bowen-Surat basins linked to the LNG netback price. The

LNG Netback run attempts to represent the market power that gas producers have at

Wallumbilla and Moomba and to model flow-on price effects throughout the rest of the

eastern Australian gas market.



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11.1 Summary of results

For all six demand scenarios there sufficient 2P reserves across most basins

over the 10 year study period to meet east coast domestic and LNG demand.

There are only 2 basins which run out of 2P reserves during the modelling

period - these are Otway and Bass basins in 2021 and 2022, however both

these basins continue to produce gas from 2C reserves assumed in model.

In all scenarios, the large majority of production comes from CSG in the Bowen-

Surat basins in Queensland, with remaining production coming mostly from the

Gippsland basin in Victoria and the Cooper-Eromanga basins in South Australia.

11.2 Reference scenario

Figure 11-1 and Figure 11-2 chart the projects prices from the Production Cost and LNG

Netback run across Sydney, Adelaide, Melbourne and Brisbane respectively. The gas

prices represent the marginal cost of gas at each node.

Figure 11-1 Reference scenario – $/GJ (Production Cost run)

Over the ten years of the study period, gas prices from the Production Cost run

(Figure 11-1) are projected to rise steadily with no major price fluctuations at the

Brisbane, Melbourne and Adelaide hubs.

The largest overall price increase during the study period is at the Melbourne hub

(5.8 %; $0.32/GJ) with the smallest overall price increases experienced at the Brisbane

hub (3.3 %; $0.17/GJ). Only the gas prices at the Sydney hub are projected to decrease

over the entire study period (3.1 %; $0.17/GJ). The Sydney hub experiences a large drop

in gas prices between 2019 and 2021 (5.3 %; $0.29/GJ from $5.66/GJ) and is attributed

to new gas production commencing from the Gunnedah and Gloucester basins.



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The difference in gas price between demand hubs is a maximum of $0.79/GJ between

Brisbane and Adelaide in 2023. Over the ten years of the study period, gas prices range

between $5.20/GJ in the Brisbane hub and $6.15/GJ in the Adelaide hub. The range of

gas prices between the Brisbane hub (lowest), Sydney hub, Melbourne hub and

Adelaide hub (highest) is due to production and transportation costs from the different

gas-producing basins.

The Sydney hub experiences relatively lower gas prices compared to the Adelaide and

the Melbourne hubs due to the new gas supply from the Gloucester and Gunnedah

basins in the later years.

Gas prices from the LNG Netback run (Figure 11-2) are generally reflective of LNG

Netback prices and commonly show significant price fluctuations. The Brisbane and

Adelaide hubs are highly reflective of LNG Netback prices with gas prices above $9/GJ

from 2016 onwards. The Adelaide hub experiences a slightly lower gas price compared

to the Brisbane hub due to lower transport tariffs from Moomba via the MAPS. The

large increase in gas prices noted in the Adelaide hub from 2015 to 2016 (56.3 %;

$3.22/GJ increase from $5.72/GJ) is a direct result of the increased cost to netback

pricing at the Cooper-Eromanga basins and a follow-on effect of the switch in gas flows

from Moomba towards GLNG for export.

This increased cost to netback pricing at the Cooper-Eromanga basins, due to the switch

in gas flows from Moomba, is also experienced at the Sydney hub with a large price

increase from 2015 to 2016 (25%; $1.34/GJ increase from $6.70/GJ). However, the gas

price at the Sydney hub is projected to experience a drop between 2019 and 2020 (7.6

%; $0.56/GJ decrease from $7.34/GJ) due to new gas production commencing from the

Gunnedah and Gloucester basins. In this run, the Sydney hub experiences relatively

lower gas prices compared to the Adelaide and Brisbane hubs due to a larger amount of

gas supply coming from Victoria and in later years the new gas supply from the

Gloucester and Gunnedah basins.

Only the gas price at the Melbourne hub is projected to experience a steady rise with no

major price fluctuations and is less reflective of LNG Netback prices. An overall price

increase at the Melbourne hub of 6.9 % ($0.39/GJ increase from $5.67/GJ) over the

study period is attributed to a steady gas supply from the Gippsland, Otway and Bass

basins as well as the physical constraints on transporting gas to Gladstone for LNG

export.

The model does not capture market power which producers in Victoria may use to

increase prices towards Adelaide prices.



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Figure 11-2 Reference scenario – $/GJ (LNG Netback run)

Table 11-1 shows the yearly gas price at each major domestic demand hub for both the

Production Cost and LNG Netback runs. The price difference between the two runs is

roughly $1.5/GJ in Sydney and up to $5/GJ in Brisbane. The small increase in gas price

at the Melbourne hub from the Production Cost run to the LNG Netback run shows the

small effect LNG Netback pricing has on Victoria. The price effect of LNG Netback

pricing is more readily experienced at the Sydney and Adelaide hubs.

Table 11-1 Reference scenario prices - $/GJ (Production Cost & LNG Netback run)

Sydney Adelaide Melbourne Brisbane

2014 5.54 / 5.39 5.90 / 5.75 5.54 / 5.67 5.18 / 10.89

2015 5.56 / 5.36 5.92 / 5.72 5.57 / 5.70 5.20 / 10.60

2016 5.58 / 6.70 5.94 / 8.94 5.60 / 5.74 5.21 / 9.51

2017 5.60 / 6.81 5.96 / 9.05 5.63 / 5.78 5.23 / 9.62

2018 5.63 / 7.46 5.99 / 9.70 5.66 / 5.82 5.25 / 10.33

2019 5.66 / 7.34 6.02 / 9.58 5.70 / 5.86 5.27 / 10.15

2020 5.45 / 6.78 6.05 / 10.39 5.73 / 5.91 5.29 / 10.96

2021 5.37 / 6.83 6.08 / 10.51 5.77 / 5.96 5.31 / 11.18

2022 5.37 / 6.88 6.11 / 10.63 5.81 / 6.01 5.33 / 11.29

2023 5.37 / 6.93 6.14 / 10.74 5.86 / 6.06 5.35 / 11.31

Figure 11-3 illustrates the gas supply mix for eastern Australia under the Reference

scenario for the LNG Netback run. By the end of the study period, the Reference

scenario has 8 LNG trains requiring approximately 2,200 PJ per year. The scale of the

LNG ramp up is by large relative to domestic gas demand of around 700 PJ per year .

The gas required for LNG trains is reflected in the ramp up of production out of the

Bowen/Surat basins from 217 PJ in 2014 growing to 2,25 PJ by 2023 (Figure 11-3).



91

Production out of all other geological basins remains relatively steady with some

fluctuations. For example, production out of the Gippsland Basin drops by 34 PJ in

2021 as a direct result of the new gas supply out of the Gloucester and Gunnedah basins

supplying NSW a total of 43 PJ by 2022 (approximately one third of total gas

requirements for NSW).

Figure 11-3 Reference scenario supply - PJ (LNG Netback run)

Figure 11-4 shows the total domestic demand by state (including GPG but excluding

LNG) over the study period for the LNG Netback run. The total domestic demand

decreases by almost 3 per cent over the study period with almost all states experiencing

a decrease in demand. Only Victoria experiences an increase in domestic demand of

6 PJ over the study period, which is attributed to assumed demand growth in the mass

market and industrial sectors more than offsetting the decrease in VIC GPG. The

decrease in total domestic demand is driven by reductions in GPG demand, which has

offset the small natural domestic gas demand (ex GPG) growth assumptions. SA

experiences the largest decline in demand of 18 PJ across the 10 year period as a result

of the high LNG Netback prices. The growth in non-GPG gas demand at Gladstone for

LNG export offsets most of the GPG demand losses in QLD.



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Figure 11-4 Reference scenario total demand excluding LNG* - PJ

* Volumes based on LNG Netback run

Figure 11-5 charts the impact of LNG Netback prices on GPG demand by state over the

study period for the Reference scenario. GPG gas volumes are roughly 190 PJ per year

between 2014 and 2016. After 2016, GPG gas volumes slowly decrease as a result of

higher gas prices eroding the competitiveness of GPG in the NEM. QLD and SA are

particularly affected given the higher gas prices and the larger amounts of base

load/intermediate GPG in these regions. As a result, GPG gas demand drops to 108 PJ

by the end of the study period. The relatively flat generation during the first 2 years of

the study period is due to the modelling assumption that contracts gradually roll-off.

In the Reference scenario current 2P CSG reserves and 3P conventional gas reserves are

sufficient to meet domestic and LNG gas demand over the study period. Given the short

study period (10 years) it is expected that most of the gas reserves will be sufficient to

meet demand (Cooper-Eromanga and Gippsland still contain 382 PJ and 1,430 PJ

respectively). The current 2P conventional gas reserves from the Otway and Bass basins

are depleted by 2021 and 2022 respectively. Gas production from the Otway and Bass

basins draw from 3P reserves and 2C resources from 2021 onwards.

New gas supply from the CSG reserves in the Gloucester and Gunnedah basins increases

the life-span of 2P conventional gas reserves in Victoria. The model assumes higher gas

prices lead to the development of previously sub economic resources in the Clarence-

Moreton basin by 2020.



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Figure 11-5 Reference scenario GPG demand - PJ (LNG Netback run)

The main findings from the Reference case are:

The modelling results show there is no shortage of gas during the study period.

Delays in the exploration and development of gas resources can affect the

timing of reserves becoming available to the market and ultimately the price of

gas.

Current 2P CSG reserves and 2P & 3P conventional gas reserves are sufficient to

meet domestic and LNG gas demands. The current 2P conventional gas

reserves from the Otway and Bass basins will be depleted by 2022 with gas

production from these basins subsequently drawing from 2C resources. New

gas supply from the CSG reserves in the Gloucester and Gunnedah basins

increases the life-span of 2P conventional gas reserves in Victoria.

The gas prices from the Production Cost run are projected to rise steadily with

no major price fluctuations because of the sufficient reserves to supply each

demand hub. The range of gas prices experienced at demand hubs are mainly

due to production and transportation costs from the different gas-producing

basins;

Gas prices from the LNG Netback run are generally reflective of LNG Netback

prices and commonly show major price fluctuations. Gas prices are highest at

Brisbane and Adelaide hubs averaging $10/GJ due to LNG Netback price

assumptions at Moomba and Wallumbilla, with prices at the Sydney hub $3/GJ

lower. The gas price at the Melbourne hub is roughly $5.5/GJ and shows only a

minor increase from the production cost run, indicating the small effect of LNG

Netback pricing;

The Sydney hub experiences relatively lower gas prices compared to other

demand hubs due to a larger amount of gas supply coming from cheaper gas-



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producing basins (Queensland in the Production Cost run or Victoria in the LNG

Netback run) and in later years the new supply from the Gloucester and

Gunnedah basins. Gas production from the Gunnedah and Gloucester basins

have a downward impact on gas prices at the Sydney hub;

The higher gas prices experienced in QLD and SA during the LNG netback run

have a marked impact on GPG demand and results in GPG demand dropping by

almost 45% by 2023; and

LNG demand will be sourced primarily from the Bowen-Surat basins given its

vast reserves and proximity to the LNG export terminal.

11.3 Scenario gas prices by region

The following section shows the gas prices by region for each of the six scenarios

modelled across the Production Cost and LNG Netback runs. The prices of gas represent

the marginal cost of gas at each node.

Figure 11-6 shows the gas prices at the Sydney hub for all scenarios across the

Production Cost and LNG Netback runs. The Production Cost run prices across all

scenarios show no major fluctuations due to minimal deviations of supply sources (and

costs) of gas over the study period. The slight decrease in gas prices from 2019 in four

of the scenarios (Reference, LNG Low, High Growth, High Infrastructure) is due to new

gas supply from geological basins, particularly Gunnedah, which feeds gas directly into

Sydney via the QLD Hunter Pipeline

In the LNG High and Low Supply scenarios, new gas supply from these geological basins

are not developed and prices continue to rise. Under these two scenarios, NSW will

continue to rely on gas imports from Longford or Moomba. Supply out of Moomba

increases considerably (switching the direction of flow from Moomba to Wallumbilla)

with the introduction of LNG demand at Gladstone for all scenarios.



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Figure 11-6 Sydney gas prices - $/GJ (Production Cost and LNG Netback run)

The initial price spike in gas prices from 2015 to 2016 is due to the increased netback

cost at Moomba and the switching of SWQP flows from west to east from the Cooper-

Eromanga basins, which is the swing provider for NSW. LNG Netback run prices at

Sydney drop by $0.5/GJ with the introduction of new gas supply from the Gunnedah and

Gloucester basins which supply up to 70 PJ to the NSW market (High Infrastructure and

High Growth scenarios).

The highest gas prices at the Sydney hub result from the LNG High scenario, while the

LNG Low scenario results in the lowest prices. These prices are primarily due to the oil-

linked LNG netback prices assumed in these scenarios. The Low Supply and High

Growth increase after 2020 due to no new basins and higher domestic demand

respectively. The Reference and High Infrastructure scenarios flatten towards the Low

Supply scenario due to total NSW gas demands being similar across all scenarios and the

new CSG basins supplying Sydney.

Figure 11-7 charts the Melbourne gas prices for both runs across all scenarios. Under

the Production Cost run, prices at the Melbourne hub for all scenarios are projected to

rise steadily with no major price fluctuations over the study period. This result was

anticipated as the gas requirements for the Melbourne hub is supplied internally by the

Otway, Bass and Gippsland basins which holds considerable volumes. As such the price

levels between $5.5/GJ and $5.9/GJ reflect the production and transportation costs

from the Gippsland, Otway and Bass basins.

In the LNG Netback run, the cost of gas at the Melbourne hub rises slightly but the price

trajectory remains relatively unchanged. This is due to the hub’s position relative to

Gladstone. As seen from the modelling results, prices are slightly higher but the change

is small (about $0.1/GJ) and shows VIC is relatively buffered from the export dynamics

of the LNG projects that affect the eastern Australia gas market.

3

5

7

9

11

13

2014 2015 2016 2017 2018 2019 2020 2021 2022 2023

REFERENCE LOWSUPPLY HIGHINFRASTRUCTURE

LNGHIGH LNGLOW HIGHGROWTH

_____ LNG Netback cost run

- - - - - Production cost run Gunnedah and Gloucester gas production

Higher domestic gas demand

Moomba gas goes to QLD



96

Figure 11-7 Melbourne gas prices - $/GJ (Production Cost and LNG Netback run)

Figure 11-8 shows gas prices at the Brisbane hub for all scenarios across the Production

Cost and LNG Netback runs. The Production cost run shows least-cost prices for the

Brisbane hub are below $6/GJ in most scenarios and is attributed to the Brisbane hub

being mainly supplied out of the Bowen and Surat basins via the RBP

The Low Supply scenario shows the highest gas prices due to reduced CSG development

rates and reduced access to gas from specific basins (i.e. gas from Clarence-Moreton

basins which feeds into the Brisbane hub) and limited pipeline development. Prices are

projected to rise steadily with no major price fluctuations through the study period,

similar to the situation at the Melbourne hub because the Brisbane hub is mainly

supplied out of the large gas reserves of the Bowen/Surat basins.

Figure 11-8 Brisbane gas prices - $/GJ (Production Cost and LNG Netback run)



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The gas prices at the Brisbane hub for the LNG netback run show major fluctuations

over the study period and reflect the connection of LNG netback prices to fluctuating oil

prices in each of the scenarios. The price range between the scenarios is large due to a

difference in JCC prices between high and low LNG prices of $US 33/bbl across the study

period. Prices at the Brisbane hub for the LNG Netback run are in line with expectations

given its close proximity and direct competition for gas with Gladstone.

Under the LNG Low scenario, prices start at $10/GJ in 2014, before decreasing to $7/GJ

as a result of global macroeconomic factors before rising back to $10/GJ by 2023. The

LNG High case represents 12 trains by 2023 and indicates prices to be $11/GJ for most

of the period before increasing to $13/GJ by 2023. The results here also support the

case that QLD large-users are to expect a greater potential of market power influencing

pricing outcomes relative to other states, with highs of almost $13/GJ by 2023 and least

cost prices under $6/GJ.

Figure 11-9 below charts the Adelaide gas prices for both runs across all scenarios the

prices at the Adelaide hub for the Production Cost for all scenarios are projected to rise

steadily with only slight fluctuations in the LNG High case because of the higher LNG

requirements at Gladstone and are similar to the price trajectory at Melbourne, Sydney

and Brisbane hubs. The relatively steady prices at the Adelaide hub are due to the static

supply sources from the Cooper-Eromanga and Otway basins and stay around $6/GJ.

The prices from the LNG Netback run are lower than at the Gladstone hub due to the

Adelaide hub being further away from the export node and additional supply sources

out of Otway, Bass and Gippsland basins. However, the price trajectory at the Adelaide

hub follows the LNG netback profile and shows an increase of up to $3/GJ from 2015 to

2019 and indicates a material impact from the LNG export industry as gas from Moomba

is partly redirected to LNG export.

Under the LNG Low scenario (6 trains), prices in the first 5 years are close (within $1/GJ)

to that of the Production Cost run and support the view that there are sufficient

reserves to support a 6 LNG train export terminal until further trains come online post

2019, tightening supply and increasing prices at the Adelaide hub.

Differences in prices between scenarios from 2019 onwards are dependent on GPG and

domestic demands. Under all scenarios, the expected range of prices over the 2016 and

2020 period are from roughly $6 to 12/GJ.



98

Figure 11-9 Adelaide gas prices - $/GJ (Production Cost and LNG Netback run)

11.4 Gas demand across scenarios by region

The following six figures show domestic gas demands for each state and the LNG export

gas demand for the Gladstone hub. Mass market and industrial demands are based on

AEMO’s 2012 GSOO with Gladstone demand adjusted for expected expansion timings.

Domestic demands projected by the model are based on the LNG Netback runs and are

generally lower than GPG demand from Production Cost runs due to the higher gas

prices.

Figure 11-10 charts the domestic gas demand for NSW across all 6 scenarios. GPG

demand is roughly 20% of total domestic gas demand in 2014. NSW gas demand is

forecast to decline slightly across all scenarios over the study period (-0.06% pa in the

Reference case). Assumed increases of 1.2% pa in domestic demand (excluding GPG) is

offset by the decrease in GPG during the later years of the study period as a result of

higher gas prices in NSW.



99

Figure 11-10 NSW domestic gas demand - PJ/year (LNG Netback run)

Victorian domestic gas demand (Figure 11-11) is forecast to increase slightly over the

study period for all 6 scenarios (6 PJ or 0.3% pa over the 10 year period). This demand

increase is due to the demand forecast assumption (i.e. GSOO) and the little effect on

overall gas demand of the reduction in GPG due to the size of GPG relative to total gas

demand. The High Growth scenario shows slightly higher demand due to the high-gas

demand assumptions in this scenario. GPG demand is roughly 3.3% of total domestic gas

demand in 2014 dropping to 1.2% by 2023.

Figure 11-11 VIC domestic gas demand (PJ/year – LNG Netback run)



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Queensland domestic gas demand (below in Figure 11-12) is forecast to generally

decline over the study period with slight fluctuations. Post 2016, gas demand for each

of the scenarios deviates and is dependent on the scenario assumptions. The High

Growth and Low Supply scenarios have the highest and lowest total gas demand

respectively due to the GPG gas demand profiles. Under the High Growth scenario,

domestic demand (excluding GPG) increases by 48 PJ over the 10 year period whereas

GPG decreases 59% from 74 PJ to 31 PJ in 2023. GPG demand is roughly 35 per cent of

total domestic gas demand in 2014 and drops to 15% by 2023. Assumed increases in

domestic demand excluding GPG are offset by the large decline in GPG after 2016.

It is likely that some of the QLD gas powered generators who have direct access to CSG

reserves will be used to balance LNG contracts for some companies. If CSG well

production and/or drilling is slightly behind schedule, generators will be turned off to

save gas for LNG export. Another scenario would be if well production and/or drilling is

ahead of schedule, GPG may generate more electricity to use excess gas.

Figure 11-12 QLD domestic gas demand (PJ/year – LNG Netback run)

Figure 11-13 charts the domestic gas demand for SA across all 6 scenarios. SA gas

demand is forecast to decline in all scenarios after 2016 driven by rising gas prices and

changes in GPG. The LNG High scenario experiences the largest decline in gas demand

due to the largest increases in costs for gas-fired generation (prices move towards

$12/GJ), which are directly linked to higher netback gas prices assumed in the scenario.

Gas demand in SA is highly dependent on GPG as it makes up approximately 65% of

total gas demand in 2014. GPG remains steady after 2021 for almost all scenarios

despite increasing gas prices and suggests there is a lower limit of base load GPG in SA.

Unlike QLD, the domestic demand that excludes GPG is not offset by the large decline in

GPG after 2016 and the total domestic gas demand declines through the study period.



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Figure 11-13 SA domestic gas demand (PJ/year – LNG Netback run)

LNG export demands shown below in Figure 11-14 are based on the following LNG train

development assumptions for 2013/14 to 2022/23 (discussed in Section 10.5.1):

The LNG Low scenario assumes 6 trains are developed;

The LNG High assumes 12 trains are developed;

The other scenarios assume 8 trains are developed; and

The timing of LNG train developments for each scenario deviates after 2017.

Figure 11-14 LNG export gas demand (PJ/year – LNG Netback Run)

50

550

1050

1550

2050

2550

3050

3550

4050

2014 2015 2016 2017 2018 2019 2020 2021 2022 2023

REFERENCE LOWSUPPLY HIGHINFRASTRUCTURE

LNGHIGH LNGLOW HIGHGROWTH



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11.5 Gas supply across scenarios

The following section gives an overview of the gas production from geological basins

that supply the market. The supply results are based on the LNG Netback run. Despite

a decline in 2P gas reserves, sufficient 2P reserves remain in most basins over the

10 year study period (Figure 11-15). Figure 11-15 includes a reserves graph with and

without Bowen-Surat CSG so the smaller reserves can be seen.

The Gippsland and Cooper-Eromanga basins show low levels of remaining 2P reserves

by 2023 (1,430 PJ and 382 PJ respectively in the Reference scenario). The 2P reserves in

the Otway and Bass basins are depleted by 2021 and 2022 respectively. Gas production

from these basins is subsequently sourced from 2C resources.

Figure 11-15 Reference scenario remaining 2P reserves* – PJ

The graph below has Surat/Bowen CSG removed to show the detail of smaller reserves.




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For the following results, labels on figures have been categorised into the following:

QLD Bowen/Surat CSG – CSG from Bowen-Surat basins;

NSW – CSG from Sydney, Gunnedah and Gloucester basins;

QLD – conventional gas from Bowen Surat (particularly Moranbah region),and

Clarence-Moreton basins;

Cooper –conventional gas from Cooper-Eromanga basins; and

VIC – conventional gas from the Bass, Gippsland and Otway basins.

The reference case is discussed again and presented in Figure 11-16. The majority of

gas production comes from the Bowen-Surat basins that directly support the LNG export

demand. The remaining gas production is mostly from the offshore southern basins

(e.g. Gippsland Basin) and the Cooper-Eromanga basins (SA and QLD). Gas production

from the Cooper-Eromanga basins fluctuates between 120 PJ and 170 PJ/year over the

study period as a result of LNG demand ramp up and additional supply basins coming

online thereafter (Gunnedah, Gloucester and Clarence-Moreton). Gas production from

basins in NSW increases after 2019 as Gloucester and Gunnedah basins come online and

produce up to 43 PJ of gas.

By 2023, a significant amount of 2P CSG reserves remain in the Bowen-Surat basins.

However, 2P reserves in some geological basins are depleted (i.e. Otway and Bass

basins) or at low levels (e.g. Gippsland and Cooper-Eromanga basins) by 2023.

Figure 11-16 Reference scenario aggregated gas supply* – PJ/year


Figure 11-17 to Figure 11-21 below show the change in production from the Reference

scenario. The majority of production in all scenarios is supplied by CSG from the

Bowen/Surat basins to supply demand at Gladstone, most of which is used to meet LNG



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export demand. The LNG High and LNG Low scenarios vary the most due to the higher

number LNG trains assumed.

Figure 11-17 shows the difference in production between the Low Supply and Reference

scenarios. Less gas is being produced from NSW CSG basins and QLD conventional gas

basins due to the lack of new supply being developed in the Low Supply scenario.

Production out of the Bowen-Surat basins also reduce. These gas volumes are instead

supplied by increased production from the Cooper-Eromanga basins. Total production

is slightly lower in the Low Supply scenario due to lower gas demand growth.

Figure 11-17 Change in gas production (Low Supply – Reference)* – PJ/year


Figure 11-18 shows the difference in production between the High Infrastructure and

Reference scenarios. Gas is being produced earlier by new supply from QLD and NSW

basins due to the earlier commencement dates of gas from the Gloucester, Gunnedah

and Clarence-Moreton basins and the associated pipeline infrastructure. Extra gas is

also being produced from the Bowen Basin near Moranbah due to the commissioning of

the NQGP. Gas from the Bowen Basin near Moranbah is displacing gas from the Cooper-

Eromanga. Total production is very similar in both scenarios.



105

Figure 11-18 Change in gas production (High Infrastructure – Reference)* - PJ/year


Figure 11-19 shows the difference in production between the LNG Low and Reference

scenarios. The Bowen-Surat basins are producing much less CSG after 2018 due to the

reduction of LNG demand compared to the Reference scenario (6 and 8 trains by 2023

respectively). The gas from the Cooper-Eromanga basins and offshore conventional gas

basins also vary slightly before 2020. Total production is much lower in the LNG Low

scenario due to only 6 LNG trains coming online.

Figure 11-19 Change in gas production (LNG Low - Reference)* – PJ/year


Figure 11-20 compares the LNG High scenario against the Reference scenario. The QLD

Bowen-Surat CSG basins produce much more CSG after 2017 due to the increase in LNG



106

demand compared to the Reference scenario (from 8 to 12 trains). The LNG High

scenario assumes 12 LNG trains with trains additional to the first 8 coming online from

2018.

Figure 11-20 Change in gas production (LNG High - Reference)* – PJ/year


Figure 11-21 shows the difference in production between the High Growth and

Reference scenarios. Gas volumes are being produced by new gas supply from basins in

QLD and NSW due to the earlier commencement dates of gas from the Gloucester,

Gunnedah and Clarence-Moreton basins, the Bowen Basin near Moranbah and

associated infrastructure. The new NSW and QLD basins displace gas volumes from the

Bowen-Surat basins. Total production is slightly higher in the High Growth scenario due

to the increase in gas demand compared to the Reference scenario.



107

Figure 11-21 Change in gas production (High Growth - Reference)* – PJ/year


11.6 Potential shortfalls and constraints

This section discusses the various bottlenecks and constraints highlighted by the

maximum demand run of the model.

Each scenario was run using the forecast maximum demands from the AEMO 2012 Gas

Statement Of Opportunities (GSOO). GPG for this run was set higher than the other

runs to replicate a high total maximum daily demand. In this scenario all regions have

high demand at the same time, which is unlikely as maximum demand for each of these

regions will be reached during different times of the year, but provides a good

indication of system constraints.

Some limits to production and flow in the maximum demand run were allowed to be

broken in order to see where potential bottlenecks and constraints may occur in the

system. Gas storage and line-pack, amongst other gas management options, were not

modelled. These have considerable utility during or leading up to peak demand days in

managing these situations.

A key assumption in this modelling is the South West Queensland Pipeline has west to

east capacity of 600 TJ/day from 2016.



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11.6.1 Mt Isa/Carpentaria Gas Pipeline

The maximum demands forecast for the Mt Isa node is higher than the capacity on the

Carpentaria Gas pipeline (demand = 121-129 TJ /day, pipeline limit = 119 TJ/day). As gas

can only get to Mt Isa via this pipeline, these forecast maximum demands will not be

met unless the pipeline can flow at higher levels or storage is used.

11.6.2 North Queensland Gas Pipeline/Townsville

Under maximum gas demand conditions in the High Growth scenario, and high

generation at Townsville, it is possible that this line could constrain demand. This would

involve Townsville power station running at higher level than normal. This line is easily

upgradeable with compressors if this were to become an issue. In all other scenarios no

constraint was found to this node.

11.6.3 Gladstone/Queensland Gas Pipeline

The AEMO forecast loads for Gladstone were 65 PJ for 2013/14. This was higher than

the pipeline capacity on the Queensland Gas Pipeline (52 PJ). IES/RLMS adjusted the

demand at Gladstone to a level we believe is more realistic. We have also assumed an

upgrade on the Queensland gas pipeline in July 2016 to meet increasing demand. Once

these changes were made we found no supply issues at the Gladstone node in any

scenarios.



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12 Key findings and conclusion

12.1 Prices across the east coast

Average prices for the east coast are presented in Figure 12-1. Production cost prices

will remain relatively flat around the $6/GJ mark whereas the LNG Netback run, a proxy

for market power at Wallumbilla and Moomba, shows average prices across the east

coast starting at $7/GJ and increasing towards $9/GJ. Brisbane and Adelaide prices are

higher and Sydney and Melbourne lower than these averages.

A major driver of the LNG Netback price outcomes is the number of LNG trains. The

difference between 6 and 12 trains across the study period is approximately $2/GJ

across the ten years (greater at Brisbane and Adelaide, and lower at Sydney and

Melbourne). Additional basin developments do impact the price trajectory although

this is a second order effect relative to the LNG export story.

Figure 12-1 Average gas prices - $/GJ (Production Cost and LNG Netback)

12.2 Basin supply outlook

The supply situation across the east coast gas market over the study period can

be summarised by the concentrated supply from the Gippsland, Cooper-

Eromanga and Bowen-Surat basins. The Bowen-Surat basins are expected to

supply the majority of the requirements for the LNG export terminals, due to

proximity and cost (as well as these reserves owned by LNG proponents being

earmarked for export). Under the Reference case the Bowen-Surat basins ramp

up production from 217 PJ to 2,252 PJ, an increase of 2,035 PJ, to support 8

LNG trains.



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The commissioning of the Gloucester, Gunnedah and Clarence-Moreton basins

only slightly displace existing basin production. In saying this, NSW significantly

reduces its reliance on gas imports from the Gippsland and Cooper-Eromanga

basins by up to 50% as Gloucester and Gunnedah gas are expected to feed

directly into the Sydney market. The new CSG basins also have a downward

price impact at Sydney of approximately $0.5/GJ.

There are also sufficient 2P reserves to supply the domestic gas demand under

all of the 6 scenarios. The exception was at Otway and Bass basins which run

out of 2P gas in 2021-2022 and rely on 2C reserves thereafter.

12.3 Domestic gas demand outlook

Demand across the east coast is forecast to stay relatively flat in both the Production

Cost and LNG Netback runs, as growth assumptions in the mass market and industrial

sector are offset with GPG demand responses to increasing gas prices Under the LNG

netback run, GPG demand drops from 190 PJ to 108 PJ in the Reference case. The

declining trend is consistent across all scenarios although to varying amounts depending

on gas prices.

12.4 Potential supply constraints

Based on the Maximum Demand run, Mt Isa, Townsville and Gladstone showed signs of

bottlenecks under certain circumstances although they were generally short-term

rather than long-term supply issues (QGP should be upgraded in line with demand

growth expectations). These results are also consistent with GSOO findings. However

we recognise that there are gas management tools available not factored into our

modelling that can add considerable utility in managing peak day situations. IES are of

the opinion these short-term supply constraints will be managed by the market

participants.



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13 Western Australia gas market

The Western Australian (WA) gas market is a standalone system that is not physically

connected to the East Australian gas market. The WA gas market is characterised by a

large, historically strong and growing LNG export market and a relatively small domestic

gas market dominated by a few large industrial gas consumers and power generation.

WA has significant gas reserves and resources. These include the very large

conventional reserves of the Bonaparte, Browse and Carnarvon Basins. The bulk of

these gas reserves are offshore and are mostly controlled by a small number of

multinational petroleum groups. Smaller gas reserves and resources occur in the Perth

Basin with the operators being smaller and mid-tier Australian based companies. These

conventional gas fields, like the larger offshore fields, are mostly liquids rich. In the

Canning Basin, in the remote far north of the State, a very large unconventional gas

resource is in the early stages of evaluation and appraisal.

WA has well-developed gas infrastructure in gas processing plants and gas pipelines

linking the major gas supply areas to the LNG facilities and the major domestic gas

consuming centres in the State’s south-west and in the mineral rich regions centred on

Kalgoorlie. There is a close integration between the LNG projects and gas supply

infrastructure supplying the WA domestic market

Recent studies by the WA Independent Market Operator (IMOWA) indicate that there is

expected to be an adequate gas supply in Western Australia to meet forecast demand in

the domestic market for at least the next decade after allowing for the current and

expected investment in new LNG production facilities.

The Western Australian Government introduced a gas reservation policy in 2006 which

requires gas producers engaged in LNG exports to reserve 15% of gas produced from

each gas field for supply to the domestic market in exchange for permission to situate

processing facilities on land and use infrastructure provided under State jurisdiction.

The policy does not apply to gas fields in Commonwealth controlled offshore waters.

A key aspect of the gas reservation policy is that is that prices and contracts for

domestic gas supply are to be determined by the market. As a consequence, the price of

domestic gas in WA has for some time been tied to international gas market prices and

conditions. This is now occurring with eastern Australian gas prices as the LNG projects

around Gladstone are being developed.



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13.1 Overview of the market

The Western Australian gas market is significantly larger than the eastern Australian and

the Northern Territory gas markets. Its gas production of 1,458 PJ in 2012 was 62% of

the estimated total Australian gas production of 2,352 PJ.

Natural gas in WA is all conventional gas. It is an important part of the State’s energy

mix providing approximately 55% of its energy needs. Approximately 75% of the gas

produced in 2012 (1,093 PJ) went to LNG exports of 16.1 million tonnes (962 PJ). The

remaining 132 PJ was utilised as energy in the production of the LNG and gas processing

plants supplying the domestic gas market.

The domestic gas market in WA consumed approximately 365 PJ of gas in 2012 with

98.3% going to large industrial, mineral-based and power generation sectors. Over 90%

of the domestic gas consumption was used by eight major consumers including 145 PJ

by the alumina refining industry and 120 PJ by grid connected power generators.

On the gas supply side, Woodside through the Karratha Gas Plant and Apache with its

Varanus Island and Devil’s Creek Gas Plants currently provide 98.3% of Western

Australia’s domestic gas supply. These plants have a total gas process ing capacity of

1,240 TJ/day. The remaining 1.7% is provided by the Dongara (AWE), Beharra Springs

(Origin) and Red Gully (Empire) gas processing plants in the Perth Basin. They have an

aggregate capacity of 45 TJ/day. BHP Billiton has recently commissioned its Macedon

Project which is adding a further 200 TJ/day processing capacity near Onslow, for supply

into the domestic market.

Gas for domestic use produced in the Carnarvon Basin in the north-west is conveyed to

the principal markets in the south west of the State through the Dampier to Bunbury

Natural Gas Pipeline (DBNGP). The DBNGP currently has a capacity of 845 TJ/day (308

PJ/year). It has been looped for approximately 84% of its length. With full looping, its

capacity is expected to increase to 1,169 TJ/day (426 PJ/year).

Gas from the Varanus Island gas plants joins the DBNGP at Yarraloola where the

Goldfields Gas Pipeline (GGP) provides natural gas supply to a number of mining

communities for power generation and mineral processing between the Pilbara and

Kalgoorlie. The GGP connects through to Kambalda and Esperance. The GGP which is

operated by the APA Group has a capacity of 155 TJ/day but is being expanded with

additional compression to raise this to 202 TJ/day. The increased capacity is expected to

be operational early in 2014.

The Parmelia Gas Pipeline which runs from Dongara, to the south of Geraldton, to

Kwinana and Pinjarra was the original gas pipeline built for domestic gas supply in

Western Australia. It has interconnection with the DBNGP as well as to the Mondarra

gas storage facility. It is owned and operated by the APA Group. It has a capacity of

82 TJ/day (30 PJ/year). The Parmelia Pipeline is currently operating at approximately

55% capacity.



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The bulk of the natural gas in the Western Australian market is traded under medium to

long term bilateral contracts. Short term trades in the market are small and estimated

at between 10 and 25 TJ/day.

As a consequence of the significance of the export LNG industry in Western Australia

and the dominance exercised by the two major gas suppliers in the domestic gas

market, domestic gas prices in WA since the expiry of the initial legacy gas contracts in

2004 have increased. Today they are currently linked to international energy prices and

the exchange rate.

13.2 LNG production

The Woodside Petroleum operated North West Shelf Joint Venture (NWSJV) has a five

train LNG plant near Dampier on the Burrup Peninsula using gas from the offshore

Carnarvon Basin. The project has an overall capacity of 16.3 Mtpa (897 PJ/year). Nearby

is the Woodside owned and operated Pluto LNG Plant, currently with one LNG train with

4.3 Mtpa (237 PJ/year) capacity. A second LNG processing train of similar capacity is

planned for Pluto when sufficient gas reserves have been established.

LNG production in 2012 from the Burrup Peninsula plants was 16.1 million tonnes,

principally from NWSJV as Pluto was still ramping up in the commissioning phase.

The Chevron managed Gorgon Joint Venture is constructing a three train LNG facility on

Barrow Island. Each LNG train has a design capacity of 5.2 Mtpa (286 PJ/year) with first

cargoes planned to be shipped in 2015. The three trains are expected to be fully

operational by early 2017.

Chevron is also constructing the two train Wheatstone LNG project with a production

capacity of 8.9 Mtpa (490 PJ/year). The Wheatstone plant is scheduled to commence

LNG production in 2016.

Both the Gorgon and Wheatstone LNG projects are constructing, as part of the

developments, processing facilities to supply pipeline quality gas into the Western

Australian domestic gas markets. Both projects will connect into the DBNGP.

Shell and its Browse Basin partners are developing the Prelude Floating LNG project

utilizing gas from its reserves, most of which are in Commonwealth waters. This facility

will have no gas connections to on-shore Western Australia but will add a further

3.6 Mtpa (198 PJ/year) of LNG of capacity to north-west Western Australia.



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13.3 Gas reserves and resources

Western Australia has significant natural gas reserves and resources. These comprise

gas from both conventional and unconventional reservoirs. Approximately 92% of

Australia’s conventional gas resources in 2012 were in WA in the Carnarvon, Browse and

Bonaparte basins, virtually all offshore. Important unconventional gas resources occur

onshore in the Canning and Perth Basins. These are mostly tight gas and shale gas and

are in an early stage of appraisal.

A feature of the gas resource in the three major offshore basins is that it has been

developed primarily by large international petroleum majors including a number of

National Oil Companies. Details of the conventional gas reserves by basin in Western

Australia are given in Table 13-1.

Table 13-1 WA conventional gas reserves - PJ

Basin 2P Gas Reserves Est Remaining Reserves

Bonaparte 1,054 22,000

Browse 17,384 35,300

Canning - 10

Carnarvon 71,885 101,500

Perth 40 200

Total 90,363 159,000

Source: Australian Gas Resource Assessment 2012, GA & BREE., Energy Quest

The Carnarvon and Perth basins are the sole producers of gas for the Western Australian

domestic and LNG export markets though gas from the Bonaparte Basin supports the NT

domestic market and export LNG production. Gas from the Perth Basin is fully supplied

into the domestic market in the south west of the State.

The Carnarvon Basin, which has the largest gas reserves and is the most highly explored

and developed, is expected to remain the major supplier of gas in WA for both the

domestic and LNG export markets for over and beyond the next decade.

The Browse and Bonaparte basins are remote from the existing gas hubs in Western

Australia. They would require massive development to connect with the Carnarvon

Basin developments. Investment in pipelines to connect Bonaparte and Browse Basin

developments to supply gas into the domestic market is estimated to be many years

away, certainly after 2022. However further offshore gas developments in the

Bonaparte Basin are expected with gas coming ashore in the Northern Territory in the

Darwin Region.

An important feature of the large gas resource in offshore WA is that it is mostly liquids

rich with important LPG and condensate values. These provide a significant revenue

stream to gas producers and offset the high costs of developing offshore gas fields and

onshore gas plants.



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There is a potentially large unconventional gas resource in Western Australia in the form

of both tight gas and shale gas. The onshore Canning and Perth Basins are considered

the most prospective. Exploration and appraisal of the unconventional gas resource is at

a very early stage. However the prospectivity of these Basins has attracted considerable

interest from mid-tier and smaller explorers in the Perth Basin while a number of

international groups are farming–in or have taken up acreage in the more remote, but

larger Canning Basin.

Because of the early stage of the evaluation of the unconventional gas resource in the

Canning and Perth Basins, there is a considerable divergence in the estimates of the

potential size of the resource.

The US Energy Information Administration in 2011 estimated that there were 268 Tcf

(280,000 PJ) of shale gas in the Canning (87.7%) and Perth (12.3%) basins while a more

recent report (2013) by the Australian Council of Learned Academies estimated that

there were 475 Tcf (522,000 PJ) of shale gas resources with 95% being in the Canning

Basin. In addition, Geoscience Australia has estimated that the tight gas resource in the

Canning and Perth Basins is 40 Tcf (42,000 PJ) with 65% being in the Perth Basin. This

unconventional gas resource is significantly larger than Western Australia’s current

conventional gas reserves.

Limited exploration and appraisal has been undertaken in WA for CSG. Results for

shallow drilling for CSG recovery have been disappointing due to the nature of the coals,

particularly the low gas contents. A significant gas resource occurs in the deep, Permian

Irwin River Coal Measures which form an important component of the gas bearing

strata in the unconventional tight gas formations of the Perth Basin.

13.4 Gas processing facilities

There are a number of gas processing facilities in Western Australia dedicated to the

domestic gas industry. These had their origin in the initial 1979 agreements between

the NWS Joint Venture and the State Government which underwrote the establishment

of the export LNG industry near Dampier on the Burrup Peninsular. The agreement was

instrumental in establishing an adequate gas supply regime to the domestic market by

the requirement of the NWSJV to provide dedicated domestic gas processing facilities

while the WA Government underwrote the establishment of the gas transmission

pipeline (now DBNGP) from Dampier to the south-west of Western Australia.

The five foundation domestic customers entered into long term, large volume contracts

at low fixed prices. These mostly prevailed over the period from 1984 to 2004. They

effectively set the gas price bench mark which resulted in significant growth in gas

markets in the State, including those in the Pilbara, Mid West and the Goldfields. The

growth in gas demand also attracted additional gas processing facilities and capacity.



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Since the expiry of the legacy gas supply contracts, some of which lasted to 2004,

domestic gas prices in WA have increased as they transitioned to an international

energy price linkage.

In 2006 the WA Government developed its first policies in securing domestic gas

supplies. This resulted in a requirement for future LNG proponents to provide 15% of

their gas reserves and establish gas processing facilities for dedicated gas supply into

the domestic market. This applies to gas reserves and resources under the State’s

jurisdiction.

Details of the gas processing facilities dedicated to the Western Australian domestic gas

supply are outlined in Table 13-2.

Table 13-2 WA domestic gas processing facilities

Facility Operator Capacity (TJ/d) Pipeline Connection

Carnarvon Basin

Karratha Woodside 630 DBNGP, GGP

Varanus Island (East Spar) Apache 270 DBNGP, GGP

Varanus Island (Harriet) Apache 120 DBNGP, GGP

Devil Creek Apache 220 DBNGP

Macedon BHP Billiton 200 DBNGP, commissioned Aug 2013

Gorgon Domestic Chevron 150 DBNGP, 2016 start-up stage 2 +150 TJ/d

Wheatstone Domestic Chevron 200 DBNGP Start-up 2018

Pluto Domestic Woodside n/a DBNGP>2018. Subject to viability

Perth Basin

Dongara AWE 7 Parmelia

Beharra Springs Origin 25 Parmelia

Red Gully Empire Oil & Gas 10.6 DBNGP Stage 2 >2020 + 10.6 TJ/d

In addition to the above gas processing facilities, in July 2013 the APA Group completed

the expansion of the gas storage facility at Mondarra in the northern section of the

Perth Basin. This facility, which is connected to both the DBNGP and the Parmelia gas

pipelines, has a gas storage capacity of 15 PJ with a charge capacity of 70 TJ/day and

output capacity of 150 TJ/day. The Mondarra gas storage plant provides stability in the

operations of the DBNGP as well as providing for gas peaking and emergency back-up

gas supplies.

13.5 Gas transmission pipelines

The significant gas demand centres in Western Australia are a considerable distance

from the major centre of gas supply based on the gas resource of the Carnarvon Basin.

Important gas demand centres include the South-West, the Mid West and the

Goldfields. These regions, and some smaller gas demand centres, are connected to the



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Dampier and Perth Basin supply hubs through a number of gas transmission pipelines.

The major ones include the DBNGP, Parmelia and Goldfields Gas Pipeline. A number of

laterals are connected to the major gas transmission pipelines supplying mining centres

where gas is used for power generation and process use.

The Goldfields Gas Pipeline is connected to the DBNGP at its northern end while there is

interconnection between the Parmelia and DBNGP which roughly follow parallel routes

between Dongara and Kwinana.

Details of the significant gas transmission pipelines are given in Table 13-3.

Table 13-3 WA major gas transmission pipelines

Pipeline Start date Operator Length

km

Diameter

mm

Capacity

TJ/d

Regulatory

Coverage

Parmelia 1971 APA Group 417 116/356 82 No

DBNGP1 1984 DBP Limited 1,489

mainline

339

laterals

650/500

650/450

(loop)

845 Yes

Pilbara

Pipeline

1995 APA Group 219 610 166 No

Goldfields2 1996 APA Group 1,380 350/400 155 Yes

Kalgoorlie to

Kambalda

1999 APA Group 44 200 30 Light

Notes - 1: DBNGP is approximately 84% fully looped. With full looping and compression, estimated capacity

will be 1,169 TJ/d. 2: Goldfields Gas Pipeline is currently being expanded to carry 202 TJ/d.

Virtually all of the gas delivered into and transported by the gas transmission pipelines

is traded under bi-lateral, medium to long term contracts. Consequently there are only

very small quantities of interruptible gas available for short term trading. Short term gas

requirements are typically traded amongst existing gas market participants either

directly with each other or via a broker. These short term trades are estimated to be in

the 10 to 25 TJ/day range.



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13.6 Gas pricing

The WA gas market is dominated by eight large customers accounting for over 90% of

the demand. Each of the major gas consumers is supplied through long term bi-lateral

agreements. This has led to an inelastic market demand.

Over the initial gas supply agreements between 1984 and up to 2004, when most of the

contracts were up for renegotiation, the gas price remained stable at approximately

$2.25/GJ. Since about 2005, contract gas prices have risen steadily to new contracts

being reported in the $5/GJ to $6/GJ range.

Estimates of likely domestic gas prices over the next decade range from $6/GJ to $9/GJ,

depending on the growth and related gas demand scenarios adopted. As has recently

occurred in eastern Australia, there has been a slowing of both economic growth and

particularly that for gas fired power generation. This, with a predicted steady but low

growth in the mining and mineral processing sectors, is expected to see future gas

prices level out in the $6/GJ to $9/GJ range and then follow the patterns in international

energy pricing.

13.7 Projected gas demands

The Western Australian Government and the IMOWA have recently commissioned a

number of studies into domestic gas market. IMOWA, in its Gas Statement of

Opportunities of July 2013, concluded:

Under the various gas demand scenarios, gas supply will continue to be able to

meet forecast gas demands. The market will be adequately supplied to at least

2022;

There are more than adequate reserves of gas in Western Australia and gas

processing facilities to meet the projected domestic gas demand for the next

10 years (to 2022);

The critical gas transmission infrastructure, the DBNGP, is fully contracted to at

least 2019. While no firm plans have been announced to further increase its

capacity, it is understood that detailed planning and engineering is well

advanced to undertake the necessary expansion should market conditions

develop;

The Parmelia gas pipeline is under-utilised but because of its small size, it has

limited spare capacity, while the Goldfields Gas Pipeline is currently being

expanded by 25%;

The domestic gas market in Western Australia is highly illiquid with two

dominant gas suppliers (and shortly three with Chevron) supplying eight major

gas consumers, all with long term gas contracts. This limits the ability of new

medium and large gas users to enter the market; and



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Future gas prices are expected to continue to reflect the non-competitive

nature of the Western Australian domestic gas supply situation. In this, prices

will reflect international energy costs, principally linked to LNG prices as well as

the increased costs of production and those associated with investment in gas

supply infrastructure.

13.8 Western Australia gas reservation policy

The Western Australian Government introduced a domestic gas policy in 2006. Under

this policy, gas producers, where not covered by specific State agreements, are required

to reserve 15% of gas produced from each field for supply to the domestic market in

exchange for permission to locate their processing facilities on State land. Some aspects

of the application of the policy have not been clear or consistent and as a consequence

the WA Government recently reviewed the policy which helped clarify many issues.

The Gas Reservation Policy only applies to facilities based on gas resources under State

jurisdiction. It does not apply to the significant offshore gas resource in Commonwealth

controlled waters.

The key points of the WA Gas Reservation Policy following the review as outlined in the

2012 Strategic Energy Initiative are:

Where specific agreements between the gas producer and the State regarding

domestic gas supply obligations do not exist, each LNG export project is

required to reserve gas for domestic use the equivalent to 15% of their share of

LNG production;

The gas supply reservation must be finalised and locked in before obtaining

access to the required land, infrastructure and services under State control;

Gas producers are required to ensure that domestic gas availability coincides

with the start of LNG production, though this is negotiable depending on the

state of the domestic market at the time;

Producers may offset their domestic gas supply obligations with gas swaps by

supplying gas from alternative sources rather than the specific LNG project

provided that they can demonstrate that the proposed offset represents a net

addition to the State’s domestic gas supply;

Prices and contract requirements for the supply of gas into the domestic

market are expected to be determined by the market; and

Gas producers are expected to operate with diligence and good faith when

marketing gas into the domestic market.

The Western Australian Government has stated that it proposes to review the

policy in 2014-2015.



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The WA gas reservation policy has led to substantial investment, and possible

overcapitalisation, in gas supply infrastructure to physically support the needs of the

domestic gas market. With the price of gas supplied to the domestic industry being

determined by the market, and in recent years being linked to international energy

prices, it is arguable that the gas reservation policy has achieved an optimum or

efficient economic outcome.

The concentration in the ownership of the gas reserves in WA and the market

dominated by a few large gas consumers on long term contracts has resulted in a non-

competitive market with no liquidity.

It has resulted in domestic gas prices in WA being closely linked to international energy

prices. This is now being seen in eastern Australian gas markets as the LNG

developments around Gladstone impact.



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Appendix A Gas reserve tables

Table 13-4 Conventional 2P reserves by basin (RLMS, Dec 2012)

State Basin 2P Reserves % in East Aust.

QLD

Adavale 21 0.3%

Bowen 74 1.2%

Surat 66 1.0%

Total 161 2.5%

NSW Gunnedah 0 0.0%

SA Cooper-Eromanga 1,835 28.5%

VIC

Gippsland 3,890 54.0%

Otway 720 11.2%

Total 6,025 65.2%

TAS Bass 245 3.8%

ALL Total 6,851 100.0%

Table 13-5 Conventional gas reserves by company (RLMS, Dec 2012)

Company 1P Reserves 2P Reserves 3P Reserves 2C Resources 3C Resources

AGL Energy 61 158

APLNG 37 53

AWE 164 164 192 192

Beach Energy 345 345 2,333 2,333

Benaris 122 122

BHP Billiton 1,830 1,830

CalEnergy 22 22

Drillsearch Energy 16 44 73 90 244

Energy World Corp 33 33

Esso Australia 1,770 1,770

Mitsui E & P 51 51 29 29

Nexus Energy 122 122 102 102

Origin Energy 621 621 159 159

Santos 1,589 1,589 2,403 2,403

Toyota Tsusho 28 28 40 40

Others 12 12 1,167 1,167

Total 6,851 6,993 6,515 6,669



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Table 13-4 CSG reserves and resources by activity - PJ (RLMS, Dec 2012)

Activity Grouping 2P Reserves 3P Reserves 2C Resources

LNG Projects

APLNG 13,053 15,973 3,825

Arrow LNG 9,494 13,970 2,521

GLNG 5,376 6,823 1,638

QCLNG 10,326 18,876 13,700

Total LNG 38,249 55,642 21,684

Power Generation & Utilities

AGL 2,170 3,961 130

Energy Australia 285 285 692

ERM Power 2 38 -

Origin Energy 178 889 -

Santos 1,448 1,448 3,951

Stanwell Corp 143 143 -

Total Power & Utilities 4,226 6,764 4,773

International Ownership

Harcourt Petroleum 343 824 594

Mitsui Group 505 1,265 301

Toyota Tsusho 122 122 -

Total International 970 2,211 895

Independent Companies

Blue Energy 50 180 820

Clarence Moreton Resources 12 266 -

Comet Ridge - - 260

Dart Energy - - 542

Galilee Energy - - 129

Metgasco 428 2,542 2,511

Red Sky 3 76 -

Senex Energy 157 358 240

Westside Corporation 347 885 -

Total Independents 997 4,307 4,502

TOTAL 44,442 68,916 31,853



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Appendix B Longer-term QLD suppliers

B.1 Blue Energy

Due to the stranded location of its gas resources in the northern Bowen Basin, Blue

energy will need to rely on a third party to provide the gas pipeline infrastructure, most

likely Arrow Energy’s planned Bowen Pipeline, which is not expected to be available

before 2017.

Blue Energy is also moving to develop its CSG and shale prospects in the Burrum Coal

Measures in the Maryborough-Harvey Bay Region. The Envestra operated gas pipeline

from Gladstone to Harvey Bay passes through Blue Energy’s permits.

Blue Energy’s two largest shareholders are the Stanwell Corporation , which has a 13%

interest, and KOGAS, which belongs to the GLNG consortium and has a 10% interest.

B.2 Icon Energy

Icon Energy holds CSG tenements in the southern and western Surat Basin as well as

some tenements in the south west Queensland section of the Cooper-Eromanga basins .

The results from its initial CSG drilling program were disappointing. Icon Energy is now

focusing its activities on shale gas appraisal in the south west Queensland section of the

Cooper-Eromanga basins in a joint venture with Beach Energy and Chevron. The SWQP

passes through Icon Energy’s Cooper-Eromanga basins tenements.

B.3 LNG Limited

LNG Limited is continuing with its evaluation of a midscale LNG plant at Fisherman’s

Landing on the mainland side of Gladstone Harbour. The project is planned around 2 x

1.8 million tonne per year trains using the company’s proprietary technology.

LNG Limited has yet to secure a gas supply for the project, which it plans to operate on a

tolling basis. The largest shareholder in LNG Limited is a subsidiary of PetroChina which

has a 50% interest in the Arrow Project. Any delays in the sanctioning of the Arrow

project may see some of PetroChina’s share of Arrow gas reserves directed to the LNG

Limited project. Each LNG train for the proposed Fisherman’s Landing project would

require 100 PJ of gas per year.

B.4 Metgasco / Red Sky/ERM Power

Metgasco and Red Sky hold contiguous leases in the Clarence-Moreton basins in

northern New South Wales, 145 km from potential connection points on the Roma to

Brisbane Pipeline (RBP). ERM Power is farming into the Red Sky permits and has



124

become the project operator. From a reserves and resource perspective, as well as from

their potential to supply the Queensland market, these two groups may be considered

collectively.

The location of Clarence-Moreton Basin gas reserves and resources requires the

construction of the gas transmission pipeline, such as the proposed Lions Way pipeline,

for these companies to provide gas to south east Queensland. The Lions Way pipeline is

yet to receive environmental and planning approvals from the Commonwealth, New

South Wales and Queensland Governments. It has attracted strong opposition from a

number of environmental groups.

In an effort to monetise its gas, Metgasco considered the construction of two power

stations, the largest being a 200 MW combined cycle gas turbine in the northern New

South Wales region. Red Sky also undertook a feasibility study into the construction of a

27 MW gas-fired power station. ERM Power has focused on the supply of gas to its

proposed Wellington power project.

Both Metgasco and ERM/Red Sky have conventional gas prospects in their Clarence-

Moreton Basin permits. Further evaluation of these resources is planned.

Due to the policy uncertainties regarding gas exploration in New South Wales, it appears

that Metgasco and ERM/Red Sky joint venture may not realistically be in a position to

supply gas to the Queensland market in the next decade and certainly not before 2020.

B.5 Senex Energy

Senex has interests in the Don Juan CSG prospect in the eastern Surat Basin. Senex is the

operator, with Arrow Energy holding a 55% interest through the recent Bow Energy

acquisition. Recent exploration drilling has been encouraging.

Senex also has a minority interest in a Surat Basin tenement which is operated by QGC

and scheduled to be connected into the QCLNG system.

Gas marketing arrangements between Senex and Arrow Energy, and between Senex and

QGC, are not known but it is most likely that Senex will contract with its JV partners who

would be providing the basic gas infrastructure, should the permits in question be

developed.



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B.6 Toyota Tsusho

Toyota Tsusho has a minority interest in a Surat Basin gas field being developed by QGC

to supply CSG to QCLNG. Gas marketing arrangements between the two companies are

not known but it is most likely that Toyota Tsusho will contract its share of gas to QGC.

B.7 Shale and other unconventional gas

In the long term, the development of other unconventional gas reserves, such as tight

gas, deep CSG and shale gas is also expected to impact on the gas market. Industry

sources suggest that gas prices in the order of AUD$ 5-8/GJ would be required for shale

and other unconventional gas production to be commercial. A number of gas

proponents, including those with an interest in LNG export, have secured interests in

the Cooper-Eromanga basins and have commenced preliminary exploration and

appraisal of various unconventional gas formations. Initial resource figures indicate that

the development of shale and other unconventional gas would substantially boost gas

reserves and relieve current supply constraints to the domestic market. However this

position is unlikely to be clarified before around 2015 and commercial volumes of shale

gas are not expected to be produced before 2020.

B.8 Galilee Basin

A significant CSG, conventional and shale gas resource exists in the Galilee Basin,

located to the west of the Bowen Basin. The resource is presently under exploration

and appraisal by a number of companies including AGL, Arrow Energy, Blue Energy,

Comet Ridge, Exoma, Galilee Energy, Origin, QER and WestSide/Mitsui E & P.

The Galilee Basin gas resource has been estimated to contain in excess of 200,000 PJ as

gas in place. First gas reserves are expected to be announced in late 2014, though some

gas resources have been established. Commercial gas contracts for gas from the Galilee

Basin are unlikely to be available much before 2020. Significant gas pipeline and other

infrastructure will be required before Galilee Basin gas can be marketed.



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Appendix C Gas market modelling

IES has developed an Integrated Gas and Electricity Model (IGEM). This is a partial

equilibrium model of the gas and electricity sectors that accounts for the connection

between these sectors. A brief summary of the model is provided.

C.1 The TIMES Framework

TIMES is a mathematical model of an energy system or systems (such as gas and

electricity or both) that consists of a large set of equations that governs system

operation and development according to the specified technologies and requirements

(as specified through input data). The objective of TIMES is to optimise a chosen

objective function subject to meeting all system constraints that are defined.

While a variety of such objectives are available within TIMES, the one normally used is

the minimum of total system discounted cost over the study period. System constraints

include issues such as the supply side attempting to meet demand within economic

limits, flow limits on transmission lines and pipelines, limits or imposed prices on

emissions, earliest years for a certain technology to enter etc.

In its fullest application, demand in TIMES is not set exogenously but endogenously

through the incorporation of the processes that use energy.

The TIMES solution is obtained by using a linear programming optimiser that finds the

minimum objective function value while simultaneously satisfying all the constraints

that have been defined.

The output from a TIMES solution is two-fold. The most obvious is the so called

‘primary’ solution that details the technologies used each year, the extraction /

importing / exporting of energy, the investments required, the fuel flows etc. This

represents the physical outcomes over the study period.

The other (and of equal importance) is the so-called ‘dual’ solution that provides the

economic prices (or shadow prices) associated with each constraint in the model. The

shadow price of the supply equals demand constraint gives the cost of increasing the

demand by 1 unit (this is the increase in the objective function associated with

increasing the demand in a particular time period by 1 unit). Other examples are the

cost saving of increasing a transmission limit or of reducing the level of emissions

allowed. We note that these are marginal costs as they are associated with the change

in costs over the study period of a small change in a specified factor. Thus the shadow

prices indicate the true worth (opportunity cost) of each fuel to the system. Fuels in

unlimited supply will have a shadow price equal to the input cost but if supply is limited

and there is an excess demand for the fuel, then the model may impute a higher

‘scarcity’ value to the fuel. This scarcity premium may also arise from supply limitations

imposed by pipelines or other means.



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Economics models of energy systems such as gas and electricity usually have a study

period of 10 to 40 years enabling the long term economics of existing resources, asset

retirements and investments to be properly included. As system condition can vary

considerably during different time periods in a year, TIMES provides for each study

period to be segmented. Examples of this are the different seasons and day types.

Other segmenting examples are high to low demand or high to low wind generation (as

might be needed in a high wind generation electricity system. The importance of

segmenting years is that capacity issues are not lost as is the case when average values

are used. TIMES provides for different energy sectors such as electricity and gas to

utilise different time segment descriptions.

C.2 The Integrated Gas and Electricity Model

IGEM is a model of the Australian electricity and gas systems developed using the TIMES

framework. It contained both these systems in all the Australian states although one

can select to involve a subset of these if desired (such as the east coast system only).

IGEM has a variety of representations of these system from the very detailed to less

detailed. A brief summary is as follows:

(Gas) Gas basins characterised by ownership, 1P/2P/3P reserves and extraction

costs;

(Gas) All major pipelines characterised by tariff and flow limits;

(Gas) Connection to gas power stations contained in the electricity model;

(Gas) Committed and potential new LNG trains and gas demands;

(Gas) Potential new pipelines;

(Electricity) Generator units characterised by capacity, availability, efficiency,

fuel cost, fixed and variable non fuel costs;

(Electricity) Interconnection transmission characterised by flow limits and

losses;

(Electricity) Demand usually set exogenously at all major demand centres;

(Electricity) Potential new generation characterised by development cost,

location, fuel type, efficiency etc.;

(Electricity) Renewable generation scheme rules and requirements;

(Electricity) Emissions and renewable policies; and

(Electricity) Requirements for supply reliability usually expressed as a minimum

reserve margin in each NEM region.



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A large amount of energy infrastructure is typically in place at the start of a study and

consumers own much equipment already used to provide various energy services. This

information is presented to TIMES as ‘residual’ technology amounts that can be utilised

without investment cost until their lifetime is reached. TIMES makes choices from the

available range of technologies to replace equipment as it is retired as well as to provide

for growth in demand.

One of the strengths of IGEM is that it provides for different policy options and other

issues to be readily incorporated in the model. For example, applying a renewable

portfolio standard simply involves an equation to be specified that ensures the required

portion of relevant electricity demand be supplied from renewable sources. The model

would meet this in a least-cost manner from the range of technologies presented to it.



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Appendix D Modelling assumptions

Table 13-6 Reserves by basin and type - PJ

Gas Source Geological Basin 2P 3P 2C Prospective

Conventional Bass 254 254 360 800

Conventional Bowen/Surat 160 203 0 300

Conventional Cooper-Eromanga 1,835 1,835 4,968 10,000

Conventional Gippsland 3,890 3,890 1,094 10,000

Conventional Gunnedah 0 0 0 0

Conventional Otway 720 720 116 1,200

CSG Bowen/Surat 39,148 57,783 25,024 150,000

CSG Galilee 0 0 316 25,000

CSG Moranbah 2,472 5,504 0 10,000

CSG Clarence-Moreton 445 2,922 2,511 7,500

CSG Gloucester 669 832 0 1,200

CSG Gunnedah 1,426 1,426 3,460 20,000

CSG Sydney 282 457 542 1,500

CSG Cooper 0 0 0 25,000

Table 13-7 Maximum production capacity – TJ/day

Basin TJ/day

Bowen- Surat 1099

Cooper- Eromanga 490

Sydney 26

Bass 70

Gippsland 1245

Otway 848

Clarence-Moreton 100

Gloucester 90

Gunnedah 100

Galilee Not modelled

Total 4068



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Table 13-8 Production costs by basin and type - $/GJ

Type Basin 2P 3P Contingent Prospective

Conventional Bass 4.77 5.02 5.27 6.27

Conventional Bowen/Surat 4.40 4.84 5.08 6.10

Conventional Cooper-Eromanga 4.20 4.62 4.85 6.09

Conventional Gippsland 4.76 5.01 5.26 6.26

Conventional Otway 4.77 5.02 5.27 6.27

CSG Bowen/Surat 4.42 4.86 5.11 6.13

CSG Clarence-Moreton 4.82 5.30 5.57 6.68

CSG Galilee 5.01 5.51 5.79 6.95

CSG Gloucester 4.42 4.85 5.11 6.13

CSG Gunnedah 4.62 5.08 5.34 6.40

CSG Moranbah 4.62 5.08 5.34 6.40

CSG Sydney 5.58 6.08 7.08 8.08

Unconventional Cooper-Eromanga 6.01 6.61 6.94 8.33



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Table 13-9 Pipeline capacities and tariff – TJ/day and $/GJ

Pipeline From Townsville Tariff ($/GJ) Max cap

North Queensland Gas Pipeline Moranbah Townsville 1.42 68

Carpentaria Gas Pipeline Ballera Mt Isa 1.40 119

Queensland Gas Pipeline Wallumbilla Gladstone 0.87 249

Roma to Brisbane Pipeline Wallumbilla Brisbane 0.49 232

South West Queensland Pipeline Ballera Wallumbilla 1.04 694 South West Queensland Pipeline Reverse Flow Wallumbilla Ballera 1.04 595

QSN Link Ballera Moomba 0.40 694

QSN Link Reverse Flow Moomba Ballera 0.40 595

Moomba to Sydney Pipeline Moomba Young 0.75 439

Moomba to Sydney Pipeline Young Dalton 0.06 439

Moomba to Sydney Pipeline Dalton Sydney 0.13 439

Moomba to Sydney Pipeline Reverse Flow Sydney Dalton 0.13 315

Moomba to Sydney Pipeline Reverse Flow Dalton Young 0.06 315

Moomba to Sydney Pipeline Reverse Flow Young Moomba 0.75 315

Dalton to Canberra pipeline Dalton Canberra 0.15 439

Eastern Gas Pipeline Longford Hoskinstown 0.71 288

Eastern Gas Pipeline Hoskinstown Sydney 0.43 288 Longford to Canberra via Eastern Gas Pipeline Hoskinstown Canberra 0.43 77

NSW-VIC Interconnect (VIC to NSW) Melbourne Culcairn 0.32 92

NSW-VIC Interconnect (VIC to NSW) Culcairn Wagga Wagga 0.06 92

NSW-VIC Interconnect (VIC to NSW) Wagga Wagga Young 0.09 92

Longford-to-Melbourne Pipeline Longford Dandenong 0.20 1030

Longford-to-Melbourne Pipeline Dandenong Melbourne 0.07 1030

South West Pipeline Port Campbell Melbourne 0.27 429

South West Pipeline Reverse Flow Melbourne Port Campbell 0.27 429

SEAGas Pipeline Port Campbell Penola 0.25 314

SEAGas Pipeline Penola Adelaide 0.50 314

Moomba to Adelaide Pipeline Moomba Whyte Yarcowie 1.00 253

Moomba to Adelaide Pipeline Whyte Yarcowie Adelaide 0.30 253 Moomba to Adelaide Pipeline Reverse Flow Adelaide

Whyte Yarcowie 0.30 380

Moomba to Adelaide Pipeline Reverse Flow Whyte Yarcowie Moomba 1.00 380

Tasmanian Gas Pipeline Longford Bell Bay 1.30 130

Tasmanian Gas Pipeline Bell Bay Hobart 1.00 130

Queensland Hunter Pipeline Wallumbilla Gunnedah 1.00 230

Queensland Hunter Pipeline Gunnedah

Newcastle (then to Sydney) 0.75 230

Queensland Hunter Pipeline Reverse Flow Gunnedah Wallumbilla 1.00 230

Central Queensland Pipeline Moranbah Gladstone 0.70 0

Lions Way Pipeline Casino (Clarence-Moreton Basin)

Ipswich (then to Brisbane) 0.50 74

Stratford to Hexham Pipeline Stratford (Gloucester Basin)

Hexham (then to Sydney) 0.35 100

* Limits vary by scenario



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Appendix E Major gas pipelines

E.1 VIC Declared Transmission System

The DTS enables gas to be transported in VIC and to the NSW-VIC Interconnect. It is a

meshed network of pipelines with multiple injection and withdrawal points. BHP/ESSO

are the main suppliers of gas injected at Longford as seen in the chart below (dark

brown area) with capacities of up to 1,000 TJ/day depending on system conditions. VIC

demand is above 220 PJ per year. Figure 13-1 shows total injections across the DTS.

Figure 13-1 DTS injections - PJ/day (AEMO)

Figure 13-2 is a chart of the annual demands with the number of heating degree days

(HDD) plotted across the financial years for Victoria. No further regression analysis was

performed however recent levels show gas demand is significantly off 2008 and 2009

levels even with similar or higher HDD years. Peak demands over the past 3 years

(1.1 PJ) are also lower than the peak in 2009 (1.3 PJ). We look at the impact of

generation behaviour on the VIC gas market separately following this section.

VIC gas powered generation across the previous 6 years has shown a declining trend

predominantly driven by a reduction in output at Newport (tan area in following chart)

driven by the portfolio optimisation and changes to the Energy Australia (EA) portfolio

in combination with a diminishing electricity demand.



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Figure 13-2 Annual VIC gas demand (MIBB)

Generally the VIC gas market will only exhibit extreme daily prices and volatility on cold

high demand heating load days when EA are running Newport in combination with

other gas fired generation. Given Newport and to a lesser extent Jeeralang have been

essentially off since Q1 2010, we can only assume EA have significantly restructured

their gas supply contracts and are either banking large quantities of gas (possibly at

considerable cost) or are very short of gas (we cover this in more detail later) relative to

their peers.

Mortlake and Bairnsdale power station have been included (gas sourced directly from

the Otway Basin and the EGP respectively) but does not form part of gas consumption in

the DWGM. Although not shown in the chart, the Uranquinty power station also sources

a portion of its gas from the Culcairn withdrawal point from the Victorian system.

Origin and APA recently announced an upgrade of the Culcairn interconnect by

increasing the capacity of the northern zone of the Victorian Transmission System by

59% by looping sections of the Wollert to Barnawartha pipeline, which is expected to be

completed by winter 2015. On the chart below take note of the reduction of Newport

output and the dramatic increase of Mortlake output which has its own dedicated

pipeline directly from Otway.



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Figure 13-3 Monthly VIC gas-fired generation - GWh (IES)

IES believe the trend is further exacerbated by lower electricity demand. This is driven

by solar PV, wind penetration, energy efficiency and structural economic issues,

removing the need for gas-fired generation. Gas producers seeking higher gas prices

are also causing vertically integrated retailers to bank as much gas as possible for future

consumption when the market collectively believe gas will be worth more. Also , the

very likely removal of the carbon tax in combination with higher gas prices, will reverse

the recent trend of coal fired generation moving higher up the short run marginal cost

(SRMC) merit order to the lowest cost SRMC.

Figure 13-4 shows the average daily quantity offered by participants in 2012/13. The

chart does not distinguish price bands (quantities offered at $800/GJ opportunistically

are included).



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Figure 13-4 Average daily quantity offered by participant – FY2013 (MIBB)

E.2 Eastern Gas Pipeline and the Moomba to Sydney Pipeline

Gas in NSW is supplied by two major pipelines from VIC via the EGP and Moomba along

the MSP. The gas requirement in Sydney typically ranges from 200 TJ/day to

350 TJ/day during winter peaks, with the MSP providing most of the demand swing gas

in winter.

Figure 13-5 Flows into Sydney split by pipeline – TJ/day (GBB)



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The EGP stretches from Longford in Victoria, up into New South Wales past the

Australian Capital Territory, and then on to the outer suburbs of south Sydney. With a

capacity of 268 TJ/day, the EGP transports gas from the Gippsland basin to Canberra,

Wollongong and Sydney.

Construction of the EGP commenced in 1999 and the project was completed in 2000. At

the present time, the EGP is not subject to economic regulation ( i.e., regulation of

tariffs) under the National Gas Rules. Figure 13-5 shows daily flows on the EGP versus

the MSP from July 2008 until July 2013, where you can clearly see the higher load factor

on the EGP against the higher flex load on the MSP.

The EGP has a relatively high utilisation and has seen increasing demand for capacity

upgrades over time, particularly since winter 2007. Energy Australia is a major shipper

on the pipeline because of its retail load in NSW and Tallawarra power station. The dips

in flow along the EGP, represent the running regime at Tallawarra power station which

is largely driven by the medium term purchase of firm capacity on the EGP.

IES understand the EGP is fully contracted and gas demand peaks will not affect

Tallawarra given its firm shipping rights and favourable location along the EGP. In the

current trend towards higher gas pricing it would seem logical to expect EA to switch

generation away from Tallawarra towards their coal assets and to potentially use this

gas to supply customers at potentially lucrative prices. Additionally we note the

removal of the carbon tax impost on EA’s NSW coal assets, which were not eligible for

any carbon tax compensation, also strengthens the case for less output at Tallawarra.

The major competitor to the EGP is the Moomba-to-Sydney Pipeline (MSP), owned by

APA Group. The MSP carries gas from the Moomba hub in South Australia, down to

Wilton, to the South of Sydney. The MSP was commissioned in 1976 and extends

approximately 1,300 km from Moomba to Wilton, located south west of Sydney. Inline

compressor stations are located at Bulla Park and Young.

The MSP is the central spine of the gas transmission network and has various laterals

extending to towns such as Dubbo and Wallerawang, as well as the 219 km Young to

Culcairn pipeline which connects to the Victorian Transmission System.

The MSP TJ no longer operates at its full nameplate capacity of 420 TJ/day. In the last 18

months it has rarely exhibited flows above 300 TJ/day, as can be seen in Figure 13-5.

In 2004, stress corrosion cracking was identified in the MSP, particularly in sect ions

close to Moomba where the pipe is subject to highly alkaline soil and high summer

temperatures. Subsequent analysis determined that the grade of steel used for the

pipeline was susceptible to stress corrosion cracking, particularly if failures occurred in

the external pipe coating system. Modern pipelines are constructed from higher grade

steels and employ more robust, factory applied coating systems.

As a consequence, APA carried out repairs in a number of sections of the pipeline by the

installation of sleeves. The Company also introduced a pressure management plan for

the pipeline, particularly for the winter peak flows. This scheme involved reconfiguring



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some inline compressors and associated valving to enable the compressors to run in

series which helped reduce upstream pressures. Subsequently detailed inspections of

the MSP have been undertaken. This has led to the replacement of a number of sections

of the 34-inch pipeline. Ongoing inspections may result in further removal and

replacement of sections of the MSP while maintaining gas deliveries downstream relying

principally on line-pack during lower seasonal demands.

The demand on the MSP is such that the critical flow restrictions tend only to manifest

during the winter months when gas demand for heating load is higher. APA, as far as

can be ascertained, has not specified the extent of the capacity restrictions that apply to

the MSP. APA has finished a 5 year project to expand the winter capacity of the MSP by

60 TJ/day (i.e. 20% of the current maximum)14

.

It is understood that APA have detailed plans to replace or loop major sections of the

MSP, particularly upstream of Bulla Park, should market demand eventuate.

Figure 13-6 Monthly NSW gas-fired generation - GWh (IES)

E.3 Moomba to Adelaide Pipeline Systems and SEAgas

Adelaide is supplied by two major gas pipelines: the South East Australia Gas Pipeline

(SEAGas) from VIC and the Moomba to Adelaide Pipeline System (MAPS). Historically

MAPS was the only provider of gas into the Adelaide market with max capacity of

350 TJ/day. Compressors on MAPS have since been mothballed with the

commissioning of SEA Gas in 2004 and lower winter demands. SEA Gas now supplies

Adelaide with approximately 155 TJ/day predominantly for GPG, and hence at higher

14

State of the Energy Market 2011 , Australian Energy Regulator, 2011.



138

load factor compared to MAPS, of around 115 TJ/d. MAPS has essentially become the

flex gas provider for GPG.

The change in flows has largely been driven by diminishing gas supplies out of Moomba

and newer gas discoveries off the coast of Victoria. Historical flows on the two pipelines

since July 2008 can be seen below.

Figure 13-7 Flows into Adelaide split by pipeline – TJ/d (GBB)

Figure 13-8 Monthly SA gas-fired generation (GWh, IES)

E.4 Queensland

Queensland has an extensive natural gas infrastructure comprising gas fields, gas and

water gathering lines, gas treatment facilities and compression stations, water

treatment plants and gas transmission lines.



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In addition and integrated with this infrastructure are a number of gas fired power

generation facilities. There are 5 main pipelines in QLD however the most important

from a generation standpoint is the Roma to Brisbane pipeline (RBP). The RBP has a

high capacity factor and has been upgraded several times to meet a gradual increase in

gas demand in Brisbane. The focus on this pipeline in this review is due to several large

swing generators connected to the pipe: Darling Downs (Origin), Braemer 1 (Alinta) and

2 (Arrow), and Swanbank E (Stanwell), which operate in base load and intermediate

manner.

Figure 13-9 Monthly QLD gas-fired generation - GWh (IES)

E.5 Roma to Brisbane Gas Pipeline

The RBP is a fully looped gas that pipeline runs from the Wallumbilla Gas Hub, located

approximately 50 km south east of Roma, to the Bellbird Park Gate Station near Ipswich.

The initial RBP (1969) pipeline consists of 397 km of 250 mm pipe operating at 7 MPa.

The full looping of the RBP with 405 km of 400 mm pipe operating at 9.6 MPa was

completed in 2001. There are six compressor stations along the RBP. The metropolitan

section of the RBP extends a further 40 km to Gibson Island on the lower Brisbane River.

The RBP is owned and operated by the APA Group. It is a fully regulated pipeline.

Gas is supplied into the RBP at Wallumbilla as well as from a number of laterals and

injection points including Scotia/Peat, Windibri, Argyle and Kogan North. There are a

number of gas off-takes supplying gas to Dalby, Oakey, Toowoomba, Ipswich, the

Brisbane area and the Gold Coast.

The RBP currently has a MDQ of 219 TJ/day (79 PJ/year). It has little spare capacity

operating at capacity factors of approximately 90 %, as can be seen by the very high

load factor on the chart below. APA completed a further expansion of the RBP including

additional compression at Dalby, which will lift its capacity to 240 TJ/day being a 10%

increase and is virtually fully contracted.



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Figure 13-10 Flows on the RBP – TJ/d (GBB)

E.6 Queensland Gas Pipeline

Figure 13-11 Flows on the QGP – TJ/day (GBB)

The QGP, which is owned and operated by Jemena, conveys natural gas from the

Wallumbilla Gas Hub to Gladstone, with a major lateral supplying gas to Rockhampton.

The Envestra owned Gladstone to Harvey Bay Pipeline, which also supplies gas to

Bundaberg and Maryborough, is connected to the QGP at Larcom Creek near Gladstone.

The QGP has a main line length of 514 km between Wallumbilla and the Gladstone City

Gate at Yarwun. The 323 mm diameter pipeline has a design pressure rating of

10.2 MPa. It was commissioned in 1991 and underwent a major expansion in 2009 with



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a 113 km section looped from Oombabeer to Callide Station with 400 mm section pipe.

The 79 km Larcom Creek to Parkhurst (Rockhampton) lateral has a diameter of 219 mm.

The current capacity of the QGP is 142 TJ/day (51 PJ/year). It is operating at near full

capacity as seen by the high load factor on the chart above with average gas flows in the

125-130 TJ/day.

There are major gas injection points into the QGP at Ridgelands (South Denison and

Fairview), Rolleston Junction and Moura.

Planning for further looping and compression of the QGP has been undertaken by

Jemena to increase the capacity up to approximately 240 TJ/day as gas transportation

contracts are finalized.

E.7 South West Queensland Gas Pipeline and QSN link

The SWQP, which is owned and operated by Epic Energy, links the Wallumbilla Gas Hub

to the Santos operated Ballera Gas Plant in far South West Queensland. The

interconnected QSN Link (Queensland New South Wales South Australia), also owned by

Epic (owned by Hastings Diversified Utilities Fund and APA), provides the connection

between the SWQP at Ballera with the South Australian Gas Hub at Moomba.

The SWQP and QSN is a fully looped system and has a length of 937 km including the

182 km QSN section. The initial SWQP, which conveyed conventional natural gas from

Ballera to Wallumbilla, had a capacity of 180 TJ/day through the 406 mm pipeline which

was commissioned in 1996. The system was designed to a 14.9 MPa pressure rating. In

September 2007, the flow in the SWGP was reversed to enable CSG to supply gas to

North West Queensland via the Carpentaria Gas Pipeline instead of gas sourced from

conventional reservoirs in the Cooper-Eromanga basins. In January 2009 the QSN Link

was completed enabling CSG to flow to Moomba and supply gas to the Adelaide and

Sydney markets.

In January 2012, the fully looped SWQP and QSN was brought into service. The second

pipeline [450 mm], which parallels the original [400 mm], enabled the capacity of the

system to be increased to 385 TJ/d for gas flows in an east to west direction. The SWQP

and QSN have been designed for gas flows in either direction. From 2015, the gas flows

in the SWQP and QSN are expected to be from west to east.

New compression is being installed at Moomba to enable 360 TJ/day of gas to be

transported to Wallumbilla and thence on to Gladstone. This increase in capacity is

scheduled for commissioning in 2016. Capacity of up to 600 TJ/day is possible with

additional compression.

If the pipeline is expanded to 600 TJ/day, this could support the production of 3.65

Mtpa (200 PJ) of LNG, or 93% of the gas needs of one of GLNG’s Curtis Island gas trains.

The current capacity along with the new expanded capacity on the SWQP and QSN is

fully contracted. There are gas receipt points on the SWQP and QSN at Wallumbilla,

Ballera and Moomba and delivery points at the same three places as well as at Cheepie



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and Roma, where gas is supplied to the Barcaldine and Roma Power Stations

respectively.

Figure 13-12 Flows on the SWQP – TJ/day (GBB)

E.8 Carpentaria Gas Pipeline

Figure 13-13 Flows on the CGP – TJ/day (GBB)

The CGP is owned and operated by Roverton Pty Ltd, a wholly owned subsidiary of the

APA Group. It conveys natural gas from the Ballera Gas Hub to Mount Isa Gate Station at

Mica Creek through an 841 km, 324 mm pipeline with a maximum operating pressure of

14.9 MPa. There are compressor stations on the line at Morney Tank and Davenport

Downs and off take points for the Cannington lateral, for gas supply at Phosphate Hill

and to the Xstrata Mount Isa Mine. The CGP was commissioned in 1998.



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The current capacity of the CGP is 119 TJ/day while recent daily gas flows have averaged

105-110 TJ/day, making the pipeline fully committed. Further expansion of the pipeline

is expected to be brought on line from mid-2013 to meet the needs of the 242 MW

Diamantina Power Station being jointly built for AGL and APA Group. While some

capacity at Diamantina will replace approximately 60 MW of old gas fired plant at Mica

Creek, the net increase in gas demand at Mount Isa is expected to be in the order of 35

to 40 TJ/day, assuming the Phosphate Hill fertiliser project continues to operate its

existing ammonia production facilities.

E.9 North Queensland Gas Pipeline

The NQGP supplies CSG from the Moranbah Gas Project to Townsville with major off

takes to major industrial consumers at Stuart and at Yabulu. The 393 km, 273 mm

pipeline was commissioned in September 2004 and is owned by the Victorian Funds

Management Corporation. It is operated on their behalf by Arrow Energy.

The pipeline, which is an isolated system and is not connected to the rest of the Eastern

Australian Natural Gas Pipeline Grid, has a free flow capacity of 108 TJ/day (39 PJ/year).

With in-line compression, the capacity can be increased to approximately 158 TJ/day.

Currently the pipeline has excess capacity with gas flows averaging 50 TJ/day.

E.10 Proposed new gas pipelines

A number of new multi-user gas transmission pipelines have been subject to detailed

feasibility study. In some cases they have received the basic environmental and

regulatory approvals. These pipelines are in addition to the large diameter transmission

pipelines under construction and planned to meet the specific needs of the LNG projects

on Curtis Island.

i. Queensland Hunter Gas Pipeline

The QHGP is a proposed 850 km, 500 mm high pressure (15.3 MPa) gas pipeline running

from Wallumbilla to Tomago near Newcastle. The route of the pipeline passes through

most of the Gunnedah Basin and has been designed to receive CSG from proposed

developments in the Basin.

The pipeline has received environmental and regulatory approvals from both the

Queensland and New South Wales Governments.

Based on use of 500 mm pipe, the capacity of QHGP would be approximately 230 TJ/day

(85 PJ/year) and 410 TJ/day (150 PJ/year) with in-line compression. Planning and

approvals for QHGP allowed for a 600 mm (24 inch) pipe to be used if required. A

600 mm pipeline will have approximately 40% greater capacity over a 500 mm system.



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The estimated tariff for a 500 mm system conveying 165 TJ/day (60 PJ/year) from

Wallumbilla to Newcastle was AUD $0.40/GJ.

Following the acquisition by Santos of major interests in the Gunnedah Basin, the QHGP

has been reconsidered to be developed in two stages. The first stage is based on

transporting CSG from Narrabri to Wallumbilla and for the second stage from Narrabri

to Newcastle. The estimated gas transportation tariff for CSG from Narrabri to

Wallumbilla through a 500 mm diameter pipeline is AUD $0.80/GJ.

ii. Dedicated LNG pipelines

Each of the LNG Proponent Groups have designed their projects around dedicated gas

transmission pipelines linking the upstream gas production centres with the LNG

processing plants on Curtis Island. Each of the dedicated pipelines is designed to

transport “conditioned” gas solely for their own projects. They are not proposed to be

common carrier pipelines subject to AER or National Competition Council regulation.

QCLNG. The QGC managed QCLNG Project has commenced the preliminary

construction activities for a 380 km, 1050 mm pipeline with maximum

operating pressure of 10.2 MPa. This pipeline will start near Miles and be fed

by treated gas from the Project’s Surat Basin Gas Fields via two major gas

headers of some 150 km in length.

GLNG. The Santos sponsored GLNG Project will be drawing the bulk of its CSG

from the Fairview and Arcadia Gas Fields in the Southern Bowen Basin and from

the Roma Shelf area in the Surat Basin around Wallumbilla. GLNG is also likely

to initially source up to 750 PJ of gas from the Cooper-Eromanga basins while in

the longer term it may use gas from the Gunnedah Basin.

The GLNG Project has commenced early construction activities on a 420 km,

1050 mm pipeline to operate up to 10.2 MPa. This pipeline will follow the basic

alignment of the QGP from Arcadia to Callide where it will use the Queensland

Governments Major Infrastructure Corridor, being used by the other LNG

Proponents, which goes all the way to Gladstone.

APLNG. The APLNG pipeline alignment roughly parallels that of QCLNG from

Miles to Callide before traversing to Gladstone by way of the common

infrastructure corridor. The major part of the pipeline is 380 km of 1050 mm

section pipe with maximum operating pressure of 10.2 MPa. Gas will be fed

into this pipeline from 70 km of large diameter headers. APLNG have

commenced preliminary construction activities on their gas transmission

pipeline

Arrow LNG. Arrow Energy proposes to construct two gas transmission pipelines

to feed their proposed LNG Project on Curtis Island. The initial gas supply will

be from Arrow’s gas fields in the Surat Basin with gas being transported

through the Arrow Surat Pipeline. At a later stage, Arrow will be drawing gas



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from its Northern Bowen Basin tenements. The Arrow Bowen Pipeline will be

used to transport this gas to the Gladstone Region.

The Arrow Surat pipeline has a planned length of 470 km including major headers. It is

likely to have a diameter of between 800 mm and 900 mm. It will be aligned east of the

QCLNG and APLNG pipelines until it joins the common Infrastructure corridor at Callide.

The Arrow Bowen Pipeline is proposed to commence approximately 90 km north of

Moranbah and track to Gladstone mostly east of the Bowen Basin Coal Measures. It will

have an approximate length of 477 km with three major laterals of some 103 km.

Both Arrow gas pipelines are being designed to 15.3 MPa standards.

iii. Central Queensland Gas Pipeline

Arrow Energy, before its acquisition by the Shell/PetroChina JV, acquired the rights

(PPL 121) to build a 440 km, 350 mm pipeline from Moranbah to Gladstone. It was

proposed that this pipeline would operate as a common carrier pipeline and to provide

a link for gas operations in the northern part of the Bowen Basin to be linked with the

Eastern Australian Gas Pipeline Grid.

With the subsequent developments by Arrow to investigate the Curtis Island LNG

Project, gas from the Northern Bowen Basin would be transported to Gladstone in the

Arrow Bowen Pipeline. Arrow is no longer pursuing the CQGP. At this stage, there are

insufficient gas reserves and resources held by other permit holders in the northern

section of the Bowen Basin to underwrite the CQGP or an equivalent pipeline from the

Region to Gladstone.



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iv. Lion’s Way Gas Pipeline

Metgasco Limited has established a significant CSG reserve and resource base in the

Clarence-Moreton Basin in northern New South Wales. In adjacent permits, Red Sky

Energy is developing both gas reserves and resources. The Clarence-Moreton Basin

reserves and resources are a stranded asset and require connection to the Eastern

Australian Pipeline Grid if they are to be successfully monetized.

Metgasco has proposed to connect its gas to the RBP near Ipswich through the

construction of the Lions Way Gas Pipeline. This is a 145 km pipeline from near Casino

to the RBP. It would follow the alignment of the Lions Way, a road and rail corridor

through the rugged Border Ranges between New South Wales and Queensland.

Metgasco is continuing with studies into the proposal which faces a number of

environmental issues.

v. Galilee Basin gas pipeline studies

While the Galilee Basin is in its early stages of exploration activity, a number of the

permit holders exploring in the Basin have undertaken preliminary studies into how any

gas production from their tenements might get to market.

These studies, particularly from exploration groups in the eastern sections of the Galilee

Basin, have focused on transporting gas east to Moranbah, to Gladstone and direct to

Bowen-Abbot Point. Those in the central and western parts of the Basin have

considered pipelines south to Wallumbilla, to the SWQP and direct to Ballera and or

Moomba. A study has also been undertaken for supply of gas to Cloncurry-Mount Isa.

All of these studies are preliminary scoping exercises based on individual company

expectations. Whole of Basin gas transportation studies have not been undertaken

though it is too early to undertake such an investigation in a meaningful way until the

gas resource across the Basin is better understood.



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Appendix F Factors influencing CSG supply costs

There is no standard cost for the production of CSG. The production costs for CSG varies

from field to field, depending on the nature of the coals such as depth of the coal

seams, aggregate coal seam thickness, regional coal formation geology, including the

extent of faulting, intrusions, cleating and jointing and the nature of other sedimentary

strata in the coal measures such as clay layers and aquifers. The characteristics of the

coal are also important. These include gas content, gas composition, level of gas

saturation, coal porosity and permeability, degree of water saturation, and formation

water quality. These are the determining factors in deciding the type of well drilled and

the well completion methods. Wells range from simple vertical well with under-reaming

to surface to in seam wells which can cost at least twice that for an equivalent vertical

well.

In the case of wells on the Central Walloon Fairway in the Surat Basin Nose, average

well productivity is approximately 1 TJ/day or 950,000 cfd. The principal impact of high

productivity is that the initial number of wells required to establish a production gas

field is substantially lower. However, the need for ongoing development wells is greater

as the finite amount of gas that can be recovered from a given gas field is practically the

same irrespective of well productivity. Typically CSG companies are planning on

recovering 50% of gas in place though with recent well completion techniques and

closer monitoring of pressure drops within the well has enabled recoveries of up to 70%

gas in place being achievable. This is particularly so in coals with high permeability such

the Central Walloon Fairway in the Surat Basin and at Peat, Scotia, Spring Gully and at

Fairview in the Bowen Basin.

For surface to in-seam wells, as were initially developed by Arrow Energy at Moranbah,

well productivity averages 0.9 TJ per day or 850,000 cfd. The two horizontal/one vertical

well configuration is initially more expensive to drill but well life and potential gas

recovery factors appear higher than for the more traditional vertical and under-reamed

well. With production drilling and directional single pad drilling, many more in-seam

wells can be drilled at a lower cost than in the past. This drilling technique, using

modern automated rigs, also results in a lower footprint than earlier drilling on rural

lands.

Another basic assumption is that up to 7.5% of field gas production is required for

power generation to drive pumps, compressors and utilities. Some high pressure gas

compressors are directly gas driven.

The cost of producing and supplying CSG is also dependent of the nature and market for

the gas. This determines the amount of processing that needs to be undertaken on the

raw gas. Gas that is produced for distant markets and transported by way of a high

pressure gas transmission pipeline or into a reticulated system is required to be treated

to meet gas transmission pipeline standards.



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These standards limit the quantity of inert gases such as carbon dioxide and nitrogen

that can be included in sales gas. The inert gases are limited to approximately 3.4% of

the gas. Gas with a higher inert content needs to be processed to remove some of the

inert gases or has to be blended with other gas containing lower amounts of inert gases.

There are also limits to the quantities of heavier hydrocarbons in the raw gas stream

such as ethane, LPG's and condensates. These are not normally present in CSG. With

conventional gas these heavier hydrocarbons are a valuable by-product. Also important

is the sulphur content and water saturation of the raw gas. High pressure gas

transmission pipelines require the gas to be compressed up to 15.3 MPa pressure. This

requires the gas to be completely dried as well as having very low sulphur levels to

prevent operating issues with compressors and ice formation and internal corrosion

within the pipeline. Gas compression is also energy intensive with up to 7.5% of the gas

produced needed to process the gas and to power the compression units.

Where CSG is able to be sold as raw gas to an onsite or nearby customer such as a

power generator, the processing of the gas to pipeline standards is usually not required.

In these cases the CSG usually only has to be processed to meet the specific needs of

the gas purchaser. This usually involves partial dehumidification, compression to

intermediate pressures (usually 2 to 4 MPa) and no or limited removal of inert gases,

sulphur compounds etc. as the gas in such cases is usually sold on its actual heating

value and its likely post combustion NOx/SOx emissions values.



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Appendix G International LNG pricing

This Appendix provides further discussion for Section 8.3.2.

G.1 Europe

European contract gas prices remain linked to oil & oil products, with most of the supply

dominating long-term (pipeline) gas contracts being on this basis. The formulae for

these contracts are often complex, reflecting a basket of oil and oil products. Term LNG

supplies also reflect this pricing basis.

All LNG imported into the UK is priced on a National Balance Point (“NBP”) basis, which

is becoming increasingly relevant to spot LNG deliveries into Europe.

G.2 USA

In the USA, all traded gas, and any imported LNG, is priced against Henry Hub (located

close to the major gas producing areas in and adjacent to the Gulf of Mexico), with

locational differentials as appropriate. This locational differential enabled a limited

quantity of LNG to be imported in 2011 (mostly into the North East, where gas prices

are seasonally higher due to transmission costs and bottlenecks), despite the prevailing

low Henry Hub price.

The different formulae and markers of the LNG consuming regions of the world have

provided the potential and the actuality of quite different prices applying to each

region. The differences have been extenuated by:

High oil prices (impacting on term LNG prices in Asia and Europe);

Extremely low Henry Hub prices (applying to all LNG imported into the USA, a

significant amount of LNG purchased from Atlantic Basin LNG sources, and to

much of the LNG sold into South America);

NBP being somewhere in the middle of crude prices and Henry Hub (applying to

all LNG imported into the UK, and increasing quantities of spot LNG into

Europe).

As a consequence, cargo diversions (on a spot and term basis) have become increasingly

evident. Notwithstanding the huge investment in LNG import infrastructure in the USA,

in anticipation of gas shortages or high gas prices, the commercialisation of vast

quantities of non-conventional shale gas has resulted in only very small quantities of

LNG now being imported into the USA. Indeed, the USA (and Canada) now looks very

likely to become a large exporter of LNG, with supplies aimed at the currently much

higher priced gas markets of Asia. The world’s largest LNG supplier, Qatar, is



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increasingly diverting its European and USA planned deliveries to Asia under new

medium and long term contracts.

Asian LNG pricing for new contracts in the period up to 2020 will be determined by the

interaction of a series of factors:

Realisation of demand growth;

Competition amongst suppliers, including the relative costs of supply;

Crude oil prices; and

Magnitude of LNG exports from North America, driven by sufficiently low Henry

Hub pricing, thereby providing an input gas price for liquefaction that enables a

globally competitive LNG cost of supply.

There are currently plans for more than 8 LNG export plants in North America that could

produce in excess of 80 Mtpa (4,400 PJ). The US Energy Information Administration (EIA)

has studied the impact of LNG exports on Henry Hub pricing, and concluded in its report

dated January 2012 that the increase in Henry Hub pricing attributable to LNG exports

(expressed as an average over the period 2015-2025 in 2009 USD) would be USD 1.34

per MMBtu (scenario dependent), over the forecast no-export scenario price of

USD 5.17 per MMBtu. Even taking into account these impacts, US exports are likely to

be a significant source of competitive LNG in Asian markets, with the potential to supply

at prices below current prevailing prices. However, major Asian buyers (such as Kogas,

CNPC, and GAIL), have already taken upstream and/or LNG midstream positions in some

of the North American projects. Whilst this will provide them with an LNG price hedge,

they may wish to use the position to leverage down LNG pricing in Asia. Conversely, the

existing LNG suppliers (such as Shell, BG, and Total), who have also taken North

American LNG positions, will be keen to maintain crude oil linked LNG pricing in Asia.



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Appendix H LNG development requirements

As an example of the major, numerous and multi-faceted facilities required, an 8 MTPA

LNG project with two liquefaction trains and utilizing CSG extracted from the Walloon

Coal Measures in the Surat Basin would encompass:

Up to 8,000 production wells drilled over 20 years at a rate of approximately

400 per year. Approximately 1,200 wells will be required to be connected for an

initial Train 1 start-up.

Between 12 to 18 gas processing facilities, regionally staged over a 20 year

period as new gas fields are brought into operation. These usually will comprise

a mix of intermediate gas compression capabilities, gas dehydration facilities,

and an integrated central gas plant with gas dehydration, centralized water

treating (reverse osmosis), and high pressure gas compression equipment.

Up to several hundred km of buried low pressure gathering lines for both gas

and water, feeding wet gas and water to dehydration plants and central water

treatment facilities.

High pressure dehydrated gas (10.2 to 15.3 MPa) from the gas processing

facilities is then introduced into a 500-700 km gas transmission pipeline, with

diameter of the order of 1,050 mm (42 inch), to convey the CSG to the Curtis

Island liquefaction units.

In addition, considerable gas field infrastructure is required, including power

supplies, access to wells, telemetry systems, maintenance and support services.

Integrated central gas and water treatment facilities with main transmission

pipeline compression have power demands of up to 60 MW, while individual

wells require approx. 60 kW, which can be supplied from the grid or, in more

remote areas, by off-grid gas fired generation.

At the Curtis Island liquefaction plants, there is major LNG storage, wharf

facilities, and extensive plant utilities, including environmental and emissions

treatment plants. Maintenance and operation support facilities are required.

Also, there is a range of accommodation and community support facilities for

plant staff.

Overall capital costs of the projects maybe in a USD$16 billion to USD$20 billion range,

depending on the regional diversity of the project’s upstream developments and the

extent of additional infrastructure being installed to accommodate future expansion.



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Appendix I Ramp gas management

The ability to suddenly connect and operate in unison of between 800 and 1,200

production wells with long and variable de-watering lead times poses a major

operational issue for the start-up of new LNG projects. To minimize the gas supply risk

to a CSG supplied LNG operation, the CSG wells need to have been de-watered and to

be flowing gas as they are connected to the LNG gas supply network. With the usual

long lead time to get a well into steady continuous gas production, this results in

significant management issues that have to be addressed to manage the ramp up of gas

supply until it is needed in the large volumes required. Flaring is not an option on both

economic and environmental grounds.

There is a portfolio of options available to CSG to LNG project operators to manage

ramp up gas. These will vary from project to project depending on the gas supply

circumstances facing each project. Most LNG projects propose to use a mix of the

following available options:

I.1 Partial shut-in of CSG wells

This is currently practised in many of the larger and more established gas fields such as

at Fairview and Spring Gully in the southern Bowen Basin and those on the Central

Walloons Fairway in the Surat Basin. Each of the LNG project groups is using this

method in varying degrees depending on the characteristics of individual gas fields.

I.2 Timing of gas field developments

As most CSG well developments have a long de-watering phase before gas production

occurs and the inability of CSG wells to be quickly cycled, the staggered development of

gas field development can, at best, only provide a very limited means of handling ramp

up gas.

I.3 Internal gas swaps

LNG proponent groups, such as APLNG and GLNG, where partner companies such as

Origin Energy and Santos have a large gas reserve and resource portfolio outside of the

LNG joint venture, can swap gas between various internal supply sources as a gas ramp-

up management tool. Furthermore conventional gas reservoirs can quickly be shut in

and re-commissioned at short notice to help manage gas ramp up requirements.

Currently the production of CSG in Queensland exceeds domestic demand and is

increasing as new fields are developed and brought on-line pending the use of the gas

for LNG production. Much of this gas is sent from the Wallumbilla Gas Hub through the

South West Queensland Gas Pipeline to Ballera where CSG is now the natural gas source



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for the North West Mineral Province centred on Mount Isa. The remaining CSG is

supplied to Moomba where it is directed to the New South Wales and South Australian

markets. The conventional gas in the Cooper-Eromanga Basin, which has traditionally

supplied these markets, has largely been shut in other than for wet gas fields, where

condensate and light crude oil revenue is significant and in gas fields rich in ethane to

supply ethane contracts to Botany in Sydney.

The ability of a company to swap gas between its own reserves in different petroleum

bearing sedimentary basins is governed by the nature of the markets being supplied and

available pipeline capacities between the basins where gas has to be physically

transported.

Santos has an agreement with GLNG to supply up to 750 PJ of conventional natural gas,

over a short period, from its Cooper-Eromanga basin reserves to help manage supply

build up for the commissioning of the GLNG trains.

Santos through its acquisition of the bulk of the gas reserves in the Gunnedah Basin has

the choice to supply into the New South Wales markets, freeing up gas in its Bowen,

Cooper and Surat Basins for possible LNG feedstock, or supplying direct into the GLNG

feeder hub being constructed at Wallumbilla. Gunnedah production will require

investment in new gas pipeline infrastructure, such as the Queensland Hunter Gas

Pipeline, which has received planning and environmental approvals.

QGC with all of its producing gas fields as CSG operations in the Surat Basin does not

have the flexibility of internal gas swaps.

I.4 External gas swaps

Because of the different timings in the scheduled start-up times for the various LNG

processing trains on Curtis Island, gas swaps between project participants can assist in

the management of ramp up gas.

Origin Energy, which has interest in a number of joint venture CSG operations operated

by QGC on the Central Walloon Fairway, has entered into a commercial arrangement

with QGC for QGC to have early access to some of Origin’s entitlements from the

relevant tenements, with QGC agreeing to supply Origin with a similar quantity of gas at

a later date and post QCLNG start-up.

It is understood that Origin has entered into somewhat similar arrangements with

Santos over early gas supply from the Fairview Gas Field operated by Santos, and where

Origin has an approximate 24% interest.

AGL Energy has major gas supply contracts with QGC to supply CSG for AGL’s domestic

gas markets, a significant portion being around Sydney. These contracts can potentially

be brought forward or delayed to enable some of the contracted gas to be allocated

initially to AGL and then be re-diverted to QCLNG start-up. QGC at a later date can re-

supply AGL with any shortfalls at an agreed time.



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It is understood that all of the LNG proponents are in discussions about entering into

short term gas swap arrangements to give them more flexibility in handling ramp-up

gas. Details of such arrangements tend to be kept as commercial in-confidence

transactions.

I.5 Power generation

Gas fired power generation offers a potentially flexible means of managing ramp up gas.

Many of the gas fired power plants, particularly the larger open cycle units located close

to the CSG supply points such as Braemar 1 and Braemar 2, with a combined capacity of

approximately 1,000 MW, have a history of operating at high capacity factors in the

past. Similarly, the 332 MW Oakey gas fired peaking power plant, operated by ERM

Power, has the ability to operate at continuous high loads.

Arrow Energy owns and operates the 519 MW Braemar 2 power plant and is factoring it

in as part of its ramp up gas strategy for its proposed Arrow LNG Project. As the timeline

for this project is some three to four years behind the other three LNG projects under

construction on Curtis Island, it may be able to handle some ramp up gas from the

others subject to the relativity between power dispatch prices and the offer price of

ramp up gas. Origin Energy has an agreement with Arrow for the dispatch rights of up to

300 MW from Braemar 2. Arrow also operates the small 30 MW Daandine base load

power plant adjacent to the Kogan North-Daandine Gas Fields.

QGC operates the 140 MW gas-fuelled combined-cycle Condamine power plant, close to

some of its producing gas fields. It has a power supply agreement with AGL. There is

very limited capacity to increase gas throughput through this plant.

Origin Energy operates the 630 MW Darling Downs power plant at Braemar, with gas

supplied from the Origin operated CSG gas fields of APLNG. While the capacity factor in

this station can be increased by a limited amount (60% to 85%), this has been factored

into the ramp-up of APLNG. Origin also owns and operates the 74 MW open cycle Roma

Power Station, which can be operated at much higher capacity factors. It is understood

that this has been factored into the APLNG ramp up strategy.

Santos has gas supply agreements with Stanwell Corporation to supply some gas to the

385 MW Swanbank E combined cycle power plant near Ipswich. This plant has limited

ability to increase its capacity factor.



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I.6 Gas storage

Santos has considerable gas storage capacity associated with its Cooper-Eromanga

basins conventional gas operations. The Cooper Bain is connected to the Wallumbilla

Gas Hub by APA’s the South West Queensland Gas pipeline. Santos is also developing, as

part of GLNG, the Roma Underground Gas Storage (RUGS) capability using some of the

depleted conventional gas reservoirs in the Surat Basin. This will be part of the GLNG

ramp up management plan.

Origin Energy has operated a small gas storage capability centred on its Kincora Gas

Plant near Surat. This facility, with an estimated capacity of 5 PJ, is integrated with the

Origin operated APLNG gas fields in the Surat Basin. Origin also has an interest in gas

storage capacity in the Cooper-Eromanga basins as part of the Cooper Basin Joint

Venture.

QGC has contractual arrangements with AGL Energy to supply gas storage capacity in

the depleted Silver Springs and Renlim Gas Fields, approximately 100 km south of

Wallumbilla. AGL has completed the first phase development of this facility, with new

injection wells, pipelines and compressors, as well as gas recovery systems, treatment

and compression. The initial storage/recovery capacity is understood to be 20 PJ, and is

being expanded to about 45 PJ. From earlier studies undertaken by Mosaic Oil, before

its acquisition by AGL, the ultimate gas capacity at Silver Springs/Renlim was estimated

to be 80-85 PJ.

All of Arrow’s gas production is CSG from its Surat and Northern Bowen Basin gas fields.

It has no known access to gas storage capacity.

I.7 Pipeline line pack

Gas pipelines can act as short term storage accumulators for natural gas. The line pack is

a recognized management tool to even out short term flow variations in gas pipelines,

usually over a 24 hour or weekend period. However, they offer little help in providing

longer term gas storage or for relatively large quantities of gas.



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Appendix J Specific ownership interest

In the case of international companies, Benaris has a 27.8% interest in the

Otway Gas Project operated by Origin energy. Benaris has an agreement with

Origin who takes their share of the output of the project which is currently

averaging 130 TJ/day. Similarly Toyota Tsusho has 11.25 % interest in the Origin

operated Bass Gas Project which is ramping up to 60 TJ/day. Toyota Tsusho has

an agreement with Origin to market its share of the gas production.

Toyota Tsusho also has CSG interests in two tenements in the southern Bowen

Basin which are operated by QGC. It is understood that the Japanese group has

a gas marketing agreement with QGC.

Harcourt Petroleum NL is the operating subsidiary of PetroChina for the

Dawson valley CSG fields that PetroChina acquired last year from Molopo

Energy. Harcourt has a Heads of Agreement with Liquefied Natural Gas Limited

(LNG Ltd) to supply gas to the proposed mid-scale LNG project planned for

Fisherman’s Landing at Gladstone.

In conventional gas, Mitsui E & P has a 25% interest in the Casino Project in the

Otway Basin operated by Santos. Gas production at Casino is approximately

100 TJ/day with Mitsui’s share being 25 TJ/day. The Casino Project has gas

contracts with AGL and Energy Australia as well as Santos taking its share (50%)

of production. Mitsui also has a 49% interest in the Meridian CSG Project at

Moura in the Dawson valley, 160 km west of Gladstone. The Meridian Project is

operated by Westside Corporation. Gas production at Meridian, approximately

15 TJ/day, is supplied to the Queensland Nitrates ammonium nitrate plant at

Moura (9 TJ/day) with the balance going to AGL.

AWE has a 25% interest in the Santos operated Casino Project in the Otway

Basin with a current net gas production to AWE of 25 TJ/day. The Company also

has a 46.25% interest in the Bass Gas Project located in Tasmanian waters but

connected by pipeline to the Lang Lang gas plant in SE Victoria. Bass Gas is

operated by Origin Energy which on-sells the gas on behalf of the project.

AWE’s net share of gas production from Bass Gas is approximately 28 TJ/day.

Beach Energy is a significant conventional gas producer in the Cooper-

Eromanga basins with net production of 21.8 PJ for year 2012 (60 TJ/day). The

bulk of Beach Energy’s gas production currently comes from the interests of

Delhi Petroleum in the Santos operated Cooper Basin Joint Venture (CBJV).

Delhi is a wholly owned subsidiary of Beach Energy. In the South Australian

sector, Delhi has a 20.21% interest while in the South West Queensland sector

Beach Energy has a 23.20% interest. Beach Energy also has interests in other

gas producing areas in the Cooper-Eromanga basins outside the CBJV.



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Beach Energy recently entered into a Gas supply agreement with Origin Energy

to supply 139 PJ over eight years with a potential to extend the contract for a

further two years. This contract which averages 17.3 PJ/year (47 J/day) will be

at gas prices linked to international oil prices for delivery ex-Moomba. A

number of financial analysts estimate that the base gas price will be of the

order of $7.00/GJ.

In terms of unconventional gas which includes tight conventional gas, deep coal

seam gas and shale liquids and gas, Beach Energy is a leader in this field in the

Cooper-Eromanga basins. It has announced 2C contingent resources of 2,533 PJ

at 31 December 2012. These comprise 638 PJ in conventional reservoirs and the

balance in tight un-conventional formations.

Chevron has finalised a farm-in agreement with Beach Energy, and JV partner

Icon Energy, over the Nappamerri Trough Project which has an estimated gas

resource of 100 Tcf (105,000 PJ). The Nappamerri Trough Project covers an

extensive area in the eastern part of the Cooper Basin encompassing PEL 218 in

South Australia and ATP 855 in Queensland. The initial farm-in gives Chevron a

30% interest in the SA tenement and 18% in the Queensland permit.

Drillsearch has an active exploration program for both oil and gas in the

Cooper-Eromanga basins. This encompasses both conventional and

unconventional resources. In unconventional gas, Drillsearch has entered into a

farm-in agreement with BG Group to develop the unconventional gas resource

to underpin further expansion of the QCLNG project at Curtis Island post 2018.

BG has rights to acquire up to 60% interest in ATP 940 for an expenditure of

$130 million over 5 years. Drillsearch estimates that the permit has a gas in

place resource of at least 22 Tcf (23,000 PJ).

Metgasco has entered into a Heads of Agreement with North Coast dairies to

supply gas to the Lismore dairy products plant as well as pursuing power

generation options. All of these projects are on hold following the policy

changes for CSG recovery recently brought in by the New South Wales

Government. In April 2013, ERM Power acquired a 12.83% equity interest in

Metgasco. ERM had previously investigated the potential for the Metgasco and

near-by Red Sky permits to supply gas to the proposed power station

development near Wellington. ERM Power has entered into a farm-in

agreement with Red Sky Energy over its Clarence-Moreton gas prospects in

Northern New South Wales. ERM is initially acquiring a 10% interest in two

permits (PEL’s 457 and 479) as well as becoming the permit operator. ERM has

also acquired a 9.5% equity interest in Red Sky.

Nexus Energy operates the Longtom conventional gas field, offshore Gippsland

Basin. The gas is processed by Santos through its Patricia-Baleen Gas Plant at

Orbost. The gas is then supplied to Santos for transportation to Sydney through

the Eastern Gas Pipeline operated by Jemena. On 14 May 2013, Nexus



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announced a significant change to its Gas Supply Agreement with Santos to

provide 40 TJ/day to end of 2018 (83 PJ in total) under a new, but unannounced

pricing structure. As part of the new arrangements Nexus proposes to drill two

further wells on the Longtom structure. The agreement also envisages that

production could ramp up to 100 TJ/day, the capacity of Santos’s Orbost gas

processing plant.

Senex Energy has conventional and unconventional gas resources in the

Cooper-Eromanga basins as well as CSG reserves in the Surat Basin. Senex

operates a number of permits in the eastern part of the Cooper-Eromanga

basins. A focus has been tight conventional gas as well as deep organic shales.

In PEL 115, it has a gross 1C contingent gas resource of 176 Bcf (185 PJ) with a

prospective gas resource of 2.9 Tcf (3,045 PJ). The company has an estimated

20 Tcf (21,000 PJ) unconventional gas in place across its operated permits.

In CSG, Senex has interests in four permits in the Surat Basin. Two are in JV with

QGC with QGC as the operator. Any gas produced from these permits (PL 171,

SXY 20% and ATP 574, SXY 30%) is likely to be sold to QGC unless some form of

gas swap can be negotiated. The other two permits (ATP 593 and 771) are

operated by Senex which has a 45% interest. The remaining 55% is held by

Arrow. Senex currently has 157 PJ of 2P reserves with 112 PJ in the QGC

operated tenements. Recently Senex made a significant new “conventional”

gas discovery in the Cooper Basin, in the Hornet for up to 2.9 Tcf of prospective

resources in a single reservoir, including 141 Bcf of “contingent resources”. The

Hornet find is conveniently located less than 30 km from APA Group’s major

gas pipeline taking gas from the Cooper Basin to Sydney. It lies across the

PEL115 licence owned by Senex and Orca Energy, and the PEL516 permit wholly

held by Senex. The shallow depth, low CO2, proximity to pipeline infrastructure

with available capacity, and conventional reservoir characteristics of this

resource are advantageous for early commercialisation and opens Senex up to

be an attractive target for a strategic gas producer play or for a retailer

WestSide Corporation is the operator of the Meridian SeamGas Project near

Moura. WestSide has a 51% interest in the project with Mitsui E & P holding the

balance. CSG production from the project is 15 TJ/day with gas being supplied

to nearby Queensland Nitrates and to AGL. Gross 2P gas reserves at Meridian

are 680 PJ with 3P reserves totalling 1,524 PJ. Much of this gas is uncontracted

though LNG Limited is known to be discussing a possible Gas Supply Agreement

for its proposed mid-scale LNG project at Fisherman’s Landing at Gladstone.

Westside has other exploration interests (25.5%) with some 3P CSG reserves in

the Southern and northern Bowen Basin in permits where the majority interest

holder (50%) is QGC.



159

IES Advisory Capability

Our team comes from a variety of backgrounds with extensive experience across all

areas of the energy markets. A focus on quality analysis, market insight and innovative

solutions for clients has helped IES grow and expand our presence over the past 30

years. Specifically our expertise comes from the following backgrounds:

Mergers and acquisitions, due diligence, strategy, contract reviews and

negotiations;

Physical spot and forward trading of electricity, gas and portfolio optimisation

and management;

Wholesale risk management solutions including financial and physical options;

Detailed market modelling, transmission studies and cost benefit analyses;

Innovative price risk management solutions for end-use customers;

Policy impacts and market frameworks for governments and regulators; and

Market development and reviews for overseas markets and organisations.

Expertise from extensive market experience is integral to properly develop solutions

specific to customer requirements in the context of dynamic energy markets. For

further information please visit http://www.iesys.com/ies/advisory/Home.aspx or

contact us directly.

Contacts

Jamie Summons – has extensive experience across the energy markets with senior roles

at Barclays Capital, Energy Australia, and TRUenergy formulating and executing

management strategies as well as consulting broadly throughout the entire sector.

Phone: 0433 400 055

[email protected]

Patrick Wang - has well-regarded experience across the power and gas markets highly

applicable in a trading environment focused on detailed analytics and modelling.

Phone: +612 8622 2216

[email protected]

http://www.iesys.com/ies/advisory/Home.aspx

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