2013.09.04 LNG Report.pdf

8/11/2019 2013.09.04 LNG Report.pdf

1/51

Projections of Gas Demand forLNG Export from Eastern andSouth Eastern AustraliaJuly 2013

8/11/2019 2013.09.04 LNG Report.pdf

2/51

AEMO 2013 GSOO | Eastern & South Eastern Australia: Projections of Gas Demand for LNG Export Terms of Use

I \ July 2013

Terms of Use

This document has been prepared by Core Energy Group Pty Limited, A.C.N. 110 347 085, holder of AFSL 307740(Core ) for the sole purpose of providing the Australian Energy Market Operator ( AEMO) with an analysis of gasdemand for Liqueed Natural Gas ( LNG) export from eastern and south eastern Australian states over the 2013 to2033 period.

This document has been prepared on the basis of a specic scope and does not purport to contain all the informationthat a particular party may require. The information contained in this document is general in nature and may notbe appropriate for all persons and it is not possible for Core to have regard to the investment objectives, nancialsituation and particular needs of each party who reads or uses this document. This document should not be reliedupon in any way to make any form of investment decision.

Core believes that the information contained in this document has been obtained from sources that are materiallyaccurate at the time of issue, but Core makes no representation or warranty as to the accuracy, reliability,completeness or suitability of the information contained within this document. To the extent permitted by law,Core, its employees, agents and consultants accept no liability for any statements, opinions, information or matter(expressed or implied) arising out of the information contained within this document.

Core Energy Group All material in this document is subject to copyright under the Copyright Act 1968(Commonwealth) and international law and permission to use the information in any form of document or report byany party other than AEMO, must be obtained in advance and in writing from Core.

8/11/2019 2013.09.04 LNG Report.pdf

3/51/ II Core Energy Group

Table of Contents AEMO 2013 GSOO | Eastern & South Eastern Australia: Projections of Gas Demand for LNG Export

Contents1. Introduction .................................................................................... .............................................................. 1

1.1. Terms of Reference............................................................................................................. .............. 1

1.2. Denitions ........................................................................................... .............................................. 1

2. Methodology .................................................................................. .............................................................. 3

2.1. Core GSOO LNG Scenarios ............................................................................................... .............. 3

3. Key Information Sources and Assumptions .............................................................................................. 6

3.1. Information Sources......................................................................................................................... 6

3.2. Assumptions ....................................................................................... .............................................. 6

4. Summary ........................................................................................ .............................................................. 8

4.1. Eastern and South Eastern Australia LNG Demand versus Supply ............................................. 8

4.2. Global LNG Demand .......................................................................................... .............................. 9

5. Global LNG Sector ......................................................................................... .............................................. 11

5.1. Overview ............................................................................................ .............................................. 11

5.2. Demand .............................................................................................. .............................................. 12

5.3. Supply Capacity .................................................................................. .............................................. 14

6. Global LNG Demand Outlook ....................................................................................... .............................. 16

6.1. Demand Projection ............................................................................................. .............................. 16

6.2. LNG Demand Drivers ......................................................................................... .............................. 16

6.3. LNG Demand Scenario ...................................................................................... .............................. 16

6.4. Global LNG Demand Sensitivities .................................................................................... .............. 18

7. Global LNG Supply Outlook ......................................................................................... .............................. 19

7.1. Overview ............................................................................................. .............................................. 19

7.2. Global Contract Prole ....................................................................................... .............................. 19

7.3. Expected Decline of Existing Supply Capacity .............................................................................. 20

7.4. Expected Addition of New Supply Capacity .................................................................................. 20

7.5. Proposed/Likely Future Global LNG Supply Sources .................................................................... 20

7.6. Competing Sources of Supply ......................................................................................... .............. 22

8. Eastern and South Eastern Australia LNG Demand ................................................................................. 25

8.1. Overview ............................................................................................. .............................................. 25

8.2. Committed Projects ............................................................................................ .............................. 25

8.3. Proposed Projects ............................................................................................... .............................. 26

8.4. Key Drivers for New Eastern and South Eastern Australian LNG Supply ................................... 26

8.5. Projected Gas Demand Eastern and South Eastern Australia LNG ........................................... 27

8/11/2019 2013.09.04 LNG Report.pdf

4/51

AEMO 2013 GSOO | Eastern & South Eastern Australia: Projections of Gas Demand for LNG Export Table of Contents

III\ \ July 2013

9. Key Issues, Risks and Uncertainties ................................................................................... ........................ 30

9.1. Ramp Gas .................................................................................. ........................................................ 30

9.2. CSG Water Production ............................................................................................. ........................ 31

9.3. Development Schedule ............................................................................................ ........................ 31

9.4. Infrastructure ............................................................................................ ........................................ 31

10. Key Future Events/Signposts .............................................................................................. ........................ 32

10.1. Signposts Relating to Asia Pacic LNG Demand and Supply ...................................................... 32

10.2. Signposts Relating to Eastern and South Eastern Australian LNG .............................................. 32

11. Validation ............................................................................................. ........................................................ 34

11.1. Comparison with 2012 GSOO - Eastern and South Eastern Australia LNG ................................. 34

11.2. Comparison with Third Party Sources - Global LNG Demand and Supply .................................. 35

12. Summary and Conclusion .................................................................................. ........................................ 36

References .................................................................................. ........................................................................ 38

Acronyms ................................................................................... ........................................................................ 40

Attachment 1: Terms of Reference ............................................................................................ ........................ 41

8/11/2019 2013.09.04 LNG Report.pdf

5/51/ / IV Core Energy Group

List of Figures AEMO 2013 GSOO | Eastern & South Eastern Australia: Projections of Gas Demand for LNG Export

List of FiguresFigure 2.1 | Core Project Methodology - AEMO GSOO LNG Demand ..................................................... 4

Figure 2.2 | Core Energy Model Architecture LNG Demand and Supply .............................................. 5

Figure 4.1 | Eastern and South Eastern Gas Demand for LNG Export, PJ p.a. ........................................ 8

Figure 4.2 | Gas Demand Sensitivities for LNG, PJ ................................................................................... 9

Figure 4.3 | Global LNG Demand versus Contracted LNG Supply ........................................................... 9

Figure 5.1 | Major LNG Importers, Mt ........................................................................................... .............. 12

Figure 5.2 | LNG Demand by Consuming Asia Pacic Region/Country, 2012 .......................................... 12

Figure 5.3 | Historic Global LNG Supply ....................................................................................... .............. 14

Figure 5.4 | Major LNG Liquefaction Capacity, Mt ..................................................................................... 14

Figure 5.5 | LNG Shipping Routes ................................................................................. .............................. 15

Figure 6.1 | Global LNG Demand (Global LNG Reference Scenario) ....................................................... 16

Figure 6.2 | Global LNG Demand Sensitivity Analysis .............................................................................. 18

Figure 7.1 | Location of Existing LNG Production (Liquefaction) Facilities ............................................... 19

Figure 7.2 | Global LNG Demand - Contracted and Not Yet Contracted ................................................... 19

Figure 7.3 | Global LNG Reference Scenario Liquefaction Capacity, Mt ................................................... 21

Figure 7.4 | Global LNG Reference Scenario Demand-Supply Balance, Mt ............................................. 21

Figure 7.5 | Global LNG Reference Scenario Demand-Supply Balance, Mt ............................................. 21

Figure 7.6 | LNG Supply Cost Estimates for New Developments ............................................................. 24

Figure 8.1 | Eastern and South Eastern Gas Demand for LNG Export, PJ p.a. ........................................ 28

Figure 8.2 | Eastern and South Eastern Australia Gas Demand Sensitivities for LNG, PJ ..................... 29

Figure 11.1 | 2013 Projections versus 2012 GSOO ...................................................................................... 34

Figure 11.2 | 2013 Projections versus 2012 GSOO (with 2013 methodology) ........................................... 35

Figure 11.3 | Core Global LNG Reference Demand Scenario versus Third Party Sources, Mt ................ 35

Figure 12.1 | Eastern and South Eastern Gas Demand for LNG Export, PJ p.a. ...................................... 37

Figure TOR | AEMO RFP Projections of Gas Demand for Liqueed Natural Gas (LNG) Export .......... 41

8/11/2019 2013.09.04 LNG Report.pdf

6/51

AEMO 2013 GSOO | Eastern & South Eastern Australia: Projections of Gas Demand for LNG Export List of Tables

V \ July 2013

List of TablesTable 1.1 | Report Denitions ............................................................................................... ........................ 1

Table 5.1 | Major Global LNG Importing Countries - Existing and Planned ............................................. 11

Table 5.2 | Global LNG Consumption (Descending Volume Order), Mtpa ............................................... 13

Table 7.1 | Global LNG Projects Under Construction ................................................................................. 20

Table 8.1 | Planning and 7 Train Scenario Summary.................................................................................. 28

8/11/2019 2013.09.04 LNG Report.pdf

7/51

1. Introduction AEMO 2013 GSOO | Eastern & South Eastern Australia: Projections of Gas Demand for LNG Export

| 1 Core Energy Group

1. Introduction

1.1. Terms of Reference

The objective of this report is to present an independent assessment of the most likely gas demand 1 for LNGproduction 2, in eastern and south eastern Australia 3, during the 20-year period to 2033.

This Report is based on a detailed analysis of the outlook for global LNG demand and supply, including, in particular,the Asia Pacic importing region (as dened in Sections 1.2), which is assessed as the most likely end market for

Australian LNG.

The Request For Proposal ( RFP) provided by AEMO for this engagement is presented as Attachment 1 to thisreport.

1.2. Denitions

Unless otherwise stated, the following denitions will apply throughout this report:

Table 1.1 | Report Denitions

$ or dollars or United States ofAmerica Dollar (USD)

USD, in 2013 real terms.

AEMO Planning Scenario A scenario developed by AEMO for the 2013 National Electricity ForecastingReport ( NEFR) and used consistently in the 2013 Gas Statement ofOpportunities ( GSOO ). This Scenario assumes only committed projects as atJanuary 2013 (6 trains) come online over the projection period. It is noteworthythat at the time of this Report, there remained 6 committed trains in easternand south eastern Australia. 4

Asia Pacic Importing Region A broad geographical region including China, Japan, India, South Korea, Taiwan,Other south east ( SE) Asia.

Atlantic Importing Region A broad geographic region including the United States of America ( USA),Central and South America and Europe.

Coal Seam Gas (CSG) Natural gas contained in coal deposits. Generally high proportion of methane,but may be produced with variable amounts of inert or non-inert gases.

Conventional Gas Natural gas that is extracted from underground reservoirs using traditionalexploration and production methods.

Core Global LNG ReferenceScenario

A scenario developed by Core which is estimated to represent the most likelyscenario of global LNG demand.

Core 7 Train Scenario A scenario developed by Core based on assessment of the committed andproposed projects in eastern and south eastern Australia, and global LNGmarket dynamics. Core assesses this scenario to have a high probability (>50%)of likelihood. It differs from the AEMO Planning Scenario in that it considersproposed projects as well as committed projects.

De-water (a well) To remove water from coals to enable gas to be produced.

Eastern and South Eastern

Australia

The states and territories of Queensland, New South Wales, the Australian

Capital Territory, Victoria, South Australia and Tasmania.

1 Petajoules per annum ( PJ p.a. ).2 Gas demand as at the front of a transmission line (excluding losses at the eld).3 Comprising the states and territories of Queensland, New South Wales, the Australian Capital Territory, Victoria, South Australia and Tasmania.4 The AEMO Planning Scenario is based on AEMOs best guess of the future direction of major drivers; desgined to include any policy or other changes that canbe predicted with reasonable certainty; designed as a central growth scenario; includes currently legislated carbon policies, based on the Treasury core scenario andcurrently estimated rates of development of new technologies.

8/11/2019 2013.09.04 LNG Report.pdf

8/51

1. IntroductionAEMO 2013 GSOO | Eastern & South Eastern Australia: Projections of Gas Demand for LNG Export

2 | July 2013

Effective Annual Output Core has assumed that effective annual output of an LNG plant is 93% of itsname plate capacity, based on a typical operating capacity factor for existingLNG plants which accounts for periods of maintenance and other non-productive times.

Gas Demand Gas eld production to meet LNG production requirements measured at theentry to the transmission line, which excludes an assumed 4% of produced gas

lost due to processing.Gas Production Gas eld production to meet LNG production requirements, measured at the

well-head, before any subsequent use or losses.

Global LNG Reference Scenario A scenario developed by Core representing Cores view of the most likelyscenario of global LNG demand.

LNG Demand Demand for nal LNG production, after any use and/ or losses incurred from theprocessing of gas to point of export.

Unconventional Gas Natural gas that is not found in permeable sandstone reservoirs as is the case

for conventional gas (eg tight gas, shale gas).

Year A reference to a year is a calendar year unless otherwise stated.

8/11/2019 2013.09.04 LNG Report.pdf

9/51

2. Methodology AEMO 2013 GSOO | Eastern & South Eastern Australia: Projections of Gas Demand for LNG Export


2. MethodologyCore has developed a tailored LNG forecasting methodology to meet the specic requirements of AEMO for the 2013GSOO.

This methodology has been designed with three objectives in mind:

To dene the expected volume and timing of gas consumption associated with existing, committed LNG projects ineastern and south eastern Australia.

To determine projected global and Asia Pacic LNG demand relative to existing, contracted global and Asia PacicLNG demand, to derive a best estimate (Reference Scenario) of the volume and timing of projected LNG demandwhich is yet to be contracted.

Determine what portion of projected Asia Pacic demand (the most likely market for Australian LNG generally),which is yet to be contracted, is likely to be supplied by eastern and south eastern Australian LNG projects versuscompetitive supply sources.

Section 2.1.1 presents the methodology used by Core to derive a Global LNG Reference Scenario of LNG demand andsupply.

2.1. Core GSOO LNG Scenarios

Core has developed a systematic approach to deriving scenarios of future LNG demand and supply, utilising aproprietary database and modelling system. This enables feasible demand and supply scenarios to be developed at aninternational level, with a view to evaluating implications for the Australian LNG sector, and more specically from theperspective of this Study, implications for eastern and south eastern Australia gas supply.

In addition, Core has assessed the conversion factor and losses associated with the production of LNG (see Section 1for details) and the likely ramp-up prole for each of the trains.

As described in Section 1, AEMOs Planning Scenario consists of committed projects - that is 6 trains. Core hascompleted an assessment of current market conditions, company announcements and project progress to date,to assess the most-likely start-up and ramp prole of these facilities - giving rise to the AEMO Planning Scenarioprojections.

In addition to the Planning Scenario, Core has developed a 7 Train Scenario, which is Cores view of a probable(>50% likelihood) forward trajectory having consideration to committed and proposed projects. The methodology fordeveloping this Scenario is discussed in Section 2.1.1.

2.1.1. Core 7 Train Scenario: Gas Demand for LNG in Eastern and South Eastern Australia

The Core system has been tailored to meet the specic needs of AEMO for the 2013 GSOO. The six step processadopted is summarised in Figure 2.1.

8/11/2019 2013.09.04 LNG Report.pdf

10/51

2. MethodologyAEMO 2013 GSOO | Eastern & South Eastern Australia: Projections of Gas Demand for LNG Export

4 | July 2013

Figure 2.1 | Core Project Methodology - AEMO GSOO LNG Demand

1. Global Demand Outlook: 2. LNG Supply: 3. Uncontracted Demand:

6. Validation: 5. Eastern and South Eastern Australia LNG:

4. Gas Demand for CommittedEastern and South EasternAustralia LNG Projects:

Derive historical and projectedprimary energy use for eachcountry/region

Derive historical and projected gasshare of total primary energy usefor each country/region

Derive historical and projected LNGshare of total gas demand for eachcountry/region

Define existing global liquefactionand regasification capacity

Define contract profile by country/region

Define all potential new LNGsources and cost of production

Define LNG demand scenarios bycountry/ region - based on 1

Define expected contracted supplyscenarios to meet projecteddemand - based on 2

Derive projected demand which is

not yet contracted and thusavailable to new LNG supply

Define committed projects

Define other potential projects

Analyse cost of LNG production

Define gas requirement on annualbasis based on liquefaction capacity,LNG contracts and gas requirementfor own use

Analyse global cost competitivenessof potential new east and south east

Australian supply

Define Reference Scenario of gasdemand for LNG projects andundertake sensitivity analysis

Compare global LNG supply anddemand findings and assessment ofeastern and south eastern AustraliaLNG growth potential against thirdparty sources

Explain any variance with view tovalidation of findings

Source: Core Energy Group; June 2013.

8/11/2019 2013.09.04 LNG Report.pdf

11/51

2. Methodology AEMO 2013 GSOO | Eastern & South Eastern Australia: Projections of Gas Demand for LNG Export


The Core approach to assessing the market for eastern and south eastern Australian LNG comprises four primaryelements:

Demand Outlook | dene economic growth and Government policy scenarios for importing countries as a basisfor deriving projections of total primary energy demand and expected gas demand relative to alternative energysources.

Energy Cost and Price Analysis | develop scenarios of future energy supply costs and prices from the perspectiveof importing countries, including consideration of technological advances, as a basis for deriving future gas and LNGcosts and price paths relative to alternative energy sources.

Natural Gas Supply Options Analysis | analyse total gas demand and alternative gas sourcing options, byimporting country, as a basis for deriving projections of LNG demand.

LNG Supply Options Analysis | global LNG supply is modelled by project to derive the full universe of supplyoptions. Preferred supply options are derived for each importing country, having regard to specic volume, cost/price, timing, foreign policy and other considerations.

In simple terms Total Gas Demand is derived for each country/region by reference to economic growth, policy andprice outlook. In order to derive projected LNG imports, the level of domestic gas production and international pipelinegas 5 is deducted from Total Gas Demand.

Figure 2.2 illustrates Cores approach to global LNG scenario modelling.Figure 2.2 | Core Energy Model Architecture LNG Demand and Supply

Total Gas Demand

Domestic GasProduction

less

International PipelineGas Purchases

LNG Imports

less

equals

Energy & EnvironmentPolicyEconomic Growth

Substitution from Coalto Gas, Nuclear and

Renewable Technologies

Conventional andUnconventional Gas

Foreign Policy andImport Economics G

a s

P r i c e

O u

t l o o

k a n

d

i m p a c

t o n

t o t a l e n e r g y c o s t s

a n

d c o m p e

t i t i v e n e s s

LNG Supply Availability

LNG Demand (mtpa) 2013 2014 2035

Country 1

Country 2

Country x

Total Regional Demand

LNG Supply (mtpa) 2013 2014 2035

LNG 1

LNG 2

LNG x

Total Supply Capacity

T e c

h n o

l o g y c

h a n g e ,

c o s t

a n

d p r i c e

i m p

l i c a

t i o n s

Realities and Economics

Source: Core Energy Group, 2013.

5 Gas ows via pipelines from other countries.

8/11/2019 2013.09.04 LNG Report.pdf

12/51

3. Key Information Sources and AssumptionsAEMO 2013 GSOO | Eastern & South Eastern Australia: Projections of Gas Demand for LNG Export

6 | July 2013

3. Key Information Sources and AssumptionsTo develop projections of eastern and south eastern Australia LNG demand and associated gas supply, Core has reliedupon a wide range of publicly disclosed information and made a series of key assumptions which are referencedbelow.

3.1. Information Sources

A wide range of source documents have been reviewed, relating to estimates of international and domestic gas andLNG demand, liquefaction capacity, project timing, and other factors (refer to the References Section at the end of thisreport), including but not limited to:

Government plans, budget and policy documents.

Third party economic analysis and projections.

Third party energy, gas and LNG demand, supply, cost and price analysis.

Bloomberg LNG and international gas and economic analysis.

Websites of major Australian and international energy, gas and LNG industry participants.

3.2. Assumptions

Core has made the following assumptions to develop projections of gas demand for LNG production:

Core has assumed that 14.5% 6 of produced gas is consumed in production, transmission and liquefaction activities.Details are as follows:

> Cores assumption of this 14.5% own consumption is derived from:

- A 3 to 5% loss and use in relation to eld and processing facilities 7.

- A 1 to 2% loss and use in relation to the transmission network.

- An 8 to 10% loss and use in relation to the liquefaction process.

> Core acknowledges that losses vary from project to project.

Core has assumed that gas demand for LNG includes, in addition to the gas liqueed, all gas lost or used totransport and power the LNG facility (10.5% of gas produced) but excluding gas lost in production (4% of gasproduced).

Core has assumed that there is no electrication of any of the liquefaction facilities, as instructed by AEMO, whichis consistent with the NEFR.

Core has assumed that effective annual output of an LNG plant is 93% of its nameplate capacity, based on a

typical operating capacity factor for existing LNG plants which accounts for periods of maintenance and other non-productive times. For example an Australia Pacic LNG ( APLNG) train with a nameplate capacity of 4.5 Milliontonnes per annum ( Mtpa ) is expected to produce and sell 4.2 Mtpa.

The objective of this Report is to forecast gas demand for LNG production and therefore does not include anydemand from domestic activities associated with LNG production. For example, Core projections would not includeany gas demand associated with manufacturing activities associated with fabricating the LNG trains et al.

Core has assumed that 1 Mt of LNG is equivalent to 55 PJ of gas 8.

Core has had regard to key drivers dened in AEMOs Planning Scenario 9 as a basis for developing projectionsincluded in this report. Furthermore, Core has relied upon the assumption that the AEMO Planning Scenario

6 14.5% is derived from the midpoint of the total ranges of each of the assumed liquefaction, transmission and processing losses.

7 Consistent with historic data such as publicly available statistics from the Queensland Department of Energy which suggest that from 1 January 2005through 30 June 2010, approximately 654 PJ of CSG was produced in Queensland ( QLD), with approximately 4% used in production and approximately 2% aredor vented. Core has assume that vented or ared gas has historically been a function of pilot testing and will be minimal in the production phase but additional energyrequirements for water desalination is expected to increase processing losses to 5%. Note that the specic breakdown of the 14.5% of total gas lost is not consideredin Cores reporting/calculation of demand.8 According to Sempra LNG, 1 tonne of LNG is equivalent to 54.7 gigajoules ( GJ ) of energy. Therefore 1 Mt is equivalent to approximately 55 PJ.9 AEMO has developed a central Planning Scenario that represents their best estimate of how the future will develop given the currently known and well advancedand anticipated changes having regard to a number of key drivers. These include economic growth, policy, gas and oil prices and generation technology and development.A denition of AEMOs Planning Scenario is available here .
http://www.aemo.com.au/Consultations/National-Electricity-Market/Open/~/media/Files/Other/planning/2418-0005%20pdf.ashxhttp://www.aemo.com.au/Consultations/National-Electricity-Market/Open/~/media/Files/Other/planning/2418-0005%20pdf.ashx

8/11/2019 2013.09.04 LNG Report.pdf

13/51

3. Key Information Sources and Assumptions AEMO 2013 GSOO | Eastern & South Eastern Australia: Projections of Gas Demand for LNG Export


consists only of committed projects, consistent with AEMOs NEFR publication.

8/11/2019 2013.09.04 LNG Report.pdf

14/51

4. SummaryAEMO 2013 GSOO | Eastern & South Eastern Australia: Projections of Gas Demand for LNG Export

8 | July 2013

4. Summary

4.1. Eastern and South Eastern Australia LNG Demand versus Supply

This report presents projections of gas demand for LNG production from eastern and south eastern Australia undertwo scenarios: The AEMO Planning Scenario, which consists of the 6 committed trains, and the Core 7 Train Scenario,

which comprises the 6 committed projects as well as one additional LNG train. Details for each of these facilities areprovided below.

Two Queensland Curtis LNG ( QCLNG) trains starting LNG production in 2014 and reaching full capacity in 2016,with maximum gas demand 10 of approximately 486 PJ per annum ( p.a. ) thereafter. This is a committed project.

Two APLNG trains - starting LNG production in 2015 and reaching full capacity in 2017, with maximum gas demandof approximately 514 PJ p.a. thereafter. This is a committed project.

Two Gladstone LNG ( GLNG) trains starting LNG production in 2015 and reaching full capacity in 2019, withmaximum gas demand of approximately 446 PJ p.a. thereafter. This is a committed project.

One additional LNG train, Train 7, likely using Arrow LNG gas, requiring maximum annual gas demand ofapproximately 229 PJ p.a. 11

In addition there is scope for further spot sales; representing the level of gas required to utilise the balance of LNGliquefaction capacity (difference between practical total plant capacity and contracted production capacity). Howeverthe following Figure excludes such sales, which are expected to be relatively immaterial for the purpose of this Study.

Figure 4.1 summarises projected gas demand for LNG production under the AEMO Planning and Core 7 TrainScenario.

Figure 4.1 | Eastern and South Eastern Gas Demand for LNG Export, PJ p.a.

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2014 2016 2018 2020 2022 2024 2026 2028 2030 2032

Projected Eastern and South Eastern Australia GasDemand for LNG | PJ

QCLNG GLNG APLNG Train 7

AEMO 2013 - Planning ScenarioSource: Core Energy; June 2013.

Core has undertaken sensitivity analyses to determine the impact of a movement of one or more key assumptionson projected gas demand. Resultant high and low sensitivity scenarios are presented below based on changes in keyassumptions regarding the number and timing of LNG developments and associated ramp up of production.

The High Demand Sensitivity assumes an additional 229 PJ p.a. of LNG gas demand from 2023:

Core 7 Train Scenario; plus

An additional train developed via one of the above listed projects (QCLNG, APLNG, GLNG), requiring additional gasfeed at full capacity of approximately 229 PJ p.a., from 2023; plus

An accelerated commencement of Train 7 gas production to 2019.

The Low Demand Sensitivity involves a slower ramp up through to utilisation of two train plant capacity of each

10 Calculation of gas demand for LNG ignores an assumed 4% of produced gas lost in processing activities, and assumes 10.5% of produced gas is lost intransmission and liquefaction activities. See Section 3.2 for further detail regarding this assumption.11 It is noteworthy that Arrow LNG has approximately 9,500 PJ of reserves at the date of this report and that the assumed train would require approximatelyhalf of this reserve, leaving additional capacity to feed into LNG or domestic markets.

Gas Demand for LNG, PJ

Project 2015 2017 2019 2021-33

QCLNG 430 486 486 486

GLNG 55 320 446 446

APLNG 138 514 514 514

Train 7 0 0 0 229

Total 624 1,320 1,446 1,675

AEMO 2013PlanningScenario

624 1,320 1,446 1,446

8/11/2019 2013.09.04 LNG Report.pdf

15/51

4. Summary AEMO 2013 GSOO | Eastern & South Eastern Australia: Projections of Gas Demand for LNG Export


project and a permanent deferral of 229 PJ p.a. of capacity:


Train 7 does not proceed, with the 229 PJ p.a. of gas production used to service the other six trains (and someportion going to the domestic market).

Figure 4.2 | Gas Demand Sensitivities for LNG, PJ

0

500

1,000

1,500

2,000

2,500

3,000

2014 2016 2018 2020 2022 2024 2026 2028 2030 2032

Projected Eastern & South Eastern Australia Gas Demandfor LNG | PJ

Core - 7 Trains Low SensitivityHigh Sensitivity 2012 GSOO - PlanningGSOO 2012 - Decentr al ised Wor ld 2012 GSOO - Sl ow Rate of C hang e

AEMO 2013 - Planning Scenario

Source: Core Energy Group; 2013.

4.2. Global LNG Demand

To determine the potential for future LNG production from eastern and south eastern Australia to 2033, Core hasundertaken an assessment of future global LNG demand and supply. The objective of this element of the study is two-fold:

To dene the level of future Asia Pacic demand which is not yet contracted.

To determine whether eastern and south eastern Australia LNG sources are expected to meet any part of demandwhich is yet to be contracted.

The following graph presents Cores projection of demand and demand not yet contracted under Cores Global LNGReference Scenario.

Figure 4.3 | Global LNG Demand versus Contracted LNG Supply

250 Mt280 Mt

240 Mt

185 Mt143 Mt

32 Mt41 Mt

110 Mt198 Mt

260 Mt

0

50

100

150

200

250

300

350

400

450

2015 2020 2025 2030 2033

Global LNG Demand versus Contracted LNG Supply

Contracted Supply Demand - Not Yet Contracted (Reference Scenario)


Core analysis indicates that well over 210 Mt of competitive LNG supply through projects currently proposed or inFront End Engineering and Design ( FEED) is available to meet this uncontracted demand over the period to 2033.In addition, Core estimates that there are a range of potential projects with additional capacity of over 150 Mt. As

8/11/2019 2013.09.04 LNG Report.pdf

16/51

4. SummaryAEMO 2013 GSOO | Eastern & South Eastern Australia: Projections of Gas Demand for LNG Export

10 | July 2013

a result, Core is of the opinion that there is limited scope for eastern or south eastern Australia LNG demand toeffectively compete in this market given expectations of an uncompetitive cost structure under current and expectedmarket conditions.

8/11/2019 2013.09.04 LNG Report.pdf

17/51

5. Global LNG Sector AEMO 2013 GSOO | Eastern & South Eastern Australia: Projections of Gas Demand for LNG Export


5. Global LNG SectorThis Section of the Report provides an overview of the history and current realities of the global LNG market. Inparticular, this includes the Asia Pacic market, which is considered to be the most likely market for any additionalLNG supply from east and south eastern Australia, due largely to proximity and associated transport cost advantage.

5.1. Overview

LNG export commenced in 1965 with a cargo shipped from Algeria to the United Kingdom ( UK), followed bycargoes from Alaska to Japan in 1969. There are now 17 LNG exporting countries and 27 countries globally eitherimporting today or with import terminals under construction.

Australia began exporting LNG from the North West Shelf ( NWS ) project in Western Australia ( WA) in 1989.

For the purpose of this Report, Core considers global LNG markets to comprise two primary regions - Asia Pacic andAtlantic.

Table 5.1 | Major Global LNG Importing Countries - Existing and Planned

Asia Pacic Atlantic

Asia Pacic North America South & CentralAmerica Europe Middle East

Japan

South Korea

Taiwan

China

India

Singapore 1

Thailand1

Malaysia 1

Indonesia 1

USA

Canada

Argentina

Chile

Brazil

Mexico

Puerto Rico

France

Italy

Spain

UK

Netherlands

Turkey

Greece

Portugal

Belgium

Kuwait

United Arab Emirates


Note 1: Imports to begin in 2012-2014.

8/11/2019 2013.09.04 LNG Report.pdf

18/51

5. Global LNG SectorAEMO 2013 GSOO | Eastern & South Eastern Australia: Projections of Gas Demand for LNG Export

12 | July 2013

5.2. Demand

Over the 20-year period ending 2012, LNG trade has increased approximately four-fold, from 60 Mt in 1992 to 241 Mtin 2012. 12 As at the end of 2012, LNG accounted for approximately 10% of global natural gas consumption. 12

Figure 5.1 | Major LNG Importers, Mt

0 30 60 90 120 150306090120150

74

114

0

50

100

150

2012 2033

TurkeyJapan

South Korea

India

China

Indonesia

Vietnam

Singapore

Major Established LNG Importers Rapidly Emerging LNG Importers

United Kingdom

Spain

Taiwan

South East Asia

Total Atlanti c*

Asia-Pacic

0

50

100

150

200

250

300

2012 2033

Total Asia Paci c

0 120 240 360 480 600

2012

2033

Total World

167

289

241

403

Growth | 40 Mt

Greece

Growth | 121 Mt

Portugal

Belgium

Source: Core Energy Group; 2013.Note : The statistics refer to total demand in Cores GLobal LNG Reference Scenario. *Includes Middle East.

During 2012 an estimated 167 Mt 12 of LNG was consumed across the Asia Pacic region. The distribution ofconsumption between major consuming countries is presented in Figure 5.2.

Figure 5.2 | LNG Demand by Consuming Asia Pacic Region/Country, 2012

India9%

South Korea22%

Japan52%

Thailand1%

LNG Demand byConsuming Asia

Pacific Region/Country% of Total

Taiwan7%

China9%

Source: Core Energy Group; BP Statistical Review of World Energy 2013.

12 Core Energy analysis and BP Statistical Review of World Energy 2013 data.

8/11/2019 2013.09.04 LNG Report.pdf

19/51



In 2012 Global LNG demand was 241 Mt. Major importers are presented in the following Table.

Table 5.2 | Global LNG Consumption (Descending Volume Order), Mtpa

Country/Region 2012 LNGDemandLNG % Share of Total

Regional Gas Demand Core Comment/Analysis

Japan 87 Mt 99% Increased by 19 Mt over 2010 level asa result of nuclear capacity shutdown.This is approaching the practical limit ofJapanese import capacity.

Europe 51 Mt 14% Weaker economic performance is limitingLNG demand.

South Korea 37 Mt 100% Government stated objective of reducinglevel of gas dependency.

North and South America 20 Mt 14% Including 4 Mt in the USA which isexpected to fall away as the USA begins

LNG exports after 2015.India 15 Mt 37% Government plan includes increased gas

use but high cost of LNG expected tobe a limiting factor and level of growth inlocal production uncertain.

China 15 Mt 14% Government plan includes increased gasuse but high cost of LNG expected tobe a limiting factor and level of growth inlocal production and pipeline imports isuncertain.

Taiwan 12 Mt 100% Targeting 20 Mt by 2025.

Thailand 1 Mt 3% First imports in 2012.

Total World 241 Mt 10%

Source: Core Energy analysis, data from BP Statistical Review of World Energy 2013. Total may not add due to rounding.

Over the Study period to 2033, the following countries are expected to begin importing LNG:

Malaysia | Commissioning of the LNG import terminal in 2013.

Indonesia | First imports scheduled for second half 2013.

Singapore | First imports scheduled for second half 2013.

Pakistan, Bangladesh, Sri Lanka,Vietnam, Philippines | No rm start dates.

8/11/2019 2013.09.04 LNG Report.pdf

20/51

5. Global LNG SectorAEMO 2013 GSOO | Eastern & South Eastern Australia: Projections of Gas Demand for LNG Export

14 | July 2013

5.3. Supply Capacity

As illustrated in Figure 5.3, the Middle East and Asia Pacic together account for the majority of LNG supply overrecent years.

Figure 5.3 | Historic Global LNG Supply

0

50

100

150

200

250

300

2005 2006 2007 2008 2009 2010 2011 2012

Historical GlobalLNG Supply | Mt

Asia Pacific Europe Africa Middle East North America South America

Source: Core Energy Group with data from BP Statistical Review of World Energy 2013.

Australias 2012 production of 20.7 Mt, represents approximately 9% of global LNG supply in that year.

The following Figure illustrates the potential level of growth in LNG liquefaction capacity by major potential exporterfrom 2012 to 2033. Of particular note is Cores projected growth in LNG supply capacity from North America, Australia,Russia, Nigeria and Mozambique.

Figure 5.4 | Major LNG Liquefaction Capacity, Mt

0 30 60 90 120 150306090120150

United Arab Emirates

Major Established LNG Exporters Rapidly Emerging LNG Exporters

United Statesof America

Canada

Indonesia

Australia

Qatar

Malaysia

Russia

Algeria

0

25

50

75

100

2012 2033

20120

25

20330

25

50

2012 2033

0

25

2012 2033

0

25

2012 2033

0

25

50

2012 2033

0 120 240 360 480 600

2012

2033

Total World

0

25

50

75

100

2012 2033

77.5 77.5

17.5

26.3

020

0

85.6

269.9

575.9

25.5 22.1

25.4 25.4

9.6

48.9

Growth | 97 Mt

Reduction | 3.4 Mt

Minimal Change

Growth | 39.3 Mt

Minimal Change

0

25

2012 2033

5 5

Minimal Change

Growth | 8.8 Mt

Growth| 20 Mt

Growth | 85.6 Mt

Growth | 306 Mt

Nigeria

21.9

39.9

0

25

50

2012 2033Mozambique

0

20

0

25

2012 2033

Growth | 18.0 Mt

Growth | 20.0 Mt

23.1

120.2

0

25

50

75

100

125

2012 2033


8/11/2019 2013.09.04 LNG Report.pdf

21/51



5.3.1. LNG Shipping

The following Figure presents a series of major LNG shipping routes together with a high level guide to the cost ofshipping to Asia from those locations.

Figure 5.5 | LNG Shipping Routes

0 30 60 90 120 150306090120150

United Statesof America

Canada

Australia

Mozambique

China

Exist ing LNG Shipping Routes Indicative LNG Shipping Routes

2.70

0.800.70

0.80

0.80 USD per MMBtu

1.00

Source: Core Energy Group; 2013.Note: Million British Thermal Units ( MMBtu ). One MMBtu is approximately equal to 1.055 GJ.

8/11/2019 2013.09.04 LNG Report.pdf

22/51

6. Global LNG Demand OutlookAEMO 2013 GSOO | Eastern & South Eastern Australia: Projections of Gas Demand for LNG Export

16 | July 2013

6. Global LNG Demand Outlook

6.1. Demand Projection

Growth in global LNG demand is projected to be concentrated in the Asia Pacic region as shown in Figure 6.1. This isattributable primarily to continuing growth in LNG demand in China and India and new demand in Malaysia, Singapore,

Thailand and Indonesia.Figure 6.1 | Global LNG Demand (Global LNG Reference Scenario)

0

50

100

150

200

250

300

350

400

450

2005 2010 2015 2020 2025 2030

Asia Pacific Europe Middle East North America South America

Global LNG Demand (Reference Scenario) | Mt

Historic

Source: History - BP Statistical Review of World Energy; Projections - Core Energy Group.

6.2. LNG Demand Drivers

Growth in global LNG demand is a largely a function of the following factors: Population growth.

Growth in economic activity.

Growth in primary energy demand.

Gas share of primary energy demand.

Competitiveness of LNG relative to alternative gas sources.

Although this report makes generic references to LNG demand, the demand and supply drivers vary signicantlybetween regions. For this reason, Core has completed analyses on each of these factors on a region-by-region basis

to develop a Reference LNG Demand Scenario.

6.3. LNG Demand Scenario

The Global LNG Reference Scenario presented in Figure 6.1 represents Cores view of most likely outlook for globalLNG demand. This scenario has been developed following consideration and modelling of the factors listed in Section6.2.

This Section contains specic comments on the Asia Pacic and Atlantic Region elements of the Global LNGReference Scenario.

8/11/2019 2013.09.04 LNG Report.pdf

23/51

6. Global LNG Demand Outlook AEMO 2013 GSOO | Eastern & South Eastern Australia: Projections of Gas Demand for LNG Export


6.3.1. Asia Pacic Region

Japan:

Japan is currently the largest importer of LNG, sourcing approximately 87 Mt in 2012.

Although Japan is the largest importer, historic growth in LNG demand was relatively slow until the 2011 Fukushimadisaster resulted in the shutdown of nuclear reactors, placing increased pressure on gas-red power stations andan increase in LNG demand of 18 Mt (2012 year compared to 2010 year).

Projected LNG demand in Japan is primarily dependent on the countrys stance on nuclear power. Cores GlobalLNG Reference Scenario assumes that over the 2013 to 2033 period, LNG demand grows at a rate of 0.5% p.a.

South Korea:

The National Energy Plan in Korea, also known as Green Korea focuses on an increase in renewable and nuclearfuelled power. As such, gas/LNG is not expected to increase its market share materially.

Cores Global LNG Reference Scenario reects these plans, with LNG consumption growing at 0.8% p.a. over theperiod to 2033.

Taiwan:

The Taiwanese Bureau of Energy has stated that it intends to increase Taiwans energy security and ensureenvironmental protection.

The Taiwanese Bureau of Energy has also stated that the country has an LNG supply target of 20 Mt by 2025.Cores Global LNG Reference Scenario is consistent with this trajectory, growing at a rate of 2.6% p.a.

China:

Gas consumption in China is expected to increase signicantly over the period to 2033 as a result of increasingprimary energy demand and as the country targets lower energy emissions consistent with their twelfth ve-yearplan spanning the 2011-2015 period.

There is a high level of uncertainty regarding the source of this gas supply as China has access to locally-sourced

(indigenous) gas, pipeline gas from adjacent countries and imported LNG. Cores Global LNG Reference Scenario models growth from 2013 levels at a rate of 5.9% p.a.

India:

Gas is expected to increase its share of primary energy in India over the period to 2033.

Similar to China, India has access to indigenous gas, resulting in high levels of uncertainty over the source(s) offuture supply.

Indias indigenous gas supply is currently priced well below international LNG pricing, and Core expects that Indiawill seek to minimise reliance on higher-cost LNG imports by accessing pipeline supply and new indigenous gassources. As a result, Cores Global LNG Reference Scenario models growth from 2012 levels at a rate of 4.9% p.a.

Other Asia:

LNG import terminals have been, or are being, constructed in Singapore, Malaysia, Indonesia and Thailand. TheGlobal LNG Reference Scenario assumes LNG consumption grows to increase market share.

Analysis of plans for new LNG import terminals and LNG demand projections published by relevant authoritiescombined with consideration of Gross Domestic Product ( GDP) growth projections were used to derive demandprojections.

6.3.2. Atlantic Region

Europe:

LNG forms an important component of Europes gas supply with a 14% market share in 2012. The remainder issupplied by indigenous production and pipeline gas. Core has assumed that LNG will maintain this market share.

8/11/2019 2013.09.04 LNG Report.pdf

24/51

6. Global LNG Demand OutlookAEMO 2013 GSOO | Eastern & South Eastern Australia: Projections of Gas Demand for LNG Export

18 | July 2013

Americas:

Total LNG consumption in the Americas in 2012 was 20 Mt, with 5 Mt in the USA and Canada. LNG Demand in theUSA and Canada is expected to decline as those countries become LNG exporters.

Other countries consuming LNG include Brazil, Argentina, Chile and Mexico (east coast). These countries havesignicant domestic gas resources and LNG is used to meet short term imbalances or to supply areas notconnected to indigenous supply. It is therefore not projected to increase signicantly.

6.4. Global LNG Demand Sensitivities

Core has undertaken sensitivity analyses to determine the potential for higher or lower LNG demand than representedby the Global LNG Reference Scenario. The results are presented in the following Figure.

Figure 6.2 | Global LNG Demand Sensitivity Analysis

0

100

200

300

400

500

600

2008 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032

Projected Global LNG Demand SensitivityMt | 2008-2033

Scenarios

High | 461

Reference | 403

Low | 347

Source; Core Energy Group; 2013

The major factors inuencing the level of sensitivity analysis include:

The level of projected economic growth in major importing countries.

The projected share of gas in the energy mix of major importing countries.

The level of alternatives to LNG to meet the gas demand of major importing countries.

8/11/2019 2013.09.04 LNG Report.pdf

25/51

7. Global LNG Supply Outlook AEMO 2013 GSOO | Eastern & South Eastern Australia: Projections of Gas Demand for LNG Export


7. Global LNG Supply Outlook

7.1. Overview

There are currently 17 countries exporting LNG, with the largest supplier being Qatar, followed by Indonesia andMalaysia.

Australia began exporting LNG from the NWS project in 1989, followed by Darwin LNG in 2006 and Pluto in 2011.

Core data indicates global liquefaction capacity in 2012 was approximately 270 Mt.

Figure 7.1 shows the location of major global liquefaction plants.

Figure 7.1 | Location of Existing LNG Production (Liquefaction) Facilities

Algeria LNGDamietta LNG

EG LNG

Egyptian LNG

Nigeria LNG

Yemen LNG

Adgas LNG

Kenai LNG

Oman & Qalhat LNGQatargas LNG

Rasgas LNG

Darwin LNG

North West Shelf LNG

Pluto LNG

Sakhalin LNG

Snohvit LNG

Tangguh LNGArun LNG

Bontang LNG

Brunei LNG

MLNG

Atlantic LNG

Peru LNG


7.2. Global Contract Prole

Core maintains a data book containing all LNG contracts available from public disclosures. This data has been used toderive a prole of contracted demand over time and by deduction, the level of projected demand which is remainingto be contracted, as shown in the following Figure.

Figure 7.2 | Global LNG Demand - Contracted and Not Yet Contracted

250 Mt280 Mt

240 Mt

185 Mt143 Mt

32 Mt41 Mt

110 Mt198 Mt

260 Mt

0

50

100

150

200

250

300

350

400

450

2015 2020 2025 2030 2033

Global LNG Demand versus Contracted LNG Supply

Contracted Supply Demand - Not Yet Contracted (Reference Scenario)


8/11/2019 2013.09.04 LNG Report.pdf

26/51

7. Global LNG Supply OutlookAEMO 2013 GSOO | Eastern & South Eastern Australia: Projections of Gas Demand for LNG Export

20 | July 2013

7.3. Expected Decline of Existing Supply Capacity

Indonesias Arun plant is expected to cease operation in 2014 and several plants have been producing below capacitydue to insufcient gas production. These include the Bontang LNG plant in Indonesia and trains in Algeria and Egypt.Bontang output has been in decline for some years, falling from peak capacity of 22 Mt to 16.5 Mt in 2011 and isexpected to decline further over the next 10 years as reserves are depleted.

From an Australian perspective, the NWS LNG project has contracts maturing throughout the Study period and

longest standing contracts extend beyond 2030. Contracts for the Darwin LNG project mature by the mid-2020s andPluto contracts extend beyond the Study period.

7.4. Expected Addition of New Supply Capacity

There are a number of LNG plants under construction as at the date of this Report, mainly in Australia but also inPapua New Guinea ( PNG), Algeria, Indonesia and USA. These account for total expected additional capacity of 82Mt by 2017. These projects are expected to begin production between 2013 and 2017 taking total global liquefactioncapacity to 431 Mt in 2017.

Table 7.1 provides further details of LNG projects under construction at the date of this Report.

Table 7.1 | Global LNG Projects Under Construction

Name Country Number of Trains Total Capacity, Mt Expected Start Date

Arzew Algeria 1 4.7 1-Jan-2014

Gorgon LNG Australia (west) 3 15.0 1-Jan-2014

Wheatstone LNG Australia (west) 2 8.9 1-Jul-2016

Ichthys LNG Australia (west) 2 8.4 1-Jan-2017

GLNG Australia (east) 2 7.2 1-Jan-2015

QCLNG Australia (east) 3 8.0 1-Jan-2014

APLNG Australia (east) 2 8.5 1-Jul-2015

Prelude FLNG Australia (west) 1 3.6 1-Jan-2017

Donggi-Senoro Indonesia 1 2.0 1-Jan-2015

PNG LNG PNG 2 6.6 1-Jul-2014

Sabine Pass USA 2 9.0 1-Jan-2015

Total 21 82.0

Source: Core Energy Group, 2013.

7.5. Proposed/Likely Future Global LNG Supply SourcesCore has undertaken an analysis of projects which have entered FEED and other Proposed/Likely LNG projects. Indoing so, Core has taken account of the reserve or resource base, technical challenges, economic viability and politicalor regulatory hurdles. The combined capacity of projects Core has assessed to be likely is 210 Mt.

The primary hurdle for each of these projects to proceed to commercialisation and construction is the ability toexecute sales contracts (at a competitive price), as this a prerequisite for funding approvals.

Figure 7.3 illustrates potential global liquefaction capacity based on existing projects and Cores assessment of mostlikely proposed projects.

8/11/2019 2013.09.04 LNG Report.pdf

27/51



Figure 7.3 | Global LNG Reference Scenario Liquefaction Capacity, Mt

0

100

200

300

400

500

600

2008 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032

Liquefaction CapacityMt, 2008-2033

Producing In Construction In FEED Core Proposed/Likely

Historic


Figure 7.4 compares the level of potential liquefaction capacity to Cores Reference Scenario to illustrate the demand-

supply balance.

Figure 7.4 | Global LNG Reference Scenario Demand-Supply Balance, Mt

0

100

200

300

400

500

600

2008 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032

Projected Global LNG Demand versus LiquefactionCapacity | Mt, 2008-2033

Producing In ConstructionIn FEED Core Proposed/LikelyProjected Global demand

Historic


As this chart shows, if all projects currently under consideration were to proceed, the entire market for the planningperiod would be satised.

Figure 7.5 extends this analysis to the high and low Global Demand sensitivities to illustrate that projected LNGliquefaction capacity is sufcient to meet even the high sensitivity.

Figure 7.5 | Global LNG Reference Scenario Demand-Supply Balance, Mt

0

100

200

300

400

500

600

2008 2011 2014 2017 2020 2023 2026 2029 2032

Projected Global LNG Supply and DemandMt, 2008-2033

Producing In ConstructionIn FEED Core Proposed/ LikelyProjected Global Demand Low Scenario Projected Global Demand - High ScenarioReference Scenario

Scenarios

High | 461Reference | 403Low | 347

Scenarios

High | 461Reference | 403Low | 347


8/11/2019 2013.09.04 LNG Report.pdf

28/51

8/11/2019 2013.09.04 LNG Report.pdf

29/51



> The combination of large volumes of gas resources for Vladivostok and Sakhalin-3 and close proximity to the AsiaPacic region mean that these projects will be competing with Australia for Asian customers.

> Developments in Russia have been somewhat hindered by harsh locations of some of the gas elds, jointventure issues and competing priorities within Gazprom. Russia is also considering commercialisation of gasresources via pipeline supply.

PNG:

> PNG currently hosts one committed project (with potential expansion) and one proposed project. > Whilst the committed project is fully contracted, the gas elds supporting proposed projects still require furtherappraisal.

> Location and proximity to market are advantageous as are liquid yields, which improve project economics.However, perceived risk and timing may impact their competitiveness.

Western Australia ( WA) and the Northern Territory ( NT):

> WA and the NT host Australias three existing liquefaction facilities (NWS, Darwin LNG and Pluto LNG), as wellas four projects under construction (Gorgon, Wheatstone, Prelude and Ichthys) and another seven proposedprojects/project expansions.

> Some of these proposed projects have associated liquids production; however, these are still not consideredeconomically viable, primarily due to the high prevailing cost environment in Australia. This is evidenced by theBrowse LNG joint venture decision not to proceed with the onshore LNG project and to evaluate an alternativeFloating LNG ( FLNG) project. Core expects these cost pressures to decline to some extent post-2018, whenhigh existing levels of development activity begin to reduce materially.

Qatar:

> Qatar has no plans for additional trains having stated they will monitor the performance of reservoirs beforecommitting to further developments.

> Qatar reserves are in excess of one million PJ of liquids-rich gas and total production is in excess of 7,700 PJ p.a.representing a 130 year reserves-to-production ratio. Qatar therefore would appear to have adequate capacity toexpand its LNG production at a globally competitive cost.

> Qatars strategy would appear to involve positioning itself as a price leader to maximise value of its existing 78Mt production. It is not expected to expand without strong unmet global demand signals.

Figure 7.6 compares the approximate current cost to deliver LNG to the Asia Pacic region for a selected group ofcompeting regions and compares it to the estimated cost of LNG delivered from Australia. This Figure highlights thatAustralian LNG production costs, and greeneld eastern Australia LNG in particular, are expected to be materiallyhigher than competitive LNG supply sources.

8/11/2019 2013.09.04 LNG Report.pdf

30/51

7. Global LNG Supply OutlookAEMO 2013 GSOO | Eastern & South Eastern Australia: Projections of Gas Demand for LNG Export

24 | July 2013

Figure 7.6 | LNG Supply Cost Estimates for New Developments

8.00

8.00

8.00

6.00

6.00

5.00

5.00

5.00

4.00

4.00

4.00

3.00

0.80

0.70

0.80

1.00

0.80

2.70

0 2 4 6 8 10 12 14 16

Eastern Australia (Greenfield)

Browse Basin

Eastern Australia (Brownfield)

Canada (20 Mt)

Mozambique (50 Mt)

US Gulf Coast (50 Mt)

LNG Supply Costs for New DevelopmentsUSD per MMBtu

U ps tr eam Li qu ef ac ti on S hi ppi ng

Total 12.80

Total 11.00

Total 10.80

Total 10.70

Total 13.80

Total 13.70

Source: Core Energy Group analysis; 2013.Note: One MMBtu is approximately equal to 1.055 GJ.

8/11/2019 2013.09.04 LNG Report.pdf

31/51

8. Eastern and South Eastern Australia LNG Demand AEMO 2013 GSOO | Eastern & South Eastern Australia: Projections of Gas Demand for LNG Export


8. Eastern and South Eastern Australia LNGDemand

This Section of the Report provides a summary of projected eastern and south eastern Australia gas demand for LNGexport to 2033.

8.1. OverviewTo determine projected gas demand for eastern and south eastern Australian LNG export, Core has considered thefollowing:

The status of proposed projects including:

> Reserves and resource base.

> Status of exploration or appraisal activity.

> Technical capacity of proposed operators to execute an LNG project.

> Financial capacity to fund the project. > Political factors.

The level of projected global LNG demand which is yet to be contracted, particularly in the Asia Pacic region.

The volume and timing of competing sources of supply.

8.2. Committed Projects

There are three committed projects, each with two LNG trains under development at Gladstone in Queensland. Thesethree committed projects form AEMOs Planning Scenario in its entirety and part of Cores 7 Train Scenario. Analysis ofthe start-up, ramp prole and capacity of these projects is based on publicly available documents and Core analysis.

8.2.1. QCLNG

The QCLNG project is operated by QGC, a subsidiary of BG and is partnered by the Chinese National Oil Company(CNOOC). This project has two trains with expected annual output 14 of 7.9 Mt.

QCLNG forms part of BGs global LNG supply portfolio and will be used to underpin long term supply contracts withcustomers in China, Japan, Chile and Singapore.

As at May 2013, BG stated the project was on schedule for rst LNG production in the second half of 2014, rampingup to full production by 2016. According to BG, it is expected to produce approximately 2 Mt in 2014.

Total annual gas demand at peak production is expected to be 486 PJ p.a. including project fuel usage andtransmission losses.

8.2.2. GLNG

The GLNG project is joint venture between Santos, Total, Petronas and Kogas. It has two trains under constructionwith expected annual output of 7.2 Mt and 20-year supply contracts with Petronas of Malaysia and Kogas of Koreafor a substantial proportion of the full output of the project.

The project is scheduled to begin production in 2015, ramping to full production by 2019. Total estimated annual gasdemand at peak production is 446 PJ p.a., including project fuel usage and transmission losses.

8.2.3. APLNG APLNG is a joint venture between Origin Energy, ConocoPhillips and Sinopec. This project has two trains under

construction with expected annual output of 8.4 Mt and 20 year contracts with Sinopec of China for annual volumesup to 7.6 Mtpa and Kansai Electric of Japan for approximately 1 Mtpa.

14 Expected annual output is 93% of plant capacity as dened in Section 4.

8/11/2019 2013.09.04 LNG Report.pdf

32/51

8. Eastern and South Eastern Australia LNG DemandAEMO 2013 GSOO | Eastern & South Eastern Australia: Projections of Gas Demand for LNG Export

26 | July 2013

The project is scheduled to being production in 2015. Total annual gas production at peak production is expected tobe 514 PJ p.a., including project fuel usage and transmission losses.

8.3. Proposed Projects

Arrow LNG

> Arrow Energy is a 50/50 joint venture between Shell and Petrochina, which announced in 2013 that it held

over 9,500 PJ of Proved and Probable ( 2P) reserves and was progressing toward making a Final InvestmentDecision ( FID) in 2013 whether to proceed with a LNG project.

> The proposed project is a two train 8 Mt capacity liquefaction facility at Gladstone.

> After taking into account domestic sales contracts, ramp gas and tail gas, the 2P reserve is consideredinsufcient to underpin a production for 20 years. Although the LNG plant will operate well beyond 20 years, thisis considered the minimum requirement to underpin long term contracts.

> Core assumes that this greeneld project will not proceed beyond FID as a standalone project, as Cores analysissuggests it is unlikely to meet the economic hurdles of one or both of its owners, and may instead be developedas a third train via the QCLNG/APLNG/GLNG trains.

> Based on recent announcements by Shell executives and Cores independent analysis, Cores 7 Train Scenarioassumes one additional train of 4 Mt is constructed on the site of an existing project with rst supply fromArrows gas reserves in 2020. Core has considered this possibility of more than one additional train in itssensitivity analysis set out in Section 8.5.1.

The 2012 GSOO discussed a number of other proposed projects including:

> LNG Newcastle.

- This was proposed by Eastern Star Gas to use its resource base in the Gunnedah Basin in New South Wales.Eastern Star has since been taken over by Santos and EnergyAustralia. Santos have announced that currentplans for those reserves and resources will be targeted at the domestic market rather than LNG.

> Projects at concept stage (Fishermans Landing, Southern Cross, Icon Energy, Beach Energy, Abbot Point).

- These projects are not associated with a specic reserve or resource base and have not proceeded beyondthe concept stage. No signicant progress has been made since 2012 in terms of rming up the concept orproving up a resource base. Core does not believe these projects are likely to be commercialised in the 7 TrainScenario within the timeframe of this Study, as they are assessed by Core to be uncompetitive.

Existing project expansions.

> Each of the committed LNG projects has the capacity to accommodate an additional train without the need toexpand tank or jetty capacity. Both APLNG and QCLNG have announced they will look to explore for additionalreserves to feed an additional train once the existing plants are in operation. Assuming approximately 5,000 PJ 15 are required for an additional train, it is considered unlikely that rst production associated with any additionaltrain would commence prior to 2020.

8.4. Key Drivers for New Eastern and South Eastern Australian LNG Supply

There are two key drivers that will dictate the level of further liquefaction capacity in eastern and south easternAustralia to improve global competitiveness: reserve additions (to provide a base for future production to feedliquefaction) and lower production costs.

8.4.1. Reserves Additions

With the exception of Arrow LNG reserves, Cores analysis indicates that there are insufcient 2P reserves held byany single party to underpin an LNG development. Any future eastern and south eastern Australian LNG projects willtherefore require new exploration and development, most likely involving CSG or unconventional gas.

Current gas exploration activity is focused on Cooper Basin unconventional, and to a lesser extent CSG and tight gasin the Bowen Basin. For example:

15 Core assumes 250PJ p.a. for twenty years.

8/11/2019 2013.09.04 LNG Report.pdf

33/51



Beach Energy has recently been partnered with Chevron, to explore its permits in the Cooper Basin forunconventional gas. The rst stage of exploration will be completed in 2015 and if the results are positive they willcontinue to a second phase.

BG, through its subsidiary QGC, has recently conducted exploration for tight gas in the Bowen Basin.

8.4.2. Future Gas Production Costs

Core expects any future eastern and south eastern Australian LNG projects to be underpinned by CSG orunconventional gas.

The three committed LNG projects will be supplied by CSG, which is of variable quality and associated cost. Thehigher quality areas of Fairview/Spring Gully in the Bowen Basin and the Undulla nose area in the Surat Basin havedemonstrated initial rates exceeding 1 terajoule ( TJ ) per day. However, CSG areas which are geologically removedfrom these sweet spots are likely to produce gas at much lower rates or will be accessed with higher costhorizontal wells. Core estimates that development costs for future, lower quality/productivity CSG will be in excessof AUD7.00 per GJ. When combined with transportation costs, the gas costs at the inlet to the LNG plant will beapproximately AUD8.00 per GJ.

Similarly for unconventional gas, which is being actively explored for in the Cooper Basin and other areas, Coreestimates that the cost of would be no less that AUD8.00-9.00 per GJ delivered to Gladstone.

These estimated costs place future eastern and south eastern Australian LNG projects at the high end of the range ofsupply costs for all competing global LNG projects. Marked improvements in well productivity and development costwill be required to change this position.

8.5. Projected Gas Demand Eastern and South Eastern Australia LNG

As referred to in Section 3, Core has derived a 7 Train Scenario for eastern and south eastern Australia LNG demand.This compares with the AEMO Planning Scenario, which consists of six trains and is based on the three currentlycommitted LNG projects in eastern and south eastern Australia.

AEMO Planning Scenario

> Two QCLNG trains starting 2014 reaching full capacity in 2016 with maximum annual gas demand ofapproximately 486 PJ p.a.

> Two APLNG trains - starting 2015 reaching full capacity in 2017 with maximum gas production of approximately514 PJ p.a.

> Two GLNG trains - starting 2015 reaching full capacity in 2019 with maximum annual gas production ofapproximately 446 PJ p.a.

Core 7 Train Scenario

> 6 committed trains, as listed above.

> A seventh LNG train (likely to be developed as a third train via one of the above listed projects), starting 2020reaching full capacity in 2021 with maximum annual gas production of approximately 229 PJ p.a.

These assumptions are broadly consistent with company announcements, with the exception of certain delays whichhave been assumed by Core.

8/11/2019 2013.09.04 LNG Report.pdf

34/51

8. Eastern and South Eastern Australia LNG DemandAEMO 2013 GSOO | Eastern & South Eastern Australia: Projections of Gas Demand for LNG Export

28 | July 2013

Figure 8.1 | Eastern and South Eastern Gas Demand for LNG Export, PJ p.a.

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2014 2016 2018 2020 2022 2024 2026 2028 2030 2032

Projected Eastern and South Eastern Australia GasDemand for LNG | PJ

QCLNG GLNG APLNG Train 7 AEMO 2013 - Planning Scenario

Source: Core Energy Group; June 2013.

Table 8.1 | Planning and 7 Train Scenario Summary

Scenario Summary

Project Train EffectiveAnnualOutput

(Mt)

GasDemandEquiva-lent (PJ)

Online Full Pro-duction

2015 2020 2025 2030

QCLNG 1 4.0 243 2014 2015 243 243 243 243

QCLNG 2 4.0 243 2015 2016 187 243 243 243

GLNG 1 3.6 223 2015 2017 55 223 223 223

GLNG 2 3.6 223 2017 2019 0 223 223 223

APLNG 1 4.2 257 2015 2016 138 257 257 257

APLNG 2 4.2 257 2016 2017 0 257 257 257

Train 7 1 3.7 229 2020 2021 0 123 229 229

Total 7 27.2 1,675 624 1,569 1,675 1,675


6 23.5 1,446 624 1,446 1,446 1,446

8.5.1. High and Low Demand Sensitivities

The High Demand Sensitivity assumes an additional 229 PJ p.a. of LNG demand from 2023:


An additional LNG train of 3.7 Mt expected annual output requiring additional gas production at full capacity ofapproximately 229 PJ p.a. from 2023; plus

An acceleration of Train 7 16 production to 2019.

The Low Demand Sensitivity involves a slower ramp to utilisation of full capacity of each two-train project and apermanent deferral of 229 PJ p.a. of capacity:


Train 7 does not proceed, with the 229 PJ p.a. of gas production used to service the other six trains (and someportion going to the domestic market).

16 Note: Train 7 refers to an additional train sourced from either (i) Arrow LNG (noting this may be developed as an additional third train under the QCLNG/ APLNG/GLNG trains) or (ii) as a separate additional train from the QCLNG/ APLNG/ GLNG trains.

Gas Demand for LNG, PJ

Project 2015 2017 2019 2021-33

QCLNG 430 486 486 486

GLNG 55 320 446 446

APLNG 138 514 514 514Train 7 0 0 0 229

Total 624 1,320 1,446 1,675


624 1,320 1,446 1,446

8/11/2019 2013.09.04 LNG Report.pdf

35/51



Figure 8.2 | Eastern and South Eastern Australia Gas Demand Sensitivities for LNG, PJ

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

2014 2016 2018 2020 2022 2024 2026 2028 2030 2032

Projected Eastern & South Eastern Australia Gas Demandfor LNG | PJ

Core - 7 Trains Low Sensitivity

High Sensitivity AEMO 2013 - Planning Scenario


Gas Demand Sensitivities for LNG, PJ

Scenario 2015 2017 2019 2021 2023-33

Core 7 Train 624 1,320 1,446 1,675 1,675

Low 501 1,168 1,400 1,446 1,446

High 624 1,443 1,675 1,675 1,903


624 1,320 1,446 1,446 1,446

8/11/2019 2013.09.04 LNG Report.pdf

36/51

9. Key Issues, Risks and UncertaintiesAEMO 2013 GSOO | Eastern & South Eastern Australia: Projections of Gas Demand for LNG Export

30 | July 2013

9. Key Issues, Risks and UncertaintiesThis Section of the Report provides a summary of key issues, risks and uncertainties associated with gas demand forLNG production in eastern and south eastern Australia. For the purpose of this Study:

Risk is the chance of a given outcome taking place.

Uncertainty is reference to the range of possible outcomes.

Key issues are matters of importance.

9.1. Ramp Gas

Ramp gas production is the term used to describe the volume of gas produced ahead of the start up of an LNGproject based on CSG i.e. gas production which is below the minimum level for plant commissioning.

CSG wells typically take a number of months (or even years) to dewater completely and for gas production to reach apeak production rate.

To develop sufcient deliverability from CSG acreage to supply the requirements of an LNG facility, a large number ofwells are required, and most will require dewatering. During the process of dewatering, a material cumulative volumeof ramp gas will be produced.

Core expects that the development drilling for a CSG-to-LNG project would take place over a number of years, andtherefore these wells will be brought online and dewatered progressively over a period of three to ve years. Theresult is that, in the absence of any other means of dealing with this issue, gas production is expected to increaseeach year until the start up of the LNG project.

Should ramp gas volumes be produced into the domestic market, downward pressure on contract gas demandand spot gas prices could result; however, Core notes that companies have been employing various techniques tosafeguard against surplus gas being supplied to the market. These techniques include:

Portfolio management.

Gas storage.

Third party contracts.

The choking back of wells.

Examples include:

Production ramp up:

> Each plant in Gladstone used ConocoPhillips Cascade process which can operate at low capacity factors.

> BG has stated that the QCLNG project will take 18 months to match the build-up in CSG production.

> Santos has stated that it will take Train 2 at GLNG 2 to 3 years to reach full production. Third party purchases:

> Santos will supply 50 PJ p.a. of conventional gas to Train 1 at GLNG representing 20% of requirement for Train 1.

> QCLNG has bought back gas from AGL that they are contracted to sell to them in years 2014-16.

> APLNG will supply gas to QCLNG in 2014 and 2015 prior to the start up of their LNG plant in late 2015.

Storage:

> GLNG is currently reinjecting gas into a storage facility at Roma which should have a production capacity inexcess of 100 TJ per day.

> AGL is constructing a storage facility near Roma which will used by QCLNG to inject their ramp gas and withdrawonce the LNG plant is operational.

As a result of the investment in mitigation techniques, Core does not expect signicant volumes of ramp gas to beproduced into the domestic market.

8/11/2019 2013.09.04 LNG Report.pdf

37/51

9. Key Issues, Risks and Uncertainties AEMO 2013 GSOO | Eastern & South Eastern Australia: Projections of Gas Demand for LNG Export


9.2. CSG Water Production

In 2013 the Federal Government introduced an amendment to Australias National Environment Law, such that waterresources are a deemed a matter of national environmental signicance, which must be considered as part of CSGdevelopments.

There is a risk a signicant impact on water resources may be caused by one or more CSG-based LNG developments.Factors which may directly or indirectly bring about a signicant impact on water resources could include:

A change in the quantity, quality or availability of surface or ground water.

Impact on ground water pressure and/or water table levels.

There is scope for such factors to cause delays and cost increases, the extent to which is uncertain.

9.3. Development Schedule

Cores LNG demand projections are based on announcements by the project proponents regarding rst productionand time expected to reach full production.

Core understands that Bechtel (the construction contractor for all three LNG plants) is on schedule for completion of

QCLNG in 2014 and GLNG and APLNG in 2015.There have been some delays in the upstream (gas production) component due to:

Land access due to ooding.

Delays in negotiating access agreements with landholders.

Greater number of wells required than initially forecast.

The Low Demand Sensitivity scenario assumes a slow ramp up of gas production such that it takes longer for theprojects to reach full production.

As the combined production rate to supply all projects at peak production in 2018 is greater than four times the 2012production from CSG wells, there is a risk that this targeted aggregate production rate will not be met. Risk anduncertainty factors include:

Initial rates are consistently lower than currently estimated.

Well decline rates are higher than currently estimated.

Additional approvals delay drilling.

These risks could be mitigated by:

Increase in the drilling rate by increasing the number of drilling rigs.

Purchases of gas such as gas from the Cooper Basin.

9.4. Infrastructure

Core Energy recognises that there is scope to physically deliver gas from southern production facilities such asGippsland Basin to the north to meet LNG demand. However this involves signicant transport costs and in manycases there are capacity restrictions on orderly ow and/or will require enhancement to infrastructure to facilitateow of large volumes. Core considers it more likely that contractual arrangements will be entered into as betweenparties to bring about effective swap of gas volumes, to achieve the same outcome with lower transportation cost.Nevertheless history has demonstrated that economic infrastructure will be developed when required. Further theexisting market sees a large number of willing investors to fund quality infrastructure projects.

8/11/2019 2013.09.04 LNG Report.pdf

38/51

10. Key Future Events/ SignpostsAEMO 2013 GSOO | Eastern & South Eastern Australia: Projections of Gas Demand for LNG Export

32 | July 2013

10. Key Future Events/SignpostsThe objective of this Section of the Report is to summarise key future events or signposts that will provide furtherclarity or certainty in relation to the Asia Pacic LNG sector, and the east and south eastern Australian gas demand forLNG export market in particular.

10.1. Signposts Relating to Asia Pacic LNG Demand and Supply

The Asia Pacic gas market is entering a period of signicant growth in demand, which is being targeted by new andexisting LNG projects globally. Factors of particular interest include:

The success of indigenous gas exploration campaigns in the Asia Pacic region . Gas exploration programs arecurrently underway in both China and India. Should these projects be successful, LNG demand from these regionswould be reduced. For example, China is undertaking an extensive unconventional exploration program but it isexpected to take at least ve years to understand the potential of this resource.

The success of cross-border pipeline proposals in the Asia Pacic region. Countries such as China and Indiaare continuing to investigate the potential of importing gas from bordering countries via pipelines. Should theseprojects be successful, LNG demand from these regions may be reduced.

The speed of development of new liquefaction proposals , in particular those in North America and East Africa.

The rate of development and size of emerging markets, particularly China and India but also SE Asia, includingthe transition of historic exporters such as Malaysia and Indonesia to importers.

Evolution of global energy policy , in particular any move away from nuclear or coal.

The rate of advancement of FLNG . Successful development of FLNG could be a game changer by improvingsupply side economics.

10.2. Signposts Relating to Eastern and South Eastern Australian LNG

As the three LNG projects under construction have long term contracts for the vast majority of their output, Coreexpects these projects to produce those contract volumes at a minimum, with potential for spot sales above thislevel. Recent announcements indicate LNG plant construction for all three projects is in line with the Core 7 Train andAEMO Planning Scenarios and any unforeseen delays are unlikely to be longer than six months.

Key future events and signposts relating to the development of this sector include:

FID decision for Arrow LNG.

> Arrow LNG continues to advance its project with a target to present an FID recommendation to its owners (Shelland Petrochina) by the end of 2013.

> Shell has indicated that Arrow is in discussions with the other three projects in regard to developing one train in

collaboration as an alternative to constructing their own facility. They have not commented on their preference foreither.

> For its 7 Train Scenario, Core has assumed that a standalone project is not economically viable and will notproceed and that Arrow will construct one train of 3.7 Mt expected annual output on the site of one of theexis

Date post:	03-Jun-2018
Category:	Documents
Upload:	craigunderwood
View:	216 times
Download:	0 times

2013.09.04 LNG Report.pdf

Documents