MDQ Consulting NSW Wholesale Gas Market Report February ...€¦ · MDQ Consulting – February...

MDQ Consulting

NSW Wholesale Gas Market Report

February 2014

Final Report – Public Version

MDQ Consulting 63 Gimba St Mitchelton 4053

[email protected] 0438209420

MDQ REPORT: NSW Wholesale Gas Market Report

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MDQ Consulting – February 2014 Page 1

Table of Contents

1 Executive Summary ............................................................. 2

2 Introduction - Scope of Report ........................................... 5

3 NSW Wholesale Gas Market Phases ................................ 6

4 Drivers for Change to the NSW Wholesale Market ........... 8

5 Queensland LNG Projects ................................................... 9

6 High Priced Queensland Domestic Market ...................... 17

7 Northern Gas Supply to the NSW Market ........................ 21

8 Other Potential Sources of NSW Supply ......................... 28

9 Southern Gas Supply to NSW ........................................... 29

10 Summary of NSW Market Conditions (2014-2016) ........... 34

Appendix A: LNG Project’s Minimum Reserves ................... 35

Appendix B: MDQ Consulting ................................................. 43

Copyright This report is copyright of MDQ Consulting. This report is for the sole benefit of the purchaser and may not be reproduced to any other persons without the prior consent of MDQ Consulting.

Reliance and Disclaimer The information, analysis and conclusions are based on MDQ Consulting’s experience, knowledge and expertise. They have been arrived at following careful consideration however no guarantee is provided to their completeness or accuracy. MDQ Consulting does not accept any loss or liability arising directly or indirectly from reliance of information, analysis, opinions or conclusions contained in this report.


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1 Executive Summary

1.1 Introduction

AGL Energy Limited (“AGL”) is a gas retailer in NSW. The NSW Independent Pricing and Regulatory Tribunal (“IPART”) is undertaking a regulatory review of the standard tariffs for gas retailers in New South Wales from July 2014 to June 2016. AGL has engaged MDQ Consulting ("MDQ") to provide a NSW gas market report to assist its Voluntary Pricing Arrangements (VPA) proposal to IPART for the period July 2014 to June 2016 (“VPA Period”).

1.2 Conclusions

MDQ’s key conclusions are:

(i) Commodity markets can be categorised by different market phases, where major supply and demand dynamics exist for a period of time and ultimately change into another state as major market events arise.

The NSW gas market1 has experienced three major supply phases, namely:

1) 100% Cooper Basin supply; 2) northern gas (Cooper and Qld CSM) competing with southern gas

(Gippsland Basin); and 3) scarcity of material quantities of northern gas supply due to a dramatic

increase in Queensland gas demand, resulting in an increased reliance on southern gas to supply the NSW market.

The NSW market is transitioning from phase 2 to phase3.

(ii) The major factors which are influencing the NSW wholesale gas price during the VPA Period are:

a) The transformational impact of the Queensland LNG projects and the short supply position of some LNG projects;

i. Gladstone LNG (“GLNG”) has a material shortfall of gas reserves and deliverability. As a consequence GLNG has been active in the domestic market purchasing large quantities of third party gas at a long run Wallumbilla LNG netback price. GLNG has been the largest gas buyer in the east coast market for the last 3 years, competing against existing domestic customers for available reserves and production;

ii. Given the short time until the start of LNG production and the tight domestic gas market created by previous LNG purchases, there is a risk that any new incremental third party sales (albeit in small

1 In this report the reference to the ‘NSW market’ and ‘QLD market’ refers to the geographic regions

where gas is bought and sold and is not intended to denote a defined ‘market’ in an economic sense.


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quantities) to the LNG projects will be in the range of short run LNG netback prices at Wallumbilla. The recent domestic sale of gas to Incitec Pivot suggests Queensland domestic customers may also be entering this short run LNG netback price range (refer Section 6.2 for details); and

iii. Sale of spot LNG cargoes provides a further incentive for the LNG projects to purchase additional gas from the domestic market at LNG netback prices. Throughout the term of the LNG projects and especially in the early years of production (2015-2020), the LNG producers have excess plant capacity compared to their firm LNG sales commitments providing an opportunity to sell additional LNG on a spot basis. MDQ estimates that during the period from 2015 to 2019, the LNG projects in aggregate have 150 – 200 PJ/a of spot sale capability and 50 – 100 PJ/a of spot sale capability from 2020+. Given the challenges of the LNG Producers to satisfy their firm LNG contracts and the limited availability of additional domestic gas, it is considered a low probability that material sales of spot cargoes will occur during this period, however the opportunity remains should additional domestic supplies materialise during 2015 to 2020. This unsatisfied opportunity for Gladstone spot LNG sales provides additional support LNG netback prices in the domestic market at least until the end of this decade.

b) High gas prices in the Queensland domestic market:

i. the combination of the LNG producers withdrawing as suppliers of new gas to the Queensland domestic market and LNG producers such as GLNG acting as large gas buyers, has transformed the Queensland market into the shortest, highest price domestic market in eastern Australia;

ii. GLNG has set the market price for gas in Queensland by its large gas purchases from Origin (May 2012 and Dec 2013) at around $US8-9/GJ/$A9.40-$10.60/GJ1 (based on $US100/bbl oil price) at Wallumbilla.

iii. GLNG’s ongoing requirement for additional gas supports an upside bias to short run LNG netbacks as the LNG projects approach the start of operations; and

iv. the LNG spot sale opportunities provides further support to maintaining high Queensland gas prices during 2015 to 2020 and beyond.

c) As evidenced by the latest sale by Beach Energy to Origin (April 2013), Cooper Basin sale prices are linked to the prevailing price of gas in Queensland netted back to Moomba. NSW customers must pay the Cooper Basin gas price that it can achieve by selling gas into

1 Exchange rate of AUD/USD of 0.85 is assumed in this report.


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Queensland. There is also a risk Cooper prices will increase from long run to short run Queensland LNG netbacks during the VPA Period;

d) High gas demand in Queensland has reduced the availability of new northern gas supply to NSW and increased reliance on Gippsland Basin JV to supply the NSW market:

i. Cooper Basin JV has a substantial production challenge to satisfy its existing contractual arrangements up to the end of 2016 as gas is directed to the high price Queensland market; and

ii. Other than AGL’s Gloucester basin project, material quantities of NSW CSM or other unconventional gas production is subject to an extended period of appraisal and development and unlikely to be available prior to the end of this decade.

e) Transportation constraints will limit the extent that Gippsland Basin JV

can increase supply to NSW prior to mid-2015 and additional new southern gas into NSW is subject to further expansion of the Eastern Gas Pipeline or the Vic/NSW interconnect; and

f) Southern gas prices are increasing in response to the changing northern market conditions. The Origin GSA and other recent sales suggests the indicative Gippsland Basin JV ex-Longford price for new supply during the VPA Period is in the range of $A6.25 - $A6.50/GJ ($2013).


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2 Introduction

2.1 Scope of Report

The NSW Independent Pricing and Regulatory Tribunal (“IPART”) is undertaking a regulatory review of the standard tariffs for gas retailers in New South Wales (“NSW”) from July 2014 to June 2016 (“VPA Period”). AGL has engaged MDQ Consulting ("MDQ") to provide a report on the prevailing wholesale gas market conditions in NSW during the VPA Period to assist the Brattle Group’s (AGL’s economic consultants) assessment of NSW wholesale gas prices during the VPA Period.


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3 NSW Wholesale Gas Market Phases

3.1 Introduction Commodity markets can be categorised by different market phases, where major supply and demand dynamics exist for a period of time and ultimately change into another state as major market events arise. These different market phases affect the alternatives available to buyers and sellers and is reflected in the commodity price and other supply terms in gas sales agreements. Historically, the NSW gas market has been supplied 100% by the Cooper Basin. With the establishment of network interconnection with Victoria via the Vic/NSW interconnect and the Eastern Gas Pipeline (“EGP”), the Cooper Basin began to compete with Gippsland Basin JV gas from the south. The introduction of coal seam gas in Queensland provided the NSW market with an additional source of supply. During this time there were multiple sources of supply for the NSW market. This situation is now changing, with Queensland LNG projects such as GLNG purchasing large quantities of domestic gas and the Cooper Basin focussed on supplying gas to Queensland, the NSW market is transitioning into a new phase which will rely heavily on southern gas as its major source of new supply. As a consequence of the changes to the NSW market, the Gippsland Basin JV is competing with Cooper Basin gas that has superior market alternatives, namely supply to Queensland LNG. Note there are other southern gas producers such as gas from the Otway that could supply gas to NSW, however Otway gas has a greater supply role in Victoria and South Australia and Gippsland Basin JV gas is the major southern supplier into NSW and is the focus in this report. This will enable the Gippsland Basin JV to seek higher prices for new gas supply to the NSW market however in the short term, EGP and Vic/NSW interconnect transmission constraints limit the amount of new supply that Gippsland Basin JV or other southern suppliers can deliver to NSW. In summary, the NSW gas market has experienced three major supply phases, viz:

1) 100% Cooper Basin supply; 2) northern gas (Cooper and Qld CSM) competing with southern gas

(Longford); and 3) scarcity of material quantities of northern gas supply created by the LNG

projects in Queensland and heavily reliance on southern gas to supply the NSW market.

3.2 Phase 1 – 100% Cooper Basin Supply The Cooper Basin producers (Santos, Delhi Petroleum and Origin Energy) were the foundation suppliers to the NSW natural gas market. Cooper Basin gas supply to NSW commenced on 23rd December 1976. From this date up to September 2000, the


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Cooper Basin producers were the sole suppliers to NSW, although the construction of the NSW/Vic interconnect through Culcairn enabled small quantities of bi-direction flow between NSW and Victoria from 1998. During this period of sole Cooper supply the price review clauses, amongst other factors, were explicitly linked to Cooper Basin production costs. The wholesale gas price under long term Cooper Basin supply agreements was periodically reviewed to reflect the latest assessment of Cooper Basin development costs. By the late 1990’s the Cooper Basin had reached its peak gas production capabilities and was no longer able to satisfy 100% of the NSW gas market.

3.3 Phase 2 – Northern and Southern Gas Competition The EGP commenced supply to NSW in September 2000, based on supply of gas from the Gippsland Basin to BHP’s NSW steel mills and Sithe Energies at Smithfield. The initial capacity of the EGP was 65 PJ/a in 2000 and through a number of staged expansions the EGP’s capacity is currently 106 PJ/a. At the same time of southern gas expansion into NSW, major new contracts enabled the entry of Queensland CSM gas into NSW. The major Queensland CSM supply and infrastructure agreements were:

a) May 2004 - the SWQ Producers and Origin announced a gas swap agreement to enable Origin’s Wallumbilla CSM gas to be delivered to Moomba from 2004 to 2011;

b) December 2006 – AGL enters into a 20 year gas purchase agreement with QGC to purchase approximately 30 PJ/a of CSM gas from its eastern Queensland operations; and

c) October 2007 - AGL commits to a long term transportation agreement with Epic Energy to transport gas from Wallumbilla to Moomba which facilitated the construction of the Ballera to Moomba interconnect. AGL’s Queensland CSM commenced physical flow from Wallumbilla to Moomba in January 2009.

During Phase 2, the Cooper Basin, Queensland CSM and Gippsland Basin gas competed for share of the NSW market. The parameters for periodic price reviews under the long term wholesale supply agreements changed from a production cost focus during Phase 1 to a market based review mechanism during Phase 2. The price review mechanisms became focussed on the market price of gas delivered to Sydney, rather than the production costs of an individual producer as the case during Phase 1. This meant the wholesale price of gas at Moomba and Longford were essentially the same, since the reference point was Sydney gate prices, although the Longford price was slightly lower than Moomba because of the transportation cost differential between the Moomba Sydney Pipeline (“MSP”) and the EGP.


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3.4 Phase 3 – Scarcity of Northern Gas Supply The NSW gas market is entering a new market phase of substantially reduced supply from the Cooper Basin producers and Queensland CSM. The rapid increase in gas demand in Queensland is creating a scarcity in material quantities of gas supply from the Cooper Basin and Queensland to NSW and a greater reliance on southern gas to satisfy NSW’s uncontracted gas demand. Section 4 provides further details on this material change in market dynamics. MDQ anticipates that at some point in the future, the market will move beyond phase 3 and enter a new phase when LNG producers have secured sufficient reserves and deliverability from the east coast market to satisfy their project requirements. As detailed in Section 5, this change is considered unlikely until post 2020.

4 Drivers for Change to the NSW Wholesale Gas Market

4.1 Introduction

The NSW wholesale gas market has entered a period of material change, where gas prices are increasing from historical ex-Moomba prices of approximately $A4.50/GJ ($2013) to long run LNG netback prices1. In some areas, particularly Queensland, wholesale market prices have exceeded long run LNG netback prices and approached short run LNG prices2 (refer Section 6 for further details). To understand the reasons for this material change to the NSW wholesale gas market prices, it is necessary to review the key drivers for change, viz:

1) the Queensland LNG projects (the three LNG projects, namely GLNG, APLNG and QCLNG) and their short supply position (refer section 5);

2) high gas prices in the Queensland domestic market (refer section 6) 3) Cooper Basin JV’s existing supply commitments and Santos’s strategic

alignment to GLNG (refer section 7); and 4) limited new sources of major supply to the NSW domestic market and the

impact of current transportation constraints. (refer section 8) The above factors have transitioned the NSW into a new market phase referred to as Phase 3 in Section 3. LNG projects such as GLNG have bought up large quantities of third party gas in Queensland and the Cooper Basin gas which has created a short supply position in Queensland. The scarcity of material quantities of new supply from the north has enhanced the southern suppliers’ (such as Gippsland Basin JV gas) competitive position in the NSW market. While transportation constraints in the EGP and the Vic/NSW interconnect will restrict new supplies of southern gas into NSW in the short term, the medium to long term is likely to see a significant increase in southern gas into NSW.

5 Queensland LNG Projects Note: 1) A LNG net back price is the LNG sale price less liquefaction and pipeline tolling costs (expressed

in $/GJ). Long run LNG netbacks deduct all LNG plant and transmission pipeline costs (i.e. all fixed and variable costs).

2) Short run LNG netbacks only deduct variable LNG plant and transmission tolling costs.


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5.1 Introduction The most significant factor affecting the supply and price dynamics in the east Australian gas market has been the introduction of the LNG Projects. In particular, their shortage of gas supply relative to their LNG contractual obligations (referred to as a “short supply position”). LNG projects such as GLNG have accelerated the move away from “traditional” domestic gas prices to equivalency with LNG netback prices. GLNG’s short supply position and large gas purchases has set a new LNG netback paradigm for domestic gas prices. Section 5 analyses the reserve and deliverability position of the LNG projects in detail, to assist understanding of why these projects are having such a major impact on the east coast gas market.

5.2 Reserves and Deliverability

A LNG project must have sufficient upstream reserves and deliverability to satisfy its LNG supply obligations. Deliverability relates to the daily production capability of the upstream facilities. These upstream facilities must deliver gas at sufficient rates to satisfy the LNG loading schedule, which is determined on the basis of contractual LNG supply obligations. Gas reserves and deliverability are related, but can also be separate issues. For example, a LNG project can have sufficient reserves, but may have insufficient deliverability during the first few years of production. Insufficient reserves is likely to lead to insufficient deliverability at some point over the life of the LNG project. Each LNG project must drill and connect sufficient wells to produce and store enough LNG to satisfy their customer’s LNG offtake. The most challenging deliverability phases occur:

1) during the first few years of LNG production as the LNG projects ramp-up from very low gas production rates to full 2 train LNG production in a relatively short period of time; and

2) the last years of the plateau production (refer Figure A.5 in Appendix A for explanation of plateau production phase) as incremental deliverability projects become exhausted just prior to the commencement of the tail gas production phase.

The period of ramp up to full LNG production (i.e. 2014 to 2020) has been recognised as a major challenge for the LNG projects. The build-up of upstream gas deliverability has been hampered by a range of factors, including the Queensland 2011 floods, landowner and environmental protests restricting upstream drilling and construction, an increase in “green tape” and government regulation and lower than expected well performance in areas outside the core CSM producing zones. As early as February 2012, Grant King (Origin MD) publically commented on the deliverability challenges (emphasis added by MDQ in underlined italics).


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ORIGIN Energy boss Grant King says Queensland's burgeoning coal-seam gas export industry may struggle to drill enough of the thousands of onshore wells needed to meet the early demands of multi-billion-dollar plants being built at Gladstone, highlighting a tightening of a market some feared would be in a glut.

The managing director said whereas previously the industry had feared Queensland would be awash with gas as onshore production ramped up to feed Gladstone's liquefied natural gas, there was now the possibility that drilling could fall short.

``I think we will enter another paradigm where, in aggregate, not only will the industry be able to manage the ramp-up but probably it's going to be a bit challenged to deliver the aggregate resource,'' Mr King told The Australian.

While all three under-construction Gladstone plants that will freeze the gas and transfer it to ships bound for Asia were on track, the huge effort needed to get all the onshore gas wells up and going had been affected by flooding in Queensland over the past two years, he said.

Britain's BG Group is planning to be the first to export, with first shipments planned in 2014, followed by the Santos-led Gladstone LNG and the Origin/ConocoPhillips-owned Australia Pacific LNG the following year.

Source: Australian Newspaper, 24 February 2012, pg 21

ACIL Tasman’s report to IPART in April 2013 also expressed concerns regarding upstream field performance affecting LNG project’s reserves and deliverability. However, a number of analysts have noted that the rate of growth of Queensland CSG reserves appears to have been slowing, and that average well performance has not lived up to initial expectations. So, for example, Citi Research in a recent note observed that:

“Overall, however, we think the appraisal of the QLD CSM fields has identified the geology to be more variable than initially envisaged back in 2008 and 2009, and we think the estimated ultimate recovery from the CSM acreage is less than the original estimates. We think this is evident across all four projects.” (Citi Research, March 2013). Source: ACIL Tasman Report, DRAFT Cost of gas for the 2013 to 2016 Regulatory Period, April 2013, pg 28

GLNG has purchased over 1200 PJ of third party gas on a short and long term basis. GLNG would not be buying third party gas if it could develop its own gas production. GLNG’s third party purchases clearly support the position that it is short gas reserves and deliverability.

5.3 LNG Project’s Reserve Assessment

5.3.1 Introduction

As noted in Section 5.1, an important part of a LNG project’s success is firstly having sufficient reserves and deliverability to satisfy firm LNG contracts and secondly, additional supply capability to satisfy spot LNG sales opportunities which may arise over the life of the project. Appendix A calculates the minimum reserves requirement (in PJ) to satisfy each LNG project’s firm LNG supply commitments. Appendix A takes


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into account each LNG project’s reserves, existing domestic commitments and third party purchases.

Figure 1 provides a summary of Appendix A’s LNG project reserve analysis and details the minimum reserve requirement for each LNG project. Figure 1 also includes a comparison of MDQ’s minimum reserve calculations with third party consultants Energy Quest’s estimate of minimum reserve requirements for each LNG project.

Project Actual 2P Reserves (as at mid 2013)1

(PJ)

Energy Quest – Minimum Reserve

Requirements (PJ)

MDQ Minimum Reserve

Requirement (PJ)

QCLNG 10518 12500 12020

GLNG 5376 10150 8420

APLNG 13349 15,6862 14830

Source: MDQ Consulting and Energy Quest Energy Quarterly August 2013

Figure 1: Comparison – Minimum LNG Project Reserve Requirement

Notes:

1) 2P (Proved and Probable) reserves from Energy Quest Quarterly August 2013. 2) Origin reserve estimate, not Energy Quest assessment, adjusted for tail and ramp gas

requirement.

Figure 2 determines the 2P1 excess/shortfall and 2P+2C1 excess/shortfall for each LNG project.

Project Excess 2P Reserves1

(PJ)

Excess 2P+2C2

Reserves (PJ)

QCLNG - 1503 2831

GLNG - 3043 - 1405

APLNG - 1481 2163

Figure 2: LNG Project Reserve Shortfall

Notes:

1) Excess 2P Reserves = 2P Reserves – MDQ Minimum Reserve Requirement

Note: 1) 2P reserves is the quantity of proved and probable reserves based the American society of

petroleum engineer’s project resource management system (PRMS) 2007. 2) 2P + 2C is the sum of 2P reserves and 2C (contingent resources) assessment under PRMS.


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The conclusion from Figure 1 and Figure 2 is all LNG projects are short 2P reserves compared to their existing domestic and LNG supply commitments, however QCLNG and APLNG have a larger 3P and 2C base to increase their 2P reserves over time to satisfactory levels. On a 2P reserve basis GLNG is short 3034 PJ against existing contractual commitments, representing over 1/3 of its minimum 2P reserves requirement. This figure is after the large quantity of third party purchases (refer Appendix A for details) has been included. This conclusion is also supported by Credit Suisse’s analysis, which also confirmed a large GNLG reserve shortfall (note Credit Suisse’s reserve comments below are based on a 2P+2C basis).

“Credit Suisse analysts say the Santos-led GLNG project will probably need to buy more than a third of its required gas from third parties and is facing a $US3bn-plus cost blowout.

The downbeat assessment, which resulted in a Santos valuation cut from the bank, comes after chief executive David Knox and his direct reports delivered a five-hour investor briefing on December 4 that confirmed the project was on budget and set to meet its scheduled 2015 target for first LNG exports.

"Huge uncertainty remains on third-party gas needs," Credit Suisse analyst Mark Samter said.

Based on GLNG having secured about 25 per cent of its earlier gas needs through third-party purchases, and that it is still a potential buyer of more gas, Credit Suisse is now forecasting the project will need to purchase 35 per cent of its gas, up from a previous forecast of 25 per cent.”

Source: The Australian, January 14, 2014

A point of further concern is the trend of GLNG reserves growth over the last 3 years is negative, instead of positive growth. GLNG’s 2P + 2C reserves in 2013 is 80% of its 2010 figure, as detailed in Figure 3.

Source: Santos GLNG Investor Presentation, May 2013

Figure 3: GLNG Reserve Decline


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5.4 Spot LNG Sales Opportunity

5.4.1 Introduction The aggregate of a LNG project’s firm contracts generally does not equal 100% of nameplate LNG plant processing capacity. Approximately 5-15% of LNG processing capacity is spare compared to firm LNG commitments for most LNG projects. In some LNG projects which have intentionally taken spot market risk, the quantity of spare capacity would be larger. Once a LNG plant has been fully commissioned and operating normally, there is also an opportunity to resolve minor plant processing constraints which may provide additional spot sales capabilities. The Gladstone LNG projects’ spot sale opportunity provides additional support for LNG netback prices in the domestic market at least until the end of this decade.

5.4.2 Queensland LNG Project Spot Sale Opportunity

Figure 4 highlights the spot sales opportunity for the Queensland LNG projects to participate in LNG spot sales, although periods of LNG plant downtime would restrict some periods of spot sale activity. The wedge of excess plant capacity in the early years (2015 to 2019) when the firm contracts are not at full offtake, provides the largest spot sale opportunity. MDQ estimates that during the period from 2015 to 2019 the LNG projects in aggregate have 150 – 200 PJ/a (greater in some years) of spot sale capability and 50 – 100 PJ/a of spot sale capability from 2020+ during the plateau production phase.

Figure 4: Spot LNG Sale Opportunity The LNG producers are likely to need additional third party gas to supply spot LNG Given the LNG producers’ difficulties in satisfying their firm LNG contracts and the limited availability of domestic gas, it is considered a low probability that material sales

Spot Sale Opportunity


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of spot cargoes will occur during this ramp-up period. This unsatisfied opportunity of Gladstone spot LNG sales provides additional support for LNG netback prices to continue in the east Australian domestic market.

5.5 Upstream Shortfall Risks to LNG Projects Insufficient upstream gas deliverability and reserves can result in either of the two scenarios:

1) sufficient gas to satisfy existing LNG contacts, but insufficient gas to utilise 100% of nameplate plant capacity via additional spot sales above LNG firm commitments (refer Figure 4); or

2) insufficient gas to satisfy existing LNG contracts.

Under scenario 1, the LNG producer experiences an opportunity loss to participate in LNG spot sales. Under scenario 2, the LNG Producer would be subject to damages to the LNG buyer for breach of contract and risk of purchasing spot LNG cargoes to cover their contract shortfall. While an LNG Producer would prefer to purchase additional third party domestic gas at a long run LNG netback price (which provides a return on pipeline and plant infrastructure for the LNG producer), depending on the time and domestic market circumstances, the LNG producer could afford to pay up to the LNG spot cargo price (less variable costs of LNG production) to mitigate a breach of a long term supply agreement. The conclusion is that under both shortfall scenarios, the LNG Producers’ could afford to pay up to short run LNG netback prices.

5.6 LNG Projects – Third Party Gas Purchases

Figure 5 summaries the third party gas purchases by GLNG and BG. Unlike other LNG projects, it is understood APLNG has not made any third party gas purchases.


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LNG Buyer

Seller Details Comment

GLNG Santos 750 PJ, 50 PJ/a for 15 years at Wallumbilla from 2015 (Sept 2010)

Santos supply contract announced simultaneous with Santos GLNG farm down to Total

.

Est. Gas Price = 5.9% x Brent ($US/bbl) + 0.5

1

$US6.40/GJ ($A7.52/GJ) at Wallumbilla @ $US100/bbl

GLNG Origin (tranche 1)

365 PJ, 36.5 PJ/a for 10 years at Wallumbilla from 2015 (May 2012)

Est. Gas Price = 7.5% x Brent ($US/bbl)+ 0.50

1

$US8/GJ ($A9.40/GJ) at Wallumbilla @$100/bbl

MDQ’s assessment is $US8-9/GJ ($A9.40-$10.60/GJ) and oil price based on JCC.

GLNG Origin (tranche 2)

100 PJ, 20 PJ/a for 5 years at Wallumbilla from 2016 (Dec 13)

Price similar to Tranche 1, potentially with a small increase

QCLNG APLNG 95 PJ/a for first 2 years from 2014, then 25 PJ/a for remaining 18 years (March 2010)

Joint development and gas sale agreement to develop ATP 648 and 640.

QCLNG Origin 30 PJ, 15 PJ/a for 2 years at Wallumbilla for 2014 and 2015

Oil linked price contract

Figure 5: GLNG and QCLNG Gas Purchases

Notes:

1) Gas Price Estimates from Citi Research Paper, 4 Dec 2013

The gas prices in Figure 5 are considered to be consistent with other independent consultant’s assessment. For example, IES estimated the gas price under the GLNG/Santos agreement to be $A7-$A8/GJ (IES, Study of the Australian Domestic Gas Market, December 2013) compared to MDQ’s assessment of $US6.40/GJ ($A7.53/GJ).

GLNG has been the largest buyer of gas from the domestic market. Its first purchase was in September 2010 and last additional purchase was December 2013. GLNG has purchased long term gas (10-15 years) and short term gas (5 year), supporting the position it is short long term reserves and also short deliverability during the ramp up to 2 train production (i.e. period from 2015 to 2020). GLNG has been active in the market since its final investment decision seeking to purchase top up gas from the domestic market to improve its challenging reserve and deliverability position. The purchase price of the GLNG/Origin agreements of around $US8-9/GJ ($A9.40-$10.60/GJ) at Wallumbilla is considered to be in the range of long run LNG netback prices.


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It is also understood QCLNG may have recently entered into an additional short term purchase agreement, raising issue of QCLNG’s deliverability shortfalls during its ramp up to 2 train production.

5.7 Summary - LNG Project Conclusions

Based on the reserve and deliverability analysis of the LNG projects, the key conclusions are:

a) GLNG is materially short long term reserves (short 3034 PJ on a 2P basis against its minimum reserve requirement to satisfy its LNG commitments) and deliverability. As a consequence, GLNG has been active in the market purchasing large quantities of third party gas at long run Wallumbilla LNG netback prices. GLNG has been the largest gas buyer in the east coast market for last 3 years, competing against existing domestic customers for available gas reserves and production;

b) each project’s critical risk period for LNG contract shortfall is during 2015 – 2020, especially when the second train commences operation and LNG sales contracts have ramped up to their full offtake. It is unclear whether GLNG and QCLNG now have sufficient deliverability to cover this ramp-up period, however MDQ considers it likely that GLNG and potentially QCLNG will experience periods of gas shortfalls against firm contracts during 2015-2020. GLNG’s long term reserve position remains short;

c) APLNG is the best placed LNG project to have sufficient reserves and deliverability to satisfy its firm LNG contracts, although the 2015 to 2020 period remains a challenge;

d) Given the short time to LNG project start-up and the tight domestic gas market created by previous LNG purchases, it is likely any new incremental third party sales (albeit in small quantities) to the LNG projects will be in the range of short run LNG netback prices at Wallumbilla;

e) The sale of spot cargoes provides a further incentive for LNG producers to enter the domestic market for additional gas purchases up to short run LNG netback prices. The wedge of excess plant capacity in the early years (2015 to 2020) when the firm contracts are not at full offtake, provides a large spot sale opportunity and the LNG producers are likely to need additional third party gas to supply spot LNG during this period. Given the LNG producers’ difficulties of satisfying their firm LNG contracts and the limited availability of domestic gas, it is considered a low probability that material sales of spot cargoes will occur during this period, however the opportunity remains should additional domestic supplies materialise during 2015 to 2020. The spot sale opportunity of the Gladstone LNG projects provides additional support for LNG netback prices in the domestic market at least until the end of this decade.


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6 High Price Queensland Domestic Market

6.1 LNG Producers’ Role in the Queensland Domestic Market

6.1.1 Historical Role – LNG Producers1

AEMO’s estimate of the Queensland’s 2012/13 gas market was approximately 200 PJ. Excluding Townsville’s 2013 gas demand of approximately 13 PJ, the 2012/13 demand for the Queensland market that is connected to the east Australian transmission network (made up of demand centres of Mt Isa, Gladstone and south east Queensland) was around 187 PJ.

The 2012/2013 production from eastern Queensland CSM gas producers that are not related to the existing three Gladstone LNG projects is detailed in Figure 6.

CSM Production

Area

Owners 2012/2013 Production

(PJ)

Daandine Arrow Energy 10.3

Tipton West Arrow Energy 9.8

Meridian Seamgas (Moura)

Westside/Mitsui 3.6

Kogan North Arrow Energy/Stanwell

2.6

Mungi Molopo 0.2

Total 26.5

Source: 2012/2013 Production from Energy Quest Quarterly Review, August 2013

Figure 6: Non Qld LNG Project Gas Production - 2012/2013

Based on 26.5 PJ of CSM gas in 2012/2013 supplied from non LNG participants, approximately 85% of the existing Queensland market is supplied by the LNG producers. If Arrow Energy’s production is excluded, this figure increases to 98%. The conclusion is the LNG producers have been the major suppliers to Queensland’s domestic gas market based on existing long term contracts entered into prior to their LNG project’s final investment decision (“FID”). The FID for BG’s LNG project was October 2010, GLNG January 2011 and APLNG April 2011. These existing long term domestic GSAs date back to the 2002 - 2007 period, prior to the original Australian

Note: 1) LNG producer refers to the owners of the GLNG, APLNG or QCLNG projects. Depending on the specific reference it may apply to one or all of the LNG projects.


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listed CSM companies being taken over by the gas majors such as BG and Shell. Some examples of these long term Queensland GSAs entered into by the original CSG companies are:

1) Tipperary’s (Fairview) 15 PJ/a 13 year GSA with Origin Retail in 2002, for supply from 2007 to 2020 (now GLNG);

2) QGC’s 7.4 PJ/a 10 year GSA with Incitec Pivot (Brisbane) in 2004, for supply from 2007 – 2017 (now owned by QCLNG);

3) Origin’s 7.4 PJ/a 10 year GSA with Incitec Pivot (Brisbane) in 2004, for supply from 2007 – 2017 (now owned by APLNG);

4) Tipperary’s (Fairview) 1.2 PJ/a 10 year GSA with Orica (Gladstone) in 2004 for supply from 2006 to 2016 (now owned by GLNG);

5) QGC’s 35 PJ/a 20 year GSA with AGL in 2006, for supply 2008 to 2029 (now owned by QCLNG)

6) Origin’s 11 PJ/a 15 year GSA with QAL (Gladstone) in 2003, for supply 2006 to 2021 (now APLNG);

6.1.2 Current Role – LNG producers

While the LNG producers (or their predecessors) have played a major supply role in the Queensland domestic market, as these major supply agreements expire, the LNG producers are unwilling to renew gas supply arrangements due to their deliverability and reserve challenges. Eighty five percent of the existing suppliers to the Queensland domestic market are unwilling to supply new gas to renew existing contracts or satisfy growth in demand. Since 2010/2011 all major new Queensland domestic supply contracts have been supplied by the gas retailers, viz

1) October 2011 – AGL supplies a 10 year, 125 PJ gas sale agreement (“GSA”) to Xstrata’s Mount Isa Mines;

2) December 2012 – Origin Retail supplies a 7 year, 22 PJ GSA to MMG to supply its NWQ operations; and

3) December 2013 – unnamed source (MDQ understands AGL or Origin) supplies a 2 year GSA to Incitec Pivot to supply its NWQ operations.

Public comments by companies such as Rio Tinto regarding gas supply to its Gladstone Alumina plant, confirms the LNG producers’ inactivity with Queensland domestic customers.

Alumina head Pat Fiore raised red flags over Queensland’s domestic gas supply outlook.

"We're not asking for preferential prices or that sort of thing, we're just asking for there to be a

market in eastern Australia," Fiore told The Australian.


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"Right now we're struggling to attract anyone to the table to negotiate."

While the executive did not reveal when the plant’s existing gas supply contracts will expire, it

seems this will occur during the next several years as Queensland’s three key Curtis Island-

based CSG to LNG projects come online.

Given that Fiore wasn’t troubled by the prospect of paying higher prices, his comments lent

weight to other views that all was not well on the CSG field supply front.

“Our understanding is it doesn't seem like they have the (gas) molecules to send to us,” Fiore

reportedly said of the key gas players in the state.

Source: Energy News Bulletin, 3 December 2013

Not only have LNG producers withdrawn from their traditional domestic supply role, some LNG parties such as GLNG, have been acting as large buyers competing against Queensland domestic customers for scare sources of supply, exacerbating Queensland’s tight supply position.

6.2 Prevailing Queensland Gas Market Conditions The combination of LNG producers’ withdrawal from the domestic market and LNG parties such as GLNG acting as large buyers instead of sellers has transformed the Queensland gas market into the shortest, highest price domestic market in eastern Australia. GLNG’s large purchases of gas from Origin and its continued requirement for additional gas has put a floor price under the Queensland gas price equal to long run LNG netbacks at Wallumbilla. The recent gas purchase announcement by Incitec Pivot suggests a market price above long run Wallumbilla netbacks and close to the range of short run LNG prices. Two recent Queensland domestic supply contracts support the position of high Queensland gas prices. 6.2.1 Origin Supply to MMG Origin announced on 21 Dec 2012, a 7 year 22 PJ GSA to supply MMG’s Century mine and proposed Dugald River mine in north-west Queensland. The following exert from the Australian indicates the high price nature of this agreement:

ORIGIN Energy has inked the east coast's most expensive domestic gas agreement to

date, signing a deal with Chinese-controlled miner MMG to supply gas for north

Queensland mines at prices more than double the current rate and 50 per cent higher

than other recent long-term deals.

In a deal gas sellers hope will set a benchmark for domestic sales, it is understood MMG will

pay close to $9 a gigajoule after $70 billion worth of coal-seam gas export plants being built at

Gladstone start operating in earnest from 2015.


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The price compares with current prices of between $3 and $4 a gigajoule now being paid and a

price of about $6 a gigajoule for a long-term north Queensland gas supply deal signed between

AGL Energy and miner Xstrata late last year.

Source: The Australian, 21 December 2012

6.2.2 Incitec Pivot Gas Purchase Agreement On 19 December 2013, Incitec Pivot announced a 2 year gas contract for its phosphate fertiliser plant in north-west Queensland from 1 February 2015. The seller was not named, although expected to be either AGL or Origin. Incitec Pivot noted it would increase manufacturing costs by $50m per year in 2015 and 2016. Incitec Pivot’s plant consumes approximately 9 PJ/a, equating to an additional cost of $A5.50/GJ above current gas sale agreement prices. With “traditional prices” approximately $A4.50/GJ, the estimated commodity price of this new gas agreement is around $A10/GJ. This price is approaching the range of short run LNG netback prices and represents another step-up in domestic gas prices in Queensland. As the LNG projects approach their commencement date it is expected additional gas purchases would be in the range of short run LNG netback basis, leading to a further increase in Queensland’s domestic gas prices.

6.3 Summary Queensland Gas Market Conditions Figure 7 shows the upward trend of new domestic gas prices in Queensland. All prices are at Ballera in south west Queensland.

0

2

4

6

8

10

12

11/10/11 21/12/12 19/12/13

MIM MMG Incitec

$A

/GJ

Customer and Date

Queensland Domestic Gas Price ($A2013 Ballera)

Source: MDQ and the Australian

Figure 7: Recent Queensland Domestic Prices


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The conclusions regarding the present state of the Queensland gas market are:

a) the LNG producers (or their predecessors) have historically been the major suppliers of domestic gas in the Queensland, through long term supply contracts entered into prior to the LNG projects’ FID;

b) LNG producers have withdrawn from participating in the Queensland domestic market and are unlikely to re-enter the market until they are fully satisfied they have sufficient reserves and deliverability for their LNG projects;

c) since the LNG projects have announced their FID, only the gas retailers (AGL and Origin) have been active in supplying new gas to Queensland domestic customers as evidenced by the recent major sales to MIM, MMG and Incitec Pivot;

d) GLNG has been the largest gas buyer in eastern Australia and set the Queensland gas market price with its large gas purchases from Origin Retail at around $US8-9/GJ,$A9.40-10.60/GJ (at $US100/bbl oil price) at Wallumbilla, with an upside bias to short run LNG netbacks for additional gas;

e) the combination of LNG producers withdrawing from new domestic supply and LNG producers such as GLNG acting as a large gas buyer, has transformed the Queensland gas market into a high priced and short supply market; and

f) the domestic gas price for new Queensland gas contracts has increased rapidly during the last few years. Incitec Pivot’s 2015/2016 gas price suggests Queensland prices are approaching the short run LNG netback price range.

7 Northern Gas Supply to the NSW Market

7.1 Introduction Cooper Basin gas has been an integral part of the NSW gas market since 1976. As detailed in Section 3, during the most recent market phase (phase 2) northern gas (Cooper basin and CSM from Queensland) competed with southern supplies from the Gippsland Basin for NSW market share. This competition between northern and southern supplies established the NSW wholesale market gas price. With the LNG developments in Queensland, the availability of new northern gas at Moomba has changed. While small amounts of new supply from the Cooper Basin may be available during the VPA Period, the availability of material quantities of northern gas supply for the NSW domestic market no longer exists, as northern gas is drawn into the high priced Queensland market.


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7.2 Northern Gas – Queensland CSM

7.2.1 Queensland CSM to NSW Market New Queensland CSM supply at Moomba during the VPA Period is not available and this is likely to continue beyond the end of this decade. As detailed in Section 5, the LNG producers are focussed on supplying their own LNG projects and have withdrawn from supplying the domestic Queensland and southern gas markets. 7.2.2 Arrow Energy’s LNG Project Arrow Energy (“Arrow”) is jointly owned by Shell and PetroChina and is proposing a 4th LNG project on Curtis Island in Gladstone. Arrow planned to make a final investment decision in 4Q 2013, however recently announced a deferral of its LNG project due to “economics and inflation risks” (Shell chief executive Ben van Beurden public comments in the Sydney Morning Herald, 1 February 2014). It is unclear whether Arrow will ultimately proceed with its own LNG project, collaborate with an existing Gladstone LNG project, or seek to sell its upstream acreage. Shell and PetroChina spent around $US4b acquiring various CSM interests in Queensland with the objective to develop a LNG export project. If Shell and PetroChina decided to sell Arrow, a sale to a major LNG player is needed to maximise its sale price. Notwithstanding a sale to a LNG party, any transaction is likely to be well under its acquisition costs given the current value of CSM acreage is lower compared to the period when major oil and gas internationals acquired their original CSM positions during 2006 – 2008. It is highly likely that Shell and PetroChina would incur a significant loss if it proceeded with a sale of its CSM acreage. While a sale to a LNG party is likely to incur a loss, a sale to a domestic gas producer or customer would involve a write down of the majority of its acquisition costs. To recover $US4b in acquisition costs a major project (such as a LNG project) is required to generate a large NPV to recover such high acquisition costs. Commercialisation of Arrow’s reserves on the basis of a domestic project would provide immaterial value compared to a major LNG project. A joint domestic and LNG sale option is also unlikely since similar to the existing LNG projects, the scale of reserves and deliverability required to commercialise a LNG project tends to focus LNG producers on their own development rather than joint participation in the domestic market. If Arrow proceeded with its own LNG project or collaborated with another existing LNG project, its gas reserves would be committed to overseas customers and there would be limited impact on Queensland and the southern domestic markets. If Arrow sold its acreage to APLNG and QCLNG, a similar outcome is likely since these parties would acquire Arrow on the basis of an expansion of their existing LNG facilities. The only circumstance which could have an impact on east coast dynamics is a sale of Arrow to GLNG, since GLNG continues to be a major gas buyer. A better reserve position for GLNG could reduce the supply pressure on the east Australian domestic market. There are a number of issues GLNG would need to resolve such as sales


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price, non-alignment of GLNG joint venture partners to another major CSM acquisition (especially since some parties such as KOGAS are seeking to sell their GLNG interest), Santos’s unconventional gas focus in the Cooper Basin and NSW, limited synergies with GLNG’s upstream and pipeline infrastructure with Arrow’s Bowen Basin CSM assets and capital constraints of some GLNG joint venture partners. GLNG is considered a possible, but unlikely buyer of Arrow’s CSM assets. Even if some gas was sold domestically, Arrow’s project has been deferred because of its high CSM development costs which may not assist a significant reduction in east Australian gas prices. The conclusion is there are a range of outcomes which could transpire from Arrow deferring its LNG project decision. Any decision by Arrow will take time and have no impact on the NSW wholesale market price during the VPA Period. Most of the likely outcomes will continue the short market dynamics across eastern Australia. The unlikely outcomes of a GLNG acquisition of Arrow or a large scale domestic project could lead to a softening of the short market conditions, although to what extend is subject to a range of factors. Either of these outcomes is also likely to be contingent on a reduction in Arrow’s long run development costs and any gas production would not be expected until the end of this decade at the earliest. MDQ considers the deferral of Arrow’s LNG project is not relevant to the NSW wholesale market during the VPA Period.

7.3 Northern Gas – Cooper Basin Gas

7.3.1 Existing 2P Reserves The Cooper Basin joint venture’s (“Cooper Basin JV”) 2P reserves as at mid-2013 was 1828 PJ (Energy Quest, Energy Quest Quarterly Report, August 2013). This figure has increased in recent years (in December 2010 Cooper Basin JV reserves was 1311 PJ) primarily due to infilling drilling reserve bookings. Infill drilling involves drilling new wells into a mature gas field which increases the ultimate recovery factor from that existing field. Infill drilling requires a higher gas price to be economic, since the quantity of gas recovered (reserves and deliverability) per well from infill drilling is less than the original development wells.

7.3.2 Cooper Tail Gas Production

While Cooper Basin JV reserves of 1828 PJ seems large, the majority of these existing reserves are tail gas reserves. Tail gas production commences after all material new development projects to increase production has been exhausted and it is no longer possible to maintain production at a plateau rate. The Cooper Basin’s peak year of production occurred in 2001 (refer Figure 9) and since this time the Cooper Basin JV has been in tail gas production phase. The ability of producers to enter into new gas supply agreements is constrained by the shape of the tail gas profile. During the tail gas production phase, gas supply contracts drop off to broadly


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match the triangular shape of tail gas production. Third party purchases can also be made during “pinch” years where the contract profile does not perfectly match the tail gas production profile. The recent additional 2P Cooper reserves booked from infill drilling provides the first major new development opportunity in over 10 years to arrest tail gas decline and increase production.

7.3.3 Cooper Basin - Strategic and Market Issues Santos is strategically aligned to support GLNG’s reserve and deliverability challenges. Santos sold down its GLNG equity at different stages to PETRONAS, Total and KOGAS at high equity values. Arguably the sell down in Santos’s GLNG interests occurred before the project challenges were fully understood by the new partners. Given this background and Santos’s strong economic driver to ensure that GLNG has sufficient reserves and deliverability, it is incentivised to supply additional gas to GLNG from all other sources available to Santos. The Cooper Basin is naturally the largest and most logical source of supply to GLNG, given its existing upstream infrastructure and transmission pipelines connecting Moomba to Wallumbilla. Consistent with Santos’s strategic driver to support GLNG, in October 2010 Santos announced a 750 PJ gas sale from the Cooper Basin to GLNG. However this supply announcement was made without the agreement of the other joint venture partners. Beach and Origin Energy do not have the same strategic alignment with GLNG as Santos and ultimately elected to take their share of production and market their gas separately. 7.3.4 Cooper Basin Gas Flow to Queensland

Market fundamentals dictate that in an unconstrained environment, gas will flow to the market which pays the highest price for a commodity. This dynamic is exactly what has transpired with regards to the Cooper Basin. The high Queensland gas prices and large gas sale agreements to the LNG producers by Santos, Origin and AGL has facilitated major infrastructure investments to reverse the flow of gas in the South West Queensland Pipeline (“SWQP”). Presently gas flows in the SWQP from Wallumbilla to Ballera/Moomba.

APA is currently re-configuring the SWQP for bi-directional operation by mid-2014 and at that

time, the pipeline will have an Easternhaul capacity of approximately 340 TJ/day with a

maximum allowable operating pressure (MAOP) of 14.9 Mpa.

Additional compression will be installed at Moomba and Wallumbilla by 2014/15 to support

future Easternhaul flows.

(APA’s website, February 2014)


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Upon commencement of the LNG projects, large quantities of Cooper Basin gas will physically flow from Moomba to Queensland. Figure 8 details the major infrastructure developments which will enable gas flow in the SWQP to change direction from 2014-2015. New Moomba compression will increase ex-plant pressure from approximately 6.4 MPa to 14.9 MPa. Additional Wallumbilla compression will increase the delivery pressure of Moomba gas sufficient to gain entry into GLNG’s Wallumbilla to Gladstone pipeline. Transportation capacity for eastern flow from Moomba to Wallumbilla is approximately 340 TJ/d and has been fully contracted to major shippers such as Santos, Origin and AGL.

Figure 8: SWQP Flow Reversal from 2014-2015 and New Infrastructure 7.3.5 High Cooper Basin Prices

Cooper Basin prices are now linked to the prevailing price of gas in Queensland. NSW customers must pay the Cooper Basin JV’s gas price that it can achieve by selling gas

Brisbane

New Moomba Compression

Melbourne

Adelaide

Longford

Moomba Wallumbilla

Mt Isa

Gladstone

Sydney

New Moomba Compression

New Wallumbilla Compression

Ballera

SWQP


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into Queensland. The most recent Cooper Basin gas sale from Beach’s share of Santos’s GLNG contract to Origin was at a record price. Citigroup’s estimate of Beach/Origin GSA price is 7.5% Brent ($US/bbl) + $US0.5 (at $US100/bbl this is $US8/GJ, $A9.40/GJ ex-Moomba). MDQ’s and Citigroup’s price estimate is consistent with IES’s estimate of the Origin/Beach deal which was $A8-$A9/GJ ex Moomba.

7.3.6 The Cooper Contract Supply Challenge up to YED 2016 The Cooper Basin JV traditionally sold to domestic gas customers on a joint basis, where all Cooper Basin parties (Santos, Beach, and Origin) participated in each sales contract. As noted in Section 7.3.3, the different strategic drivers between the parties has introduced a change to separate marketing, where each party sells their share of production under separate contracts. The decision by Beach and Origin not to participate in Santos’s GLNG contract (and sell their share of production separately) substantially increases the Cooper Basin’s supply challenge over the next few years, requiring Santos to gross-up Cooper Basin JV production to satisfy its 50 PJ/a obligation to GLNG. What was originally intended to be 50 PJ/a Cooper Basin JV supply arrangement is now a 75 PJ/a production requirement. As noted in Section 7.3.5, Origin Retail has purchased Beach’s share of the 75 PJ/a GLNG contract and Origin is also taking its own upstream Cooper equity gas into its east Australian gas portfolio. This new GLNG supply commitment commencing in 2014/2015, combined with AGL’s existing legacy domestic gas supply agreement with the Cooper Basin JV which continues to the end of 2016, is substantially above Cooper Basin’s current production levels. Figure 9 details the historical production from the Cooper Basin JV (sales gas and ethane) and estimated forward contractual commitment up to the end of 2016.

0.0

50.0

100.0

150.0

200.0

250.0

300.0

PJ

Year

Cooper Basin Historical and Future Production

Historical Sales Gas + Ethane Production Existing Contracts

Source: Historical Sales and Ethane Production (Santos website)

Figure 9: Cooper Basin JV Production – Historical and Future


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By 2015, Cooper Basin sale gas and ethane commitments are estimated at approximately 129 PJ/a, compared to the equivalent 2013 production of approximately 94 PJ/a. In approximately 12-18 months’ time Cooper Basin JV production, which has been declining for over 10 years will need to be increased by 30 percent of its 2013 sales gas and ethane production, primarily through large scale development of low deliverability infill drilling projects. Santos estimates that over the 2014 to 2016 period over 220 Cooper Basin wells will be drilled, which is double the number of wells in the previous 3 year period. This is a significant supply challenge and before 2017, there is unlikely to be any significant quantities of new gas available from the Cooper Basin. After 2017 when AGL’s contract expires, it is likely Santos will continue to make available its share of Cooper Basin JV production to GLNG. 7.3.7 Conclusions – Northern Gas Supply The key conclusion for Northern Gas Supply to NSW are:

a) there is no new Queensland CSM available to supply the NSW gas market for an extended period of time, at least until after the end of this decade at best;

b) Arrow’s deferral of its LNG project is unlikely to change the prevailing tight market conditions across eastern Australia and certainly will have no impact on the NSW market during the VPA period;

c) the Cooper Basin wholesale gas price is currently set by Queensland LNG netbacks;

d) the Cooper Basin JV has a large production challenge to increase 10 years of production decline and satisfy their contractual obligations in 2015/2016, which is approximately 30% above current production levels;

e) during the VPA Period there is unlikely to be large quantities of new Cooper gas available for the NSW market and Cooper Basin prices are expected to approach short run LNG netback costs based on current trends in Queensland; and

f) From 2017, GLNG’s short reserve position, Santos’s strategic alignment with GLNG and spot LNG cargo opportunities will maintain LNG netback prices in the Cooper for an extended period of time. High Cooper Basin prices are expected to remain until large quantities of unconventional 2P gas reserves are successfully appraised to provide some relief to the scarcity of gas production in the Queensland market.


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8 Other Potential Sources of NSW Supply

8.1 Introduction The domestic gas market has provided more than enough high price signals to stimulate new reserves and production. However unlike other energy industries, such as the electricity industry which can commence the development process for a new power station based on a company’s interpretation of market signals, the gas industry cannot develop a gas project until gas reserves have been discovered. Hence the process of finding and appraising gas reserves adds a significant period of time to the full cycle development process. This process is made even longer, given that unconventional gas resources are increasingly becoming the mainstay of the east coast market and can take a significantly longer period to appraise and develop compared to traditional conventional gas reserves which have historically supplied eastern Australia. The gas market is actively seeking to prove up new reserves, however material quantities of new production is still many years away. The biggest mistake that participants outside the industry make is over estimating the speed that gas producers can bring material new quantities of gas production online.

8.2 NSW CSM The last 5 years has been a difficult period for upstream gas activities in NSW. The NSW government’s resource development policies has significantly disrupted the producers’ ability to access to land and undertake drilling and other appraisal activities. Figure 10 provides an update on the major NSW CSM supply opportunities.

Party Gas Resource Comments AGL Camden Abandoned Camden expansion project.

AGL Gloucester Basin Proceeding with development, first supply 2017/2018 anticipated. AGL to take Gloucester production into NSW supply portfolio.

Dart Hunter, Sydney southwest

April 2013: Suspended all NSW operations due to state government policies.

Metgasco Northern Rivers, Clarence-Moreton

Basin

Suspended operations 1Q 2013 and recommenced operations 3Q2013, but currently small 2P reserves and long way from NSW market makes gas commercialisation difficult.

Santos Gunnedah Basin CSM

Delayed, but still attempting to appraise and prove up CSM reserves. Aiming for first gas by 2017.

Figure 10: Update to Major NSW CSM Activities The conclusion is that no material new source of NSW CSM can be developed with production available for the NSW market during the VPA Period. AGL’s Gloucester Basin CSM project and Santos’s Narrabri CSM seem to be the most advanced NSW CSM projects. AGL’s Gloucester Basin CSM, will commence production after the VPA Period and will be sold into AGL’s wholesale portfolio at the NSW market price. It is not expected to have a material effect on NSW gas prices. Santos has publically indicated it is planning to deliver first gas from its Narrabri project in 2017, however


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this is subject to a range of appraisal and development factors and material quantities of gas are not expected until 2020+.

8.2.1 Cooper Basin Unconventional Gas There are a range of large and small companies seeking to appraise unconventional gas opportunities in the Cooper Basin. The Cooper Basin JV is well placed to develop new unconventional gas production, given its existing processing infrastructure. Other parties such as Beach and Chevron are likely to develop new processing facilities should they manage to prove up a large reserve base. However all parties working on unconventional Cooper Basin gas have a long period of appraisal, locating reservoir sweet, understanding geographical changes in reservoir characteristics, the best zones to fracture stimulate and optimum drilling and completion techniques. After these issues have been understood and commercial arrangements are in place, a development of the resource can commence. Large scale development of an unconventional Cooper Basin resource will not occur during the VPA Period and is unlikely prior to 2020 assuming that a successful resource is actually discovered.

9 Southern Gas Supply to the NSW Market

9.1 Introduction Gas supply from Gippsland Basin JV has been a major source of supply to the NSW market since 2002. Various expansions of EGP capacity over the last 10 years has increased Gippsland Basin JV’s market share of the NSW market. The NSW gas market has entered a new phase of reduced competition between northern and southern gas (as the LNG plants draws in northern gas). The NSW gas market is increasingly reliant on southern gas as the major source of new supply, subject to pipeline constraints which restrict the flow of southern gas into NSW. This trend of southern gas supply to the NSW market is demonstrated by the announcements in Figure 11, which are all related to delivering southern gas into the NSW market.


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Date Type Announcement 14 May 2013 GBJV BSA Lumo Energy enters into a new 22 PJ GSA from GBJV over a

three year period from 2015. Pricing under this agreement incorporates an oil linkage mechanism. (note not all this gas is destined for the NSW market and will also supply Victoria)

10 September 2013

GBJV GSA Origin enters into a new 432 PJ GSA with GBJV over a nine-year period starting in 2014. (note not all this gas is destined for the NSW market and will also supply Victoria and South Australia)

26 September 2013

APA GTA Origin enters into a new 6 year GTA with APA, including expansion of the Vic/NSW interconnect at a cost of $65m.

The announcement also notes a reduction in transportation of gas in the Moomba to Sydney Pipeline.

23 October 2013

APA GTA Energy Australia enters into a new 4.5 years GTA with APA, including an expansion of the Vic/NSW interconnect at a cost of $70m.

This new GTA replaces Energy Australia’s Moomba to Sydney transportation service, with gas being supplied into the MSP via the Vic/NSW interconnect

4 November 2013

APA GTA Lumo enters into a new 5.5 year GTA with APA, including expansion of the Vic/NSW interconnect at a cost of $25m

This new GTA replaces Lumo’s Moomba to Sydney transportation service, with gas being supplied into the MSP via the Vic/NSW interconnect.

11 November 2013

GBJV GSA Orica announces 42 PJ GSA (14 PJ per annum over three years) from GBJV beginning in 2017 to supply its Kooragang Island plant in Newcastle.

The GSA incorporates an oil linked component

Figure 11: Recent Southern Gas new Gas Supply and Transport Contracts

Notes:

1) APA GTA denotes APA Gas Transportation Agreement. 2) GBJV GSA denotes Gippsland Basin Joint Venture Gas Sales Agreement.

9.2 Southern Transportation Constraints 9.2.1 Introduction Supply of new southern gas to the NSW market is subject to new capacity being available in Jemena’s Eastern Gas Pipeline (“EGP”) or APA’s Vic/NSW interconnect. The interconnect supplies gas into APA’s Moomba to Sydney Pipeline (“MSP”) at Young in NSW. The EGP and the Vic/NSW interconnect are presently fully contracted and expansion is required to provide additional firm capacity in these pipelines.


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9.2.2 EGP Constraints As noted in Jemena’s website, the current firm transportation capacity of the EGP is 106 PJ/a. The next stage of capacity expansion involves the installation of two compressor stations which would increase EGP capacity to 130 PJ/a. The EGP is currently in a marketing phase to secure firm transportation contracts for this expansion project. Construction would commence after Jemena has secured capacity commitments from gas market participants. Assuming a construction period of 12-18 months post a final investment decision, if commercial commitments are made in the next few months, the earliest EGP expansion date would be around mid-2015. The recent announcements by APA to expand the interconnect through agreements with Origin, Lumo Energy and Energy Australia would have taken market opportunities away from Jemena’s EGP expansion project and could lead to further delays in this project. AGL is likely to be a critical partner in potential EGP expansion given its large NSW gas market share. The timing and level of commitment by AGL to new southern gas is likely to determine the timing of Jemena’s expansion project. 9.2.3 Vic/NSW Interconnect The EGP has historically transported the vast majority of southern gas to Sydney. The Vic/NSW interconnect (owned by APA) was constructed in 1998 and has only transported small quantities of Victorian gas into NSW due to compression and pipeline constraints. As detailed in Figure 11, in recent times APA has been actively competing with Jemena to secure new transportation opportunities for southern gas into NSW and announced 3 new transportation contracts with Origin (26 September 2013), Energy Australia (23 October 2013) and Lumo Energy (4 November 2013 to expand the interconnect capacity. In total, APA is investing an additional $160m to expand the Victoria to NSW interconnect capacity. APA confirmed the three expansion projects would be completed by winter 2015 and increase firm capacity of Victorian withdrawals into the Moomba Sydney Pipeline by 145 percent. MDQ estimates the interconnect expansion will increase Victoria to NSW firm transport capacity to approximately 103 TJ/d. 9.2.4 Conclusions The conclusion is that new southern gas supplies into NSW are constrained by existing infrastructure capacity until at least winter 2015. The expansion of APA’s Vic/NSW interconnect will enable additional southern gas to be delivered to the NSW market, with a forecast date for expansion of winter 2015. The potential expansion of the EGP is pending finalisation of commercial agreements and mid 2015 would be the earliest possible timeframe for expansion if commercial agreements were finalised in the near future.


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9.3 Gippsland Basin JV Commodity Gas Prices

9.3.1 Gippsland Basin JV Price Structure As indicated in Section 7, the market price for new supply ex-Moomba is based on Queensland LNG netbacks due to the transformational impact of the LNG projects. The recently announced Gippsland Basin JV GSAs noted the new ex-Longford gas prices were partially linked to the price of oil. No Australian end use gas customer desires a gas price based in $US and linked to oil price. Australian end users such as power generators, industrial customers etc. compete in an Australian market and do not desire exchange risk through the introduction of $US prices, nor do they seek a major business input such as gas costs fluctuating dramatically with movements in the price of oil. Transitioning the eastern Australia gas market from a $A with CPI escalation model to a $US price linked to oil confirms the strong market position of the sellers. In a long supply domestic market it is unlikely a change to a $US oil linked mechanism would have occurred. The commercial conclusion is that Gippsland Basin JV may seek to move its Longford gas price to an oil-linked mechanism. 9.3.2 Gippsland JV 2014 -2016 Citigroup price estimates of the recent Origin/Gippsland Basin JV agreement as: 2014 -2015 Gas Price - $A6/GJ ($2013 index to CPI) 2016 Gas Price – 70% ($2013 index to CPI) + 30% (5.8% Brent ($US/bbl)+0.5)/fx) Assuming a $US100/bbl and fx=0.85 ($2013), the 2016 price is $A6.42/GJ ($2013) IES’s estimated a higher price for the earlier gas sales agreement between Lumo Energy and Gippsland Basin JV in May 2013 (a new 3 year agreement for 22 PJ commencing in 2015). IES estimated the price under the new Lumo/Gippsland Basin JV agreement was $7/GJ ex-Longford. MDQ has adopted a more conservative approach to Gippsland Basin JV’s transitional price phase and estimates the price of gas under new Gippsland Basin JV agreements for 2014 to 2016 is in the range of $A6.25 to $A6.50/GJ ($2013).


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9.3.3 Conclusion – Longford 2014 to 2016 Prices Longford gas price conclusions are:

1) The limited availability of material quantities of new northern gas or other sources of unconventional gas has created a market environment favouring Gippsland Basin JV to secure new higher priced $US oil linked contracts as evidenced by the recent Lumo Energy and Origin agreements with Gippsland Basin JV;

2) The EGP and Vic/NSW interconnects firm transportation capacity is fully contracted. APA has recently executed 3 agreements to expand the Vic/NSW interconnect, with expansion to be completed by mid 2015. EGP’s expansion project is pending commercial agreement. Prior to mid 2015, transportation of new GBJV gas agreements to the NSW market is constrained by transportation capacity;

3) The 2014 to 2016 ex-Longford transitional price forecast is in the range of $A6.25 to $A6.50/GJ ($2013).

10 Summary of NSW Wholesale Gas Market Conditions (2014-2016)

The NSW gas market has entered a new market phase where major new supply is heavily dependent on southern gas, subject to the EGP and Vic/NSW interconnect transportation constraints that presently restrict new southern gas into NSW. The major factors which are influencing the NSW wholesale gas price during the VPA Period are:

(i) Queensland LNG projects and their short supply position;

(ii) High gas prices in the Queensland domestic market creating a price environment of LNG netbacks at Moomba;

(iii) Limited new major sources of gas to supply the NSW domestic market:

a. Cooper Basin JV has a substantial production challenge to satisfy its existing contractual arrangements up to the end of 2016;

b. Other material quantities NSW CSM or other unconventional gas production are unavailable and unlikely to be available prior to the end of this decade.

(iv) Transportation constraints for new southern gas to remain until at least mid-2015;


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(v) Cooper Basin gas prices equal to LNG netbacks and most likely increasing to short run LNG netbacks for new gas (albeit small quantities) during 2014 to 2016; and

(vi) Indicative ex-Longford price for new supply during 2014 to 2016 is $A6.25 - $A6.50/GJ ($2013).


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APPENDIX A

LNG Project’s Minimum Reserve Requirements


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A.1 Introduction The objective of Appendix A is to establish the minimum reserve requirement to satisfy the firm LNG contracts for each LNG project. The steps to analyse this minimum quantity of reserves for each LNG project are:

1) establish the firm LNG contract demand (in mmtpa);

2) calculate the upstream reserves (in PJ) to supply the contracted LNG demand in item 1);

3) determine the reserve uplift factors which are required to be applied to item 2 due to:

a. fuel gas requirement; b. reserve basis - 1P or 2P; c. swing and field redundancy; d. quantity of upstream reserves contained in tail gas production.

4) calculate the minimum reserve project requirement based on items 2 and 3

A.2 LNG Project Gas Demand A.2.1 LNG Plant Capacity and Firm Contracts

Figure A.1 provides a summary of the contract position and LNG plant capacity for the three committed Gladstone LNG projects.

Project LNG Plant Capacity

First LNG Firm LNG Contracts

QCLNG 8.5 mmtpa 4Q 2014 9.9 mmtpa2

GLNG 7.8 mmtpa 2Q 2015 7 mmtpa

APLNG 9.0 mmtpa 3Q 2015 8.6 mmtpa Source: LNG project websites

Figure A.1: LNG Plant Capacity and Firm Contracts Notes:

1) All projects are 2 LNG train developments, with the second train to be completed 6 - 12 months after the first.

2) QCLNG excess firm contracts supplied from BG’s Asian LNG portfolio.

A.2.2 Feed Gas Requirements Figure A.2 details the equivalent PJ/a of feed gas required to satisfy contract demand and LNG nameplate capacity for each project.


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Project LNG Plant Capacity (mmtpa)

LNG Plant Capacity

(PJ/a)

Firm LNG Contracts (mmtpa)

Firm LNG Contracts

(PJ/a)

QCLNG 8.5 517 8.5 517

GLNG 7.8 474 7 425

APLNG 9 547 8.6 523

Total 25.3 1538 24 1465 Source: LNG project websites and MDQ Consulting

Figure A.2: Feed Gas Requirement for LNG Contracts and Plant Capacity Notes:

1) Includes 10.5% allowance for LNG plant and pipeline fuel gas, but excludes 4% of gas lost in upstream processing activities (as per AEMO assumptions).

2) Firm LNG Contracts (PJ/a) excludes spot sale opportunities up to nameplate LNG Plant capacity

Figure A.3 details AEMO’s forecast gas demand for the Gladstone LNG projects, which is consistent with the details in Figure A.2.

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

Figure A.3: Firm LNG Contracts – Feed Gas Requirement


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A.4 LNG Projects – Reserve Assessment

A.4.1 Introduction

LNG producers are required to have sufficient reserves and deliverability to satisfy their LNG supply commitments. Asian LNG buyers consider security of supply as one of the most important factors in any LNG sale agreement. The quality and quantity of reserves is critical in providing security of supply to LNG customers. If a LNG Producer has insufficient reserves or deliverability it will seek to purchase gas from third parties suppliers to mitigate the risk of LNG contract shortfalls. LNG producers purchasing top-up gas from other domestic supply sources is the major factor that has dramatically impacted the dynamics of the east coast gas market. An assessment of the reserve and deliverability position of each LNG project is required to understand the impact on the east coast domestic market. A LNG producer’s upstream reserves sufficiency is dependent on the following factors:

a) LNG supply commitments; b) fuel gas requirement; c) reserve basis - 1P or 2P; d) swing and field redundancy; e) quantity of upstream reserves contained in tail gas production.

A.4.2 LNG Supply Commitments Figure A.4 summarises the LNG supply commitments for each LNG project.

Project LNG Contract Total LNG Contract Volume (PJ)

QCLNG 1.2 mmtpa to Tokyo Gas, 0.4 mmtpa to Chubu Electric, Chile 1.7 mmtpa, Singapore 3 mmtpa, CNOOC 3.6 mmtpa. All contracts approximately 20 year terms

93502

GLNG 3.5 mmtpa to Petronas for 20 years, 3.5 mmtpa to Kogas for 20 years

7700

APLNG 7.6 mmtpa to Sinopec for 20 years, 1 mmtpa to Kansai Electric for 20 years

9460

Figure A.4: Total LNG Contract Volume Notes: 1) Total LNG Contracts (PJ) = Total LNG Contracts (mmtpa) x 55 (PJ/mmtpa) x 20 years 2) Based on full capacity of LNG Plant (8.5mmtpa)


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A.4.3 Fuel Gas Requirement

The fuel gas requirement of a LNG facility varies depending on a range of factors such as:

a) the distance between the upstream gas source and the LNG plant. The larger the separation, the greater energy used to transport feed gas to the LNG plant;

b) plant design, technology and efficiencies of key equipment; c) ambient temperature - i.e. hot or cold climate; and d) whether grid electricity is a variable option to supply the LNG plant and/or

upstream facilities.

AEMO has allowed a fuel gas allowance of 10.5% for the liquefaction process and gas transportation. AEMO notes that 4% of gas is estimated to be lost in upstream and downstream processes, however AEMO chose not to include this in its calculations. A fuel allowance of 10.5% has been adopted in this report.

A.4.4 Reserve Basis: 1P or 2P Traditionally all LNG projects that utilise offshore reserves use 1P (proved) reserves to cover their contractual supply commitments. The CSM LNG projects have based their contractual commitments on 2P (proved and probable) reserves. By definition 2P reserves only have a 50/50 chance of achieving this reserve outcome. While many of the LNG projects are supplied from more than one major CSM field (which creates a portfolio effect and increases the likelihood of a 2P reserve outcome), it would be appropriate to provide an uplift factor on reserves where firm contracts are based on 2P sales instead of 1P sales. An uplift factor is commonly used in domestic contracts based on 2P reserves, especially where the buyer’s project is project financed. The reliance of the Queensland LNG projects on 2P reserves and not 1P is based on the argument that future CSM 3P (proved, probable and possible) to 2P conversion will provide the necessary security for a 2P LNG sale commitment. As shown in Section 5.5, in the case of GLNG substantial 3P to 2P reserve conversion has not transpired and 2C reserves have decreased over the last 2-3 years. Notwithstanding MDQ’s concern of 2P being the basis for the Queensland LNG projects, no additional reserve uplift factor has been included in this report to allow for this risk. A.4.5 Tail Gas Profile and Reserves

Foundation LNG sale contracts which commercialise a new LNG plant typically have a short ramp in volumes to a plateau production rate which is constant for 15-20 years. At some point over the life of a gas field, upstream field deliverability becomes insufficient to maintain the plateau production phase and the tail gas phase commences where production declines due to exhaustion of new deliverability projects. Figure A.5 outlines the different phases of production.


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Figure A.5: Upstream Production Phases

The total field reserves published by the LNG producers represent recoverable reserves from all three phases, however foundation long term LNG sales contracts only use production from the plateau phase. Hence the field's total reserves have to be uplifted to allow for "non contract" sales associated with the ramp-up and tail gas phase. It would be common for tail gas to be ultimately sold as LNG, however this is done later in the life of a field when the timing and shape of the tail gas profile is better understood.

The quantity of reserves in the ramp-up and tail gas phases vary from field to field depending on the technical characteristics of each reservoir. Conventional production does not usually require a ramp up phase since deliverability can be brought on at maximum rates at the start of production from conventional wells.

Unconventional production such as CSM and shale gas tends to have longer tail gas phase and being low deliverability also requires a ramp up phase. In total 10% to 20% of production can be in the ramp-up and tail gas phases. For the purposes of this reserve assessment, 15% of total reserves has been assumed to be contained in the ramp-up and tail gas phases.

A.4.5 Contract Swing and Upstream Redundancy

LNG offtake tends to be reasonably constant throughout the year and the large storage capability of the LNG tank ensures only a small amount of swing or peak MDQ is required from upstream facilities. Where contract swing is required, additional field deliverability must be on line to satisfy the peak production requirement. This additional deliverability requires additional reserves to be developed and available for production. Hence it would be appropriate to uplift the required reserves to provide for this additional deliverability requirement.

It is also not possible to utilise 100% of upstream field productivity all the time. Approximately 5% of field capacity would be off line at any time for planned or unplanned maintenance. Similar to contract swing, additional reserve cover would be required to provide redundant upstream deliverability to allow for field downtime. For

Plateau Production Phase Tail Gas Ramp-up Gas

PJ/a


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the purposes of this report, conservatively no uplift factor for contract swing or upstream redundancy has been incorporated into this reserve assessment of the Queensland LNG projects A.4.6 Project Reserves and Minimum Reserve Requirement

Figure A.6 summarises the reserve position (in PJ) of each LNG Producer as at mid-2013.

Project 1P 2P 3P 2C

QCLNG 3047 10518 11397 4508

GLNG 1797 5376 6823 1638

APLNG 1527 13349 16110 3644

Source: Energy Quest Quarterly August 2013

Figure A.6: LNG Project Reserve Position (mid 2013 in PJ)

Figure A.7 analyses each LNG producers’ reserves (in PJ) that are required to satisfy its firm LNG contracts.

Project LNG Contract Volume1

(PJ)

Existing Domestic Contracts

(PJ)

Third Party Purchases3

(PJ)

Minimum Reserve

Requirement2

(PJ)

QCLNG 9350 750 6403 12020

GLNG 7700 140 12153 8420

APLNG 9460 2210 nil 14830

Source: MDQ Consulting

Figure A.7: Minimum Reserve Requirement to Satisfy LNG Projects (in PJ)

Notes:

1) LNG Contract Volume from Figure A.4 2) Minimum Reserves = (LNG Contract Volume + Existing Domestic Contracts – Third Party

Purchases) x 1.105 (Fuel Uplift) x 1.15 (Ramp and Tail Gas Uplift) 3) Refer Section 5.6 for Third Party Purchase Details


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Note MDQ’s Final Minimum Reserve Requirements are slightly lower than Energy Quest estimates as detailed in the Figure A.8.

Project

Energy Quest – Minimum Reserve

Requirements (PJ)

MDQ Minimum Reserve

Requirement (PJ)

QCLNG 12500 12020

GLNG 10150 8420

APLNG 15,6861 14830

Source: Energy Quest Energy Quarterly August 2013

Figure A.8: Comparison – Minimum LNG Project Reserves

Notes:

1) Origin reserve estimate, not Energy Quest assessment, adjusted for tail and ramp gas requirement.


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APPENDIX B


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MDQ Consulting – Craig Langford Biography MDQ Consulting ("MDQ") is an independent advisory business, providing strategic and commercial energy advice to a range of upstream, retail and power generation companies. MDQ specialises in the development of business strategy, commercial advice and negotiation and execution of a full suite of gas industry agreements. MDQ's clients have included Alinta, APA, AEMO, Glencore, AGL,

AWE, Jemena, Bow Energy, Westside, Mosaic, Intergen, Origin, Drillsearch, Westside and others.

Craig Langford has over 17 years’ experience in the oil and gas industry, working for Santos and as a director of MDQ. Prior to working for MDQ for the last 5 years, Craig worked for over 12 years at Santos in a number of senior strategic and commercial roles in Brisbane and Adelaide. For the last 5 years at Santos he was responsible for commercial activities of Santos’s east Australian gas business, providing leadership on gas market strategy, business development, major price reviews, and Santos’s Victorian retail and wholesale business. He was responsible for upstream east Australian gas market activities for Santos’s CSM gas assets in Queensland, the Cooper Basin and southern offshore fields. This provided him with a unique ‘hands on’ experience and has been an industry leader during major developments in the east coast gas market. Craig has in depth operational understanding and market experience in the Australian gas industry and has represented Santos and APPEA on a number of government and industry groups.

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