Available East Coast Gas Study

An independent report prepared by EnergyQuest for Marathon Resources Limited

8 November 2014

Contents List of figures ...... 2 List of tables ...... 3 Terms of reference ...... 4 Key points ...... 4 Eastern gas demand and supply context ...... 5 Gas demand ...... 5 Gas supply ...... 6 Interstate trade ...... 8 Gas prices ...... 9 LNG project impact ...... 10 Oil price...... 11 LNG projects starting to ramp up ...... 11 Gas demand and contracts ...... 12 Gas-fired generation ...... 13 Major industrial demand ...... 18 Utility demand ...... 21 Recent contracts ...... 24 Demand and supply balance ...... 25 Further supply sources ...... 27 Gas prices ...... 28 LNG netbacks and development costs ...... 28 Contract gas prices ...... 29 Appendix: Power station maps ...... 31 Abbreviations ...... 35 Conversion factors ...... 38 Terms of use ...... 39

List of figures Figure 1 East coast gas consumption...... 5 Figure 2 East coast gas supply ...... 7 Figure 3 Sales gas production and consumption 2013 (PJ) ...... 9 Figure 4 Annual average east coast gas prices...... 10 Figure 5 Oil price, Brent (US$/bbl) ...... 11 Figure 6 Daily gas production July 1 to October 19 2014 ...... 12 Figure 7 STTM gas price 1 July to 21 October 2014 ...... 12 Figure 8 NEM gas demand for generation (PJ) ...... 17 Figure 9 GPG surplus (contracted less demand forecast) (PJ) ...... 17 Figure 10 Contract profile major industrials (PJ) ...... 21 Figure 11 Major industrial gas demand (PJ) ...... 21 Figure 12 AGL gas sources (PJ) ...... 22 Figure 13 gas sources (PJ)...... 23 Figure 14 Utility demand (ex-power generation) (PJ) ...... 24 Figure 15 East coast gas demand 2014-20 (PJ) ...... 26 Figure 16 East coast domestic demand and contracts (PJ) ...... 26 Figure 17 East coast gas demand and supply 2014-2020 (PJ) ...... 27 Figure 18 Short-run LNG netbacks ...... 28 Figure 19 Australia rolling three year finding and development costs, oil and gas, proved and probable ($/GJ) ..... 29 Figure 20 Contract gas prices ($/GJ, 2014$)...... 30

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Figure 21 Queensland power stations ...... 31 Figure 22 NSW power stations ...... 32 Figure 23 Victorian and Tasmanian power stations ...... 33 Figure 24 South Australian power stations ...... 34

List of tables Table 1 South East Australia gas demand and supply ...... 6 Table 2 East coast gas production and reserves ...... 8 Table 3 Major east coast gas buyers ...... 13 Table 4 Queensland gas-fired generation ...... 14 Table 5 NSW and Victoria gas-fired generation ...... 15 Table 6 and Tasmania gas-fired generation ...... 16 Table 7 Queensland industrial contracts ...... 19 Table 8 Other east coast industrial contracts ...... 20 Table 9 Gas supply contracts, other utilities (PJ) ...... 23 Table 10 East coast gas contracts signed since October 2010 ...... 25

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Terms of reference Marathon Resources Limited is looking at the East Coast market, including the existing networks in Qld, NSW, Victoria and South Australia. The end position they are seeking to understand in detail is  What customers need gas in what volume and over what timeline,  What are the estimated cash costs of some of the newer projects, and  When the current suite of gas contracts expire. Obviously, in compiling this data, the reserves/ resources and current demand profiles will be available.

Key points  The east coast domestic gas market is currently in a period of transition as the LNG projects begin commissioning. The much-expected surge of ramp gas is now happening, increasing production and driving down short-term gas prices, at least in Queensland, leading to a jump in gas-fired power generation.  Looking beyond the ramp-gas phase however, insufficient new production capacity is being developed to service the LNG projects, which will draw gas from the domestic market (particularly from gas-fired power generation). This is exacerbated by restrictions on developing NSW gas resources.  Prices under new gas contracts have risen significantly, with difficulties also for buyers in renewing existing contracts. While there have been a number of contract renewals by domestic gas-buyers they have generally been for short periods, with attempts also to explore potentially lower cost alternatives such as upstream equity.  There is significant potential demand among utilities and industrial gas buyers but particularly among industrial buyers demand is price elastic. Industrials may be able to afford $6/GJ but not $10/GJ.  There are a number of new potential gas supply sources on the east coast, aiming to fill the perceived shortage. However most of them have challenges in terms of cost, development time or risk. There is an opportunity for Marathon Resources Limited, particularly in the southern states by backfilling Queensland and Cooper Basin gas that would otherwise have supplied the domestic market.  Demand for gas for baseload generation is likely to fall significantly so the opportunity for Marathon Resources Limited is more likely to be in meeting utility or industrial needs.  Among the utilities, AGL, Energy Australia and GDF Suez (Simply Energy) all stand out as having expiring contracts in the near-term.  Industrials will need a commercially viable price. A delivered price of $7-8/GJ would probably be attractive in current circumstances. Among industrials, Adelaide

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Brighton, Arrium, Orora, Orica, and BlueScope Steel are some of a number of possibilities.

Eastern Australia gas demand and supply context Gas demand East coast gas consumption has been reasonably stable in recent years, with weather being the main driver of any volatility (Figure 1). The east coast consumed 703 PJ of gas in 2013-14, of which 212 PJ (30%) was used in gas-fired power generation. The carbon tax did not have a big impact on use of gas for power generation. Figure 1 East coast gas consumption

Source: EnergyQuest Victoria is the largest east coast gas-consuming state, followed by NSW and South Australia (Table 1). Use of gas for power generation varies from around 90 PJ in Queensland to less than 20 PJ in Victoria and Tasmania. Coal remains the major fuel for power generation in NSW, Victoria and Queensland. Wind is increasingly important in South Australia.

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Table 1 South East Australia gas demand and supply Gas demand and supply (PJ) NSW Vic Qld SA Tas Total 2012 Consumption 160 221 219 104 18 722 of which power gen3117926012211 Production 6 379 254 94 0 733

2013 Consumption 156 216 223 98 14 707 of which power gen331986557200 Production 5 380 254 85 0 724 Source: EnergyQuest The high level of Victorian demand reflects a large residential market (101 PJ in 2011-12) and substantial manufacturing demand (80 PJ in 2011-12). Victorian gas demand was flat over the five years to 2011-12. Residential demand increased by 8.2% but manufacturing demand fell by 8.5%. NSW gas consumption has been growing. Consumption in 2011-12 was 18.4% higher than five years previously, due to increased gas-use for power generation. NSW retail demand is only a quarter of that in Victoria. The largest gas-use is manufacturing, which consumed 81 PJ in 2011-12, similar to consumption five years previously. Queensland gas consumption grew by 23.7% in the five years to 2011-12, due to increased gas-use for power generation. Apart from power generation, manufacturing is the largest use of gas in Queensland, using 71 PJ in 2011-12, 14.7% lower than five years previously. Only 3 PJ is consumed in the residential market. Gas consumption in South Australia is largely driven by power generation. Consumption in 2011-12 was similar to five years previously but has been lower. Apart from power generation, manufacturing is also the next largest gas-user in South Australia, consuming 44.9 PJ in 2011-12, higher than five years previously. Tasmanian gas consumption is relatively low (14 PJ in 2013), but increasing, largely driven by power generation. Gas supply The east coast domestic market is heavily reliant on supply of Victorian gas (from Longford and the Otway Basin) and Queensland CSG (Figure 2). Cooper Basin production has fallen from 102 PJ to 86 PJ (-16%) over the last 5 years, being more than replaced by Queensland CSG. Table 2 shows east coast gas production by basin for the 12 months to June 2013 and 2014, 2P reserves at June 2014, the volume of gas contracted from 2014 and the reserve to production ration (reserve life). The Cooper Basin JV is not fully contracted but most of the unsold gas is tail gas. The reserve life will shrink to 14 years if they are successful in increasing production to 120 PJ/a to meet the LNG contract. Some of the third-party gas is contracted to the JV.

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The Gippsland JV has the largest uncommitted conventional reserves on the east coast. Costs are high for new development, with a break-even gas price of $5-7/GJ. The JV also has considerable market power. The Otway Basin is largely contracted. AWE will be able to market its share of gas from BassGas from 2018 but otherwise it is fully contracted. The long reserve life for the Surat-Bowen reflects the fact that LNG production has not yet commenced. Reserve life will drop to around 30 years when all three LNG projects are in full production. AGL appears to be the only seller of uncontracted domestic gas in Queensland. Much of the domestic gas contracted by power stations is likely to be re-sold for LNG. Development in NSW is effectively frozen. Figure 2 East coast gas supply

Source: EnergyQuest

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Table 2 East coast gas production and reserves 12 months to: 2P reserves Contracted 2014 2017 Reserve/Production Reserve/Production Jun 2014 Jun 2013 PJ PJ PJ PJ Cooper Cooper JV 81.9 84.4 1,668 1,108 20.4 10.9

Other 4.6 1.7 128 27.9 24.6 Total Cooper 86.5 86.1 1,796 20.8 11.4 Gippsland Gippsland JV (incl 230.3 262.3 3,333 1,399 14.5 8.7 Kipper) Longtom 11.3 11.3 110 275 9.8 7.0 Total Gippsland 241.6 273.6 3,442 1,674 14.2 8.7 Bass 17.6 11.0 221 165 12.6 9.2 Otway Thylacine 59.8 50.3 361 416 6.0 3.1 Casino 30.6 33.8 232 244 7.6 4.7 Minerva 23.0 25.2 95 55 4.1 1.1 Total Otway 113.3 109.3 688 715 6.1 3.1 Surat-Bowen 277.4 253.0 44,495 160.4 24.7 NSW 4.8 5.4 2,353 0 486.0 Total 741.1 738.3 52,995 71.5 22.3 Source: EnergyQuest Interstate trade The eastern states are all linked by pipelines. Figure 3 shows total pipeline flows in 2013.

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Figure 3 Sales gas production and consumption 2013 (PJ)

Source: EnergyQuest NSW now gets around two-thirds of its gas from eastern Victoria, and the remainder through the Moomba Pipeline. South Australia gets just over half of its gas from the Otway Basin through the SEAgas pipeline and the remainder through the Moomba Adelaide Pipeline. Queensland exports gas to South Australia and NSW. Increasingly major pipelines are being re-configured for bidirectional operation. This applies to the Moomba Sydney and Moomba Adelaide pipelines. The South West Queensland Pipeline is already bidirectional. Gas prices Figure 4 shows trends in east coast gas prices. The Origin and APLNG series are average prices realised under historic contracts, together with some spot sales. APLNG prices are Queensland CSG averages. The Origin series mainly reflects east coast conventional gas and CSG but also includes 15% of WA and New Zealand gas. The Origin and APLNG series show gradual increases to just over $4/GJ for Origin and $3.50/GJ for APLNG. The other data series show average prices for relatively small sales of short-term volumes. Spot prices are more volatile than contract prices but the average for 2013-14 was similar to the Origin average.

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Figure 4 Annual average east coast gas prices

Source: EnergyQuest LNG project impact Until now the east coast market has been purely domestic. However the three plants currently under construction are close to finalisation. This is a massive development. Queensland will have similar LNG capacity to Malaysia and, in global terms, will only be behind Qatar, Trinidad Tobago and Indonesia in capacity (as well as Western Australia). QCLNG is aiming for first cargo by year end. The general view is that they are struggling to achieve this timing although BG has re-affirmed this timing as of late October 2014. Ruby- Jo, Bellevue, Kenya and Windibri, the major upstream developments for Train 1, are now in production and LNG plant commissioning is underway. GLNG is around 90% complete, with first gas in the pipeline. They are targeting first cargo in Q3 2015. APLNG is 82-85% complete. The Condabri upstream development is in production. All Train1 modules are in place, the main pipeline load-out jetty and one of two LNG tanks are complete. Preparations are being made to enter the LNG plant commissioning phase. The first cargo is planned for mid-2015. However APLNG has contracted most of the gas from its joint developments with QGC to QGC for the first two years of QCLNG operation. Delays in QCLNG may have implications for APLNG timing. The three projects will add around 830 PJ of east coast demand in 2015, 1,500 PJ in 2016 and 1,650 from 2017.

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Oil price The fall in the oil price (Figure 5) is not expected to impact on development of the three projects already under construction, which have contracts they have to fulfil. They need to ramp up as quickly as possible to start earning cash so there is unlikely to be a slowing down of development. It is also expensive to demobilise and re-mobilise. GLNG have some S-curves in their contracts to manage oil price risk and Origin has said that a US$50/bbl oil price over the life of APLNG would allow them to recover their cost of capital. US$35/bbl would cover project costs and financing obligations. However the fall in the oil prices, if sustained, will make plant expansion more difficult. Figure 5 Oil price, Brent (US$/bbl)

Source: EIA LNG projects starting to ramp up Queensland CSG production is starting to ramp up for the start-up of the LNG projects (Figure 6). QGC operated fields were producing 375 TJ/d in late October 2014 compared with 222 TJ/d in Q3 last year. Short-term gas prices in Brisbane have slumped as gas production has ramped up (Figure 7). Queensland gas-fired generation in Q3 2014 was 42% higher than in Q3 2013, despite low power prices. Origin has said they are buying ramp gas rather than producing their own. Other generators and industrial users appear to be buying spot gas rather than drawing on their contracts. Stanwell had announced that Swanbank E was to be taken out of production from October but is still generating in November, utilising cheap spot gas. It is difficult to forecast how long the ramp-up phase of abundant gas and low spot prices will last. All of the projects are now interconnected so it may be that GLNG will sell its ramp gas to QCLNG rather than selling it in the domestic market. (GLNG is also better placed to turn down its fields). APLNG has potential to use any surplus ramp gas in the Darling Downs Power Station. Overall, the ramp-gas phase may be short-lived unless there are major commissioning problems with any of the LNG plants.

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Figure 6 Daily Queensland gas production July 1 to October 19 2014

Source: AEMO Figure 7 Brisbane STTM gas price 1 July to 21 October 2014

Source: AEMO

Gas demand and contracts Table 3 lists major east coast gas buyers/users. AGL and Origin account for over half east coast gas sales or direct use as generators. Generators generally contract direct with gas producers (or have their own upstream interests). Most major industrial users in Queensland also contract direct with producers but elsewhere they have traditionally Level 30 91 King William St Adelaide SA 5000 Telephone (08) 8431 7903 Mobile 0419 828 617 Email [email protected] ABN 18 503 484 404 ACN 139 665 295 www.energyquest.com.au 12

sourced their gas from utilities such as AGL or Origin. However some industrials are now entering into agreements with upstream producers (e.g. Orica, Orora, Austral Bricks, Simplot, Dow Chemical). Table 3 Major east coast gas buyers Buyer Category Direct Buyer Category Direct contract contract wi th wi th producer? producer? Adelaide Brighton Industrial User Retailer Yes AGL Generator/Retailer Yes Marubeni Generator ?

APA Group Industrial User Murray Goulburn Industrial User Arrium Industrial User O-I Industrial User Asaleo Care Industrial User Orica Industrial User Yes Australian Paper Industrial User Origin Energy Generator/Retailer Yes Austral Bricks Industrial User Orora Industrial User BHP Billiton Industrial User Yes Qenos Industrial User Yes BlueScope Steel Industrial User Queensland Alumina Industrial User Yes Industrial User Queensland Nickel Industrial User Yes Caltex Industrial User Queensland Nitrate Industrial User Yes Cement Australia Industrial User Industrial User Yes Copper Refineries Industrial User Royal Melbourne Hospial/ Generator/Industrial User CSR Industrial User Sibelco Industrial User Dow Chemical Industrial User Simplot Industrial User Energy Australia Generator/Retailer Yes Generator/Retailer ?

ERM Power Generator Yes Stanwell Generator Yes GDF Suez Generator Yes Transfield Services Generator Hydro Tasmania Generator/Retailer Yes Visy Industrial User

Incitec Pivot Industrial User Yes Xstrata Industrial User Yes Jemena Industrial User Kimberly-Clark Industrial User Source: EnergyQuest Gas-fired generation Table 4 lists Queensland gas-fired power generators with gas-use, operator, type, year commissioned, capacity and gas supply arrangements. Table 5 does the same for NSW and Victoria and Table 6 does the same for South Australia and Tasmania.

While there are a number of supply contracts coming to an end, the outlook for base-load gas-fired generation is challenging due to falling electricity demand, growing renewables, abolition of the carbon tax and higher gas prices beyond the ramp gas phase. In Queensland Stanwell announced in February 2014 that Swanbank E, an efficient CCGT commissioned as recently as 2002 was to be closed for up to three years from 1 October 2014, with the contracted gas to be on-sold. Swanbank E is still generating so this appears to have been pushed back but is still likely. In Adelaide GDF Suez is mothballing more than half Pelican Point generating capacity from early 2015, reducing capacity from 478 MW to 230 MW. Pelican Point is a new, efficient CCGT commissioned in 2000.

Maps showing the locations of power stations are included as Figure 21, Figure 22, Figure 23 and Figure 24 in the Appendix.

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Table 4 Queensland gas-fired generation Gas use 12 months to: Operator Type Commissioned Capacity Capacity Gas supply Jun 2014 Jun 2013 utilisation Tj Tj (average annual) MW Queensland Darling Downs Power Stn 24 489 21 247 Origin CCGT 2010 58.2% 630 APLNG. Only using about half contracted gas (~44 PJ/a). Origin appears to be on‐selling contracted gas, eg Origin contracts to GLNG. Braemar Power 19 181 18 201 Alinta OCGT 2006 36.8% 504 4 PJ/a from QGC to 2016, 1.5 PJ/a from AGL to 2021, 4.5 PJ/a from GLNG to 2016, 10 PJ/a from Arrow to 2024. Swanbank E 17 287 10 485 Stanwell CCGT 2002 69.1% 385 Withdrawn from service for 3 years from October 2014. Contracted gas to be on‐sold. 4 PJ/a from QGC to 2016, 8 PJ/a from GLNG to 2017, 4 PJ/a from Arrow to 2022. Braemar 2 14 540 11 773 Arrow OCGT 2009 28.0% 519 Arrow fields. Yarwun 13 673 14 134 Rio Tinto Cogen 2010 90.0% 160 Rio has a 5 PJ/a contract expiring in 2014 but a 23 PJ/a contract from APLNG to 2030. Condamine A 4 461 4 340 QGC CCGT 2010 61.8% 140 QGC fields. Yabulu 2 054 4 582 AGL CCGT 2005 12.6% 240 AGL/Arrow Moranbah field. Roma 786 451 Origin OCGT 1999 9.3% 80 Origin portfolio Oakey 624 300 AGL OCGT 2000 2.2% 288 AGL. Barcaldine 25 82 Ergon CCGT 1996 0.6% 57 Small user. Mackay GT 4 5 Stanwell OCGT 1976 0.0% 34 Small user. Mica Creek Stanwell Steam/CCGT 1997‐2001 325 Capacity reduced to 100 MW by end of 2014 with commissioning of Diamantina. 16.5 PJ/a from Cooper Basin to 2013. Residual probably supplied via other Stanwell contracts. Diamantina APA/AGL CCGT 2014 242 13 PJ/a from AGL ex‐QGC contract to 2024. Total Qld 97 123 85 601 Source: EnergyQuest

Table 5 NSW and Victoria gas-fired generation Gas use 12 months to: Operator Type Commissioned Capacity Capacity Gas supply Jun 2014 Jun 2013 utilisation Tj Tj (average annual) MW NSW Tallawarra 22 894 19 808 Energy Australia CCGT 2009 82.1% 435 ~20 PJ/a from Longford to 2018 Smithfield Energy Facility 7 998 8 340 Marubeni CCGT 1997 62.8% 160 ~11 PJ/a from Longford to 2014. May have been extended. Uranquinty 2 517 3 851 Origin OCGT 2009 8.0% 664 Origin portfolio Colongra 151 567 Delta OCGT 2009 0.2% 668 Small user. Total NSW 33 561 32 566 Victoria Mortlake 18 272 18 028 Origin OCGT 2012 34.2% 566 Origin Otway fields. Gas supplied by Energy Australia and power sold to Newport 2 260 1 904 Industry Funds Mgt Steam 1980 5.0% 510 Energy Australia. Probably supplied from Longford. Contract details Bairnsdale 1 565 1 336 Hydro Tasmania OCGT 2001 19.1% 92 not known. Jeeralang B 305 316 Industry Funds Mgt OCGT 1980 0.9% 228 Gas supplied by Energy Australia and power sold to Energy Australia. Laverton North 185 173 Snowy Hydro OCGT 2006 0.6% 320 Small user. Somerton 165 236 AGL OCGT 2002 0.8% 160 Gas from AGL portfolio. Jeeralang A 138 60 Industry Funds Mgt OCGT 1980 0.4% 220 Gas supplied by Energy Australia and power sold to Energy Australia. Valley Power Gas Turbines 130 177 Snowy Hydro OCGT 2002 0.3% 300 Small user. Total Victoria 23 019 22 230 Source: EnergyQuest

Table 6 South Australia and Tasmania gas-fired generation Gas use 12 months to: Operator Type Commissioned Capacity Capacity Gas supply Jun 2014 Jun 2013 utilisation Tj Tj (average annual) MW SA Torrens B 15 986 19 332 AGL Steam 1977 19.0% 800 30 PJ/a to 2017 from Origin Otway. Currently finalising deal for 17.2 PJ/a from Otway for 2018‐21.

Pelican Point 13 499 21 804 GDF Suez CCGT 2000 42.2% 478 GDF Suez plans to reduce capacity to 230 MW from early 2015 due to lower power demand, competition from renewables and higher gas prices. 22 PJ/a to 2015 from BHP Billiton Minerva field in Otway Basin. Gas contract likely to have been extended at lower volume. Osborne 11 976 11 110 ATCO/Origin CCGT 1998 87.4% 185 13.5 PJ/a from Origin. Power sold to Origin. Torrens A 4 206 5 530 AGL Steam 1967 8.0% 480 30 PJ/a to 2017 from Origin Otway. Currently finalising deal for 17.2 PJ/a from Otway for 2018‐21.

Ladbroke Grove 2 697 1 072 Origin OCGT 2000 29.4% 84 Origin Otway fields. Quarantine 2 552 1 611 Origin OCGT 2002 15.8% 220 Origin portfolio Hallett 495 864 EnergyAustralia OCGT 2002 2.0% 203 Small user. Mintaro 103 157 GDF Suez OCGT 1984 1.0% 90 Small user. Dry Creek 40 91 GDF Suez OCGT 1973 0.2% 156 Small user. Total SA 51 554 61 572 Tasmania Tamar V CC 6 437 12 168 Hydro Tasmania CCGT 2009 38.1% 205 Supplied ex‐Longford. Contract details not known.

Bell Bay Three 75 140 Hydro Tasmania OCGT 2006 0.7% 105 Supplied ex‐Longford. Contract details not known.

Tamar V Peaking 0 61 Hydro Tasmania OCGT 2009 0.0% 178 Supplied ex‐Longford. Contract details not known. Total Tasmania 6 512 12 369 Source: EnergyQuest

Figure 8 shows EnergyQuest’s forecast of volumes of gas contracted for NEM generation compared with volumes contracted. This assumes that low short-term gas prices in Queensland are not prolonged. Figure 8 NEM gas demand for generation (PJ) NEM gas demand for generation (PJ) 300

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0 2014201520162017201820192020 Contracted 243.3 232.3 208.3 200.8 159.8 129.8 129.8 EQ GPG forecast 194 155 155 119 120 120 120 Source: EnergyQuest, IES, AEMO Figure 9 GPG surplus (contracted less demand forecast) (PJ) GPG surplus (PJ) 90

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0 2014 2015 2016 2017 2018 2019 2020 Source: EnergQuest

Figure 9 shows the surplus of contracted gas implied by the forecast of gas-use for power. In Queensland in particular there is nearly 100 PJ of gas contracted for power generation that is likely to be sold into LNG. This appears to be happening already with Origin and undisclosed parties having agreed to sell up to 280 PJ to GLNG. With an average gas price under existing contracts of around $3.50/GJ, power generators can make a substantial margin by re-selling their contracted gas. Major industrial demand Table 7 and Table 8 show disclosed gas contracts between gas producers and industrial companies, which are mostly in Queensland. Figure 10 shows the contract profile for Rio Tinto, Incitec Pivot and BlueScope Steel. Incitec Pivot stands out as a major gas buyer without long-term gas supplies, particularly for Duchess near Mt Isa but also for Gibson Island in Brisbane. The short-term deal for Duchess is believed to be around $11/GJ delivered ($$9.50/GJ ex-Moomba). BlueScope Steel’s contracts expire within the next two years. Based at Port Kembla, they are currently supplied from Longford. Orora, Orica and Austral Bricks have all done conditional deals with Strike Energy for possible gas supplies based on Cooper Basin coals. These are for southern state markets. Industrial companies taking exploration risk is a new development and shows the hunger by industrial companies for “cheaper” gas (i.e. ~$6/GJ ex-field) even if it is twice historic prices. There should be some indication of whether or not this play is likely to be successful by the end of the year (based on whether or not there has been gas breakthrough. Arrium and Adelaide Brighton are two important SA industrial customers who are currently supplied by AGL. Their load is ~5 PJ/a each. Both are connected to the Moomba Adelaide Pipeline and would be natural customers for Marathon Resources Limited. Figure 11 shows EnergyQuest’s forecast of gas demand by major industrial companies. Gas-use by major industrials falls from 120 PJ to 85 PJ. However the forecast is sensitive to gas price and depends on whether companies such as Incitec, Orica, BlueScope and Arrium are able to secure long-term contracts at viable prices (as well as on all the other factors impacting on their operations).

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Table 7 Queensland industrial contracts Field Market Seller Buyer Average Contract Market Likely Comments (Operator) Annual Status Type Expiry Quantity PJ Argyle Brisbane BG Group Incitec Pivot 7.4 Firm Industry 2017 7.4 PJ/a over 10 years from October 2007 All Qld BG Group BOC 2 Firm Transport 2026 30 PJ over 15 years starting July 2011. QGC Mt Isa AGL Xstrata 13.1 Firm Industry 2024 138 PJ over 10.5 years from May 2013. Gas from QGC contract. GTA with APA. QGC Mt Isa AGL Incitec 10.5 Firm Industrial 2016 23 month GSA, will increase costs by $50 million pa. Implies a new delivered cost around A$11/GJ. Spring Gully/Talinga Gladstone APLNG Rio Tinto 23.5 Firm Industry 2030 470 PJ over 20 years from 2010. (Yarwun expansion). Power cogen used 13.9 PJ 12 months to Sept 2013. Acil assumes 13 PJ/a for cogen and 7.2 PJ/a for calcining. Spring Gully Gladstone APLNG QAL 14.3 Firm Industry 2021 16 PJ/a to 2021 Spring Gully Brisbane APLNG Incitec Pivot 10 Firm Industry 2018 7.5 PJ/a to 2017 Spring Gully Rockhampton APLNG QMAG 1.8 Firm Industry 2014 1.8 PJ/a to 2014 Origin portfolio Mt Isa Origin MMG 3.1 Firm Power 2020 3.1 PJ/a for 7 years from 2013 from Origin Energy portfolio. According to 21 December 2012 price is not linked to oil and rises to a flat price of close to $9/GJ during the contract. Price is ex-Wallumbilla or Ballera according to Kylie. Four years for Century at 4.3 PJ/a and 3 years for Dugald River at 1.7 PJ/a. Fairview Gladstone Santos Orica 2 Firm Industry 2017 1.8 PJ/a to Orica until 2017. Moranbah Moranbah Arrow Incitec Pivot 7 Firm Industry 2027 Supply 7PJ/year for 15 years from mid-2012 to Ammonium Nitrate Plant at Moranbah Moranbah Townsville Arrow Queensland 6 Firm Industry 2022 6 PJ/a to Queensland Nickel Industries Nickel Industries

Moranbah Townsville Arrow Copper 0.25 Firm Industry 2016 0.25 PJ/a to Copper Refineries Pty Ltd Refineries Moura Moura WestSide Qld Nitrate 3 Firm Industry 2014 3 PJ/a to 2014. Total 104 Source: EnergyQuest

Table 8 Other east coast industrial contracts Field Market Seller Buyer Average Contract Market Likely Comments (Operator) Annual Status Type Expiry Quantity PJ Cooper Basin NSW Strike Orica 7.5 Conditional Industrial 2036 Conditional deal with Strike, commencing 2017, 20 years. Cooper Basin Strike Orora 3.0 Conditional Industrial 2026 Conditional deal with Strike, commencing 2017, 10 years. About 60% of Orora's gas needs. "Towards the bottom end of $6-8/GJ." Cooper Basin NSW Strike Austral Bricks 1.3 Conditional Industrial 2026 Conditional deal with Strike, commencing 2020, 10 years. Cooper Basin NSW Strike Orica 10.0 Conditional Industrial 2029 Conditional deal with Strike, commencing 2017, 10 years. GBJV NSW Esso/BHP Blue Scope 9 Firm Industrial 2014-2016 AFR 16 October 2013, price currently less than (NSW) $3.50, told new price over $9. GBJV NSW Esso/BHP Orica 14 Firm Industrial 11 November 2013, 42 PJ over three years starting 2017. Source: EnergyQuest

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Figure 10 Contract profile major industrials (PJ) Contract profile major industrials (PJ) 50

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Rio Tinto 25 Xstrata Incitec BlueScope 20

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0 201320142015201620172018201920202021202220232024202520262027202820292030 Source: EnergyQuest Figure 11 Major industrial gas demand (PJ) Major industrial gas demand (PJ) 140

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0 2014 2015 2016 2017 2018 2019 2020 Series1 120 120 112 109 94 94 85 Source: EnergyQuest Utility demand AGL and Origin are the two largest utilities, generating electricity and also supplying a wide range of residential, commercial and industrial customers. Origin has substantial upstream gas interests. AGL was planning to develop upstream interests in NSW but has been affected by government restrictions.

Figure 12 AGL gas sources (PJ) AGL gas sources (PJ) 250

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Otway

100 Gloucester Otway Thylacine Moranbah 50 Origin (Fairview) Origin SG QGC options 0 QGC base 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 Otway 17.25 17.25 17.25 17.25 Cooper Gloucester 30 30 30 30 30 30 30 30 30 30 30 30 30 30 30 Gippsland (NSW) Otway Thylacine 30 30 30 30 30 Gippsland (Vic) Moranbah 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 10 Origin (Fairview) 13 13 13 13 13 13 13 13 13 13 Origin SG 10 10 10 10 10 10 10 10 10 10 QGC options 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 QGC base 36 36 36 36 36 36 36 36 36 36 36 36 36 36 36 Cooper 40 40 40 40 Gippsland (NSW) 38 38 38 38 38 Gippsland (Vic) 32 32 32 32 32 Source: EnergyQuest Figure 12 shows AGL’s gas supply profile. AGL appears to be well-supplied in Queensland. It says its Queensland wholesale gas sales will be 57 PJ in 2014, up from 19 PJ in 2013-14, with potential for ~80 PJ in 2015-16 and ~70 PJ the following year. AGL has its Moranbah interest in Queensland up for sale. AGL’s gas sales in NSW, Victoria and South Australia were 142 PJ in 2013-14 (including power generation). The current Cooper Basin contract concludes in 2016 and the Gippsland and Otway Thylacine contracts in 2017. The 30 PJ/a of gas production from Gloucester is uncertain. AGL has said it is negotiating a new 17.3 PJ/a Otway contract for 2018-21 for finalisation in Q2 2015. However, overall, AGL does not have any firm long- term gas contracts in southern markets beyond 2017. In addition to Torrens Island, Arrium and Adelaide Brighton, AGL sold 11 PJ of gas in SA to retail and commercial customers in 2013-14. (In the SA residential market the respective market shares as of December 2912 were: Origin 48%, AGL 30%, EnergyAustralia 14% and Simply Energy (GDF Suez) 7%).

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Figure 13 Origin Energy gas sources (PJ) Origin gas sources (PJ) 250

200

150

Cooper contract

100 Cooper equity Bass Otway Cal Energy

50 Otway Benaris Otway equity Gippsland #2 Gippsland #1 0 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Cooper Beach Cooper contract 25 APLNG Cooper equity 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 13 Bass 20 20 20 20 20 20 20 20 20 20 20 Otway Cal Energy 3.6 3.6 3.6 3.6 3.6 3.6 3.6 3.6 3.6 3.6 Otway Benaris 7.62 7.62 7.62 7.62 7.62 7.62 7.62 7.62 7.62 7.62 Otway equity 17.85 17.85 17.85 17.85 17.85 17.85 17.85 17.85 17.85 17.85 17.85 17.85 Gippsland #2 48 48 48 48 48 48 48 48 48 Gippsland #1 25 25 25 25 25 25 25 25 Cooper Beach 8.5171717171717178.5 APLNG 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50 Source: EnergyQuest Origin Energy is better-placed than AGL (Figure 13). Not only does it have a longer and more certain duration of supply but also a better geographic spread. It is likely that Origin will take market share from AGL in key markets unless AGL secures further gas supply contracts. Table 9 Gas supply contracts, other utilities (PJ)

Field Market Seller Buyer Average Contract Market Likely Comments (Operator) Annual Status Type Expiry Quantity PJ Gippsland Melbourne/ Esso/BHP Energy 70 Firm Retailer 2017 825 PJ from 2004 - JV Sydney Australia 2017 C asino SA/Victoria Santos Energy 35 Firm Retailer 2018 Santos 50%, AWE Australia 25%, Mitsui 25%. 420 PJ over 12 yrs to Energy Australia. Started prdn in 2006 so would be to 2018. Citi 25 Feb-14 2017. GBJV NSW Esso/BHP Lumo 7.3 Firm Retail 2017 14 May 2013. 22 PJ over three years from 2015. Includes an oil linkage. Minerva Adelaide BHPB GDF Suez 27 Firm Power 2015 To 2015. 19.5 PJ use Pelican Station in 2011. Has used up Point PS to 25 PJ. and Retail Source: EnergyQuest Table 9 shows disclosed contracts for Energy Australia, Lumo and GDF Suez. Again a number of contracts expire before the end of the decade.

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Figure 14 shows EnergyQuest’s forecast of utility demand (excluding power generation). We expect slow growth in demand. While the industrial component of utility demand is price sensitive, the commercial and retail component is less sensitive. Figure 14 Utility demand (ex-power generation) (PJ) Utility demand ex‐power generation (PJ) 450

400

350

300

250

200

150

100

50

0 2014 2015 2016 2017 2018 2019 2020 Series1 406 408 410 412 414 416 418 Source: EnergyQuest Recent contracts Table 10 shows east coast gas supply contracts written since October 2010 for both LNG and domestic gas. Apart from the GLNG contracts from APLNG’s Spring Gully and Combabula, the LNG contracts all source gas from the domestic market. Reflecting market tightness, new domestic contracts are being signed at higher prices, some oil-linked, and typically for shorter terms. Industrial companies are also taking greater risks, taking interests in upstream acreage.

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Table 10 East coast gas contracts signed since October 2010 Announced Seller Buyer PJ Commences Term (years) Oil-linked? Estimated Delivery price $/GJ Point or %oil LNG Oct-10 Santos GLNG 750 2014 15 Yes 6% Wallumbilla May-12 Origin GLNG 365 2015 10 Yes Oct-12 Origin SG & GLNG 355 2015 30 Yes Combabula Nov-13 Origin QGC 30 2014 2 Yes Dec-13 Origin GLNG 100-194 2016 5 Yes 7% Mar-14 WestSide GLNG ~300 2015 20 Yes 8.60% Q2 2014 Other GLNG 25 2015 7 Yes Q2 2014 Other GLNG 60 2016 21 months Yes Total 1,985-2,079 Domestic May-11 AGL Xstrata 138 May-13 10.5 No 10 Ballera Dec-12 Origin MMG 22 2013 7 No 9 Ballera Apr-13 Beach Origin 139-173 2014-15 8-10 Yes 7-7.5% Moomba May-13 Esso-BHP Lumo Energy 22 2015 3 Yes 6% Longford Jul-13 Strike Energy Orica 150 20 No 6 Moomba Sep-13 Esso-BHP Origin 432 2014 9 Yes Longford Nov-13 Esso-BHP Orica 42 2017 3 Yes Longford Dec-13 AGL Incitec 21 2015 2 No 10 Ballera Jan-14 Strike Energy Orora 30 2017 10 Fixed 6 Moomba Feb-14 Strike Energy Austral Bricks 12.5 2017 10 Fixed 6 Moomba Mar-14 Strike Energy Orica 100 2020 10 No 6 Moomba Aug-14 Benaris? AGL 69 2018 4 Total 1,177-1,211 Source: EnergyQuest

Demand and supply balance Figure 15 shows the outlook for east coast gas demand to 2020, including the impact of LNG projects. Under this projection east coast domestic demand falls from 720 PJ in 2014 to 623 PJ in 2020. Figure 16 shows the demand curve and the current domestic gas profile. Figure 17 shows our forecast of east coast demand and supply. On the supply side Gippsland is assumed to maintain a steady 260 PJ/a and BassGas to maintain a steady 20 PJ/a. Cooper Basin production is assumed to increase to 120 PJ/a (sufficient for the 750 PJ GLNG contract) and to remain at that level. Surat Bowen production is assumed to increase to almost 1,650 PJ/a, which is the capacity of the upstream gas plants. This is achievable if APLNG and QCLNG each drill a further 300 wells per annum and GLNG drills 150. (This also allows for falling average well productivity.) QCLNG and APLNG are developing sufficient new gas production capacity to supply their LNG plants and domestic contracts. GLNG is also developing new capacity but is also reliant on existing domestic gas fields. It needs 1,350 TJ/d for two trains, 1,250 TJ/d to meet LNG contracts. The Fairview hubs and Roma and other new field being developed only have capacity of 640 TJ/d, a gap of 710 TJ/d (259 PJ/a). Cooper Basin production is assumed to increase by 40 PJ/a and domestic demand is assumed to fall by 97 PJ/a from 2014 to 2020, a total of 137 PJ/a, leaving a gap of 180 PJ in 2020 between total demand and supply.

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Figure 15 East coast gas demand 2014-20 (PJ) East coast gas demand 2014‐2020 (PJ) 2500

2000

1500

LNG Gas‐fired power 1000 Major industrial Utility

500

0 2014 2015 2016 2017 2018 2019 2020 LNG 0 824 1494 1649 1649 1649 1649 Gas‐fired power 194 155 155 119 120 120 120 Major industrial 120 120 112 109 94 94 85 Utility 406 408 410 412 414 416 418 Source: EnergyQuest Figure 16 East coast domestic demand and contracts (PJ) East coast domestic demand and contracts (PJ) 800

700

600

500

400 Surat‐Bowen Bass 300 Otway Gippsland

200 Cooper Domestic demand

100

0 2014 2015 2016 2017 2018 2019 2020 Surat‐Bowen 238 228 226 218 191 191 191 Bass 20 20 20 20 20 13 13 Otway 119 119 94 94 81 52 46 Gippsland 273 269 269 274 182 112 98 Cooper 51 49 57 17 17 17 17 Domestic demand 720 683 677 640 629 631 624

Source: EnergyQuest

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Figure 17 East coast gas demand and supply 2014-2020 (PJ) East coast gas demand and supply (PJ) 2500

2000

1500

1000

500

0 2014 2015 2016 2017 2018 2019 2020 Surat Bowen 267 664 1559 1643 1643 1643 1643 Cooper 80 110 120 120 120 120 120 Bass 20 20 20 20 20 20 20 Otway 105 105 98 93 90 70 51 Gippsland 260 260 260 260 260 260 260 Total demand 720 1507 2170 2289 2278 2280 2273

Gippsland Otway Bass Cooper Surat Bowen Total dema nd

Source: EnergyQuest

Further supply sources We do not expect any material level of NSW production this decade. NSW has 14 Tcf of CSG, largely in permits operated by Santos, AGL and Metgasco. This should be plenty to meet other domestic gas needs. It is also potentially low cost and close to markets. However the NSW Government continues to restrict development. There are other possible supply sources but nothing at an advanced stage of development and generally higher cost and/or greater risk than historic developments:  Senex is testing the Hornet field in Cooper Basin (885 PJ resource, $8.40/GJ estimated break-even cost)  As a result of an acreage swap with QGC, Senex has net 2P gas reserves of 488 PJ in the western Surat Basin. Development assessment is commencing. This is likely to be lesser quality acreage.  Strike is assessing Cooper Basin coals but is believed to be producing large water volumes. Break-even gas price possibly $6.00/GJ. (Prospective resource 4.5 Tcf.)  Arrow is just starting FEED of its reserves (2,810 PJ 2P reserves, $5/GJ estimated break-even cost).  Origin Ironbark 880 PJ pushed back 2018+? (881 PJ 3P reserves, 110 TJ/d, $5/GJ estimated break-even cost)  Other Cooper Basin unconventional: 2020+? (5,000 PJ+ resource, break-even cost $8- 9/GJ)

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 Cooper Energy is looking to develop Basker-Manta-Gummy in Bass Strait. While it also has oil, previous development attempts have failed.

 Santos is considering development of the Sole field in Bass Strait. The field has H2S and requires a high gas price.  Northern Territory: requires major pipeline investment and a 60 PJ market. Not clear where the gas will be sourced from. Transmission costs alone would be at least $3/GJ. These sources are all subject to uncertainty and none are imminent.

Gas prices LNG netbacks and development costs While short-term gas prices are low (especially in Queensland) and the average price under historical contracts is also relatively low, prices under new contracts are two to three times higher, driven by LNG netbacks, development costs and the overall balance between buyers and sellers. Domestic contracts currently being written appear to reflect LNG netbacks. Netbacks estimate the value of gas at each producing location for LNG ex-Gladstone, taking account of transmission costs to Gladstone and processing costs. Once the LNG plants are finished the short-run costs of operating the LNG plant are relevant rather than the long-run costs, which include sunk capital costs. Figure 18 Short-run LNG netbacks Short‐run LNG netbacks 20.00

18.00

16.00

14.00

12.00

10.00

8.00

6.00

4.00

2.00

0.00 60 70 80 90 100 110 120 Export price (USD/MMBtu) 8.70 10.15 11.60 13.05 14.50 15.95 17.40 Gladstone netback (AUD/GJ) 8.31 9.77 11.24 12.70 14.17 15.63 17.10 Wallumbilla netback (AUD/GJ) 8.01 9.47 10.94 12.40 13.87 15.33 16.80 Moomba neback (AUD/GJ) 6.91 8.37 9.84 11.30 12.77 14.23 15.70

Export price (USD/MMBtu) Gladstone netback (AUD/GJ) Wallumbilla netback (A UD/GJ) Moomba neback (A UD/GJ)

Source: EnergyQuest

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If a plant is short of gas the netback estimates the maximum price that the project would pay for domestic gas to produce LNG. If the netback is below domestic prices it would be better to sell the gas domestically. Figure 18 shows short-run LNG netbacks (in A$/GJ) for various east-coast supply points and various oil prices. It assumes an LNG price ex-Gladstone of 14.5% of the oil price and a US$/A$ exchange rate of 0.85. At a US$$80/bbl oil price the export price is US$11.60/MMBtu and the short-run netbacks are A$11.24/GJ at Gladstone, A$10.94/GJ at Wallumbilla and A$9.84/GJ at Moomba. Figure 19 Australia rolling three year finding and development costs, oil and gas, proved and probable ($/GJ)

Source: EnergyQuest Development costs also drive gas prices. Figure 19 shows rolling three year finding and development costs (F&DC) for Australia, expressed as A$/GJ. F&DC are a measure of capital costs and do not include operating costs, taxes, time value of money or a profit margin and break-even prices are generally around 1.8-2.0 times F&DC so the break-even price for a project with a F&DC of $4.00/GJ may be $7.20-$8.00/GJ. Contract gas prices The influence of LNG netbacks, higher costs and market tightness generally implies higher domestic gas prices of the type seen in Table 10. The LNG price assumed in Figure 18 of 14.5% of the oil price is a typical price under long- run contracts. However LNG buyers are, with some success, attempting to get away from oil-linked pricing, preferring Henry Hub. At a HH gas price of US$4.00/MMBtu, LNG could be delivered to Japan from the US Gulf Coast for US$11.00/MMBtu. The Gladstone netback for US$11.00/MMBtu delivered to Japan would be US$10.00/MMBtu and A$8.22/GJ at Moomba.

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Figure 20 Contract gas prices ($/GJ, 2014$) Contract gas prices ($/GJ, 2014$) 14.00

12.00

10.00

8.00

6.00

4.00

2.00

0.00 2014201520162017201820192020 Wallumbilla OL 12.40 11.82 12.24 12.40 10.77 9.06 9.08 Moomba OL 10.70 10.12 10.54 10.70 9.92 9.06 9.08 Wallumbilla HH 9.45 9.18 9.22 9.32 8.48 7.56 7.63 Moomba HH 8.65 8.38 8.42 8.52 8.30 8.01 8.08 Source: EnergyQuest Figure 20 shows estimates of future gas prices at Wallumbilla and Moomba based on oil- linked and Henry Hub-linked netbacks, based on the Brent forward curve in the case of oil and on the Henry Hub forward curve.

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Appendix: Power station maps

Figure 21 Queensland power stations

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Figure 22 NSW power stations

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Figure 23 Victorian and Tasmanian power stations

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Figure 24 South Australian power stations

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Abbreviations 1P proved reserves 2P proved and probable reserves 3P proved, probable and possible reserves 2C best estimate contingent resources 3C high estimate contingent resources

ACCC Australian Competition and Consumer Commission AEMO Australian Energy Market Operator APLNG Australia Pacific LNG APPEA Australian Petroleum Production and Exploration Association bbl barrel (159 litres or 35 imperial gallons) bbl/d barrels per day Bcf billion cubic feet (109 or a thousand million) Bcf/d billion cubic feet per day Bcm billion cubic metres boe barrels of oil-equivalent bopd barrels of oil per day BREE Bureau of Resources and Energy Economics Btu British thermal unit (1.055 kilojoules) CCGT combined cycle gas turbine cf/d cubic feet per day CIF cost, insurance and freight CNOOC China National Offshore Oil Corporation

CO2 carbon dioxide CSG coal seam gas DES delivered ex-ship DNRM Queensland Department of Natural Resources and Mines DRET Department of Resources, Energy and Tourism DST drill stem test EIA Energy Information Administration EIS environmental impact statement EPC engineering, procurement and construction FEED front-end engineering and design FID final investment decision FLLNG Fisherman’s Landing LNG FLNG floating liquefied natural gas FOB free on board FPSO floating production storage and offtake GJ gigajoule (1 billion joules or 109) GL gigalitre (1 billion litres or 109) GLNG Gladstone LNG GSA Gas sales agreement GW gigawatt GWh gigawatt hour Ha hectare Level 30 91 King William St Adelaide SA 5000 Telephone (08) 8431 7903 Mobile 0419 828 617 Email [email protected] ABN 18 503 484 404 ACN 139 665 295 www.energyquest.com.au 35

HOA heads of agreement Hp horsepower IEA International Energy Agency IMOWA Independent Market Operator of Western Australia JCC Japanese crude cocktail JPDA Joint Petroleum Development Area (Timor Sea) JV joint venture Kboe thousand barrels of oil-equivalent KJ kilojoule (one thousand joules) km kilometre kt thousand tonnes KTA key terms agreement LNG liquefied natural gas LPG liquefied petroleum gas (propane and butane) kbbl thousand barrels kbbl/d thousand barrels per day Mcf thousand cubic feet Mcf/d thousand cubic feet per day Md millidarcy MJ million (106) joules ML million litres (6290 barrels or 796 tonnes) mm millimetre MMbbl million barrels MMbbl/d million barrels per day MMboe million barrels of oil-equivalent MMboe/d million barrels of oil-equivalent per day MMBtu million British thermal units MMBtu/d million British thermal units per day MMcf million cubic feet MMcf/d million cubic feet per day MMcm million cubic metres (35.31 million cubic feet) MMscf/d million standard cubic feet per day MOU memorandum of understanding MPa megapascal Mt million tonnes Mtpa million tonnes a year MW megawatt MWh megawatt hour NEM National Electricity Market NGL natural gas liquids (condensate and LPG) NWS North West Shelf OCGT open cycle gas turbine OGIP Original gas in-place OIES Oxford Institute of Energy Studies OPEC Organization of the Petroleum Exporting Countries OSMR optimised single mixed refrigerant Pa pascal Level 30 91 King William St Adelaide SA 5000 Telephone (08) 8431 7903 Mobile 0419 828 617 Email [email protected] ABN 18 503 484 404 ACN 139 665 295 www.energyquest.com.au 36

PJ petajoule (one thousand terajoules) PJ/a petajoules a year Psi per square inch QCLNG Queensland Curtis LNG QGC Subsidiary of BG Group qoq quarter on quarter SAP system average price SWQP South West Queensland Pipeline T metric tonne Tcf trillion cubic feet (1012 or one thousand billion) therm 100,000 Btu TJ terajoule (one thousand gigajoules) TJ/d terajoules per day WHP well head pressure WTI West Texas Intermediate yoy year on year

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Conversion factors EnergyQuest converts the measures used by different companies to a consistent basis. In line with Australian industry conventions, we use joules for domestic gas, barrels for oil and condensate and tonnes for LPG and LNG. Where available we use individual company conversion ratios. Otherwise we use: crude oil 1 barrel (bbl) = 1 barrel oil-equivalent (boe) sales gas 1 petajoule (PJ) = 171,937 boe sales gas 1 billion cubic feet (Bcf) = 1.06 PJ LPG 1 tonne (t) = 8.458 boe LNG 1 million tonnes (Mt) = 55.43 PJ LNG 1 million tonnes (Mt) = 9531 Kboe condensate 1 barrel = 0.935 boe ethane 1000 tonnes = 0.05181 PJ ethane 1 PJ = 15.1 MMcm oil/condensate 1000 barrels = 158.97 kilolitres LPG 1000 tonnes = 1.88 ML sales gas 1 petajoule (PJ) = 26.71 MMcm British thermal units 1 million (MMBtu) = 1.055 GJ = 1Mcf = 10 therms British thermal units 1 billion Btu = 1.055 TJ = 1 MMcf British thermal units 1 trillion Btu = 1.055 PJ = 1 Bcf

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