2C4AC4BA-ABBB-4DC0-9723-062CCA781391

South East Asia - IndonesiaDecember 2011

West Madura PSC/Poleng TAC

Key Facts

Onstream OffshoreLocation Timetable Java, East Java Basin Discovery Date: Poleng Dec-72Block: Poleng TAC, Area: 41 km2 Issue Date: West Madura May-81Block: West Madura, Area: 1,615 km2 Discovery Date: West Madura PSC Oct-82Water Depth: 15 - 60m Devt Consent: West Madura PSC Jan-84Producing Horizon(s): Production Started: West Madura PSC Sep-85Neogene, Miocene, Kujung Issue Date: Poleng TAC Dec-93 Production Started: Poleng May-98 Peak Oil Production (7,600 b/d): Poleng 2008 Peak Gas Production (72 mmcfd): Poleng 2004 Peak Oil Production (20,300 b/d): West Madura PSC 2010 Peak Gas Production (158 mmcfd): West Madura

PSC 2010

Final Expiry: Poleng TAC Dec-13 Final Expiry: West Madura May-31Operator Participants %Pertamina See Participation Section Recoverable Reserves (p+p) Hydrocarbon Quality 87 mmbbl Oil Gravity (°API) - West Madura PSC 473 mmbbl Cond Gravity (°API) - Poleng 43.5768 bcf Sales Gas Calorific Value (btu/scf) - West Madura PSC 1200Remaining Reserves at 01/01/2012 Calorific Value (btu/scf) - Poleng 120022 mmbbl Oil 1 mmbbl Cond 263 bcf Sales Gas Contract Financial Summary Production Sharing Contract Technical Assistance Contract Poleng Capital costs (2012 terms) US$529M Capital costs per boe (2012 terms) US$8.84/boe Operating costs (2012 terms) US$529M Operating costs per boe (2012 terms) US$8.84/boe Remaining PV (10.0% nominal) US$37M Remaining PV per boe (10.0% nominal) US$8.48/boe Rate of return 2.1% West Madura PSC Capital costs (2012 terms) US$1,318M Capital costs per boe (2012 terms) US$7.98/boe Operating costs (2012 terms) US$1,499M Operating costs per boe (2012 terms) US$9.08/boe Remaining PV (10.0% nominal) US$272M Remaining PV per boe (10.0% nominal) US$4.21/boe Rate of return 14.8%Source: Wood Mackenzie

West Madura PSC/Poleng TAC Indonesia

South East Asia Upstream Service - December 2011 Page 2 of 23

Summary and Key Issues

Summary

The West Madura PSC comprises a group of small field developments offshore Java, while the Poleng TAC is a single oil and gas accumulation. Pertamina is the operator of the West Madura PSC and Kodeco operates the adjoining Poleng TAC. Both field developments share production facilities and are supported by an onshore base and gas receiving facilities located in Gresik, East Java.

The West Madura PSC first began production in 1985, followed by Poleng in 1998. Gas from both fields is sold jointly into the East Java market, while crude is shipped to the Balikpapan refinery. Oil and gas output from West Madura increased in 2011 as a result of an ongoing drilling programme while production from Poleng TAC has declined.

Key Issues

In May 2011, BPMIGAS announced the extension of the West Madura Offshore PSC by 20 years, with operator Pertamina increasing its interest to 80%. Kodeco continues to hold its 20% stake in the PSC.

Pertamina plans to increase oil and gas production from the block through infill drilling and EOR techniques. In the absence of any concrete Plan of Development (PoD), we have not modelled an increase in the oil production from the block.



Location Maps

Index Map

Java

Kalimantan

Java Sea

Belitung

Bangka

Sumatra

Bali

Lombok

Indian Ocean

Christmas Island(Australia)

South East Sumatra

North West Java

PAGERUNGAN

Madura

Sunda

Strait

INDONESIAAUSTRALIA

116°E

116°E

114°E

114°E

112°E

112°E

110°E

110°E

108°E

108°E

106°E

106°E

2°S

2°S

4°S

4°S

6°S

6°S

8°S

8°S

10°S

10°S

12°S

12°S

0 100 200km

TERANG

Source: Wood Mackenzie



West Madura/Poleng TAC Map

Surabaya

Tuban

ery

PangkahProcessing

Petrokimia Gresik

Gresik

14" West Madura-Gresik gas pipeline

8" o

il

10" o

il

18"

16" planned gas

16"

oil

Pertamina EP

AWE

AWE

arigali

Offer

E M bil

Kodeco

Medco Energi

H

Mubadala Development Co

Pertamina

BM

Hess

Hess

AWE

Mubadala

AWE

CNP

Medco Energi

CNPC

AWE

Hess Pertamina

Mubadala

AWE

AED Oil

Bawean

Suci

North Madura

Pangkah

North Madura

Poleng TAC

Pertamina - Java

Terumbu

Terumbu

South Madura

Terumbu

East Muriah

West Madura

Pangkah

West Madura

Madu

M

Cepu

P

lu Rembang

West Tuban

Terumbu

Bulu

Bulu

Bawean

Pangkah

Bodjonegoro-1

3

Kembang Baru-1,2East Mudi-1

Liyun-1

3

2

KE 6-4-1

2

KE-17

Pakaan-1

1

Arosbaya-1

Elang-1

JJatirogo-1

Keladi-1

Dermawu-1

1, 2, 3 & 4

JS28-1

JS13A-1

2

2

1

Kroeka-1 8

1

2

1

1/ST1/ST2

1

2

2/4

1

2,4,5

Pegat-2

Grigis-1

Ujung Pangkah West/ST1

Resik-1

Bogomiring-4

1

KE-6

KE-12 6

1

KE-5-3

C

A1

3

JS-4-1

KE 21-1ST1/ST2

Blimbing-1

Kutilang-1

SW Kepodang

Tapen-1

1

1

1

Tuban-1

Jenu-1

Kemangi-1

BP-1

1

KE-9

1

1

1A13ST

2

JS

1

S15-1

1 11

KE-4

Grigis Barat-1

C1

Sekar Korong-3

3

KE-5

4

2

JS-20-1

Karasan-1rajong-1

1,3,A1-A5

North Kepodang

Ujung Pangkah North

1

2

JS-31A-1

JS-6A-1

B

1

1

KE-19-1

1

Konan

Central Kepodang-1

East Lengo-1

Kujung-1

JS13-1

2

Tambak Boyo-1

Hayam Wuruk-1

21

JS 10-1

Ngasin-1

KE-8

KE-5-6

2A/ST

1

JS-19W-1

Gigir-1

JS1-1

Gigir East-

Tawun-1 Gegoenung-1

Metatoe-4

1

1

2 1

Lisah-1

2

KE-22-1

Bunku-1A

Dolan

Kedung Keris

Lengo

KE-7

Kepodang

Calypso

KE-12

Lerpak

i

Suci

KE-7-3

KE-13

Karang Anyar

KE-1

Bogomiring Baru

Sidayu

Gondang

Bungku

UJUNGPANGKAH

KE-38 KE-54

KE-5

K

ANGILO

BANYU URIP

KE-40

KE-32

KE-6POLENG

KE-3

NORCAM

WONOCOLO

SOUTH CAMAR

-TOBOMUDI LENGOWANGI SOUTH BUNGOH

KE-24

KE-39

KAWENGANWONOSARI

KE-23

SUKOWATI

KE-2

113°E

113°E

112°45'E

112°45'E

111°45'E

111°45'E

112°30'E

112°30'E

112°15'E

112°15'E

112°E

112°E

6°S

6°S

6°15

'S

6°15

'S

6°30

'S

6°30

'S

6°45

'S

6°45

'S

7°S

7°S

0 20 40km Source: Wood Mackenzie



Participation

The West Madura PSC was signed on 7 May 1981 between Pertamina and Kodeco. In November 1986, Pedco (the Korean state oil company, now called Korean National Oil Company or KNOC) bought 12.5% of Kodeco's interest, and provided managerial and financial support to Kodeco which retained operatorship. The original West Madura PSC contract area excluded the Poleng field (which was retained by Pertamina) and covered 6,460 km2. Successive relinquishments were made in May 1983, May 1985, and December 1991 leaving the current area at 1,615 km2.

In January 1992, Pedco withdrew from the PSC, and Kodeco assumed its share. Subsequently, in December 1993, the neighbouring Poleng TAC was awarded to Kodeco. In April 1999, YPF acquired a 25% stake in the West Madura PSC and a 50% interest in the Poleng TAC from Kodeco. Kodeco retained operatorship of both contracts. The deal was effective from 1 January 1998. Subsequently, in June 1999, Repsol and YPF merged to form Repsol YPF.

On 18 January 2002, China's CNOOC Ltd acquired Repsol YPF's stake in the West Madura PSC and Poleng TAC. The consideration paid was US$585 million and also included Repsol YPF's interests in its other Indonesian assets, namely the Southeast Sumatra, Blora and North West Java Sea PSCs.

In May 2011, the West Madura offshore PSC was extended by 20 years and Pertamina appointed as the operator with a 80% interest. Kodeco energy holds the remaining 20%. The Poleng TAC is due to expire in 2013.

West Madura PSC and Poleng TAC Participants

Company West Madura PSC Poleng TAC % %Pertamina* 80 0Kodeco 20 50CNOOC 0 50Total 100.00 100.00Source: Wood Mackenzie * Operator

Unitisation

The KE-3 field (previously known as JS-1) is located on the northern boundary of the West Madura permit and was discovered by Cities Service in 1972. Subsequent exploration activity on the adjacent Bawean Block identified KE-3 to be the southern lobe of the South Camar field. A unitisation agreement covering KE-3 (South Camar) was signed with Texas Eastern in April 1988. Under the terms of the unitisation agreement, the West Madura Block participants were carried (100%) through the Camar development. When the Bawean participants have recovered development costs, profits will be split 80:20 in favour of the Bawean Block partners (see Bawean analysis for details of the South Camar development).



Well Data Well Name Operator Spudded TMD(m) Result Discovery Field Comment Type Completed WD(m) JS-20-1 24-Sep-72 3782 +Exploration

Cities Service 23-Dec-72 53

Oil & Gas Poleng

JS-19W-1 27-May-78 2438 Exploration

Cities Service 27-Jul-78 17

Oil DST 1 from 1,616-1,620 and 1,629-1,633 flowed 9.35 mmcfd of gas and 81 b/d of condensate from a 64/64-inch choke.

KE-1 30-Jul-82 2588 *Exploration

Kodeco Energy 22-Oct-82 55

Oil KE-1

KE-2A/ST 16-Nov-82 1602 +Exploration

Kodeco Energy 16-Dec-82 15

Oil KE-2

KE-5 17-Dec-82 +Exploration

Kodeco Energy 28-Jan-83 54

Gas/Condensate KE-5

KE-5-6 10-May-83 Appraisal

Kodeco Energy 21-Jun-83 49

Gas

KE-6 01-Sep-84 2496 +Exploration


Gas/Condensate KE-6

KE-12 23-Sep-84 1615 *Exploration


Gas KE-12

KE-6-6 13-Feb-86 Appraisal

Kodeco Energy 27-Mar-86 45

Oil

KE-23-1 01-Mar-87 3399 +Exploration

Kodeco Energy 23-Apr-87 55

Gas/Condensate KE-23

KE-23 B 24-Nov-00 2359 Appraisal


Oil & Gas The well was not production tested.

KE 13-1 19-Dec-00 2287 *Exploration


Gas/Condensate KE-13 The well flowed 9.35 mmcfd of gas and 81.3 b/d.

KE 24-1/ST1/ST2 30-Jan-01 2627 +Exploration


Gas/Condensate KE-24 The well was understood to have flowed 20.75 mmcfd of gas plus condensate. Sidetracked to test the commerciality of the discovery.

KE-30-1 17-Aug-01 2649 +Exploration

Kodeco Energy 13-Sep-01 43

Oil & Gas KE-30 The well flowed 2,268 b/d of oil, 2,722 b/d of water and 0.7 mmcfd of gas in testing. Second DST flowed 563 b/d of oil and 3,194 b/d of water.

KE-40-1 06-Jan-02 2402 +Exploration

Kodeco Energy 01-Jul-02 55

Oil & Gas KE-40 Pay zone in Kujung III flowed 2,400 b/d of oil and 1.7 mmcfd of gas on a one-inch choke.

KE-30-2 02-Feb-02 1369 Appraisal

Kodeco Energy 24-Feb-02 23

Oil & Gas DST one flowed 1-9.6 mmcfd and 6-81 b/d. DST two flowed 1,467-1,789 b/d (43-45° API).

KE-39-1 27-Feb-02 2352 +Exploration


Oil & Gas KE-39 DST1 flowed 300-557 b/d of oil and 0.1 mmcfd of gas from a measured depth interval between 1,252 m and 1,261 m. DST2 flowed 11 mmcfd of gas and 96-120 b/d of condensate from two measured depth intervals between 1,204 and 1,220 m.

KE-40-2 03-Nov-02 2202 Appraisal

Kodeco Energy 30-Nov-02 55

Oil & Gas Pay zones in Kujung III flowed 1,430 bbl of oil and 6.86 mmcfd of gas on a 64/64-inch choke. Encountered 53 metres of gas pay in Kujung I and 8.5 metres of oil pay in the Kujung III.

KE-39-2 02-Dec-02 2010 Appraisal


Oil & Gas

KE-38-1 24-Dec-02 2118 +Exploration


Oil & Gas KE-38 KE-38-1 was plugged and abandoned having discovered oil and gas. On test it flowed oil at 935 b/d and gas at 0.34 mmcfd on a 56/64-inch choke.

KE-54-1 18-Jan-03 1987 +Exploration

Kodeco Energy 07-Feb-03 60

Oil & Gas KE-54



KE-5-3 28-Mar-03 Appraisal

Kodeco Energy 09-May-03 56

Gas

KE-32-1 21-Oct-03 2217 +Exploration


Oil & Gas KE-32

KE-7-3 06-Nov-04 2254 *Exploration


Oil, Gas, Cond KE-7-3 The well tested 1,000 b/d of oil and condensate and 10.5 mmcfd of gas through a 48/64-inch choke.

KE 6-4-1 28-Nov-07 3128 Exploration


Tight Hole

Source: Wood Mackenzie * Technical Discovery + Commercial Discovery

Exploration

The area's hydrocarbon potential became apparent in the early 1970s when Cities Services discovered the Poleng oil and gas field and the Camar (JS1-1) oil field. Cities also drilled 16 dry holes prior to relinquishing its acreage.

West Madura

After being awarded the West Madura PSC in 1981, Kodeco embarked upon a heavy exploration programme. By the end of 1996, the joint venture had drilled 10 exploration and 16 appraisal wells on the PSC, resulting in the KE-2, KE-5, KE-6 and KE-23 discoveries. In 1999, Kodeco shot 3D seismic over 1,100 km2 to evaluate the northern part of the West Madura block and a further 100 km2 of 3D seismic to evaluate acreage around the KE-2 field in the southern part of the block.

The results of the 1999 seismic survey led to one exploration and two appraisal wells being drilled in 2000. In May 2000, Kodeco spudded the KE-11H well on the southern part of the block, but the well was plugged and abandoned having only encountered oil and gas shows. The KE-23 B well, drilled in November 2000, successfully appraised the oil reserves in the KE-23 field. This well was followed by the discovery of the KE-13 gas field.

On the back of the successful drilling campaign in 2000, Kodeco returned to the area in 2001 and drilled three exploration wells and made two further discoveries. The KE-24-1 well is understood to have flowed gas, while the KE-30-1 well hit oil and gas, albeit with a very high water cut.

During 2002/2003, Kodeco completed 10 further exploration and appraisal wells on the block, making five further discoveries. The first well, KE-40-1, encountered oil shows in the Kujung formation, Units II and III, and was subsequently plugged and abandoned as an oil and gas discovery. In February 2002, Kodeco spudded the KE-39-1 exploration well which discovered gas and oil. Two intervals were tested and the field is understood to be small, although the KE-39-2 appraisal well, drilled later in 2002, also encountered oil and gas. In December 2002, KE-40-2 successfully encountered 53 metres of gas pay in the Kujung I formation, and 8.5 metres of oil pay in the Kujung III formation. Three more discoveries were made in 2003, namely KE-38-1, KE-54-1 and KE-32-1.

The KE-7-3 exploration well on the West Madura PSC was completed in December 2004. The well, drilled to a depth of 2,250 metres, was completed as an oil, gas and condensate discovery.

After a lull in recorded exploration drilling, the KE 6-4-1 well was completed in January 2008. The results of the well have not been released. Pertamina plans to conduct an exploration campaign to test prospects within the block in an effort to boost proven reserves.

Poleng

The Poleng field was discovered by Pertamina, prior to the award of the contract. An extensive 3D seismic campaign in 1999 identified a barrier reef complex to the south of the existing Poleng field. This was drilled in 2004 and approximately doubled the size of the combined Poleng accumulation. The discovery is noteworthy in that exploration drilling is unusual on acreage licensed under a TAC, and that it was made over 30 years after the initial discovery of the Poleng field.

Reserves

Reserves for individual fields within the West Madura PSC range from 4 to 21 million barrels of oil and 5 to 90 bcf of gas. Total oil in place on the KE-2 field was originally estimated at about 100 million barrels. However, the geological complexity of the carbonate reservoir has meant that only a small fraction of the crude is recoverable.



Through the acquisition and reprocessing of 3D seismic and successful exploration of the southern extension of the Poleng field, reserve estimates for the TAC were upgraded. This has been aided by the application of horizontal drilling techniques and reservoir simulation.

Gas from the West Madura Offshore and Poleng TAC fields has a calorific value of 1,200 btu/scf.

Estimated reserves for the West Madura PSC and Poleng TAC are detailed in the following table.

Commercial Recoverable Reserves (p+p) (Remaining Reserves at 01/01/2012)

Init Init Init Rem Rem Rem Oil Cond. Gas Oil Cond. Gas (mmbbl) (mmbbl) (bcf) (mmbbl) (mmbbl) (bcf)West Madura PSC 64 3 559 20 1 248Poleng 23 - 208 2 - 15Total 87 3 767 22 1 263Source: Wood Mackenzie

There are several other discoveries located on the West Madura PSC which, at this time, are not considered to be commercial and have been classified as technical reserves.

Technical Recoverable Reserves (Remaining Reserves at 01/01/2012)

Init Init Init Oil Cond. Gas (mmbbl) (mmbbl) (bcf)West Madura PSC 3.9 1.0 296.0Total 3.9 1.0 296.0Source: Wood Mackenzie

Production

West Madura

Overall production from the West Madura PSC has increased through the development of satellite fields and infill drilling.

KE-2 and KE-30 Production from KE-2 began in September 1985, although 0.42 million barrels were produced from the reservoir under an extended production test in May/June 1984. Initially, the field produced oil from six wells fitted with submersible pumps. Production rose very quickly to around 11,000 b/d by October 1985, but fell below 3,000 b/d due to a higher than expected water cut. KE-2 gas reserves were developed and brought onstream in 2002. The field ceased production in 2005.

The adjacent KE-30 oil field was brought onstream in 2007.

KE-5 and KE-6 The KE-5 field started producing in January 1993, through four production at a rate of 35 mmcfd. Production was expected to climb rapidly to a plateau of 40 mmcfd, as per the gas sales agreement with PLN. However, due to technical problems, gas production fell to 25 mmcfd in 1997. In order to improve gas supplies to PLN, the PSC partners brought an additional satellite well, KE-5-6, onstream in 2000. Gas supplies were boosted further when a satellite field, KE-6, located five kilometres north of the main KE-5 platform, was also brought onstream in 2000.

Both fields are believed to have ceased production.

KE-40 First production from the KE-40 oil and gas field was achieved in mid-2006. Production peaked at 2,900 b/d of oil and 15 mmcfd of gas in 2009. However, output was halted in August 2010, after a ship collided with the KE-40 platform. Repair works started in October and production resumed in Q2 2011.

Other Fields Wood Mackenzie understands that KE-23 liquids production started in Q1 2002, followed by gas in 2004. PoDs for the KE-32, KE-39 and KE-54 fields were approved in July 2007. These fields along with KE-38 are being developed



incrementally via monopod platforms. We have assumed that KE-32 and KE-38 were brought onstream during 2008 followed by KE-39 and KE-54 in early-2010 and KE-24 in 2011.

Poleng TAC

The Poleng TAC was brought onstream in May 1998 to contribute to the contracted sales gas volumes. Extensive development of the southern extension of the field from the Poleng-C and D platforms during 2007 and 2008 helped boost production. Production from the Poleng field declined in 2010 and 2011 due to natural decline. We expect Kodeco to drill development wells in the Poleng field in 2012 to boost production.

Production (2001-2010)

2001 2002 2003 2004 2005 2006 2007 2008 2009 2010Oil ('000 b/d) West Madura Offshore 0.3 7.7 9.0 10.2 10.2 10.3 8.8 6.9 8.6 20.3Poleng TAC 6.0 5.7 5.3 4.0 2.4 1.4 6.0 7.6 6.3 5.0Condensate ('000 b/d) West Madura Offshore 0.2 0.1 0.2 0.1 0.2 0.0 0.0 0.2 0.5 0.7Total Liquid ('000 b/d) 6.5 13.5 14.5 14.3 12.8 11.7 14.8 14.7 15.4 26.0 Sales Gas (mmcfd) Poleng TAC 26.0 36.0 68.9 72.5 51.6 49.0 45.3 45.0 43.1 29.3West Madura Offshore 11.0 24.0 20.0 22.5 42.5 39.0 45.0 41.0 101.0 158.0Total Sales Gas (mmcfd) 37.0 60.0 88.9 95.0 94.1 88.0 90.3 86.0 144.1 187.3Source: Wood Mackenzie Production (2011-2020)

2011 2012 2013 2014 2015 2016 2017 2018 2019 2020Oil ('000 b/d) West Madura Offshore 13.5 13.0 11.3 9.3 8.0 5.7 4.5 3.3 - -Poleng TAC 3.6 2.9 1.8 - - - - - - -Condensate ('000 b/d) West Madura Offshore 0.5 0.5 0.4 0.4 0.3 0.1 0.1 0.1 0.1 0.1Total Liquid ('000 b/d) 17.6 16.3 13.5 9.7 8.2 5.8 4.6 3.4 0.1 0.1 Sales Gas (mmcfd) Poleng TAC 28.5 22.8 18.2 - - - - - - -West Madura Offshore 152.0 150.0 121.0 96.0 77.0 61.0 50.0 39.0 31.0 23.0Total Sales Gas (mmcfd) 180.5 172.8 139.2 96.0 77.0 61.0 50.0 39.0 31.0 23.0Source: Wood Mackenzie



West Madura PSC Production Profile

Poleng TAC Production Profile

Development

West Madura

KE-2 and KE-30 The decision to proceed with a full-scale development of the KE-2 oil field was taken in 1984 and the field was deemed commercial in July that year. The development involved a three-leg jack-up converted for use as a production facility. The field was developed via three satellites and a junction platform feeding central production and processing facilities on the jack-up. A 10-well development drilling programme began in 2005. The third well (KE-2-B3) blew out but was quickly brought under control.

Each satellite platform services one well. Production from the satellites is piped via 16-inch and 8-inch subsea pipelines to the jack-up for processing. It is understood that two development wells were drilled on KE-2 in 1999, including one sidetrack and one horizontal well.

The plan of development for the KE-30 oil field was approved in 2004. Development facilities include one wellhead platform (WHP), as well as a 25 kilometre, 12-inch pipeline which enables the gas field to be tied back to the Poleng and KE-5 facilities. The KE-30 platform is larger than the standard monopod platforms which have been utilised on other



marginal developments in the area. Oil production from the KE-30 field utilises storage facilities available at the KE-2 field. COOEC installed the platform in H2 2006 and production began in early-2007.

Six development wells were drilled on KE-30 during 2007.

KE-5 and KE-6 Development drilling on the KE-5 gas field began in October 1989. The development involved the construction and installation of a WHP, an accommodation platform and an onshore processing facility. A total of six gas producers were completed including KE-5-6 which was brought onstream in 2000. KE-5-6 is a satellite well to the main KE-5 field and production was tied back to the KE-5 infrastructure. In anticipation of an increase in production rates, upgrading works to KE-5 facilities were completed in 2004 to enable the field to act as the hub for satellite field developments in the area. The field was shut in and the wells were converted to injectors for gas storage to accommodate surplus gas from the Poleng and KE-23 fields.

In 2000, the KE-6 field was developed as a subsea tie-back to the main KE-5 field to augment existing gas supplies from the PSC.

KE-40 Development of the KE-40 field, located 15 kilometres northeast of the KE-5 field, was completed in March 2006. One minimal facility monopod WHP was installed at the field, linked by a 10-inch, 15 kilometre pipeline to facilities at KE-5, with facilities for seven development wells. An EPC contract was awarded to PT Adiguna in January 2004, for the construction of the platform. A separate award for installation of the platform and associated pipelines was awarded to Clough Offshore in July 2004. Installation of the facilities was completed in early 2006.

In August 2010, the KE-40 platform was struck by a passing ship, damaging the facilities and causing production to be shut-in. Repair work started in October and production resumed in Q2 2011.

KE-23 A single monopod WHP with seven slots was installed on the KE-23 field in November 2001, followed by four development wells. Production is tied back via the Poleng A platform, four kilometres to the southwest of the KE-23 field.

KE-32 and KE-38 The KE-32 and KE-38 fields are being developed as satellite discoveries to the main hub on the KE-5 field. In both cases, a monopod WHP has been used for development of the fields. The contracts for construction of the KE-38 and KE-32 WHPs were awarded to PT Adiguna and Pal respectively. Pal subcontracted the detailed engineering work to Biru. In May 2007, Swiber Engineering was contracted for the installation of the platforms and pipelines by the end of 2007.

Two development wells on KE-32 and eight wells on KE-38 were drilled in 2008. We have assumed that a further six wells were drilled on KE-38 in 2009 and one on KE-32. Three wells were drilled on the KE-38 field in 2011 and we expect three more will be drilled on the field in 2012.

Other Fields The operator received approval for the Plan of Development (PoD) for KE-39 and KE-54 in April 2007. It is assumed that these fields were developed in 2010 and include a total of 11 development wells. KE-24 is believed to be a larger field and we have assumed that it was developed in 2011 through a single WHP, tied back to KE-5.

Poleng TAC

Poleng is tied in to the KE-5 central processing platform. The field was reactivated in October 1997 with the objective of offloading oil offshore via a floating production system. The reactivation project included platform modifications, installation of pipelines, FPSO and related facilities. In 1999, Zee Engineering consultants carried out extensive redesign and modifications to the central processing, AW and BW platforms, including process/pipeline studies and cost evaluation, and facilities extensions. In the same year, two horizontal development wells were drilled. In 2000, the TAC partners conducted a significant drilling campaign on Poleng. The programme culminated in the drilling of several development wells including sidetracks and horizontal wells from both the AW and BW platforms. In June 2001, a contract was awarded to Global Industries to further upgrade the production facilities for Poleng AW and BW after which, three more development wells were drilled. Two additional wells were drilled in 2002, Poleng BW-7 and BW-8, both encountering oil and gas.

Following the reprocessing of 3D seismic during 2003/2004, and the subsequent identification of reserve upside, the partners issued a tender in 2005 for the development of the southern extension of the field via the Poleng C and D



phases of development. Sempec Indonesia was awarded the contract for construction of a central processing platform. Facilities on the six-leg, 3,000 tonne platform include a vapour recovery compressor, oil and gas process separators, a crude oil pump transfer system and a power generation system. In H2 2006, COOEC undertook the installation of the two WHPs - CW and DW - tied back to the new CPP.

In March 2006, Kodeco contracted Diamond Offshore's Ocean Sovereign jack-up rig for an 18 month, 30 well campaign, which commenced in September 2006. During 2007 and 2008 the rig drilled around 15 development wells on Poleng C and D, as well as workovers, wildcats and development wells in the West Madura PSC. Further wells were drilled on Poleng C in 2009.

In September 2006, Sempec sub-contracted ABB to provide integrated electrical and control buildings with electrical, automation and safety systems, monitoring and controls for the processing platform. With the completion of the electrical installation for the CPP it is has been assumed that full installation of the phase C and D platforms was completed during 2007. During 2007 Wood Mackenzie also understands a new gas compressor was installed on the AW platform to improve production rates.

Following the agreement of additional gas sales, a new 80 mmcfd pipeline from Poleng, via KE-5, to Gresik was built in 2008 to accommodate higher gas volumes. This also involved the upgrade of existing onshore facilities. The location of this new pipeline is near the Tanjung Perak port's Buoy 8 and has hampered export and import activity. To prevent ships from hitting the pipeline, construction of a new pipeline began in October 2010.

Transportation

Crude production from KE-2 is stored at the field on a barge, prior to loading onto shuttle tankers via an SBM system. The crude is subsequently shipped to the Balikpapan refinery. Production from the KE-30 field began using these facilities in 2007.

Gas from KE-6 and KE-40 is tied into KE-5. Wet gas from KE-5 is then piped via a 65 kilometre pipeline to the Gresik power station in Java. The 14-inch diameter pipeline had a nominal capacity of 50 mmcfd, but with the addition of a looping pipeline in 2002, capacity increased to 90 mmcfd. Condensate is removed at Gresik. The PSC partners are understood to have also increased capacity of the onshore facilities from 70 to 90 mmcfd.

Following the agreement of additional gas sales, Wood Mackenzie understands a new 80 mmcfd pipeline from Poleng, via KE-5, to Gresik was built in 2008. This also involved the upgrade of existing onshore facilities. The location of this new pipeline is near the Tanjung Perak port's Buoy 8 and has hampered export and import activity. To prevent ships from hitting the pipeline it is currently being relocated, with the new pipeline being buried a few metres under the seabed, at 19 metres below sea level rather than the current 12 metres.

Gas from the Poleng field is piped 12 kilometres to KE-5, and Poleng liquids are stored on an FSO before export by shuttle tankers to the Balikpapan refinery. In 2000, the Madura Ayu Floating Storage and Offloading (FSO) vessel began a five-year contract on the Poleng field. The FSO had a capacity of around 200,000 barrels. In January 2003, the larger Madura Jaya FSO replaced the Madura Ayu. The vessel has a storage capacity of 630,000 barrels. The contract for the Madura Jaya was extended in April 2005 until May 2010. We expect the contract will be extended under short-term option contracts.

Production from the KE-23 and KE-30 fields is tied back to the Poleng AW platform, and utilises the existing Poleng export routes.

Production from KE-32 and KE-38 is tied back to the KE-5 field. KE-24, KE-39 and KE-54 will also utilise the KE-5 facilities.



Pipeline Summary

Pipeline Type From To Length Diameter Capacity (km) (inches) ('000 b/d,mmcfd)KE-23 to Poleng Oil KE-23 Poleng 4 10Poleng to KE-5 Gas Poleng KE-5 12 8 30West Madura to Gresik Gas KE-5 Gresik 65 14 90West Madura to Gresik II Gas KE-5 Gresik 65 80KE-6 to KE-5 Gas KE-6 KE-5 7KE-24 to KE-5 Gas KE-24 KE-5 12KE-30 to KE-2 Oil KE-30 KE-2 10 12KE-30 to Poleng Gas KE-30 Poleng 25 12KE-32 to KE-5 Gas KE-32 KE-5 10 16KE-38 to KE-5 Gas KE-38 KE-5 20 16KE-40 to KE-5 (oil) Oil KE-40 KE-5 15KE-40 to KE-5 (gas) Gas KE-40 KE-5 15 10Poleng to Poleng FSO Oil Poleng Poleng FSOSource: Wood Mackenzie

Costs

Exploration Costs

It is estimated the E-6-4-1 exploration well, completed in 2008, cost in the region of US$9.5 million. A total of US$253.5 million (in nominal terms) has been spent on exploration of the West Madura PSC as of 01/12/2011. Since the award of the Poleng TAC, it is estimated around US$13 million (nominal terms) has been spent on exploration, including the 1999 seismic campaign and exploration and appraisal drilling on the southern extension of the field.

Exploration Costs Pre-2003 to 2011 (US$ million) Pre-2003 2003 2004 2005 2006 2007 2008 2009 2010 2011Exploration Costs 199 24 34 - - - 10 - - -Source: Wood Mackenzie Costs in Nominal Terms.

Capital Costs

West Madura PSC Wood Mackenzie estimates that by the end of 2011, around US$786.2 million (in nominal terms) has been spent on the West Madura PSC. Around US$50 million was spent on the KE-2 development, with capital costs of US$43 million (nominal terms) for the nearby KE-30 field. Development of the KE-5 gas project costs an estimated US$82 million, with the adjacent KE-6 subsea satellite development requiring a spend of around US$9 million (in nominal terms). We have assumed that development of KE-40 cost around US$49 million (nominal terms).

Development of KE-32 and KE-38 cost around $50 million and $130 million respectively, incorporating two WHPs at around US$15 million each and development drilling and pipeline/flow line. Costs associated with construction and installation of production facilities and development drilling for the development of the KE-24, KE-39 and KE-54 fields are assumed to amount to a combined US$180 million.

We have also included US$5 million for repairs to the KE-40 platform in 2010/2011, and US$14 million for relocation of the shallow water pipeline. Additional compression was added to the KE-38 platform in 2010, at an estimated cost of US$5 million.

We estimate that up to four infill wells, at a cost of US$10 million each, will be drilled over the next few years to sustain production and slow down field decline.



Capital Costs Pre-2003 to 2011 (US$ million)

Pre-2003 2003 2004 2005 2006 2007 2008 2009 2010 2011Product. Facilities 139 - 25 30 7 30 10 40 23 18Dev. Drilling 52 - 8 28 16 33 70 56 91 54Pipeline - - - - 24 20 - - 3 10Total 191 - 33 58 47 83 80 96 117 82Source: Wood Mackenzie Nominal to 2011 and real (in 2011 terms) thereafter. Capital Costs 2012 to Post-2020 (US$ million) 2012 2013 2014 2015 2016 2017 2018 2019 2020 Post-2020Product. Facilities 40 - 20 - 40 - - - - -Dev. Drilling 40 20 30 40 20 30 30 - - -Pipeline 4 - - 20 - - - - - -Total 84 20 50 60 60 30 30 - - -Source: Wood Mackenzie Nominal to 2011 and real (in 2011 terms) thereafter.

Poleng TAC Wood Mackenzie estimates that US$465 million (in nominal terms) has been spent on the Poleng TAC by the end of 2011.

Spending on the Poleng C and D field developments has included US$60 million on the central processing platform and US$20 million each on two WHPs. Another US$20 million was spent on a new dedicated 65 kilometre gas pipeline to Gresik, plus US$25 million on a new gas compressor to maintain output from the Poleng AW platform. Development drilling will total around US$254 million over the life of the field.

Capital Costs Pre-2003 to 2011 (US$ million) Pre-2003 2003 2004 2005 2006 2007 2008 2009 2010 2011Production Facilities 40 - - - 80 50 - - 10 -Development Drilling 35 - 12 - 20 55 35 53 30 15Pipeline - - - - - 5 25 - - -Total 75 - 12 - 100 110 60 53 40 15Source: Wood Mackenzie Nominal to 2011 and real (in 2011 terms) thereafter.

Operating Costs

Operating costs for the West Madura PSC and Poleng TAC are detailed in the following table. Average operating costs in 2012 are estimated at US$6.12/boe for West Madura PSC and US$11.53/boe for Poleng TAC.

Operating Costs 2010 to 2014 (US$ million)

2010 2011 2012 2013 2014West Madura PSC 97 90 89 79 73Poleng TAC 32 31 29 27 -Total 129 121 118 106 73Source: Wood Mackenzie Nominal to 2011 and real (in 2011 terms) thereafter.

Sales Contracts

Gas sales to PLN from the West Madura PSC began in January 1993. Under the terms of the gas sales agreement (GSA), the joint venture committed to supply 40 mmcfd of gas to the Gresik power station over a 15 year period. Initial production from the West Madura Offshore fields was less than the contracted volumes and gas from Poleng TAC was used to cover the shortfall.

Wood Mackenzie understands that following contract negotiations in 2001 between PLN and the West Madura/Poleng partners, the pipeline tariff was removed with effect from 2003.

Production from the Kangean PSC had declined by 2003 and Kodeco agreed to supply up to 90 mmcfd from 2004, on a best endeavours basis. We estimate that the gas was priced at US$2.45/mmbtu (US$2.94/mcf). After failing to supply



any incremental volumes, the PLN GSA was amended in 2006 such that Kodeco would supply 171.56 tBtu (143 bcf) over an eight-year period - an average 50 mmcfd with a potential to supply more gas on a best endeavours basis. Gas supply for this contract started in early 2007.

In addition, a GSA was signed with PGN in Dec 2006 to supply 51 tbtu of gas over a seven year period - equating to an average 17 mmcfd. A GSA was also signed in January 2007, to supply Petrokimia Gresik 26.3 tbtu, priced at US$3.60/mmbtu (US$4.32/mcf), from 2007 to 2011. Gas supply of 7 bbtud (6 mmcfd) started on 5 Jan 2007 and peaked at 20 bbtud (17 mmcfd) in 2008. For the purpose of the cash flow analysis, we have assumed that the supply from both of these contracts is met from fields within the West Madura PSC.

In August 2007, Pertamina signed a 6-year GSA with PT Media Karya Sentosa for a contract volume of 83.9 tbtu, worth US$340.5 million. This translates to around 32 mmcfd of gas for an average flat price of US$4.05/mmbtu (US$4.86/mcf). In November 2010, Petrokimia Gresik signed a three month contract for the supply of 6 bbtud. The contract was valued at US$2.1 million.

In February 2010, a GSA was signed with PLN to cover any additional gas supply up to 123 mmcfd, on a best endeavours basis. We estimate that the gas receives a price of US$2.45/mmbtu (US$2.94/mcf).

Taxation

West Madura PSC

The West Madura PSC is a pre-1984 contract with the following key terms:

The post tax profit oil and gas splits are 85:15 and 70:30 respectively in the government's favour.

A tax rate of 56% applies and DMO is applied at 8.52% after a five-year holiday.

DMO reimbursement is set at US$0.20/bbl.

Investment credit was given at a rate of 20% on tangible capital expenditure. In 1989, investment credit on tangible gas capex was increased to 55%.

Poleng TAC

The Poleng TAC is a Technical Assistance Contract with the following key terms:

The post profit oil and gas splits are set at 85:15 and 65:35 respectively in the government's favour.

A tax rate of 48% was applied.

DMO is applied at 7.21% and DMO reimbursement is set at 15% of the export price.

Cost recovery in any year is limited to 35% of gross revenue and an additional payment is levied on windfall profits.

Economic Assumptions

Two cash flows have been produced for the West Madura PSC and the Poleng TAC. The West Madura cash flow represents the participant's total interest in the project. The unitised South Camar interest net to the West Madura participants is not included in this cash flow (see Bawean PSC analysis).

In addition, the following assumptions have been made in constructing the summary cash flow:

Oil Price Wood Mackenzie uses Brent as the benchmark blend for its oil price assumption. Prices for other crude blends and condensates are assessed in relation to Brent and then assigned a percentage (%) discount or premium on that basis.

The Wood Mackenzie Brent oil price assumption in nominal terms is US$111.29/bbl in 2011, US$106.25/bbl in 2012, US$104.75/bbl in 2013, US$92.50/bbl in 2014, US$86.59/bl in 2015 escalating at 2.0% per annum thereafter.

The West Madura and Poleng crude trades at a US$0.13/barrel premium to Ardjuna crude, which trades at a 3% premium to Brent. For the purpose of the analysis, we have assumed West Madura and Poleng crude trades at a 3% premium to Brent and condensate at a 3% discount to Brent.



Other Assumptions Liquids output is modelled until depletion for the West Madura PSC and to contract expiry for the Poleng TAC.

The gas reserves required to meet gas contracts will be produced from both the Poleng field (under the terms of the Poleng TAC) and fields in the West Madura PSC.

The West Madura PSC paid a gas pipeline tariff of US$1.15/mcf until 2003. Since 2003, no pipeline tariff has been payable.

Our inflation rate assumption is 2.0% per annum post-2011.

The cash flow is in nominal terms, discounted to 1/1/2012 using a 10% discount rate.

The corresponding GEM file names are Poleng TAC.fld, West Madura PSC.fld

Cash Flow

West Madura PSC



Cash Flow Dollars

Year Production Gross Op Capital FTP Gov. Share Cost Profit Gov. Share DMO Tax Total Field Liquids Gas Revenue Costs Costs FTP Oil Oil Profit Oil Cash flow 000b/d mmcfd US$M US$M US$M US$M US$M US$M US$M US$M US$M US$M US$M 1983 0.0 0.0 0.0 0.0 24.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 -24.01984 0.0 0.0 0.0 0.0 20.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 -20.01985 3.3 0.0 34.3 4.9 0.0 0.0 0.0 34.3 0.0 0.0 0.0 0.0 29.41986 1.6 0.0 8.7 3.4 0.0 0.0 0.0 8.7 0.0 0.0 0.0 0.0 5.31987 1.5 0.0 10.4 3.3 0.0 0.0 0.0 10.4 0.0 0.0 0.0 0.0 7.11988 1.1 0.0 6.2 3.0 1.0 0.0 0.0 6.2 0.0 0.0 0.0 0.0 2.21989 0.9 0.0 6.2 2.8 21.0 0.0 0.0 6.2 0.0 0.0 0.0 0.8 -18.41990 0.8 0.0 7.1 2.7 28.0 0.0 0.0 7.1 0.0 0.0 0.0 0.9 -24.41991 0.8 0.0 6.1 2.7 28.0 0.0 0.0 6.1 0.0 0.0 0.0 0.9 -25.51992 0.5 0.0 3.6 2.4 10.0 0.0 0.0 3.6 0.0 0.0 0.0 0.4 -9.21993 0.9 35.0 43.9 28.7 0.0 0.0 0.0 43.9 0.0 0.0 0.0 3.7 11.51994 1.1 31.0 40.4 26.8 0.0 0.0 0.0 40.4 0.0 0.0 0.0 0.0 13.61995 1.0 33.0 42.4 27.9 0.0 0.0 0.0 42.4 0.0 0.0 0.0 0.0 14.61996 0.9 29.0 38.6 25.4 0.0 0.0 0.0 38.6 0.0 0.0 0.0 0.0 13.21997 0.9 25.0 33.8 23.0 0.0 0.0 0.0 33.8 0.0 0.0 0.0 0.0 10.81998 0.6 16.5 21.0 17.9 4.0 0.0 0.0 21.0 0.0 0.0 0.0 0.4 -1.31999 0.4 10.0 13.8 13.7 5.2 0.0 0.0 13.8 0.0 0.0 0.0 0.4 -5.52000 0.8 18.0 28.3 19.1 0.0 0.0 0.0 28.3 0.0 0.0 0.0 0.0 9.22001 0.5 11.0 16.2 14.1 27.0 0.0 0.0 16.2 0.0 0.0 0.0 1.7 -26.62002 7.8 24.0 99.3 44.7 23.0 0.0 0.0 99.3 0.0 0.0 0.0 1.1 30.52003 9.2 20.0 120.6 43.6 0.0 0.0 0.0 120.6 0.0 0.0 0.0 0.0 77.02004 10.3 22.5 172.6 41.9 33.0 0.0 0.0 172.6 0.0 0.0 0.0 1.6 96.12005 10.3 42.5 258.4 46.0 58.0 0.0 0.0 193.8 64.6 42.6 0.8 41.5 69.62006 10.3 39.0 297.9 46.0 47.0 0.0 0.0 96.0 201.9 133.1 0.0 43.5 28.32007 8.8 45.0 301.1 44.7 83.0 0.0 0.0 125.9 175.3 115.5 11.1 38.9 8.02008 7.1 41.0 317.3 43.0 80.0 0.0 0.0 148.4 168.9 111.4 11.3 31.0 40.72009 9.1 101.0 347.2 77.5 96.0 0.0 0.0 181.2 166.1 103.0 6.4 44.1 20.22010 21.0 158.0 830.6 96.7 116.5 0.0 0.0 227.6 603.0 373.4 9.3 133.1 101.62011 14.0 152.0 775.9 89.8 81.5 0.0 0.0 190.3 585.6 363.5 10.8 127.5 102.72012 13.5 150.0 722.5 90.8 85.7 0.0 0.0 191.0 531.5 330.7 19.9 114.1 81.32013 11.7 121.0 607.6 82.2 20.8 0.0 0.0 134.2 473.4 291.0 17.1 93.6 102.92014 9.7 96.0 449.4 77.5 53.1 0.0 0.0 145.4 304.0 193.9 12.0 61.5 51.52015 8.2 77.0 349.1 63.9 65.0 0.0 0.0 143.1 206.0 135.8 22.7 33.7 28.22016 5.8 61.0 257.9 60.2 66.2 0.0 0.0 134.9 123.0 81.1 16.4 25.9 8.12017 4.6 50.0 207.6 58.2 33.8 0.0 0.0 115.6 92.0 60.6 13.1 11.9 30.02018 3.4 39.0 159.1 44.8 34.5 0.0 0.0 96.3 62.8 41.4 10.0 8.1 20.42019 0.1 31.0 36.6 23.4 0.0 0.0 0.0 36.2 0.4 0.1 0.0 0.1 12.92020 0.1 23.0 28.1 22.2 0.0 0.0 0.0 28.1 0.0 0.0 0.0 0.0 5.82021 0.1 19.0 23.8 21.9 0.0 0.0 0.0 23.8 0.0 0.0 0.0 0.0 1.92022 0.1 12.0 16.4 14.9 0.0 0.0 0.0 16.4 0.0 0.0 0.0 0.0 1.52023 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Totals: 66.7 559.4 6739.6 1355.6 1145.2 0.0 0.0 2981.2 3758.4 2377.0 160.8 820.2 880.8 PVs Total PV 9307.1 2381.4 2572.8 0.0 0.0 5347.8 3959.4 2508.1 147.8 944.8 752.3 Rem PV 2242.1 398.1 269.8 0.0 0.0 769.4 1472.7 928.6 83.3 290.8 271.6Source: Wood Mackenzie Discounted at 10.0% from 01/01/2012

Discount Total PV Remaining PV Remaining PV/boe Total Total Remaining Remaining P/I Capex OpexRate Post-Tax Pre-Tax Post-Tax Pre-Tax Post-Tax Pre-Tax Gov. Take Gov. Take Gov. Take Gov. Take Ratio Boe Boe% US$M US$M US$M US$M US$ US$ US$M % US$M % US$ US$ 0.0 880.8 4238.8 344.4 1938.9 5.34 30.06 3358.0 79.2 1594.5 82.2 1.8 6.93 8.215.0 901.6 4339.2 303.4 1736.8 4.70 26.93 3437.6 79.2 1433.4 82.5 1.6 9.28 10.127.0 878.3 4370.4 289.8 1667.7 4.49 25.86 3492.1 79.9 1378.0 82.6 1.5 11.09 11.468.0 851.9 4376.5 283.4 1635.3 4.39 25.35 3524.6 80.5 1351.9 82.7 1.4 12.30 12.309.0 811.3 4372.0 277.4 1604.2 4.30 24.87 3560.7 81.4 1326.8 82.7 1.4 13.77 13.2810.0 752.3 4352.9 271.6 1574.3 4.21 24.41 3600.6 82.7 1302.7 82.7 1.3 15.58 14.4211.0 669.3 4313.9 266.1 1545.6 4.13 23.96 3644.6 84.5 1279.5 82.8 1.2 17.79 15.7512.0 555.4 4248.4 260.8 1518.0 4.04 23.53 3692.9 86.9 1257.2 82.8 1.2 20.50 17.2915.0 -67.7 3799.4 246.4 1441.3 3.82 22.34 3867.1 101.8 1194.9 82.9 1.0 32.92 23.5725.0 -12881.9 -7924.7 208.9 1237.3 3.24 19.18 4957.3 n/a 1028.4 83.1 0.6 215.67 85.14Source: Wood Mackenzie



Discount Date Jan-12Remaining Liquid Reserves (mmbbls) 20.9Remaining Gas Reserves (bcf) 247.8Total Remaining Reserves (mmboe) 64.5Total Reserves (mmboe) 165.1Project IRR (post tax) 14.77%Company IRR (post tax) 14.77%Pre-tax IRR 21.10%Payback Period (years) 20.1Reserve life at current production (years) 4.4Liquid Breakeven Price at 10% (US$/bbl) 17.37Gas Breakeven Price at 10% (US$/mcf) 2.32Source: Wood Mackenzie

Split of Revenues

Cumulative Net Cash Flow - Undiscounted Cumulative Net Cash Flow - Discounted at 10% from 01/01/2012



Remaining Revenue Distribution (Discounted at 10% from 01/01/2012)

Remaining Present Value Price Sensitivities

Poleng TAC



Cash Flow Dollars

Year Production Gross Op Capital FTP Gov. Share Cost Profit Gov. Share DMO Tax Total Field Liquids Gas Revenue Costs Costs FTP Oil Oil Profit Oil Cash flow 000b/d mmcfd US$M US$M US$M US$M US$M US$M US$M US$M US$M US$M US$M 1997 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.01998 0.6 3.0 6.2 6.0 26.0 0.0 0.0 2.2 4.1 2.1 0.0 0.6 -28.41999 1.3 16.0 26.6 13.6 6.8 0.0 0.0 9.3 17.3 7.9 0.0 2.5 -4.22000 3.7 15.0 56.8 15.5 25.8 0.0 0.0 19.9 36.9 22.1 0.0 5.8 -12.42001 6.0 26.0 83.2 32.0 8.2 0.0 0.0 29.1 54.1 31.6 0.0 8.4 3.02002 5.7 36.0 92.0 26.0 8.0 0.0 0.0 32.2 59.8 33.0 0.0 14.0 11.02003 5.3 68.9 130.7 38.2 0.0 0.0 0.0 45.8 85.0 42.0 3.5 22.8 24.32004 4.0 72.5 134.5 37.7 12.0 0.0 0.0 47.1 87.4 42.8 3.5 18.4 20.22005 2.4 51.6 104.9 33.0 0.0 0.0 0.0 36.7 68.2 34.6 3.0 15.7 18.52006 1.4 49.0 87.5 31.8 100.0 0.0 0.0 30.6 56.9 27.3 2.1 7.1 -80.92007 6.0 45.3 212.5 35.3 110.0 0.0 0.0 74.4 138.1 86.1 10.0 17.4 -46.32008 7.6 45.0 326.2 36.6 60.0 0.0 0.0 114.2 212.1 138.8 17.0 46.0 27.82009 6.3 43.1 192.4 35.2 52.5 0.0 0.0 67.3 125.1 77.4 9.0 16.0 2.32010 5.0 29.3 180.6 31.9 40.0 0.0 0.0 63.2 117.4 75.7 9.1 16.3 7.62011 3.6 28.5 181.2 30.5 15.0 0.0 0.0 63.4 117.8 76.2 9.2 20.5 29.92012 2.9 22.8 139.5 29.6 0.0 0.0 0.0 48.8 90.7 58.4 7.1 18.4 26.12013 1.8 18.2 90.5 28.5 0.0 0.0 0.0 31.7 58.8 36.9 4.4 6.8 13.82014 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Totals: 23.2 208.2 2045.3 461.3 464.3 0.0 0.0 715.9 1329.4 792.9 78.0 236.6 12.2 PVs Total PV 3281.1 813.8 810.4 0.0 0.0 1148.4 2132.7 1238.6 105.5 390.1 -77.3 Rem PV 211.4 52.9 0.0 0.0 0.0 74.0 137.4 87.7 10.5 23.5 36.9Source: Wood Mackenzie Discounted at 10.0% from 01/01/2012

Discount Total PV Remaining PV Remaining PV/boe Total Total Remaining Remaining P/I Capex OpexRate Post-Tax Pre-Tax Post-Tax Pre-Tax Post-Tax Pre-Tax Gov. Take Gov. Take Gov. Take Gov. Take Ratio Boe Boe% US$M US$M US$M US$M US$ US$ US$M % US$M % US$ US$ 0.0 12.2 1119.7 39.9 171.9 9.19 39.56 1107.4 98.9 132.0 76.8 1.0 7.76 7.715.0 -21.4 1351.1 38.3 164.9 8.82 37.95 1372.5 101.6 126.5 76.8 1.0 10.17 10.137.0 -40.3 1463.4 37.7 162.2 8.68 37.34 1503.8 102.8 124.5 76.8 0.9 11.39 11.378.0 -51.4 1524.4 37.4 161.0 8.61 37.05 1575.8 103.4 123.5 76.8 0.9 12.06 12.069.0 -63.7 1588.8 37.1 159.7 8.55 36.77 1652.5 104.0 122.6 76.7 0.9 12.78 12.8110.0 -77.3 1656.9 36.9 158.5 8.48 36.48 1734.1 104.7 121.6 76.7 0.9 13.55 13.6111.0 -92.4 1728.7 36.6 157.3 8.42 36.21 1821.1 105.3 120.7 76.7 0.9 14.38 14.4712.0 -109.2 1804.5 36.3 156.1 8.36 35.94 1913.7 106.1 119.8 76.7 0.9 15.28 15.4015.0 -171.6 2057.8 35.5 152.7 8.18 35.16 2229.4 108.3 117.2 76.7 0.8 18.38 18.6225.0 -596.8 3247.7 33.2 142.7 7.65 32.83 3844.5 118.4 109.4 76.7 0.7 35.59 36.17Source: Wood Mackenzie

Discount Date Jan-12Remaining Liquid Reserves (mmbbls) 1.7Remaining Gas Reserves (bcf) 15Total Remaining Reserves (mmboe) 4.3Total Reserves (mmboe) 59.8Project IRR (post tax) 2.12%Company IRR (post tax) 2.12%Pre-tax IRR 88.68%Payback Period (years) 13.5Reserve life at current production (years) 1.7Liquid Breakeven Price at 10% (US$/bbl) 27.42Gas Breakeven Price at 10% (US$/mcf) 3.66Source: Wood Mackenzie



Split of Revenues







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South East Asia - IndonesiaJuly 2012

Muara Bakau

Key Facts

Probable Development OffshoreLocation Timetable Sector, Basin: Kalimantan, Kutei Issue Date: Muara Bakau Dec-02Block: Muara Bakau, Area: 1,082 km2 Discovery Date: Jangkrik Mar-09Water Depth: 380 - 460m Discovery Date: Jangkrik North East Jul-11 Expected Startup: Jangkrik 2017 Expected Startup: Jangkrik North East 2018 Peak Condensate Production (4,500 b/d): Muara

Bakau PSC 2019

Peak Gas Production (450 mmcfd): Muara Bakau PSC

2020

Final Expiry: Muara Bakau Dec-32Operator Participants %Eni Eni 55 GDF Suez 45Primary Reservoir(s): Neogene\Pliocene Recoverable Reserves (p+p) Hydrocarbon Quality 21 mmbbl Cond C1 (%) 961,955 bcf Sales Gas H2S (ppm) 0Remaining Reserves at 01/01/2012 Permeability (mD) 100 - 1,00021 mmbbl Cond Porosity (%) 25 - 301,955 bcf Sales Gas Net Pay (m) 10 - 80Contract Financial Summary Production Sharing Contract Capital costs (2012 terms) US$3,205M Capital costs per boe (2012 terms) US$8.79/boe Operating costs (2012 terms) US$1,823M Operating costs per boe (2012 terms) US$5.00/boe Remaining PV (10.0% nominal) US$1,648M Remaining PV per boe (10.0% nominal) US$4.52/boe Rate of return 23.1%Source: Wood Mackenzie


Summary

The Muara Bakau PSC is located in deepwater off the east coast of Kalimantan. The PSC contains the Jangkrik and Jangkrik North East gas/condensate fields, discovered in 2009 and 2011 respectively, plus the small Perintis field.

Gas from the PSC is expected to be sent to a new-build onshore receiving facility (ORF) near the Sapi field, before being piped to the Bontang LNG complex. A preliminary development plan for Jangkrik was submitted in July 2011, with Plan of Development (POD) approval given in Q4 2011. The partners expect to take a final investment decision (FID) in Q1 2013, however this could be delayed given there are currently no GSPAs in place for the LNG output from Bontang.

Muara Bakau Indonesia

South East Asia Upstream Service - July 2012 Page 2 of 14

It is expected that the POD for Jangkrik North East will be approved in late-2012. The operator has indicated it intends to achieve a combined plateau production rate for Jangkrik and Jangkrik North East of 450 mmcfd for a period of eight years. Wood Mackenzie expects this will result in associated condensate output of 3,000 b/d.

Key Issues

As at July 2012, no gas sales agreements (GSAs) have been signed. It is unclear whether gas from Muara Bakau will incur a tariff for the use of the Bontang LNG facilities in addition to the plants' base operating costs.

The neighbouring Indonesia Deepwater Development (IDD), operated by Chevron, has experienced a series of delays and cost increases. As the development of Jangkrik and Jangkrik North East will be similar to this, though smaller, managing costs will be crucial to the project economics.

The partners are targeting first gas in late-2015/2016, however, we expect the project will not be brought onstream until late-2017, given the timescales required for the construction of the deepwater project (around 3.5 years) and to allow for the LNG volumes to be marketed. We understand the operator called for bids for the EPCI tender in mid-2012.

Additional exploration targets exist in the PSC which may be drilled before the licences exploration period ends on 29th December 2012.



Location Maps

Index Map

MALAYSIA

KalimantanINDONESIA

BRUNEI

MALAYSIA

Sabah

Sarawak

120°E

120°E

118°E

118°E

116°E

116°E

114°E

114°E

112°E

112°E

110°E

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6°N

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0 200 400100km




Detail Map

Pertam ina

On Offer

Total

isEnergy

Total

Chevron

Chevron

Chevron

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Chevron

Eni

Tota

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Eni

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Muara Bakau

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West Bekapai-1

Beran i-1

Tunu -1

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Giram-1

3

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Pitis-1 1

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17,18

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Sidi-1

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1,2

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2

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Semayang-1

Sisi GN-11

H-3

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NW Peciko-14

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East Bekapai-1

Paran gat-1

Rajawa li-1 A

1

3

Harapan-1

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Telakai-1

NW Apa r-1

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2

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prop osedGa s Plant

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118°15'E

118°15'E

118°E

118°E

117°45'E

117°45'E

117°30'E

117°30'E

117°15'E

117°15'E

0°4

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Participation

The acreage contained within the Muara Bakau PSC was previously held under the Makassar PSC, but mandatory partial area relinquishments resulted in this area being carved out of the Makassar PSC.

The Muara Bakau PSC was awarded to Eni and Unocal in December 2002, with both companies holding a 50% interest and the operatorship lying with Eni. Unocal was subsequently acquired by Chevron in August 2005.

In June 2006, Chevron swapped its interest in four east Kalimantan PSCs with Anadarko, in exchange for a 40% interest in Anadarko's North East Madura exploration licence. Anadarko sold its interest in the Muara Bakau PSC to Eni in October 2007, giving the Italian company a 100% operated interested.

In 2008, Eni and GDF Suez signed an asset swap agreement. As a result of this, Eni transferred a 45% interest in the Muara Bakau PSC to GDF Suez in September 2009.

Participation Company (%) Eni 55.00 * GDF Suez 45.00 Total 100.00 Source: Wood Mackenzie * Operator

Geology

The Muara Bakau PSC contains a series of submarine fans, around five kilometres in length and several tens of metres thick.

The Jangkrik and Jangkrik North East fields are characterised by multiple stacked high-quality reservoirs in the Neogene Pilocene/Miocene formations. The gas contained with the fields has a CH4 content of 96%, contains no H2S or mercury and has only minor volumes of CO2.



Well Data Well Name Operator Spudded TMD(m) Result Discovery Field Comment Type Completed WD(m) Perintis-1 24-Jul-94 3658 * Exploration

Mobil 23-Oct-94 380

Gas/Condensate Perintis Tested gas with 200 b/d of associated condensate.

Sidi-1 20-Mar-98 4178 Exploration

Unocal 13-Apr-98 158

Gas Shows

Rajawali-1 24-Feb-05 Exploration

Eni 08-Mar-05 808

Tight Hole Believed to have been re-entered as Rajiwali-1A.

Rajawali-1A 09-Mar-05 3118 Exploration

Eni 09-Apr-05 808

Dry Hole

Jangkrik-1 14-Feb-09 2438 + Exploration

Eni 29-Mar-09 430

Oil & Gas Jangkrik Encountered 10 metres of oil pay and 28 metres of gas pay.

Jangkrik-2 16-May-10 594 Appraisal

Eni 23-Jun-10 425

Gas Encountered in excess of 80 metres of net Pliocene gas pay, tested at 17.5 mmcfd.

Capung-1 11-Sep-10 Exploration

Eni 10-Nov-10 850

Dry Hole

Jangkrik-3 11-Nov-10 2849 Appraisal

Eni 14-Dec-10 416

Gas Encountered 60 metres of net gas pay in the Pliocene formation.

Jangkrik NE-1 02-Jun-11 3633 + Exploration

Eni 14-Jul-11 460

Gas Jangkrik North East Encountered more than 60 metres of net gas pay and flowed at a constrained rate of 30.6 mmcfd.

Jangkrik NE-2 15-Jul-11 Appraisal

Eni 04-Aug-11 460

Gas

Jangkrik NE-3 19-Apr-12 575 Appraisal

Eni 15-May-12

Gas

Katak Biru-1 17-May-12 Exploration

Eni 27-Jun-12

Gas Shows


Exploration

Early exploration The Perentis field was the first to be discovered on acreage now included in the Muara Bakau PSC. The discovery well, Perentis-1, was drilled by Mobil in 1994, on acreage previously included in the Makassar PSC, and flowed gas with 200 b/d of associated condensate. However, the field was deemed sub-commercial and subsequently relinquished.

The Sidi-1 well, drilled by Unocal in 1998, also on the Makassar PSC, encountered only gas shows.

In 1999, PGS shot a Makassar multi-client 3D seismic survey covering 7,300 km2, over an area which included what was to be offered up as the Muara Bakau PSC.

Muara Bakau PSC The Muara Bakau PSC was awarded in 2002 covering 1,807 km2 and had a two well exploration commitment.

The first exploration well drilled on the PSC was Rajawali-1 in early-2005. The initial results were tight, and the re-entry, Rajawali-1A was a dry hole. A mandatory partial relinquishment resulted in the block size decreasing to 1,082 km2 in 2008.

The next well, Jangkrik-1, encountered oil and gas in March 2009. The well was successfully appraised by Jangkrik-2 the folllowing May, with testing flowing rates of up to 17.5 mmcfd. A second appraisal well, Jangkrik-3, was drilled in late-2010 and also encountered gas.

In-between the Jangkrik-2 and 3 wells, the Capung-1 well was drilled, around 20 kilometres to the south of the Jangkrik discovery. However, this well came in dry.



In mid-2011, the Jangkrik NE-1 well encountered gas, with a constrained flow rate of 30.6 mmcfd obtained during testing. A successful appraisal well was drilled immediately after the discovery well. A second appraisal well, Jangkrik NE-3 was spudded in April 2012, and is thought to have encountered gas. The well was drilled to prove up the southern extension of the field.

The Katak Biru-1 well was drilled on the PSC in Q2 2012. We understand that the well intersected gas, but additional information is unknown at the present time.

There are thought to be at least one further prospect to be drilled across the Muara Bakau acreage. The exploration period of the PSC ends on 29th December 2012.

Reserves

The gas contained within the Jangkrik and Jangkrik North East fields has a CH4 content of 96%, contains no H2S or mercury and has only minor volumes of CO2.

Estimates of gas-in-place across the PSC are thought to be up to 4 tcf. Based on the current development plan, our estimates of recoverable reserves are shown in the following table.


Init Init Rem Rem Cond. Gas Cond. Gas (mmbbl) (bcf) (mmbbl) (bcf)Jangkrik 21 1027 21 1027Jangkrik North East - 927 - 927Total 21 1954 21 1954Source: Wood Mackenzie

As the Muara Bakau PSC expires in 2032, we estimate there will be volumes of reserves within the Jangkrik and Jangkrik North East fields that remain to be recovered. These are classed as technical reserves and shown in the following table.

We currently class the Perintis field as technical due to the small volume of reserves it contains. Reserves estimates for the 2012 discovery Katak Biru are unknown at the current time.

Technical Recoverable Reserves (Remaining Reserves at 01/01/2012)

Init Init Rem Rem Cond. Gas Cond. Gas (mmbbl) (bcf) (mmbbl) (bcf)Jangkrik 5 373 5 373Jangkrik North East - 173 - 173Perintis 2 20 2 20Total 7 566 7 566Source: Wood Mackenzie

Production

The partners are targeting first gas in late-2015/2016, however, given the size of the project and the issues that have impacted nearby developments, we expect first production will not be obtained until late-2017. This assumes that FID is taken in mid-2013, and allowing for a 3.5 year construction period.

We estimate that a production plateau of 450 mmcfd will be reached in 2020, once the Jangkrik North East field has been brought onstream and ramped up to full production levels.

We expect all of the produced gas will be sent to the Bontang LNG plant in east Kalimantan. Of the produced LNG, we expect 25% will be sent to the Indonesian domestic market via regasification terminals in Java and Sumatra. Small volumes of associated condensate are expected to be produced form the Jangkrik field.




2016 2017 2018 2019 2020 2021 2022 2023 2024 2025Jangkrik ('000 b/d) - 1 3 5 5 5 5 5 5 5 Jangkrik (mmcfd) - 50 150 225 225 225 225 225 225 225Jangkrik NE (mmcfd) - - 25 125 225 225 225 225 225 225Total Sales Gas (mmcfd) - 50 175 350 450 450 450 450 450 450Source: Wood Mackenzie

Production Profile

Development

It is expected that the Muara Bakau PSC will be developed in two stages, with the Jangkrik field being brought onstream first, followed by Jangkrik North East.

The deepwater location of the fields will necessitate a floating development, with subsea trees being tied-back to a purchased FPSO. We anticipate up to 10 development wells will be drilled initially, with up to a further seven required across the life of project. In total, we expect 10 wells on the Jangkrik field tied back to three subsea trees, and up to seven wells on Jangkrik North East, requiring two subsea trees.

Produced gas will be processed on the FPSO, and then sent to a new-build onshore receiving facility (ORF) near the Sapi field, before being piped to the Bontang LNG complex via existing infrastructure. Alternatively, a new-build pipeline directly to the Bontang LNG plant may be constructed.

Associated condensate will be stripped out of the gas on the FPSO and offloaded via shuttle tankers.

Transportation

We expect that the project will utilise a purchased FPSO, with condensate offloaded periodically onto shuttle tankers.

Produced gas may be piped 70 kilometres to a new-build onshore receiving facility near the Sapi field, then on to the Bontang LNG complex via existing infrastructure, however this is uncertain as at July 2012. A new-build pipeline directly to the Bontang LNG plant may be constructed instead.



Costs

Exploration costs We estimate that US$218 million (nominal terms) has been spent on exploration and appraisal of the Muara Bakau PSC, as at 01/07/2012. This includes US$30 million for the in-progress Jangkrik NE-3 well.

Exploration Costs Pre-2008 to 2012 (US$ million) Pre-2008 2008 2009 2010 2011 2012Sunk Costs - - 50 66 52 30Source: Wood Mackenzie Costs in Nominal Terms.

Capital costs We estimate that the initial development of the Jangkrik and Jangkrik North East fields will cost around US$2.45 billion (2012 terms). This will consist of US$900 million for production facilities, both offshore and for the ORF.

We have assumed US$1,100 million will be spent on drilling and subsea manifolds, and pipelines at a cost of US$150 million. Each well is assumed to cost US$65 million (2012 terms). We have also assumed an FPSO will be purchased at a cost of US$300 million.

Further spending on drilling, completions and facility maintenance is estimated at up to US$755 million across the rest of the life of project.

Capital Costs 2014 to Post-2022 (US$ million) 2014 2015 2016 2017 2018 2019 2020 2021 2022 Post-2022Product. Facilities 200 400 300 - - - - - - -Subsea - - 300 150 - - - - - 300Dev. Drilling - - 195 195 130 130 - - - 455Pipeline - 50 90 - 10 - - - - -Other Capex - 150 150 - - - - - - -Total 200 600 1035 345 140 130 - - - 755Source: Wood Mackenzie Nominal to 2012 and real (in 2012 terms) thereafter.

Operating costs We estimate operating costs associated with the project will be around US$5/boe. No tariff in addition to the Bontang plant operating costs has been applied to gas processed from the Muara Bakau PSC.


2017 2018 2019 2020 2021Direct Costs 18 62 121 153 153Source: Wood Mackenzie Nominal to 2012 and real (in 2012 terms) thereafter.

Sales Contracts

As at July 2012, no GSAs have been signed for the gas produced from the Muara Bakau PSC. We expect that all gas will be supplied into the Bontang LNG complex, where it will be converted to LNG. We anticipate that a domestic market obligation (DMO) of 25% will be imposed on the project, with this met by LNG production from the plant, which will be sent to proposed LNG regasification terminals in Java and/or Sumatra.

For LNG export sales in 2011 the assumed DES price formula has a gradient of 0.14 and a constant of US$1.00/mmbtu. This equated to an FOB price of US$15.91/mmbtu in 2011, and a LNG plant gate price of US$12.86/mmbtu (equivalent to US$14.26/mcf).

It has been assumed that gas supplied to the domestic market is priced using a formula with a gradient of 0.11 and a constant of US$0.50/mmbtu.

Taxation

The Muara Bakau PSC is a Post-2000 Deepwater contract with the following key terms.



FTP is applied at a rate of 10%.

The post-tax profit oil and gas splits are 75:25 and 60:40 respectively in the government's favour.

An effective tax rate of 44% applies, comprising withholding tax of 20% and corporation tax of 30%.

Gross DMO will be applied at 25% after a 60-month holiday.

DMO reimbursement is set at 25% of the export price of oil.

Investment credit is available at a rate of 55% on tangible capital expenditure.


In developing a cash flow for the Muara Bakau PSC, the following assumptions have been made:

Oil price Wood Mackenzie uses Brent as the benchmark blend for its crude price assumptions. Prices for other crude blends are assessed in relation to Brent and then assigned a percentage (%) discount or premium on that basis.

The Wood Mackenzie Brent oil price assumption in nominal terms is US$115.11/bbl in 2012, US$105.25/bbl in 2013, US$100.00/bbl in 2014, US$96.00/bbl in 2015 and US$92.00/bbl in 2016, escalating at 2.0% per annum thereafter.

We have assumed Muara Bakau condensate achieves a price equivalent to a 4% discount to our Brent price assumption.

Gas price LNG Export

For LNG export sales, the assumed DES price formula has a gradient of 0.14 and a constant of US$1.00/mmbtu. This equated to an FOB price of US$15.91/mmbtu in 2011, and a LNG plant gate price of US$12.86/mmbtu (equivalent to US$14.26/mcf).

Domestic Market

For the purposes of his analysis, it has been assumed that gas supplied to the domestic market is priced using a formula with a gradient of 0.11 and a constant of US$0.50/mmbtu.

Other assumptions

Our inflation rate assumption is 2.0% per annum post-2012.

The cash flow is stated in nominal terms, discounted to 01/01/2012 using a 10% discount rate.

The corresponding GEM file name is Muara Bakau PSC.fld



Cash Flow

Cash Flow Dollars

Year Production Gross Op Capital FTP Gov. Share Cost Profit Gov. Share DMO Tax Total Field Liquids Gas Revenue Costs Costs FTP Oil Oil Profit Oil Cash flow 000b/d mmcfd US$M US$M US$M US$M US$M US$M US$M US$M US$M US$M US$M 2013 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.02014 0.0 0.0 0.0 0.0 208.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 -208.12015 0.0 0.0 0.0 0.0 636.7 0.0 0.0 0.0 0.0 0.0 0.0 0.0 -636.72016 0.0 0.0 0.0 0.0 1120.3 0.0 0.0 0.0 0.0 0.0 0.0 0.0 -1120.32017 1.0 50.0 240.1 19.8 380.9 24.0 24.0 216.1 0.0 0.0 0.0 0.0 -184.62018 3.0 175.0 839.7 69.5 157.7 84.0 84.0 755.7 0.0 0.0 0.0 0.0 528.62019 4.5 350.0 1660.6 138.6 149.3 166.1 166.1 1494.5 0.0 0.0 0.0 395.3 811.32020 4.5 450.0 2131.5 179.0 0.0 213.2 213.2 555.7 1362.7 422.5 0.0 511.8 805.02021 4.5 450.0 2172.8 182.6 0.0 217.3 217.3 327.0 1628.5 497.6 0.0 497.6 777.72022 4.5 450.0 2214.8 186.2 0.0 221.5 221.5 309.1 1684.3 516.4 13.7 507.9 769.22023 4.5 450.0 2257.8 189.9 615.5 225.8 225.8 755.2 1276.8 395.0 14.0 476.3 341.32024 4.5 450.0 2301.6 193.7 164.9 230.2 230.2 1335.8 735.6 243.0 14.2 217.9 1237.72025 4.5 450.0 2346.2 197.6 0.0 234.6 234.6 255.3 1856.3 566.9 14.5 560.9 771.62026 4.5 450.0 2391.8 201.6 0.0 239.2 239.2 249.1 1903.6 581.5 14.8 575.2 779.62027 4.5 450.0 2438.3 205.6 87.5 243.8 243.8 324.4 1870.1 569.5 15.1 569.5 747.32028 3.6 360.0 1988.6 167.8 89.2 198.9 198.9 277.7 1512.0 462.4 12.3 460.4 597.72029 2.9 288.0 1621.9 136.9 0.0 162.2 162.2 162.7 1297.0 396.7 10.1 391.7 524.32030 2.3 230.0 1320.5 111.5 0.0 132.1 132.1 302.7 885.7 274.3 8.2 265.4 529.02031 1.7 172.0 1006.7 85.1 0.0 100.7 100.7 102.5 803.6 245.7 6.3 242.7 326.32032 1.3 130.0 775.7 65.6 0.0 77.6 77.6 86.4 611.8 187.2 4.8 184.7 255.92033 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Totals: 20.6 1954.6 27708.5 2330.7 3610.1 2770.9 2770.9 7509.8 17427.9 5358.9 127.9 5857.3 7652.8 PVs Total PV 8518.1 715.5 2027.3 851.8 851.8 2792.6 4873.7 1500.1 32.7 1742.6 1648.1 Rem PV 8518.1 715.5 2027.3 851.8 851.8 2792.6 4873.7 1500.1 32.7 1742.6 1648.1Source: Wood Mackenzie Discounted at 10.0% from 01/01/2012

Discount Total PV Remaining PV Remaining PV/boe Total Total Remaining Remaining P/I Capex OpexRate Post-Tax Pre-Tax Post-Tax Pre-Tax Post-Tax Pre-Tax Gov. Take Gov. Take Gov. Take Gov. Take Ratio Boe Boe% US$M US$M US$M US$M US$ US$ US$M % US$M % US$ US$ 0.0 7652.8 21767.7 7652.8 21767.7 20.99 59.71 14115.0 64.8 14115.0 64.8 3.1 9.90 6.395.0 3594.7 11008.9 3594.7 11008.9 9.86 30.20 7414.2 67.3 7414.2 67.3 2.4 7.27 3.447.0 2647.5 8474.9 2647.5 8474.9 7.26 23.25 5827.3 68.8 5827.3 68.8 2.1 6.51 2.738.0 2266.6 7450.0 2266.6 7450.0 6.22 20.44 5183.4 69.6 5183.4 69.6 2.0 6.17 2.449.0 1935.7 6556.2 1935.7 6556.2 5.31 17.98 4620.5 70.5 4620.5 70.5 1.9 5.85 2.1910.0 1648.1 5775.3 1648.1 5775.3 4.52 15.84 4127.2 71.5 4127.2 71.5 1.8 5.56 1.9611.0 1397.6 5091.6 1397.6 5091.6 3.83 13.97 3694.0 72.6 3694.0 72.6 1.7 5.29 1.7712.0 1179.2 4492.0 1179.2 4492.0 3.23 12.32 3312.7 73.7 3312.7 73.7 1.6 5.04 1.5915.0 676.6 3092.7 676.6 3092.7 1.86 8.48 2416.1 78.1 2416.1 78.1 1.4 4.38 1.1825.0 -75.7 862.2 -75.7 862.2 -0.21 2.36 937.8 108.8 937.8 108.8 0.9 2.91 0.48Source: Wood Mackenzie

Discount Date Jan-12Remaining Liquid Reserves (mmbbl) 20.6Remaining Gas Reserves (bcf) 1954.6Total Remaining Reserves (mmboe) 364.6Total Reserves (mmboe) 364.6Project IRR (post tax) 23.14%Company IRR (post tax) 23.14%Pre-tax IRR 39.98%Payback Period (years) 7Reserve life at current production (years) 0Liquid Breakeven Price at 10% (US$/bbl) 35.55Gas Breakeven Price at 10% (US$/mcf) 4.74Source: Wood Mackenzie



Split of Revenues





Remaining PV Price Sensitivities




South East Asia - IndonesiaJuly 2012

Offshore Mahakam

Key Facts

Onstream On/OffshoreLocation Timetable Sector, Basin: Kalimantan, Kutei Issue Date Mar-67Block: Offshore Mahakam, Area: 2,821 km2 Discovery Date: Offshore Mahakam PSC 1972Water Depth: 1 - 93m Production Started: Bekapai 1974 Discovery Date: Tunu 1977 Peak Oil Production (229,750 b/d) 1977 Production Started: Tunu 1990 Extension Signature Jan-91 Contract Extension Mar-97 Peak Gas Production (2,830 mmcfd) 2006 Production Started: Nubi 2007 Production Started: Sisi 2008 Peak Condensate Production (74,440 b/d) 2009 Final Expiry Dec-17Operator Participants %Total INPEX Corporation 50 Total 50Primary Reservoir(s): Neogene\Pliocene\Zanclean\Kampung Baru Neogene\Miocene\Langhian\Balikpapan\Gelingseh\Klandasan Neogene\Pliocene\Zanclean\Baru\Sepinggan Neogene\Miocene\Langhian\Balikpapan Recoverable Reserves (p+p) Hydrocarbon Quality 1,103 mmbbl Oil Calorific Value (btu/scf) - Tunu 1073115 mmbbl LPG Calorific Value (btu/scf) - West Stupa 1119539 mmbbl Cond Gravity (°API) - Handil 3319,563 bcf Sales Gas Gravity (°API) - Sisi 40Remaining Reserves at 01/01/2012 Gravity (°API) - Tunu 5524 mmbbl Oil 19 mmbbl LPG 151 mmbbl Cond 4,915 bcf Sales Gas Contract Financial Summary Production Sharing Contract Capital costs (2012 terms) US$38,459M Capital costs per boe (2012 terms) US$7.40/boe Operating costs (2012 terms) US$14,078M Operating costs per boe (2012 terms) US$2.71/boe Remaining PV (10.0% nominal) US$10,728M Remaining PV per boe (10.0% nominal) US$10.13/boe Rate of return 28.6%Source: Wood Mackenzie LPG is barrels of oil equivalent, based on a conversion of 0.77 boe/bbl LPG.

Offshore Mahakam Indonesia



Summary

The Offshore Mahakam PSC is one of Indonesia's largest oil and gas developments, situated on and offshore East Kalimantan in the Mahakam Delta. The complex comprises seven main producing fields: Handil, Bekapai, Tambora, Nubi, Tunu, Sisi and Peciko. Production from these fields is supplemented by production from the unitised Badak and Nilam fields.

The Nubi and Sisi fields were the most recent to be developed and were brought onstream in 2007 and 2008 respectively. The next new field start-ups will be Stupa, West Stupa and East Mandu in the South Mahakam area, with first production expected in early-2013. The Jempang and Metulang fields are expected to follow around 2015/16.

Oil production from the PSC is piped to the Senipah terminal, where it is exported via a Single Point Mooring (SPM) system and shuttle tankers. The vast majority of the PSC's gas production is piped to the Bontang LNG plant.

Production in 2012 is forecast to be around 1,800 mmcfd of gas, 66,000 b/d of oil/condensate, plus small volumes of LPG.

Key Issues

The current PSC licence expires in 2017. Negotiations to extend this are underway, with the Government of Indonesia seeking to gain an enhanced profit split, and state-owned PERTAMINA seeking equity in the project. These factors have slowed the approval of the licence renewal.

LNG contracts with the Japanese Western Buyers group totaling 12 mmtpa expired at the end of 2010/early-2011. Total, PERTAMINA and INPEX signed a Heads of Agreement (which were subsequently converted into GSPAs) with these buyers in February 2009, which set out the principal terms for a total of 25 million tonnes of LNG to be delivered to Japan between 2011 and 2020 from the Bontang LNG plant. The feedgas will come entirely from the Offshore Mahakam PSC.

Since 2005, the Bontang LNG plant has experienced a shortfall in supply from other mature gas assets in East Kalimantan. As a result, the Offshore Mahakam PSC has been producing above its contracted rate to compensate, and is expected to continue to do so going forward. The operator has indicated that despite investing heavily in drilling and additional phases of development at existing fields, plus bringing onstream new fields, supply is expected to decline rapidly going forward.

At present there is no formal domestic market obligation (DMO) imposed on gas produced from the Offshore Mahakam PSC, although it does supply around 325 mmcfd to the local East Kalimantan market. Post-licence renewal, it is expected that a DMO will be imposed on gas production, at levels of up to 25% of output. Supply will go to the Kalimantan market and also to a new-build regasification terminal in Java. The first LNG cargoes from the Bontang plant were supplied into the Jakarta Bay regasification terminal in Java in early-2012, with the feedgas for this coming from the Offshore Mahakam PSC.

The global economic downturn of 2008/2009 caused decreased demand for Bontang LNG and some cargoes were cancelled. Decreased LNG demand from Bontang was partly mitigated by the re-starting of LPG production from Bontang and increased supply into the East Kalimantan domestic market.

A large proportion of capital expenditure is spent on development drilling projects using swamp barges and shallow-water jack-ups. Lower rig rates in recent times have allowed some cost savings across the PSC, however annual investment of around US$2 billion is required to minimise production decline across the PSC.



Location Maps

Index Map

MALAYSIA

KalimantanINDONESIA

BRUNEI

MALAYSIA

Sabah

Sarawak

120°E

120°E

118°E

118°E

116°E

116°E

114°E

114°E

112°E

112°E

110°E

110°E

6°N

6°N

4°N

4°N

2°N

2°N

0° 0°

2°S

2°S

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4°S

0 200 400100km




Offshore Mahakam Map A

Samarinda

Pertamina

Energi MegaPersada

a EP

Chevron

Tota

l

KrisEnergy

Monnet Ispat Energy

Total

VICO

KuteiEtam Petroleum

PetroChina

Total

Sanga

Mahakam Hilir

Sanga Sanga

East Kalimantan(Balikpapan)

Tengah


Kutai

na-Kalimantan

OffshoreMahakam

BM)

Offs

hore

Mah

akam

Semberah TACMelak-Mendung III(CBM)

Sei Nangka-Senipah

PELARANGSOUTH

BINANGAT

PAMAGUAN

LAMPAKE

SAPI

HANDIL

SAMBUTAN

TAMBORA

SISI

PELARANG

PECIKO

NILAM

SEMBERAH(SHALLOW)

NUBI

NANGKA(ceased)

KARANGMUMUS

BADAK

TUNU

SAMBOJA

MUTIARA

SANGA SANGA

BEKAPAI

planne

2 x 26"

oil20" o il from Handil12" cond. from Tambora/Tunu

24",32"multi-phase

oil

12" cond.

10" o il

planned gas

gas

36" gas

42" t

o Bon

tang

8" to

Han

dil

12" gas

42" P planned co

cond

. to

Han

dil:

Tunu

10"

Ta

mbo

ra 1

2"

30" gas

12" oil/gas

32" gas

Saka Kanan-1

Bambangan-1

NagaSelatan-1

N.Mumus-1

1,2SX,3,4

Samuel-1

N-1

NW P-16

1

5

W.Nilam-2

West Bekapai-1

Berani-1

Terumbu-1(RD)

Tunu-1

Boengaloen-1

Pitis-1 1

W-1 4

Dambus-1/ST1

Sungei Nangka-1

Punan-1

17,18

Mutiara-1Nonny-I

W.Louise-1

Peciko West-3

1

Peciko West-2

4

3

1

NW Peciko-15

NW P-A

SSB-1

Panjilatan-137 27

X1

1,2

4

2

8

Lantang-1

Semayang-1

Sisi GN

2

Lamin C

H-3

Oeloekarangmoemoes-1

1

121

NW Peciko-14

44SSD-1

Lapang-A1

32

East Bekapai-1

Parangat-1

3

Harapan-1

Mangko

1

Nonny-1

1

N 2

Anggana-1(1920)

9

1

Tunu GS-2

Tambora Utara-1

Lereng-3

OM C-1

Kalong-1

4

West Nubi-1A

2

Moera Kaeli-1

2,2a,2b

Attaka South-1/1RD

Santan West-1

1

8

Dian North-1

1

Raden1

CBM-KW -02

1

NagaUtara-1/1ST

W-1

Pelerang-1,6

11

Kembang-1A

8

17

10

1

1

TunuGS-1

Kelambu-1

1

Lereng-2

Beruang-1

7

Marangkayu-4

Sisi-7

N.Sisi -1

Rasamala-1


1

13

Cadik-1

1

12

Attaka Deep-1

Tunu-N1

39ST

5

Tanjung Bayor-1

1,3

8

1

Pan

Loa Haur-1

1,3

19

1

1,4,6,8

Tempayan-1

4

1

Bivak-A5,A7

Moeara-1

2

4

1

W. Nilam-11

7

X2

1

Moera Kaeli-5

Marangkayu-1

6

1

H-2

Djambutan Bengkok-1

H-1

Bulu-1

V-1

Peciko West-1

812

6

East Semberah-1

2

NWPeciko-18

Kanci l-1

Moera Kaeli-3

3

Moera Kaeli-2

5

3

Pancur-1

Tamor

Benawa

Kerbau

Ragat

Mandau

Lereng

Modang

Lamaru

Anggana

Terentang

Dian

Pemerung

G

Tunu South

Jangkrik NE

SBM

proposedGas Plant

SangattaTerminal

SenipahTerminal

Tanjung BatuCCGT

CPU

A11

117°45'E

117°45'E

117°30'E

117°30'E

117°15'E

117°15'E

117°E

117°E

0°1

5'S

0°1

5'S

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Offshore Mahakam Map B

VICO

Total

Hess

Benuo Taka

KrisEnergy

Total

Chevron

Pertamina EP

Pandawa Prima Lestari

Chevron

VICO

Makassar

Sanga Sanga(CBM) Sanga Sanga

Offshore Mahakam

East Kalimantan(Balikpapan)

Wain

South East Mahakam


Kutai

South Sesulu

Wailawi

BANGKIRAI (Ceased)

EAST MANDU

WESTSTUPA

SEMANLU (ceased)

SETURIAN

SEGUNISEDANDANG

SAPI

HANDIL

(ceased)

WAILAWI

PANTAIYAKIN

PE

SEDJADI

SEPINGGAN

MAHONI

STUPA

(ceased)

SAMBOJA

MUTIARA

2 x 26"

oil

20" o il from Handil12" cond. from Tambora/Tunu

from

Rub

y

24",32"multi-phase

Tanjung to Balikpapan

plan

ned

gas

gas

plan

ned

gas

42" t

o Bon

tang

8" to

Han

dil

12" gas

oil pipeline

Riko-1

Petung-1 S-1

Balikpapan-36

1

C-1

Terusan-1

Tunan Utara-1

2

Subur-1

1

Saka Kanan-1

Bambangan-1

1,2SX,3,4

Trekulu-1

NW P-16

5

West Be

West Sesulu-1Sepoi-1

1

3

Semanlu-1

Mahoni-1 ,2 , West-1

Metulang-2

Punan-1

Peciko West-3Peciko West-2 3

Bangau-1

NW Peciko-

NW P

Susulu-1

Gaharu-1

Yakin S-1,2Petung-2

W-1

Semoi-1

B.South-1,2

1

2

Maruat-1

Mandu-1

Gempur-1

Lamin C

H-3

121

NW Peciko-14

Sanggur-1

1

1

Nenang-1,2

Mentawir -1

Ratu-1RajahR-1

Pangeran-1

Gunung Bakarang-1

1

1

Telakai -1

NW Apar-1

1

9

Pondok Mariam-1

H-1

1

N-1

Bungur Shallow-1 2

East-1

1

Raden1

Bongkaran-1

Bangsal-1

Stalkuda-1

Sepatu Kuda-1

W-1

11

8

17

10

Pegah-1

TunuGS-1

1

Bangkerak A-1

S. Karamba-1

Ul in-1

Sepunang-1

Menang-1

1

Tunan Selatan-1

1

Tanjung Bayor-1

3 2

East Manpatu-1


13

Wailawi -1

2 1

Bungur-1

Klandasan-1

1

Loa Haur-1

1,3

Setuhuk-1/ST, 2

5

4

Jempang-1

Tempayan-1

4

1

7

Penajam-1

Karang-1

Labangka-1

Balang-1

1

1

1

1

H-2

Djambutan Bengkok-1

H-1

Bulu-1

Apar-1

Peciko West-1

Manggar-1

6

Teriti-1

2

Marindan-1

NWPeciko

Janu

Benawa

Metulang/Jempang

Tengah

Jumelai

Tengin

S. Wailawi

West Mandu

Perintis

Lamaru

Sesumpu

Tunu South

SBM

proposedGas Plant

BalikpapanOil Refinery

SenipahTerminal

117°15'E

117°15'E

117°E

117°E

116°45'E

116°45'E

116°30'E

116°30'E

1°S

1°S

1°1

5'S

1°1

5'S

1°30

'S

1°30

'S

1°4

5'S

1°4

5'S

0 10 20km




Participation

The Offshore Mahakam PSC was originally awarded to Japex Indonesia (now INPEX Corporation) in March 1967, covering an area of 16,870 km2. In September 1970, Total farmed into the block and gained a 50% interest plus operatorship.

The original PSC was due to expire in 1997. However, the joint venture was awarded a 20-year extension to the original contract in January 1991 for which a signature bonus of US$15 million was paid. In 1996 the expiry date was realigned to end on 31 December 2017 to match LNG sales contracts to Taiwan and Korea.

It is understood that the partners have been seeking a further extension to the PSC for some years. Negotiations are ongoing, but there is significant uncertainty regarding the terms under which the licence may be renewed. A major stumbling block appears to be PERTAMINA's desire for equity in the block. It has been reported that PERTAMINA will obtain up to a 25% interest in the PSC in the near future.

Participation

Company (%) INPEX Corporation 50.00 Total 50.00 * Total 100.00 Source: Wood Mackenzie * Operator

Unitisation

In June 1977, it was announced that part of VICO's Badak field on the Sanga Sanga PSC extended offshore into the Offshore Mahakam PSC. An agreement was signed with effect from 1 January 1976, unitising the field between the two PSCs. Under the agreement 2.10% of Badak's gas and condensate reserves were assigned to Offshore Mahakam. Sanga Sanga's oil reserves in Badak were not affected by the unitisation.

In December 1982, the Sanga Sanga participants entered into a similar unitisation agreement with Offshore Mahakam for the unitisation of Nilam production. Under the agreement, 21.16% of Nilam's oil production and 18.56% of Nilam's gas/condensate production were assigned to the Offshore Mahakam PSC.

The Sisi and Nubi fields straddle the border of the Offshore Mahakam PSC and the Tengah JOA. Effective 1 January 1997, the fields were unitised between the two blocks. Under the updated unitisation agreement, 92.37% of the fields have been assigned to the Offshore Mahakam PSC, with the remainder in the Tengah JOA. Participants in the Tengah JOA are Total (22.5% and operator), INPEX Corporation (22.5%) and Pertamina (55%). The licence was awarded in 1988 and is due to expire in 2018. No production has been assigned to the Tengah PSC in this model.

It has been indicated that a small part of the Peciko gas field may extend into the East Kalimantan PSC. Unitisation discussions are believed to have been initiated. However, going forward, our model has assumed that the Peciko field lies wholly within the Offshore Mahakam PSC.



Well Data Well Name Operator Spudded TMD(m) Result Discovery Field Comment Type Completed WD(m) Bekapai-1 01-Mar-72 3461 +Exploration

Total 24-Apr-72 34

Oil Bekapai Tested oil at a combined rate of 3,773 b/d with 3.4 mmcfd of gas.

Tambora-1 09-Dec-73 3777 +Exploration

Total 15-Jan-74 5

Gas/Condensate Tambora Tested gas at a combined rate of 26.8 mmcfd with 621 b/d of condensate.

Handil-1 15-Feb-74 2947 +Exploration

Total 25-Mar-74 6

Oil & Gas Handil Tested oil at a combined rate of 10,440 b/d.

Jumelai-1 04-Dec-74 3018 *Exploration

Total 22-Jan-75 93

Gas/Condensate Jumelai

Jumelai-2 20-Jun-75 3000 Exploration

Total 26-Aug-75 50

Dry Hole

Tunu-1 01-Nov-77 3350 +Exploration

Total 09-Dec-77 4

Gas/Condensate Tunu Tested gas at a combined rate of nine mmcfd plus some condensate from 2 DSTs.

Peciko-1 27-Sep-82 4250 Exploration

Total 18-Apr-83 50

Gas/Condensate

Sisi-1 21-May-86 3874 +Exploration

Total 03-Sep-86 80

Oil & Gas Sisi

Semanlu-1 07-May-90 3873 +Exploration

Total 30-Jul-90 47

Oil & Gas Semanlu Tested 8,888 b/d of oil and 15 mmcfd of gas from a number of stacked reservoirs.

01-Jan 26-Dec-91 3575 *Exploration

Total 25-Feb-92 45

Oil Janu Tested 37° API oil at around 2,600 b/d and gas at 1 mmcfd.

Kura Kura-1 29-Feb-92 942 Exploration

Total 11-Mar-92 37

Dry Hole

Nubi-1 14-Oct-92 3535 +Exploration

Total 15-Dec-92 67

Gas/Condensate Nubi Tested gas at 50 mmcfd, oil at 1,500 b/d & condensate at 1,100 b/d.

Lereng-1 04-Jan-93 4100 *Exploration

Total 03-Apr-93 2

Gas Lereng Tested gas at a rate of 32.3 mmcfd with 524 b/d of condensate.

Tunu-N1 05-Feb-94 4352 Appraisal

Total 29-Mar-94 2

Gas

Stupa-1 15-Mar-96 3755 +Exploration

Total 25-Jul-96 60

Gas/Condensate Stupa DST 1 tested between 3,616-3,632m and flowed 15 mmcfd of gas and 1,000 b/d of condensate through 32/64-inch choke. DST 2 tested between 3,460-3,470m and flowed 13 mmcfd of gas and 1,560 b/d of condensate through 32/64-inch choke.

North Sisi-1 21-Oct-96 4356 Appraisal

Total 04-Jan-97 70

Gas

Nubi-X1 06-Jan-97 3684 Appraisal

Total 02-Feb-97 61

Gas

Nubi-X2 03-Sep-97 4531 Appraisal

Total 21-Oct-97 60

Gas

Stupa-2 25-Oct-97 3800 Appraisal

Total 11-Feb-98 55

Gas/Condensate Flowed a total of 49.5 mmcfd of gas and 4,520 b/d of condensate from three DSTs.

Jempang-1 14-Feb-98 4330 +Exploration

Total 05-Apr-98 44

Gas Jempang

Metulang-1 07-Apr-98 4415 +Exploration

Total 20-Jun-98 44

Gas Metulang

Jumelai-3 07-Aug-98 2758 Appraisal

Total 26-Aug-98 50

Gas

Stupa-4 28-Aug-98 3477 Appraisal

Total 30-Sep-98 60

Gas Well intersected 16 metres of net gas pay and one metre of net oil pay.

Stupa-5 02-Oct-98 3750 Appraisal

Total 13-Nov-98 55

Gas



Metulang-2/ST-2 15-Nov-98 3984 Appraisal

Total 14-Jan-99 45

Oil & Gas

Mangkok-1/ST4 18-Apr-01 3929 Exploration

TotalFinaElf 20-Jul-01 87

Gas Shows Mud loss problems encountered in three of the four sidetracks.

Pancur-1 09-Aug-01 3842 Exploration

TotalFinaElf 24-Sep-01 48

Dry Hole

NW Peciko-18 23-Sep-02 3936 Appraisal

TotalFinaElf 10-Dec-02 34

Tight Hole No details released.

Berani-1 24-Mar-06 1829 Exploration

Total 12-Apr-06 43

Dry Hole

Tunu Great South-1 29-Jun-06 4725 *Exploration

Total 27-Aug-06 2

Gas Tunu Great South The well was drilled eight kilometers southwest of the southernmost platform in the Tunu field, and encountered a number of gas reservoirs.

Sisi Great North-1 05-Aug-06 3744 Exploration

Total 10-Sep-06 55

Gas Shows

Sisi-8 02-Nov-06 3280 Appraisal

Total 01-Dec-06 67

Gas

Lapang-A1 12-Nov-06 Exploration

Total 15-Feb-07 2

Tight Hole

East Mandu-1 28-May-07 3719 +Exploration

Total 20-Sep-07 53

Gas East Mandu The well encountered 164 metres of gas-bearing sandstones. The drilling of the well East Mandu-1 was particularly sensitive regarding the control of pressures and fluids.

West Stupa-1 21-Jun-07 3916 +Exploration

Total 14-Sep-07 62

Gas West Stupa The well encountered 72 metres of gas-bearing sandstones.

Tunu Great South-2 20-Mar-08 5374 Appraisal

Total 06-Jun-08 2

Gas The well logged 36 metres of gas pay.

East Bekapai-1 18-Aug-08 3721 Appraisal

Total 25-Sep-08 29

Gas

West Mandu-1 29-Jul-11 *Exploration

Total 25-Dec-11 45

Oil & Gas West Mandu


Exploration

Commitments

The Offshore Mahakam PSC originally awarded to Japex Indonesia covered an area of 16,870 km2. Several acreage relinquishments have been made, including a relinquishment of 800 km2 having been approved in December 2000, and a further relinquishment was made in January 2006. We understand rmore recent relinquishments have resulted in the block now covering an area of around 2,800 km2.

The original PSC was due to expire in 1997. However, the joint venture was awarded a 20-year extension to the original contract in January 1991 for which a signature bonus of US$15 million was paid. The PSC is now due to expire at the end of December 2017. The relinquishment schedule for the PSC was a key issue in the extension negotiations. Under the terms of the extension the group was committed to spend at least US$63 million on exploration activities on the block over a seven-year period retroactive to January 1990. This commitment has been fulfilled.

Exploration Activity

Early Years Exploration on the Offshore Mahakam PSC began in 1969 when Japex drilled OM C-1. However, it was not until Total farmed into the block that exploration began in earnest. The first commercial discovery on the block, the Bekapai field, was made in 1972. This was followed by Handil and Tambora in 1974, Jumelai in 1975, Tunu in 1982, Sisi in 1986, Semanlu in 1990, Peciko in 1991 and Nubi in 1992.



Sisi Geologically, the fields in the PSC exhibit both structural and stratigraphic trapping. The fields are highly complex, with multi-layered, stacked reservoirs. The main hydrocarbon source in the area are coals and organic shales from deltaic plain and delta front and discoveries tend to contain more gas towards the east. The area is known to have over pressured shallow gas accumulations. This was most apparent during the drilling of Sisi-2. The well, which was spudded in September 1988, blew out sinking the Viking Explorer drillship. Following the blow-out, Total suspended operations to re-evaluate drilling options on the field.

In 1989, appraisal of the discovery re-started with the drilling of Sisi-2B and a further three appraisal wells. All four appraisals successfully encountered gas and condensate, with the first - Sisi-2B - also encountering some oil. Further appraisal of the field began in late-1995, when two wells were spudded. A third well - North Sisi-1 - was completed in January 1997. All three appraisal wells were successful.

Peciko The focus of the joint venture's exploration effort moved to the Peciko field discovered in April 1991. The discovery well was abandoned after testing gas at a high cumulative rate with condensate. Encouraged by the NW Peciko-1 test result, Total returned in July 1991 to drill a multi-well programme on the field. To the end of 1994, a total of 15 appraisal wells had been completed on the field. All encountered gas and condensate. Drilling resumed in February 1997, with NW Peciko-16 and 17 encountering gas, and another well, NW Peciko-18, was drilled in 2002, details of which remain tight.

Nubi The Nubi gas and condensate discovery was made in 1992. Two appraisals of the field were undertaken in 1993 with a further two in 1994. In November 1994, a step-out appraisal on the Nubi structure was completed on the neighbouring Tengah JOA, also operated by Total. West Nubi-1A was suspended after testing gas, condensate and oil. Two appraisals were drilled on Nubi in 1995/6, with a further two in 1997. All four encountered gas or gas and condensate.

Stupa In July 1996, Stupa-1 tested good rates of gas and condensate from Mid-Miocene sands and carbonates, in the central portion of the Offshore Mahakam Block. An appraisal followed in October 1997, which flowed gas and liquids from three DSTs. Further appraisal was undertaken in 1998, when four wells were completed, all encountering either gas or gas and condensate.

Jempang and Metulang Additional discoveries followed in 1998 when, in April and June respectively, Jempang-1 and Metulang-1 were suspended having encountered hydrocarbons. Other exploration activity in 1998 included appraisals on the Jumelai and Tunu fields. An appraisal of Metulang was suspended in January 1999, having encountered oil and gas. The Jempang and Metulang fields are expected to be developed as part of an additional phase of the South Mahakam project, with additional evaluation work required on Jumelai before this could be developed.

1999-2005 Exploration activity in 1999 also included two appraisals on the Tunu field and the acquisition of 3D seismic data over the Kerbau and NE Badak areas. No wells were drilled in 2000. Drilling restarted in 2001, when two exploration wells were drilled to explore the eastern fringe of the Offshore Mahakam PSC. The first, Mangkok-1, was drilled on the border of the Saliki PSC. Four sidetracks were completed, however mud losses were encountered in the first three of the four. Only shows of gas were encountered. In 2001, a 318 line kilometre 2D seismic survey east of Tunu was completed in June 2001. In August 2001, the second wildcat, Pancur-1, which was drilled to test a prospect to the east of Tunu, was spudded. The well was completed in September 2001, however no details have been released.

No wells were drilled in 2003, however a 3D seismic survey was shot over the Sisi and Nubi fields. The survey was completed at the end of 2003 and processing and interpretation began in 2004. The survey was acquired mainly to assist with positioning of infrastructure for the development of Sisi and Nubi.

2006 onwards Exploration drilling increased in 2006, with five wells spudded. The most significant well was the Tunu South-1 well, completed as a gas discovery in August. The well was drilled eight kilometres to the south of the southernmost platform in the Tunu field and encountered a number of gas reservoirs.

In March 2006, the Berani-1 well, the first exploration well to be drilled on the Offshore Mahakam PSC in three years, was completed as a dry hole.

The Sisi field was also the focus of drilling activity in 2006, with one appraisal well successfully testing gas in the northeast of the field. A well to test the northern extension of the field encountered only non-commercial quantities of gas.



Three wells were completed in 2007. Details on Lapang-A1 were not released. The West Stupa-1 and East Mandu-1 wells both encountered gas and given the proximity to existing infrastructure are expected to begin production in 2013. During 2008, a second well was drilled in the Tunu South structure, which logged 36 metres of gas pay. A successful appraisal well on the Bekapai oil and gas field found gas in an eastern section of the structure.

No exploration wells were drilled in 2009 or 2010. Two sets of seismic was acquired across the Tunu field and a further survey was shot across the Handil field in 2011. The West Mandu oil field was discovered in 2011. The field also contains small amounts of gas, but it is not clear if this discovery is large enough to be developed at the current time.

Wood Mackenzie understands a well is planned on the South Stupa prospect, with other potential step-out targets exisiting on the Tunu and Tambora fields.

Reserves

Oil Oil is produced from the Bekapai, Handil and Nilam fields, with output gravity in the range 35-40° API. Recovery factors for Bekapai and Handil crude are high at around 45%.

Associated condensate yield is 25-30 bbl/mcf. The Bontang Return Condensates (BRC) are much lighter than condensate produced at the wellhead. The API gravity of BRCs are around 71-72°, compared to 52° for condensate produced at the wellhead.

Following gas supply shortfalls to the Bontang liquefaction plant during 2006, sales of LPG ceased for a number years in order to spike these fractions into the sales gas to maintain the requisite btu content of the LNG cargoes. However global economic conditions during 2009 meant that demand for contracted LNG from Bontang's North Asian customers was reduced. As such, the plant operator decided to utilise the spare gas to restart the LPG facility for supply into Indonesia's growing domestic LPG market.

Gas On average, the gas contains between 4-5% inerts, with the gas in the northern reservoirs richer than that in the southern fields. The dry gas supplying the LNG plant has a calorific value of 1,100-1,140 btu/scf.

Wood Mackenzie estimates that as of 01/07/12, around 80% of the feedstock for LNG is supplied from Offshore Mahakam PSC. See Sales Contracts section for more details.

Historically, the Offshore Mahakam PSC has supplied between 10%-12% of total sales gas production to the domestic market in Kalimantan. However, under new contracts and extensions to existing deals, contractors are expected to be obliged to sell 25% of total sales gas production to the domestic market. Wood Mackenzie has assumed that upon contract extension, and dependent upon demand in the domestic market, that the Offshore Mahakam PSC will supply over 25% of its total production to the domestic market from 2013. This is partly due to a total of 750 bcf which will be supplied to the Java market through LNG sales under an HOA, which started in H1 2012.

It is understood that proposed plans for a ninth train at the Bontang plant are no longer being actively pursued following the overall East Kalimantan supply problems. One train remains out of service at present.

Remaining exploration potential is relatively limited at around 1.2 to 3.3 tcf with future reserve additions likely to be a result of small reserve upgrades on existing fields or small additional discoveries of less than 500 bcf each.

The operator has indicated firm plans to develop the Stupa, West Stupa and East Mandu fields as an integrated project, adding a cumulative 550 bcf of sales gas. The Metulang and Jempang fields will also add around 100 bcf each upon their development.

Reserves associated with the Tunu South and Jumelai discoveries require appraisal before they could be considered development candidates.




Init Init Init Init Rem Rem Rem Rem Oil Cond. LPG Gas Oil Cond. LPG Gas (mmbbl) (mmbbl) (mmbbl) (bcf) (mmbbl) (mmbbl) (mmbbl) (bcf)Handil 886 - - 1502 20 - - 88Bekapai 196 - - 420 3 - - 49Tambora 1 38 - 1553 0 7 - 142Tunu - 289 - 7345 - 89 - 1764Peciko - 73 - 5656 - 19 - 1199Nubi - 15 - 806 - 10 - 502Sisi - 12 - 606 - 9 - 369Badak (gc) Off. Mahakam - 2 - 88 - 0 - 3Nilam (gc) Off. Mahakam - 20 - 838 - 1 - 49Nilam (o) Off. Mahakam 7 - - - 0 - - -Stupa - 8 - 220 - 8 - 220East Mandu - 5 - 165 - 5 - 165West Stupa - 5 - 165 - 5 - 165Jempang - - - 100 - - - 100Metulang - - - 100 - - - 100Others 13 74 115 - 0 - 19 0Total 1103 541 115 19564 23 153 19 4915Source: Wood Mackenzie LPG is barrels of oil equivalent, based on a conversion of 0.77 boe/bbl LPG.

Production

Liquids

Only Handil, Bekapai and Nilam currently produce crude oil. Condensate accounts for all the liquids production from the other fields. Enhanced oil recovery methods combined with development drilling programmes produced a rebound in liquids output during 2008 and 2009, however, overall oil and condensate production fell in 2011 to 75,000 b/d and is expected to continue its dceline going forward.

Bekapai Field Oil production from the Offshore Mahakam PSC began from a single well on the Bekapai field in July 1974 at an initial rate of 2,000 b/d. Production increased to 30,000 b/d when the Bekapai A platform came into operation in 1975 and rose still further when two new platforms, Bekapai B and C, were installed in 1976 and 1977. However, in 1984 Bekapai production fell due to a blow-out on one of the platforms. Three new platforms were installed in 1985, although these did not compensate for the drop in production. Production from the field has been in a long decline for several years, though has recently been maintained at around 2,000 b/d following the intersection of a oil-bearing interval whilst drilling gas development wells.

Handil Field Oil production from Handil started in July 1975, at an initial rate of around 17,700 b/d from a temporary installation and four wells. Full-scale production started in 1976 at 40,000 b/d, and reached a peak of 194,000 b/d in 1977. Overall production from Handil declined until 2004, when the decision was taken to increase recovery efforts on the field. This reversed the decline and an average 20,500 b/d was achieved in 2009, but we estimate this fell to 14,000 b/d in 2011 and we assume the rate will decline steeply going forward.

Nilam Field While the Nilam field had been in production under the Sanga Sanga PSC since 1977, the field was not unitised with the Offshore Mahakam PSC until December 1982. Consequently, since 1982, the field has been contributing to the total oil production from the Offshore Mahakam PSC.

Tambora and Tunu Fields The Tambora field came onstream in December 1984. Although oil production ceased in 1991, gas and condensate production continues. Condensate production from Tunu began in August 1990, and is estimated to have averaged around 37,000 b/d during 2011, with Tambora producing 2,250 b/d.



Semanlu Field The small Semanlu oil field was brought onstream in April 1991. However, water encroachment persuaded Total to cease production from the field 10 months after start-up. During its brief producing life, Semanlu yielded 194,000 barrels of oil.

Peciko Field Liquids production from the Peciko gas/condensate field began in December 1999, averaging around 9,000 b/d for 2000. It is estimated that the field will produce around 8,800 b/d in 2012.

Bontang Return Condensate In addition to condensate produced at the wellhead, liquids known as the Bontang Return Condensate (BRC), are also produced during gas processing at the Bontang LNG plant.

Gas

Historic production Gas sales started in May 1982. The PSC currently supplies gas to the Bontang LNG plant and the domestic market. Prior to this gas was either flared or vented. The Handil, Bekapai, Tambora, Tunu, Peciko, Sisi and Nubi fields are currently onstream with Tunu and Peciko producing the majority of the gas. The Peciko field came onstream in December 1999 and by April 2000 was producing around 800 mmcfd, acting as a swing producer for the PSC.

In 1998, as a result of the Asian economic crisis, certain LNG customers were unable to take all their contracted volumes. Accordingly, sales gas production was 5% down on forecast offtake. An agreement was reached to supply the cancelled quantities, plus additional compensation volumes, between 2000 and 2007. Given the current supply problems at the Bontang LNG plant, we have assumed that this agreement is no longer valid.

Production was disrupted in March 2002, after a blowout in the Tunu E5 development well. Seven wells were shut in as a result of the blowout and combined output losses are understood to have been around 130 mmcfd of gas (5% of production) until the wells were brought back onstream in April. However, Wood Mackenzie understands that supply to the Bontang LNG plant was not disrupted and that there was no export revenue loss.

Since 2005, the Bontang LNG plant has been experiencing a shortfall in supply from some of the offshore East Kalimantan gas fields. As a result of the rapid decline at the VICO-operated fields, as well as the delay in the start-up of some of the Chevron-operated fields, the Offshore Mahakam PSC has been producing above contracted volumes in order to make up for the shortfall in supply to the plant. During 2006, the Offshore Mahakam PSC group of fields supplied around 80% of the total gas supply volume to the plant and over 78% again in 2007, and approximately 81% in 2008 (for more details see Sales Contract section).

Current production Wood Mackenzie understands the Offshore Mahakam PSC contributed around 82-83% of feedgas to the Bontang facility in 2011, and we have assumed that the contribution from the Offshore Mahakam PSC will be in excess of 75% through until 2017-2019, after which it begins to decline and production from Chevron's deepwater fields and the Eni-operated Muara Bakau project ramps up.

Further phases of development are ongoing on Tunu and Peciko, to maintain and boost production levels. In addition, development of the Sisi and Nubi fields was completed in 2008. Nubi commenced production in November 2007, followed by Sisi in late-2008. Maintenance in mid-2011 impacted output, with combined production from Sisi, Nubi and Tunu falling by around 500 mmcfd.

A combined development of the Stupa, West Stupa and East Mandu gas fields is planned to come onstream in early-2013. This will be followed by the Metulang and Jempang fields, likely to be brought onstream in 2016 via a tie-back to the East Mandu platform.

Wood Mackenzie understands that production will be maintained above 1,500 mmcfd until 2014, at which point ouptut will fall as mature fields enter a steeper decline phase.

Domestic production Historically, the Offshore Mahakam PSC has supplied between 10%-12% of total sales gas production to the domestic market in Kalimantan. However, under newer contracts and extensions to existing contracts, contractors are expected to be obliged to sell 25% of total sales gas production to the domestic market. There is still some uncertainty over how gas domestic market obligation will be determined. We have assumed that upon contract extension, and dependent upon demand in the domestic market, that the Offshore Mahakam PSC will supply around 25% of its total production to the domestic market from 2016.



The first commissioning LNG cargoes were sent to the FSRU terminal offshore Jakarta, Java, in early-2012. This was the first cargo under the HOA to supply 11.75 million tonnes of LNG to Java from the Bontang LNG plant.

The Bontang LNG plant suppliers have also entered into a swap agreement with ExxonMobil in North Sumatra whereby the Bontang LNG plant will provide three cargoes of LNG to PT Arun's buyers, allowing it to supply three cargoes equivalent of gas to the fertiliser plants. The shortfall in production from the existing North Sumatran gas fields resulted in the shutdown of the fertiliser plants in 2005. The swap agreement is expected to be sufficient to run the plants for six months of the year. This agreement is commercially neutral for both Arun and Bontang and has not been modelled in the following production profile.

LPG Wood Mackenzie understands that from the start of 2006, LPG sales ceased at the Bontang LNG plant. This allowed the LPG to be spiked into the LNG in order to supply a higher number of cargoes and help alleviate the shortfall in the current contracted volumes. However global economic conditions during 2009 meant that demand for contracted LNG from Bontang's North Asian customers was reduced. As such, the plant operator decided to utilise the spare gas to restart the LPG facility for supply into Indonesia's growing domestic LPG market. We have modelled this as a medium-term event that between 2009 and 2015.

The production profile shown in the following tables is based on gas sales under Packages I-VII plus contracted sales under additional rollover packages to the Western Buyers consortium, and sales to the spot market. It also includes gas which is currently being supplied in excess of contracted volumes to make up for shortfall from other PSCs. Wood Mackenzie understands that new contracts have been signed to maintain supply to the Bontang plant post-2010 and that from early-2012, LNG has been supplied to the domestic market in Java. Given the current uncertainty over contract extensions and the volume of gas required to be supplied from the Offshore Mahakam PSC as part of the anticipated domestic market gas obligation, the split of production according to contract should be treated as indicative only.




2002 2003 2004 2005 2006 2007 2008 2009 2010 2011Oil ('000 b/d) Oil ('000 b/d) 16 16 16 17 20 21 22 23 19 16Condensate ('000 b/d) Condensate ('000 b/d) 53 57 60 63 55 67 72 74 68 59LPG ('000 b/d) LPG ('000 b/d) 16 16 16 16 16 - - 11 11 16Total Liquid ('000 b/d) 85 89 92 96 91 88 94 108 98 91 Sales Gas (mmcfd) Original LNG (mmcfd) 1871 1943 2060 2294 2455 2255 2268 2113 2000 -Rollovers and spot (mmcfd) 50 75 80 120 135 125 111 85 80 1838Domestic LNG (mmcfd) - - - - - - - - - -Local gas (mmcfd) 190 323 261 290 240 251 234 336 336 325Total Sales Gas (mmcfd) 2111 2341 2401 2704 2830 2631 2613 2534 2416 2163Source: Wood Mackenzie Production (2012-2021)

2012 2013 2014 2015 2016 2017 2018 2019 2020 2021Oil ('000 b/d) Oil ('000 b/d) 14 12 10 8 6 5 4 3 2 1Condensate ('000 b/d) Condensate ('000 b/d) 53 52 50 46 41 38 32 26 21 16LPG ('000 b/d) LPG ('000 b/d) 15 13 12 11 - - - - - -Total Liquid ('000 b/d) 82 78 72 64 47 42 35 29 23 17 Sales Gas (mmcfd) Original LNG (mmcfd) - - - - - - - - - -Rollovers and spot (mmcfd) 1475 1215 1094 988 873 771 611 484 384 263Domestic LNG (mmcfd) 46 188 188 188 188 188 188 188 188 188Local gas (mmcfd) 310 300 285 270 255 240 220 190 160 115Total Sales Gas (mmcfd) 1831 1703 1567 1446 1316 1199 1019 862 732 566Source: Wood Mackenzie Please note that LPG is produced from gas sales to the Bontang facility, and as such, the sales gas figures shown above are net of gas used to produce LPG.



Production Profile

Development

The development of the Offshore Mahakam PSC began in 1973 with the Bekapai field, with the initial focus concentrated on producing oil. However, in 1981, work began on trying to harness the associated gas which was being flared. The development scheme to utilise gas production from the area was known as the Handil-Bekapai Gas Conservation and Utilisation Scheme. The scheme began in May 1982 when the first gas sales were made to the LNG plant at Bontang. Total gas processing capacity is now around 3,400 mmcfd.

Many contracts awarded by Total for work on the Offshore Mahakam PSC are classified as EPSC contracts. These are similar to standard EPIC contracts, however a site survey aspect is usually included in the scope of work. This is due to the swampy nature of the area covered by much of the block, which requires extensive site survey work prior to installation. The nature of the environment also limits the number of contractors with the capabilities required to work in the area.

Extensive development drilling work is ongoing across the contract area to maintain production levels. Around 110 wells were drilled in 2006, 115 in 2007 and at least 85 in 2008 and 2009, with a similar number assumed for 2010. Activity rose to a record level in 2011, with 128 wells drilled. We expect around 100 wells will be drilled each year between 2012 and 2014. Over 6,000 well actions - such as re-perforations and well workovers - are conducted annually by the operator.

A more detailed description of individual field developments is given below. Details of the development of the unitised Badak and Nilam fields can be found in the Sanga Sanga analysis.

Bekapai

The initial development used temporary floating installations, with the crude being transported by barge to the Balikpapan refinery. Work proceeded quickly on permanent facilities and a new platform came into operation in July 1975, a year after start-up.

The development is now centred on a three-platform central facility, which comprises a four-pile accommodation platform (BQ), a four-pile production platform (BP) and a 12-slot wellhead platform (BA). The platforms are bridge-linked by walkways. In addition, there are two smaller tripods supporting the flare stack and its walkway.

Production from the BA wellhead platform is carried to the adjacent processing platform where initial separation is carried out. The BQ platform provides living accommodation for 50 people.

Two further nine slot wellhead platforms, BB and BC, were installed during 1976 and 1977. In 1984, a blow-out occurred on the BC platform and the platform was lost. In addition, there are seven small tripod production platforms - BE, BF, BG, BH, BJ, BK and BL. These each have between one and three wells.

In 1999, a programme of well workovers began on the field which has helped to maintain oil production levels. Development drilling in 2007 that was targeting gas encountered oil-bearing sands which are now being produced and



raised production levels. Debottlenecking of platform facilities has been proposed, however this has been delayed and it is uncertain whether it will now be carried out. Wood Mackenzie believes that future development work will focus on the recovery of the Bekapai gas, with blowdown of the gas caps anticipated once oil production is no longer economic. We understand three development wells were drilled on the field during 2008 and 2009.

Handil

Production started in July 1975 from four wells and a temporary installation. This included a separation unit located on a barge in the Mahakam River, floating living quarters and a 2.5 kilometre offtake line linked to a river terminal. By December 1976, permanent facilities had been installed on the field. These included a central processing platform (CPP). Currently over 350 wells, including gas and water injectors, are tied back to the processing platform.

Until 1977, a floating crude storage facility was used for both Handil and Bekapai. However, increasing production, combined with the fact that the waters near Handil are not navigable by large tonnage vessels, persuaded Total to build a terminal to the south at Senipah. Most of the Handil gas is recovered at the first separation stage on the processing platform. The crude is then piped to Senipah where the second stage of separation takes place.

In 1982, gas compression equipment, a dehydration unit and a metering station were installed. These have a capacity of around 200 mmcfd.

Currently around 25% of the crude is produced by secondary recovery. Water injection to improve liquids production has been used on a number of reservoirs in the Handil field since 1978. The programme has been successful in slowing the decline in output and will continue.

Gas lift on the Handil field started in 1981 and is widely used. In 1991, a gas lift compressor was installed to facilitate this. An EOR project based on lean gas injection was launched in 1993, beginning in the second half of 1995. It is understood that over 60 mmcfd of gas is currently injected.

In a drive to further increase recovery rates, TotalFinaElf (now Total) implemented an air injection programme on the field in Q1 2001. The air causes oxidation of the oil at high temperatures. The scheme consists of a 3.3 mmcfd reciprocating air compression platform, a 2.5-inch line from CPA to an injector and a well inerting system. It was expected that 0.5 million barrels of incremental oil would be produced over three years.

A workover programme on the field began in 1999 which helped to maintain oil production rates. A campaign of workovers and new development well drilling from 2004 has resulted in an increase in production from the field. It is assumed that such efforts will continue going forward.

Tambora Tambora lies in shallow waters on the northern part of the Mahakam Delta, some 10 kilometres south of Badak/Nilam. Tambora is primarily a gas field, although there is a small oil rim to the north. The field produces from a series of stacked sandstone formations, between 2,500 and 4,300 metres. These formations are classified into four main zones - D, E, F and G. More than half (60%) of the field's proven oil reserves are located in the shallower D zone, while the deeper G horizon contains about a third of the field's total gas reserves.

Tambora has thus far been developed in conjunction with the Tunu field in two phases. The joint Tambora and Tunu development is referred to as Tatun. Phase I of the Tambora development focused on the northern part of the field and involved the installation of two gathering and testing satellites (GTS). These satellites have a combined production capacity of 380 mmcfd. Gas and condensate from various single well platform structures is piped via individual six-inch diameter flow lines to the GTSs. Up to 10 producers can be connected to each GTS. In addition to the two GTSs, Total installed a central processing unit (CPU1, with a capacity of 350 mmcfd) on Tambora during Phase I. The CPU processes gas from Tambora and Tunu. A second CPU (CPU2) was installed under Phase II of the Tunu development (see below).

Phase II of the development incorporated the installation of combined Medium Pressure (MP) compression facilities for Tambora and Tunu South and was undertaken in conjunction with Tunu Phase VII (see below). An extension to Phase II of the Tambora development was commenced in December 2004 when an EPC contract for three new GTSs and four remote wellhead platforms having been awarded to Sembcorp Industries subsidiary PT Sempec. The work was completed in March 2007. The company also carried out modifications to the two existing GTSs. New 24-inch pipelines to link the GTSs and eight-inch flowlines to link the remote wellhead platforms to the GTSs were also completed by Punj Lloyd.

In 2011, it was announced additional work would be carried out on the Tambora field, but it is unclear what this will entail. We expect this will focus on workovers of existing wells and the drilling of a new batch of development wells.



Tunu

Tunu is an asymmetrical, elongated, anticline, with an areal closure of more than 500 km2. The main producing horizons are found between 2,200 and 4,500 metres. The majority of the field's proven gas reserves are located on the structure's crest between 2,500 and 3,650 metres. The reservoirs are of variable qualities, multi-layered, thin and difficult to correlate.

Phases I to III The first phase was completed in December 1989, with first production achieved in August 1990. During Phase I, a single GTS (GTS-A) was installed on the central part of the field. GTS-A has a production capacity of 160 mmcfd. Four production wells were completed on the field followed by a further eight development wells in 1993.

In December 1993, Phase II was implemented with the installation of a second CPU (CPU2, with a 900 mmcfd capacity) alongside CPU1 and four additional GTSs (B, C, D and E). Phase III saw the installation of another two GTSs (F and G) by mid-1994.

Phases IV to VI Phase IV was completed in 1998 and consisted of developing the North Tunu area with a new gas treatment unit, the North Processing Unit (NPU) with a capacity of 900 mmcfd. It also included five GTSs (I, J, L, M and N), a trunkline network between GTSs and NPU and a 26 kilometre, 32-inch export pipeline to the Badak Terminal Receiving Facilities (TRF). The TRF can receive 2,100 mmcfd of gas exported from the CPUs and NPU. A slug catcher and metering system were also installed. A further 14-inch condensate pipeline was also laid to CPUs 1 and 2. Phases V and VI, respectively consisting of five and three GTSs and associated pipelines, followed, with Phase VI completed in December 1999.

Phases VII to IX Phase VII of the Tunu development was undertaken in conjunction with Phase II of development of the Tambora field and incorporated the installation of MP compression facilities including a 4,000 tonne compression platform, a new 36-inch pipeline, two compressor modules, and MP manifolds on seven GTSs, for both Tambora and Tunu South. Installation was completed in 2000. Phase VIII implemented MP gas gathering from several existing GTSs, including the requirement for a new 5,000 tonne MP compression platform, known as the North Compression Platform (NCP), for Tunu North. Installation of the NCP was complete in 2002 and facilities were fully operational in 2003.

Phase IX comprised the installation of three new GTSs and modifications of two existing GTSs together with the laying new trunklines and flowlines to connect the new GTSs to the existing pipeline network. This phase was focused on providing new slots for ongoing drilling.

Phase X A tenth phase of development was undertaken on the Tunu field and is understood to have included the extension of six existing GTSs, including four new platform structures, and subsequent tie-in to the existing facilities. The Plan of Development was submitted to BPMIGAS and bid documents for the Phase X contract were subsequently issued in June 2004. While initial bids were made in 2004, the bidding and award process was delayed and were eventually awarded to PT Kari Raya in January 2006. Installation of the structures was carried out in phases, with the last unit installed in Q1 2007.

Phase XI Tenders for a phase eleven of development at the Tunu field are believed to include an additional five platforms to provide Low Pressure (LP) compression facilities in both North and South Tunu which includes one utility platform, two manifold platforms and two compression platforms as well as tie-in and associated facilities. Awards for the work has been subdivided into separate packages and awarded to a variety of international and Indonesian contractors. Work on this phase was completed in late-2009.

Phase XII In mid-2007 Total began inviting tenders for its twelfth phase of development on Tunu. This comprised one onshore and two offshore GTSs, plus a flare stack and associated pipelines. FEED studies were completed during 2008 and the project comprised 84 wells with 300 metres spacing. The project was carried out over 2010/2011.

Ongoing Development Drilling There are currently four to five swamp rigs continuously active on the Tunu field, concentrating mainly on drilling infill wells with an 800 metre spacing in order to tap into new gas reservoirs. There is also a very high ongoing activity in well servicing to perforate existing wells on as-yet unconnected horizons. Phases XIII and XIV may also may carried out, with Phase XIV requiring compression facilities.



Peciko

The Peciko reservoir is located at depths between 2,100 and 3,900 metres.

Phases I - III Production began in December 1999, when the eighth Bontang LNG train (Train H) came onstream. The development entailed two 12-slot, 400 mmcfd wellhead platforms, 13 gas wells and subsea pipelines to a two-train processing unit at Senipah. Phase II development involved the installation of a third 12-slot wellhead platform and the drilling of nine wells. Installation and drilling was completed in late-2001. This phase increased the ultimate production capacity to 1 bcf/d.

Phase III of the Peciko development increased maximum deliverability to 1.3 bcf/d and average output to 850 mmcfd by 2004. Phase III required work to be carried out both on and offshore, with two separate packages of contracts awarded. The offshore component of the phase included the installation of a fourth 12-slot wellhead platform associated pipeline to the Senipah terminal. Full installation and commissioning were completed by the end of 2002. The onshore component of Phase III required the addition of a third gas treatment train and some upgrading work at the Senipah terminal. This work was completed in early 2004.

Phase IV Phase IV of Peciko development was undertaken to install medium-pressure compression facilities and was split into two packages - the first a back-up pipeline project and the second entailing onshore and offshore infrastructure additions and modifications. The second package included the fabrication and installation of two new satellite wellhead platforms, five inter-platform pipelines and a water disposal pipeline. Offshore modifications, including the retrofitting of manifolds, were also included in the package of work. Onshore work involved in Phase IV comprised the installation of two onshore compression trains. The installation of the two wellhead platforms was completed in July 2004 and installation of the onshore trains was completed in 2005.

Phase V In 2005, a fifth phase of development at the Peciko field was launched and for installation of a new wellhead platform and additional development drilling at the field. The platform construction work was completed during 2008.

Phase VI Total awarded contracts for the sixth phase of development on Peciko in late-2007. These cover two onshore LP compression modules and associated facilities. Work is understood to have been completed in late-2009.

Phase VII Phase VII A was carried out in 2010, and included the drilling of 23 wells, adding up to around 150 mmcfd and 2,600 b/d of production capacity. Phase VII B will require the installation of a nine-slot WHP, which will be capable of producing up to 170 mmcfd of gas. Construction contracts were awarded in early-2012, and the four-legged SWP-J platform is likely to be installed in mid-2013.

Remedial Pipeline Work In addition to the development work associated with Phase IV, in 2003 it was identified that remedial work on the original Peciko pipelines was required. In April 2003, Saipem was awarded a contract to carry out this work. Repairs included the installation of two 24-inch trunklines, one from the SWP-A platform and a second from the SWP-B platform to the Senipah terminal. Wood Mackenzie has assumed that this remedial work was completed in late-2003/early-2004.

Further Development The next phases on development on Peciko are aimed at the upper and very shallow reservoirs, and new wells into these targets will be drilled by adding conductors onto the existing wellhead platforms. Should Phase VIII be sanctioned, it would require the installation of more compression facilities.

Sisi and Nubi

A Plan of Development for a joint development of Sisi and Nubi was approved by BPMIGAS and a phased development has been undertaken.

Phase I Under the scope of Phase I, a total of three wellhead platforms (two on Nubi and one on Sisi), a production separator (slug catcher) platform (which will be located adjacent to existing platform infrastructure on the Tunu field) and 55 kilometres of pipeline has been installed. The wellhead platforms (GTSs) on Nubi has nine slots, while that on Sisi has 15 slots. All installation work was completed in 2007.



Drilling efforts started on Nubi in 2007 and first production was achieved in November of that year. A tender rig mobilised on Sisi in April 2008 and first production from the Sisi facilities was achieved in late-2008.

Phase II A second phase of development of the Sisi and Nubi fields required similar facilities to those contracted under phase I: three wellhead platforms and associated pipelines, and was completed in 2011.

Construction contracts for two tripod platforms for Phase II B were awarded in early-2012. The operator plans to install one 15-slot WHP which will be able to handle 200 mmcfd of gas, and a second WHP, which will have nine slots and be able to process 150 mmcfd. Development drilling under this phase is expected to begin in mid-2013, with up to 24 wells drilled in total.

It is understood that a further two phases of development will be required at the fields, however, there are no firm timescales in place for phases III and IV.

South Mahakam Fields

Phase I

These include Stupa, West Stupa and East Mandu. A contract for the South Mahakam development was awarded to Nippon Steel in mid-2010. The project comprises three identical six-slot minimum facilties platforms on Stupa, East Mandu and West Stupa. The facilities will be able to handle up to 370 mmcfd of gas, which will be transmitted to facilities at the Peciko field through a 24-inch export line. First production from these fields is expected in mid-2013.

Phase II

This will involve the development of the Jempang and Metulang fields, which will be developed using WHPs tied back to the East Mandu facilties. Development is likely to be such that first production is achieved in early-2016.

Other fields Nearby these fields are also the Metulang and Jumelai discoveries, which are still at an early stage in the appraisal process, and development plans have yet to be formulated. It is therefore unlikely that the fields will come onstream before 2015. A potential development scenario is that the fields will be developed as satellites to the Stupa and East Mandu fields using minimum facilities platforms.

Transportation

Bekapai

Bekapai production is transported to the Senipah terminal by a two-phase 12-inch diameter, 40 kilometre long pipeline. The pipeline has a capacity of 15,000 b/d of liquids and 30 mmcfd of gas. The crude is then exported by tanker. Gas from Bekapai is piped through the Senipah terminal to be further compressed at Handil.

Handil

Handil crude is gathered at the CPA and then sent to the Senipah terminal for export. The connection with the Senipah terminal is by means of a 20-inch pipeline, 11 kilometres in length. Until 1982, the associated gas at Handil was flared, but now it is carried via a 20-inch line to Bontang with Bekapai gas.

Tambora and Tunu (Tatun)

Wet gas and condensates from the Tambora and Tunu fields is piped to Tatun CPUs 1 and 2. Treated gas is then transported to Badak through two lines, 20-inch and 32-inch in diameter. A 32-inch gas and 14-inch condensate line also transports gas and condensate from Tunu North to the Badak field. The condensate is sent to Senipah via two lines, 10-inch and 12-inch in diameter.

In 1996, a condensate stabilisation unit (CSU) started up at Senipah with the aim of allowing gas condensates to be marketed separately from Handil crude. A 12-inch line transports condensate from Handil to Senipah. Its capacity is around 45,000 b/d.



Peciko

Gas/condensate from the Peciko field is exported via two 24-inch and 32-inch pipelines to a dedicated processing plant, with three 450 mmcfd trains located at the Senipah terminal, as well as onshore MP compression. Condensate is treated at Senipah. The processing includes separation and chilling, to avoid separation of the condensate and gas until the inlet at Bontang. The gas is exported through a 128 kilometre, 42-inch pipeline to Badak. The pipeline has a capacity of 1,600 mmcfd of gas.

Sisi and Nubi

A seven kilometre, 16-inch pipeline links the two Nubi WHPs. Production is then routed to the Sisi manifold and wellhead platform via a 15 kilometre, 22-inch pipeline and on to the SNPS platform via a 35 kilometre, 26-inch, pipeline. The SNPS platform is located adjacent to existing platform infrastructure on the Tunu field. From SNPS, production is transported to shore via existing gas and condensate pipelines. These pipelines are 20 kilometres in length and 30-inch and 12-inch in diameter respectively.

As part of Phase II B, two 16-inch pipelines were constructed to tie the new platforms into existing infrastructure.

South Mahakam

As part of the South Mahakam project, gas will be sent to the main Peciko gathering point via a new-build 70 kilometre pipeline. Production from the second phase oft he project involving Metulang and Jempang will be tied-back to the East Mandu platform via a short pipeline.

Senipah Terminal

The Senipah terminal was constructed in 1977 and has two separate streams: one for Handil crude and one for Bekapai crude. There are two 500,000 barrel storage tanks for Handil crude, two 500,000 barrel storage tanks for the condensates and a 500,000 barrel and a 100,000 barrel storage for Bekapai crude. A heating system is required for the Handil crude because of its high pour point. Oil from Senipah is sent through two 13 kilometre, 26-inch diameter, pipelines to an offshore loading SBM buoy. The SBM buoy had to be installed some distance from the coast as the immediate coastal waters are too shallow for large vessels. The facility was installed in 1974 and can handle tankers up to 100,000 DWT.

In addition to the oil facilities and the Peciko facilities, the Senipah terminal includes a gas compression station and a dehydration unit for Bekapi gas and gas coming off the condensate stabilisation unit. It is planned to undertake a debottlenecking programme on the gas facilities to increase capacity by 50 mmcfd.

In 1996, a Condensate Stabilisation Unit (CSU) was completed. Further expansion was completed to accommodate the Peciko processing facilities.

Santan Terminal

From November 1997, the condensates extracted at Bontang during the gas liquefaction process are returned to the Santan Terminal, operated by Unocal, and stored in two dedicated 600,000 barrel tanks. The Bontang Return Condensate is subsequently exported from the Santan Terminal through a dedicated 24-inch pipeline to an SBM.



Gas Pipeline Summary

Pipeline Type From To Length Diameter (km) (inches)Peciko to Senipah (32 inch)

Gas Peciko Senipah 23 32

Peciko to Senipah (24 inch)

Gas Peciko Senipah 22 24

Senipah to Badak (42 inch)

Gas Senipah Badak (gc) Off. Mahakam

128 42

Senipah to Handil (8 inch)

Gas Senipah Handil 11 8

Handil to Mutiara Spur Gas Handil Tambora 4 20Mutiara Spur to Badak Gas Mutiara Spur Badak (gc) Sanga

Sanga 70 20

Tunu to Tambora (1) Gas Tunu Tambora 17 30Tunu to Tambora (2) Gas Tunu Tambora 23 36Tambora to Badak (32 inch)

Gas Tambora Badak (gc) Off. Mahakam

29 32

Tambora to Badak (20 inch)

Gas Tambora Badak (gc) Off. Mahakam

29 20

Tunu North to Badak (Gas)

Gas Tunu Badak (gc) Sanga Sanga

24 32

Badak to Bontang 1 Gas Badak (gc) Sanga Sanga

Bontang LNG Plant 56 48





Badak to Semberah Spur

Gas Badak (gc) Sanga Sanga

Semberah Spur 56 36


Liquids Pipeline Summary

Pipeline Type From To Length Diameter (km) (inches)Tunu North to Badak (cond)

Condensate Tunu Badak (gc) Sanga Sanga

24 14

Badak to Santan Terminal

Oil Badak (gc) Sanga Sanga

Santan 32 6

Badak to Tambora Spur Condensate Badak (gc) Off. Mahakam

Tambora 23 14

Tunu to Tambora Condensate Tunu Tambora 16 12Tambora to Tambora Spur (12 inch)

Condensate Tambora Tambora Spur 6 12

Handil to Senipah (Cond)

Condensate Handil Senipah 11 12

Handil to Senipah (Oil) Oil Handil Senipah 11 20Senipah to SBM 1 Oil Senipah Senipah SBM 12 26Senipah to SBM 2 Oil Senipah Senipah SBM 12 26Source: Wood Mackenzie

Costs

Exploration Costs

It is estimated that around US$1,275 million has been spent on exploration as of 01/07/2012. Recent exploration wells have cost in the region of US$14 million each to drill, complete and test, although the West Mandu-1 well in 2011 is thought to have cost US$50 million given it was testing a high-pressure, high-temperature play. Seismic was acquired across the Tunu and Handil fields in 2009-2011, costing a total of US$60 million.



Exploration Costs Pre-2004 to 2011 (US$ million) Pre-2004 2004 2005 2006 2007 2008 2009 2010 2011Exploration Costs 1078 - - 20 39 28 36 5 69Source: Wood Mackenzie Costs in Nominal Terms.

Capital Costs

Total capital expenditure on the Offshore Mahakam Block as at 01/01/2012 is estimated at US$17.2 billion (nominal terms). The first three phases of the Peciko development is estimated to have cost around US$1.4 billion (nominal terms). It is estimated that the total cost of Phase IV of the Peciko development is around US$480 million (nominal terms), with the majority of this spent prior to 2005. Phase V cost in the region of US$50 million.

The cost of the Tambora Extension project was U$150 million (nominal terms) and it is understood that the proposed cost of Phase X of the Tunu development is in the region of US$750 million (nominal terms).

Development wells on the Tunu, Handil and Tambora fields are estimated to cost between US$6-8 million (nominal terms). The Sisi and Nubi development wells are estimated to cost around US$15 million (nominal terms).

Planned capital expenditure for 2012 is expected to reach US$1.7 billion, of which, US$1,070 million is estimated to be spent on development drilling.

Wood Mackenzie understands the first phase of the South Mahakam project will cost around US$400 million (2012 terms), with the second phase costing around US$375 million.

Capital Costs Pre-2003 to 2011 (US$ million)

Pre-2003 2003 2004 2005 2006 2007 2008 2009 2010 2011Product. Facilities 3263 300 300 550 500 790 840 575 580 300Dev. Drilling 2522 150 400 300 700 810 980 960 1000 1280South Mahakam - - - - - - - - - 100Total 5785 450 700 850 1200 1600 1820 1535 1580 1680Source: Wood Mackenzie Nominal to 2012 and real (in 2012 terms) thereafter. Capital Costs 2012 to Post-2020 (US$ million)

2012 2013 2014 2015 2016 2017 2018 2019 2020 Post-2020Product. Facilities 475 550 550 350 350 350 275 200 100 350Dev. Drilling 1070 1000 1000 900 810 729 656 590 502 1399South Mahakam 175 100 25 250 75 50 - - - -Total 1720 1650 1575 1500 1235 1129 931 790 602 1749Source: Wood Mackenzie Nominal to 2012 and real (in 2012 terms) thereafter.

Operating Costs

Wood Mackenzie estimates total operating costs in 2012 at around US$2.40/boe and that future operating costs will escalate at around 5% per annum on a boe basis going forward. This includes the Offshore Mahakam PSC's share of the operating costs for the Nilam and Badak fields.


2010 2011 2012 2013 2014Direct Field Costs 350 340 300 300 300Field Variable 89 56 56 49 38Total 439 396 356 349 338Source: Wood Mackenzie Nominal to 2012 and real (in 2012 terms) thereafter.



Sales Contracts

LNG

Gas is currently supplied to the Bontang LNG plant under Packages I-VII. Since 2005, there have been a number of deliverability problems to the LNG plant as some of the more mature gas supply assets have struggled to maintain output. This has resulted in the original full contracted volumes not being supplied. The Offshore Mahakam PSC has been able to make up part of this shortfall from other PSCs but by year end 2005, Wood Mackenzie understands that the Bontang LNG plant supplied 19.4 mmtpa of LNG, around 0.8 mmtpa less than that agreed in the contracts. This supply problem continued with buyers from Japan, South Korea and Taiwan agreeing to reduce their LNG intake for 2006 and 2007. In 2010, LNG supply volumes were 16.48 mmtpa, with the Offshore Mahakam PSC supplying around 84% of feedgas. Wood Mackenzie has assumed that this trend will continue for the next few years, with the Offshore Mahakam PSC continuing to supply above its original contracted volumes.

Post-2010, little supply is contracted from the Bontang LNG plant. Recently, the Indonesian authorities have placed an emphasis on a desire to supply the domestic gas market over gas exports. Wood Mackenzie has assumed from recent announcements that a total of 25 million tonnes will be supplied from the Offshore Mahakam PSC to a Japanese group of buyers over the period 2011-2020. LNG sales from Bontang into the Java domestic market, sourced from Offshore Mahakam gas, began in early-2012 under an HOA signed and we expect this to ramp up to a plateau 1.18 mmtpa from 2013.

The Bontang LNG plant suppliers have also entered into a swap agreement with ExxonMobil in North Sumatra whereby the Bontang LNG plant will provide three cargoes of LNG to PT Arun's buyers, allowing PT Arun to supply three cargoes equivalent of gas to the fertiliser plants. The shortfall in production from the existing North Sumatran gas fields resulted in the shutdown of the fertiliser plants in 2005. The swap agreement is expected to be sufficient to run the plants for six months of the year.

Gas Pricing Sales to Japan, Korea and Taiwan (under original contracts) have been priced based on a linkage to the JCC oil price. Prior to 2004, the assumed DES price formula has a gradient of 0.153 and a constant of -US$0.07/mmbtu. In 2004, a gradient of 0.156 and a constant of US$0.635/mmbtu was implemented.

For sales to Japan, Korea and Taiwan (under original contracts), the upstream price was calculated on the basis of the netback price (i.e. net of plant opex, debt servicing, plant losses and transport) for each of the individual LNG contracts. The upstream partners receive this price for the sales gas net of the liquefaction cost.

For sales to Japan, Korea and Taiwan under renewed contracts, we have assumed they will be priced based on a linkage to the JCC oil price. The assumed DES price formula has a gradient of 0.154 and a constant of US$0.340/mmbtu. This equated to an FOB price of US$17.35/mmbtu in 2011, and a LNG plant gate price of US$13.84/mmbtu (equivalent to US$15.34/mcf).

For LNG sales on the spot market, the assumed DES price formula has a gradient of 0.14 and a constant of US$1.00/mmbtu. This equated to an FOB price of US$15.91/mmbtu in 2011, and a LNG plant gate price of US$12.67/mmbtu (equivalent to US$14.05/mcf).

Domestic Gas Historically, the Offshore Mahakam PSC has supplied between 10%-12% of total sales gas production to the domestic market in Kalimantan. However, under newer licences and extensions to existing contracts, contractors are expected to be obliged to sell 25% of total sales gas production to the domestic market. There is still some uncertainty over how gas domestic market obligation will be determined but it has been assumed that upon contract extension, and dependent upon demand in the domestic market, that the Offshore Mahakam PSC will supply around 25% of its total production to the domestic market from 2012/2013, when supply to Java began.

East Kalimantan market On average, the Offshore Mahakam PSC is understood to supply between 10-15% of its total sales gas volumes to the East Kalimantan domestic gas market. Wood Mackenzie estimates that around 240 mmcfd was supplied to the domestic market in 2009. This is predominantly to four fertiliser plants (KFP 1-4), which are located some five kilometres to the north of Bontang. The price of the gas was US$1.10/mcf (US$1.00/mmbtu) and subject to a pipeline tariff, which amounts to some US$0.02/mcf. Deliveries began in late 1982. Any excess which is supplied to the fertiliser plants was priced at US$1.85/mmbtu.

In 1994, a further contract to supply a local methanol plant (KMI) with up to 70 mmcfd was signed with Pertamina. First deliveries were made in 1998 and a price of not less than US$1.25/mmbtu is expected for the first 10 years of the 20-year contract. The share of the Offshore Mahakam PSC in the supply of the plant will be approximately 50 mmcfd.



In 1998 and 1999, Pertamina signed two 20-year contracts to supply 110 mmcfd of gas to two new ammonia plants (KPA and KPI). One plant commenced production at the end of 1999, while the second came onstream in 2002. The Offshore Mahakam PSC will supply 45 and 40 mmcfd of gas respectively to the two plants. Gas supply pricing is linked to ammonia and urea pricing indices.

In February 2010, a gas purchase agreement was signed with fertiliser manufacturer PKT for the supply of 80 mmcfd for a period of 10 years from 2012 from the various Kalimantan operators. The breakdown of this supply between each operator is currently unknown.

For the purposes of this analysis, it has been assumed that gas supplied to the domestic market is sold at US$6.02/mcf in 2011. This is assumed to be a weighted average of the various prices achieved for gas sold to the domestic market and is assumed to vary linked to Wood Mackenzie's Brent oil price assumption going forward. It has also been assumed that domestic demand for gas from the petrochemical sector continues to grow.

Java market In order to supply increasing demand on the island of Java, the Indonesian authorities are considering options of increasing supply to the area through either the construction of an LNG gas receiving terminal in West Java or through the construction of a 1,220 kilometre pipeline from Badak (East Kalimantan) to Semarang (Central Java). The Offshore Mahakam PSC began supplying gas to the domestic market in Java in the form of LNG sales starting in early-2012 under the terms of an HOA signed. Supply will ramp up to a plateau rate of 188 mmcfd (feedgas to LNG) by 2015. Under this scenario, and including the supply of gas to the East Kalimantan domestic market, by 2015 the PSC will be supplying around 25% of its total gas supply volumes to the domestic market.

We have assumed that LNG supplied to Java from 2012 receives a price equivalent to 11% of the JCC price.

LPG

The LPG supplied from Bontang comes from the joint venture's contract area as well as from the VICO and Unocal operated areas. A contract to supply LPG under package IIIB from Indonesia to Japan was signed between Pertamina and seven Japanese industrial concerns in 1986. In order to meet a part of this contract, an LPG facility has been constructed at Bontang. The plant was completed in early 1988 and the first Bontang shipment was despatched in August 1988. The contract was for some 1.95 million tonnes per annum over a 10-year period, to be supplied from both Bontang and Arun. The contract expired at the end of 1998 and was extended to 2001 in February 1999. Wood Mackenzie believes that this contract has been further extended.

The LPG produced at Bontang between 2000-2010 is incorporated in Packages V and VII. During this period, the PSC was supposed to sell some 560 tbtu of LPG. However, following the drop in gas supply to the LNG plant in 2005, at the beginning of 2006, LPG has been spiked in to the gas in order to produce higher volumes of LNG. As a result, LPG production effectively ceased from the start of 2006. However, as LNG demand fell in 2009 and 2010, LPG output has resumed and we expect production to continue until 2015.

Taxation

The Offshore Mahakam PSC is a pre-1976 contract.

The original post tax profit oil and gas splits are 85:15 and 65:35 in Pertamina's favour.

LPG production is considered as gas for profit sharing.

A tax rate of 56% applies.

DMO is applied at 8.52% after a five-year holiday.

DMO reimbursement is set at US$0.20/bbl.

Investment credit was given at a rate of 20% on tangible oil capital expenditure.

There is no investment credit on gas capital expenditure.

Upon the extension being signed in 1991 several modifications to the PSC terms were implemented. FTP became effective at 20% and DMO reimbursement on new fields was changed to 10% of the export price.

When the PSC extension became effective in 1997, the terms were changed as follows:



A tax rate of 48% was implemented.

The post tax profit gas split changed to 70:30 in the government's favour on certain contracts, although it is understood that a 75:25 split is applicable to some contracts.

DMO changed to 7.21%.

DMO reimbursement on new fields remained at 10% of the export price.

Investment credit on oil capital expenditure changed to 17%.

Under the terms of the PSC, INPEX was able to offset costs accrued from its share in the Attaka Unit (see Attaka Unit analysis) against costs/revenues via its participation in the Offshore Mahakam PSC. From March 1997, however, a new PSC, INPEX Attaka, became effective covering only INPEX's interest in the Attaka field. All costs, revenues and reimbursements attributable to INPEX from Attaka are now calculated within the INPEX Attaka ring fence.

The current PSC is due to expire in 2017. Upon contract extension conclusions, the PSC partners are expected to be obliged to supply 25% of its overall sales gas supply volumes to the domestic market. There is uncertainty over whether the domestic market obligation for gas will be a minimum or maximum 25% volume or how the pricing structure for DMO gas will be determined.


The cash flow is for the Offshore Mahakam PSC, and includes the unitised production from the Sanga Sanga PSC. In producing the cash flow the following assumptions were made:

Oil Price

Wood Mackenzie uses Brent as the benchmark blend for its oil price assumption. Prices for other crude blends are assessed in relation to Brent and then assigned a percentage (%) discount or premium on that basis.

The Wood Mackenzie Brent oil price assumption in nominal terms is US$115.11/bbl in 2012, US$105.25/bbl in 2013, US$100.00/bbl in 2014, US$96.00/bbl in 2015 and US$92.00/bbl in 2016, escalating at 2.0% per annum thereafter.

Handil crude trades at a 0.5% discount to Brent. Bekapai crude trades at a 2% premium to Brent, while condensate trades at a 4% discount to Brent.

JCC is assumed to trade at a 1% discount to Brent.

Gas Price

For sales to Japan, Korea and Taiwan (under original contracts), the upstream price was calculated on the basis of the netback price (i.e. net of plant opex, debt servicing, plant losses and transport) for each of the individual LNG contracts. The upstream partners received this price for the sales gas net of the liquefaction cost.

For sales to Japan, Korea and Taiwan under renewed contracts, we have assumed they will be priced based on a linkage to the JCC oil price. The assumed DES price formula has a gradient of 0.154 and a constant of US$0.340/mmbtu. This equated to an FOB price of US$17.35/mmbtu in 2011, and a LNG plant gate price of US$14.04/mmbtu (equivalent to US$15.57/mcf).

For LNG sales on the spot market, the assumed DES price formula has a gradient of 0.14 and a constant of US$1.00/mmbtu. This equated to an FOB price of US$15.91/mmbtu in 2011, and a LNG plant gate price of US$12.86/mmbtu (equivalent to US$14.26/mcf).

For LNG sold to Java, we have assumed that the delivered gas price is equivalent to 11% of the JCC price, with the upstream feedgas receiving a price net of shipping and plant opex.

Domestic sales gas was sold at a weighted average price of US$6.02/mcf in 2011. This price is linked to Wood Mackenzie's Brent oil price assumption.

LPG

LPG is assumed to obtain a price equivalent to a 10% discount to the Wood Mackenzie Brent price assumption, equivalent to US$99.08/bbl in 2011.



Other assumptions

The PSC is extended past the December 2017 expiry date, with the same fiscal terms applied.

The LNG and LPG plants were financed independently and as such are excluded from the cash flow.

LPG production, although modelled as a liquid, is subject to the same profit split as other gas.

Our long-term inflation assumption post-2012 is 2.0% per annum.

The cash flow is in nominal terms, discounted to 01/01/2012 using a 10% discount rate.

The corresponding GEM file name is Offshore Mahakam PSC.fld



Cash Flow

Cash Flow Dollars

Year Production Gross Op Capital FTP Gov. Share Cost Profit Gov. Share DMO Tax Total Field Liquids Gas Revenue Costs Costs FTP Oil Oil Profit Oil Cash flow 000b/d mmcfd US$M US$M US$M US$M US$M US$M US$M US$M US$M US$M US$M 1973 0.0 0.0 0.0 0.0 200.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 -200.01974 4.0 0.0 17.2 2.2 300.0 0.0 0.0 17.2 0.0 0.0 0.0 0.0 -285.01975 20.2 0.0 86.0 8.7 275.0 0.0 0.0 86.0 0.0 0.0 0.0 0.0 -197.71976 80.9 0.0 366.2 37.3 250.8 0.0 0.0 366.2 0.0 0.0 0.0 0.0 78.11977 230.0 3.0 1106.0 113.3 75.8 0.0 0.0 716.7 389.4 256.6 92.6 87.6 480.21978 222.4 11.0 1100.4 112.8 50.5 0.0 0.0 256.2 844.2 556.4 91.7 113.7 175.31979 212.3 9.5 2309.5 112.2 50.4 0.0 0.0 252.9 2056.7 1355.5 194.5 289.3 307.51980 199.7 10.9 2586.8 108.6 200.9 0.0 0.0 389.7 2197.1 1445.1 217.4 312.8 302.11981 204.7 10.8 2546.7 115.8 201.2 0.0 0.0 382.0 2164.7 1423.2 214.0 308.8 283.71982 166.8 23.2 2002.9 118.3 109.5 0.0 0.0 341.5 1661.4 1088.5 167.6 234.2 284.71983 173.4 73.4 1914.6 112.8 156.6 0.0 0.0 318.0 1596.6 1034.4 156.4 239.7 214.71984 174.4 218.0 2102.3 121.4 226.2 0.0 0.0 365.0 1737.4 1026.1 151.0 329.9 247.71985 164.5 265.1 1973.7 119.2 54.8 0.0 0.0 299.3 1674.4 968.3 132.4 322.5 376.71986 157.3 259.6 1004.1 116.2 125.5 0.0 0.0 314.7 689.4 389.9 65.6 138.7 168.21987 133.5 220.9 1080.1 109.5 45.5 0.0 0.0 240.6 839.5 481.1 71.3 163.4 209.41988 101.6 242.3 736.5 85.6 55.8 0.0 0.0 202.6 533.9 283.5 44.7 118.1 148.81989 93.7 253.1 828.0 82.9 83.1 0.0 0.0 215.6 612.4 316.9 48.9 142.9 153.31990 86.9 466.2 1235.0 89.3 134.0 0.0 0.0 241.5 993.6 446.1 59.9 280.2 225.61991 79.8 608.5 1162.7 95.3 82.7 0.0 0.0 232.0 930.7 368.7 44.0 293.2 278.81992 77.3 678.7 1168.1 98.9 220.7 0.0 0.0 293.8 874.3 328.2 38.1 292.6 189.81993 74.1 713.7 1086.7 99.9 160.9 0.0 0.0 313.7 773.0 278.9 30.8 263.1 253.11994 82.7 802.9 1070.6 98.0 106.1 0.0 0.0 283.2 787.5 287.8 24.9 267.6 286.21995 74.2 785.8 1274.8 108.2 99.8 0.0 0.0 242.9 1031.8 355.4 23.2 367.8 320.41996 71.5 964.0 1680.5 128.0 265.5 0.0 0.0 335.2 1345.3 434.3 39.1 493.9 319.71997 79.9 1198.9 1857.4 129.7 389.9 371.5 190.3 430.9 1055.0 530.1 31.3 328.9 257.31998 88.2 1481.7 1553.4 155.0 496.8 310.7 157.3 536.6 706.1 336.9 23.9 245.6 137.91999 92.9 1757.3 2194.3 180.0 521.0 438.9 219.9 539.4 1216.0 595.5 30.3 394.7 252.92000 104.9 2086.2 4060.1 222.0 209.0 812.0 407.9 424.2 2823.8 1413.1 52.4 848.8 906.82001 95.8 2244.7 3617.4 242.0 315.0 723.5 359.7 553.2 2340.7 1151.3 41.9 728.6 778.92002 85.7 2111.2 3394.1 255.6 321.9 678.8 335.6 533.1 2182.2 1069.2 36.5 685.0 690.22003 90.1 2340.5 4203.9 285.6 450.0 840.8 415.0 591.1 2772.1 1358.5 44.6 866.6 783.62004 92.6 2400.7 5442.9 300.3 700.0 1088.6 540.8 892.5 3461.9 1717.0 71.5 1072.5 1040.92005 97.3 2704.5 8396.9 320.0 850.0 1679.4 833.0 915.8 5801.7 2872.3 108.8 1770.1 1642.72006 92.0 2829.8 10745.8 404.4 1200.0 2149.2 1044.9 1383.1 7213.6 3493.9 113.8 2269.4 2219.42007 87.9 2630.6 11306.7 443.6 1600.0 2261.3 1128.3 1558.7 7486.6 3711.3 154.3 2298.3 1971.02008 94.0 2613.0 16186.4 446.0 1820.0 3237.3 1597.4 1778.6 11170.5 5486.2 194.5 3438.3 3204.02009 108.2 2533.5 9914.5 444.9 1535.0 1982.9 990.3 1818.4 6113.2 3028.7 126.8 1909.4 1879.42010 97.6 2415.1 12027.6 438.7 1580.0 2405.5 1195.0 1869.9 7752.2 3835.8 145.5 2404.0 2428.72011 91.5 2162.7 14073.7 396.4 1680.0 2814.8 1404.4 2153.7 9105.3 4513.5 174.9 2808.4 3096.32012 81.7 1830.7 12199.9 356.1 1720.0 2440.0 1225.7 2056.5 7703.5 3861.7 168.6 2360.2 2507.62013 77.5 1703.0 10247.7 356.1 1683.0 2049.6 1034.9 2038.6 6159.6 3106.4 143.9 1898.4 2025.02014 71.9 1567.0 8956.3 351.5 1638.6 1791.3 906.0 2087.8 5077.3 2569.9 120.3 1585.9 1784.22015 64.5 1445.7 7852.5 345.3 1591.8 1570.5 792.4 2132.6 4149.3 2098.0 101.7 1322.5 1600.72016 47.4 1315.8 6541.5 323.5 1336.8 1308.3 661.3 1854.4 3378.8 1705.8 84.9 1083.7 1345.42017 42.4 1199.5 6024.9 329.9 1246.5 1205.0 608.4 1767.9 3052.0 1539.5 77.2 986.0 1237.52018 35.3 1019.2 5137.5 313.3 1048.5 1027.5 518.4 1571.1 2539.0 1278.5 77.1 821.1 1080.82019 29.3 862.2 4388.6 296.5 907.5 877.7 442.4 1497.8 2013.0 1017.9 65.3 662.1 996.92020 23.5 732.2 3740.7 280.0 705.3 748.1 375.2 1342.8 1649.8 833.2 53.4 549.6 944.12021 17.4 566.2 2782.4 241.4 629.8 556.5 279.6 1195.9 1030.0 525.0 40.4 359.9 706.22022 12.0 382.2 1857.0 191.8 564.4 371.4 187.8 1021.4 464.1 243.4 28.4 184.5 456.82023 8.5 263.0 1325.0 155.5 446.4 265.0 134.2 848.2 211.9 115.3 20.5 102.0 351.22024 6.7 196.5 1138.0 137.5 317.1 227.6 114.3 682.1 228.3 123.0 16.5 99.1 330.62025 5.1 151.1 891.2 123.7 194.0 178.2 89.4 506.6 206.4 109.6 12.7 84.6 277.12026 3.9 126.1 751.5 119.5 0.0 150.3 74.7 332.3 268.9 138.3 10.0 94.2 314.92027 2.9 105.8 633.0 115.5 0.0 126.6 62.2 506.4 0.0 0.0 0.0 0.0 455.22028 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Totals: 1757.2 19562.8 213882.1 10895.5 31229.5 36688.5 18326.6 44127.8 133065.8 67503.4 4279.7 39322.1 42325.3 PVs Total PV 660584.4 40330.5 97401.9 47381.8 23621.9 141833.7 471368.9 268639.9 33159.6 104325.0 93105.6 Rem PV 50775.8 2369.2 9222.0 10155.2 5119.8 13019.2 27601.4 13924.1 695.9 8717.3 10727.5Source: Wood Mackenzie Discounted at 10.0% from 01/01/2012



Discount Total PV Remaining PV Remaining PV/boe Total Total Remaining Remaining P/I Capex OpexRate Post-Tax Pre-Tax Post-Tax Pre-Tax Post-Tax Pre-Tax Gov. Take Gov. Take Gov. Take Gov. Take Ratio Boe Boe% US$M US$M US$M US$M US$ US$ US$M % US$M % US$ US$ 0.0 42325.3 171757.0 16413.9 56400.7 15.51 53.28 129431.8 75.4 39986.8 70.9 2.4 6.01 2.105.0 55251.8 253779.1 12996.6 46257.9 12.28 43.70 198527.3 78.2 33261.3 71.9 2.3 8.42 3.337.0 66038.0 325502.5 11983.9 43139.3 11.32 40.76 259464.5 79.7 31155.4 72.2 2.2 10.92 4.498.0 73336.8 376344.0 11533.6 41733.5 10.90 39.43 303007.2 80.5 30199.8 72.4 2.1 12.83 5.329.0 82253.2 440877.5 11115.9 40417.8 10.50 38.18 358624.3 81.3 29301.9 72.5 2.0 15.36 6.3810.0 93105.6 522852.1 10727.5 39184.6 10.13 37.02 429746.4 82.2 28457.0 72.6 2.0 18.73 7.7611.0 106262.0 627041.3 10365.8 38026.7 9.79 35.93 520779.3 83.1 27660.9 72.7 1.9 23.23 9.5212.0 122139.2 759512.4 10028.2 36938.0 9.47 34.90 637373.1 83.9 26909.7 72.9 1.8 29.23 11.7815.0 190818.5 1414338.0 9140.0 34032.7 8.63 32.15 1223519.4 86.5 24892.8 73.1 1.6 62.21 23.2625.0 580183.9 13761357.6 7100.1 27115.4 6.71 25.62 13181173.8 95.8 20015.3 73.8 1.1 1009.65 267.73Source: Wood Mackenzie

Discount Date Jan-12Remaining Liquid Reserves (mmbbl) 193.5Remaining Gas Reserves (bcf) 4915Total Remaining Reserves (mmboe) 1058.5Total Reserves (mmboe) 5200.3Project IRR (post tax) 28.56%Company IRR (post tax) 28.56%Pre-tax IRR 67.28%Payback Period (years) 5.7Reserve life at current production (years) 7.2Liquid Breakeven Price at 10% (US$/bbl) 21.54Gas Breakeven Price at 10% (US$/mcf) 2.87Source: Wood Mackenzie

Split of Revenues









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