1

Good OilConference

September 2007

O I L S E A R C H L I M I T E D

2

Overview

Growth driven by commercialistion of discovered 1bnboe gas and associated liquids

Significant progress on LNG and other options

Core business progressing wellPNG production sustained for 2+ yearsContribution growing from Middle East portfolioCosts tightly controlled but operations impacted by equipment delivery delays

Exploration programme largest everPNG just startingMiddle East 5 from 12

3

Oil SearchWhere We Operate

3

4

World Class Safety PerformanceBetter than Industry Peers

Total Recordable Incidents (TRIs) 1998 – 2006

TR

I /

1,0

00

,00

0 H

ou

rs

1998 1999 2000 2001 2002 2003 2004 20050

2

4

6

8

10

12

14

2006

APPEAOSH OGP

8.5

10.6 10.7

5.8

1.7

4.7

2.42.31

9.4

Oil Search

International Companies

12.7

9.1 9.3

8.2 7.87.0 7.3

9.8

5.2

Australian Companies8.3

6.8

3.054.0 2.92

5

Underlying Operationsare sound

0

50

100

150

200

250

300

350

1H 04 1H 05 1H06 1H07

US$m

Revenue

EBITDAX

Net Profit

170.9

233.4

323.3305.4

130.5167.4

276.8

249.8

41.7

63.9

115.3

46.9

242.2

188.3

136.1

276.8

266.9

Operating Cash Flow

EBITDAX down 9.7% on prior first half* 1H06 NPAT excludes profit of US$258.5 million on sale of licence interests to AGL

6

Some Cost Pressures

Other Prod’n Opex

7.08.7Net Corp Costs

1.90.0FX Losses

56.4

8.20.1

28.48.02.8

US$’m

1H07

46.5Total

7.20.1

- Oil- Hides

22.25.92.3

Field Costs- Oil: PNG- Oil: MENA- Hides

US$’m

1H06

FY2006 1H07

PNG Oil FieldCosts per BarrelUS$

0

1

2

3

4

5

6

7

Other FieldOther FieldCosts $2.09Costs $2.09

CoreCoreFieldFieldCostsCosts$4.43$4.43

TariffsTariffs$1.00$1.00

CoreCoreFieldFieldCostsCosts$4.18$4.18

TariffsTariffs$0.82$0.82

Other FieldOther FieldCosts $1.69Costs $1.69

8

Core PNG field costs per barrel up 6% on 2006 levels

7

Since 2002, OSH has created substantial value for shareholders

Source: OSH Analysis

0

100

200

300

400

500

600

Jul-02 Jan-03 Jul-03 Jan-04 Jul-04 Jan-05 Jul-05 Jan-06 Jul-06 Jan-07 Jul-07

Oil Search

Santos

OriginWoodside

ROC Oil

Sh

are

an

d i

nd

ices

pri

ces

(reb

ase

d t

o 1

00

)

ASX 100 Top Quartile by Annualised TSR (1 Jul 02 - 17 Jan 07)

242%

125%

83% 82%67% 60% 58%

47% 45% 42% 38% 38% 37% 37% 36% 36% 35% 35% 32% 32% 32% 31% 31% 30% 30%

0%

50%

100%

150%

200%

250%

300%

Paladin

Resou

rces

Zinife

xWorl

eyPars

ons

Caltex

Austra

liaBab

cock

& Brow

nOxia

na

Allco Fin

ance

Group

Promina

Grou

pRink

er Grou

p

QBE Ins

uranc

e Grou

pOil S

earch

Macqu

arie C

ommun

icatio

nsMay

ne Ph

arma

Compu

tersh

are

Macqu

arie G

oodm

an Grou

p

Sigma P

harm

aceu

ticals

OneStee

lAlin

taSim

s Grou

pSon

ic Hea

lthca

re

Macqu

arie A

irport

sBlue

scop

e Steel

Newcre

st Mini

ng

A.B.C. Lea

rning

Centre

s

ASX

8

Strategy for Growth

Deliver maximum value from existing production assets (production and cost focus)

Extract value from existing discovered gas and liquids resource

Create value from exploration success and acquisitions to build production base prior to gas development

9

DELIVER VALUE

10

Oil Search Net Production

Kutubu Moran Gobe Main SE Gobe Hides

Nabrajah SEM Area A ERQ

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

stb

/d

2000 2001 2002 2003 2004 2005

+23%+23%

+25%+25%+6%+6%

+10%+10%

2006

PostPostAGL AGL salesale

2007F 2008F 2009F

11

Field Development Drilling Activity

Usano:2007-8 development

3-5 wells

SE Gobe:2008 development:

1 well potential

Kutubu:2008 development:

2-3 wells

Agogo:2008 development:

1 well potential

Moran:2008 development:

3 wells

12

Usano MainBlock

Usano EastBlock

SE noseKutubu

Field

Arakubi

IDTG

UDTC

UDTG

UDTB

UDTF

UDTD

UDTE

UDT3A pad

UDT2 padUDT1 pad

Arakubi 1 Pad Location

UDT7

Usano Development

An under-developed field with significant infill potentialUDT 7 performing above expectation4 wells likely in 2008Success at Arakubi could positively impact Usano east

UDTJ

UDTH

Potential Usano well

Likely Usano well 2007-8

13

Kutubu infill well

Potential Appraisal well

Kutubu Development

Possible IDT-11twin (Iagifu target)

Remapping and simulation support a Hedinia Digimu infill well

IDT 23ST2: strong performance indicates potential for at least one additional well +/-appraisal wells

IDT 23ST2

14

PNG Oil Production Outlook (gross bopd)

Expect to continue to invest in PNG fields, targeting to maintain gross production around 50,000 bopd through to 2009Requires investment of approx US$100m pa net to OSH

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

Oil

Pro

du

ctio

n (

stb

/d

)

0

Jan-

2000

Jan-

2001

Jan-

2002

Jan-

2003

Jan-

2004

Jan-

2005

Jan-

2006

Jan-

2007

Jan-

2008

Jan-

2009

Jan-

2010

Jan-

2011

Jan-

2012

Jan-

2013

OSH AssumesField Operatorship

Historical Production

Added over 34mmbblsin production 2003-06

Decline before Oil Search

P50

P90

Forecast Base Production

P10

15

Egypt Area A Production

Oil Search shares in production above specified base production levelSince August, have been in ‘sharing’territory. This result has been achieved even with a 2 month delay to the start of the development drilling programme, due to the unavailability of a suitable drilling rigExploration targets being tested in 4Q07No reserves booked for Area A to date

0

Jan-

2007

Apr-2

007

Jul-2

007

Oct

-200

7Ja

n-20

08Apr

-200

8Ju

l-200

8O

ct-2

008

Jan-

2009

Apr-2

009

Jul-2

009

Oct

-200

9Ja

n-20

10

Gro

ss O

il P

rod

uct

ion

(b

op

d)

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

P50

16

Yemen Nabrajah Production

Nabrajah-15

Nabrajah-16

Nab15

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

Jan-

2007

Apr-2

007

Jul-2

007

Oct

-200

7Ja

n-20

08Apr

-200

8Ju

l-200

8O

ct-2

008

Jan-

2009

Apr-2

009

Jul-2

009

Oct

-200

9Ja

n-20

10

Gro

ss O

il P

rod

uct

ion

(b

op

d)

P50

Nabrajah-15 well has proven a new terrace/compartment within the fieldField reserves currently being evaluated by NSA. Anticipate an increase in certified reserves

17

EXTRACT VALUE

18

Gas Commercialisation

Strong momentum building for world scale LNG project operated by ExxonMobil. Oil Search interest ~ 30%

Studies ongoing with BG Group

Work underscoring viability of PNG LNG development

Strong market demand continues

Major interest in participation at various levels

Capital costs well understood

19

PNG’s Competitive Advantage

Quality and location of resource makes PNG very competitive in project line up for a 2012 – 2014 development timetable

Advantages of LNG from PNG Highlands:Substantial certified reserve base, sufficient to underwrite development

High liquids content improves economics

Clean gas, minimal impurities (CO2), no additional processing capex required

Onshore, with existing infrastructure base (Kutubu & liquids pipeline)

Environmental approvals well advanced

Excellent location to exploit Asian markets

Competitive labour costs relative to Australia

Favourable fiscal regime with strong Government support

20

Comparative LNG Pricing

Source: FACTS Global Energy

NWS Traditional Contracting

Crude Oil Parity

0

2

4

6

8

10

12

14

15 20 25 30 35 40 45 50 55 60 65 70

LNG ($/mmbtu)

JCC ($/b)

NWS Recent Contracting

21

Angore

Barikewa

Uramu

Pandora

Juha

Kimu Iehi

Korobosea

Hides

Key Gas Fields in PNG

Hides / Angore Fields (OSH –27.5%/52.5%)

Hides – 5.3 tcf of 2P resource, 3P upside to 10 tcfAngore ~ 1.2 tcf

Kutubu Complex Fields (OSH -60.0%)

~ 1.5 tcf plus liquids, largely developedKey strategic resource and infrastructure hub, high value

Juha Field (OSH 31.5%)Post Juha 4 & 5, 2P resource ~ 1 tcf, subject to review of J-4 results Liquids rich

Other fields include:Kimu – 0.8 tcf (OSH –60.7%)Barikewa – 0.8 tcf (OSH –42.5%)Uramu – 0.4 tcf (OSH –49.6%)Appraisal drilling required to firm up resource size

Korobosea gas prospect (potential resource 0.5+ tcf), to be drilled 4Q07 (OSH – 70%)

22

LNG with ExxonMobil

ExxonMobil Pre-FEED review progressing well - strong momentum build

Kutubu/Agogo/Moran/Gobe Main participants have joined Hides/Angore/Juha JVs in LNG studies. OSH’s funding share has increased to 36.6%. Interest post Government back-in/unitisationexpected to be ~ 30%

Studies on technical aspects have been expanded. Number of different configurations eg one large train (5 – 6.5 mtpa) or two smaller (3.2 mtpa) trains, plus different technologies, are under review

Plant location being finalised

Negotiation of fiscal terms expected to accelerate in September when new Government is in place

Working towards agreement on Unitisation framework, Joint Development Agreement

Capex estimates of between US$9-10bn for 6 – 7 mtpa of capacity appear to be robust post Pluto

Timetable - target end 2007/early 2008 to enter FEED, 12-18 months to FID, mid-2013 for first deliveries

23

Full foldbelt 6.3 mtpaExxonMobil LNG option

Kopi

Kutubu & Agogo

Gobe

Hides & Angore

Juha

Port Moresby

Estimated capital cost (US$bn):

- Upstream & Pipeline 5.0

- LNG Plant 4.5

Total 9.5

Reserves required (20 yrs): 7.7 tcf

Configuration and cost estimates being refined in pre-FEED work

Valve & Pigging Station

311 km 32-inch Hides-Kopi pipeline

250 mmscfd (nominal)

960 mmscfd Conditioning Plant

66 km 14-inch gas line

8-inch condensate line

~300 km 32/34-inch subsea gas line to LNG

Plant at Cape Possession or Port Moresby

75km

24

Other Complementary Gas Activities

Core focus to develop ancillary gas business complementary to LNG

Active programme to secure and/or find further certifiable reservesReviewing options for early pipeline development in conjunction with PNG GovernmentExploration and appraisal drilling at Korobosea (0.5+ tcf) and appraisal at Barikewa (0.8+ tcf) to complement existing discoveries Kimu (0.8tcf) and Uramu (0.4tcf)

Discussions with petrochemical developers continue with strong support

25

CREATE VALUE

26

Korobosea

Juha

Barikewa

Arakubi

Mananda Attic

NW Paua

Cobra

PNG Exploration

Oil - Remaining 2007 programme testing ~40 mmbbl net risked reserves

Gas – exploration/appraisal to add reserves to support commercialisation projects

PNG 2007 exploration budget US$120m net

Continued seismic for gas and oil exploration/appraisal, in Highlands, Forelands and Offshore

Offshore licence bid submitted in April 2007

Active programme to optimise interests in existing licences and new venture opportunities

27

Juha Update

Juha 5 well confirms GWC for Juha main poolJuha 4ST1 proves separate pool to the eastAwaiting analysis of fluid composition and resource base2P resource base likely to be maintainedDevelopment options being assessed

56.0ExxonMobil

12.5Merlin Petroleum

31.5Oil Search

WI %PRL 2

Juha-1X

Juha-2X

Juha-3X

10km

PRL2

Juha 4ST1

Juha 5

28

PDL 2 - Arakubi

14.5*ExxonMobil

11.9AGL

6.8Merlin Petroleum

6.8PRK

60.0Oil Search

WI %PDL 2

Located 2km from infrastructure, connected by roadMean reserves ~18 mmstb Well spudded late August – approx 60 days to TD

Line PN04-411Depth migration

Usano 2x block

UDT4 block

Arakubi structure

Reserves: 18 mmstbCOS: 35%

* ExxonMobil did not participate in initial Arakubi well but will be involved in re-drill

APF

Moro

Ridge CampCPF

SE Mananda

Moran

Paua

Kutubu

LakeKutubu

Agogo

ARAKUBI

PDL2

10km

29

PPL 233 – NW Paua

47.5%Esso Highlands

52.5Oil Search

WI %PPL 233

Highly prospective structure adjacent to MoranDigimu target with Toro secondaryWide range of reservesPartially constrained by Paua 1X well (1996)Important test of ‘next trend’New seismic acquired in 2005Site construction complete Oil Search operating on behalf of EssoTo be drilled after Arakubi

Reserves: 40-120mmstb (depends on column height and number of reservoirs)

COS: 24%

Line PN04-411Depth migration

Usano 2x block

UDT4 block

Arakubi structure

APF

Moro

Ridge CampCPF

SE Mananda

Moran

Paua

Kutubu

LakeKutubu

Agogo

NW PAUA

PDL2

PPL233

PPL219

PDL5

10km

30

PPL240 - Korobosea

10%Gedd

90.0Oil Search

WI %PPL240

Korobosea well will test prospect along trend from Kimu gas discoveryProspect is well defined by seismic (9 lines of good quality)Reservoir known to be effectiveMost likely phase is gas but there is a chance of a late oil charge – evidence in Kimu, Koko, BujonGas resources 0.3-0.6 tcf(mean) in Alene reservoir

Reserves: 0.3-0.6 tcf (Alene Sst only, possible upside in Toro)

COS: 19%

KIMU

KOROBOSEA

PPL240

PRL08

10km

31

Yemen Exploration

Al Harsh-2

NABRAJAH

Ataq-1

Reeb-1 currently drilling (75mmbbl, COS=21%)

Prospect B(~10mmbbl COS=20%)

West Ghobata-1 (20mmbbl, COS=23%)

Dahgah-1 (~10mmbbl, COS=40%)

Thoub-1 (~15mmbbl, COS=52%)

BLOCK 7

BLOCK 3

BLOCK 15

BLOCK 35

BLOCK 74

BLOCK 49

BLOCK 43

ShirTerminal

Remaining 2007 Activity5 Exploration Wells testing total ~130mmbbl1 Nabrajah Appraisal400+sqkm 3D in Block 3

3D survey ongoing

50km

32

3 wells drilled to date3 discoveries at 4 stratigraphic levels

Development plans submitted for Shahd and Ghard

Production in 4Q 07No reserve additions booked to dateFurther 3D seismic acquired in 2007 and planned in 2008Rana :

Reserves ~ 10-15 mmbblDST’s 2- 4 planned

Extensive prospect inventory. Next wells :

Raheek ~ 8-12 mmbbl (COS = 35%)Salma ~ 100 mmbbl (COS = 15%)

Egypt - East Ras Qattara

Rana-1Discovery

Ghard-1Discovery

Shahd-1Discovery

Raheek-1 to follow Rana, then Salma Prospect

5km

33

Strategic Review

Company has embarked on major Strategic Review, focussing on:

Maximising value from existing oil fieldsExtended field life managementOil and gas operational interface and value impactOperational cost and efficiencies

Commercialising gas through LNG development and ancillary in-country gas projects

Review project optimisation and long term positioningResource/reserve build

Exploration and New Ventures focus, production and value build filling in the production gap to first gasMENA value crystallisation

Developing the organisation to deliverInitial results at year end

34

Outlook

35

Outlook for 2007Operational

Production expected to be between 9.5 – 10.0 mmboe

Kutubu and Moran fields performing well, but no new development wells expected onstream in PNG in 2007. Focus in 2008

Rising production from MENA (Nabrajah, Area A, ERQ) and contribution from NW Moran will offset mature field declines

Expanded exploration programme to continue. 2H 2007 programme includes a number of high impact wells (Arakubi, NW Paua, ERQ)

Moving towards FEED decision on LNG – expect all major agreements to be in place/issues resolved by year end

36

Outlook beyond 2007

Rig delays push production into 2009

Seeking to fill production gap pre-LNG through exploration success and/or acquisitions

Includes risked exploration production contribution (firm one year programme)

0

Jan-

2007

Jan-

2009

Jan-

2011

Jan-

2013

Jan-

2015

Oil P

rod

uct

ion

(b

op

d)

20,000

40,000

60,000

80,000

PNG LNGGas Liquids

PNG LNG Gas

Jan-

2008

Jan-

2010

Jan-

2012

Jan-

2014

PNG Development

PNG Exploration

MENA Exploration

MENA Development

37

Summary

Continuing to generate strong cash flows from operations – underlying business is robust

Commercialising gas resource remains Oil Search’s highest priority – PNG LNG provides attractive returns, progressing steadily with growing momentum

Strategic focus on building business to first gas and positioning for long term multiple gas developments

38

O I L S E A R C H L I M I T E D