O I L S E A R C H L I M I T E D(Incorporated in Papua New Guinea)

ARBN – 055 079 868

A U S T R A L I A N R E G I S T E R E D O F F I C E

Level 27 Angel Place, 123 Pitt Street, Sydney NSW 2000 Australia. GPO Box 2442, Sydney NSW 2001 Australia.

Telephone: (61) 2 8207 8400 Facsimile: (61) 2 8207 8500

31 October 2007 THE AUSTRALIAN SECURITIES EXCHANGE (SYDNEY) LIMITED Level 4, Exchange Centre 20 Bridge Street Sydney NSW 2000 Attention: Company Announcements Officer Dear Sir/Madam

Re: Oil Search Limited Investor Field Trip. October/November 2007 Please find attached. Yours sincerely

MICHAEL SULLIVAN General Counsel/Group Secretary Encl.

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Oil Search Investor Field

Trip

October/November 2007For

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Gas Commercialisation

October/November 2007

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

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Outline

Gas Resources in PNG

LNG markets

ExxonMobil LNG Project

Gas Growth Initiatives

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Oil Search’s Gas Agenda

Progress ExxonMobil LNG development with FEED entry

Develop ancillary gas businessAdditional LNG trains/plants over timeActive programme to secure and/or find further certifiable reservesReview options for early pipeline developmentExploration and appraisal drilling at Korobosea and appraisal at Barikewa to complement existing discoveries Kimu and Uramu

Continue discussions with petrochemical developers and othersF

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Gas Resources in PNG

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Existing gas fields, gas

exploration and appraisal opportunities

Angore

Barikewa

Uramu

Pandora

Juha

Kimu Iehi

Korobosea

Hides

Moran

Kutubu

Gobe

Flinders

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Gas Resources(Gross PNG)

Current 3P gas resources approximately 24 tcf ex ElkMix of appraisal and exploration is underway to further mature the resource

ElevalaKetuPandoraUramuKimuBarikewaP'nyangAngoreJuhaHidesSE GobeGobe MainMoranAgogoSE ManandaKutubu

0

5

10

15

20

25

30

1P 2P 3P

Recoverable Gas

tcf

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PNG Gas Resources

Current 2P gas resources of approx 14 tcf

Significant condensate/liquids in conjunction with Highlands gas

Sufficient resources for sequential multi-train LNG development

A prudent mix of appraisal and exploration required to support gas reserves to underpin additional commercial projects

Oil Search net gas and associated liquids resource 940 mmboe

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Key FieldsHides Gas Field

27.5Oil Search

25.0Santos Ltd.

47.5Esso Highlands (Operator)

WI %Greater Hides

9.975.333.81Gas Reserves (tcf)

3P2P1PGross

World class gas and gas condensate field discovered in 1987

4 wells + 1 Sidetrack, 120 km 2D seismic. 2 Producers (Hides 1 & 2), 1 Cased and completed (Hides 4)GWC yet to be confirmed through the drill bit

Approximately 60 bcf gas produced to date

Wells in pressure communicationLow risk of compartmentalisation in Central and SE areas

Significant resource upside 10 tcf at 3P Potential exists for increased liquids recovery with optimised well placement (down-dip)Comprehensive technical review completed as part of PNGGP FEED from Subsurface through to field development plan

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Key FieldsPRL 11 - Angore Gas Field

1.771.150.60Gas Reserves (tcf)

3P2P1PGross

Angore 1 discovery well drilled in 1990

Condensate volumes estimate based on average CGR of 15 bbls/mmscf

Low field development costs in conjunction with potential Hides Field development

Application for extension of licence has been submitted

47.5ExxonMobil (Operator)

52.5Oil Search

WI %PRL 11

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Key FieldsKutubu & Agogo Gas

Kutubu gas production capacity of 170 mmscf

Gas developments assume new gas conditioning plant is required at CPF

Minimum field capital depending on blowdown rateMay only require dehydration depending on development scenario

Agogo gas currently used for pressure support at Moran

Pipeline to CPF required for gas development

1.611.451.12Gas Reserves (tcf)

3P2P1PGross

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Key FieldsMoran Unit Gas

0.580.240.15Gas Reserves (tcf)

3P2P1PGross

Currently re-injecting 100% of Moran gas for pressure support

Agogo gas production used to supplement pressure support to 100-110 mmscfd

Moran gas available for gas development supply ca. 2020 to maximise oil recovery

Minor gas development capital assuming APF already tied into CPFF

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Key fieldsGobe Main & SEG Unit Gas

GM and SEG fields:3 gas injectors2 water disposal wells17 production wells

Gas conditioning plant and 10 km pipeline tie-in to main gas line required for gas development

May only require dehydration depending on development scenario

GPF compression capacity of 70 mmscfd

0.390.320.20Gas Reserves (tcf)

3P2P1PGross

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Key fieldsPRL 2 - Juha Gas Field

2.001.100.50Gas Reserves* (tcf)

3P2P1PGross

31.5Oil Search

56.0ExxonMobil (Operator)

12.5Merlin Petroleum

WI %PRL 2

Discovered in 1983

Condensate reserves estimate based on average CGR = 60 bbl/mmscfLicence extension granted with a well commitmentJOA allows sole risk development

* - includes both Juha and Juha North pools

Juha-1X

Juha-2X

Juha-3X

10km

PRL2

Juha 4ST1

Juha 5

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LNG markets and PNG’s positioning

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AtlanticBasin

MiddleEast

Asia PacificBasin

New supplies from Asia Pacific can move in 2 directions – within Asia and to the US West Coast

Supplies from the Middle East can go in 3 directions – USGC and East Coast, Europe/UK, and Asia

LNG market is changing

Source: FACTS Global Energy, as adapted by Oil Search Limited

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There’s an Asia-Pacificopportunity

Regional market fundamentals are robust

Steady expansion from existing marketsBurgeoning growth from emerging markets of India & China

Projected supply/demand imbalance has created a “Sellers” market

Inevitable delays to announced projectsEscalating development costs & environmental issuesQuestions over domestic requirements in Indonesia

A number of “Possible”projects looking to fill demand gap

Demonstrates importance of early commitment

2005

20

06

2007

20

08

2009

20

10

2011

20

12

2013

20

14

2015

20

16

2017

20

18

2019

20

20

70

90

110

130

150

170

190

210

230

mm

tpa

Onstream Supply

SupplyUnder Construction

(Peru LNG, Qatar Gas 2/3/4, RasGas3, Sakhalin 2, Tangguh, Yemen LNG, Pluto)

Probable Supply(includes Gorgon, Ichthys)

Demand(Alternate 3rd Party View)

Source: WoodMac, Oil Search

Asia-Pacific Supply Demand

Demand(WoodMac)

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Supply will remain tight until next decade

Only one project made it to FID in 2006 (Peru LNG). Two so far in 2007 (Skikda rebuild and Pluto)

New LNG supply will remain scarce until 2012-13 when greenfield projects come onstream but tightness could last longer as projects continue to face delays

In an environment of rising costs, greenfieldprojects are likely to negotiate price floors to justify the investment and secure financing

Source: FACTS Global Energy

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Continuous construction cost increaseEnvironmental issuesChallenging conditions/locationsPolitical issues

PROJECTSDELAYED

Source: FACTS Global Energy and Oil Search estimates

Challenges ahead for greenfield projects

Liquefaction Plants Construction Costs: Where Next?

US

$/

t

0

200

400

600

800

1000

1200

1400

1965

-70

1971

-75

1976

-80

1981

-85

1986

-90

1991

-95

96-2

000

2001

-05

2006

-10

Indicative range forPNG LNG

?

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LNG prices have risen

Higher oil prices mean higher natural gas prices directionally, though gas prices are capped by competition from coal and nuclear at the burner tip, especially in the longer term.Construction costs have risen significantly The United States has entered the LNG market from virtually zero early in the decade, and is very likely going to become the second largest LNG importer next to Japan after 2010. Japan will continue to be the largest importer of LNG through 2020Indonesia, once the world’s largest LNG exporter, is heading for a decline of exports to nearly zero (except for Tangguh) due to a combination of resource problems and political pressure to divert resources to the domestic marketQatar holds most of the cards in the near term

Source: FACTS Global Energy

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High prices and high future demand?

FACTS view of the future is a HH price of US$7-9/mmbtu (real) long term, despite the current weak prices. However, prices may rise and fall with oil prices

Can the consumer pay US$7-9/mmbtu or higher ex-ship price? FACT believes the consumers in Japan, Korea, Taiwan, and the US have no choice. They are paying the high price for oil and they can afford the high price for gas, but do so reluctantly and with much resistance, particularly in the power sector

Some Asian countries are being asked to pay $8-12/mmbtu today to divert volumes from the West to the East

Can the Chinese and Indian consumers pay such prices? Can fertiliser producers pay such prices? The answer is highly uncertain. China and India are still not addicted to gas. They will find coal as the best buy. Some sectors can pay the high prices, but most cannot, particularly in the traditional state-owned power sector, except where gas replaces fuel oil or naphtha

Source: FACTS Global Energy

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Higher long-term price benchmarks

NWS Traditional to Japan NWS-T1-3 Bilateral Renewals Gorgon to Japan

Pluto to Japan NWS Allocation Process RasGas to KOGAS from 2007

Crude Oil Parity

Analysis of Recent Contracts to Japan and Korea (DES)

JCC ($/bbl)

LN

G (

$/

mm

btu

)

Oct 05 - Mar 06

Mar - May 06

April - May 06

December 06Sellers are now positioning between these markers

Source: FACTS Global Energy

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LNG pricing relative to oil

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

LN

G (

$/

mm

btu

)

JCC ($/bbl)

NWS Recent Contracting

10

Source: FACTS Global Energy

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PNG has competitive advantages

Quality and location of resource makes PNG very competitive in project line up for a 2013 – 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 & US West Coast markets

Competitive labour costs relative to Australia

Favourable fiscal regime with strong Government support

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PNG well placed geographically

PNG‘s geographical location & stability make it an ideal supplier

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LNG Projectin PNG

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LNG with ExxonMobilSummary

ExxonMobil Pre-FEED review progressing well - strong momentum

Participants in LNG pre-FEED are Hides/Angore/ Juha/ Kutubu/ Agogo/ Moran/Gobe Main JVs. OSH’s funding share is 36.6%. Interest post Government back-in/unitisation expected to be ~ 30%

Studies on technical aspects are ongoing and include LNG plant technology, configuration, site development and execution planning

Plant location being finalised

Negotiation of fiscal terms taking place with new PNG Government

Working towards agreement on Unitisation framework, Joint Development Agreement

Capex estimate of around US$10bn for 6.3 mtpa of capacity appears to be robust post Pluto, full bottom-up capex re-build underway pre-FEED

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

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ExxonMobil-led LNG Project

Capacity: 6.3 mtpa

Indicative capital cost: US$10 bn

Reserves required (project life): 10-12 tcf

Configuration and cost estimates being refined in pre-FEED work

Kopi

Kutubu & Agogo

Gobe

Hides & Angore

Juha

Port Moresby

75km

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

~400km 32/34-inch subsea gas line to LNG Plant at Konebada, Port

Moresby

LNG Facility - 6.3MTA Capacity

2x 125,000m³ LNG Tanks2x 50,000bbls Condensate Tanks2.1km LNG Trestle

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What’s being done…..

Activities underway include:Plant size & technologySiteGas resourceUnitisationCommercial JV frameworkFiscal regime & State deliverablesFinanceMarketingBenefitsInterface with the existing Oil Projects

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Plant Size & Technology

Owners have considered the number and size of trains for the initial development

Currently certified resource supports an initial 6.3 mmpta LNG development

Owners elected to run dual pre-FEEDs in order to ensure appropriate technology selection

Pre-FEED work considered a single large train and dual smaller trains

Pre-FEED work also considered APCI technology and Cascade technology

Consideration has been given to risk and economics

Both technologies have proven track records

Work is being finalised

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LNG Plant Site

Site selection and land tenure issues have been considered

World-scale LNG plant11 potential sites were evaluated, with a focus on coastal locations in the southSite near Port Moresby (portion 152, near Konebada Petroleum Park) is currently favoured:

Large, low relief block suitable for initial LNG development and expansion trainsGood sea accessNeed for a jetty, but no breakwaterRoad access to Port Moresby infrastructure

Confirming processes for site access and tenureOSH assisting

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Upstream: Production Facilities and Pipelines

Wells:Hides AngoreJuha

Gas production facilities:Hides Gas Conditioning Plant (HGCP)Juha Production Facility (JPF)Measurement of gas/condensate for sale purposes

Pipelines:Field to Facility

Hides field to HGCPAngore field to HGCPJuha field to JPFJPF to HGCP

Main Gas PipelinesHGCP to Omati River landfallSubsea gas pipeline from Omati River landfall to LNG facility site, near Port MoresbyKutubu, Gobe and Agogo facilities to the main gas export pipeline

Condensate and Liquids PipelinesJPF to HGCP (liquids)HGCP to Kutubu Central Processing Facility (condensate)

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Downstream: LNG Facility

Schematic of LNG facility site and loading terminal

LNG facility and loading terminal:LNG facility will be located on State Portion 152 near Port Moresby

LNG facility—gas will be cooled to extremely low temperature to form liquefied natural gas (LNG)

LNG is stored in storage tanks at the facility

LNG loading terminal (trestle structure) will be built off the coast for tanker ships to berth and load the LNG

Material offloading facility (earthen structure) will be built for transfer of equipment and materials during construction and operations

Supporting facilities and infrastructure:

Large camp for construction (~7,500) and operations (~500) personnel

Waste disposal facilities

Upgrade of existing road between LNG facility and Port Moresby and rerouting of the road around the LNG facility to maintain traffic flow to the north

Temporary laydown areas during construction only

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Reserves Cover for LNG

Circa 1 bcf/d for initial LNG (6.3 mmtpa) development for 20-30 years

7-10+ tcf total

Total Circa 9 tcf available (certified) provides:Circa 14 years of 1P at plateauCirca 20 years of 2P at plateauJuha recent results includedHides circa 80% of total non-associated gas

Summary Resources EstimatesOil Fields 2.0 tcfHides 6.0 tcfJuha 0.5 tcfAngore 1.1 tcf

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Unitisation

Unitisation and cooperative development is required to proceed to FEEDMethodology under discussion Indicative unitisation is as follows:

~ 2%2.7%JPP

18-20%1.1% State / Landowners

~3%3.3%AGL

11-13%13.8%Santos

28-32%36.6%Oil Search

30-34%42.5%ExxonMobil

Indicative Unitisation*

Cost Sharing Agreement

* Oil Search estimates only, based on After State back-in and dependent on assumptions and negotiated outcomes

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Project Structure

JuhaDevelopment

Hides/AngoreDevelopment

Additional TRAINS

(?)

TRAIN 2

TRAIN 1

Ship

Pipeline JV

Common Facility JV

Developable or expansion capacity?

New FieldDev

GasDevelopment

KGAM Oilfields

LNG Project is a fully integrated JV

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Fiscal Terms and State Deliverables

Early gas commercialisation is a priority for the returned Somare governmentDiscussions on fiscal terms and other conditions now well underwayPNG Gas Project (Pipeline to Australia) signed a gas agreemnet

Dealt with all material issues regarding fiscal terms and state deliverables (30% tax rate for gas)

There are material project differences:LNG Project requires a larger upstream configurationAdditional processing component (LNG Plant) in PNG

New Gas Agreement is required Key issues are:

Tax Approach to Oil Fields as they become gas sellersFiscal StabilityProvision of infrastructure & accessBenefits

Other State deliverablesFinancing for its stake in the ProjectAgreements with affected communities for benefit sharing

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Finance

Workable finance plan required by FEED entry

Likely to involve multilateral agencies and commercial banks

State equity is fundamental

Finance plan under developmentAdvisor appointed for phase 1

Project based finance

Need for State to work closely with developers on financing

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Marketing

Owners considering approach to marketing and discussing framework as part of commercial discussions

Expect to commence discussions with potential customers in early 2008, post FEED decision

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LNG Project Schedule

2007

FEED Program &EPC Contracting

PNG GovernmentApprovals

Benefits SharingAgreement

Project Financing& Marketing

Detailed EngineeringDesign & Procurement

Construction /Commissioning

2008 2009 2010 2011 2012 2013 2014

Pre-FEED

FirstCargoLNG

Schedule is Indicative only

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LNG Project Production

Indicative profile reflects initial estimate of recoverable gas

LNG energy value and condensate production fluctuate with stream composition

Final field production sequencing under review

mm

bo

e

0

10

20

30

40

50

60

70

2013

2016

2019

2022

2025

2028

2031

2034

2037

LNG

Condensate

0

200

400

600

800

1000

1200

1400

1600

1800

Cumul

ativ

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Other Potential LNG Projects

InterOil-Merrill Sponsors continue to express confidenceRelies on gas from ElkSeparate plant location near IOL Refinery

BGMOU with Oil Search lapsed at end of October

Reflects progress with ExxonMobil LNG Informal relationship with a view to future LNG opportunities

OthersFrequent inquiries seeking opportunities for involvement with Oil Search in developing LNG from its gas portfolio in PNG

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Gas Growth

Strategic Opportunity

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Gas Growth Strategy

Build gas resource base for:LNG expansion, or:Alternative, complementary and possibly accelerated gas development.

By:Prudently exploring and appraising in existing licences.Increasing Oil Search equity in some existing licencesPotential farm-ins to high graded quality acreageMaintaining appropriate momentum on alternative gas commercialisation options

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Foreland Hub

Forelands Hub

Kimu (0.85 tcf)OSH @ 60.7%

Barikewa (0.72 tcf)OSH @ 42.5%

Korobosea (0.5 tcf)OSH @ 90%

Increase equity in licences (eg Kimu)Farm-in opportunities

Angore

Uramu

Pandora

Juha

P’nyang

Iehi

BarikewaKimu

Korobosea

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PRL 8 - Kimu Gas Field

Drilled in 1998/99 by Oil Search intersected a 30m gross gas column

70km new seismic acquired Q3 2007Seismic currently being interpreted

28.6Mosaic Oil Niugini

60.7Oil Search

10.7Cue Energy

WI %PRL 8

Reserves: Current 2P 0.85 tcf

PRL08

PPL240

KIMU

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PPL 240 - Korobosea

10.0Gedd

90.0Oil Search

WI %PPL 240

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 0.4-0.5 tcf (mean) in Alene reservoir

Reserves: 0.4-0.5 tcf (Alene Sst only, possible upside in Toro)

COS: 19%

KIMU

KOROBOSEA

PPL240

PRL08

10km

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PPL 240 - Korobosea

SW NEKorobosea

2km

Alene Sst

Toro Sst

Darai Lmst

Korobosea Prospect covers 20+km and is well defined by seismicKorobosea-1 spudded 22nd OctoberScheduled to intersect Alene and Toro reservoirs in early November

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PRL 9 - Barikewa Gas Field

Discovery well drilled in 1956Hedinia tested 10 mmscf/dToro tested 4 mmscf/dGas analysis result show high Nitrogen content of 17%

N2 content in question

Field located next to main export Right of WayAppraisal well(s) required to delineate field and confirm gas compositionConsiderable upside in 3P and also untested exploration in deeper sandsGround work for site construction underway

42.6Oil Search

42.6Santos

14.8Cue

WI %PRL 9

BARIKEWA

PRL09

10km

PPL246

Barikewa 12

Barikewa A

1500720150Gas (bcf)

3P2P1PReserves

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Offshore Hub

Offshore HubUramu (0.37 tcf)

OSH @ 49.5%Pandora (1.5 tcf)

OSH @ 5%3D seismic scheduled to firm up resource size

Near field exploration opportunities

FlindersPPL 234APPL 293

Angore

Barikewa

Juha

P’nyang

Kimu

Iehi

Korobosea

Flinders

PPL234

Pandora

APPL293

Uramu

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PRL 1 - Pandora Gas Field

5.0Oil Search

16.4ExxonMobil

48.2Talisman Oil Ltd

12.7Command Petroleum (Cairn)

6.4Claremont Petroleum (Beach)

6.4Pacrim Energy

5.0Secab Niugini (ENI)

WI %PRL 1

500km2 3D to be acquired in 2008Untested Upside

Along trend low relief reefsPandora Mesozoic sub reef section

IssuesOffshore development, with slightly sour gas

26401500230Gas (bcf)

3P2P1PReserves

5 Km

D

C

AJ

B

FG

947 948 949

1019 1020 1021

1091 1092

1163

5 Km

D

C

AJ

B

FG

947 948 949

1019 1020 1021

1091 1092

1163

Pandora 1X

Pandora B1X

PANDORA

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PRL 10 - Uramu Gas Field

370275Gas (bcf)

2P1PReserves

Drilled in 1968 by Phillipswater depth 6-10 metres3 km offshore30 km NE from Kumul Terminalintersected a 49m gross gas column

Production tested Uramu-1A at 24 mmscfdReservoir pressure ca. 3300 psi (500 psi over-pressured)Field area 10.2 sq. km

40.5ML Energy Investment Fund Upstream (PNG)

49.5Oil Search

10.0Gedd (PNG) Ltd

WI %PRL 10

URAMU

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PPL 244 – Flinders Prospect

40.0Oil Search

15.0SP Interoil

35.0Talisman Oil Ltd

5.0Drillsearch Energy

5.0IOR Exploration

WI %PPL 244

Flinders prospect is a seismically defined structure with coincident amplitude anomalyNew play type - main risk is on reservoir presence/qualityTechnical COS 10-15%Success here would create considerable offshore supply for in-country development

39001800400Gas (bcf)

23014029Liquids (mmbbl)

P10MeanP90In Place

FLINDERS

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PPL 234

100Oil Search

WI %PPL 234

Licence to immediate east of Flinders prospect (PPL244)Same primary target as Flinders –the Tertiary clastic sequenceSeveral leads identified from 2,900km 2D survey acquired in 2006750km of infill 2D to be acquired 2008 to mature existing leads

PPL234

Flinders Gas Chimney ?

SW NE

2008 Seismic

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APPL 293

20Nippon Oil Exploration Ltd

80Oil Search

WI %APPL 293

Application made during 2007 Gulf of Papua licencing round. Currently awaiting licence awardCovers the offshore/SE extension of the Aure fold beltPrincipal focus is the younger (Tertiary) clastic sequences similar to those at Flinders (PPL244)Structurally complex. Based on current seismic, potential for gas condensate pools in order of >1 tcf5,000km 2D seismic to be acquired in 2008

APPL293

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Commercialisation Options

Oil Search continues to drive the following alternative, complementary and possibly accelerated commercialisation options:

LNG expansion:Higher net OSH equity based on upstream fieldsCommercial and technical flexibility to facilitate expansion

Alternative options:Methanol/DMEGas-to-LiquidsSmall scale LNGF

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Oil Search MENA

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Oil Search MENA LicencesF

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Oil Search in the MENA Region

OSH commenced programme of measured diversification into the Middle East/North African region in 2000Focus is on proven petroleum systems with:

Existing infrastructureLow finding & development costsLow well costs to complement PNG activityProduction & deliverability reliability, rapid first oil

OSH has established key strategic relationshipsSpecific National Oil Companies

Manage regional risk issuesSolid Opportunity flowJoint Operating arrangements

Strong cultural & political relationsExcellent databasesExisting long term relationships

Balance of Operated & Non-Operated areasLow cost entry

Seeking to build material positions

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Why MENA?

Oil Search commenced programme of measured international diversification in 2000Middle East/North Africa (MENA) selected as focus areaRapidly built a material exploration portfolio in areas with proven petroleum systems Oil Search Production Sharing Agreements (PSAs) have attractive fiscal termsMENA has multiple near term drilling opportunities

Cost of typical onshore exploration well ~US$2–6 millionTarget sizes range from 5–100mmbblsLow capital and opex (typically <US$3/bbl and US$4/bbl respectively) with short payback periods

Complements PNG high cost, higher reward prospectsAccess to producing infrastructure in key basins Moderate/high security risk, but manageable

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Portfolio Build in Progress

In past 12 months, OSH has initiated: 2 drilling rig campaigns in Yemen – onshore and offshore

4 rigs in Egypt – 2 drilling and 2 workover

Further production operations with our quality HSES program embedded

Achieved significant drilling performance improvements in each campaign

Resolved challenging cultural issues in new areasF

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Portfolio Build in Progress

Technical challengesWe haven’t satisfied our exploration objectives

Score = 2 / 11 dry holes in Yemen

= 5 / 5 in Egypt, ERQ & 2nd’y targets in Egypt Area A

= 1 / 1 in Kurdistan

Higher risk end of the portfolio has been drilled in Yemen

So far frontier areas – B15, B35, Bina Bawi

Moderate risk basinal plays with 3D data – B43, B49, ERQ

Mature plays in structurally complex areas with limited ability to de-risk in Area A

Performance over a three year period will be the better judge, cannot achieve portfolio evaluation within calendar year

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Portfolio Build in Progress

Portfolio ManagementProgramme de-risking occurred prior to much of 2007 program

3D seismic available to technically de-risk many prospects –B15, B43, B49, ERQ

Block 3 acquiring 3D, farmed down to 40%

US$22m exposures reducedB3, B15 and B35 farmed down for carries

Farmed in to B49Acquired 42% from CCC in 2007Farmed out 26% in north area to Virgin for full carry on 2 wellsRetained 42% in southern area with option to increase

Technical de-risking still ongoingProduction testing as an effective appraisal tool

2D/3D seismic being acquired

Area A farm-out ongoing

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Portfolio Build in Progress

Portfolio is the envy of numerous competitorsBalance of higher/lower risk with high/lower reward

Operational skills are highly valued

Creates opportunities that OSH can capitalise on

Materiality still not there

Lacks a solid production element

Existing fields immaterial

Discovery & rapid development required

Acquisitions are still being reviewed

Further portfolio optimisation will continue

… lack of production is causing significant P&L pressures due negative impact of higher effective tax rate

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Egypt Area AProduction

Oil Search earns production above specified base production levelSince August, have been in ‘earning’ territory

2 month delay to the start of the development drilling programme, due to the unavailability of a suitable drilling rig

Ongoing workovers /recompletions required in mature fieldsAdditional development candidates under evaluation

Not in forecastNo reserves booked for Area A to dateEstimated 2008 net production of +150mstbo (after 30% farmout)

Jan-

07Apr

-07

Jul-0

7Oct

-07

Jan-

08Apr

-08

Jul-0

8Oct

-08

Jan-

09Apr

-09

Jul-0

9Oct

-09

0

1,000

2,000

3,000

4,000

5,000

6,000

Oil

Pro

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Development Wells

Work-overs

Gross Production

Net OSH

Baseline +500

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Egypt ERQ Production

Early production from new discoveries awaits approval from EGPC and inauguration of new OpCo - PetroshardCritical reservoir deliverability information required to assist with further appraisal and development plansShahd-1 production will commence as early as Dec 2007 via trucking operationGhard-1 and Rana-1 production to follow soon after, also to be truckedField reserves to be certified by NSAEstimated 2008 net production of 185mstbo

East Ras Qattara

0

500

1,000

1,500

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2,500

3,000

3,500

4,000

4,500

Jan-

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Jan-

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-08

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Jan-

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Oil

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Net OSH

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Yemen Nabrajah Production

Nabrajah-15

Nabrajah-16

Nab15

Nab16 0

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2,000

3,000

4,000

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7,000

8,000

9,000

Jan-

07Apr

-07

Jul-0

7Oct

-07

Jan-

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8Oct

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Net OSH

Nabrajah gross production currently 6,650bopdNabrajah-15 well has proven a new terrace/compartment within the fieldCurrently drilling Nabrajah-16Simulation model being finalised to assess viability of future candidatesEstimated 2008 net production of 268mstbo

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EgyptExploration

East Ras Qattara, Western Desert

49.5% equity; PSAOperator SiPetrolOngoing exploration programme in ERQ

Area ‘A’, Gulf of Suez4 development and 2 exploration concessionsOSH operator, 100% equity: PSA & ESAExploration scheduled to recommence in Area A in 4Q07

Mesaha Block 630% equityOperator Melrose

2007 OSH Egypt spend around US$40m

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3 wells drilled to date3 discoveries at 4 stratigraphic levels

Development plans submitted for Shahd and Ghard. Production in 1Q 08No reserve additions booked to dateFurther 3D seismic acquired in 2007 and planned in 2008Rana :

Flowed 850 bbl/d from Kharita on small choke Test on 3 Bahariya zones to resume with w/o rig

Extensive prospect inventory Next wells :

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

East Ras Qattara“String of Pearls”

Rana-1Discovery

Ghard-1Discovery

Shahd-1Discovery

Raheek-1 currently drilling, to be followed

by Salma Prospect

5km

East Ras Qattara, Western Desert49.5% equity; PSAOperator SiPetrolF

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East Ras QattaraExploration Success and Prospects

and Leads

76

Well Name OSLOil Inventory EquityShahd Discovery Shahd 1 0.495Ghard Discovery Ghard 1 0.495South Shahd 0.495Fahd (SE Shahd) Shahd SE 1 0.495Riffy Raheek 1 0.495Rana (Prospect K) Rana 1 0.495Mesk Mesk 1 0.495SE Mesk SE Mesk 1 0.495Rana NE Rana NE 1 0.495Rana SE Rana SE 1 0.495Dia'a Marwa 1 0.495Heba Rehan 1 0.495Salma (Prospect G) Salma 1 0.495Yara (Prospect F) Yara 1 0.495Yara NW Yara NW 1 0.495Prospect E (J Milha Updip) 0.495Prospect H 0.495Prospect I 0.495Prospect J 0.495Lead 1 0.495Lead 2 0.495Lead 3 0.495Lead 4 0.495Strat Lead North 0.495Strat Lead Central 0.495Strat Lead South 0.495Gas InventoryAlam El Boueib Gas 0.495

Remaining Prospects25+ Remaining P&L2x 3D surveys acquired

Raheek-1Drilling

Rana-18mmstbo 2P

Ghard-12.6mmstbo 2P

Shahd-16mmstbo 2PProduction to

commence 1Q 2008

25 + prospects now defined by seismicProbability of success >40% - first three wells are discoveries (100% success)2 new 3D surveys planned – commencing in December 07Mean field size 5-10mmbo with 4 prospects/leads >50mmboRig availability is challenging – 2 to 3 rigs required through 2008 and into 2009

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East Ras QattaraDevelopment Plan

Currently developing a full potential development plan for ERQPotential peak gross production of 150-200 kboepdPotential gross reserves 300 mmboe+“String of pearls”exploration program –15-20 wellsFull potential development concept

Cluster development with central production facility Tied in to existing infrastructure north of the block180-200+ development wellsGross development cost of US$1b+

East Ras Qattara - Oil Search Production & Cost Profiles

0.0

50.0

100.0

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2007 2008 2009 2010 2011 2012 2013 2014 2015

Cap

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)

Total Capex Total Opex Total Prodn. Rate

Northern Gas Development

Southern Large Cluster Development w/ single CPFNorthwestern Small Cluster DevelopmentFor

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Egypt Area A Exploration

Proposed South Gharib-X1

Yusr-AyunAppraisal

Shukheir Bay

Onshore Propsect

Proposed West Zeit-X3

Coastal Leads

El Khalig Appraisal

Shukheir Appraisal

Three well exploration drilling program to commence in 4Q 2007

West Zeit-3South Garib-1Shukheir Bay Onshore-1

In the event of a discovery, rapid tie-in to nearby facilities

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Participation in 11 exploration wells2 successes (Nab 13 & 15) & 9 dry holes to date (3xB49, 2xB15, 2xB35, 3xB43)

B49 – large residual columnsB15 – downgrade deeper areasB43 - disappointingB35 – proved working hydrocarbon system in block

4 successful wells: Block 432 on production2 completed

2 wells tested1 flowed 0.065 mmscfpd: Block 351 water: Block 49

Yemen: 2007 Drilling CampaignResults

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Yemen Block 43

Block 43

Nabrajah field

Proposed Shaibah-1

400sqkm 3D Seismic Survey

Basement Structure Map

OSH 28.33%, non-Op (DNO)Interpretation of 3D dataset has identified multitude of in-fill and exploration targets on-trend with Nabrajah Oil FieldIntegrated study of the Nabrajah Naifa & Basement reservoirs ongoingJV considering plans to drill 2-3 exploration wells in Block 43 in 2008

N1

C10

C4-W

D2

C8

C7

Nabrajah Field

D3

C11

N3

N2

Qishn

Basement

Shallow

Deep

Shallow

Deep

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Yemen Block 49

OSH 31.75% Non-Op(CCC, OSH Drilling Op)

2 additional Exploration wells planned for 4Q 2007 (OSH being fully carried)Ghobata-1 & Kasad-1 wells have residual oil column Significant oil & gas shows prove oil charge across the northeast margin of Block A number of large untested structures still flank the Shabwah Basin in Block 49

Mintaq-1:Oil & Gas shows in Kohlan/basement, Lam, & Qishn

Mature Sourcekitchen

Lead B

Lead C

Lead D

Lead E

Balharak-1:Minor Oil & gas shows

Hufayr-1:Oil & Gas shows in lower section of wellGas condensate discovery

Balharak South-1:Excellent Oil & gas Madbi/Basement tested oil & gasApprox 110bbls of oil recovered

West Ghobata

Lead F

Al Nokhailat-1

Kasad-1

Gohbata-1 Ghobata-1:Oil & gas shows

Kasad-1:Oil shows

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Yemen Block 35

OSH 32.5%, OperatorAl Magrabah-1 flowed small quantity of gas & recovered 34 API oilProves working petroleum systemProspectivity established, requires further review, analysis, and de-risking

DST#1

DST#2

Al Magrabah-1 Test

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OSH 35.0%, Operator6 Month licence extension granted, additional 12 month extensions requestedWell results to be integrated into review of remaining prospectivitySharmah-Ras Ghashwahdiscovery to be re-evaluated during licence extensionDeeper Jurassic / Basement targets under evaluation

Yemen Block 15

Block 15

Shuhayr-1 Prospect

165MMbbls

Sarar-1X Recovered 1700 litres 45° API oil from Cretaceous sands

Ras Ghashwah-1X Recovered 38° API oil from fractured Eocene limestone

Hami-1XHeavy oil &

bitumen

Sharmah-1XProduced 3045bopd 43°API oil from fractured

Eocene limestone

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OSH 40%, OperatorPSA Ratified 7 June 2006OMV’s recent Habban-1 Basement discovery in Block S2 and YICOM’s West Ayadfields are on-trend to untested basement structures identified in Block 3Potential mean reserves range 20 - >100 mmbbls500 sqkm 3D seismic starting late 2007Subject to rig availability, OSH will seek to drill 1 well in Block 3 in 4Q 2008

Block 3

Yemen Block 3OMV Habban

New Basement Discovery>750m oil column

Seri

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Stag

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Def

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Nay

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tayn

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169

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1 3 4 7 -2 1 4 8

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OSL

OSL

OSL

OSL

OSL

Historical Focus = No Success

Oil Search Opportunity

West Ayad Field ~500sqkm 3D

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OSH 34%, OperatorPSA signed by Minister 15 April, awaiting ratificationOMV’s recent Habban-1 Basement discovery in Block S2 and YICOM’s West Ayad fields are on-trend to untested Basement structures identified in Block 7Potential mean reserves range 20 - >100 mmbblsThe block is close to infrastructure4 firm wells commencing 2009

Yemen Block 7

Block 3

Block 7

Block S2

Block 8

Block 2

OSH 34%

OSH 60%

OMV HabbanNew Basement Discovery

>750m oil column

S N

Tilted Block

Strat . Traps

Tilted Block

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Blocks 3 & 7Multiple Plays & Analogues

Block 10 Kharir Basement Field ~ 1 Billion mmbbl

Block S2 HabbanBasement Field ~ 350 mmbbl

Seri

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Stag

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Form

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Lith

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Def

ined

Top

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US

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Nay

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tayn

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Nay

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gini

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OSL

OSL

OSL

OSL

OSL

Historical Focus = No Success

Oil Search Opportunity

S N

Tilted Block

Strat . Traps

Tilted Block

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Block 74OSH 34%

Nabrajah

Block 14 Fields>1.2 billion bbls

reserves

OSH 34% OperatorPSA signed by Minister 15 April 2007, awaiting ratificationBlock lightly explored with potential for Basement and conventional Qishn/Saar/Kholan playsPotential mean reserves range 20 - +50 mmbblsThe block is close to infrastructure3 firm wells commencing 2009

Yemen Block 74

Lead A

Quzah West Laed

Lead B

Quzah BasementLead

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Yemen: Remaining 2007 Activity

Nabrajah-16

BLOCK 7

BLOCK 3BLOCK 15

BLOCK 35

BLOCK 74

BLOCK 49

BLOCK 43

ShirTerminal

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

North Ghobata-1(10mmstbo, COS=20%

500sqkm 3D

Remaining 2007 Activity2 Exploration Wells in B49 testing total ~130mmbbl, OSH fully carried1 B43 Exploration & 1 Nabrajah Appraisal500+sqkm 3D in Blocks 3, continuing into Block 7 in 2008

Dahgah-16mmstbo,

COS = 30%

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5 Year Exploration Period (ends May 2010)Commitments:

2000 km 2D seismic (completed)500 sqkm 3D seismic (completed)1 Exploration well (to be drilled 4Q 2008)

Libya Area 18

10000km2

Petrobras 70%Oil Search 30%

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Libya Area 18Prospects and Leads

Reserves Range 100 –450MMbbls

1 Prospect and 3 Leads identified in the block1664km 2D and 830 sqkm 3D Seismic acquisition completed in 20071 exploration well scheduled 4Q08

Libya

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Tunisia

Tajerouine 100%, operator (to be ratified)

Obligation 1st 4 year period 2D seismic and 1 well

Forward ProgramSigning at the end of October and licence effective 1Q 2008Strong interest from strategic partners to participateStudies & reprocessing in 2008Seismic in 2009

Le Kef 50% & control on operations (to be ratified)

Obligation 1st 4 year period 2D seismic and 1 well

Forward ProgramSigning by end of 2007 and licence effective 1Q 2008Studies & reprocessing in 2008Seismic in 2009

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IRAN

IRAQ

SAUDI ARABIA

SYRIA

KUWAIT

TURKEY

Baghdad

Mosul

Tikrit

Kirkuk

Zakhu

BasrahOil Field

Gas FieldOil & Gas FieldGas Pipeline

Oil Pipeline

Oil Field

Gas FieldOil & Gas FieldGas Pipeline

Oil Pipeline

KurdistanRegion

0 200km

Iraq – Kurdistan ProvinceBina Bawi EPSA

Strategy20% equity in A&T Petroleum, option to convert to 10% direct EPSA interestLow cost, medium-long term positioning strategy

Establish a position in the prolific ZagrosStrategic position in future Western European energy marketsExposure to large, low risk potential reserves >500 mmbbls - ~2.0 bnbbls

Reasonable and secure EPSA Contract:20yr termRoyalty/production sharing

Bina Bawi EPSA

Kirkuk Field17 billion bbls

Taq Taq Field15,000bopdAddax/G-Energi

DNO Tawke-1wellFlowed oil 7,000bopd from zone at 350m

Bushyhr Project IranKEPS/OSH/Kufpec

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KurdistanBina Bawi Potential

Proven Petroleum SystemLarge surface anticline: 350 sqkm; 800m closure For comparison: Kutubu 40 sqkmBina Bawi-1 and Bina Bawi-2 wells completed

Gas tested at 6 mmscfdOther zones not yet testedMechanical issues, further appraisal / testing required

Currently acquiring 250km 2D seismic program

Bina Bawi Surface Anticline:

P10: 800m vertical closure40x8km area

P90: 100m vertical closure 9x2 km area(similar area to Kutubu)

Bina Bawi-1 Well Location

Bina BawiEPSA

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New Business Summary

Exploration - Organic GrowthBuild materiality around existing core areas

Develop assets that have operational synergies

Focus on material step out opportunities Build on established relationships with local partners and NOC’s

Establish reputation in focus areas as operator / partner of choice

Technical excellence and transparent operating style with partners and GovernmentsFocus on Health, Safety, Environment and Security and social development programsLocalisation program & commitment to training opportunities for staff and gov’t secondees

Assessing material acquisitions

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MENAFocus, Activity and Results

Libya•Entry strategy•1 non-operated area (Petrobras

operator)•Acquired 1664km 2D seismic and

830sqkm 3D in 2007•1 prospect (250mmbbls+ potential)

and 3 leads•Drilling 1 well 4Q 2008

Egypt•Building material exploration position•6 Operated & 2 Non-operated•4 of these are development licences with production•ERQ

• 3 successes (Ghard, Shahd and Rana 7-10mmbo each)

• 25+ additional prospects requiring 2+ rigs• <2 years remaining on license• Require continuously active drilling program

•Area A Expln• 2 Nubia test have come in deep & wet• Incremental oil in shallower horizons• Next expl wells in 4Q 2007, seismic interp’n ongoing

•Block6• 1 well & seismic obligation, well in 2009/10

Iraq (Kurdistan)•Medium-long term

positioning strategy•10% indirect

participation in Bina Bawi EPSA

• Bina Bawi drilling program completed

• Currently acquiring 250km 2D seismic data

•Evaluating other material opportunities

Tunisia•Building material exploration

position•2 blocks captured (1 operated) – to

be ratified 1Q 2008•Work program for each area

includes 2D seismic and 1 well

Yemen•Material exploration position, largest licence holder in country•5 operated & 2 non-operated area•1 of these is a development licence with production (Nabrajah)•Prodn ahead of forecast but upside remains tantalising•Exploration program – 2 successes (Nab 13 & 15) & 9 dry holes

to date (3xB49, 2xB15, 2xB35, 2xB43)• B49 – large residual columns• B15 – downgrade deeper areas• B43 - disappointing• B35 – proved working hydrocarbon system in block

• Initial results disappointing but strong shows in B49 & B35 and proven oil in B15 attest to active petroleum systems

•Subsurface de-risking required in 2008 including 3D seismic in B3, B7 and potentially B49 (dependent on extension)

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MENA2007/2008 Activity Schedule

2007 2008

3Q 4Q 1Q 2Q 3Q 4Q

Offshore

Onshore (OSH Operated)

Seismic

Onshore (DNO Operated)

Wildcat exploration well

Development Well

EGYPT

Seismic

Commitment Well

YEMENBlock 49

West Ghobata

Block 49Balharak

North

Block 3

Offshore well

Block 43Thoub-1

Onshore A

Onshore ERQ

Blk43Nab-15

ERQRaheek-1

Block18Caliph-1

ERQ North(1000 sqkm)

Block 6(AeromagEgypt

Yemen

Libya

S GharibW ZeitS-22 Area AShukheir BayY-51Y-50

ERQRana-1

ERQSalma-1

ERQSE Shahd-1

ERQYara-1

ERQYara-1

ERQNW Lead

ERQSE Mesk-1

ERQYara NW-1

ERQ Centre(1000 sqkm)

ERQNE Lead

Zeit Updip

Blocks 3 & 7(500 sqkm)

Block 35Reeb-1

Blk43Nab-16

Blk43Dev’t

Block 43Dahgah-1

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MENA Specific Issues

MENA licences are Production Sharing Agreements compared to PNG licences which are Tax/Royalty

Except Egypt Area ‘A’ which is a Revenue Sharing Service Agreement

Production Sharing Agreements allow for Cost Recovery and Profit Sharing between the Contractor and the Government

Not subject to income taxCosts (exploration, development and operating) are recoverable against any future production subject to a cost recovery limitRemaining revenue after cost recovery is shared between the Contractor and the Government

For Oil Search, MENA costs (including unsuccessful exploration expenses) are not tax deductible against PNG income because of PNG tax law

However, costs are recoverable against any future productionExploration costs in Egypt Area ‘A’ are tax deductible (it is a Revenue Sharing Service Agreement)

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PNG Oil Operations

AGENDA:PNG Production:

2007 update2008 focus areasLife of field

Operating Environment:Rig update and strategyCost environment

Oil and Gas Interface IssuesPNG Oil ExplorationCorporate Summary

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PNG Production

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2007 Update

Overall:

Underlying field performance is strong in all fields and reservoir management activities have been encouragingKutubu:

Decline has largely been mitigated by UDT7 and reservoir management activities. Performance of UDT7 remains encouraging

Moran:Impacted by NW Moran shut-in for 6 months and the poorer performance of M6 post-workover. Issues resolved in 2H and 2007 forecast to exceed 2006 by 5%

SE Mananda:Steady as a result of the improved field management

Gobe Main: Adversely affected by the gas compression shutdown during 4Q’06. Programme to convert to Upper Iagifu production is proceeding well

SE Gobe: Adversely affected by the gas compression shutdown. The Wedge area (SEG11) continuing to perform well

Hides:1Q production affected by Porgera JV turbine maintenanceOperations resumed during 2Q and demand is currently exceeding forecast

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2008 Focus Areas

Usano:4-6 development wells, optimised

with Arakubi outcome

SE Gobe:Possibly 1

development well

Kutubu:2 development wells

and selected workovers

Agogo:Possibly 1

development

Moran:3 development wells

and selected workovers

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Kutubu

Potential poorly drained saddle

area

2008 PlanA continuous drilling campaign at UsanoKutubu wells in 2H with 2nd rig5-8 workovers anticipated in 2H 2008Develop focussed waterfloodplanFurther optimise gas injectionUsano and Kutubu wells provide competitive returns on investment

Usano redevelopment

5,000

10,000

15,000

20,000

25,000

30,000

Jan 06 Jan 07 Jan 08 Jan 09

bo

pd

P50 RatesP10 Rates

Base (P50)History

P90 RatesFor

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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 well and above expectation4 – 6 wells likely in 2008First two wells confirmed at UDTG and UDT C, remaining programme to be optimised based on Arakubi outcome

UDTJ

UDTH

Potential Usano well

Likely Usano well 2007-8

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Moran Development

Moran infill well

5,000

10,000

15,000

20,000

25,000

30,000

MR (B Block)

M10 ST2 (J Block)

MZ (K Block)

2008 PlanDrill new infill wells:

Downdip producer MZ in the NWCrestal gas injector MR in B block Downdip producer M10 sidetrack

Optimise well rates and balance off take with injectionControl well GOR with rate control, by changing zones and swing well managementThe three Moran wells provide competitive returns on investment

Jan 06 Jan 07 Jan 08 Jan 09

bo

pd

P50 Rates P10 Rates

Base (P50)History

P90 Rates

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Gobe Main 2008

2008 PlanContinued emphasis on maintaining current production rates through 2008Consolidate Iagifu A production from up to 4 zone changes:

GM4ST3, GM2ST1, GM1ST2, G2X (Hedinia)

Water handling and gas compression optimisationImplement options to return GM7 to production

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

Jan 06 Jan 07 Jan 08 Jan 09

Bo

pd

P10 Rates

P50 Rates

P90 Rates

Base (P50)History

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SE Gobe 2008

2008 PlanImplement options to bring SEG 1ST1 on line, and access Iagifu B in SEG 8 Maintain water injection support to SEG WedgeWater handling and gas compression optimisationPossible infill/appraisal well subject to technical work (not included in forecast)

Iagifu B target in SEG 1 Block area Iagifu A/B Target in G7X block area

4,000

2,000

8,000

Jan 06 Jan 07 Jan 08 Jan 09

bo

pd

P50 Rates

P90 Rates

Base (P50)History

6,000

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SE Mananda 2008

2008 PlanContinue to revise geological & reservoir models to improve understanding of field and make better performance predictionsContinue to improve uptime efficiencyUse well production data to improve understanding of field structure and drainage volumes

-

1,000

2,000

3,000

4,000

Jan 06 Jan 07 Jan 08 Jan 09

bo

pd

P50 Rates

P10 Rates

Base (P50)History

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PNG Gross Production

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

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

Oil P

rod

uct

ion

(b

op

d)

P10P50P90

Natural decline

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Life of Field

Life of field analysis being conducted:Reviewing track recordFull resource potential of fieldsCost effective ways to optimise reserves and production.

Work in progress at the moment but positive initial results:60 mmstb+ unrisked potential from 40 activitiesRisked P50 contingent resources of 17 mmstb estimated

Source: RISC

PNG Reserve Addition Potential 5 year lookahead

0

10

20

30

40

50

60

70

Unrisked Total EUR Adds

Unrisked 2C EUR Adds

Risked 2C EUR Adds

EU

R A

dd

s m

mst

b

Kutubu

Moran

Gobe/SE GobeSE Mananda

Kutubu

MoranGobe/SE Gobe

KutubuMoranGobe/SE GobeF

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Life of Field

We have consistently underestimated production 3 to 5 years out:

Focus on the benefit from next year’s activityRisking less mature opportunities

Probabilistic forecasting tool will assist in improved forecasting of production in the near term

PNG Oil Production Budget Forecast vs Actual 2002-2007

Source: RISC

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PNG Operating Environment

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PNG Rig Update

Rig 101:Refurbishment, commissioning and crewing successfully completedCurrently drilling KoroboseaFuture plans include Cobra, Wasuma and possibly Barikewa or Gobe

Rig 3:Commissioning complete and rig being mobilised to siteDrilling contractor secured and resourcing on trackTarget early December 07 spud for Usano campaign – sites and flowlines ready

Rig 226:Drilling Arakubi sidetrack then to NW Paua by roadThen to Moran for development wells

Rig 4:Delivery 3Q08. Costs maintained

New Rigs provide upgraded capability and dual sub-structure and mast to improve drilling efficiency and minimise moving time between wells

Strategy review considering the optimum rig numbers, balancing future development, exploration and appraisal requirements for oil and gas and the optimum cost structure

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Cost Management

Cost pressures:Impact of A$ appreciationInflationary pressures:

CommoditiesTransportation costsEquipment and contractor costsDrilling consumables

Mitigation measures:Ongoing tight cost control High grading of opex projects Overhead challenge Special projects:

Aviation efficiency Supply chain optimisation

Target:Small increase in 2H07 due to planned MEJs, strong dollar, targeting no real increase in per barrel costs in 2008

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Oil and Gas Interface

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Oil and Gas Interface

Oil fields provide significant P1 and P2, low development cost gas resource to the LNG projectGas development provides benefits to the oilfields:

Operating cost sharing Reserves bookings and amortisation improvementsPossible tax rate improvements subject to negotiation with the StateIncremental pipeline tariffsIncremental condensateAbandonment cost deferral

Current thinking:Oil Search remains Operator of the oil fieldsOil fields have gas delivery obligations but retain flexibility to optimise oilGas offtake has positive impact on oil production and appears rate insensitive

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PNG Exploration

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PNG Exploration 2008

Oil - Remaining 2007 & 2008 programme testing ~25-30 mmbbl net risked reserves

Gas – exploration/appraisal to add reserves to support commercialisation projects –testing ~30mmboe net risked reserves

PNG 2007 exploration budget US$120m net

Planned 2008 exploration budget up to ~US$80m net subject to budget reviews

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

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

Korobosea

Barikewa

NW Paua

Cobra

Wasuma

Flinders

ArakubiMananda Attic

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PDL 2 - Arakubi

14.5ExxonMobil

11.9AGL

6.8Merlin Petroleum

6.8PRK

60.0Oil Search

WI %PDL 2

Located 2km from infrastructure, connected by roadArakubi 1A proved the presence of excellent Toro and Iagifu reservoirsStructure is folded tighter than initially mapped. Mean reserves now ~15 mmstb Up dip side track underway

Reserves: 15 mmstbCOS: 50%

* ExxonMobil did not participate in initial Arakubi well

Line PN04-411Depth migration

Usano 2x block

UDT4 block

Arakubi structure

APF

Moro

Ridge CampCPF

SE Mananda

Moran

Paua

LakeKutubu

Agogo

ARAKUBI

PDL2

10km

Kutubu

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Bawia

Juha

Alene

Toro

Hedinia

Iagifu

PDL 2 - Arakubi

South North

Possible deepeningof sidetrack?

UEBT Thrust Fault?

Arakubi 1A

Backlimb of Usano Main Block – c. 40 deg dips

Possible extension ofUsano East block

Fault penetrated@3184mMD

Possible steep thrust

Schematic section – well currently at top reservoir in sidetrack

Arakubi 1A sidetrack

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PPL 233 – NW Paua

47.5Esso Highlands

52.5Oil Search

WI %PPL 233

Highly prospective structure adjacent to MoranDigimu target with Toro secondaryLarge upsidePartially 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 Q4 2007 after Arakubi

Reserves: 40-120mmstb (depends oncolumn 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

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PPL 190 – Cobra

26.5Murray Petroleum

10.9Cue PNG Ltd

62.6Oil Search

WI %PPL 190

Near field exploration opportunitySeismically defined structure adjacent to SE GobeTest of Footwall play with potential to open up a significant new fairwayIagifu sandstone is primary objectiveWell site under constructionTo spud late 2007 after Korobosea

Reserves: 30-40mmstbCOS: 17%

Gobe Unit

Gobe Main

COBRA

PPL219

SE Gobe

PPL190

PDL4

Iehi

PDL4PDL3

10km

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PPL 219 – Wasuma

8.75Merlin Petroleum

91.25Oil Search

WI %PPL 219

Reserves: 30-40mmstbCOS: 20%

Near field exploration opportunitySeismically defined structure to north of GobeOne of the last un-drilled ‘simple’ Hanging wall structure within the main Foldbelt trendIagifu sandstone is primary objectiveWell site construction scheduled to start late 2007To spud Q1 2008 after Cobra

Gobe Unit

Gobe Main

WASUMA

PPL219

SE Gobe

PPL190

PDL4

Iehi

PDL4PDL3

10km

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PPL 219 – Mananda Attic

8.75Merlin Petroleum

91.25Oil Search

WI %PPL 219

Prospect updip from Mananda 3 and 4Site construction to commence Q1 2008Drilling late 2008/early 2009

Reserves: 30-70mmstb (depends on fluid phase and number of reservoirs)

COS: 20%

APF

SE Mananda

Moran

Agogo

MANANDA ATTIC

APDL6

PPL219 PPL233

Paua

Kutubu

PDL5

PDL210km

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PNG Exploration - Gas

Two core areas;

ForelandKorobosea (0.5 tcf @ 19% COS, OSH @ 90%)Kimu (0.85 tcf)OSH @ 60.7%Barikewa (0.72 tcf)OSH @ 42.5%Farm-in opportunities

OffshorePandora (1.5 tcf)OSH @ 5%Near field exploration opportunities

FlindersPPL 234APPL 293

AngoreJuha

P’nyang

Iehi

PPL234

APPL 293

Uramu

Pandora

Flinders

BarikewaKimu

Korobosea

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PNG Q4 2007 - 2008 Exploration

Oil exploration25-30mmstb net risked reserves being testedNet well cost ~US$60mArakubi, NW Paua, Cobra, Wasuma

Gas - Co-ordinated programme to add reserves to support commercialisation projects

Exploration1 well - Korobosea Net well cost US$22mPossible Flinders offshore well late 2008

Appraisal1 gas appraisal well - BarikewaNet well cost US$8mFor

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PNG Q4 2007 – 2008 Exploration Cont.

Continued seismic for gas and oil exploration/appraisal

Highlands 50km firm, up to 100km depending on well resultsOffshore

Up to 1,000km infill for PPL 234Up to 5,000km regional grid for APPL 293Possible 3D over Pandora

Ongoing review of farm-in opportunities onshore and offshoreTotal 2008 PNG exploration budget up to US$80m net (subject to budget)

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Corporate Summary

&Strategic ReviewF

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Snapshot of2007 First Half Results

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

* 1H06 NPAT excludes profit of US$258.5 million on sale of licence interests to AGL

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Some Cost Pressuresin First Half

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

46.5

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

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Strong Balance Sheetat June 2007

US$487 million in cash at end June, no debtUS$163 million in undrawn committed bank lines (refinancing planned at year end)Final 2006 dividend of US 4 cent dividend (US$44.8 m) paid in March 2007No oil hedging undertaken during 1H07 or currently in place

US$’m

0

100

200

300

400

500

2004 2005 2006 Jun-07

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Revenue update at30 September 2007

6,3336,406Oil Sales volume (mmbbl)

471.3457.2Sales Revenue (US$m)

17.77.8Other Revenue

489.0

73.75

7,308

9mthsTo Sept

07

465.0Total

70.30Oil Price (US$/bbl)

7,535Oil & Gas production (mmboe)

9mthsTo Sept

06

2006 2007

Total Revenue YTD

0

184.4184.43Q3Q

304.6304.61H1H

318.1318.11H1H

146.9146.93Q3Q

500

200

300

400

100

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Capital update at30 September 2007

114.757.3PNG

Exploration & Evaluation (incl. gas)

60.4109.8Development and Production

277.1

48.7

53.3

30/9/07

198.0

11.3Rigs etc

19.6MENA

30/9/06

Capital Expenditure

YTD 2006

YTD 2007

Capital Spend

0

168.0168.0ExpExp

60.460.4DevDev

109.8109.8

76.976.9

11.311.3

48.748.7RigsRigs

Exploration Expensed

100.329.0

46.911.2MENA

53.417.8PNGYTD

300

100

200

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Update on Financial Outlook for 2007

Oil Search remains unhedged, pure exposure to oil pricesSecond half field costs in PNG expected to be slightly higher than the first half, as advised at half yearSecond half corporate costs expected to be slightly higher, due to impact of strong Australian Dollar. Vigorous cost cutting taking place to ensure increase is not materialAmortisation rate expected to average around US$13.00/boeEffective tax rate estimated at 60-64%, very dependent on overall MENA result and impact of MENA exploration expense

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Update on Capital Outlook for 2007/08

Cash at end September US$405.4m, no debt outstandingTargeted refinance of corporate (oil based) facility early in 2008. Refinance not expected to be impacted by sub-prime issues but sensible to defer refinance to new yearExploration and gas expenditure remains on target for upper end of US$230-240m half year guidance for 2007Development expenditure likely to be a little lower than US$100 million, rig/corporate expenditure close to US$65m target2008 exploration spend expected to remain around initial target of US$120m (ex gas), gas costs around US$60-70m, and development/production expenditure higher than US$125m half year outlook. These costs remain subject to detailed budget review and are indicative onlyF

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StrategicReview

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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

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Strategic ReviewSome Early Insights

Oil ProductionMaterial volume remaining in discovered PNG fieldsReview of “life of fields” being undertakenWell and work-over investments have delivered strong returns2008/09 programme robustNew forecasting tool to give greater long term reliabilitySensitivities to opex being analysedFocus on drilling performance and cost reductions, close monitoring of new rig performance and logistics management

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Strategic ReviewSome Early Insights

Gas CommercialisationEM led LNG Project

Work to ensure optimum commercial position in projectEconomic robustness and viability fully testedValue optimisation of oil and gas, with identified synergiesProject risk managementOptimal financingGame changer for Oil Search

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Strategic ReviewSome Early Insights

Gas CommercialisationOther possible developments

Reviewing resource base and value options1-1.5 tcf clusters

Review development models, pipeline optimisationCorporate positioning, options for staged growth

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Strategic ReviewSome Early Insights

Exploration - PNGReview of potential and optimal programme for appraisalIntegrated drilling programme, with development activity, rig numbers etcActive portfolio management

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Strategic ReviewSome Early Insights

Exploration – MENAReview of value of all assets, definition of full potential, investment requirements and timing of value incrementsAsset tiering and rankingOptions definitionExpect active portfolio management

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Strategic Review

Organisation to deliver

Initial results at year end, with rollout in 1Q, 2008

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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

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Outlook for 2007

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

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Outlook beyond 2007

Rig delays push production into 2009

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

Chart includes risked production contribution from firm one year exploration programme

0

Jan-

2007

Jan-

2009

Jan-

2011

Jan-

2013

Jan-

2015

Oil

Pro

du

ctio

n (

bo

pd

)

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

For

per

sona

l use

onl

y

147

Summary

Company value growth will be driven by commercialisation of its 1 bnboe quality resource. Strong momentum build for LNG Development, with likely 30% in world scale project

Core business robust, with strong cash flows and Balance Sheet to support development options

Material reserves upside from ongoing exploration programme in PNG and Middle East

Strategic focus on building business to first gas, optimising oil and gas synergies, and positioning for multiple gas developments

For

per

sona

l use

onl

y