1 2009 Full Year Results Agenda - Oil Search · 5 2009 Performance Summary ¬NPAT of US$133.7 million, US$99.6m excluding PNG Government back-in and tax adjustments ¬Satisfactory

1

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

2

2009 Full Year Results Agenda

Performance Summary Peter Botten

Financial Overview Zlatko Todorcevski

PNG LNG & Gas Expansion Phil Bainbridge

Operations Review Phil Caldwell

Outlook & Summary Peter Botten

3

2009 Full Year Results






4

2009 Performance Summary

Highlight of 2009 was PNG LNG Project development decision:

Less than two years from FEED to Sanction

Transformational impact on Oil Search and PNG

ExxonMobil quality operator

Foundation for major LNG industry in PNG

Seven fold increase in proven and probable reserves, increasing from 67 mmboe to 567 mmboe, with significant further potential upside

5

2009 Performance Summary

NPAT of US$133.7 million, US$99.6m excluding PNG Government back-in and tax adjustments

Satisfactory result given commodity environment, with average oil price down 35%

Strong balance sheet with US$1.3 billion cash. Total liquidity of US$1.6 billion (including line of credit). Sufficient for both PNG LNG equity contribution plus funding of T3/T4 gas exploration/ appraisal programme

Board approved final dividend for 2009 of 2 US cents, making 4 US cents for the year. Funded by fully underwritten Dividend Reinvestment Plan

6

Outstanding Safety Performance

Total Recordable Incidents (TRIs) of 1.16 in 2009

TR

I /

1,0

00

,00

0 H

ou

rs

0

2

4

6

8

10

12

14

1998 1999 2000 2001 2002 2003 2004 2005 2007

Oil Search

2006

Australian Companies (APPEA)

2008

InternationalCompanies

(OGP)

12.7

9.1 9.37.8

7.0 7.3

5.2

9.4

8.2

6.3 6.8

3.9 3.1 2.9 2.7 2.1

4.0

3.6

4.9

5.76.0

2009

8.5

10.69.8 10.7

5.8

1.7

4.7

2.4 2.31 2.05 1.162.04

7

Strong Five Year Share Price Performance

Jan 05 Jul 05 Jan 06 Jul 06 Jan 07 Jul 07 Jan 08 Jul 08

Share price (rebased to OSH)

0.00

1.00

2.00

3.00

4.00

5.00

6.00

7.00

Jan 09

Annualised TSR for five years to end 2009 of 29.5%

Jan 10Jul 09

Woodside

Santos

ASX 100

WTI oil

Oil Search

8

Consistent TSR performance over 5 years

Source: IRESS

Relative TSR performance for period ending 31 December, 2009

ASX 100 Index Median Company OSH performance# Ranking based on ASX 100 composition at the beginning of the reference period.

-5

0

10

20

30

40

1 Year 3 Year 5 Year

% T

SR

1st

3rd

OSH Ranking #

42nd

9

Future Value Growth

Driven by :-PNG LNG DeliveryProject optimisationFurther LNG Train DevelopmentReserve growth and Exploration Success

Comprehensive programmes to delivervalue through to PNG LNG first gas

10







11

2009 Financial Performance

(US$’m)RevenueCash ExpensesEBITDAXNon-cash itemsExploration ExpenseInterest income/(expense)Pre-tax ProfitTaxNPATCore Profit

814.3(116.3)

698.1(127.2)

(91.2)6.1

520.3(206.9)

313.4240.0**

20082009

512.2(102.8)

409.4(105.4)

(75.7)(3.3)239.8

(106.2)133.799.6*

Revenue and profit impacted by 35% decline in realised oil prices to $65.40/bbl and 7% lower oil sales due to underlying field decline rates and sale of MENA producing assets

* Excludes PNG Government licence back-in adjustments and one-off tax credit** Excludes net profit sale of MENA assets/JV licence sale profit adjustment and impairment losses

-37%

-41%

-59%

-54%

12

Cash Earnings Performance

Cash operating margin remains healthy at current oil price

2005 2006 2007 2008 2009

100

65

78

6758

Oil Price

83%

86%

83%

80%

86%

EBITDAXMargin

0

US$/bbl

20

40

60

80

100

120%

70

75

80

85

90

95

100

13

2009 EBIT Drivers

EBIT decline driven by fall in oil prices, PNG field production decline and sale of MENA assets

0

100

200

300

500 479.6

20

08

EB

IT

228.2

20

09

E

BIT

(258.9)

15.513.5

Cash

O

pex

Exp

lora

tio

nExp

en

se

21.8

Am

ort

isati

on

(10.1)

Oth

er

US$m

400

Oil P

rice

Oil

Volu

mes

(33.2)

14

Ongoing Cost Management

2009 2008US$’m US$’m

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

73.70.05.9

76.94.18.0

Other Prod’nOpex

79.6 89.0

- Oil- Hides

14.40.4

17.80.4

14.8 18.2

Net Corp Costs 10.7 8.1

FX Movements (2.5) 1.0

Total 102.8 116.3

Adverse FX movements impacted 2H cost performance

Continuing active cost reduction programmes

Field Costs Other Opex Corp Costs/FX

US$/boe Total cash costs per boe

10.68

2.18

1.09

10.08

1.87

1.04

1.88

1.75

9.13

1.45

1.26

7.64

0

2

4

6

8

10

12

14

16

2006 2007 2008 2009

15

2009 Cash Flows

Openi

ng

Cash*

Opera

ting

Inve

stin

g

Fina

ncin

g

Closing

Cash*

Operating cashflow included US$79m of tax paid (inclusive of prior period tax recoveries)

Investing cash outflows included US$139m on production, US$324m on exploration & evaluation, including PNG LNG expenditure

Financing included US$900m of proceeds from share placement, SPP and DRP underwriting

* Includes Company share of JV cash balances

535535

284284

851851

1,2881,288

US$’m

0

250

500

750

1000

1250

1500

(382)(382)

16

US$1.29 billion in cash at end December

Cash invested with highly rated bank counterparties

US$362.5 million available from term revolving facility, nil drawn down

Group liquidity ~US$1.65 billion

No oil hedging undertaken during the year or currently in place - realised earnings uplift from 2H09 oil price recovery

Sanction of PNG LNG Project in December delivered US$88 million of proceeds net to OSH from PNG Government back-in to Project gas licences

Claw-back from lenders of 70% of Project costs spent prior to Financial Close will realise a further ~US$270 million inflow

Treasury Update

17







18

PNG LNG Project

19

PNG LNG Project

World class ProjectAligned joint venture ExxonMobil Operator –excellent track recordSupportive Government and communitiesProvides infrastructure for future growthTransformational for Oil Search and PNG

20

PNG LNG Projectthe road to sanction

2008Signed JOA, aligning JV partners in MarchSigned Gas Agreement with Govt in MayCommenced FEED in MayCommenced marketing discussions late 2008Developed financing plan

2009Submitted EIS in JanuarySigned UBSA in MaySigned HOAsCommenced early worksEIS approved in OctoberCompleted FEED, LNG plant capacity increased to 6.6 MTPA

21

PNG LNG Projectthe road to sanction

December 2009 Completed LBSAs Signed 3 SPAs with TEPCO, Osaka Gas and SinopecDevelopment approval 8 December 2009EPC contracts awarded 9 December 2009Financing documents signed 15 December 2009 with ECAs, Commercial Banks and ExxonMobil for $14 billionGovernment offered and Project accepted all development licencesGovernment paid past costs for equity back-in to new development licences

Major milestones achieved on schedule, highlights Project quality

22

Financial Close expected in 1Q 2010Approvals of final SPA

Minor legislation amendments at the first sitting of Parliament in early March

Construction has commenced (roads, bridges, camps, site preparation and training facilities)

Targeting first LNG sales 2014

PNG LNG Project

23

Operator ExxonMobil has excellent record of delivering projects on time, on budgetFirst phase CAPEX, including FEED and early works -US$15 billionContracts:

LNG Plant: Chiyoda/JGCOffshore Pipeline SaipemHides Gas Plant CBI/Clough JVOnshore Pipeline SpiecapagInfrastructure McConnell Dowell/CCC JVEarly Works Clough/Curtain JVAssociated Gas (OSH only) Aker Solutions

Mix of fixed price/variable price contractsResourcing by contractors underway now

PNG LNG Project

24

Proposed PNG LNG Future Activities

2010 2011 2012 2013 2014

FinancialClose

Continued early works.Detailed design.

Order long leads and place purchase orders.Opening supply routes.Contractor mobilisation.

Commence AG construction.

Pipe laying Kutubu to Hides.

Ongoing drilling.Complete Hides plant.Commission LNG plant

with Kutubu gas.

Ongoing procurement and mobilisation.

Airfield construction.Drilling mobilisation.

Offshore pipeline construction start.

Onshore line clearing.Start LNG equipment

installation.

First Gas from Train 1,

then Train 2

AG complete.Pipe laying

(Kutubu to Omati).Offshore pipe lay

complete.Start Hides plant

installation.

25

GasGrowth

26

PNG Gas Growth

Key strategic priority for Oil Search is to grow gas business in PNGLNG remains optimum commercialisation route for additional gas PNG LNG will provide infrastructure and capacity to facilitate expansion and provide excellent cost structure:

Use of capacity in pipeline, jetty, tanks and servicesTrained local work force

Government is supportive of future gas growthPace of gas growth will be determined by:

Resource aggregation/explorationJoint Venture alignmentMarket access

27

Existing Gas Discoveries

PRL01

PPL234

PRL08PPL240

PRL03

PRL11

PDL7

PPL239

PDL1

PPL190

PPL219

PRL10

PRL02

PDL2

PDL4

PDL3

PRL09

PPL244

9°S

6°S

145°E50km

Kumul Terminal

PDL6PDL5

APRL14

PPL260

APPL249

APPL250

PPL

233

PDL9PDL8

142°E

Hides/Juha

Kutubu/Agogo/SEM

P’Nyang

Pandora A

Uramu

Barikewa

Gobe/SEGElk/Antelope

Distribution of discovered 2P reserve/resourceSignificant Oil & Gas Reserves have been discovered in Papuan Basin to date (predominantly in Fold Belt)Basin is predominantly gas prone85% of basin’s resources by boe are gas

28

PNG Gas Growth - Resource

Full regional exploration review conducted during 2009Focus areas for Oil Search are:

Foldbelt/Highlands:− Adjacent to PNG LNG upstream infrastructure− Large structures, moderate risk, high OSH equity− 2010 and 2011 activity:

− Drilling Korka− Barikewa seismic (completed) followed by appraisal drilling− Huria seismic− Mananda drilling

Gulf of Papua:− Large under-explored areas with diverse licence holdings− 3D seismic will image subsurface, help high-grade portfolio − Opportunity to extend 3D survey into nearby licence− 2010/2011 activity:

− 3D seismic survey− Drill Flinders− Appraise Pandora

Foreland and Strickland:− Maintain watching position− CBM test in 2010

29

Papuan Basin Major Areas

NW Fold BeltLarge undrilled surface anticlines remain.

Low risk on reservoir, charge and seal.

StricklandA number of undrilled small low risk prospects and leads are present.

Poor quality seismic.

Southern ForelandA number of risky small undrilled prospects and leads remain.

Poor quality seismic. Gulf of PapuaA number of prospects and leads across varied play fairways.

Prospects can be quickly de-risked with 3D seismic.

Aure Fold BeltArea is under explored –Elk indicates significant potential for carbonate plays and emerging play potential.

Key risk is reservoir effectiveness.

Interior Fold BeltNumerous oil & gas seeps indicate a working hydrocarbon system.

Central Fold BeltOnly proven oil prone area.

Significant subthrustpotential exists.

8°S

142°E 144°E

100km

30

NotesCircle areas proportional to reserves potential. Outer circle unrisked potential, inner circle risked potential

Red =Gas,Orange= CondensateGreen = Oil

Proposed PNG Gas Exploration

PRL01

PPL234

PRL08PPL240

PRL03

PRL11

PDL7

PPL239

PDL1

PPL190

PPL219

PRL10

PRL02

PDL2

PDL4

PDL3

PRL09

PPL244

9°S

6°S

145°E50km

Kumul Terminal

PDL6PDL5

APRL14

PPL260

APPL249

APPL250

PPL

233

PDL9PDL8

Flinders

Barikewa Deep

Wasuma Deep (PPL219 & 190)

Cecilia West

KorkaHuria (PRL11)

Mananda FW

Mananda Attic

142°E

31

PNG LNG ResourceOffshore 3D survey

4,700 km2 3D

4,700 km2 of 3D seismic – largest in PNG history

32

Gas Growth - Partnering

Having aligned Joint Venture with required skills and relationships is critical to driving timely gas commercialisationPNG LNG has ability to expand the unit, with upside discovered resourceGas growth in PNG LNG fields is aligned with existing developmentGas growth in non PNG LNG fields and exploration licences involves various aligned JV'sOil Search considering optimum partnering strategies in exploration licences to position for timely gas commercialisation

33







34

Oil Search Production

0

2

4

6

8

10

12

14

2004 2005 2006 2007 2008 2009

Net Production (mmboe)

11.05

12.17

10.219.76

8.608.12

7.2-7.4

2010

Kutubu

Moran

Gobe Main

SE Gobe

SEM

Hides GTE

MENA

(Forecast)

3535

2009 Production Performance

Excellent safety performanceProduction:

8.12 mmboe, demonstrated strong underlying performance in all fieldsKutubu production enhanced by new development wells and workoversMoran impacted by facility downtime mid-year, however drilling and workovers made up for temporary shortfallNo new wells on Gobe during 2009. Performance above expectation

PNG field costs:Cost control and reduction initiatives undertaken to offset the impact of:− Appreciating A$ & Kina on US

dollar cost base in 2H− Reduction in drilling activities,

in response to fall in oil price − 4% reduction in saleable oil

volumes− Inflationary environment in PNG

Production impact of recent drilling at Usano

ADD5 well – extension to Agogo Field

0

2,000

4,000

6,000

8,000

10,000

12,000

1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009

Oil R

ate

(b

op

d)

Usano Main Block

Usano East Block

UDT 7

UDT 11

UDT 8,9

UDT 10,12

3636

2009 PNG Drilling

Two new rigs (103 and 104) operating throughout the year

Significant performance improvements achieved:

Faster drilling rates / lower cost per metre

Rig move time substantially reduced

Lower non productive time

New technology successfully applied

Programme for 2010 based on geographical optimisation of rigs fleet with flexibility to include 3rd party programmes

Hydraulic workover unit operating successfully, will recommence five well programme mid-2010

37

ADT 2 – Opens up new play

ADT 2 Well Results:1,100 metre+ proven height4 fault compartmentsDigimu in fault compartment 1 has proven oilNo pressure data in fault compartments 2, 3, 4 though Toro had elevated gas and resistivitiesMulti-zone completion installedProduction testing underway, 2,000 bopd from first zone (FC1)

7”

ST3

ST1

2200

2400

2600

2800

3200

3400

OverturnedForelimb

Hangingwall

mTVD

Alene

Fault Compartment 1

5”

Fault Compartment 2

ST23000 Fault Compartment 3

Digimu

Fault Compartment 4

Toro A

SW NE

Hedinia Sand

Toro B/C

38

Oil development drilling continues to add value

Since 2003, gross PNG proven oil reserves have increased by 51 mmbbl to 73 mmbbl, with further 34 mmbbl in probable reservesDevelopment drilling has added reserves at average cost of US$11.72/bbl Many further opportunities exist, including appraisal of Agogo deep (ADT 2), drilled in late 2009/10, recently tested at 2,000 bopd

PNG Oil Fields - Ultimate Recoverable Reserves (pre-LNG)

1P

2P

440

460

480

500

520

540

560

Millio

ns

of

Barr

els

2003 2004 2005 2006 2007 2008 2009

3939

Reserves & Resources31 December 2009

Six-fold increase in proven (1P) reserves, from 50 mmboe at end 2008to 344 mmboe:

PNG LNG Project reserve booking of 301 mmboe2009 production of 8.1 mmboe Oil reserve additions at Kutubu, Gobe and SE Gobe of 2.4 mmboe

Seven-fold increase in proven & probable (2P) reserves, from 67 mmboe to 567 mmboe:

PNG LNG Project reserve booking of 505 mmboe2009 production of 8.1 mmboe Oil reserve additions at Kutubu, Gobe and SE Gobe of 2.8 mmboe

2C resources, comprising gas and associated liquids, of 281 mmboe at end 2009, compared to 886 mmboe at end 2008:

Adjustment of 79 mmboe, due to Government back-in, to PNG LNG, initial equity determination and field reserve changesPNG LNG Project reserves booking of 505 mmboeDecrease of 21 mmboe for revisions to certain fields’ 2C estimates and Government back-in

Total 2P and 2C reserves and resources of 848 mmboe

4040

2010 Operations Outlook

Key strategic rebuild to optimise oil and gas businessGas value driving revised Operating Framework:

Field reliability managementGas conservation with minor oil production impact

Production outlook for 2010 of 7.2 – 7.4 mmboeValue adding PNG production activities will continue:

Reduced drilling programme with 1 – 2 wells at Moran and appraisal of Agogo deep playWorkover campaign in Kutubu, Moran, SE GobeNew well optimisation and testing, reservoir management activities

Continued focus on capturing additional in-field reserve opportunities post-ADT 2 sidetrackOngoing focus on costs and capital efficiency following successful 2009 Operations ReviewAligning and maximising use of infrastructure to support LNG project

4141

Exploration Outlook

PNG:Exploration for gas – key to driving LNG expansionAdditional oil focused exploration in 2010:−Wasuma (25 mmbbl mean, currently drilling in PPL 219) −Mananda Attic (30 mmbbl mean in PPL 219, plus gas

play)

MENA:Focus on finding material oil and maximising asset value:−Evaluate commerciality of Shakal (Iraq) and Tubb’a (Yemen)

discoveries−Oil–focused drilling ongoing within Blocks 3 and 7 in Yemen,

targeting 3D defined structures−Seismic in Kurdistan (K42 world class exploration province) and

Tunisia planned to define drillable large structures

42

PNG 2010 Exploration Summary

PRL01

PPL234

PRL08PPL240

PRL03

PRL11

PDL7

PPL239

PDL1

PPL190

PPL219

PRL10

PRL02

PDL2

PDL4

PDL3

PRL09

PPL244

142°E

9°S

6°S

145°E50km

Kumul Terminal

PDL6PDL5

APRL14

PPL260

APPL249

APPL250

PPL

233

PDL9PDL8

Commitment

Discretionary

Future Commitment

Well Types

Prospect/Lead (POS%)Mean Oil Gross (mmstb)Mean Gas Gross (bscf)

Seismic

CommitmentDiscretionary

Permit 2D(distance)/3D(area)

Flinders (12.5%)1.0 tcf+

Korka (15%)1.3 tcf +

Mananda Attic (45%)30 mmstb

Mananda FW (10%)1.2 tcf +

PPL234 3000+km2

PRL11 80km

PPL233 55km

PDL2 100km

Wasuma HW(30%)25 mmstb

Wasuma Deep (20%)25 mmstb

43

MENA 2010 Exploration Activity Summary

Sana’a Office

Dubai Office

Commitment

Discretionary

Future Commitment

Well Types

Prospect/Lead (POS%)Mean Oil Gross (mmstb)Mean Gas Gross (bscf)

Seismic

CommitmentDiscretionary

Permit 2D(distance)/3D(area)

Tajerouine

Le Kef

K42

Shakal

Block 7

Block 3

Area 18

Taj. + Le Kef 600km

K42 200km

Shakal 60km

Lead E Lam (9%)70 mmstb

Lead M (9%)20 mmstb

Block 3 & 7 400km

Al Measher (20.0%)20 mmstb

44







45

Outlook and Summary

Oil Search core business in excellent shape to drive further value growth over next 3 yearsPNG LNG Project Sanctioned

ExxonMobil quality operator for deliveryContractors mobilising, construction startedBuyers secured, with pricing locked inFinance secured, excellent packageSignificant impact on PNG already being felt

Country and Company transformational, Project underway

46

Focus on Value Enhancement

Two largely independent core gas development streams:

PNG LNG dedicated fieldsMaterial core reserves

Proven 300 mmboe (OSH share) sold. Proven & Probable 500 mmboe (OSH share) –significant upside

Field development optimisation being analysedFuture appraisal being plannedStrong partner alignment

Other fields and explorationMaterial resources still to be commercialised Proven & probable 281 mmboe (OSH share)Future appraisal and exploration underwayDeveloping material portfolio ex PNG LNG

Assessed sufficient risked resource base to underwrite Trains 3 and 4

47

Significant LNG Reserve Booking Potential

OSH commitment to PNG LNG delivers an incremental 301 mmboe and 505 mmboe on 1P and 2P basis respectivelyAdditional net 2C resources of 281 mmboe are available from other OSH fieldsTotal resources in OSH and other PNG fields (ex PNG LNG) estimated at 1,686 mmboe (9 Tcf)

PNG 2009Reserves & Resources (100% License Estimates)

-

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

Mil

lio

ns

of

Barr

els

Oil

Eq

uiv

.

Oil Only Oil + PNG LNGOSH Fields'Reserves &Resources

All OtherResources

2P/2C

Oil Search 2009PNG Fields Net Reserves & Resources

0

100

200

300

400

500

600

700

800

900

Mil

lio

ns

of

Barr

els

Oil

Eq

uiv

. (N

ET)

Oil Fields Oil + PNG LNG Oil + PNG LNG +Resources

1P/1C 2P/2C

48

Active programmes to deliver in 2010

Field and Development Optimisation (Central Foldbelt)

Seismic acquisition and drilling

Accelerated exploration (NW Foldbelt and Gulf)

Seismic and drilling, CSM

Selected Acquisitions (PRL 1, PPL 244 and others)Partner Alignment (PNG LNG and others)

49

OSH good value on 1P reserves relative to Global Energy Sector

0

5

10

15

20

25

30

35

40

Arr

ow

Hu

sky

Mu

rph

y

BG

Mara

tho

n

Rep

sol

Wo

od

sid

e

EN

I

Ch

evro

n

An

ad

ark

o

Sh

ell

Hess

Tali

sman

Ap

ach

e

Devo

n

San

tos

Oil

Searc

h

Exxo

nM

ob

i

To

tal

BP

Ph

illi

ps

Note: Enterprise Values as at 31 January, 2010. 1P reserves based on latest publicly available reserves figures

Source: Public Information

Enterprise value (US$m) / 1P reserves (mmboe)

50

Production Outlook

PNG LNG adds ~18 mmboe pa to OSH at plateau in 2015 onwards. 30 year Project life

T3 could add an additional ~9 mmboe pa, with T4 of similar magnitude

Net

Pro

du

ctio

n (

bo

ep

d)

0

10,000

20,000

30,000

40,000

50,000

60,000

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

LNG GasLNG Gas

PNG DevelopmentPNG Development

70,000

80,000

Potential T3 LNG GasPotential T3 LNG Gas

LNG CondensateLNG Condensate

90,000

Potential T3 LNG CondensatePotential T3 LNG Condensate

51

Summary

Core oil production remains solid. Focus on life extension, reliability and gas conservation

A new value equation

Measured oil exploration in PNG and MENA

Activities underwritten by strong balance sheet and liquidity to meet LNG obligations, T3/T4 appraisal and exploration activity

52

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

53

Appendix

54

2010 Guidance Summary

Production: 7.2 – 7.4 mmboe

Opex: US$16-18/boe Increase due to FX, PNG inflation, increased spend to improve reliability & extend life and relatively fixed cost base on lower production. In addition, accelerated focus on workovers to maximise oil recovery prior to gas blow down

D,D & A: US$6-8/boe Decrease due to recognition of LNG reserves

Capex:Exploration – US$210m (80% in PNG, 20% in MENA)Production/Other – US$85m (inc corporate & other gas)PNG LNG – US$1,000 - 1,350m

Documents

1 2009 Full Year Results Agenda - Oil Search · 5 2009 Performance Summary ¬NPAT of US$133.7 million, US$99.6m excluding PNG Government back-in and tax adjustments ¬Satisfactory