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
Performance Summary Peter Botten
Financial Overview Zlatko Todorcevski
PNG LNG & Gas Expansion Phil Bainbridge
Operations Review Phil Caldwell
Outlook & Summary Peter Botten
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$1.6 billion (including line of credit). Sufficient for both PNG LNG equity contribution plus funding of T3/T4 gas exploration/ appraisal programme
Board approved final dividend for 2009 of 2 US cents, making 4 US cents for the year. Funded by fully underwritten Dividend Reinvestment Plan
6
Outstanding Safety Performance
Total Recordable Incidents (TRIs) of 1.16 in 2009
TR
I /
1,0
00
,00
0 H
ou
rs
0
2
4
6
8
10
12
14
1998 1999 2000 2001 2002 2003 2004 2005 2007
Oil Search
2006
Australian Companies (APPEA)
2008
InternationalCompanies
(OGP)
12.7
9.1 9.37.8
7.0 7.3
5.2
9.4
8.2
6.3 6.8
3.9 3.1 2.9 2.7 2.1
4.0
3.6
4.9
5.76.0
2009
8.5
10.69.8 10.7
5.8
1.7
4.7
2.4 2.31 2.05 1.162.04
7
Strong Five Year Share Price Performance
Jan 05 Jul 05 Jan 06 Jul 06 Jan 07 Jul 07 Jan 08 Jul 08
Share price (rebased to OSH)
0.00
1.00
2.00
3.00
4.00
5.00
6.00
7.00
Jan 09
Annualised TSR for five years to end 2009 of 29.5%
Jan 10Jul 09
Woodside
Santos
ASX 100
WTI oil
Oil Search
8
Consistent TSR performance over 5 years
Source: IRESS
Relative TSR performance for period ending 31 December, 2009
ASX 100 Index Median Company OSH performance# Ranking based on ASX 100 composition at the beginning of the reference period.
-5
0
10
20
30
40
1 Year 3 Year 5 Year
% T
SR
1st
3rd
OSH Ranking #
42nd
9
Future Value Growth
Driven by :-PNG LNG DeliveryProject optimisationFurther LNG Train DevelopmentReserve growth and Exploration Success
Comprehensive programmes to delivervalue through to PNG LNG first gas
10
2009 Full Year Results
Performance Summary Peter Botten
Financial Overview Zlatko Todorcevski
PNG LNG & Gas Expansion Phil Bainbridge
Operations Review Phil Caldwell
Outlook & Summary Peter Botten
11
2009 Financial Performance
(US$’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
2009 Full Year Results
Performance Summary Peter Botten
Financial Overview Zlatko Todorcevski
PNG LNG & Gas Expansion Phil Bainbridge
Operations Review Phil Caldwell
Outlook & Summary Peter Botten
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
2009 Full Year Results
Performance Summary Peter Botten
Financial Overview Zlatko Todorcevski
PNG LNG & Gas Expansion Phil Bainbridge
Operations Review Phil Caldwell
Outlook & Summary Peter Botten
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
2009 Full Year Results
Performance Summary Peter Botten
Financial Overview Zlatko Todorcevski
PNG LNG & Gas Expansion Phil Bainbridge
Operations Review Phil Caldwell
Outlook & Summary Peter Botten
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