W h e r e w e a r e n o w . . .

O I L S E A R C H 1 9 9 8 A N N U A L R E P O R T

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. . . w h e r e w e g of r o m h e r e

The company has never been better placed to build shareholder value intothe new millennium.

We now have a major reserve base of oil and gas, unprecedented for acompany of our size.

The challenge to run our business with low oil prices will be met bymaximising cost-effective production, reducing our cost base, managingour cash flow and undertaking judicious exploration based on strictinvestment criteria, in conjunction with:

¥ Continued reserve and production growth by commercialisation of oursubstantial gas reserves. This will have a major impact on companyprofitability, cash flows and value.

¥ Continued development of our known fields at Gobe, Moran, Kutubuand Hides.

¥ Ongoing exploration success, especially in areas close to infrastructure.

¥ Continued increase in shareholder wealth.

¥ Maintaining world-class safety and environmental standards in our areasof operations.

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“ Whilst 1998 was a very

difficult year for the oil

industry, we have built our

business through major

growth in reserves, oil

production and significant

progress in commercialising

our large gas resources.

We have an unprecedented

platform for growth over the

coming three years.

The challenge remains to

realise that potential.”

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Trevor Kennedy A.M.Chairman

Our objectives and achievementsare to ...

ACHIEVE MAJOR INCREASES IN RESERVESAND PRODUCTION LEVELS

4DEVELOP NEW OIL AND GAS FIELDS

6PROGRESS THE PROPOSEDPNG–QUEENSLAND GAS PROJECT

8OBTAIN A HIGH SUCCESS RATE INEXPLORATION DRILLING

10INCREASE OUR SHAREHOLDERS’ WEALTH

12

How we met our objectives ...

THE YEAR IN DETAIL

14QUESTIONS TO THE MANAGING DIRECTOR

25

The results we achieved ...

FINANCIAL STATEMENTS

36DIRECTORS’ ANNUAL REPORT

62

OIL SEARCH LIMITED

( Incorporated in Papua New Guinea)

A.R.B.N. 055 079 868

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• We more than doubled our proven and probable oil reserves to around 87 millionbarrels as at 31 December.

• We quadrupled our proven and probable gas reserves to more than 4 TCF.

HOW WE MET OUR OBJECTIVE IN 1998

Our aim ... INCREASE RESERVES ANDPRODUCTION

Reserves of oil and gas wereat record levels at the end of1998

• The acquisition of further interests in Kutubu, Moran and Hides assets from BP.

• The booking of oil reserves from the Moran Central oil field for the first time.

• Further exploration and appraisal success at Moran and Hides.

This was achieved through

• Oil production for the year totalled 6.3 million barrels, up almost 200% from 1997.

• Average oil production was 17,223 BOPD – up from just over 5,000 BOPD in theprevious year.

• Gas production totalled 3,555 mmscf – a 16-fold increase over 1997.

• Average daily gas production totalled 9.8 mmscfd.

• Production of oil came from 4 fields, as Gobe Main, SE Gobe and Moran Central oilfields were commissioned in 1998. Only Kutubu contributed production in 1997.

Information on reserves and production appears on pages 14 and 15.

Production of oil and gasreached record levels for thecompany in 1998

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• Oil production from the Gobe Main oil field commenced on 9 March 1998 and fromSE Gobe at the end of the month, some 13 months after construction activitiescommenced.

• Production was achieved ahead of schedule and materially below budget.

• Development costs for the field, based on approximately 100 million barrels of provenand probable reserves, were a world class US$3.10 per barrel.

• The Gobe Development is the first in Papua New Guinea where project arealandowners received direct equity in the project at the commencement of oilproduction. This clearly facilitated the development process and helped to ensure nodisruptions to operations.

• Oil production commenced in the Moran Central oil field using extended well testing.

• The Moran oil field is immediately adjacent to the Kutubu fields and facilities. Closeproximity to Kutubu facilities allowed for economical development of Moran oil at atargeted development cost of around US$1.60 per barrel.

• Unlike Gobe, the Moran development will be phased, involving progressivedevelopment away from the Moran Central area and utilising spare productioncapacity in the Kutubu facilities, where possible. The initial development will beconcentrated around the Moran 1, 2, 4 and 5 wells.

• Extended well testing marks a new way to rapidly commercialise discoveries in closeproximity to infrastructure. It demonstrates a growing maturity in the relationshipsbetween developers, the State and landowners. Production can now commenceprior to full development of a field and the granting of a production licence.

• Time from discovery at Moran to first oil production was a world class 20 months,compared to almost seven years at Gobe.

Information on field development appears on pages 15 and 16.

HOW WE PROGRESSED TOWARDS OUR OBJECTIVE IN 1998

Our aim ... DEVELOP NEW FIELDS

Three new oil fields werebrought on productionahead of schedule andbelow budget

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• Various memoranda of understanding and conditional gas sales agreements weresigned with potential customers in the Townsville and Gladstone areas whichunderscored the likely viability of the project. These agreements cover potentialmarket loads of up to 140 PJ per year, well in excess of the 110 PJ per year initiallyrequired for the project.

• The establishment of competitive tariff arrangements and access principles for theAustralian portion of the pipeline to be built and owned by the AGL Petronasconsortium represented a major landmark.

• The signing of accords with indigenous landowners in Queensland demonstratedclear community support for the project.

• The passage of new oil and gas legislation in PNG provided the regulatory frameworkfor the development.

• The signing of a tripartite Memorandum of Understanding between Papua NewGuinea’s National Government, Australia’s Federal Government and Queensland’sState Government ensured unprecedented government support for this project.

• Environmental approvals for the development in Australia have removed a majorpotential area for delays in construction.

• Technical and engineering studies provided the framework for optimal development ofthe production and processing facilities and pipeline.

• Major progress was made in early 1999 to ensure that adequate reserves of gas areavailable from both Kutubu and Hides for markets in Queensland with the signing ofan agreement between Oil Search and Exxon.

• Progress was also made in redefining the markets in Queensland with the possibleextension of the pipeline from Gladstone into SE Queensland and the potentialdelivery of gas to large power customers in the Brisbane area.

• Project viability and capital cost requirements are also being revised, with thelikelihood that upstream project sponsors in PNG are likely to introduce third partyownership of the pipeline and some processing facilities in PNG.

Information on the PNG–Queensland gas project appears on pages 16 to 18.

HOW WE PROGRESSED TOWARDS OUR OBJECTIVE IN 1998

Our aim ... COMMERCIALISE OURLARGE RESERVES OF GAS

Major progress was made inestablishing the viability ofthe PNG–Queensland gasproject

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• Successful completion of the Hides 4 well added substantial volumes of gas andliquids reserves to the Hides field. It extended the field some 12 kilometres to thesouth-east from existing well control and demonstrated likely reservoir continuity.

• Testing of the Hides 4 well demonstrated high potential productivity of the Tororeservoirs and a materially higher liquids content in the gas. The well confirmed a gascolumn height in the field in excess of 1,200 metres. No hydrocarbon/water contacthas yet been established for the field.

• The Hides 4 well has proved that the Hides field contains a world class gas resourcewith reserves in excess of 5 TCF.

• Moran 5X and its sidetracks successfully further delineated the Moran Central portionof the field, demonstrating that the Toro and Digimu reservoirs are oil bearing.

• At the end of 1998, and in the early part of 1999, gas and oil discoveries were madeat Kimu 1 and Koko 1 (the first wells operated by Oil Search for over 30 years). Thesewells demonstrated that significant volumes of both oil and gas have been generatedin the south-east foreland area of the Papuan Basin and show that this area is likelyto become a new oil and gas province in Papua New Guinea. These well resultssignificantly upgraded the lightly explored foreland area in which Oil Search hassignificant licence holdings. Kimu 1 is the first well to demonstrate potentiallycommercial flow rates of gas from the Alene Sandstone.

• Major advances in seismic acquisition and processing techniques over the ruggedfoldbelt structures led to the identification of large Footwall prospects underlying theKutubu and Gobe fields.

Information on exploration activities appears on pages 18 to 20.

HOW WE PROGRESSED TOWARDS OUR OBJECTIVE IN 1998

Our aim ... HIGH SUCCESS RATE INEXPLORATION DRILLING

100% success in 1998

Four exploration wells andsidetracks were commencedin 1998, all of which weresuccessful in provingreserves of hydrocarbons

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• Forecast production rates are at least 25,000 BOPD over the next five years, basedon existing fields.

• The opportunity to commercialise the company’s gas was enhanced and has thepotential to provide a material increase in wealth to shareholders.

• A term loan at very competitive rates was put in placeafter year end, despite a difficult credit environment.

• Summary of key results

Sales revenue up 150% to US$90.8 million

EBITDA up 148% to US$60.3 million

Operating profit after tax (before Abnormals) up 14% to US$13.4 million

Operating profit after tax down 34% to US$9.3 million

Operating cash flow(after preference dividend) up 130% to US$44.8 million

Shareholders’ funds up 82% to US$308.8 million

• Joint venture operating costs and administration werereduced by US$1.10 per barrel.

• Hedging of 8.7 million barrels, at US$14.60 per barrel over two years from July 1999to June 2001, was put in place to provide downside oil price protection and enhancedebt quality.

Information on shareholders’ wealth appears on page 20.

Our aim ... TO INCREASE THEWEALTH OF OURSHAREHOLDERSHOW WE PROGRESSED TOWARDS OUR OBJECTIVE IN 1998

The acquisition of BP assetsprovided a platform forgrowth with major newreserves and productionbases

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

1994 1995 1996 1997 1998

US$ 000 US$ oil price per bbl

EBITDA vs average realised oil price

EBITDA

Average realised oil price

0.00

5.00

10.00

15.00

20.00

25.00

RESERVES

The company’s reserves of proven andprobable, developed or near developedoil reserves rose from just over 40 millionbarrels in 1997 to 87 million barrels atthe end of 1998, following production of6.3 million barrels during the year. Thecompany also substantially increased itsreserve base for gas, more thanquadrupling potential reserves in thiscategory to more than 4 TCF, postcompletion of the sale of an interest inthe Hides gas field to Santos.

A detailed review of the company’sreserves in the Kutubu, Gobe Main, SE Gobe, SE Mananda and MoranCentral oil fields took place during 1998.Analysis of the company’s gas resourcein the Kutubu and Gobe fields, alongwith SE Hedinia, Juha and P’nyang alsotook place, to provide a review ofavailable reserves for a potential gasproject to supply gas into Queensland.These figures do not include potentialadditional black oil, condensate and LPGvolumes that may be recovered, shoulda gas project proceed. These volumes,along with compositional anddeliverability data, will be assessed indetail during studies planned for 1999and will form part of the core activitiesfor the PNG-Queensland gas project. An assessment of the company’s reserveand resource base will be summarised in all future annual reports.

Reserve growth during 1998 wasachieved predominantly through theacquisition of further interests in theKutubu, Moran and Hides fields. Oilreserves were also booked for the firsttime in the Moran Central oil field.

Reserve levels in the Kutubu and SEMananda fields have been adjusted forproduction during 1998. A substantialfurther review of production practicesand recovery techniques is planned atKutubu in 1999 to ensure that we aremaximising economic reserves fromthese fields. This is linked to ongoing gas deliverability studies and a review of the optimal development of MoranCentral/SE Mananda fields.

Reserves in the Moran Central oil fieldremain under continuous review, asproduction data and pressure surveyscontinue in various wells and reservoirsacross the field. The oil/water contacts,and the extent of the field to the north-west of Moran 4, remain to bedefined. Further appraisal drilling onMoran is required to evaluate the extent ofthis field and to determine the distributionof reserves away from Moran 4 to theMoran 1 and 2X area.

Reserves in the Gobe/SE Gobe area willbe reviewed in 1999 to incorporate thedrilling results of the 1998-99development drilling programme and theproduction history being established inthe fields. Although both the drilling andproduction activities have highlightedvarious differences with the original fieldmapping and production model, we donot presently anticipate any materialchanges to the reserve base.

The Hides 4 exploration well, drilled in1998, confirmed the extension of gasreserves some 12 kilometres to thesouth-east of existing well control. It alsoconfirmed the presence of an additional383 metres of gas column in the field,which is now proven in excess of 1,200metres thick. Pressure and test data inthis well indicate continuity with otherwells in the field, adding confidence tothe reserve levels. No hydrocarbon/watercontact has yet been intersected andthere is material information to suggestthat substantial downdip potential is stillpresent in the field. Hides represents aworld class gas resource with likelyreserves of gas in excess of 5 TCF.

THE YEAR IN DETAIL

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PNG RESERVES SUMMARY (AS AT 31/12/98)

TOTAL RESERVES OIL SEARCH SHARE

Field name Licence Oil Search 2P oil 3P oil 2P gas 3P gas 2P oil 3P oil 2P gas 3P gas equity mmstb mmstb bcf bcf mmstb mmstb bcf bcf

Kutubu/SE Mananda PDL 2 27.1 87 103 1,364 1,670 23.6 28.0 370.1 453.2

SE Gobe/Gobe Main PDL 3 & PDL 4 21.9 & 27.1 95 113 291 354 22.7 26.5 70.3 85.8

Gobe 2X block PDL 4 27.1 – 1 34 38 – 0.3 9.2 10.3

Moran Central PDL 2 & PPL 138 27.1 & 52.5 99 150 238 576 40.5 59.8 81.0 229.3

SE Hedinia PDL 2 27.1 – – 166 253 – – – 42.6

Hides PDL 1 & PPL 138 27.5 – – 5,281 7,600 – – 1,452.3 2,090.0

Angore PPL 138 52.5 – – 2,062 3,453 – – 1,082.3 1,812.8

Juha APRL 2 6.02 – – 1,563 2,219 – – 94.1 133.5

P'nyang APRL 3 6.02 – – 1,690 3,112 – – 101.7 187.3

Uramu PPL 188 54.5 – – 375 462 – – 204.4 252.0

Kimu PPL 193 31.3 – – 298 490 – – 93.0 153.0

Pandora A PRL 1 5.0 – – 967 1,601 – – 48.4 80.1

Pandora B PRL 1 5.0 – – 56 73 – – 2.8 3.7

Barikewa PPL 189 40.4 – – 830 1,622 – – 335.0 655.0

Iehi PPL 190 30.1 – – 99 395 – – 29.8 118.9

Kuru PPL 189 & PPL 191 40.4 & 0.0 – – 54 252 – – 10.9 50.9

Total 281 367 15,368 24,170 86.8 114.6 3,985.3 6,358.4

1994 1995 1996 1997 1998

mmboe

Annual BOE production(1998 split by field)

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Moran

SE Gobe

Gobe Main

Kutubu

PRODUCTIONProduction of oil and gas reached recordlevels for the company in 1998, with 6.3million barrels of oil produced (up almost200% from 1997) and 3,555 mmscf ofgas produced (a 16-fold increase on theprevious year). Average daily oilproduction totalled 17,223 BOPD, upfrom just over 5,000 BOPD in 1997 and9.8 mmscfd of gas, again a substantialincrease over 1997. Although the primaryreason for these rises was the purchaseof BP’s interests in the Kutubu, Moranand Hides fields, importantly, three newfields were brought into productionduring 1998 - Gobe Main, SE Gobe andMoran Central.

The outlook for production over thecoming five years is very strong. Basedon continued production of oil fromKutubu, Gobe Main and SE Gobe andthe phased development of MoranCentral, the company’s daily productionof oil will rise to over 30,000 BOPD in2000-01. Further potential still exists inour various fields, plus SE Mananda, to increase this further. With rapiddevelopment possible through extendedwell testing, exploration success at NWGobe, Gobe Footwall, Hedinia Footwallor NW Moran could provide additionaloil production within this time-frame.The successful development of a gasproject would also add materialquantities of oil, condensate and LPGsto our production levels.

DEVELOPMENT OF NEW FIELDS

GOBE

Production from the Gobe Oil Projectcommenced on 9 March 1998, whichrepresented the commencement ofPapua New Guinea’s second-ever oilproject. This was achieved 13 monthsafter construction activities commenced,which was ahead of time and belowbudget. This represents a majorachievement for all parties involved,including Chevron and the developinggroup, government and the project arealandowners. Gobe represents the first oil development where project arealandowners took equity in the project at the commencement of production. This, along with a very active programmeof involvement by landowner companiesin contracts associated with constructionand production work on the project, has been an important factor insatisfying the legitimate aspirations ofthe landowners.

Development expenditure on the projectwas around US$290 million, someUS$30 million less than anticipated.Further development drilling in theproject area has lifted this expenditure to over US$300 million, however,

development costs are still at a worldclass US$3.10 per barrel.

Various teething problems wereencountered in plant commissioning, themost serious of which were problemsexperienced with the state-of–the-artgas compressors, and sand productionfrom the Gobe Main oil wells. Repairsand modifications to the compressorswere completed in the latter part of 1998and gas compression levels now exceedthe original project specifications ofaround 65 mmscfd.

Geotechnical studies carried out onmaterial from SE Gobe indicated thatsand production could occur along withthe oil in this field and appropriate sandcontrol measures, such as screens, wereput into production wells as they werecompleted. While this was notconsidered to be a problem in the GobeMain area, significant sand productionwas, however, experienced from thisfield early in the development, requiring a series of well workovers andrecompletions so that appropriatescreens could be fitted. This problemhad been overcome by the end of 1998and production had increased to over35,000 BOPD.

Analysis of production information fromthe field has indicated that higherproduction rates, and possibly enhancedoil recovery, can be achieved from thedrilling of horizontal development wells.A programme of at least four horizontalwells was commenced late in 1998 andis expected to continue through 1999 to increase production levels to the50,000 BOPD originally anticipated inthe field design.

Exploration opportunities, including theGobe Footwall and NW Gobe, are drillingcandidates for 1999 which, givensuccess, would rapidly be brought onproduction using the Gobe facilities.Seismic acquisition over the SE Gobefield has also highlighted further reservepotential on the forelimb of the structure.

MORAN

The development of the Moran oil field is utilising a different philosophy to thatoriginally used at Kutubu and Gobe. The possibility of major facilities withspare production capacity at Kutubu has removed the requirement to fullyappraise the Moran structure prior todevelopment. The reserve threshold tomake an economically viable development

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1998 production (100%): 18.947 mmstb (51,908 BOPD)Operating costs per barrel: US$2.73Estimated 2P reserves: 295 mmstb

FACILITIES DESCRIPTION • 30 production and 4 injection wells (gas and water), delivering crude oil to Kutubu Central

Processing Facility with separation/stabilisation facilities, and transportation via export pipelineto the Kumul offshore loading facility

COMMENTS ON PRODUCTION CONSTRAINTS• Fields are in natural decline due to field maturity1999 OUTLOOK• Continued production decline• Positive impact from PNG–Queensland gas project• Reservoir and production optimisation studies continue to look for opportunities to optimise

recoveries

Kutubu Development

1998 production (100%): 7.107 mmstbGobe Main: 11,980 BOPD from start up on 9 MarchSE Gobe: 13,656 BOPD from start up on 17 AprilOperating costs per barrel: US$3.20 (excluding tariff)Estimated 2P reserves: 102 mmstb

FACILITIES DESCRIPTION

• 14 production/injection wells (gas and water), delivering crude oil to Gobe Central ProcessingFacility with separation/stabilisation facilities, and transportation via export pipeline to theKumul offshore loading facility

COMMENTS ON PRODUCTION CONSTRAINTS

• Production restricted due to sand production and delays to stable compression performance

1999 OUTLOOK

• Horizontal wells to lift production to 50,000 BOPD

• NW Gobe extended well test potential

• Operating costs expected to decrease with full year of production

Gobe/SE Gobe Development

is, therefore, quite low and the need toprove significant reserves prior to majorcapital expenditure is not required.

Moran development is, therefore,breaking new ground in that, for the firsttime in PNG, production throughextended well testing has been possibleusing facilities at Kutubu. This representsa major breakthrough in developer/landowner relations in that, prior toMoran, it was necessary to have aproduction licence granted beforeproduction could commence. Earlycashflow to the PDL 2 joint venture has,therefore, been possible through theextended well testing programme.Although the production capacity of thewells in the field is in excess of 25,000BOPD, agreements with the landownershas limited production to an average of10,000 BOPD. This has recently beenlifted to 15,000 BOPD and we arehopeful of more than doubling this in1999 as licence applications proceed on the PPL 138 portion of the field.

The present proven and probablereserves in Moran Central are around100 million barrels, however, potentialexists in this area for up to 150 millionbarrels of recoverable oil, as the extentof the field to the north-west and south-east requires further delineation.

The potential of the Greater Moranfeature is still very large and a series ofexploration wells, including NW Moranand Komo, over the coming two yearswill be required to ascertain field limits.

The scope of the phased developmentwill be dependent on the success of thisappraisal work. The desire to limit theduplication of facilities, maximise the useof the Kutubu infrastructure and thepossible material impact on developmentof a successful gas project will mean ameasured but steady approach to thedevelopment, initially concentrating on

Moran Central. The objectivedevelopment costs are a world classUS$1.60 per barrel.

It is expected that the developers willapply for a production licence over theMoran 4 area during the second quarterof 1999. As Moran Central covers atleast two licences, PDL 2 and PPL 138,cost sharing and unitisation agreementshave been negotiated between thegroups. The development and tie-in ofMoran 4 is expected early in the secondhalf of 1999.

PNG-QUEENSLAND GAS PROJECT

Material progress was made during 1998 to establish the viability of thisexciting project and to bring it towardscommercial reality. Most important in this process was the determination thatsufficient markets for PNG gas exist inthe Townsville and Gladstone areas tosupport the project, along with theconfirmation that a consortium of AGL-Petronas (APC consortium) waswilling to build, own and operate apipeline to bring gas from PNG intoQueensland at highly competitive tariffrates. The signing of an agreement inOctober 1998 between the projectdevelopers and the APC consortium,defining delivery and tariff rates, wasprobably the most significant of a numberof major developments during the year.

An analysis of the size of the requiredmarket necessary in Queensland tomake the project viable has shown thatinitial contracts are likely to exceed 110 PJ per year, representing aproduction rate of approximately 300 mmscfd. Although there are manyprojections about how the market forgas in Queensland will grow, even onvery conservative assumptions, it is likelythat the estimated gas production willmore than double in an 8–10 year periodcommencing from initial delivery. We areconvinced that keenly priced PNG gaswill provide the platform for electricitygeneration and industry growth in bothQueensland and PNG.

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THE YEAR IN DETAIL

Gas operations

Field Processing

Wet GasPipeline

Marine Terminal

Dry GasPipeline

QLDLPG

LPG Exports

LPG Bottled Gas (PNG)

Condensate Exports

Oil Exports

LPG

Oil Storage

1998 production (100%): 3.442 mmstb (10,183 BOPD from start up on 28 January)Operating costs per barrel: US$2.05Estimated 2P reserves: 103 mmstb

FACILITIES DESCRIPTION

• 3 production wells delivering crude oil to satellite facilities at Agogo with separation/stabilisingfacilities, for transportion via Kutubu Central Processing Facility and export pipeline to theKumul offshore loading facility

COMMENTS ON PRODUCTION CONSTRAINTS

• Production limited to 10,000 BOPD under extended well test

1999 OUTLOOK

• Moran Production Licence Application mid year

• Production limit increased to 15,000 BOPD

• Full field development plan and engineering design

• Phased development to early 2000s

Moran Central EWT

1998 production (100%): 4.97 BCF (13.6 mmscfd)Operating costs per mcf: US$0.84Estimated Hides field 2P reserves: 5.3 TCF

FACILITIES DESCRIPTION

• 2 alternate gas wells delivering gas to Porgera Joint Venture for power generation for Porgeragold mine

COMMENTS ON PRODUCTION CONSTRAINTS

• production limited to gas sales contract to Porgera.

1999 OUTLOOK

• Potential integration into PNG-Queensland gas project

Hides Gas to Electricity Project

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Various potential customers inQueensland have signed conditionalagreements to purchase PNG gas.These agreements exceed the thresholdminimum requirements for the project toproceed, should they be turned into firmcontracts. Potential customers includeStanwell Power Station Townsville (up to48 PJ per year), Queensland Nickel andassociated Trans Alta AGL power plant(20 PJ per year), Comalco Aluminarefinery, Gladstone (27 PJ per year),NRG power station, Gladstone (20 PJper year), Queensland Aluminium (20 PJper year), and potential longer termcustomers such as an aluminium plant at Gove. The overall size of the potentialmarkets in Townsville and Gladstonearea is likely to be around 140 PJ peryear, well in excess of the 110 PJ peryear required to underwrite the project.

Significant milestones achieved in 1998 also included the signing of various accords with indigenouslandowner groups in Queensland thatwill underscore community support forthe project. This was a tremendousachievement, given recent experiences in this area, and the Operator (Chevron)and the landowners involved need to becongratulated on their frank, open andtrusting approach to these difficultissues. Environmental approvals werealso received for the development inAustralia, and major progress was madein PNG on these important issues.

A key element to the potential successof this project is the unprecedentedsupport that it is receiving from thevarious National, State and ProvincialGovernments in PNG and Australia.

This project represents the largest-evercontemplated in Papua New Guinea andthe second-largest in Australia, after theNorth-West Shelf Project. It isrecognised as being the only short tomedium term project that can materiallychange economic circumstances inPNG, underwriting the country’seconomy and growth for at least 30years. In Queensland, many thousandsof permanent jobs will be created bothfrom the project and from industries that will grow from the supply of largevolumes of competitively priced gas. It will also provide a diversity of energysupply to the State and ensure wellpriced energy for one of the fastestgrowing regions in Australia. In theAustralian Federal arena, a successfulgas project in PNG will reduce pressureon government and taxpayers to providecontinued substantial aid to PNG whichpresently exceeds A$300 million peryear. The use of natural gas as anenergy source will also aid in achievingenvironmental standards, especiallygreenhouse gas emissions, that arebeing set by governments and theinternational community.

There has been close co-operation andco-ordination between Australia’sFederal Government, the PNG’s NationalGovernment and Queensland’s StateGovernment in co-ordinating the manylegislative approvals required to build amajor project across two countries. Atripartite Memorandum of Understandingbetween the two national governmentsand the State authorities has ensured fulland active support for the project. Thepassage of new oil and gas legislation inPNG has also provided the legislativeframework for the development of theproject and ensured the activeinvolvement of Provincial Governmentsand the landowner groups in thedevelopment. This is considered to beessential to the success of the projectand, again, demonstrates the strongsupport of government and the people inPNG for the project to proceed. Still,however, much remains to be done.

THE OUTLOOK FOR 1999

The provision of adequate gas reservesto underwrite markets in Queensland,and the economics of building a longand expensive pipeline from theHighlands of Papua New Guinea tocentral and possibly SE Queensland, isan essential part of ensuring the projectmay proceed. Approximately 4 TCF ofsales gas must pass through the pipelineover a 25–30 year period for the projectto be economic. In order to provide thiscertainty, it has been necessary toensure that reserves of gas are availablefrom both Kutubu and the other major(partially defined) gas resource at Hides.

It is presently considered that Kutubucan provide approximately 1.5 TCF ofgas to the project, with the balance of aminimum of 2.5 TCF coming from Hides.This was one of the two key drivers inour purchase of an interest in Hides from BP.

Negotiations for the provision of thesereserves between the two field groupstook place through the latter part of1998 and into 1999. These were difficultdiscussions, exacerbated by lack ofcertainty on how large and how fast thecustomer base for gas in Queenslandwould grow. A breakthrough wasreached in April 1999 where Oil Searchand Exxon finalised an agreementwhereby gas from Hides could bededicated to the Queensland market,should appropriate commercial terms beagreed between the upstream suppliersand customers. Under this agreement,Oil Search can represent over 50% ofthe gas to be potentially dedicated to theproject from both the Hides and Kutubufields. This provides certainty to thecustomers, allowing firm contracts to benegotiated and agreed, with full reservebacking. It also represents a major stepforward for the project and allows theproject team to proceed with majormarketing efforts.

A new approach has also been appliedto the market and customer base forgas from PNG in the past few months.Discussions with various energygenerators and distributors havehighlighted the potential to extend gasdeliveries south from Gladstone into the

SE Queensland and Brisbane markets.This would increase the market potentialupon which to build project viability fromthe maximum 140 PJ per year to over200 PJ per year, thereby significantlyenhancing our ability to exceed theminimum threshold volume for theproject to succeed. Subject toappropriate volumes being required, it is likely that a new pipeline would bebuilt down a coastal route betweenGladstone and Brisbane, allowingfurther potential to dramatically changethe east coast gas market. The recentlyexpanded marketing team will beactively pursuing energy customers in this area over the coming months, along with our more traditional base in Townsville and Gladstone.

Having reached agreement on reservededication to the Queensland market,the focus for the second and thirdquarters of 1999 will be to negotiate gas contracts and establish the project’sviability. This will involve a major effortwith the customers and an agreementhas been made with AGL to provideboth personnel and expertise to ourintense marketing efforts. They bring awealth of experience and knowledge tothe project team.

A review of the desired ownership of theproject over the past few months hasalso highlighted the desire by projectsponsors not to fully own the wet gaspipeline and liquids processing facilitiesassociated with the gas in Papua NewGuinea. This infrastructure would providea regulated, relatively low rate of returnto the project group, yet would tie upsubstantial capital. A number of pipelinebuilders and operators have approachedthe project group to take an interest inthese facilities and we will continue thesediscussions to identify appropriate

participants. A sell down of interest inthe PNG infrastructure, in a similar wayto that carried out to the APCconsortium in Australia, materiallyincreases the project’s viability for theproject sponsors and limits the amountof capital required to be spent in aregulated rate of return area.

Following an analysis of the company’sdesired equity holding in thePNG–Queensland gas project after thepurchase of equity in both Kutubu andHides, it was decided to sell a 25%interest in the Hides gas field to SantosLimited. This reduced our equity in thegas project to around 27%, with ourinterests in Kutubu and Hides at a similarlevel. The sale also allowed us to boostour balance sheet (raising a minimum of US$55 million), monetise some of ourstatic gas resource at a profit to the BPpurchase price, as well as introduce acompany that can add value to theproject through their knowledge of theQueensland gas markets and thepotential to address gas swaps andsecurity of supply issues using their gasfrom other Queensland fields.

THE WAY FORWARD

The focus of work for the early part of1999 will be to fully evaluate the availablemarkets in central and SE Queenslandand deliver sufficient gas contracts toreach project viability. We are clearlyaware of competitors for key electricitymarkets in this area and are working todeliver adequate customers for gasbefore too many of them sign up for coalgenerated projects. Although we believethe project can cope with a number ofcustomers developing coal-fired powerstations, this remains a key risk for theproject and time is running short tosecure these customers and volumes.

Discussions will be held over the comingmonths with various parties to ascertaintheir desire for taking up an interest inthe PNG infrastructure. This remains key to materially lowering the hurdle forproject viability. Although we are clearlycareful of setting realistic goals to reachmarket and commercial milestones, the complexity of this project inevitablyleads to protracted discussions andnegotiations and, commonly, somefrustration.

The North-West Shelf Project tookalmost 17 years to come to fruition; we are confident of reaching aninvestment decision in less than fouryears, sometime late in 1999.

THE IMPACT ON OIL SEARCH

The impact on Oil Search of a successfulgas project is huge. Although we nowhave a tremendous oil production andreserve base and continue to haveoutstanding exploration potential, thedevelopment of a gas project will result in outstanding growth for the company.Based on relatively conservative marketgrowth and price assumptions, asuccessful project would more thandouble company cash flows in the firstthree years of production. It would allowus to book a large portion of our gasreserves, add to our liquids reserves,change our amortisation rates and wouldhave a major impact on our profitability. It is a true company maker for Oil Searchand its shareholders, and we will continueto work hard to deliver this potential.

EXPLORATION

In 1998 Oil Search predominantlyfocussed its exploration effort on theMoran Central oil field and the Hides gas field. Two wells and a sidetrack weredrilled on the Moran structure and asignificant step-out well was drilled onthe Hides Anticline. The Hides 4 wellsuccessfully extended the knowndistribution of the Hides gas field 12 kilometres to the south-east fromHides 1, and the Moran drillingprogramme proved that a commerciallyviable oil field exists in the Moran Centralarea. In 1998, exciting progress was alsomade on the analysis of the seismic dataacquired over key areas in the Papuanfoldbelt, and seismic data acquired overboth the Kutubu and Gobe oil fieldsindicated that potentially large structuralclosures exist under both structures.These have never been penetrated bydrilling and highlight the untappedpotential in the foldbelt along with theimportance of imaging the subsurface.

One of the most importantdevelopments in the company’sexploration efforts in 1998 was thesuccess at Kimu 1 in PPL 193, whichmade a significant gas discovery in the

THE YEAR IN DETAIL

OSL A$/share

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Oil Search Limited share price and WTIWeekly from January 1996 to April 1999

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Alene Sandstone. Kimu 1, in PPL 193 in the Papuan foreland, was the first well drilled with Oil Search as Operator in over 30 years and opened up a newpetroleum province in Papua NewGuinea. The well indicated continuousfluorescence in many of the sandsintersected, demonstrating thatsignificant volumes of oil had migratedthrough the area. This was previouslyconsidered the key risk for the area.

Hides 4, in PPL 138, was spudded on26 December 1997. The objective of the well was to determine the south-eastextent of the Hides gas field and toconfirm that an economically viablevolume of gas existed for a potentialLNG project that was being consideredat the time. Hides 4 was located 12.6 kilometres south-east of the Hides1 discovery well. The well was drilled toa total depth of 3,330 metres andencountered gas saturated earlyCretaceous to late Jurassic Age Toroand Digimu sandstones over the intervalfrom 3,050 metres to 3,187 metres. A single Drill Stem Test (DST) (3,113metres to 3,140 metres) was run overthe Toro sandstone and flowed 12.9mmscfd of gas and 446 bpd through a 22/64" choke. The flow rate wasrestricted for environmental reasons. The Hides 4 well results were significantas the reservoir section appears to be inpressure communication with the Hides1, 2 and 3 wells, proving continuity ofthe field for a distance of over 12.6kilometres. It also extended the provengas column by 383 metres to 1,240metres, making it one of the longest gascolumns in the world: the hydrocarbon/water contact has still not yet beenpenetrated in the field and regionalpressure data suggests that the ultimategas column in the field may have avertical extent of over 2,000 metres.Finally, the well also confirmed that anadequate volume of gas exists not onlyfor a future LNG project but also tounderpin the PNG–Queensland gasproject. It was suspended as a potentialfuture gas producer.

Moran 4 was also drilled in PPL 138 in1988, after being spudded on 19November 1997. It was drilled as afollow-up well to the Moran 1X ST1 oildiscovery, to determine the north-westextent of the Moran Central oil field. Thewell was drilled to a total depth of 3,246metres and encountered oil saturatedEarly Cretaceous to Late Jurassic Toroand Digimu sandstones over the interval3,025 metres to 3,156 metres. DST#1was run over the Digimu sandstonefrom 3,121 metres to 3,156 metres,flowing 2,141 bpd of 40º API oil and4,949 mmscfd of gas through a 22/64"choke. DST#2 was run over the Torosandstone from 3,025 metres to 3,068metres, flowing 1,962 bpd of 39º API oiland 4,164 mmscfd of gas through a

22/64" choke. The flow rates for thetests were restricted both due tosurface equipment capacity constraintsand for environmental reasons. This wellwas significant as it extended the MoranField to the north-west into PPL 138and confirmed the Moran Central oilfield as an economically viabledevelopment. The well was completedas a future oil producer and will bebrought into the extended well testprogramme in mid 1999.

Moran 5X, located in PDL 2, wasspudded on 22 April 1998 and wasdrilled as a delineation of the Moran 1Xoil discovery. Moran 5 was drilled to atotal depth of 2,819 metres andencountered water saturated EarlyCretaceous to Late Jurassic Toro andDigimu sandstones. The well wasplugged back and Moran 5X ST#1kicked off at 1,247 metres and drilled toa total depth of 2,777 metres, 900metres to the west of Moran 5X. Itencountered good shows in the Toroand Digimu sandstones over the interval2,530 metres to 2,727 metres. Whilepulling out of the hole to run logs the drillstring became differentially stuck acrossthe Toro sandstone. Accordingly, the wellwas plugged back and Moran 5XST#2was kicked off from 2,481 metres anddrilled to a total depth of 2,786 metres,encountering oil-filled Toro and Digimusandstones over the interval 2,575metres to 2,746 metres. The wellconfirmed the southeastern extent of theMoran Central oil field and it extendedthe proven vertical oil column in theDigimu sandstone by 138 metres to1,258 metres making it one of thelongest oil columns in the world. It wascompleted as a future oil producer. TheDigimu reservoir was production testedfrom the interval 2,712 metres to 2,746metres, flowing 1,936 bpd of 48º API oiland 5,928 mmscfd of gas through a22/64"choke. The flow rate of the testwas restricted due to surface equipmentcapacity constraints.

Kimu 1 in PPL193 was spudded on 21 November 1998. It discovered a net29 metre gas-bearing interval withinexcellent quality Alene sandstones and a DST over the interval 1,620 metres to1,642 metres flowed gas at anequipment restricted rate of 7.79mmscfgd. Analysis of the test resultsindicated that the Alene sandstone hasthe capacity to flow at over 50 mmscfgdunder optimised testing conditions. Thewell also penetrated over 120 metres ofcontinuous hydrocarbon fluorescencewithin the Hedinia and Iagifu sandstoneintervals, indicating that a significant oilcharge has migrated through the PPL193 licence area. This is an importantresult in that it confirmed the OmatiTrough as an active petroleum systemand substantially upgraded theprospectivity of the company’s foreland

Dec 94 Dec 95 Dec 96 Dec 97 Dec 98

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Remaining 2P gas reserves(1998 split by field)

Others

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mmstb

Remaining 2P oil reserves(1998 split by field)

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acreage. Oil Search controls theprospective foreland acreage in PNGfollowing the acquisition of the largelicences (PPL 193, PPL 188, PPL 179,PPL 203 and PPL 208) over the pastfour years. Given that the majority of themain players in PNG had considered thearea non-prospective, Kimu 1 is a goodresult in demonstrating the existenceand potential of a new petroleum systemin the Papuan Basin.

Koko 1, the second well in the PPL 193permit, tested a very large old basement(high) and also penetrated gas saturatedHedinia sands (1,041 metres to 1,045metres) and Lower Iagifu sandstones(1,157 metres to 1,162 metres). The wellpenetrated good oil shows within theHedinia–Iagifu sandstone interval andtraces of oil were also recovered fromSFT samples taken over the Lower Iagifusandstone interval. Due to the thinness ofthe hydrocarbon-bearing sands, the wellwas plugged and abandoned. The Kokowell did confirm, however, that the PPL193 area had experienced a significanthydrocarbon charge and substantialfollow-up exists in PPL 193. Thecompany will be focussed on analysingthe well results to identify additionalopportunities in the area.

A further key development in 1998 wasthe identification by seismic of potentialfootwall structures underlying the Kutubuand Gobe oil fields. These structures willbe evaluated by further seismic work in1999 in order to establish an optimiseddrilling location to test each structure inlate 1999 or 2000. Given the closeproximity of these footwalls to existinginfrastructure any discovery ofhydrocarbons can be quickly brought onproduction which, if successful, will openup an entirely new play frontier in thePapuan Basin.

SHAREHOLDER WEALTHThere is no doubt that the singlegreatest step during 1998 to increasethe long-term wealth of shareholderswas our acquisition of BP’s upstreamassets in Papua New Guinea.

BP ACQUISITION

This step has set up the company formajor growth. The acquisition wascompleted for around US$6.50 perbarrel of proven and probable developedor near developed oil, a reasonable priceto pay for assets with the potential ofthose acquired. This potential includes alarge gas resource and a significantinterest in the upside potential of thepresently partially appraised Moran oilfield. When undeveloped gas is includedin the calculation, the acquisition costreduces to US$0.50/BOE, demonstratingthe impact that commercialising our gasreserves will have. There is no doubt it isa potential company maker.

As a result of the acquisition, we nowhave a major reserve base on which tobuild production growth, with oilproduction rates of at least 25,000 BOPDover the next five years, based onexisting fields alone. We have atremendous platform for growth, with awell-balanced mix of mature fields, newoil production, and proven fields movingtowards final development. The focus ofthe company has changed from anexploration focus to a more balancedmix of producing assets, gas potential,and exploration upside.

Furthermore, the acquisition has enabledus, with increased equity in key licences,to have a much greater influence onexploration and developmentprogrammes, and ensure that value iscreated, rather than eroded by therespective joint ventures.

CORPORATE DEBT

For the first time in Oil Search’s history, we have worked the balancesheet hard and introduced corporatedebt into the company. Funding ofUS$370 million was raised for theacquisition with an appropriate mix of bridging debt (US$292 million) and equity (US$78 million). Generallyspeaking, our aim with any acquisition is to maximise long-term earnings pershare growth and hence to follow a well used maxim of "debt is cheaperthan equity".

Whilst we recognise that there areprudent limits to gearing, we have no debt covenants which limit gearing and we are prepared to allow gearing (based upon ‘debt/debt plus equity’) to exceed 50% where, by working our balance sheet, we can minimiseequity injections. This avoids the long-term erosion of earnings per share generated by continued issues of equity.

In the case of our current debt, gearingpeaked at around 54% following theacquisition. This has already beenreduced to around 50% following theretirement of US$47.5 million of bridging finance in March 1999, afterreceipt of the first tranche of US$55million from Santos from the sale of 25% of the Hides gas field. Cash flowforecasts indicate a relatively rapidreduction in debt so that, when we drawproject debt for the PNG–Queenslandgas project, our gearing is unlikely toexceed previous peaks.

The bridging finance was raised throughWarburg Dillon Read at very competitiveterms. Despite a difficult creditenvironment, this was successfullyrefinanced with a five-year term loan at all up rates of 3.25% over LIBOR,including political risk insurance. Thiscompares very favourably with rates thatwere achievable in other capital markets.

Funding rates achieved, and the levels of debt raised, will be to the long-termbenefit of shareholders. These havebeen attained both as a result of thestrong relationships the company hasestablished with a number of banks, as well as the quality of our asset base.The borrowing base is very robust, witha break-even oil price of less thanUS$10 per barrel. This has beenenhanced by hedging 8.7 million barrelsof oil over two years from July 1999 toJune 2001 at average prices of aroundUS$14.60 per barrel.

1998 RESULTS

1998 was a very difficult year in terms ofoil price, with a drop in oil price by 35%from US$20.24 to US$13.15 per barrel.Despite this drop, most key measurablesdemonstrate a material improvementover 1997.

THE YEAR IN DETAIL

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The results were achieved partly as aresult of the larger production basefollowing the BP acquisition. If theacquisition had not gone ahead, theprofit would have been very low indeed.

With the larger production base from theacquisition, as well as first oil beingachieved at Gobe, and the extended welltest commencing from Moran, recordsales revenues of US$90.7 million wereachieved compared to US$36.4 millionin 1997. This was despite the 35% dropin the oil price. Five-year revenue historyis illustrated in the attached graph and isimpacted for the first time this year bymultiple projects being on stream.

Shareholders’ funds have alsosubstantially increased to US$308.8million from US$170 million in 1997. The increase over five years of 124%has been achieved over a period wherethe shareholder base has increased by33%, as illustrated in the graphopposite.

The restatement of accounts to USdollars, whilst causing some distortion indirect comparisons with previous years,now gives the company a much moremeaningful accounting base for futurecomparisons. Assets (net of amortisation)were written up by US$68 million. As aresult, amortisation in 1998 increased byaround US$4.8 million compared withthe old methodology. Shareholders willget a more realistic view of thecompany’s performance in the future asthe change in currency will eliminateexchange rate movements caused bytranslating US dollar assets and liabilitiesto kina each year at the prevailingexchange rate.

Improvements were also achieved byvery tight cost control in the low oil priceenvironment. Whilst a drop in Kutubuproduction has had a slightly detrimentalimpact on per barrel joint operatingcosts, tight control over administrationcosts have resulted in a drop incombined joint venture operating costsand administration costs of aroundUS$1.10 per barrel.

Earnings before interest and tax,depreciation and amortisation (EBITDA)were also at a record level, at US$60.3million, compared to US$24.3 million in1997. This increase, as illustratedgraphically, was driven by both the largerproduction base and by cost controlmeasures.

Operating profit after tax beforeabnormals totalled US$13.4 millioncompared to US$11.8 million in 1997(refer to graph). This was after writing off US$41.2 million in amortisation ofexploration and development costs(actual and forecast), a conservativeallocation of acquisition costs andcertain capitalised finance charges inMoran and Gobe. As noted above, this

charge was increased by US$4.8 millionas a result of functional currencychanges. Additionally, net interest andfinance costs totalling US$7.9 millionwere expensed (US$3.0 million incomein 1997). All interest associated withGobe, Kutubu and new explorationassets was written off. Interestassociated with Moran and theacquisition of gas assets was capitalisedand carried forward, although interest in relation to Moran was amortised, asnoted above. Overall, the 'bottom line'operating profit was down to US$9.3million, against US$14.2 million in 1997,largely due to a decision to write downthe carrying value of PPL 101 by US$5 million of expenditure incurred in the 1980s.

Operating cash flows (after allowing forthe preference share dividend) were arecord US$44.8 million (refer to graph forfive-year record) compared to US$19.5million. This demonstrates that with ourincreased production base, even at thelow oil prices experienced in 1998, weare able to generate strong cash flows.

With only a modest improvement in oilprices over 1998 levels, to some extentalready locked in by the judicioushedging programme outlined above, ourproduction and reserves base, andcontinuing tight cost control, virtuallyensures substantial growth over the nextfive years.

OUTLOOK FOR 1999

Given the present volatility of oil pricesand the impact of these on availablecashflow, the company instituted verystrict criteria for exploration expenditurebased on licence commitments andinvestments that provide opportunitiesfor an early return through production.Our exploration programme andinvestment criteria are reviewed monthlyand are subject to change depending onprice and opportunity. We will focus the1999 drilling programme on prospectswhich can be readily and quickly tiedinto production facilities such as NWGobe, NW Moran and the footwallprospects at Gobe and Hedinia. The NWGobe exploration well will be drilled inthe second quarter of 1999. It is arelatively low risk structure that has beendefined by seismic, immediately north-west of the Gobe Main field. It willbe able to be brought into productioneasily, initially through extended welltesting using the Gobe facilities, some11 kilometres to the south-east.

The Hedinia and Gobe footwallprospects also represent very attractivetargets for immediate drilling. Seismicacquisition over these structures hasreduced the risk and confirmed trapdefinition. They represent relatively largefeatures, immediately underlying theKutubu and Gobe facilities. Success

in these prospects would have animmediate effect on the company’sproduction capacity and would representa major increase in value, given theproximity of infrastructure and thepotential rapidity of development.

While present planning indicates that the1999 exploration budget will be betweenUS$10 and US$15 million, targeting upto 160 mmstb of risked reserve potentialto Oil Search, the timing and size of theprogramme will depend on the oil priceand available cashflow, not just for OilSearch but also for our joint venturepartners who have, in some cases,significant constraints on expenditures.

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Nineteen-ninety-eight was one of the most difficult and

challenging years that the oil industry has experienced.

Depressed oil prices affected the company’s profitability

and severely restricted the cash available for acquisitions,

exploration and development. This also materially

impacted share prices of oil companies, and Oil Search

has seen its share price fall to levels seen in 1996, in line

with all mid-sized companies.

The company has been pro-active in managing all

aspects of our business to achieve growth, despite

lower oil prices. This has resulted in a material reduction

in the company’s operating costs, down by more than

26% to an average of around US$4.52 per barrel

(including administration, which dropped almost 60% –

from US$1.30 per barrel to around US$0.96).

Tight cost control and a rigid review of exploration and

development expenditure throughout the year have

placed the company in a sound position to weather

expected ongoing low oil prices, and substantial growth

in oil production over the coming two years (which

should see production almost doubling from 1998 levels)

will place the company in a very strong earnings position.

A rise in oil prices over this time would also see a

material increase in profitability.

The following section answers the questions

that have been most frequently asked by

shareholders and investors. It also summarises

key developments and issues that face the

company in 1999 and beyond. I trust you will

find it a useful dialogue.

How did Oil Search meet its targets?

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1994 1995 1996 1997 1998

US$’000 US$’000 US$’000 US$’000 US$’000

PROFIT AND LOSS (A$)Sales revenue 74,957 68,494 80,155 59,494 145,517 Total revenue 85,672 75,172 84,361 64,440 149,700

Operating expenses * 9,554 8,828 10,485 12,451 39,945Administration costs 7,429 5,178 6,539 7,360 9,478

EBITDA 57,974 54,488 63,131 39,683 96,665 Amortisation 27,949 18,231 17,293 15,083 66,070

EBIT 30,025 36,257 45,838 24,271 30,024Net Interest 6,591 4,490 2,644 4,954 (12,648)

Operating profit before abnormals & income tax 36,616 40,747 48,482 29,225 17,376

Income tax expense (credit) (excl. abnormals) 15,128 15,770 22,018 10,002 (4,116)

Operating profit after income tax before abnormals 21,488 24,977 26,464 19,223 21,492

Abnormals (net of tax) – 496 2,417 (3,944) 6,528Operating profit after income tax

before extraordinary items 21,488 24,481 24,047 23,167 14,964 Extraordinary items 12,303 (1,640) – – –

Operating profit 33,791 22,841 24,047 23,167 14,964 Dividends – ordinary 5,267 4,834 4,869 4,318 –

– preference – – – – 5,746Movement in retained

earnings 28,524 18,007 19,178 18,849 14,964

BALANCE SHEET Total assets 241,341 237,571 283,377 369,519 1,228,920Exploration expenditure

incurred 19,220 31,593 32,332 34,371 47,347Development expenditure

incurred 13,903 7,452 4,235 72,635 34,815Acquisition exploration – – – – 359,738Acquisition development – – – – 364,620Total cash 90,199 11,714 61,328 76,158 38,400Total debt 47,278 – – 76,612 582,633Shareholders’ equity 176,792 208,201 258,104 259,941 508,832 OTHER INFORMATION Average realised oil price 17.73 24.18 25.80 31.23 21.67Operating cashflow 44,148 40,959 50,360 31,936 71,810Operating cashflow per

ordinary share (cents) 0.11 0.10 0.12 0.07 0.15Gearing (%) 26.74% 0.00% 0.00% 22.76% 53.38%Number of issued shares

– ordinary (000s) 386,399 425,437 467,937 468,745 468,860– preference (000s) – – – – 1,189

NET ANNUAL PRODUCTIONOil (mmstb) 3.42 2.82 3.00 2.14 6.29Gas (bcf) 0.17 0.17 0.26 0.22 3.56Total BOE (mmboe) 3.44 2.85 3.04 2.18 6.88

NET ANNUAL LIFTINGSOil (mmstb) 3.42 2.82 2.94 2.14 6.09Gas (bcf) 0.17 0.17 0.26 0.22 3.56Total BOE (mmboe) 3.45 2.85 2.98 2.18 6.68

1994 1995 1996 1997 1998

US$’000 US$’000 US$’000 US$’000 US$’000

PROFIT AND LOSS (US$)Sales revenue 46,994 48,873 61,594 36,358 90,788Total revenue 53,712 53,637 64,825 39,414 93,398

Operating expenses * 5,990 6,299 8,057 7,532 24,922Administration costs 5,683 3,285 5,365 4,556 5,557

EBITDA 35,321 39,289 48,172 24,270 60,309Amortisation 15,805 12,885 13,088 9,211 41,221

EBIT 19,516 26,403 35,084 14,846 18,732 Net Interest 3,440 2,536 2,032 3,029 (7,891)

Operating profit before abnormals & income tax 22,956 28,939 37,116 17,875 10,841

Income tax expense (credit) (excl. abnormals) 9,485 11,253 16,919 6,117 (2,568)

Operating profit after income tax before abnormals 13,471 17,686 20,197 11,758 13,409

Abnormals (net of tax) – 219 1,718 (2,412) 4,073Operating profit after income tax

before extraordinary items 13,471 17,467 18,479 14,170 9,336Extraordinary items 7,714 (1,170) – – –

Operating profit 21,185 16,298 18,479 14,170 9,336Dividends – ordinary 3,302 3,449 3,757 2,641 –

– preference – – – – 3,585Movement in retained

earnings 17,883 12,849 14,722 11,529 9,336

BALANCE SHEETTotal assets 188,209 177,443 226,358 241,644 745,832Exploration expenditure

incurred 14,989 23,597 25,826 22,272 28,747Development expenditure

incurred 0,843 5,566 3,383 47,067 21,129Acquisition exploration – – – – 218,325Acquisition development – – – – 221,288Total cash 70,342 8,750 48,988 49,797 23,305Total debt 36,870 – – 50,100 353,600Shareholders’ equity 137,871 155,507 206,170 169,986 308,810OTHER INFORMATION Average realised oil price 16.21 17.85 20.42 20.24 13.15Operating cashflow 27,678 29,226 38,698 19,533 44,802Operating cashflow per

ordinary share (cents) 0.07 0.07 0.08 0.05 0.10Gearing (%) 26.74% 0.00% 0.00% 22.76% 53.38%Number of issued shares

– ordinary (000s) 386,399 425,437 467,937 468,745 468,860– preference (000s) – – – – 1,189

Exchange ratesYear end A$: US$ 0.6269 0.7381 0.7915 0.6468 0.6069

K : US$ 0.8445 0.7425 0.7360 0.5635 0.4710K : A$ 1.0829 0.9941 0.9214 0.8617 0.7683

Average A$: US$ 0.7798 0.7469 0.7907 0.7698 0.6239K : US$ 0.9891 0.7721 0.7538 0.6822 0.4667K : A$ 1.3470 1.0406 0.9578 0.9213 0.7378

* Operating expenses includes operating costs, hedge costs, provision for siterestoration, marketing costs, royalties and insurance

FIVE YEARS OF PERFORMANCE

NWGOBE

ANGORE

SEMANANDA

WASU

KIMUKOROBOSEA

ANAMA

HIDES

AGOGO

IAGIFUHEDINIASE HEDINIA

HEDINIAFOOTWALL USANO

GOBEMAIN

SEGOBE

GOBEFOOTWALL

IEHI

BARIKE

KOKO

PROPCGS/

MORANJUHAPAUA

KOMO

˙ to Queensland

7¡ 00’S

6¡ 00’S

5¡ 00’S

9¡ 00’S

8¡ 00’S

141¡ 00’E 142¡ 00’E 143¡ 00’E 144¡ 00’E

PAPUA NEW GUINEAAUSTRALIA

IRIAN JAYA

PAPUA NEW GUINEA

10¡ 00’S

Gulf of P

PPL138

P NYANG

PROSPECT

PPL143

PPL157

PPL175

PPL179

PPL182

PPL207

PPL188

PPL

PPL193

PPL192

PPL204

APPL218

APRL03

APRL02PPL194

PPL106

PPL106

PPL106

PPL101

PDL1 PL1

POWER PLANT

PDL2

PL2

PL3

PPL161

PPL

PDL4

PDL4

PPL161

PPL161

PPL161

PDL3

PPL191

PDL2

PPL161

PPL206

PPL161

PPL199

PPL202

PPL138PPL138

PPL203

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PDL 4PDL 3 PDL 4

PPL- 161

GOBE MAIN

GPFOperationsCamp

CampAirstrip

G5AxSTG1x

GM3GM4GM5

G4xG4xST1 GM2 ST1

GM2GM1ST1

GM1ST2G6xST1

G2xST1

G2x

G7x

G3x

SEG4SEG3

SEG1SEG2SEG6ST1

0 4km

SEG6, 6ST1

G6x

SE GOBE

Hides 1

Hides 2 Hides 3

5 km0

Hides 4

Angore 1Karius 1

Power Plantand

Gas Facility Kobalu

NogollCamp

Komo

HIDES

GOBE

PPL161

PDL 2

MORA4X

2X1X

1X

5X

0 8km

OilPipeline

Agogo ProcFacilit

SE MANANDA

FLINDERS

ASUMA

URAMU

PANDORA

KUMUL TERMINAL

IKEWA

ROPOSED GS/FPSO

’E 145¡ 00’E

Kilometres

0 20 40 60 80 100

146¡ 00’E

INEA

Papua

T F

207

8

PPL189

PRL01

PPL200

PPL190

1

PPL201

APPL208

PPL184

OIL SEARCH INTEREST

OIL SEARCH APPLICATION(OPERATING/INTEREST)

OIL SEARCH OPERATED

PETROLEUM DEVELOPMENT LICENCE

PETROLEUM RETENTION LICENCE

GAS FIELD

OIL FIELD

CONDENSATE FIELD

PROSPECT

LEAD

OIL PIPELINE (PL 2 & 3)

GAS PIPELINE (PL 1)

PROPOSED GAS PIPELINETO QUEENSLAND

Licence Interests % INTEREST AS AT 1 MARCH 1999

PDL1 Hides gas field 27.50PL1 Hides gas pipeline 100.00PDL2 Kutubu oil field 27.14PL2 Kutubu pipeline 27.14PDL3 SE Gobe oil field 15.50PL3 Gobe oil pipeline 21.32PDL4 Gobe Main & SE Gobe oil fields

27.14PRL101 Pandora 5.00APRL02 Juha 6.01APRL03 P’nyang 6.01PPL138 52.50PPL161 35.02PPL179 50.00PPL184 10.00PPL188 54.55PPL189 40.40PPL190 30.10PPL193 31.25PPL199 50.00PPL200 50.00PPL203 85.00APPL208 25.00APPL218 50.00

RE

PO

RT F

RO

M T

HE

MA

NA

GIN

G D

IRE

CTO

R

Glossary of terms1p – proven reserves2p – proven and probable reserves3p – proven, probable and possible reserves

API – American Petroleum Institute (measurement of specific gravity of oil)

APPL – Application for Petroleum Prospecting Licence

APRL – Application for Petroleum Retention Licence

bbl – barrelBCF – billion cubic feetBOE – barrels of oil equivalent

BOPD – barrels of oil per dayewt – extended well test

LNG – liquefied natural gasLPG – liquid petroleum gas

mmscf – million standard cubic feet (measurement of gas volume)

mmscfd – million standard cubic feet per day mmstb – million stock tank barrels

PDL – Petroleum Development LicencePJ – PetajoulePL – Pipeline Licence

PPL – Petroleum Prospecting LicencePRL – Petroleum Retention LicenceTCF – trillion cubic feet

(measurement of gas volume)

PPL161

PDL

Agogo

lagifuAntlcline

Accessroad

Moro LakeKutubu

0 4km

Airstrip

Ridgecamp

Usano

HediniaAntlcline

AgogoProduction

Facility

CentralProcessing

Facility

PPL161PPL161

PPL161

PPL138

ORAN

1X

5X

3X

Paua 1X

Oileline

Processingacility

Moro Campand Airstrip

PAUA

MORAN KUTUBU

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Ask the Managing Director

Peter Botten

answers the questions

most commonly asked

of Oil Search in 1998

The acquisition made sense for a number of important

reasons. The purchase was done on variable economics.

We bought the residual 95% of the Hides Gas to Electricity

Project which, although small, is highly profitable and provides

us with an operating ability at Hides.

An acquisition cost of around US$6.50 per barrel of oil is

reasonable and, based on the reserves and reserve potential of

the fields involved, looks extremely cheap at around US$0.50

per barrel of oil equivalent (BOE) if we are able to commercialise

the large volumes of gas in the proven and probable inventory.

The addition of BP’s production assets, along with the

commissioning of Gobe/SE Gobe and initial development of

Moran Central, will see the company’s production rise from

around 5,800 BOPD in 1997 to more than 30,000 BOPD

in 2000. This will have a major impact on revenues and

profitability, especially if there is even a moderate increase

in oil price over this time.

Other important aspects of the transaction included the

necessity to obtain much greater influence in our major

projects. The failure of the Nomad well to find gas reserves

early in 1998 resulted in the requirement for the Hides field to

be brought into the PNG–Queensland gas project to provide

reserve backing for contracts. This would have been

impossible if BP still owned an interest in Hides, and hence

this project would now not be viable.

Although the major oil companies bring expertise to any joint

venture, materiality for them is an important issue and, where

their interests are low, PNG licences do not command funds

from their worldwide resources, especially where cash flows are

constrained by low oil prices. This can result in less than

optimal programmes for Oil Search being approved, and hence

loss in shareholder value. BP’s assets in PNG were clearly not

material to them when the prospects for LNG development

were delayed, risking the stalling of major projects such as the

PNG–Queensland gas project and the Moran oil project, due to

lack of investment.

Oil Search now has much greater influence in our key joint

ventures and will continue to optimise programmes to add

value to us.26

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Q: What was the rationale used for the acquisition?

ACQUISITION OF ASSETS FROM BP

I believe this acquisition probably represents the most important

action that the company has taken since its incorporation. It has

fundamentally changed the company from a largely exploration

orientated organisation with some production, to the company

that it is today.

Oil Search now has substantial oil production, a very large

reserve base unprecedented for a company of our size and a

dominant position in the potential commercialisation of PNG’s

gas resources. If successful, this will be a company maker for

Oil Search.

The acquisition also made us focus on our balance sheet, and

I will discuss these aspects of the acquisition later.

While we continue to have the exploration upside that we had

before, we now have major production growth and much greater

control of our assets.

Q: Clearly, the acquisition ofassets from BP was a majorhighlight in 1998. Can youplease describe what you thinkthe impact of this acquisitionhas had on Oil Search?

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Initial funding for the transaction was provided by a fully

underwritten bridging facility, at a very competitive cost, by Union

Bank of Switzerland/Warburg Dillon Read. The US$370 million

facility was reduced by the proceeds raised from an issue of

converting preference shares, and subsequently was replaced by

a successful five year term loan facility. The original intent of the

company was to replace the bridge financing with proceeds from

a bond issue. This did not proceed, however, following the

downturn of that market. We did, however, succeed in

negotiating a five year term loan with a syndicate of banks on

highly competitive terms. This facility places the company on

stable and manageable footing, even if oil prices remain in the

US$11 to US$12 per barrel range for the next few years.

The terms of the loan are very competitive, with an interest rate,

inclusive of political risk insurance, of 3.25% over LIBOR.

Security is by way of recourse over oil receivables and

specified off-shore bank accounts of the company.

Importantly, the terms of the financing have been structured to

allow a gas financing to proceed, including the necessary

completion and gas buyers’grarantees.

This financing was successfully completed, despite a difficult

market for loans. We have a very supportive group of banks,

led by UBS/WDR, who understand the company, its assets

and Papua New Guinea. We will further build on this

relationship when the gas project proceeds.

At the end of 1998 our corporate debt stood at US$353.6 million,

or a gearing level of 53%. The subsequent sale of interest in the

Hides gas field reduced this to US$314.1 (or 50.4% gearing).

Q: The acquisition has clearlyimpacted the balancesheet. Could you pleasecomment on this and thelong-term funding andfinancing of the company.

The significant drop in the oil price of almost US$7.00 per

barrel from 1997 to 1998 has impacted the profit generated

from our production base. Although we have materially

reduced operating and administration costs during the year

by about US$1.65 per barrel, this price drop directly impacts

our profits. With an average field operating cost last year of

US$3.56 per barrel, PNG oil remains one of the most profitable

oils in South-East Asia. With operating, interest and

amortisation charges included, we remain marginally profitable

at an oil price of around US$11 per barrel and, despite these

prices, the company did record a reasonable profit in 1998.

Without the impact of the acquisition our profit would have

been very small.

The acquisition has set the company up for major growth,

independent of oil price fluctuations. We now have a major

reserve base on which to build production growth from our

known fields and we can continue to produce oil at rates of

more than 25,000 BOPD for the next five years based on our

existing fields. We also have the potential to build a company-

making gas project, and the acquisition allows us to optimise

our PNG holdings and influence the programmes required for

our own value creation to a much greater extent.

Q: The deteriorating oil pricehas clearly impacted theprofitability and positiveimpact of the acquisition.Could you please comment.

REPORT FROM THE MANAGING DIRECTOR

Since we first purchased the BP assets, we have said that a

company of our size could not support an interest of around

40% in the PNG–Queensland gas project and that our

optimal equity was around 25–27%, balancing interests

across the Kutubu and Hides fields.

The sale of an interest in Hides allowed us to do a number of

things. These included: monetising some of our static gas

reserves and immediately offset some of our BP acquisition

costs without selling oil production at a discount price.

The sale raised material funds of between US$55 million

and US$90 million, of which the first payment has already

been used to reduce debt to US$314.1 million.

The sale also brought our interest in the gas project down to

a level that we can fully support, as well as introducing to

the joint venture a company that can add value to the

project in a number of ways by opening new marketing

and supply opportunities.

Following the completion of the BP acquisition, Oil Search

commissioned an independent review of its developed and

developing oil reserve base. This was carried out by the highly

reputed Netherland, Sewell & Associates, Inc. in September

1998. Netherland, Sewell & Associates, Inc. reviewed the 2P

oil reserves at Kutubu, Moran Central, Gobe/SE Gobe and

SE Mananda. They also reviewed production profiles, likely

development costs and operating expenses as a basis for the

cash flows used in our bank loan calculations.

A summary of the yearend oil reserves, calculated under

Society of Petroleum Engineers specifications for proven and

probable reserves, appears in a table on page 14. We believe

that these numbers are appropriately conservative, however, we

recognise further reserves in a number of these fields, which we

feel confident will be recognised by the auditor as production

histories are compiled and further appraisal work takes place.

We expect to continue annual reserves audits and will publish

these reserves in our future Annual Reports.

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Q: Why did you sell an interest in Hides to Santos?

Q: Could you pleasesummarise the company’sreserves position.

Oil Search has a number of fields that presently do not form part

of a development plan or a resource base that is yet to be

developed, for instance, into a gas project. We will publish a

summary of these reserves static resources each year. Gas

reserves in the Kutubu and Gobe fields were independently

reviewed during 1998 by Gaffney Cline and Associates to

provide numbers to underpin contract negotiations for the gas

project and a summary of this appears in the table on page 14.

Other gas resources not subject to this audit are also shown in

this table.

It is likely that gas reserves in the Hides gas field will be

independently audited in the first half of 1999. We will publish

this data in the 1999 Annual Report.

Q: What about other oil and gas reserves?

RESERVES

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Every year we comment on the success of the Kutubu oil fields

and this year is no exception. Kutubu continues to be an

outstanding success, even though it has reached maturity and

oil production is in decline. At the end of 1998 it had produced

almost 231 million barrels of oil with an unparalleled history of

safe and reliable operations. This is a tremendous achievement,

especially as original reserves were estimated to be less than

200 million barrels. While production rates are at around 45,000

BOPD, they are expected to decline at around 27% per year

due to the encroachment of the gas cap into the oil wells and

our requirement to reinject produced gas back into the

reservoirs. The future of this development is very much linked to

a successful gas project. Material extra liquids, extracted as

propane, butane, condensate and black oil, can be produced

from Kutubu if its gas cap can be extracted for use into a gas

project. This would bring a major increase in value to the PDL 2

participants and allow a major upgrade of reserves.

Apart from studies and work surrounding the gas project, a full

review of reservoir performance to identify further workover and

drilling opportunities in Kutubu is planned in 1999.

Q: Is Kutubu still the outstanding performerit has always been?

The successful development of the Gobe and SE Gobe oil

fields was achieved ahead of time and materially below the

original development budget of US$335 million.

First oil was exported from the project on 29 March 1998. This

was an excellent result, given that construction only commenced

in February 1997 and that the construction of roads and

facilities, required the excavation of over 5 million tonnes of

limestone.

Initial development costs were around US$290 million,

however, further development drilling will increase this to

around US$310 million – still a very reasonable US$3 per

barrel of proven and probable oil reserves.

Oil production from both fields was initially affected by sand

production from the reservoirs and poor completion

techniques which impacted reservoir deliverability. These

problems have been successfully addressed by using various

sand control methods and carrying out a number of new

completions in new sidetrack wells of the original production

wells. Initial problems were also encountered with the state-of-

the-art compressors, which are now working very well.

Whilst early production was affected by teething problems at

the development, these issues appear to have been resolved

and at the time of writing, production had increased to more

than 35,000 BOPD.

Development is now concentrating on drilling horizontal

wells which are expected to increase production towards

the estimated plateau of 50,000 BOPD. Initial results of

the horizontal drilling programme have been encouraging,

and two further wells are planned in the first part of 1999.

Q: Could you summarise the present status of theGobe Project, please?

PRODUCTIONREPORT FROM THE MANAGING DIRECTOR

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MORAN CENTRAL OIL FIELD

During 1998 the Moran 4X and 5X well, and sidetrack were

completed. These wells confirmed the extension of the

Moran Central field to the north-west and south-east, away

from the Moran 1X discovery well.

These wells confirmed the presence of approximately

100 million barrels of proven and probable oil reserves

in the area around the wells. The field is not closed to

the north-west and is only partially delineated to the south-east.

It is calculated that Moran Central has the potential to contain

150 million barrels of recoverable oil, although further drilling will

be required to confirm the field limits.

Q: Can you please give an update on drilling results inthe Moran oil field.

The Moran Central field lies immediately adjacent to the

Kutubu oil treatment facilities and hence can benefit from

using that equipment to produce the oil. This will minimise

development costs for Moran, with a target cost of around

US$1.60 per barrel.

The approach to developing this field is, therefore, quite different

to that of Kutubu and Gobe. In both of these fields, it was

necessary to fully delineate the size and shape of the oil pools

before commencing construction of stand-alone facilities, which

were specifically designed to treat crude oil from those fields.

At Moran it is quite different. As we already have some of the

facilities available it has been decided to develop the field in a

staged way so that we do not have to build substantial new

plant. This will minimise our capital investment and maximise

the use of facilities at Kutubu. It will also mean that we will

develop Moran Central then move to the north-west to NW

Moran and Komo, if drilling results warrant it. Finally, it will mean

that we will take a number of years to develop the field but that

it will cost us much less – a good trend when cash flows are

constrained due to low oil prices.

Q: What approach is being taken to develop the field?

A new and significant step has been taken at Moran to

appraise and develop the