OIL SEARCH 1998 ANNUAL REPORT
Where we are now ... OIL SEARCH LIMITED 1998 ANNUAL REPORT ... where we go from here
The company has never been better placed to build shareholder value into the new millennium. We now have a major reserve base of oil and gas, unprecedented for a company of our size. The challenge to run our business with low oil prices will be met by maximising cost-effective production, reducing our cost base, managing our cash flow and undertaking judicious exploration based on strict investment criteria, in conjunction with: ¥ Continued reserve and production growth by commercialisation of our substantial gas reserves. This will have a major impact on company profitability, cash flows and value. ¥ Continued development of our known fields at Gobe, Moran, Kutubu and Hides. ¥ Ongoing exploration success, especially in areas close to infrastructure. ¥ Continued increase in shareholder wealth. OIL SEARCH ANNUAL REPORT 1998 OIL SEARCH ANNUAL REPORT ¥ Maintaining world-class safety and environmental standards in our areas 1 of operations. OIL SEARCH ANNUAL REPORT 1998 OIL SEARCH ANNUAL REPORT
1 “ 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.”
Trevor Kennedy A.M. T 1998 Chairman OIL SEARCH ANNUAL REPOR
2 Our objectives and achievements are to ...
ACHIEVE MAJOR INCREASES IN RESERVES AND PRODUCTION LEVELS 4 DEVELOP NEW OIL AND GAS FIELDS 6 PROGRESS THE PROPOSED PNG–QUEENSLAND GAS PROJECT 8 OBTAIN A HIGH SUCCESS RATE IN EXPLORATION DRILLING 10 INCREASE OUR SHAREHOLDERS’ WEALTH 12
How we met our objectives ...
THE YEAR IN DETAIL 14 QUESTIONS TO THE MANAGING DIRECTOR 25
The results we achieved ...
FINANCIAL STATEMENTS T 1998 36 DIRECTORS’ ANNUAL REPORT 62
OIL SEARCH LIMITED (Incorporated in Papua New Guinea)
A.R.B.N. 055 079 868 OIL SEARCH ANNUAL REPOR
3 T 1998 OIL SEARCH ANNUAL REPOR
4 Our aim ... INCREASE RESERVES AND PRODUCTION
HOW WE MET OUR OBJECTIVE IN 1998
Reserves of oil and gas were at record levels at the end of 1998
• We more than doubled our proven and probable oil reserves to around 87 million barrels as at 31 December. • We quadrupled our proven and probable gas reserves to more than 4 TCF.
This was achieved through
• 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.
Production of oil and gas reached record levels for the company in 1998
• 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 the previous year. • Gas production totalled 3,555 mmscf – a 16-fold increase over 1997. T 1998 • Average daily gas production totalled 9.8 mmscfd. • Production of oil came from 4 fields, as Gobe Main, SE Gobe and Moran Central oil fields were commissioned in 1998. Only Kutubu contributed production in 1997.
Information on reserves and production appears on pages 14 and 15. OIL SEARCH ANNUAL REPOR
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6 Our aim ... DEVELOP NEW FIELDS
HOW WE PROGRESSED TOWARDS OUR OBJECTIVE IN 1998 Three new oil fields were brought on production ahead of schedule and below budget
• Oil production from the Gobe Main oil field commenced on 9 March 1998 and from SE Gobe at the end of the month, some 13 months after construction activities commenced. • Production was achieved ahead of schedule and materially below budget. • Development costs for the field, based on approximately 100 million barrels of proven and probable reserves, were a world class US$3.10 per barrel. • The Gobe Development is the first in Papua New Guinea where project area landowners received direct equity in the project at the commencement of oil production. This clearly facilitated the development process and helped to ensure no disruptions 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. Close proximity to Kutubu facilities allowed for economical development of Moran oil at a targeted development cost of around US$1.60 per barrel. • Unlike Gobe, the Moran development will be phased, involving progressive development away from the Moran Central area and utilising spare production capacity in the Kutubu facilities, where possible. The initial development will be concentrated around the Moran 1, 2, 4 and 5 wells. • Extended well testing marks a new way to rapidly commercialise discoveries in close proximity to infrastructure. It demonstrates a growing maturity in the relationships between developers, the State and landowners. Production can now commence prior 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. T 1998
Information on field development appears on pages 15 and 16. OIL SEARCH ANNUAL REPOR
7 T 1998 OIL SEARCH ANNUAL REPOR
8 Our aim ... COMMERCIALISE OUR LARGE RESERVES OF GAS
HOW WE PROGRESSED TOWARDS OUR OBJECTIVE IN 1998 Major progress was made in establishing the viability of the PNG–Queensland gas project
• Various memoranda of understanding and conditional gas sales agreements were signed with potential customers in the Townsville and Gladstone areas which underscored the likely viability of the project. These agreements cover potential market loads of up to 140 PJ per year, well in excess of the 110 PJ per year initially required for the project. • The establishment of competitive tariff arrangements and access principles for the Australian portion of the pipeline to be built and owned by the AGL Petronas consortium represented a major landmark. • The signing of accords with indigenous landowners in Queensland demonstrated clear community support for the project. • The passage of new oil and gas legislation in PNG provided the regulatory framework for the development. • The signing of a tripartite Memorandum of Understanding between Papua New Guinea’s National Government, Australia’s Federal Government and Queensland’s State Government ensured unprecedented government support for this project. • Environmental approvals for the development in Australia have removed a major potential area for delays in construction. • Technical and engineering studies provided the framework for optimal development of the production and processing facilities and pipeline. • Major progress was made in early 1999 to ensure that adequate reserves of gas are available from both Kutubu and Hides for markets in Queensland with the signing of an agreement between Oil Search and Exxon. • Progress was also made in redefining the markets in Queensland with the possible
extension of the pipeline from Gladstone into SE Queensland and the potential T 1998 delivery of gas to large power customers in the Brisbane area. • Project viability and capital cost requirements are also being revised, with the likelihood that upstream project sponsors in PNG are likely to introduce third party ownership of the pipeline and some processing facilities in PNG.
Information on the PNG–Queensland gas project appears on pages 16 to 18. OIL SEARCH ANNUAL REPOR
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10 Our aim ... HIGH SUCCESS RATE IN EXPLORATION DRILLING
HOW WE PROGRESSED TOWARDS OUR OBJECTIVE IN 1998 100% success in 1998 Four exploration wells and sidetracks were commenced in 1998, all of which were successful in proving reserves of hydrocarbons
• Successful completion of the Hides 4 well added substantial volumes of gas and liquids reserves to the Hides field. It extended the field some 12 kilometres to the south-east from existing well control and demonstrated likely reservoir continuity. • Testing of the Hides 4 well demonstrated high potential productivity of the Toro reservoirs and a materially higher liquids content in the gas. The well confirmed a gas column height in the field in excess of 1,200 metres. No hydrocarbon/water contact has yet been established for the field. • The Hides 4 well has proved that the Hides field contains a world class gas resource with reserves in excess of 5 TCF. • Moran 5X and its sidetracks successfully further delineated the Moran Central portion of 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 made at Kimu 1 and Koko 1 (the first wells operated by Oil Search for over 30 years). These wells demonstrated that significant volumes of both oil and gas have been generated in the south-east foreland area of the Papuan Basin and show that this area is likely to become a new oil and gas province in Papua New Guinea. These well results significantly upgraded the lightly explored foreland area in which Oil Search has significant licence holdings. Kimu 1 is the first well to demonstrate potentially commercial flow rates of gas from the Alene Sandstone. T 1998 • Major advances in seismic acquisition and processing techniques over the rugged foldbelt structures led to the identification of large Footwall prospects underlying the Kutubu and Gobe fields.
Information on exploration activities appears on pages 18 to 20. OIL SEARCH ANNUAL REPOR
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12 Our aim ... TO INCREASE THE WEALTH OF OUR SHAREHOLDERS
HOW WE PROGRESSED TOWARDS OUR OBJECTIVE IN 1998 The acquisition of BP assets provided a platform for growth with major new reserves and production bases
• Forecast production rates are at least 25,000 BOPD over the next five years, based on existing fields.
• The opportunity to commercialise the company’s gas was enhanced and has the potential to provide a material increase in wealth to shareholders.
• A term loan at very competitive rates was put in place EBITDA vs after year end, despite a difficult credit environment. average realised oil price
• Summary of key results US$ 000 US$ oil price per bbl 70,000 25.00 Sales revenue up 150% to US$90.8 million 60,000 20.00 EBITDA up 148% to US$60.3 million 50,000
Operating profit after tax 40,000 15.00 (before Abnormals) up 14% to US$13.4 million 30,000 10.00 Operating profit after tax down 34% to US$9.3 million 20,000 5.00 Operating cash flow 10,000 (after preference dividend) up 130% to US$44.8 million 0 0.00 1994 1995 1996 1997 1998
Shareholders’ funds up 82% to US$308.8 million EBITDA Average realised oil price
• Joint venture operating costs and administration were reduced by US$1.10 per barrel.
• Hedging of 8.7 million barrels, at US$14.60 per barrel over two years from July 1999 T 1998 to June 2001, was put in place to provide downside oil price protection and enhance debt quality.
Information on shareholders’ wealth appears on page 20. OIL SEARCH ANNUAL REPOR
13 THE YEAR IN DETAIL
RESERVES A detailed review of the company’s Reserves in the Moran Central oil field reserves in the Kutubu, Gobe Main, remain under continuous review, as The company’s reserves of proven and SE Gobe, SE Mananda and Moran production data and pressure surveys probable, developed or near developed Central oil fields took place during 1998. continue in various wells and reservoirs oil reserves rose from just over 40 million Analysis of the company’s gas resource across the field. The oil/water contacts, barrels in 1997 to 87 million barrels at in the Kutubu and Gobe fields, along and the extent of the field to the the end of 1998, following production of with SE Hedinia, Juha and P’nyang also north-west of Moran 4, remain to be 6.3 million barrels during the year. The took place, to provide a review of defined. Further appraisal drilling on company also substantially increased its available reserves for a potential gas Moran is required to evaluate the extent of reserve base for gas, more than project to supply gas into Queensland. this field and to determine the distribution quadrupling potential reserves in this These figures do not include potential of reserves away from Moran 4 to the category to more than 4 TCF, post additional black oil, condensate and LPG Moran 1 and 2X area. completion of the sale of an interest in volumes that may be recovered, should Reserves in the Gobe/SE Gobe area will the Hides gas field to Santos. a gas project proceed. These volumes, be reviewed in 1999 to incorporate the along with compositional and drilling results of the 1998-99 deliverability data, will be assessed in development drilling programme and the detail during studies planned for 1999 production history being established in and will form part of the core activities the fields. Although both the drilling and Annual BOE production for the PNG-Queensland gas project. production activities have highlighted (1998 split by field) An assessment of the company’s reserve various differences with the original field mmboe and resource base will be summarised mapping and production model, we do in all future annual reports. 8 not presently anticipate any material changes to the reserve base. 7 Reserve growth during 1998 was 6 achieved predominantly through the The Hides 4 exploration well, drilled in acquisition of further interests in the 1998, confirmed the extension of gas 5 Kutubu, Moran and Hides fields. Oil reserves some 12 kilometres to the reserves were also booked for the first 4 south-east of existing well control. It also time in the Moran Central oil field. confirmed the presence of an additional 3 383 metres of gas column in the field, Reserve levels in the Kutubu and SE which is now proven in excess of 1,200 2 Mananda fields have been adjusted for metres thick. Pressure and test data in production during 1998. A substantial 1 this well indicate continuity with other further review of production practices wells in the field, adding confidence to 0 and recovery techniques is planned at 1994 1995 1996 1997 1998 the reserve levels. No hydrocarbon/water Kutubu in 1999 to ensure that we are contact has yet been intersected and Hides Gobe Main maximising economic reserves from there is material information to suggest Moran Kutubu these fields. This is linked to ongoing that substantial downdip potential is still SE Gobe gas deliverability studies and a review present in the field. Hides represents a of the optimal development of Moran world class gas resource with likely Central/SE Mananda fields. reserves of gas in excess of 5 TCF.
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
T 1998 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 OIL SEARCH ANNUAL REPOR
14 PRODUCTION Kutubu Development Production of oil and gas reached record levels for the company in 1998, with 6.3 1998 production (100%): 18.947 mmstb (51,908 BOPD) million barrels of oil produced (up almost Operating costs per barrel: US$2.73 Estimated 2P reserves: 295 mmstb 200% from 1997) and 3,555 mmscf of gas produced (a 16-fold increase on the FACILITIES DESCRIPTION previous year). Average daily oil • 30 production and 4 injection wells (gas and water), delivering crude oil to Kutubu Central production totalled 17,223 BOPD, up Processing Facility with separation/stabilisation facilities, and transportation via export pipeline from just over 5,000 BOPD in 1997 and to the Kumul offshore loading facility 9.8 mmscfd of gas, again a substantial COMMENTS ON PRODUCTION CONSTRAINTS increase over 1997. Although the primary • Fields are in natural decline due to field maturity reason for these rises was the purchase 1999 OUTLOOK of BP’s interests in the Kutubu, Moran • Continued production decline and Hides fields, importantly, three new fields were brought into production • Positive impact from PNG–Queensland gas project during 1998 - Gobe Main, SE Gobe and • Reservoir and production optimisation studies continue to look for opportunities to optimise Moran Central. recoveries The outlook for production over the coming five years is very strong. Based on continued production of oil from Gobe/SE Gobe Development Kutubu, Gobe Main and SE Gobe and the phased development of Moran 1998 production (100%): 7.107 mmstb Gobe Main: 11,980 BOPD from start up on 9 March Central, the company’s daily production SE Gobe: 13,656 BOPD from start up on 17 April of oil will rise to over 30,000 BOPD in Operating costs per barrel: US$3.20 (excluding tariff) 2000-01. Further potential still exists in Estimated 2P reserves: 102 mmstb our various fields, plus SE Mananda, to increase this further. With rapid FACILITIES DESCRIPTION development possible through extended • 14 production/injection wells (gas and water), delivering crude oil to Gobe Central Processing well testing, exploration success at NW Facility with separation/stabilisation facilities, and transportation via export pipeline to the Gobe, Gobe Footwall, Hedinia Footwall Kumul offshore loading facility or NW Moran could provide additional COMMENTS ON PRODUCTION CONSTRAINTS oil production within this time-frame. • Production restricted due to sand production and delays to stable compression performance The successful development of a gas 1999 OUTLOOK project would also add material quantities of oil, condensate and LPGs • Horizontal wells to lift production to 50,000 BOPD to our production levels. • NW Gobe extended well test potential • Operating costs expected to decrease with full year of production DEVELOPMENT OF NEW FIELDS development costs are still at a world Analysis of production information from GOBE class US$3.10 per barrel. the field has indicated that higher production rates, and possibly enhanced Production from the Gobe Oil Project Various teething problems were oil recovery, can be achieved from the commenced on 9 March 1998, which encountered in plant commissioning, the drilling of horizontal development wells. represented the commencement of most serious of which were problems A programme of at least four horizontal Papua New Guinea’s second-ever oil experienced with the state-of–the-art wells was commenced late in 1998 and project. This was achieved 13 months gas compressors, and sand production is expected to continue through 1999 after construction activities commenced, from the Gobe Main oil wells. Repairs to increase production levels to the which was ahead of time and below and modifications to the compressors 50,000 BOPD originally anticipated in budget. This represents a major were completed in the latter part of 1998 the field design. achievement for all parties involved, and gas compression levels now exceed including Chevron and the developing the original project specifications of Exploration opportunities, including the group, government and the project area around 65 mmscfd. Gobe Footwall and NW Gobe, are drilling landowners. Gobe represents the first candidates for 1999 which, given Geotechnical studies carried out on oil development where project area success, would rapidly be brought on material from SE Gobe indicated that landowners took equity in the project production using the Gobe facilities. sand production could occur along with at the commencement of production. Seismic acquisition over the SE Gobe the oil in this field and appropriate sand This, along with a very active programme field has also highlighted further reserve control measures, such as screens, were of involvement by landowner companies potential on the forelimb of the structure. put into production wells as they were in contracts associated with construction completed. While this was not MORAN T 1998 and production work on the project, considered to be a problem in the Gobe has been an important factor in Main area, significant sand production The development of the Moran oil field satisfying the legitimate aspirations of was, however, experienced from this is utilising a different philosophy to that the landowners. field early in the development, requiring originally used at Kutubu and Gobe. Development expenditure on the project a series of well workovers and The possibility of major facilities with was around US$290 million, some recompletions so that appropriate spare production capacity at Kutubu US$30 million less than anticipated. screens could be fitted. This problem has removed the requirement to fully Further development drilling in the had been overcome by the end of 1998 appraise the Moran structure prior to project area has lifted this expenditure and production had increased to over development. The reserve threshold to to over US$300 million, however, 35,000 BOPD. make an economically viable development OIL SEARCH ANNUAL REPOR
15 THE YEAR IN DETAIL
Moran Central. The objective Moran Central EWT development costs are a world class US$1.60 per barrel. 1998 production (100%): 3.442 mmstb (10,183 BOPD from start up on 28 January) Operating costs per barrel: US$2.05 It is expected that the developers will Estimated 2P reserves: 103 mmstb apply for a production licence over the FACILITIES DESCRIPTION Moran 4 area during the second quarter • 3 production wells delivering crude oil to satellite facilities at Agogo with separation/stabilising of 1999. As Moran Central covers at facilities, for transportion via Kutubu Central Processing Facility and export pipeline to the least two licences, PDL 2 and PPL 138, Kumul offshore loading facility cost sharing and unitisation agreements COMMENTS ON PRODUCTION CONSTRAINTS have been negotiated between the groups. The development and tie-in of • Production limited to 10,000 BOPD under extended well test Moran 4 is expected early in the second 1999 OUTLOOK half of 1999. • Moran Production Licence Application mid year • Production limit increased to 15,000 BOPD PNG-QUEENSLAND GAS PROJECT • Full field development plan and engineering design Material progress was made during • Phased development to early 2000s 1998 to establish the viability of this exciting project and to bring it towards commercial reality. Most important in this process was the determination that Hides Gas to Electricity Project sufficient markets for PNG gas exist in the Townsville and Gladstone areas to 1998 production (100%): 4.97 BCF (13.6 mmscfd) support the project, along with the Operating costs per mcf: US$0.84 confirmation that a consortium of Estimated Hides field 2P reserves: 5.3 TCF AGL-Petronas (APC consortium) was FACILITIES DESCRIPTION willing to build, own and operate a • 2 alternate gas wells delivering gas to Porgera Joint Venture for power generation for Porgera pipeline to bring gas from PNG into gold mine Queensland at highly competitive tariff COMMENTS ON PRODUCTION CONSTRAINTS rates. The signing of an agreement in October 1998 between the project • production limited to gas sales contract to Porgera. developers and the APC consortium, 1999 OUTLOOK defining delivery and tariff rates, was • Potential integration into PNG-Queensland gas project probably the most significant of a number of major developments during the year.
An analysis of the size of the required market necessary in Queensland to is, therefore, quite low and the need to The potential of the Greater Moran make the project viable has shown that prove significant reserves prior to major feature is still very large and a series of initial contracts are likely to exceed capital expenditure is not required. exploration wells, including NW Moran 110 PJ per year, representing a and Komo, over the coming two years production rate of approximately Moran development is, therefore, will be required to ascertain field limits. 300 mmscfd. Although there are many breaking new ground in that, for the first projections about how the market for time in PNG, production through The scope of the phased development gas in Queensland will grow, even on extended well testing has been possible will be dependent on the success of this very conservative assumptions, it is likely using facilities at Kutubu. This represents appraisal work. The desire to limit the that the estimated gas production will a major breakthrough in developer/ duplication of facilities, maximise the use more than double in an 8–10 year period landowner relations in that, prior to of the Kutubu infrastructure and the commencing from initial delivery. We are Moran, it was necessary to have a possible material impact on development convinced that keenly priced PNG gas production licence granted before of a successful gas project will mean a will provide the platform for electricity production could commence. Early measured but steady approach to the generation and industry growth in both cashflow to the PDL 2 joint venture has, development, initially concentrating on Queensland and PNG. therefore, been possible through the extended well testing programme. Although the production capacity of the Gas operations wells in the field is in excess of 25,000 BOPD, agreements with the landowners Field Processing Marine Terminal has limited production to an average of Wet Gas Dry Gas Pipeline Pipeline 10,000 BOPD. This has recently been LPG QLD lifted to 15,000 BOPD and we are
T 1998 hopeful of more than doubling this in 1999 as licence applications proceed on the PPL 138 portion of the field. LPG Exports
LPG The present proven and probable reserves in Moran Central are around LPG Bottled Gas (PNG) 100 million barrels, however, potential exists in this area for up to 150 million Condensate Exports barrels of recoverable oil, as the extent Oil Storage of the field to the north-west and south-east requires further delineation. Oil Exports OIL SEARCH ANNUAL REPOR
16 Various potential customers in Queensland have signed conditional agreements to purchase PNG gas. These agreements exceed the threshold minimum requirements for the project to proceed, should they be turned into firm contracts. Potential customers include Stanwell Power Station Townsville (up to 48 PJ per year), Queensland Nickel and associated Trans Alta AGL power plant (20 PJ per year), Comalco Alumina refinery, Gladstone (27 PJ per year), NRG power station, Gladstone (20 PJ per year), Queensland Aluminium (20 PJ per year), and potential longer term customers such as an aluminium plant at Gove. The overall size of the potential markets in Townsville and Gladstone area is likely to be around 140 PJ per year, well in excess of the 110 PJ per year required to underwrite the project.
Significant milestones achieved in 1998 also included the signing of various accords with indigenous landowner groups in Queensland that will underscore community support for the project. This was a tremendous achievement, given recent experiences in this area, and the Operator (Chevron) and the landowners involved need to be congratulated on their frank, open and trusting approach to these difficult There has been close co-operation and It is presently considered that Kutubu issues. Environmental approvals were co-ordination between Australia’s can provide approximately 1.5 TCF of also received for the development in Federal Government, the PNG’s National gas to the project, with the balance of a Australia, and major progress was made Government and Queensland’s State minimum of 2.5 TCF coming from Hides. in PNG on these important issues. Government in co-ordinating the many This was one of the two key drivers in legislative approvals required to build a our purchase of an interest in Hides A key element to the potential success major project across two countries. A from BP. of this project is the unprecedented tripartite Memorandum of Understanding support that it is receiving from the between the two national governments Negotiations for the provision of these various National, State and Provincial and the State authorities has ensured full reserves between the two field groups Governments in PNG and Australia. and active support for the project. The took place through the latter part of passage of new oil and gas legislation in 1998 and into 1999. These were difficult This project represents the largest-ever PNG has also provided the legislative discussions, exacerbated by lack of contemplated in Papua New Guinea and framework for the development of the certainty on how large and how fast the the second-largest in Australia, after the project and ensured the active customer base for gas in Queensland North-West Shelf Project. It is involvement of Provincial Governments would grow. A breakthrough was recognised as being the only short to and the landowner groups in the reached in April 1999 where Oil Search medium term project that can materially development. This is considered to be and Exxon finalised an agreement change economic circumstances in essential to the success of the project whereby gas from Hides could be PNG, underwriting the country’s and, again, demonstrates the strong dedicated to the Queensland market, economy and growth for at least 30 support of government and the people in should appropriate commercial terms be years. In Queensland, many thousands PNG for the project to proceed. Still, agreed between the upstream suppliers of permanent jobs will be created both however, much remains to be done. and customers. Under this agreement, from the project and from industries Oil Search can represent over 50% of that will grow from the supply of large THE OUTLOOK FOR 1999 the gas to be potentially dedicated to the volumes of competitively priced gas. project from both the Hides and Kutubu It will also provide a diversity of energy The provision of adequate gas reserves fields. This provides certainty to the supply to the State and ensure well to underwrite markets in Queensland, customers, allowing firm contracts to be priced energy for one of the fastest and the economics of building a long negotiated and agreed, with full reserve growing regions in Australia. In the and expensive pipeline from the backing. It also represents a major step Australian Federal arena, a successful Highlands of Papua New Guinea to forward for the project and allows the T 1998 gas project in PNG will reduce pressure central and possibly SE Queensland, is project team to proceed with major on government and taxpayers to provide an essential part of ensuring the project marketing efforts. continued substantial aid to PNG which may proceed. Approximately 4 TCF of presently exceeds A$300 million per sales gas must pass through the pipeline A new approach has also been applied year. The use of natural gas as an over a 25–30 year period for the project to the market and customer base for energy source will also aid in achieving to be economic. In order to provide this gas from PNG in the past few months. environmental standards, especially certainty, it has been necessary to Discussions with various energy greenhouse gas emissions, that are ensure that reserves of gas are available generators and distributors have being set by governments and the from both Kutubu and the other major highlighted the potential to extend gas
international community. (partially defined) gas resource at Hides. deliveries south from Gladstone into the OIL SEARCH ANNUAL REPOR
17 THE YEAR IN DETAIL
SE Queensland and Brisbane markets. participants. A sell down of interest in Discussions will be held over the coming This would increase the market potential the PNG infrastructure, in a similar way months with various parties to ascertain upon which to build project viability from to that carried out to the APC their desire for taking up an interest in the maximum 140 PJ per year to over consortium in Australia, materially the PNG infrastructure. This remains 200 PJ per year, thereby significantly increases the project’s viability for the key to materially lowering the hurdle for enhancing our ability to exceed the project sponsors and limits the amount project viability. Although we are clearly minimum threshold volume for the of capital required to be spent in a careful of setting realistic goals to reach project to succeed. Subject to regulated rate of return area. market and commercial milestones, appropriate volumes being required, the complexity of this project inevitably it is likely that a new pipeline would be Following an analysis of the company’s leads to protracted discussions and built down a coastal route between desired equity holding in the negotiations and, commonly, some Gladstone and Brisbane, allowing PNG–Queensland gas project after the frustration. further potential to dramatically change purchase of equity in both Kutubu and the east coast gas market. The recently Hides, it was decided to sell a 25% The North-West Shelf Project took expanded marketing team will be interest in the Hides gas field to Santos almost 17 years to come to fruition; actively pursuing energy customers Limited. This reduced our equity in the we are confident of reaching an in this area over the coming months, gas project to around 27%, with our investment decision in less than four along with our more traditional base interests in Kutubu and Hides at a similar years, sometime late in 1999. in Townsville and Gladstone. level. The sale also allowed us to boost our balance sheet (raising a minimum THE IMPACT ON OIL SEARCH Having reached agreement on reserve of US$55 million), monetise some of our The impact on Oil Search of a successful dedication to the Queensland market, static gas resource at a profit to the BP gas project is huge. Although we now the focus for the second and third purchase price, as well as introduce a have a tremendous oil production and quarters of 1999 will be to negotiate company that can add value to the reserve base and continue to have gas contracts and establish the project’s project through their knowledge of the outstanding exploration potential, the viability. This will involve a major effort Queensland gas markets and the development of a gas project will result with the customers and an agreement potential to address gas swaps and in outstanding growth for the company. has been made with AGL to provide security of supply issues using their gas Based on relatively conservative market both personnel and expertise to our from other Queensland fields. growth and price assumptions, a intense marketing efforts. They bring a successful project would more than wealth of experience and knowledge to THE WAY FORWARD double company cash flows in the first the project team. The focus of work for the early part of three years of production. It would allow A review of the desired ownership of the 1999 will be to fully evaluate the available us to book a large portion of our gas project over the past few months has markets in central and SE Queensland reserves, add to our liquids reserves, also highlighted the desire by project and deliver sufficient gas contracts to change our amortisation rates and would sponsors not to fully own the wet gas reach project viability. We are clearly have a major impact on our profitability. pipeline and liquids processing facilities aware of competitors for key electricity It is a true company maker for Oil Search associated with the gas in Papua New markets in this area and are working to and its shareholders, and we will continue Guinea. This infrastructure would provide deliver adequate customers for gas to work hard to deliver this potential. a regulated, relatively low rate of return before too many of them sign up for coal generated projects. Although we believe to the project group, yet would tie up EXPLORATION substantial capital. A number of pipeline the project can cope with a number of customers developing coal-fired power builders and operators have approached In 1998 Oil Search predominantly stations, this remains a key risk for the the project group to take an interest in focussed its exploration effort on the project and time is running short to these facilities and we will continue these Moran Central oil field and the Hides secure these customers and volumes. discussions to identify appropriate gas field. Two wells and a sidetrack were drilled on the Moran structure and a significant step-out well was drilled on Oil Search Limited share price and WTI the Hides Anticline. The Hides 4 well Weekly from January 1996 to April 1999 successfully extended the known A$ US$ distribution of the Hides gas field 4.50 30.00 12 kilometres to the south-east from OSL A$/share Hides 1, and the Moran drilling 4.00 WTI US$/bbl programme proved that a commercially 25.00 viable oil field exists in the Moran Central 3.50 area. In 1998, exciting progress was also made on the analysis of the seismic data 20.00 3.00 acquired over key areas in the Papuan foldbelt, and seismic data acquired over 2.50 15.00 both the Kutubu and Gobe oil fields 2.00 indicated that potentially large structural T 1998 closures exist under both structures. 1.50 10.00 These have never been penetrated by drilling and highlight the untapped 1.00 potential in the foldbelt along with the 5.00 importance of imaging the subsurface. 0.50 One of the most important 0.00 0.00 developments in the company’s exploration efforts in 1998 was the success at Kimu 1 in PPL 193, which Apr 1999 Jan 1996 Jan 1997 Jan 1998 Jan 1999
OIL SEARCH ANNUAL REPOR made a significant gas discovery in the
18 Alene Sandstone. Kimu 1, in PPL 193 22/64" choke. The flow rates for the Operating cashflow in the Papuan foreland, was the first tests were restricted both due to well drilled with Oil Search as Operator surface equipment capacity constraints Cashflow Cashflow per share in over 30 years and opened up a new and for environmental reasons. This well US$ 000 US cents petroleum province in Papua New was significant as it extended the Moran 50,000 0.12 Guinea. The well indicated continuous Field to the north-west into PPL 138 45,000 fluorescence in many of the sands and confirmed the Moran Central oil 0.10 40,000 intersected, demonstrating that field as an economically viable 35,000 significant volumes of oil had migrated development. The well was completed 0.08 through the area. This was previously as a future oil producer and will be 30,000 considered the key risk for the area. brought into the extended well test 25,000 0.06 programme in mid 1999. Hides 4, in PPL 138, was spudded on 20,000 0.04 26 December 1997. The objective of Moran 5X, located in PDL 2, was 15,000 the well was to determine the south-east spudded on 22 April 1998 and was 10,000 0.02 extent of the Hides gas field and to drilled as a delineation of the Moran 1X 5,000 confirm that an economically viable oil discovery. Moran 5 was drilled to a 0 0.00 volume of gas existed for a potential total depth of 2,819 metres and 1994 1995 1996 1997 1998 LNG project that was being considered encountered water saturated Early at the time. Hides 4 was located Cretaceous to Late Jurassic Toro and Operating cashflow 12.6 kilometres south-east of the Hides Digimu sandstones. The well was US$ cashflow per ordinary share 1 discovery well. The well was drilled to plugged back and Moran 5X ST#1 a total depth of 3,330 metres and kicked off at 1,247 metres and drilled to encountered gas saturated early a total depth of 2,777 metres, 900 Cretaceous to late Jurassic Age Toro metres to the west of Moran 5X. It Remaining 2P gas reserves and Digimu sandstones over the interval encountered good shows in the Toro (1998 split by field) from 3,050 metres to 3,187 metres. and Digimu sandstones over the interval bcf A single Drill Stem Test (DST) (3,113 2,530 metres to 2,727 metres. While 4,000 metres to 3,140 metres) was run over pulling out of the hole to run logs the drill the Toro sandstone and flowed 12.9 string became differentially stuck across 3,500 mmscfd of gas and 446 bpd through the Toro sandstone. Accordingly, the well 3,000 a 22/64" choke. The flow rate was was plugged back and Moran 5XST#2 restricted for environmental reasons. was kicked off from 2,481 metres and 2,500 The Hides 4 well results were significant drilled to a total depth of 2,786 metres, as the reservoir section appears to be in encountering oil-filled Toro and Digimu 2,000 pressure communication with the Hides sandstones over the interval 2,575 1,500 1, 2 and 3 wells, proving continuity of metres to 2,746 metres. The well the field for a distance of over 12.6 confirmed the southeastern extent of the 1,000 kilometres. It also extended the proven Moran Central oil field and it extended 500 gas column by 383 metres to 1,240 the proven vertical oil column in the metres, making it one of the longest gas Digimu sandstone by 138 metres to 0 Dec 94 Dec 95 Dec 96 Dec 97 Dec 98 columns in the world: the hydrocarbon/ 1,258 metres making it one of the water contact has still not yet been longest oil columns in the world. It was Hides Gobe Main/SE Gobe penetrated in the field and regional completed as a future oil producer. The Kutubu/SE Mananda Angore pressure data suggests that the ultimate Digimu reservoir was production tested Moran Others gas column in the field may have a from the interval 2,712 metres to 2,746 vertical extent of over 2,000 metres. metres, flowing 1,936 bpd of 48º API oil Finally, the well also confirmed that an and 5,928 mmscfd of gas through a adequate volume of gas exists not only 22/64"choke. The flow rate of the test Remaining 2P oil reserves for a future LNG project but also to was restricted due to surface equipment (1998 split by field) underpin the PNG–Queensland gas capacity constraints. project. It was suspended as a potential mmstb future gas producer. Kimu 1 in PPL193 was spudded on 21 November 1998. It discovered a net 100 Moran 4 was also drilled in PPL 138 in 29 metre gas-bearing interval within 1988, after being spudded on 19 excellent quality Alene sandstones and 80 November 1997. It was drilled as a a DST over the interval 1,620 metres to follow-up well to the Moran 1X ST1 oil 1,642 metres flowed gas at an 60 discovery, to determine the north-west equipment restricted rate of 7.79 extent of the Moran Central oil field. The mmscfgd. Analysis of the test results well was drilled to a total depth of 3,246 indicated that the Alene sandstone has 40 metres and encountered oil saturated the capacity to flow at over 50 mmscfgd
Early Cretaceous to Late Jurassic Toro under optimised testing conditions. The T 1998 20 and Digimu sandstones over the interval well also penetrated over 120 metres of 3,025 metres to 3,156 metres. DST#1 continuous hydrocarbon fluorescence was run over the Digimu sandstone within the Hedinia and Iagifu sandstone 0 Dec 95 from 3,121 metres to 3,156 metres, intervals, indicating that a significant oil Dec 94 Dec 96 Dec 97 Dec 98 flowing 2,141 bpd of 40º API oil and charge has migrated through the PPL SE Mananda Gobe Main 4,949 mmscfd of gas through a 22/64" 193 licence area. This is an important Moran Kutubu choke. DST#2 was run over the Toro result in that it confirmed the Omati SE Gobe sandstone from 3,025 metres to 3,068 Trough as an active petroleum system metres, flowing 1,962 bpd of 39º API oil and substantially upgraded the and 4,164 mmscfd of gas through a prospectivity of the company’s foreland OIL SEARCH ANNUAL REPOR
19 THE YEAR IN DETAIL
acreage. Oil Search controls the As a result of the acquisition, we now Funding rates achieved, and the levels prospective foreland acreage in PNG have a major reserve base on which to of debt raised, will be to the long-term following the acquisition of the large build production growth, with oil benefit of shareholders. These have licences (PPL 193, PPL 188, PPL 179, production rates of at least 25,000 BOPD been attained both as a result of the PPL 203 and PPL 208) over the past over the next five years, based on strong relationships the company has four years. Given that the majority of the existing fields alone. We have a established with a number of banks, main players in PNG had considered the tremendous platform for growth, with a as well as the quality of our asset base. area non-prospective, Kimu 1 is a good well-balanced mix of mature fields, new The borrowing base is very robust, with result in demonstrating the existence oil production, and proven fields moving a break-even oil price of less than and potential of a new petroleum system towards final development. The focus of US$10 per barrel. This has been in the Papuan Basin. the company has changed from an enhanced by hedging 8.7 million barrels exploration focus to a more balanced of oil over two years from July 1999 to Koko 1, the second well in the PPL 193 mix of producing assets, gas potential, June 2001 at average prices of around permit, tested a very large old basement and exploration upside. US$14.60 per barrel. (high) and also penetrated gas saturated Hedinia sands (1,041 metres to 1,045 Furthermore, the acquisition has enabled 1998 RESULTS us, with increased equity in key licences, metres) and Lower Iagifu sandstones 1998 was a very difficult year in terms of to have a much greater influence on (1,157 metres to 1,162 metres). The well oil price, with a drop in oil price by 35% exploration and development penetrated good oil shows within the from US$20.24 to US$13.15 per barrel. programmes, and ensure that value is Hedinia–Iagifu sandstone interval and Despite this drop, most key measurables created, rather than eroded by the traces of oil were also recovered from demonstrate a material improvement respective joint ventures. SFT samples taken over the Lower Iagifu over 1997. sandstone interval. Due to the thinness of CORPORATE DEBT the hydrocarbon-bearing sands, the well was plugged and abandoned. The Koko For the first time in Oil Search’s Sales revenue vs well did confirm, however, that the PPL history, we have worked the balance average realised oil price 193 area had experienced a significant sheet hard and introduced corporate hydrocarbon charge and substantial debt into the company. Funding of Sales US$ 000 US$ oil price per bbl follow-up exists in PPL 193. The US$370 million was raised for the company will be focussed on analysing acquisition with an appropriate mix 100,000 25.00 the well results to identify additional of bridging debt (US$292 million) 90,000 opportunities in the area. and equity (US$78 million). Generally 80,000 20.00 speaking, our aim with any acquisition 70,000 A further key development in 1998 was is to maximise long-term earnings per the identification by seismic of potential share growth and hence to follow a 60,000 15.00 footwall structures underlying the Kutubu well used maxim of "debt is cheaper 50,000 and Gobe oil fields. These structures will than equity". 40,000 10.00 be evaluated by further seismic work in 1999 in order to establish an optimised Whilst we recognise that there are 30,000 drilling location to test each structure in prudent limits to gearing, we have 20,000 5.00 late 1999 or 2000. Given the close no debt covenants which limit gearing 10,000 and we are prepared to allow gearing proximity of these footwalls to existing 0 0.00 infrastructure any discovery of (based upon ‘debt/debt plus equity’) 1994 1995 1996 1997 1998 hydrocarbons can be quickly brought on to exceed 50% where, by working Sales revenue production which, if successful, will open our balance sheet, we can minimise up an entirely new play frontier in the equity injections. This avoids the Average realised oil price Papuan Basin. long-term erosion of earnings per share generated by continued issues SHAREHOLDER WEALTH of equity. Shareholders equity vs There is no doubt that the single In the case of our current debt, gearing greatest step during 1998 to increase peaked at around 54% following the ordinary shares the long-term wealth of shareholders acquisition. This has already been was our acquisition of BP’s upstream reduced to around 50% following the Equity US$ 000 No. of shares 000s assets in Papua New Guinea. retirement of US$47.5 million of 350,000 800,000 bridging finance in March 1999, after BP ACQUISITION receipt of the first tranche of US$55 300,000 700,000 million from Santos from the sale of This step has set up the company for 600,000 250,000 major growth. The acquisition was 25% of the Hides gas field. Cash flow 500,000 completed for around US$6.50 per forecasts indicate a relatively rapid reduction in debt so that, when we draw 200,000 barrel of proven and probable developed 400,000 or near developed oil, a reasonable price project debt for the PNG–Queensland 150,000 gas project, our gearing is unlikely to 300,000
T 1998 to pay for assets with the potential of exceed previous peaks. 100,000 those acquired. This potential includes a 200,000 large gas resource and a significant The bridging finance was raised through 50,000 100,000 interest in the upside potential of the Warburg Dillon Read at very competitive presently partially appraised Moran oil terms. Despite a difficult credit 0 0 field. When undeveloped gas is included environment, this was successfully 1994 1995 1996 1997 1998 in the calculation, the acquisition cost refinanced with a five-year term loan Shareholders equity reduces to US$0.50/BOE, demonstrating at all up rates of 3.25% over LIBOR, Number of ordinary shares the impact that commercialising our gas including political risk insurance. This reserves will have. There is no doubt it is compares very favourably with rates that A notional 10% increase has been allowed for preference a potential company maker. shareholders for illustrative purposes in 1998. OIL SEARCH ANNUAL REPOR were achievable in other capital markets.
20 The results were achieved partly as a charge was increased by US$4.8 million Sales revenue vs result of the larger production base as a result of functional currency average realised oil price following the BP acquisition. If the changes. Additionally, net interest and acquisition had not gone ahead, the finance costs totalling US$7.9 million profit would have been very low indeed. were expensed (US$3.0 million income Sales US$ 000 US$ oil price per bbl in 1997). All interest associated with With the larger production base from the 100,000 25.00 Gobe, Kutubu and new exploration acquisition, as well as first oil being 90,000 assets was written off. Interest achieved at Gobe, and the extended well 20.00 associated with Moran and the 80,000 test commencing from Moran, record acquisition of gas assets was capitalised 70,000 sales revenues of US$90.7 million were and carried forward, although interest 60,000 15.00 achieved compared to US$36.4 million in relation to Moran was amortised, as in 1997. This was despite the 35% drop 50,000 noted above. Overall, the 'bottom line' in the oil price. Five-year revenue history 40,000 10.00 operating profit was down to US$9.3 is illustrated in the attached graph and is million, against US$14.2 million in 1997, 30,000 impacted for the first time this year by largely due to a decision to write down 20,000 5.00 multiple projects being on stream. the carrying value of PPL 101 by 10,000 Shareholders’ funds have also US$5 million of expenditure incurred 0 0.00 substantially increased to US$308.8 in the 1980s. 1994 1995 1996 1997 1998 million from US$170 million in 1997. Operating cash flows (after allowing for Sales revenue The increase over five years of 124% the preference share dividend) were a has been achieved over a period where Average realised oil price record US$44.8 million (refer to graph for the shareholder base has increased by five-year record) compared to US$19.5 33%, as illustrated in the graph million. This demonstrates that with our opposite. increased production base, even at the The restatement of accounts to US low oil prices experienced in 1998, we dollars, whilst causing some distortion in are able to generate strong cash flows. direct comparisons with previous years, With only a modest improvement in oil Operating profit after tax vs now gives the company a much more prices over 1998 levels, to some extent average realised oil price meaningful accounting base for future already locked in by the judicious comparisons. Assets (net of amortisation) hedging programme outlined above, our Profit US$ 000 US$ oil price per bbl were written up by US$68 million. As a production and reserves base, and result, amortisation in 1998 increased by 25,000 25.00 continuing tight cost control, virtually around US$4.8 million compared with ensures substantial growth over the next the old methodology. Shareholders will five years. 20,000 20.00 get a more realistic view of the company’s performance in the future as OUTLOOK FOR 1999 the change in currency will eliminate 15,000 15.00 exchange rate movements caused by Given the present volatility of oil prices and the impact of these on available translating US dollar assets and liabilities 10,000 10.00 to kina each year at the prevailing cashflow, the company instituted very exchange rate. strict criteria for exploration expenditure based on licence commitments and 5,000 5.00 Improvements were also achieved by investments that provide opportunities very tight cost control in the low oil price for an early return through production. environment. Whilst a drop in Kutubu 0 0.00 Our exploration programme and 1994 1995 1996 1997 1998 production has had a slightly detrimental investment criteria are reviewed monthly impact on per barrel joint operating and are subject to change depending on Operating profit after tax [pre Abnormals] costs, tight control over administration price and opportunity. We will focus the Average realised oil price costs have resulted in a drop in 1999 drilling programme on prospects combined joint venture operating costs which can be readily and quickly tied and administration costs of around into production facilities such as NW US$1.10 per barrel. Gobe, NW Moran and the footwall in these prospects would have an Earnings before interest and tax, prospects at Gobe and Hedinia. The NW immediate effect on the company’s depreciation and amortisation (EBITDA) Gobe exploration well will be drilled in production capacity and would represent were also at a record level, at US$60.3 the second quarter of 1999. It is a a major increase in value, given the million, compared to US$24.3 million in relatively low risk structure that has been proximity of infrastructure and the 1997. This increase, as illustrated defined by seismic, immediately potential rapidity of development. graphically, was driven by both the larger north-west of the Gobe Main field. It will production base and by cost control be able to be brought into production While present planning indicates that the measures. easily, initially through extended well 1999 exploration budget will be between testing using the Gobe facilities, some US$10 and US$15 million, targeting up T 1998 Operating profit after tax before 11 kilometres to the south-east. to 160 mmstb of risked reserve potential abnormals totalled US$13.4 million to Oil Search, the timing and size of the compared to US$11.8 million in 1997 The Hedinia and Gobe footwall programme will depend on the oil price (refer to graph). This was after writing prospects also represent very attractive and available cashflow, not just for Oil off US$41.2 million in amortisation of targets for immediate drilling. Seismic Search but also for our joint venture exploration and development costs acquisition over these structures has partners who have, in some cases, (actual and forecast), a conservative reduced the risk and confirmed trap significant constraints on expenditures. allocation of acquisition costs and definition. They represent relatively large certain capitalised finance charges in features, immediately underlying the Moran and Gobe. As noted above, this Kutubu and Gobe facilities. Success OIL SEARCH ANNUAL REPOR
21 FIVE YEARS OF PERFORMANCE
1994 1995 1996 1997 1998 1994 1995 1996 1997 1998 US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 PROFIT AND LOSS (US$) PROFIT AND LOSS (A$) Sales revenue 46,994 48,873 61,594 36,358 90,788 Sales revenue 74,957 68,494 80,155 59,494 145,517 Total revenue 53,712 53,637 64,825 39,414 93,398 Total revenue 85,672 75,172 84,361 64,440 149,700 Operating expenses * 5,990 6,299 8,057 7,532 24,922 Operating expenses * 9,554 8,828 10,485 12,451 39,945 Administration costs 5,683 3,285 5,365 4,556 5,557 Administration costs 7,429 5,178 6,539 7,360 9,478 EBITDA 35,321 39,289 48,172 24,270 60,309 EBITDA 57,974 54,488 63,131 39,683 96,665 Amortisation 15,805 12,885 13,088 9,211 41,221 Amortisation 27,949 18,231 17,293 15,083 66,070 EBIT 19,516 26,403 35,084 14,846 18,732 EBIT 30,025 36,257 45,838 24,271 30,024 Net Interest 3,440 2,536 2,032 3,029 (7,891) Net Interest 6,591 4,490 2,644 4,954 (12,648) Operating profit before Operating profit before abnormals & income tax 22,956 28,939 37,116 17,875 10,841 abnormals & income tax 36,616 40,747 48,482 29,225 17,376 Income tax expense Income tax expense (credit) (excl. abnormals) 9,485 11,253 16,919 6,117 (2,568) (credit) (excl. abnormals) 15,128 15,770 22,018 10,002 (4,116) Operating profit after income Operating profit after income tax before abnormals 13,471 17,686 20,197 11,758 13,409 tax before abnormals 21,488 24,977 26,464 19,223 21,492 Abnormals (net of tax) – 219 1,718 (2,412) 4,073 Abnormals (net of tax) – 496 2,417 (3,944) 6,528 Operating profit after income tax Operating profit after income tax before extraordinary items 13,471 17,467 18,479 14,170 9,336 before extraordinary items 21,488 24,481 24,047 23,167 14,964 Extraordinary items 7,714 (1,170) – – – Extraordinary items 12,303 (1,640) – – – Operating profit 21,185 16,298 18,479 14,170 9,336 Operating profit 33,791 22,841 24,047 23,167 14,964 Dividends – ordinary 3,302 3,449 3,757 2,641 – Dividends – ordinary 5,267 4,834 4,869 4,318 – – preference – – – – 3,585 – preference – – – – 5,746 Movement in retained Movement in retained earnings 17,883 12,849 14,722 11,529 9,336 earnings 28,524 18,007 19,178 18,849 14,964
BALANCE SHEET BALANCE SHEET Total assets 188,209 177,443 226,358 241,644 745,832 Total assets 241,341 237,571 283,377 369,519 1,228,920 Exploration expenditure Exploration expenditure incurred 14,989 23,597 25,826 22,272 28,747 incurred 19,220 31,593 32,332 34,371 47,347 Development expenditure Development expenditure incurred 0,843 5,566 3,383 47,067 21,129 incurred 13,903 7,452 4,235 72,635 34,815 Acquisition exploration – – – – 218,325 Acquisition exploration – – – – 359,738 Acquisition development – – – – 221,288 Acquisition development – – – – 364,620 Total cash 70,342 8,750 48,988 49,797 23,305 Total cash 90,199 11,714 61,328 76,158 38,400 Total debt 36,870 – – 50,100 353,600 Total debt 47,278 – – 76,612 582,633 Shareholders’ equity 137,871 155,507 206,170 169,986 308,810 Shareholders’ equity 176,792 208,201 258,104 259,941 508,832 OTHER INFORMATION OTHER INFORMATION Average realised oil price 16.21 17.85 20.42 20.24 13.15 Average realised oil price 17.73 24.18 25.80 31.23 21.67 Operating cashflow 27,678 29,226 38,698 19,533 44,802 Operating cashflow 44,148 40,959 50,360 31,936 71,810 Operating cashflow per Operating cashflow per ordinary share (cents) 0.07 0.07 0.08 0.05 0.10 ordinary share (cents) 0.11 0.10 0.12 0.07 0.15 Gearing (%) 26.74% 0.00% 0.00% 22.76% 53.38% Gearing (%) 26.74% 0.00% 0.00% 22.76% 53.38% Number of issued shares Number of issued shares – ordinary (000s) 386,399 425,437 467,937 468,745 468,860 – ordinary (000s) 386,399 425,437 467,937 468,745 468,860 – preference (000s) – – – – 1,189 – preference (000s) – – – – 1,189 Exchange rates NET ANNUAL PRODUCTION Year end A$: US$ 0.6269 0.7381 0.7915 0.6468 0.6069 Oil (mmstb) 3.42 2.82 3.00 2.14 6.29 K : US$ 0.8445 0.7425 0.7360 0.5635 0.4710 Gas (bcf) 0.17 0.17 0.26 0.22 3.56 K : A$ 1.0829 0.9941 0.9214 0.8617 0.7683 Total BOE (mmboe) 3.44 2.85 3.04 2.18 6.88 Average A$: US$ 0.7798 0.7469 0.7907 0.7698 0.6239 NET ANNUAL LIFTINGS K : US$ 0.9891 0.7721 0.7538 0.6822 0.4667 Oil (mmstb) 3.42 2.82 2.94 2.14 6.09 K : A$ 1.3470 1.0406 0.9578 0.9213 0.7378 Gas (bcf) 0.17 0.17 0.26 0.22 3.56 Total BOE (mmboe) 3.45 2.85 2.98 2.18 6.68 * Operating expenses includes operating costs, hedge costs, provision for site restoration, marketing costs, royalties and insurance
How did Oil Search meet its targets?
Nineteen-ninety-eight was one of the most difficult and Tight cost control and a rigid review of exploration and challenging years that the oil industry has experienced. development expenditure throughout the year have Depressed oil prices affected the company’s profitability placed the company in a sound position to weather and severely restricted the cash available for acquisitions, expected ongoing low oil prices, and substantial growth exploration and development. This also materially in oil production over the coming two years (which impacted share prices of oil companies, and Oil Search should see production almost doubling from 1998 levels) has seen its share price fall to levels seen in 1996, in line will place the company in a very strong earnings position. T 1998 with all mid-sized companies. A rise in oil prices over this time would also see a material increase in profitability. The company has been pro-active in managing all aspects of our business to achieve growth, despite The following section answers the questions lower oil prices. This has resulted in a material reduction that have been most frequently asked by in the company’s operating costs, down by more than shareholders and investors. It also summarises 26% to an average of around US$4.52 per barrel key developments and issues that face the (including administration, which dropped almost 60% – company in 1999 and beyond. I trust you will
OIL SEARCH ANNUAL REPOR from US$1.30 per barrel to around US$0.96). find it a useful dialogue.
22 PPL161
5¡ 00'S MORA PPL106 4X
PPL202 PPL175 PDL 2 1X 2X PPL106 1X 5X SE MANANDA
PAPUA NEW GUINEA Oil IRIAN JAYA APRL03 Pipeline Agogo Proc Facilit PPL106 P NYANG HIDES PPL1940 8km APRL02 PPL101 ANGORE PDL1 PL1 KOMO JUHA PAUA 6¡ 00'S POWER PLANT MORAN PPL157 PPL138 PPL199 AGOGO PPL204 PPL161 PPL138 APPL218 PPL138 PPL PDL2161 IAGIFU SE HEDINIA PPL PPL161 MANANDA 161 SE HEDINIA PPL191 PPL192 PPL161 GOBE HEDINIA PPL FOOTWALL USANO 161 PDL2 MAIN WASU HIDES PDL PPL193 PL2 4 NW PPL Power Plant GOBE PL3 PDLPDL and 3 4 Gas Facility Kobalu SE GOBE IEHI 7¡ 00'SHides 1 Nogoll KOROBOSEA Camp BARIKE KIMU GOBE FOOTWALL PPL Hides 2 Hides 3 KOKO PPL206
Karius 1 Angore 1 Hides 4 PPL188 PPL203
PPL143 0 5 km Komo
GOBE PPL179 G5AxST G1x PPL- 161 GM5 GM3 8¡ 00'S GM4 G4xST1 GM2 ST1 G4x GM1ST1 GM2 GM1ST2 G6xST1 ANAMA GOBE MAIN G6x PROP CGS/ G2xST1 G2x SE GOBE PROSPECT GPF Operations G7x PDL 4 Camp SEG4 PDL 3 SEG3 PDL 4 SEG1 G3x SEG2 SEG6ST1 SEG6, 6ST1 PPL207 Camp PPL182 Airstrip 0 4km
9¡ 00'S
P T 1998 APU A N EW GUI AUS NEA TRA LIA
d n a l s Gulf of P n e e u Q
o t
10¡ 00'S Ç OIL SEARCH ANNUAL REPOR 141¡ 00'E 142¡ 00'E 143¡ 00'E 144¡ 00'E 23 PPL138 Agogo PPL161 MORAN Production KUTUBU Facility Agogo Moro Lake Kutubu Airstrip ORAN PPL184 Paua 1X 1X PPL161 Access road 5X PAUA 3X PDL lagifu PPL161 PPL161 Antlcline
Oil Ridgecamp eline Central Processing Processing acility Facility Licence Interests Hedinia Moro Camp Antlcline % INTEREST AS AT 1 MARCH 1999 and Airstrip 0 4km Usano PDL1 Hides gas field 27.50 PL1 Hides gas pipeline 100.00 PDL2 Kutubu oil field 27.14 PL2 Kutubu pipeline 27.14 OIL SEARCH OPERATED GAS FIELD OIL PIPELINE (PL 2 & 3) PDL3 SE Gobe oil field 15.50 OIL SEARCH INTEREST OIL FIELD PL3 Gobe oil pipeline 21.32 OIL SEARCH APPLICATION CONDENSATE FIELD (OPERATING/INTEREST) GAS PIPELINE (PL 1) PDL4 Gobe Main & SE Gobe oil fields PETROLEUM DEVELOPMENT LICENCE PROSPECT PROPOSED GAS PIPELINE 27.14 PETROLEUM RETENTION LICENCE LEAD TO QUEENSLAND PRL101 Pandora 5.00 APRL02 Juha 6.01 APRL03 P’nyang 6.01 1 PPL138 52.50 ASUMA PPL161 35.02 PPL179 50.00 PPL190 PPL184 10.00 PPL188 54.55 PPL189 40.40 PPL190 30.10 IKEWA PPL193 31.25 PPL189 PPL201 PPL199 50.00 PPL200 50.00 APPL208 PPL203 85.00 APPL208 25.00 8 APPL218 50.00
URAMU Glossary of terms T FROM THE MANAGING DIRECTOR KUMUL TERMINAL 1p – proven reserves 2p – proven and probable reserves 3p – proven, probable and possible reserves
ROPOSED API – American Petroleum Institute REPOR GS/FPSO (measurement of specific gravity of oil) T F APPL – Application for Petroleum Prospecting Licence APRL – Application for Petroleum Retention Licence 207 bbl – barrel BCF – billion cubic feet FLINDERS BOE – barrels of oil equivalent PPL200 BOPD – barrels of oil per day ewt – extended well test LNG – liquefied natural gas PRL01 LPG – liquid petroleum gas PANDORA mmscf – million standard cubic feet (measurement of gas volume) mmscfd – million standard cubic feet per day
I mmstb – million stock tank barrels NEA PDL – Petroleum Development Licence PJ – Petajoule Kilometres PL – Pipeline Licence Papua 0 20 40 60 80 100 PPL – Petroleum Prospecting Licence PRL – Petroleum Retention Licence TCF – trillion cubic feet (measurement of gas volume)
'E 145¡ 00'E 146¡ 00'E Peter Botten answers the questions most commonly asked of Oil Search in 1998
Ask the Managing Director T 1998 OIL SEARCH ANNUAL REPOR
25 ACQUISITION OF ASSETS FROM BP
Q: Clearly, the acquisition of assets from BP was a major highlight in 1998. Can you please describe what you think the impact of this acquisition has had on Oil Search? dominant position in the potential commercialisation of PNG’s I believe this acquisition probably represents the most important gas resources. If successful, this will be a company maker for action that the company has taken since its incorporation. It has Oil Search. fundamentally changed the company from a largely exploration The acquisition also made us focus on our balance sheet, and orientated organisation with some production, to the company I will discuss these aspects of the acquisition later. that it is today. While we continue to have the exploration upside that we had Oil Search now has substantial oil production, a very large before, we now have major production growth and much greater reserve base unprecedented for a company of our size and a control of our assets.
Other important aspects of the transaction included the necessity to obtain much greater influence in our major Q: What was the rationale projects. The failure of the Nomad well to find gas reserves used for the acquisition? early in 1998 resulted in the requirement for the Hides field to be brought into the PNG–Queensland gas project to provide The acquisition made sense for a number of important reserve backing for contracts. This would have been reasons. The purchase was done on variable economics. impossible if BP still owned an interest in Hides, and hence We bought the residual 95% of the Hides Gas to Electricity this project would now not be viable. Project which, although small, is highly profitable and provides Although the major oil companies bring expertise to any joint us with an operating ability at Hides. venture, materiality for them is an important issue and, where An acquisition cost of around US$6.50 per barrel of oil is their interests are low, PNG licences do not command funds reasonable and, based on the reserves and reserve potential of from their worldwide resources, especially where cash flows are the fields involved, looks extremely cheap at around US$0.50 constrained by low oil prices. This can result in less than per barrel of oil equivalent (BOE) if we are able to commercialise optimal programmes for Oil Search being approved, and hence
T 1998 the large volumes of gas in the proven and probable inventory. loss in shareholder value. BP’s assets in PNG were clearly not The addition of BP’s production assets, along with the material to them when the prospects for LNG development commissioning of Gobe/SE Gobe and initial development of were delayed, risking the stalling of major projects such as the Moran Central, will see the company’s production rise from PNG–Queensland gas project and the Moran oil project, due to around 5,800 BOPD in 1997 to more than 30,000 BOPD lack of investment. in 2000. This will have a major impact on revenues and Oil Search now has much greater influence in our key joint profitability, especially if there is even a moderate increase ventures and will continue to optimise programmes to add OIL SEARCH ANNUAL REPOR in oil price over this time. value to us. 26 REPORT FROM THE MANAGING DIRECTOR
Q: The deteriorating oil price has clearly impacted the amortisation charges included, we remain marginally profitable profitability and positive at an oil price of around US$11 per barrel and, despite these prices, the company did record a reasonable profit in 1998. impact of the acquisition. Without the impact of the acquisition our profit would have Could you please comment. been very small. The acquisition has set the company up for major growth, The significant drop in the oil price of almost US$7.00 per independent of oil price fluctuations. We now have a major barrel from 1997 to 1998 has impacted the profit generated reserve base on which to build production growth from our from our production base. Although we have materially known fields and we can continue to produce oil at rates of reduced operating and administration costs during the year more than 25,000 BOPD for the next five years based on our by about US$1.65 per barrel, this price drop directly impacts existing fields. We also have the potential to build a company- our profits. With an average field operating cost last year of making gas project, and the acquisition allows us to optimise US$3.56 per barrel, PNG oil remains one of the most profitable our PNG holdings and influence the programmes required for oils in South-East Asia. With operating, interest and our own value creation to a much greater extent.
Q: The acquisition has clearly impacted the balance sheet. Could you please comment on this and the long-term funding and The terms of the loan are very competitive, with an interest rate, financing of the company. inclusive of political risk insurance, of 3.25% over LIBOR. Security is by way of recourse over oil receivables and Initial funding for the transaction was provided by a fully specified off-shore bank accounts of the company. underwritten bridging facility, at a very competitive cost, by Union Importantly, the terms of the financing have been structured to Bank of Switzerland/Warburg Dillon Read. The US$370 million allow a gas financing to proceed, including the necessary facility was reduced by the proceeds raised from an issue of completion and gas buyers’grarantees. converting preference shares, and subsequently was replaced by This financing was successfully completed, despite a difficult a successful five year term loan facility. The original intent of the
market for loans. We have a very supportive group of banks, T 1998 company was to replace the bridge financing with proceeds from led by UBS/WDR, who understand the company, its assets a bond issue. This did not proceed, however, following the and Papua New Guinea. We will further build on this downturn of that market. We did, however, succeed in relationship when the gas project proceeds. negotiating a five year term loan with a syndicate of banks on highly competitive terms. This facility places the company on At the end of 1998 our corporate debt stood at US$353.6 million, stable and manageable footing, even if oil prices remain in the or a gearing level of 53%. The subsequent sale of interest in the US$11 to US$12 per barrel range for the next few years. Hides gas field reduced this to US$314.1 (or 50.4% gearing). OIL SEARCH ANNUAL REPOR
27 Q: Why did you sell an interest in Hides
to Santos? costs without selling oil production at a discount price. The sale raised material funds of between US$55 million Since we first purchased the BP assets, we have said that a and US$90 million, of which the first payment has already company of our size could not support an interest of around been used to reduce debt to US$314.1 million. 40% in the PNG–Queensland gas project and that our The sale also brought our interest in the gas project down to optimal equity was around 25–27%, balancing interests a level that we can fully support, as well as introducing to across the Kutubu and Hides fields. the joint venture a company that can add value to the The sale of an interest in Hides allowed us to do a number of project in a number of ways by opening new marketing things. These included: monetising some of our static gas and supply opportunities. reserves and immediately offset some of our BP acquisition
RESERVES
Q: Could you please summarise the company’s reserves position.
Following the completion of the BP acquisition, Oil Search A summary of the yearend oil reserves, calculated under commissioned an independent review of its developed and Society of Petroleum Engineers specifications for proven and developing oil reserve base. This was carried out by the highly probable reserves, appears in a table on page 14. We believe reputed Netherland, Sewell & Associates, Inc. in September that these numbers are appropriately conservative, however, we 1998. Netherland, Sewell & Associates, Inc. reviewed the 2P recognise further reserves in a number of these fields, which we oil reserves at Kutubu, Moran Central, Gobe/SE Gobe and feel confident will be recognised by the auditor as production SE Mananda. They also reviewed production profiles, likely histories are compiled and further appraisal work takes place. development costs and operating expenses as a basis for the We expect to continue annual reserves audits and will publish cash flows used in our bank loan calculations. these reserves in our future Annual Reports.
Q: What about other oil and gas reserves? provide numbers to underpin contract negotiations for the gas Oil Search has a number of fields that presently do not form part project and a summary of this appears in the table on page 14. of a development plan or a resource base that is yet to be Other gas resources not subject to this audit are also shown in developed, for instance, into a gas project. We will publish a this table. T 1998 summary of these reserves static resources each year. Gas It is likely that gas reserves in the Hides gas field will be reserves in the Kutubu and Gobe fields were independently independently audited in the first half of 1999. We will publish reviewed during 1998 by Gaffney Cline and Associates to this data in the 1999 Annual Report. OIL SEARCH ANNUAL REPOR
28 PRODUCTION REPORT FROM THE MANAGING DIRECTOR
Q: Is Kutubu still the outstanding performer it has always been?
Every year we comment on the success of the Kutubu oil fields our requirement to reinject produced gas back into the and this year is no exception. Kutubu continues to be an reservoirs. The future of this development is very much linked to outstanding success, even though it has reached maturity and a successful gas project. Material extra liquids, extracted as oil production is in decline. At the end of 1998 it had produced propane, butane, condensate and black oil, can be produced almost 231 million barrels of oil with an unparalleled history of from Kutubu if its gas cap can be extracted for use into a gas safe and reliable operations. This is a tremendous achievement, project. This would bring a major increase in value to the PDL 2 especially as original reserves were estimated to be less than participants and allow a major upgrade of reserves. 200 million barrels. While production rates are at around 45,000 Apart from studies and work surrounding the gas project, a full BOPD, they are expected to decline at around 27% per year review of reservoir performance to identify further workover and due to the encroachment of the gas cap into the oil wells and drilling opportunities in Kutubu is planned in 1999.
Q: Could you summarise the present status of the Gobe Project, please?
The successful development of the Gobe and SE Gobe oil problems have been successfully addressed by using various fields was achieved ahead of time and materially below the sand control methods and carrying out a number of new original development budget of US$335 million. completions in new sidetrack wells of the original production First oil was exported from the project on 29 March 1998. This wells. Initial problems were also encountered with the state-of- was an excellent result, given that construction only commenced the-art compressors, which are now working very well. in February 1997 and that the construction of roads and Whilst early production was affected by teething problems at facilities, required the excavation of over 5 million tonnes of the development, these issues appear to have been resolved limestone. and at the time of writing, production had increased to more
Initial development costs were around US$290 million, than 35,000 BOPD. T 1998 however, further development drilling will increase this to Development is now concentrating on drilling horizontal around US$310 million – still a very reasonable US$3 per wells which are expected to increase production towards barrel of proven and probable oil reserves. the estimated plateau of 50,000 BOPD. Initial results of Oil production from both fields was initially affected by sand the horizontal drilling programme have been encouraging, production from the reservoirs and poor completion and two further wells are planned in the first part of 1999. techniques which impacted reservoir deliverability. These OIL SEARCH ANNUAL REPOR
29 MORAN CENTRAL OIL FIELD
Q: Can you please give an
update on drilling results in These wells confirmed the presence of approximately the Moran oil field. 100 million barrels of proven and probable oil reserves in the area around the wells. The field is not closed to During 1998 the Moran 4X and 5X well, and sidetrack were the north-west and is only partially delineated to the south-east. completed. These wells confirmed the extension of the It is calculated that Moran Central has the potential to contain Moran Central field to the north-west and south-east, away 150 million barrels of recoverable oil, although further drilling will from the Moran 1X discovery well. be required to confirm the field limits.
Q: What approach is being
taken to develop the field? were specifically designed to treat crude oil from those fields. At Moran it is quite different. As we already have some of the The Moran Central field lies immediately adjacent to the facilities available it has been decided to develop the field in a Kutubu oil treatment facilities and hence can benefit from staged way so that we do not have to build substantial new using that equipment to produce the oil. This will minimise plant. This will minimise our capital investment and maximise development costs for Moran, with a target cost of around the use of facilities at Kutubu. It will also mean that we will US$1.60 per barrel. develop Moran Central then move to the north-west to NW The approach to developing this field is, therefore, quite different Moran and Komo, if drilling results warrant it. Finally, it will mean to that of Kutubu and Gobe. In both of these fields, it was that we will take a number of years to develop the field but that necessary to fully delineate the size and shape of the oil pools it will cost us much less – a good trend when cash flows are before commencing construction of stand-alone facilities, which constrained due to low oil prices.
Q: Can you please explain the benefits of extended
well testing. sand production problems seen at SE Gobe if we had carried out extended well testing in those wells and modified the A new and significant step has been taken at Moran to development plan a lot earlier in the programme. This would appraise and develop the field in a new way. Controlled oil have saved us substantial money. production from Moran 1X, 2X and later this year Moran 4X, Extended well testing is also a landmark achievement in the
T 1998 has resulted in our obtaining very useful production data on the maturing relations between developers, the State, and performance of each reservoir containing oil. By taking pressure project area landowners. It is clearly a breakthrough in trust readings in each reservoir we can see how continuous and how between all parties that we are able to produce oil prior to all large the oil pools are, while simultaneously obtaining a useful the details and benefits surrounding the issue of a revenue stream. Extended well testing (EWT) has allowed us to production licence being finalised. We hope to extend the bring on Moran production less than 2 years after the field was EWT concept to other new discoveries in the Kutubu, Moran discovered, compared to over 7 years for Kutubu and Gobe. It and Gobe areas, with the NW Gobe well an ideal candidate,
OIL SEARCH ANNUAL REPOR is very likely that we would not have experienced some of the if it is successful.
30 REPORT FROM THE MANAGING DIRECTOR
Q: When do you expect that the final development plan and production licence will
be issued? agreement with the landowners (we are presently able to produce an average 15,000 BOPD although the existing The Moran Central field falls within a number of licence areas wells could produce a lot more). We expect to apply for a and the joint venture participants are presently working to production licence in the middle of 1999 and expect it to be finalise the initial development plan for, the area, the various awarded early in the year 2000. We are still studying what the commercial terms of unitisation of the reserves and the cost initial optimal production rates from the field will be, but split for the development. Agreements covering the first believe that we can lift oil production to rates in excess of phase of the development have been finalised under an 35,000 BOPD by the end of the year.
EXPLORATION
Q: What were the significant achievements in your
exploration programme Kutubu and Gobe oil fields. Although it has always been in 1998? thought that these potential hydrocarbon traps have been present, recent advances in seismic acquisition in the rugged Oil Search participated in four exploration wells and Highlands have allowed us to confirm that these traps are associated sidetracks during 1998, with success achieved at there. These represent a major increase in potential reserves Moran 4X and 5X and a very important well drilled at Hides 4. and are very important in that any success in discovering oil or The Moran drilling proved that a commercially viable field gas could be developed quickly and very cheaply into the exists at Moran Central and that the field extends to the existing facilities at Gobe and Kutubu. north-west and south-east of present well control. Hides 4 Following the end of the year, two foreland wells – Kimu 1
extended the Hides gas field approximately 10 kilometres to and Koko 1 – were completed. The Kimu well discovered a T 1998 the south-east of Hides 3, proving the continuity of the 29 metre net gas bearing reservoir in the Alene Sandstone accumulation and adding almost 400 metres to the proven which demonstrated very high productivity. Koko 1 gas column which now stands at over 1,200 metres. No discovered gas in the Hedinia and Lower Iagifu sandstones hydrocarbon/water contact has been intersected in this large and recovered oil in the Lower Iagifu. Although this well was gas field. plugged and abandoned, it clearly demonstrated that large Other important events included the successful identification volumes of both oil and gas have been generated in the
of large footwall structures below or very close to our existing south-eastern foreland area. OIL SEARCH ANNUAL REPOR 31 Q: What is the significance of finding oil and gas in
the foreland? significantly. The foreland area is only lightly explored and it has the advantage that good quality seismic can be acquired The geology seen in the foreland area is very similar to that of in the area and the logistics needed for exploration and the highly productive North-West Shelf of Australia which has development are much easier and cheaper than in the numerous discoveries. The primary risk in exploration in the Highlands. foreland was that insufficient oil and gas had been generated Although much work remains to be done, the south-east in the area to form potentially commercial accumulations. foreland area could develop into a new oil and gas province The results of Kimu and Koko have demonstrated that large in Papua New Guinea. Oil Search has much of this area volumes of oil and gas have been generated in the area and under licence and is very well situated to add real value to its hence the risk of each of the prospects has reduced licence holdings.
Q: What will be the main focus for exploration over
the coming 1 to 2 years? mature further northern extensions, such as Komo, to drillable status. The recent period of low oil prices has forced a lot of There will also be a focus on drilling close to the Gobe companies to review their upcoming exploration programmes infrastructure where North-West Gobe is due to start drilling in the light of diminished cash flows. Oil Search has closely in early April. Given success in this well, it will be possible to reviewed its exploration strategy and will continue to tie this well into the Gobe facilities and commence production judiciously explore as we must clearly continue to more than through extended well testing. replace the reserves that we produce. The exploration Recent seismic acquisition in the Gobe area, to further define programme in 1999 will remain flexible, being reviewed the Gobe footwall prospect, has proved very encouraging, regularly, in the light of changing oil prices. There will be a and a well to test this structure is planned as part of the strong focus on areas where any discovery can be brought Gobe development drilling programme. Further work is also
T 1998 into production very quickly and cheaply. The emphasis will planned to mature the Kutubu footwall structure for drilling. be to further appraise the Moran field, slowly extending the A full review of the foreland area, together with the results of field initially to the north-west. The drilling of North-West Kimu and Koko, will still make 1999 a meaningful, albeit Moran is likely in the latter half of 1999, along with work to somewhat subdued, exploration year. OIL SEARCH ANNUAL REPOR
32 REPORT FROM THE MANAGING DIRECTOR
Q: How much potential remains in the company’s exploration portfolio? The success of seismic in the Highlands has also the The exploration potential in our Highlands and foreland potential to increase our inventory as prospects such as the licences remains very large; indeed, with the positive results at Kutubu and Gobe footwall plays are identified. A number of Kimu and Koko, it has materially increased. The present prospects in our off-shore areas have also been enhanced by inventory contains over 80 leads and prospects, with potential the Kimo and Koko results. Simple extensions of the Moran unrisked reserves in excess of 3 billion barrels of oil and over Central field, such as North-West Moran and Komo, are also 3.5 TCF of gas. high impact prospects with relatively low risk.
PNG–QUEENSLAND GAS PROJECT
Q: Could you explain the present status of this project and why there appear to be continuing delays. Guinea’s National Government, Australia’s Federal Significant progress was made during 1998 to bring this Government and Queensland’s State Government to make project towards commercial reality. This included better this project work. Environmental approvals and the support market definition, with a growing certainty that sufficient of various indigenous groups in Australia and PNG have also
markets exist in Queensland to allow this project to proceed, materially improved the chances of the project proceeding. T 1998 the finalisation of very competitive access principles and tariff The passage of the new Oil and Gas Act in PNG also framed arrangements for the Australian portion of the pipeline and a stable and favourable fiscal regime which provides certainty the continued unprecedented support of Papua New to investors and other project stakeholders. OIL SEARCH ANNUAL REPOR
33 PNG–QUEENSLAND GAS PROJECT (CONTINUED)
Q: Progress towards project certainty appears frustratingly slow. Could you please outline what are
the present hurdles to the to immediately underwrite contracts in Queensland was project proceeding. present in the Hides gas field. Discussions commenced between the Kutubu and Hides
There are a number of important milestones that must be licence groups for the integration of both fields into the achieved for the project to receive endorsement from its project, as agreements on production rates and project sponsors. participation was required before appropriate representations The major hold-up in assessing the viability of the project has could be made to the potential gas customers in been resolution of how adequate gas reserves can be Queensland. While agreement between the two licence committed from various fields in PNG to the project. groups on these key commercial issues has proved extremely Following the unsuccessful Nomad 1X exploration well, it was difficult, a sound commercial solution to enable appropriate clear that there was not enough gas in Chevron operated reserves to be guaranteed to the markets was being finalised licences to underpin the reserve requirements for markets in at the time of compilation of this report. This resolution will Queensland. Although there are substantial reserves of gas in see a much greater participation by the Hides Group in the PNG, the only volume large enough to provide sufficient gas management and direction of the project.
SAFETY
Q: Given the sensitivity of safety and environmental issues, what are Oil Search’s
records in these areas? safety of our employees, contractors and the local community Oil Search was able to drill two wells in logistically Most oil and gas companies are now focussed on difficult areas without a lost time incident in more than undertaking their activities in a safe and environmentally 100,000 hours worked. sensitive manner. Importantly however, some companies fail Oil Search involved the local community in many aspects of to translate their verbal commitment on safety and the the operations from site clearance, road building to working environment into tangible results. At Oil Search the safety of around the rig floor as roustabouts. All of these areas
T 1998 our employees and the community with which we work are of contain safety risks and it is a credit to those involved who the utmost importance and this is demonstrated by our ensured that all activities were carried out in an environment record. During 1998 Oil Search became the Operator of the in which safety was not only discussed but became a state Hides Gas to Electricity Project and, by year end, had of mind. completed almost 800,000 hours without one lost time Oil Search is absolutely committed to safety, health and incident. Oil Search also operated an exploration drilling environmental issues affecting its staff as well as the community programme for the first time in more than 30 years. Due to and environment in which we operate. Our verbal commitment
OIL SEARCH ANNUAL REPOR our extensive local knowledge and our commitment to the is demonstrably translated into outstanding results.
34 Y2K ISSUES REPORT FROM THE MANAGING DIRECTOR
Q: What measures has the company implemented to ensure that it will be compliant in respect of Year 2000 issues? technology systems that the company maintains in PNG and Australia, as well as the interaction with Year 2000 Projects of The company established a Year 2000 Project in 1998 with our joint venture partners for our other operational facilities. the goal of ensuring that Oil Search’s core business areas and A Year 2000 Project Co-ordinator was assigned to administer processes will continue to function safely and without the project and co-ordinate both internal staff and external disruption from 31 December, 1999. The prime focus of the consultants engaged on the project. The Co-ordinator reports project is on the operation of the facilities at the Hides Gas to to the Managing Director and the Board on the progress of Electricity Project (which Oil Search Operates), the information the project. The project has an initial budget of $500,000.
Q: Are you confident that there will be no significant downtime or other material impacts to the company as a
result of the millennium bug? equipment will be tested and made compliant by 31 December, 1999. All IT vendors are required to Yes. Oil Search has dedicated certain personnel specifically to provide statements of compliance, and discussions ensuring that the company’s systems, and those if its have been underway for some time with vendors such suppliers, will continue to operate accurately and safely over as telecommunications suppliers, building managers the period of concern. Significant work has already been and utilities suppliers, such as electricity, gas and water, to undertaken to ensure that all of Oil Search’s computer ensure that their supplies will also continue uninterrupted. T 1998 OIL SEARCH ANNUAL REPOR
35 PROFIT & LOSS ACCOUNT
Q: Why has profit after tax dropped from US$14.2 million in 1997 to US$9.3 million in 1998, despite revenue being up 137%?
There are a number of reasons for the reduced profitability. The main factor is the fall in oil price, which has dropped from an average of US$20.24 to US$13.15 per barrel while operating costs, by their nature, remained relatively steady on a per barrel basis
The next major factor is the expensing of financing costs in relation to the Gobe Project in 1998, whereas in 1997 these were capitalised. Australian Accounting Standards require that costs such as these be capitalised until TEMENTS the field commences production. Finally, 1998 was also impacted by the writing off of US$4.0 million of Abnormal Items, being exploration expenditure A in relation to PPL 101 and foreign exchange losses incurred during the year.
Q: Why has only 50% of interest been expensed in the accounts?
This is also a requirement of Australian Accounting Standards, which requires that interest costs, in this case in relation to the Bridge Facility, is divided between capital and revenue accounts. Where the interest relates to potential future projects, such as the PNG–Queensland gas project or Moran full field development, interest is capitalised. Where the interest relates to existing projects or to exploration, it is written off to the profit and loss as it is incurred.
Q: Why does the company have such a low effective income tax rate? T 1998
The main reason for the tax rate looking so low is due to the impact of the acquisition of BP’s assets. While Oil Search entered into the transaction with BP at the end of April 1998, and took effective control of the assets at that date, completion was not reached until 13 August. Under PNG taxation law, the income earned on the assets during this period was assessable income to BP, whereas it was booked as revenue in the books of Oil Search. Thus,
OIL SEARCH ANNUAL REPOR it was reported as income which was exempt from tax in the books of
36 Oil Search, creating a large tax credit of around US$7.2 million. FINANCIAL ST FOR THE YEAR ENDED 31 DECEMBER 1998
CONSOLIDATED CHIEF ENTITY NOTE 31/12/98 31/12/97 31/12/98 31/12/97 US$’000 US$’000 US$’000 US$’000 Note 1(p) Note 1(p)
Operating revenue 2 93,398 39,414 34,608 18,299 Operating profit before abnormal items and income tax 2 10,841 17,875 27,907 12,730 Abnormal items before income tax 3 (4,073) 2,412 (13,257) 8,130 Income tax expense (credit) attributable to operating profit 4 (2,568) 6,117 54 1,041 Operating profit after income tax 9,336 14,170 14,596 19,819 Retained profits at the beginning of the financial year 1(b)(p) 42,927 43,801 (6,899) 34,739 Total available for appropriation 52,263 57,971 7,697 54,558 Dividends provided for or paid 6 (3,585) (2,641) (3,585) (2,641) Retained profits at the end of the financial year 48,678 55,330 4,112 51,917
The profit and loss account should be read in conjunction with the accompanying Notes. T 1998 OIL SEARCH ANNUAL REPOR
37 BALANCE SHEET
Q: Why did the company change its functional currency from kina to US$?
It was considered that reporting in US$ better reflects the performance of the company and allows shareholders and investors to analyse the company’s results without major distortions in currency movements. The vast majority of the company’s business is transacted in US$, with substantially all revenues and over 90% of expenditure denominated in that currency, rather than in kina. It was also considered that, as the company’s business grows in both size and complexity, continued reporting in kina will be distorted by abnormal swings in currency conversions, the results of which would be difficult to interpret and be confusing to many shareholders. The change in functional currency is consistent with the approach taken by other listed companies under similar circumstances, such as Lihir Gold Limited, Niugini Mining Limited and Fletcher Challenge Energy Limited.
Q: What was the impact on the results of changing the functional currency?
The results are really impacted in two ways from changing the company’s functional currency–amortisation charges and foreign currency gains and losses. Amortisation charges are the writing off of the costs of assets, based on their historical costs. In Oil Search’s case, many of its asset costs were incurred when the kina was at least on par with the US$. Subsequent to that, while the kina has depreciated and the amortisation charges have remained relatively fixed in kina terms, they have appeared lower when they were converted to US$ or A$ for reporting purposes. Now that the costs of these assets have been recalculated into actual US$ at historic exchange rates this has, effectively, increased the T 1998 amortisation charges in US$ terms.
The foreign exchange movements in the kina denominated accounts largely arose due to a continually depreciating kina against the US$, while the majority of the company’s monetary assets and liabilities (bank loans and receivables in respect of oil sales) were denominated in US$. This impact has largely been eliminated in the US$ denominated accounts. OIL SEARCH ANNUAL REPOR
38 AS AT 31 DECEMBER 1998
CONSOLIDATED CHIEF ENTITY NOTE 31/12/98 31/12/97 31/12/98 31/12/97 US$’000 US$’000 US$’000 US$’000 Note 1(p) Note 1(p)
Current assets Cash 23(b) 23,305 49,800 16,080 46,513 Receivables 7 16,278 6,875 265,042 48,419 Inventories 8 14,865 5,670 275 285 Total current assets 54,448 62,345 281,397 95,217 Non current assets Receivables 9 493 342 191,371 13,013 Investments 10 – – 6,000 4,200 Plant and equipment 11 1,582 1,298 550 233 Exploration and development costs 12 684,138 175,273 85,412 64,242 Other 13 5,171 2,386 145 152 Total non current assets 691,384 179,299 283,478 81,840 Total assets 745,832 241,644 564,875 177,057 Current liabilities Accounts payable 14 64,947 11,349 6,212 2,349 Borrowings 15 72,100 7,420 62,800 – Provisions 16 1,156 6,127 598 3,202 Total current liabilities 138,203 24,896 69,610 5,551 Non current liabilities Accounts payable 17 – – 4,187 3,932 Borrowings 18 281,500 42,680 221,700 – Provisions 19 17,319 4,082 5,134 1,001 Total non current liabilities 298,819 46,762 231,021 4,933 Total liabilities 437,022 71,658 300,631 10,484 Net assets 308,810 169,986 264,244 166,573 Shareholders’ equity Share capital 20 260,132 114,656 260,132 114,656 Retained profits 48,678 55,330 4,112 51,917 Total shareholders’ equity 308,810 169,986 264,244 166,573
The balance sheet should be read in conjunction with the accompanying Notes. 1998 OIL SEARCH ANNUAL REPORT
39 STATEMENT OF CASH FLOWS
Q: What impact does the continued fall in the value of the kina have on the company s activ ities and finances?
The impact of the falling kina to Oil Search has been relatively minimal, as almost all of the company’s earnings and borrowings are denominated in US$. This has provided a natural hedge against the falling value of the kina. Obviously, we have a certain amount of income and expenditure that is denominated in kina, and we have certainly seen these costs increase over the past few years. Fortunately, however, the company’s exposure to this impact is minimal and is largely protected by bringing funds onshore to PNG to meet much of this expenditure as it is required.
Q: Why is the company not paying a div idend this year? In light of the poor share price performance, shouldn t the company give something back to its shareholders?
The Board considered the decision of whether or not to pay a dividend to its ordinary shareholders this year very carefully, and decided against paying one for the first time in a number of years. This decision was reached having regard to the low oil price environment in which the company is presently operating, which necessitates very prudent cash management. It was felt that the cash outflow that would result from the payment of an ordinary dividend would be better utilised towards the company’s exploration programme or towards retiring some of the company’s debt. T 1998 OIL SEARCH ANNUAL REPOR
40 FOR THE YEAR ENDED 31 DECEMBER 1998
CONSOLIDATED CHIEF ENTITY NOTE 31/12/98 31/12/97 31/12/98 31/12/97 US$’000 US$’000 US$’000 US$’000 Note 1(p) Note 1(p)
Cash flows from operating activities Receipts from customers 85,484 39,395 1,319 1,622 Payments to suppliers and employees (30,760) (13,649) (4,583) (4,204) Interest received 2,928 2,779 2,471 2,114 Interest and other costs of finance paid (8,179) (2) – (1) Income tax paid (4,671) (8,991) – – Dividends received – – 25,000 10,558 Net operating cash flows 23(a) 44,802 19,532 24,207 10,089 Cash flows from investing activities Payments for property, plant and equipment (400) (852) (106) (28) Interest paid and capitalised into asset values (7,332) – – – Other – exploration and development costs incurred (38,809) (69,900) (10,626) (21,526) Payments for the acquisition of exploration and development assets (393,007) – – – Net investing cash flows (439,548) (70,752) (10,732) (21,554) Cash flows from financing activities Loans to controlled entity – – (393,895) (4,107) Loans from controlled entity – – 9,944 19,096 Proceeds from shares issued 69,733 610 69,733 610 Dividends paid (6,226) (2,637) (6,226) (2,637) Loans repaid by State Nominee – 14,381 – – Borrowings 303,500 40,965 284,500 – T 1998 Net financing cash flows 367,007 53,319 (35,944) 12,962 Net (decrease) increase in cash held (27,738) 2,099 (22,469) 1,497 Cash at the beginning of the year 49,800 37,507 46,513 35,992 Exchange rate adjustments to the opening balance 1,243 10,194 (7,964) 9,024 Cash at the end of the year 23(b) 23,305 49,800 16,080 46,513 OIL SEARCH ANNUAL REPOR
41 This statement of cash flows should be read in conjunction with the accompanying Notes. NOTES TO AND FORMING PART OF THE ACCOUNTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
While the chief entity is incorporated in Papua New Guinea, all amounts are expressed in US$ as this is the functional currency of the economic entity. (a) Basis of accounting The general purpose financial statements have been made out in accordance with Australian Corporations Law, applicable Australian Accounting Standards and mandatory reporting requirements. These standards substantially meet the requirements of the International Accounting Standards adopted in Papua New Guinea and Papua New Guinea Accounting Standards, as they apply to these financial statements, with the exception of the following: Accounting for Income Taxes – As the fair value of assets acquired during the year exceeds their tax base, the tax effect of the difference is treated under IAS-12 “Income Taxes” as an increase in the deferred income tax liability of US$31.6 million and the equivalent amount is an increase in Accumulated Exploration and Development Expenditure. These amounts have not been reflected in the balance sheet. There is no amortisation impact on the profit and loss as these assets are categorised in the exploration phase. (b) Change in accounting policies The economic entity changed its functional currency from kina to US$ on 1 January 1998 to more accurately reflect the currency of its underlying business. The material cumulative financial impacts of this change on the opening balances and reporting were as follows:
Consolidated Chief Entity Balance sheet category Increase/(decrease) Increase/(decrease) US$’000 US$’000
Retained earnings (12,430) (58,816) Accumulated exploration costs 55,119 18,785 Accumulated development costs 58,072 1,024 Accumulated amortisation (45,155) (865) Provision for deferred income tax (5,290) (4,078) Capital 75,742 75,742 (c) Plant and equipment
T 1998 Plant and equipment are carried at cost. Any gain or loss on the disposal of assets is determined as the difference between the carrying value of the asset at the time of disposal and the proceeds from disposal, and is included in the results of the economic entity in the year of disposal. Depreciation Depreciation is calculated on a straight line basis on all plant and equipment so as to write off the cost of each fixed asset during its effective life. Depreciation is applied to joint venture
OIL SEARCH ANNUAL REPOR plant and equipment so as to expense the cost of each item over the estimated economic life of the reserves with which it is associated. 42 NOTES TO THE ACCOUNTS
Note Page
1 Summary of significant accounting policies 42 FOR THE YEAR ENDED 31 DECEMBER 1998 2 Operating profit before income tax 45 3 Abnormal items 46 (d) Currency translation 4 Income tax 46 Translation of transactions denominated in currencies other than US$ 5 Consolidated entities 47 Transactions in currencies other than US$ of entities within the economic entity are converted to US$ at the rate 6 Dividends paid or of exchange ruling at the date of the transaction. provided for 47 Amounts payable to and by the entities within the economic entity that are outstanding at the balance date and 7 Receivables (current) 47 are denominated in currencies other than US$ have been converted to US$ using rates of exchange ruling at 8 Inventories 48 the end of the financial year. 9 Receivables (non current) 48 All resulting exchange differences arising on settlement or re-statement are brought to account in determining 10 Investments (non current) 48 the profit or loss for the financial year. 11 Plant and equipment 48 Translation of accounts of foreign operations 12 Exploration and All overseas operations are deemed to be integrated as each is financially dependent on Oil Search Limited. development costs 48 The accounts of foreign operations are translated using the temporal method and exchange gains and losses 13 Other assets (non current) 48 arising on translation are brought to account in the profit and loss account of the economic entity. 14 Accounts payable 48 (e) Exploration and development costs 15 Borrowings (current) 49 Costs carried forward 16 Provisions (current) 49 The area of interest method of accounting for pre-production costs has been adopted. Areas of interest are 17 Accounts payable (non current) 49 defined as individual petroleum prospecting and development licence areas. 18 Borrowings (non current) 49 All exploration, evaluation and development costs in respect of each area of interest are accumulated and 19 Provisions (non current) 49 carried forward provided the rights to tenure of the area of interest are current, and such costs are expected to 20 Share capital 49 be recouped through successful development, or by sale, or where exploration and evaluation activities have not reached a stage to allow reasonable assessment regarding the existence of economically recoverable reserves. 21 Interests in joint ventures 49 Restoration costs 22 Contingent liabilities and commitments 50 Where significant site restoration costs are expected on cessation of producing operations, a provision is raised 23 Statement of cash flows 51 and charged against profits for those costs, calculated on a unit of production basis over the reserves of that 24 Directors’ and Executives’ field. The amount provided for site restoration costs is disclosed in Note 19 to the financial statements and remuneration 52 includes demobilisation of joint venture assets and environmental regeneration, where required. The provision for 25 Auditors’ remuneration 53 restoration costs is reassessed at balance date based on current estimates of undiscounted future costs, and 26 Employee entitlements any adjustment required to restate the provision is brought to account over the remaining life of that field. and superannuation commitments 53 Amortisation of development and exploration costs 27 Related party transactions 54 Costs in relation to productive areas are amortised on a production output basis. In relation to the Kutubu, Gobe 28 Earnings per share 54 and Moran oil fields, exploration and development costs, along with any future expenditure necessary to develop T 1998 the assumed reserves, are amortised over the remaining estimated economic life of the fields. 29 Segment reporting 54 Costs in relation to the Hides gas project are amortised in order to expense accumulated exploration and 30 Events occurring after balance date 55 development costs over the life of the 19-year sales contract with the Porgera Joint Venture for supply of gas to 31 Financial instruments 55 the Porgera Gold Mine.
Directors’ declaration 57 Independent Auditors’ report 58 OIL SEARCH ANNUAL REPOR Corporate governance 59 43 Directors’ report 62 NOTES TO AND FORMING PART OF THE ACCOUNTS
(f) Inventories Inventories are valued at the lower of cost or net realisable value. Cost is determined as follows: (i) materials, which include drilling and maintenance stocks, are valued at cost; and (ii) petroleum products, comprising extracted crude oil and condensate stored in tanks and pipeline systems, are valued using the full absorption cost method. Inventories and material stocks are accounted for on a FIFO basis. (g) Income recognition The economic entity’s revenue, which is mainly derived from the proceeds from sale of oil and the investment of its surplus funds in Papua New Guinea and other countries, is recorded in Note 2. Revenue from the sale of crude oil is brought to account after each shipment of oil is loaded. Gas and diesel sales are recognised on production. (h) Interest on borrowings Interest and other finance charges on borrowings for major capital projects is capitalised until the commencement of production and then amortised over the estimated economic life of the project. (i) Joint venture assets and liabilities Exploration, development and production activities of the economic entity are carried on through joint ventures with other parties and the economic entity’s interest in each joint venture is brought to account by including in the respective classifications, where material, the share of individual assets and liabilities. (j) Rounding All amounts included in the accounts are rounded to the nearest thousand US$ under the option available to the economic entity under ASIC Class Order 98/100. (k) Hedging contracts Where hedging contracts are entered into to limit the financial exposure of the economic entity in relation to oil price, interest rate and foreign exchange movements, the gains and losses realised on such contracts are deferred and recognised as revenue or expense in the period in which the related financial exposure is realised. (l) Leases Operating lease payments, where the lessor effectively retains substantially all of the risks and benefits of ownership of the leased items, are included in the determination of the operating profit in equal instalments over the lease term. (m) Cash For the purposes of the statement of cash flows, cash includes cash at bank and on hand and interest bearing investments readily convertible into cash within two working days, net of bank overdraft. (n) Employee entitlements Provision is made for long service leave and annual leave estimated to be payable to employees on the basis of statutory and contractual requirements. Vested entitlements are classified as current liabilities. The contributions made to superannuation funds by entities within the economic entity are charged against profits when due. In Australia, contributions of up to 7% of employees’ salaries and wages are legally required to be made. The value of the employee share options in Note 26 are not being charged as an employee entitlement expense. (o) Recoverable amount Non current assets are not revalued to an amount above their recoverable amount, and where carrying values exceed this recoverable amount assets are written down. In determining recoverable amounts the expected net cash flows have not been discounted to their present value. (p) Comparatives
T 1998 As outlined in Note 1(b), the economic entity changed its functional and reporting currency from kina to US$ on 1 January 1998. As a result, the comparative figures presented are based on a convenience translation of the audited kina accounts from 31 December 1997 at the rate of 0.5635 kina to the US$. The result is that the opening US$ balances as at 1 January 1998 do not equate to the closing US$ balances reported as at 31 December 1997. OIL SEARCH ANNUAL REPOR
44 FOR THE YEAR ENDED 31 DECEMBER 1998
(q) Income Tax The liability method of tax effect accounting is applied. Under this method, income tax expense is based on operating profit adjusted for any permanently non-allowable and non-assessable items. Timing differences, which arise due to the different accounting periods in which items of revenue and expense are recognised in the accounts and when items are taken into account in determining taxable income, are brought to account at prevailing tax rates, as either a provision for deferred income tax or as a future income tax benefit. The net future income tax benefit relating to tax losses and timing differences is not brought to account unless the benefit is virtually certain of being realised. In bringing to account such benefits, it is assumed that no adverse or beneficial change will occur in income tax legislation, that the company will derive sufficient future assessable income to enable the benefits to be realised and that the company will continue to comply with the conditions of deductibility imposed by law. (r) Investments Investments are carried at the lower of cost and recoverable value.
CONSOLIDATED CHIEF ENTITY 31/12/98 31/12/97 31/12/98 31/12/97 US$’000 US$’000 US$’000 US$’000
2. OPERATING PROFIT BEFORE INCOME TAX IS: (a) after charging: Amortisation of exploration & development costs 41,221 9,211 440 210 Operating expenses of producing licences 21,974 4,751 238 256 Royalties 1,629 665 7 16 Cost of sales 64,824 14,627 685 482 Borrowing costs paid to controlled entities – – 219 224 Borrowing costs paid to other entities 10,563 1 – 2 Depreciation of fixed assets 357 215 49 59 Hedging costs – 748 – – Loss on disposal of fixed assets – 44 – – Management charge to controlled entity – – 3,871 2,485 Provisions: – long service leave 29 32 23 22 – employment entitlements 78 47 48 26 – site restoration 922 714 8 7 Rental – operating leases 876 535 276 307 (b) and after crediting revenue from the following sources: Sales revenue Oil sales 83,021 35,885 – – Gas and diesel sales 7,767 473 558 473 Other revenue Interest from – controlled entities – – 1,807 2,836 – other corporations 2,673 3,030 2,208 2,309 Management charges – controlled entities – – 5,098 2,097 Dividends from T 1998 – controlled entities – – 25,000 10,558 Other (63) 26 (63) 26 Operating revenue 93,398 39,414 34,608 18,299 OIL SEARCH ANNUAL REPOR
45 NOTES TO AND FORMING PART OF THE ACCOUNTS
CONSOLIDATED CHIEF ENTITY 31/12/98 31/12/97 31/12/98 31/12/97 US$’000 US$’000 US$’000 US$’000
3. ABNORMAL ITEMS Item credited: Foreign exchange gain (loss) 1,218 2,412 (7,966) 8,130 Income tax expense applicable thereto – – – – 1,218 2,412 (7,966) 8,130 Item charged: Write off of accumulated exploration expenses (5,291) – (5,291) – Income tax expense applicable thereto – – – – (5,291) – (5,291) – 4. INCOME TAX
The prima facie tax, using tax rates applicable in the country of operation, on operating profit differs from the income tax provided in the accounts as follows: Prima facie tax expense (credit) on operating profit 6,891 10,661 (1,338) 5,215 Tax effect of permanent differences: Exempt income (13,124) (5,490) – (4,704) Expenses not allowable 1,215 3,894 – 6 Prior period adjustment 24 (2,858) – 524 Tax credits available – (199) – – Tax losses not brought to account 2,426 30 1,392 – Other – 79 – – Income tax (credit) expense (2,568) 6,117 54 1,041
The 1998 prima facie income tax expense has been calculated by applying the taxation rates applicable to each company’s results as follows:
Tax rate applicable Tax regime Auton Investments Pte Limited 33% Singapore Iona Limited 25% Papua New Guinea Oil Search (Australia) Pty Limited 36% Australia Oil Search (Gobe) Limited 50% Papua New Guinea Oil Search (Kutubu) Limited 50% Papua New Guinea Oil Search Limited 25% Papua New Guinea Oil Search (Moran) Limited 25% Papua New Guinea Oil Search (Tumbudu) Limited 30% Papua New Guinea Oriomo Oil Search Limited 25% Papua New Guinea Papuan Oil Search Limited 36% Australia T 1998 OIL SEARCH ANNUAL REPOR
46 FOR THE YEAR ENDED 31 DECEMBER 1998
5. CONSOLIDATED ENTITIES
Place of At cost % owned by At cost % owned by incorporation 31/12/98 Chief Entity 31/12/97 Chief Entity US$’000 US$’000 Auton Investments Pte Limited Singapore 5,990 100 4,195 100 Oil Search (Gobe) Limited PNG – 100 – 100 Oil Search (Kutubu) Limited PNG 10 100 6 100 Oil Search (Moran) Limited PNG – 100 * * Oil Search (Tumbudu) Limited PNG – 100 * * Oriomo Oil Search Limited PNG – 100 – 100 and its controlled entity Iona Limited PNG 10,363 100 5,839 100 Papuan Oil Search Limited # NSW – 100 – 100 and its controlled entity Oil Search (Australia) Pty Limited NSW – 100 – 100
# At Directors’ valuation 1984 * Incorporated in 1998 The cost of the economic entity’s investments in the following controlled entities have been rounded to nil in the above Note, in accordance with Note 1(j) “Rounding”.
31/12/98 31/12/97 US$ US$ Oil Search (Australia) Pty Limited 61 65 Oil Search (Gobe) Limited 2 1 Oil Search (Moran) Limited 1 – Oil Search (Tumbudu) Limited 1 – Oriomo Oil Search Limited 2 1 Papuan Oil Search Limited 270 146
CONSOLIDATED CHIEF ENTITY 31/12/98 31/12/97 31/12/98 31/12/97 US$’000 US$’000 US$’000 US$’000
6. DIVIDENDS PAID OR PROVIDED FOR Ordinary dividends proposed – final unfranked – 2,641 – 2,641 Preference dividends proposed and paid – unfranked 3,585 – 3,585 – 3,585 2,641 3,585 2,641 Dividends paid during the year: Ordinary – previous year final unfranked 2,641 2,637 2,641 2,637 Preference – current year unfranked 3,585 – 3,585 – 6,226 2,637 6,226 2,637
As Oil Search Limited is a Papua New Guinea incorporated company, there are no franking credits available on dividends.
7. RECEIVABLES (CURRENT)
Trade debtors 7,662 2,018 54 79 T 1998 Other debtors 8,616 4,857 2,744 2,711 Amounts due by: – controlled entities – – 262,244 45,629 16,278 6,875 265,042 48,419 OIL SEARCH ANNUAL REPOR
47 NOTES TO AND FORMING PART OF THE ACCOUNTS
CONSOLIDATED CHIEF ENTITY 31/12/98 31/12/97 31/12/98 31/12/97 US$’000 US$’000 US$’000 US$’000
8. INVENTORIES Materials and supplies 13,016 5,125 275 285 Petroleum products 1,849 545 – – 14,865 5,670 275 285
9. RECEIVABLES (NON CURRENT)
Amounts due by: – controlled entities – – 191,371 13,013 – other entities 493 342 – – 493 342 191,371 13,013
10. INVESTMENTS (NON CURRENT)
Shares in controlled entities – – 6,000 4,200
11. PLANT & EQUIPMENT
Motor vehicles, office furniture, fittings and equipment at cost 2,590 1,883 985 486 Less: accumulated depreciation (1,008) (585) (435) (253) 1,582 1,298 550 233
12. EXPLORATION AND DEVELOPMENT COSTS
Accumulated exploration costs – at cost Areas in exploration or evaluation phase 280,606 109,192 84,892 62,027 Areas in which production has commenced 152,935 21,594 5,750 1,981 Less: accumulated amortisation (37,325) (14,194) (1,422) (623) Less: written off to profit and loss (5,291) – (5,291) – Net accumulated exploration costs 390,925 116,592 83,929 63,385 Accumulated development costs – at cost Areas in construction phase – 44,659 – – Areas in which production has commenced 399,574 57,639 2,390 1,258 Less: accumulated amortisation (106,361) (43,617) (907) (401) Net accumulated development costs 293,213 58,681 1,483 857 684,138 175,273 85,412 64,242 Borrowing costs incurred during the year and included in the above 10,381 4,821 – –
The ultimate recoupment of costs carried forward for areas in exploration or evaluation phases is dependent on the successful development and commercial exploitation of the area or commercial sale of the respective petroleum prospecting areas. Amortisation of the costs carried forward for the development phase is not charged until the commencement of commercial production.
CONSOLIDATED CHIEF ENTITY 31/12/98 31/12/97 31/12/98 31/12/97 US$’000 US$’000 US$’000 US$’000
13. OTHER ASSETS (NON CURRENT) T 1998 Future income tax benefit – timing differences 5,171 2,386 145 152
14. ACCOUNTS PAYABLE
Trade creditors & accruals 64,947 11,341 6,212 2,341 Other creditors – 8 – 8 64,947 11,349 6,212 2,349
Of the above amount, US$50 million relates to a deferred cash settlement due to BP in August 1999 in settlement of the OIL SEARCH ANNUAL REPOR acquisition for their upstream PNG oil and gas assets in 1998. 48 FOR THE YEAR ENDED 31 DECEMBER 1998
CONSOLIDATED CHIEF ENTITY 31/12/98 31/12/97 31/12/98 31/12/97 US$’000 US$’000 US$’000 US$’000
15. BORROWINGS (CURRENT) Secured by mortgage – bank loans (refer Note 22(e)) 72,100 7,420 62,800 –
16. PROVISIONS (CURRENT)
Dividends – 2,641 – 2,641 Taxation 455 2,854 – – Employee entitlements 309 233 206 163 Directors’ retirement allowances 392 399 392 398 1,156 6,127 598 3,202
17. ACCOUNTS PAYABLE (NON CURRENT)
Owing to controlled entities – – 4,187 3,932
18. BORROWINGS (NON CURRENT)
Secured by mortgage – bank loans (refer Note 22(e)) 281,500 42,680 221,700 –
19. PROVISIONS (NON CURRENT)
Deferred income tax – timing differences 7,512 1,836 5,078 953 Site restoration 9,807 2,246 56 48 17,319 4,082 5,134 1,001
20. SHARE CAPITAL
Authorised 1,000,000,000 ordinary shares Issued 468,859,557 (1997: 468,744,807) ordinary shares, fully paid (no par value) 190,491 114,656 190,491 114,656 Issued 1,189,000 (1997: nil) converting preference shares, fully paid 69,641 – 69,641 – 260,132 114,656 260,132 114,656
Shares issued during the year During the year 114,750 ordinary shares were issued to employees exercising their share options in accordance with the terms of the Oil Search Limited Employee Share Option Scheme. The shares were issued at K1.716, raising US$92,000. The shares rank equally for dividends from the date of issue. During the year 1,189,000 9.5% converting preference shares of A$100 each were issued. The shares are convertible into ordinary shares, at the company’s discretion, at a 10% discount to the share price at the time of conversion. The shares expire in May 2000. Underwriting fees of US$3.0 million were offset against the proceeds received from the issue of the shares in arriving at the amount disclosed as share capital on the balance sheet. Due to changes in the PNG Companies Act the share premium reserve of US$140.7 million has been aggregated with the value of ordinary shares.
CONSOLIDATED CHIEF ENTITY 31/12/98 31/12/97 31/12/98 31/12/97 US$’000 US$’000 US$’000 US$’000
21. INTERESTS IN JOINT VENTURES (a) Net assets employed in joint ventures Current assets: – Cash 8,437 2,688 3,674 1,330 – Receivables 1,103 2,269 86 1,531 T 1998 – Inventories 13,016 5,126 275 285 Non current assets: – Exploration 390,925 116,592 83,929 63,385 – Development 293,213 58,680 1,483 857 Less: current liabilities (7,541) (9,524) (712) (2,050) 699,153 175,831 88,735 65,338 OIL SEARCH ANNUAL REPOR
49 NOTES TO AND FORMING PART OF THE ACCOUNTS
(b) Interests in joint ventures The principal activities of the following joint ventures in Papua New Guinea in which the economic entity holds an interest are the exploration for and the production of crude oil and natural gas:
% Interest % Interest (i) Production joint ventures 1998 1997 PDL 1 Hides gas field 52.50 5.00 PL 1 Hides gas pipeline 52.50 5.00 PDL 2 Kutubu oil field 27.14 7.76 PL 2 Kutubu oil pipeline 27.14 7.76 PDL 3 Gobe oil field 15.50 15.50 PL 3 Gobe oil pipeline 21.32 21.32 PDL 4 Gobe oil field 27.14 27.14 (ii) Exploration joint ventures PPL 82 – 5.00 PPL 101 – 6.01 PPL 138 52.50 7.50 PPL 152 40.00 40.00 PPL 161 35.02 35.02 PPL 179 50.00 50.00 PPL 184 10.00 10.00 PPL 188 54.55 30.00 PPL 189 40.40 40.40 PPL 190 30.10 30.10 PPL 193 30.00 35.00 PPL 199 70.00 100.00 PPL 200 50.00 50.00 PPL 203 85.00 85.00 APPL 208 25.00 – APPL 218 50.00 – PRL 1 5.00 – APRL 2 6.01 –
The various production joint ventures in which the economic entity is a participant contributed the following to the profit after tax of the economic entity:
PDL 1 US$0.8 million (1997: US$0.1 million loss) PDL 2 US$14.7 million (1997: US$27.6 million) PDL 3 US$1.2 million loss (1997: nil)
CONSOLIDATED CHIEF ENTITY 31/12/98 31/12/97 31/12/98 31/12/97 US$’000 US$’000 US$’000 US$’000
22. CONTINGENT LIABILITIES AND COMMITMENTS:
(a) Operating leases not capitalised in the accounts Rental of premises and motor vehicles – Payable within 12 months 635 885 67 216 – Payable 1 to 2 years 994 700 – 95 – Payable 2 to 5 years 875 515 – 60 (b) Exploration expenditure The economic entity, together with joint venture partners, has undertaken exploration programmes. The Directors estimate T 1998 the economic entity’s contribution to these joint ventures, based on firm commitments and existing joint venture interests as at 31 December 1998, will be approximately US$16.3 million during the year ending 31 December 1999. These obligations may be varied from time to time, subject to approval, and are expected to be fulfilled in the normal course of operations of the economic entity. (c) Capital expenditure The economic entity, through its participation in various joint ventures, has capital expenditure commitments during 1999 in relation to the Kutubu, Gobe and Moran Projects. At balance date, the Directors estimate that the economic entity has firm
OIL SEARCH ANNUAL REPOR commitments of US$2.8 million in respect of the Kutubu Project, US$5.3 million in respect of the Gobe Project and US$11.6 million in respect of the Moran Project. 50 FOR THE YEAR ENDED 31 DECEMBER 1998
(d) Provision for Directors’ retirement benefit In accordance with the terms of Article 110(a) of the Articles of Association of the chief entity then applicable, a Provision for Retirement Benefit for all Directors of the chief entity was approved by a resolution of the Board of Directors of the chief entity on 27 July 1990. (e) Guarantees re debts of controlled entities 1. As part of the terms and conditions of a Loan Agreement between Oil Search (Gobe) Limited (“OSG”), Oil Search Limited (“OSL”) and the UBS Lending Syndicate (“UBS”) for the provision of a US$81.0 million facility to fund OSG’s share of the capital expenditure for the Gobe Oil Project development, the following security was provided: (i) OSL provided to UBS a payment guarantee over the outstanding portion of the loan, and a performance guarantee over OSG’s obligations under the Loan Agreement. These guarantees will remain in place until Financial Completion, which is anticipated to be in 1999; (ii) OSL provided to UBS a mortgage over its 100% shareholding in OSG and a mortgage to UBS over funds held in escrowed bank accounts containing US$2.1 million at year end as security for outstanding advances and future political risk insurance premiums by OSG. The share mortgage and the mortgage over the escrow account will remain in force until all monies for which OSG was liable under the Loan Agreement with UBS are repaid; and (iii) OSG provided to UBS a charge over its interests in the Gobe and S.E. Gobe licences, being PDL3, PDL4 and PL3. This charge is subject to the other joint venture participants’ rights of priority. 2. As part of the terms and conditions of a Loan Agreement between OSL as borrower, and OSG, Oil Search (Tumbudu) Limited (“OST”), Oil Search (Moran) Limited (“OSM”) and Oil Search (Kutubu) Limited (“OSK”) as guarantors, UBS for the provision of a US$292.5 million bridging facility to partly fund the acquisition of BP’s upstream assets in PNG, the following security was provided: (i) OSM, OSK, OSG and OST jointly and severally provided a payment guarantee over the loan; (ii) OSK provided a charge over its credit account in Hong Kong with the HongKong and Shanghai Banking Corporation Limited; and (iii) OSG provided a charge over its credit account in Hong Kong with the HongKong and Shanghai Banking Corporation Limited. 3. The chief entity has guaranteed the ongoing performance of OSK in relation to certain oil swap transactions.
CONSOLIDATED CHIEF ENTITY 31/12/98 31/12/97 31/12/98 31/12/97 US$’000 US$’000 US$’000 US$’000
23. STATEMENT OF CASH FLOWS (a) Reconciliation of operating profit to net cash flows from operating activities Operating profit after tax 9,336 14,170 14,596 19,819 Add/(less): Exploration write off 5,291 – 5,291 – Amortisation 42,209 9,211 440 210 Depreciation charges 357 215 49 59 Interest charged by controlled entities – – 219 224 Exchange losses (gains) (1,219) (2,413) 7,967 (8,130) Movement in tax provisions (5,081) (2,876) 54 1,041 Interest received from controlled entities – – (1,807) (2,845) Loss on disposal of bonds and fixed assets 12 44 – – Net increase (decrease) in provisions 70 (72) 37 (103) Management fee charged – – 3,871 2,485 Management fee credited – – (5,098) (2,097) Provision for site restoration 922 713 8 7
Increase in creditors 4,292 (444) 34 (2) T 1998 (Increase) decrease in debtors (11,387) 985 (1,454) (579) 35,466 5,363 9,611 (9,730) Net cash flows from operating activities 44,802 19,533 24,207 10,089 (b) For the purposes of the above cash flow statement, cash includes cash on hand and at bank, deposits at call, and bank overdraft Cash at bank and on hand 13,626 8,543 6,401 5,256
Interest bearing investments 9,679 41,257 9,679 41,257 OIL SEARCH ANNUAL REPOR 23,305 49,800 16,080 46,513 51 NOTES TO AND FORMING PART OF THE ACCOUNTS
(c) Financing facility A financing facility of US$81.0 million was available to the economic entity in respect of the Gobe Project at the end of the year. As at year end, US$69.1 million had been drawn down (Refer Note 22(e) for the terms and conditions of this financing facility). A financing facility of US$292.5 million was available to the economic entity in respect of the acquisition of BP’s upstream PNG assets at the end of the year. As at year end, US$284.5 million had been drawn down (refer Note 22(e) for the terms and conditions of this financing facility). (d) Acquisitions/disposals During the year the economic entity acquired the upstream PNG oil and gas assets of British Petroleum in PDL 1, PDL 2 and PPL 138 for US$400 million. This included a deferred settlement of US$50 million, which is due in August 1999 to BP and which is included in Note 14 to the accounts.
CONSOLIDATED CHIEF ENTITY 31/12/98 31/12/97 31/12/98 31/12/97 US$’000 US$’000 US$’000 US$’000
24. DIRECTORS’ AND EXECUTIVES’ REMUNERATION
(a) Directors’ remuneration Remuneration paid or payable, or otherwise made available, in respect of the financial year, to all Directors of the economic entity, directly or indirectly, by the entities of which they are Directors or any related party: – Directors’ fees 138 130 – Fees for other services 36 32 – Directors’ retirement allowances 59 64 – Fixed salary of full time employees 633 546 866 772 Remuneration paid or payable, or otherwise made available, in respect of the financial year, to all Directors of Oil Search Limited, directly or indirectly, by the entity or any related party: – Directors’ fees 134 124 – Fees for other services 36 32 – Directors’ retirement allowances 59 64 – Fixed salary of full time employees 471 418 700 638
The number of Directors of Oil Search Limited whose income per annum (including Directors’ retirement allowances) falls within the following bands:
31/12/98 31/12/97 No. No.
US$10,000–US$19,999 – 2 US$20,000–US$29,999 1 1 US$30,000–US$39,999 1 1 US$40,000–US$49,999 2 1
T 1998 US$70,000–US$79,999 1 1 US$410,000–US$419,999 – 1 US$470,000–US$479,999 1 – In the opinion of Directors, remuneration paid to Directors is considered reasonable. OIL SEARCH ANNUAL REPOR
52 FOR THE YEAR ENDED 31 DECEMBER 1998
CONSOLIDATED CHIEF ENTITY 31/12/98 31/12/97 31/12/98 31/12/97 US$’000 US$’000 US$’000 US$’000
(b) Executives’ remuneration Amounts received or due and receivable by executive officers of the economic entity whose remuneration is US$50,000 (K100,000) per annum or more, from entities in the economic entity and related entities 1,209 868 Amounts received or due and receivable by executive officers of the chief entity whose remuneration is US$50,000 (K100,000) per annum or more, from entities in the economic entity and related entities 491 367
The number of executive officers whose remuneration per annum falls within the following bands:
CONSOLIDATED CHIEF ENTITY 31/12/98 31/12/97 31/12/98 31/12/97 No. No. No. No. US$60,000–US$69,999 – 1 – – US$110,000–US$119,999 1 1 – – US$120,000–US$129,999 – 1 – – US$130,000–US$139,999 – 1 – – US$140,000–US$149,999 1 – – – US$150,000–US$159,999 1 – – – US$160,000–US$169,999 2 – – – US$410,000–US$419,999 – 1 – 1 US$470,000–US$479,999 1 – 1 –
CONSOLIDATED CHIEF ENTITY 31/12/98 31/12/97 31/12/98 31/12/97 US$’000 US$’000 US$’000 US$’000
25. AUDITORS’ REMUNERATION Amounts receivable or due and receivable in respect of: auditing the company’s accounts 87 47 24 19 other services – – – – 87 47 24 19 26. EMPLOYEE ENTITLEMENTS AND SUPERANNUATION COMMITMENTS
Employee entitlements The aggregate employee entitlement liability comprises: accrued wages, salaries and on costs 125 148 310 95 provisions (current) 473 87 473 68 598 235 783 163 T 1998 Employee Share Option Scheme An employee share scheme was established in 1995 where employees of the economic entity are issued with options over ordinary shares of Oil Search Limited. The options, issued for nil consideration, are issued in accordance with guidelines established by the Directors of Oil Search Limited. The options cannot be transferred and will not be quoted on the Australian Stock Exchange. There are currently 46 employees participating in the scheme. OIL SEARCH ANNUAL REPOR
53 NOTES TO AND FORMING PART OF THE ACCOUNTS
Details of outstanding options are as follows:
Issue date Exercise date Exercise price Number outstanding
1 May 1996 1 May 1997 A$1.266 167,500 1 May 1996 1 May 1998 A$1.266 362,750 1 May 1996 1 May 1999 A$1.266 391,250 27 March 1997 27 March 1999 A$2.586 238,750 27 March 1997 27 March 2000 A$2.586 238,750 27 March 1997 27 March 2001 A$2.586 477,500 30 May 1997 23 May 1999 A$2.870 334,000 30 May 1997 23 May 2001 A$2.870 333,000 30 May 1997 23 May 2002 A$2.870 333,000 24 March 1998 24 March 2000 A$2.544 375,000 24 March 1998 24 March 2001 A$2.544 750,000 24 March 1998 24 March 2002 A$2.544 375,000 Total options outstanding at year end 4,376,500 Superannuation commitments Employees are entitled to varying levels of benefits on retirement, disability or death. Employees contribute to the superannuation plan at various percentages of their salaries, and the economic entity also contributes at various rates. Contributions by the economic entity in Australia of 7% of employees salaries are legally enforceable.
27. RELATED PARTY TRANSACTIONS
(a) The Directors of Oil Search Limited during the year to 31 December 1998, and their interests in the shares of Oil Search Limited as at 31 December 1998, were:
No. of ordinary shares No. of options 31/12/98 31/12/97 31/12/98 31/12/97
T J Kennedy A.M. 239,352 229,352 – – N N Beangke – – – – P R Botten – – 1,200,000 1,200,000 J L Stitt 9,600 N/A M Taylor 3,000 3,000 – – J O Zehnder 2,000 2,000 – – Mr P R Botten holds 200,000 options to purchase Oil Search Limited ordinary shares at A$1.266 per share and 1,000,000 options to purchase Oil Search Limited ordinary shares at A$2.87 per share. (b) No related party transactions occurred during the year to 31 December 1998. All transactions between entities within the economic entity, as disclosed in Note 2 to the financial statements, were made under normal commercial terms and conditions.
28. EARNINGS PER SHARE
CONSOLIDATED 31/12/98 31/12/97 US cents US cents
Basic earnings per share 1.23 3.03 Weighted average number of ordinary shares
T 1998 issued during the year used in the calculation of basic earnings per share 468,792,301 468,282,403
Diluted earnings per share have not been disclosed as they are not materially different from basic earnings per share.
29. SEGMENT REPORTING
The economic entity operates within the oil and gas industry in Papua New Guinea. OIL SEARCH ANNUAL REPOR
54 FOR THE YEAR ENDED 31 DECEMBER 1998
30. EVENTS OCCURRING AFTER BALANCE DATE
Subsequent to balance date the economic entity refinanced US$245 million of the US$292.5 million bridge facility that was in place at year end (refer to Note 22(e) for the terms and conditions of this financing facility). The refinancing was completed by way of a five-year syndicated bank loan and disclosures have been made as if this loan was in place as at 31 December 1998. The balance of the bridging facility will be repaid from proceeds of the sale of the 31% of the economic entity’s interest in PDL 1, which was also completed subsequent to balance date, for US$55 million. The sale was completed on 15 March 1999 and the interest was transferred to the purchaser on that date.
31. FINANCIAL INSTRUMENTS
(a) Terms, conditions and accounting policies The economic entity’s accounting policies, including the terms and conditions of each class of financial asset, financial liability and equity instrument, both recognised and unrecognised at balance date, are as follows:
Recognised financial Balance sheet Accounting policies Terms and conditions instruments notes
(i) Financial assets Receivables – trade 7 Trade receivables are carried at nominal Credit sales are on 30-day terms. amounts due less any provision for doubtful debts. A provision for doubtful debts is recognised when collection of the full nominal amount is no longer probable. Receivables – 7,9 Amounts (other than trade Receivables from related parties/entities related parties/entities debts) receivable from related are payable at call. parties/entities are carried at nominal amounts due. Short term deposits Short term deposits are stated Short term deposits have an average at the lower of cost and net realisable maturity of 14 days and effective interest value. Interest is recognised in the rates of 4.9% to 9.25%. profit and loss account when earned. Unlisted shares 10 Unlisted shares are carried at the lower of cost or recoverable amount. Dividend income is recognised when the dividends are declared by the investee. (ii) Financial liabilities Secured loans 15,18 Secured loans are carried at the The secured loans are repayable in principal amount. Interest on quarterly instalments from proceeds borrowings for major projects is earned from the Kutubu, Gobe and capitalised until the commencement Moran Oil Projects, and the Hides Gas of production and then amortised Project. Interest is charged at LIBOR plus over the estimated life of the project. a margin. Details of the security over the secured loans is set out in Note 22(e). Trade creditors and accruals 14 Liabilities are recognised for amounts Trade liabilities are normally settled on
to be paid in the future for goods and 30-day terms. T 1998 services received, whether or not billed to the economic entity. OIL SEARCH ANNUAL REPOR
55 NOTES TO AND FORMING PART OF THE ACCOUNTS
31. FINANCIAL INSTRUMENTS (CONTINUED)
Recognised financial Balance sheet Accounting policies Terms and conditions instruments notes Accounts payable – 14,17 Loans from related parties are carried related party/entity at the principal amount. Interest is taken up as an expense on an accrual basis. Dividends payable 16 Dividends payable are recognised when No ordinary dividend was declared for declared by the company. the year ended 31 December 1998. Dividends payable represent a final dividend of 1 toea per share for the year ended 31 December 1997. The dividends are not franked.
Taxation payable 16 The liability for taxation payable The income tax liability is calculated is accounted for in accordance using a tax rate of between 25% and with AASB 1020. 50%. Interest is charged at the rate of 20% on amounts overdue. (iii) Equity Ordinary shares 20 Ordinary share capital is The company is authorised to issue recognised at the US$ up to 1,000,000,000 ordinary shares. equivalent of K100,000,000. Details of shares issued and the terms and conditions of options outstanding over ordinary shares are disclosed in Note 20 and 26.
Converting preference shares 20 Converting preference shares The converting preference shares are recognised at the historical carry a dividend rate of 9.5% per US$ equivalent of A$118,900,000. annum. (iv) Unrecognised financial instruments Hedges From time to time the economic entity There are no outstanding forward enters into forward sales contracts where sales contracts at balance date. it agrees to sell specified amounts of oil in the future at predetermined prices. The objective is to match the contract with anticipated future cash flows from oil sales to protect the economic entity against the possibility of loss from future oil price fluctuations. The forward contracts are usually for no more than three months. It is the company’s policy not to recognise forward sales contracts in its financial statements. (b) Interest rate risk The economic entity’s exposure to interest rate risks and the effective interest rates of financial assets and financial liabilities, both recognised and unrecognised at balance date, are as follows:
Financial Instruments Floating Fixed interest rate maturing in: Non Total Weighted interest interest carrying average rate 1 year 1-5 years More than bearing amount as effective or less 5 years per the interest balance sheet rate 31/12/98 US$’000 US$’000 US$’000 US$’000 US$’000 US$’000 % Financial assets Cash 23,305 – – – – 23,305 6.0 %
T 1998 Total financial assets 23,305 – – – – 23,305 Financial liabilities Secured loans 353,600 – – – – 353,600 7.1% Total financial liabilities 353,600 – – – – 353,600
31/12/97 Financial assets Cash 49,800 – – – – 49,800 6.0 % Total financial assets 49,800 – – – – 49,800
OIL SEARCH ANNUAL REPOR Financial liabilities Secured loans 50,100 – – – – 50,100 7.1% 56 Total financial liabilities 50,100 – – – – 50,100 FOR THE YEAR ENDED 31 DECEMBER 1998
(c) Net fair values The aggregate net fair values of financial assets and financial liabilities, both recognised and unrecognised at balance date, are as follows:
Aggregate net fair value 31/12/98 31/12/97 US$’000 US$’000
Financial assets Cash 23,305 49,800 Receivables – trade 7,662 2,018 Other debtors 8,616 4,857 Due from other entities 493 342 Total financial assets 40,076 57,017 Financial liabilities Trade creditors and accruals 64,947 11,341 Other creditors – 8 Taxation payable 455 2,854 Secured loans 353,600 50,100 Total financial liabilities 419,002 64,303 Recognised financial instruments The carrying value of all recognised financial assets and liabilities approximates fair value. Unrecognised financial instruments Hedge contracts The fair value of hedge contracts is determined as the present value of future cash flow based on current oil price. (d) Credit risk exposures The economic entity’s maximum exposure to credit risk at balance date in relation to each class of recognised financial asset is the carrying amount of those assets as indicated in the balance sheet. In relation to unrecognised financial assets (hedge contracts), credit risk arises from the potential failure of counterparties to meet their obligations under the contract. The economic entity’s maximum credit risk exposure in relation to these is the full amount of the hedge contract the counterparty will be required to pay when settling the hedge contract, should the counterparty not pay the money it is committed to deliver to the company. At balance date this amount was nil. Concentrations of credit risk The economic entity minimises concentrations of credit risk in relation to trade accounts receivable by undertaking transactions only with major oil companies within the oil industry. Payment terms are maintained at 30 days, in accordance with standard oil industry practice. DIRECTORS’ DECLARATION
In accordance with a resolution of the Directors of Oil Search Limited, we state that: In the opinion of the Directors: (a) the financial statements and notes: (i) give a true and fair view of the financial position as at 31 December 1998 and the performance for the year ended on that date; and (ii) comply with Accounting Standards as set out in Note 1(a); and (b) there are reasonable grounds to believe that the chief entity will be able to pay its debts as and when they become due or payable. T 1998
On behalf of the Board.
T J KENNEDY, A.M. N N BEANGKE
Chairman of Directors Deputy Chairman OIL SEARCH ANNUAL REPOR
Port Moresby, 2nd March 1999 57 INDEPENDENT AUDITORS’ REPORT TO THE MEMBERS OF OIL SEARCH LIMITED
SCOPE
We have audited the financial statements of Oil Search Limited for the financial year ended 31 December 1998 as set out on pages 37 to 57 and the Directors' Declaration. The financial statements include the accounts of Oil Search Limited and the consolidated accounts of the economic entity comprising Oil Search Limited and the entities it controlled at year's end or from time to time during the financial year. The company's Directors are responsible for the preparation and presentation of the financial statements and the information contained therein. We have conducted an independent audit of these financial statements in order to express an opinion on them to the members of the company. Our audit has been conducted in accordance with Australian Auditing Standards and International Standards on auditing to provide reasonable assurance as to whether the financial statements are free of material misstatement. Our procedures included examination, on a test basis, of evidence supporting the amounts and other disclosures in the financial statements, and the evaluation of accounting policies and significant accounting estimates. These procedures have been undertaken to form an opinion as to whether, in all material respects, the financial statements are presented fairly in accordance with Australian Accounting Standards, the disclosure requirements of the Australian Corporations Law and other mandatory professional reporting requirements, so as to present a view which is consistent with our understanding of the company's and the economic entity's financial position, the results of their operations and their cash flows. The audit opinion expressed in this report has been formed on the above basis.
AUDIT OPINION
In our opinion the financial statements of Oil Search Limited are properly drawn up: (a) so as to give a true and fair view of the state of affairs as at 31 December 1998 and the profit and cash flows for the financial year ended on that date of the company and the economic entity: and (b) in accordance with applicable Australian Accounting Standards, the disclosure requirements of the Australian Corporations Law and other mandatory professional reporting requirements.
ERNST & YOUNG
Sydney Dated: 2nd day of March 1999 T 1998 OIL SEARCH ANNUAL REPOR
58 CORPORATE GOVERNANCE OIL SEARCH LIMITED
Oil Search is committed to the highest standards of corporate governance and the Board of Directors ensures that the best interests of shareholders is the basis for all their decision making.
The main corporate governance practices in place during the year are summarised below. While those practices simply focus on particular areas, the overall goal of Oil Search is best practice in all areas and Oil Search is consistently striving to improve performance in all areas. Each of the corporate governance matters set out in Appendix 4A of the Australian Stock Exchange Listing Rules has been considered by the Board and a Corporate Governance Committee is in place to specifically consider such matters where they are not considered by pre-existing committees.
The Board consists of six members comprising five non-executive Directors and the Managing Director, Peter Botten. The Chairman, Trevor Kennedy, is a non-executive Director. When appointing new directors, Oil Search looks for individuals who are leaders in their field and who have a commitment to excellence. While a number of Board members have spent their working lives in the oil and gas industry, Oil Search also looks for directors who have exceptional qualifications or experience in other relevant areas with a view to ensuring that the Board consists of the best available talent in as many relevant areas as possible. The last Director appointed to the Board, John Stitt, was appointed in April 1998 bringing with him over 30 years of financial experience in the oil and gas industry.
The Board has established five committees to consider and make recommendations to the Board. The committees comprise an Audit Committee, a Remuneration Committee, a Corporate Governance Committee, a Technical Committee and a Hedging Committee. The members of the respective committees comprise those directors who have experience most relevant to the particular committee’s area of responsibility.
The Chairman meets regularly with the Managing Director and the individual members of the Board to review the company’s performance. Board members are able to seek independent professional advice at Oil Search’s expense where such advice is necessary to help them satisfactorily fulfil their duties as directors. There are no restrictions imposed on the directors in seeking independent professional advice.
At each Annual General Meeting certain Directors (as prescribed by Oil Search’s Constitution and excluding the Managing Director), automatically retire and are eligible for reappointment. If not reappointed, that retirement takes effect at the conclusion of the annual meeting.
REMUNERATION COMMITTEE
A Remuneration Committee comprising Messrs Kennedy, Zehnder and Botten meets at least once a year to make recommendations to the Board on remuneration levels for the Managing Director and other employees. This Committee considers the appropriate remuneration levels for the Board members themselves and makes recommendations thereon to the Board and, if necessary, the shareholders. The Remuneration Committee also makes recommendations to the
Board under the regulations of the Employee Share Option Scheme as required. T 1998 OIL SEARCH ANNUAL REPOR
59 CORPORATE GOVERNANCE
AUDIT COMMITTEE
The Audit Committee comprising Messrs Stitt, Botten, Kennedy and Zehnder meets at least twice a year, in August and February, and otherwise as directed by the Board, and external auditors are invited to attend when appropriate. The Audit Committee reviews the annual accounts so as to enable the Directors to sign the Directors’ Declaration that the accounts give a true and fair view of Oil Search’s state of affairs. The Committee also reviews the carrying value of assets, in particular exploration and development assets, on a six-monthly basis so as to ensure that the assets are recorded at appropriate values. The Audit Committee also reviews the Half Yearly Statement and the Preliminary Final Statement to the Australian Stock Exchange with a view to recommending to the Board release of those Statements. The Audit Committee nominates the external auditors and sets their remuneration and makes recommendations to the Board on the appropriate dividend level. Finally, the Audit Committee meets at the direction of the Board to consider accounting matters and internal control issues when required. The Audit Committee is particularly concerned with the scope and quality of the annual external audit.
HEDGING COMMITTEE
The Board is concerned to identify areas of significant business risk and has established a Hedging Committee comprising Messrs Stitt, Botten and Kennedy to identify and manage such risks. The main function of the Hedging Committee is to approve appropriate hedging guidelines for Oil Search covering oil, foreign exchange and interest rate exposure. The Hedging Committee meets on an “as needs” basis and at least once annually to review the appropriate hedging levels. The Committee sets guidelines for oil hedging, foreign exchange hedging and interest rate hedging and tries to ensure that hedging reduces price exposure without being speculative. The Hedging Committee monitors hedges in place and open positions by reference to realised and unrealised profits and losses. It also considers appropriate levels of insurance for Oil Search, in particular Directors’ and officers’ T J Kennedy A.M. liability insurance, approves hedging counterparts and considers specific hedging strategies when Chairman required as part of financing arrangements.
TECHNICAL COMMITTEE
The Technical Committee meets at least twice per year to consider technical matters in relation to the company’s exploration and development activities. In particular, it considers matters relating to Oil Search operated licences. The committee comprises Messrs Botten and Zehnder.
CORPORATE GOVERNANCE COMMITTEE
56 years This committee meets to consider the company’s performance in meeting appropriate standards Mr Kennedy joined the Board in 1993 T 1998 and was appointed Chairman of Oil of Corporate Governance, and comprises Ms Taylor and Messrs Kennedy, Stitt and Zehnder. It Search on 1 January 1994. He is also considers criteria for Board membership along with ongoing reviews of Board membership. Chairman of AWA Limited, Kilkenny Gold NL, and Cypress Lakes Group Limited; Deputy Chairman of Darowa Corporation Limited and a Director of Qantas Airways Limited, and other public and private companies. Mr Kennedy is a member of the Australian Federal Government Remuneration Tribunal, and a member of the Audit Committee of Oil Search Limited. Ordinary shares, fully paid: 239,352 OIL SEARCH ANNUAL REPOR Options: nil 60 OIL SEARCH LIMITED
COMMERCIAL CODE OF CONDUCT
Oil Search maintains the highest possible ethical standards amongst its employees and contractors. A Commercial Code of Conduct (“Code”) was adopted early in 1997 which governs the commercial conduct of Directors, employees and all others who represent Oil Search. The aim is to ensure that the highest standards of compliance with all relevant laws and the Australian Stock Exchange Listing Rules are maintained at all times. The Code seeks to regulate behaviour in relation to, among other things, unacceptable payments, giving or receiving gifts, conflicts of interest, use of inside information and share trading generally, and protection of company assets. Failure to comply with applicable laws, prevailing business ethics or other aspects of the Code may result in disciplinary action, which may include reprimand, formal warning, demotion, or termination of employment. Failure to comply with the insider trading policy stated in the Code constitutes cause for immediate dismissal, and breach of applicable laws may also result in prosecution by the appropriate authorities. Similar disciplinary action will be taken against any supervisor or manager who directly approves such action or who has knowledge of the action and does not immediately take appropriate remedial action. Any Oil Search employee who deals with agents, contractors or consultants is obliged to make them aware of the Code and that Oil Search expects them to conduct their business in accordance with the Code.
ENVIRONMENTAL POLICY
Oil Search is committed to conducting all of its activities in an environmentaly responsible way. All activities are required to be planned and managed to ensure minimum environmental impact and with a sensitivity to the culture of the people that they may affect. To this end, Oil Search has formulated a specific Environmental Policy which requires Oil Search, its officers, employees and agents, to:
1. incorporate the planning for, and management of, environmental risks into the management of each of its projects and activities; N N Beangke B.A. Deputy Chairman 2. comply with all environmental laws and regulations and, where appropriate, apply more stringent company standards; 3. communicate openly and positively with interested parties on environmental matters; and 4. conduct operations in an energy efficient manner. This policy is displayed in Oil Search’s offices.
OCCUPATIONAL HEALTH AND SAFETY
The welfare and health of Oil Search employees is of the highest priority. All activities
46 years undertaken by Oil Search are required to be conducted safely so as to avoid accidents or T 1998 A Papua New Guinea citizen and injuries. Safety is systematically considered as part of the management of all Oil Search’s currently the Managing Director of activities. With this in mind, Oil Search has developed an occupational health and safety Credit Corporation, Mr Beangke was appointed to the Oil Search Board policy which requires Oil Search to: on 3 July 1992, and was elected to the position of Deputy Chairman on 9 May 1994. He is also Chairman 1. provide a safe and healthy work environment; of the Bank of South Pacific Limited, and a Board member of several 2. comply with all applicable health and safety regulations; other companies operating within the country. 3. maintain an appropriate emergency response plan; and Ordinary shares, fully paid: nil 4. communicate openly with interested parties on occupational health and safety matters. Options: nil OIL SEARCH ANNUAL REPOR This policy is also displayed in Oil Search’s offices. 61 DIRECTORS’ ANNUAL REPORT
DIRECTORS
The names, details and shareholdings of the Directors of the company in office at the date of signing this report are set out on pages 49–55.
The Directors submit their Annual Report of the chief entity and its controlled entities for the year ended 31 December 1998.
RESULTS OF THE YEAR
During the year, the economic entity made an operating profit of US$9.3 million after providing for an income tax credit of US$2.6 million.
DIVIDENDS
The Directors do not recommend the payment of a dividend to ordinary shareholders in respect of the year. During the year the company paid prior year ordinary dividends of US$2.64 million and dividends on converting preference shares of US$3.58 million to its shareholders.
PRINCIPAL ACTIVITIES
The principal activity of the Oil Search economic entity is the exploration for oil and gas deposits in Papua New Guinea and the development and production of such deposits.
OTHER MATTERS REQUIRED TO BE ADDRESSED BY THE DIRECTORS
The financial statements attached to this Report form part of, and should be read in conjunction with, the Report. These financial statements include the Auditors’ Report, details of changes in accounting policies, and details of Directors, executives and Auditors’ remuneration.
P R Botten BSc. ARSM An entry was made in the Directors’ Interest Register during the year to record that Mr J L Managing Director Stitt owned 9,600 ordinary shares in Oil Search Limited at the time of his appointment as a Director of the economic entity.
During the year the company made donations totalling US$44,723.
SHARE OPTIONS
In accordance with the terms and conditions of the Oil Search Limited Employee Share Option Plan, as approved by shareholders at the Annual General Meeting of the company held in 1995, 1,550,000 unlisted options to take up unissued ordinary shares in Oil Search
T 1998 Limited at A$2.554 per share were issued to employees. The options become exercisable in 44 years three annual tranches, commencing on 24 March 2000. The options expire on 24 March Mr Botten was appointed Managing Director on 28 October, 1994, having 2003. As at 31 December 1998 there were 4,376,500 options outstanding to take up previously filled both Exploration and General Manager roles in the company unissued ordinary shares in Oil Search Limited. During the year 114,750 options were since joining in 1992. He has extensive worldwide experience in the oil and gas exercised. business, previously holding various senior technical and managerial In terms of a circular dated 14 November 1936, options are outstanding for the issue of positions in a number of listed and government owned organisations. 5,670 shares in Oil Search Limited. Ordinary shares, fully paid: nil OIL SEARCH ANNUAL REPOR Options: 1,200,000
62 OIL SEARCH LIMITED
DIRECTORS’ BENEFITS
During the financial year the company paid premiums to insure all Directors, officers and employees of the company against claims brought against the individual while performing services for the company and against expenses relating thereto. The amount of the insurance premium paid during the year has not been disclosed as it would breach the confidentiality clause in the insurance policy. Since the end of the previous financial year, no Director of the company has received, or become entitled to receive, any benefit (other than a benefit included in the aggregate amount of emoluments received or due and receivable by Directors shown in the consolidated accounts) by reason of a contract entered into by the company or a related entity with a Director, or with a firm of which he is a member, or with an economic entity in which he has a substantial financial interest.
The economic entity has not entered into any contract or agreement with the Directors that gives rise to any other benefits or business.
Details of all related party transactions are disclosed in Note 27 to the financial statements.
DIRECTORS’ AND OTHER OFFICERS’ REMUNERATION
The Remuneration Committee of the Board is responsible for reviewing compensation for the Directors and staff and recommending compensation levels to the Board. The Committee assesses the appropriateness of the nature and amount of emoluments on a periodic basis with reference to relevant employment market conditions, with the overall benefit of maximising shareholder value by the retention of high quality personnel. To achieve this objective, the Board links the nature and amount of executive director’s and other staff emoluments to the company’s financial and operational performance. In addition, staff and the executive director have the opportunity to participate in the Oil Search Limited Employee Share Option Scheme which provides share option incentives.
Details of the amount, in US$, of each element of the emolument for the financial year of each Director and of the five officers of the company receiving the highest emoluments are as follows:
M A J L Stitt . . Director’s Fees for Retirement Fixed Director fees additional allowance salary 2 Directors1 services
T J Kennedy, A.M. 28,100 28,100 17,500 – N N Beangke 28,100 7,600 11,400 – P R Botten – – – 470,600 J L Stitt 21,300 – 21,300 – M Taylor 28,100 – 8,700 – J O Zehnder 28,100 – – – T 1998
55 years 1. No options were granted to Directors during the year. Mr Stitt joined the Board in April 1998. He has extensive experience 2. Fixed salary is stated on a cost to the company basis, which may be more than the actual value received by the in the international oil and gas Managing Director and includes contractual obligations such as housing, personal and family travel and motor business, having worked for 33 years vehicle expenses. with the Royal Dutch/Shell Group of companies. Mr Stitt is Chairman of Amounts are shown in US$. the Audit Committee of Oil Search Limited. The insurance premium paid during the year to insure the Directors against claims made against Ordinary shares, fully paid: 9,600
them while performing services to the company has not been disclosed as it would breach the OIL SEARCH ANNUAL REPOR Options: nil confidentiality clause in the insurance policy. 63 DIRECTORS’ ANNUAL REPORT
Base Other 1 Total Option Exercise 2 pay compensation compensation grants: price Executives US$ US$ US$ No. of options A$
K J Wulff 119,317 59,621 178,938 100,000 $2.544 N D R Hartley 108,104 57,415 165,519 100,000 $2.544 M G Sullivan 109,979 45,611 155,590 100,000 $2.544 A T Grogan 108,402 43,445 151,847 100,000 $2.544 J G Speed 3 82,525 35,298 117,823 – –
1. Other compensation is stated on a cost to the company basis, which may be more than the actual value received by the executive and includes contractual obligations such as superannuation, health insurance, motor vehicle expenses and car parking.
2. All options issued during the year are exercisable on 24 March 2000 (25%), 24 March 2001 (50%) and 24 March 2002 (25%).
3. Mr J G Speed was not employed for the full year.
ENVIRONMENTAL DISCLOSURE
The economic entity complies with all environmental laws and regulations and operates at the highest industry standard and world’s best practice for environmental compliance. No liability has been incurred under any environmental legislation.
APPOINTMENT OF DIRECTOR
Mr John Lanktree Stitt was appointed to the Board on 27 April 1998.
RETIREMENT OF SECRETARIES
During the year Messrs Hartley and Payne retired as secretaries.
SIGNIFICANT EVENTS AFTER BALANCE DATE
Up to the date of this report, all significant events after balance date which affect the M Taylor L.L.M. Director economic entity are reported in Note 30 to the accounts.
SIGNIFICANT CHANGES IN THE STATE OF AFFAIRS
During the year, oil production commenced from the Gobe/S.E. Gobe oil fields in PNG and the economic entity acquired the upstream PNG oil and gas assets of British Petroleum Limited at a cost of US$400 million.
LIKELY DEVELOPMENTS
T 1998 Oil and gas production from each of the Petroleum Development Licences in which the 47 years economic entity is a participant is expected to continue, unabated, throughout 1999. A Papua New Guinea citizen and lawyer, Ms Taylor joined the Oil Search Board in December 1988. Ms Taylor is a board member of the Bank of Papua New Guinea, Chairperson of PNG Coffee Exports Limited, a Director of Lihir Gold Limited and Misima Mines Limited. Ordinary shares, fully paid: 3,000 OIL SEARCH ANNUAL REPOR Options: nil
64 OIL SEARCH LIMITED
ATTENDANCES AT DIRECTORS’ MEETINGS
The number of meetings of Directors (including meetings of committees of Directors) held during the year, and the number of meetings attended by each Director were as follows:
Directors’ Meetings of Committees meetings Audit Hedging Corporate Technical Remuneration Governance
Number of meetings held 6 2 2 1 2 1
Number of meetings attended T J Kennedy, A.M. 6 2 2 1 1 N N Beangke 6 P R Botten 6 2 2 2 J L Stitt 1 5 1 2 M Taylor 6 1 J O Zehnder 6 2 1 2 1
1 Mr Stitt attended all five of the Directors’ meetings and the Audit Committee meeting which were held after his appointment.
As at the date of this report, the company had an Audit Committee, a Hedging Committee, a Corporate Governance Committee, a Technical Committee of the Board of Directors, and a Remuneration Committee. The members of the Committees are as follows:
Audit: Mr J L Stitt (Chairman), Mr T J Kennedy, Mr J O Zehnder and Mr P R Botten; Hedging: Mr J L Stitt (Chairman), Mr T J Kennedy and Mr P R Botten; Corporate Governance: Mr T J Kennedy (Chairman), Mr J L Stitt, Mr J O Zehnder and Ms M Taylor; Technical: Mr J O Zehnder (Chairman), and Mr P R Botten; and Remuneration: Mr T J Kennedy (Chairman) and Mr J O Zehnder.
ROUNDING
J O Zehnder BSc. All amounts included in the accounts are rounded to the nearest thousand US$ under ASIC Director Class Order 98/100. The economic entity is an entity to which the Class Order applies.
CORPORATE GOVERNANCE
In recognising the need for the highest standards of corporate behaviour and accountability, the Directors of the company support and have adhered to the principles of corporate governance. The economic entity’s corporate governance statement is contained in this 1998 Annual Report.
Signed in accordance with a resolution of the Directors. T 1998
72 years Mr Zehnder joined the Board in March 1987. Mr Zehnder is a geologist with extensive experience in the petroleum industry. Mr T J KENNEDY, A.M. N N BEANGKE Zehnder is a member of the Audit Committee of Oil Search Limited. Chairman of Directors Deputy Chairman Ordinary shares, fully paid: 2,000 2nd March 1999 Options: nil OIL SEARCH ANNUAL REPOR
65 STOCK EXCHANGE INFORMATION
(a) Authorised capital 1,000,000,000 ordinary shares INVITATION TO ANNUAL Issued capital 468,903,307 ordinary shares, fully paid GENERAL MEETING 1,189,000 converting preference shares, fully paid 4,376,500 unlisted employee share options over fully Notice is hereby given paid shares, held by 46 employees that the sixty-eighth (b) The distribution of ordinary fully paid shares ranked according to size was: Annual General Meeting Size of holding Number of holders Number of shares of members of 1–1,000 10,920 7,226,338 Oil Search Limited 1,001–5,000 10,962 26,638,069 will be held in 5,001–10,000 2,143 16,244,397 the Erima Suite at 10,001–100,000 1,276 32,386,808 the Gateway Hotel, 100,001 and over 151 386,407,695 Port Moresby, 25,452 468,903,307 Papua New Guinea, (c) The distribution of converting preference shares ranked according to size was: on Friday, 4 June 1999 Size of holding Number of holders Number of shares at 11:00 a.m. 1–1,000 206 43,886 1,001–5,000 32 86,718 5,001–10,000 18 145,571 10,001–100,000 29 771,829 100,001 and over 1 140,996 286 1,189,000 (d) The twenty largest ordinary shareholders representing 73.65% of the issued capital were as follows: Shareholder Number of shares % of issued capital
Westpac Custodian Nominees Ltd 91,393,714 19.49 National Nominees Ltd 51,296,248 10.94 Chase Manhattan Nominees Ltd 34,574,992 7.37 BT Custodians Ltd 33,139,421 7.07 Australian Mutual Provident Society Ltd 15,119,535 3.22 Citicorp Nominees Pty Ltd 14,304,470 3.05 MLC Life Ltd 14,257,198 3.04 Commonwealth Custodial Services Ltd 11,622,062 2.48 Cho Poon Chow 10,999,291 2.35 Westpac Life Insurance Services Ltd 9,522,093 2.03 Queensland Investment Corporation 8,478,265 1.81 Brispot Nominees Pty Ltd 7,613,047 1.62 PTA Nominees Ltd 7,538,969 1.61
T 1998 National Mutual Life Association of Australasia Ltd 7,358,502 1.57 ANZ Nominees Ltd 6,315,532 1.35 State Services Superannuation Fund 5,005,000 1.07 Sandhurst Trustees Ltd 4,789,587 1.02 SAS Trustee Corporation Ltd 4,620,365 0.99 Norwich Union Life Australia Ltd 3,734,176 0.80 Merrill Lynch (Australia) Nominees Ltd 3,637,042 0.77 345,319,509 73.65 OIL SEARCH ANNUAL REPOR
66 STATEMENT REGARDING HYDROCARBON RESERVES AND RESOURCES REFERRED TO IN THIS REPORT The information in this report is based on, and accurately reflects, 2P oil reserves information compiled by Netherland, Sewell & Associates, Inc. (“NSAI”), and information compiled in conjunction with the Operators of each of the permits in which the company is a participant. NSAI was engaged by Oil Search Limited due to its relevant experience in relation to the hydrocarbon reserves and resources being reported, and qualifies as a Competent Person as defined in the Australasian Code for Reporting of Identified Mineral Resources and Ore Reserves. There are no material differences between the Financial Statements included in this report and Appendix 4B lodged with the Australian Stock Exchange. Oil Search Limited has a formally constituted Audit Committee.
AS AT 1 MARCH 1999
(e) The twenty largest converting shareholders representing 80.34% of the issued converting CORPORATE DIRECTORY preference shares were as follows: Shareholder Number of shares % of issued capital
REGISTERED OFFICE Westpac Custodian Nominees Ltd 173,278 14.57 5th floor, NIC Haus, Champion Parade, MLC Life Ltd 79,813 6.71 Port Moresby, National Capital District. P.O. Box 1031, Port Moresby, Elise Nominees Pty Ltd 71,077 5.98 PAPUA NEW GUINEA. PTA Nominees Ltd 71,000 5.97 Telephone: (675) 321 3177 Facsimile: (675) 321 4379 Permanent Trustee Company Ltd 68,780 5.78 AUSTRALIAN OFFICE Chase Manhattan Nominees Ltd 54,504 4.58 15th floor, NAB House, Calex Nominees Pty Ltd 50,189 4.22 255 George Street, National Nominees Ltd 48,710 4.10 Sydney, New South Wales, 2000. G.P.O. Box 2442, Sydney, Challenger Life Ltd 48,454 4.08 New South Wales, 2001, AUSTRALIA. Perpetual Trustees Nominees Ltd 35,370 2.97 Telephone: (61-2) 92518400 National Mutual Life Association of Australasia Ltd 32,820 2.76 Facsimile: (61-2) 92511232 Citicorp Nominees Pty Ltd 32,251 2.71 SHARE REGISTRAR Sandhurst Trustees Ltd 27,750 2.33 Computershare Registry Services Austrust Ltd 27,565 2.32 Pty. Limited 3rd floor, 60 Carrington Street, BT Custodial Services Pty Ltd 25,614 2.15 Sydney, New South Wales, 2000. FAI Workers Compensation NSW Ltd 25,000 2.10 G.P.O. Box 7045, Sydney, New South Wales, 1115, Brispot Nominees Pty Ltd 22,305 1.88 AUSTRALIA. Australian Mutual Provident Society Ltd 20,773 1.75 REGISTER OF DEPOSITARY RECEIPTS Australian United Investment Company Ltd 20,000 1.69 Bank of New York Diversified United Investments Ltd 20,000 1.69 ADR Division 955,253 80.34 22nd floor, 101 Barclay Street, New York, NEW YORK, 10286, UNITED STATES OF AMERICA (f) The following interests are recorded in the company’s Register of Substantial Shareholders en as at 1 March 1999: SENIOR MANAGEMENT Shareholder Number of shares % of issued capital McLar
+ Gerea Aopi C.B.E. Government & Corporate Affairs Manager Norwich Union Financial Services Ltd 57,076,190 12.17 (Papua New Guinea) Genesis Asset Managers Ltd 36,850,800 7.86
ong Miller Peter R Botten (g) The securities of the company are listed on the Australian Stock Exchange. ch Limited – Brad Hawkins Managing Director (Papua New Guinea) mstr Nigel D R Hartley VOTING RIGHTS ATTACHED TO SHARES Chief Financial Officer (Australia) Ordinary shares John G Speed (1) On a show of hands, one vote per member; Operations Manager (Australia) oduced by Ar (2) On a poll, every member present shall have one vote for every share held by him/her Michael G Sullivan
dination for Oil Sear in the company. General Counsel (Australia) Keiran J Wulff Converting preference shares Exploration Manager (Australia) Limited voting rights are attached to converting preference shares. oject coor Pr Designed and pr … VISIT OUR WEB SITE ON www.oilsearch.com.au ERHLMTED 1998 ANNUAL REPORT M L SEARCH O