REPLENISHING AND UPGRADING RESERVES  Santos added 57 million boe of Proven (1P) reserves which represents 121% of 2004 production. Proven reserves at the end of the year, after 47.1 million boe of production and after divestments, were 348 million boe, compared with 338 million boe at the end of 2003.  The replacement of Proven reserves exceeded Santos’ total group production for the third year in a row, with the replacement rate for Proven reserves averaging 130% over the past three years: a good result and in line with international best practice. Proven plus Probable (2P) reserves increased by 54 million boe prior to production, or by 7 million boe after production which represents a reserves replacement rate of 114%. The 2004 reserves figures do not include any potential reserve bookings for the Jeruk oil discovery in the Sampang PSC in East Java or the Hiu Aman oil and gas discovery in the Donggala PSC in the Kutei Basin, offshore East Kalimantan. The average Proven reserve replacement cost for 2004 was US$12.37 per boe. Replacement costs in any one year are affected by the timing of spending and reserve bookings, so a three-year average is a more reliable indicator of costs. Santos’ three- year average replacement cost of US$7.19 per boe is world- competitive.  2004 was also a significant year in terms of development, with some 102 million boe of 1P reserves and 134 million boe of 2P reserves being moved from undeveloped to developed, significantly increasing the value of reserves. The material movements in reserves during the year were as follows: The shift in Santos’ focus since 2001 is evidenced by the reduction in onshore reserves and the corresponding increase in offshore reserves over time, as shown in the charts below. This trend can be expected to continue as the central Australian fields mature and new projects move through the development conveyor. • Onshore Australia – revisions due to positive reservoir performance and development results in onshore Australia added 18.5 million boe of  1P reserves. • Cooper Basin – poorer than expected performance in some tight gas fields and the integration of results from some previously unsuccessful fracture stimulations resulted in a 2P reserve reduction of 16 million boe.  • Bayu-Undan – excellent results from development drilling program in the Bayu-Undan field added 7 million boe of  1P and 14 million boe of 2P reserves. • Mutineer-Exeter – a disappointing appraisal and development drilling campaign resulted in downgrades in 1P reserves of 10 million boe and 2P reserves of 13 million boe. • John Brookes – integration of the late 2003 drilling results in the John Brookes gas field, along with detailed reservoir modelling, resulted in a significant positive revision of 15 million boe of 1P and 32 million boe of 2P reserves. • East Spar – disappointing production performance resulted in downgrades in 1P reserves of 3 million boe and 2P reserves of 8 million boe. • Maleo – sufficient progress with commercialisation resulted in the booking of 19 million boe of 1P and 27 million boe of 2P reserves. • Acquisitions and divestments – a net increase in 1P reserves of 12 million boe and 2P reserves of 22 million boe from the acquisition of certain Novus Petroleum assets and an increase in Patricia-Baleen equity, with negligible movement due to divestments. Annual Report 2004 24 OFFSHORE 1P AND 2P RESERVES mmboe - nett ’01 ’02 ’03 ’04 25 8 222 303 327 Probable Proven 0 100 200 300 400 500 600 ONSHORE 1P AND 2P RESERVES mmboe - nett ’01 ’02 ’03 ’04 474 503 333 316 Probable Proven 0 100 200 300 400 500 600