24th Mar 2005 07:01
Premier Oil PLC24 March 2005 Premier Oil plc Preliminary Results for the year ended 31 December 2004 Premier is a leading independent exploration and production company with gas andoil interests principally in the UK, Asia and West Africa Highlights Financials • Profit after tax up 57% to US$43.8 million (2003: ongoing operations US$27.9 million) • Healthy cashflow - operating cashflow after interest and tax of US$109.8 million (2003: ongoing operations US$135.8 million) • Ungeared balance sheet with net cash balances up at US$19.6 million • £10 million share buy-back programme Operational achievements • Production ahead of budget - 34,700 boepd (2003: ongoing operations 35,100 boepd) • Booked working interest reserves higher at 177 mmboe • Six exploration and appraisal drilling successes - over 50% success rate • Record gas exports from Premier's operated West Natuna gas project, in Indonesia • Acquired stakes in promising exploration acreage offshore Vietnam and onshore Egypt 2005 Outlook • 16 exploration and appraisal wells currently planned • Mauritanian and Indonesian oil and gas developments on-track Chief Executive Officer • Further to the announcement last September, Operations Director Simon Lockett takes over as CEO from today. Charles Jamieson remains on Premier's Board until end June 2005 Sir David John, Chairman, commented: "Premier's 2005 objective is to add significant value for shareholders throughits planned 16 well exploration and appraisal programme, and by capturingcommercial deals. The strong financial position, as reflected in our excellent2004 results and ungeared balance sheet, provides the firepower to do so." 24 March 2005 Enquiries: Premier Oil plc 020 7730 1111Simon LockettJohn van der Welle College Hill 020 7457 2020Jim JosephNick Elwes CHAIRMAN'S STATEMENT Our results for 2004, both operating and financial, have been built on thebenefits of the restructuring in 2003, good exploration results and commercialdeals, particularly in Mauritania, together with high oil prices. This hasestablished an excellent foundation to continue to deliver strong performance. Financial and Operating Performance As announced in October 2004, Premier is reporting its results in US dollars forthe first time. As this is the currency of the oil and gas business, the Boardbelieves that the US dollar accounts will give a clearer picture of theperformance of the group's business, minimising the impact of US dollar exchangerate fluctuations. In 2004 profits after tax were US$43.8 million (2003: US$66.5 million). On acomparative basis, net profits increased by 57% (2003: US$27.9 million from 'ongoing operations' reflecting the restructuring completed in September 2003).This profit improvement largely reflects higher oil prices and lower interestcharges following the restructuring. Operating cashflow after taxes andinterest amounted to US$109.6 million (2003: ongoing operations US$135.8million) and, at year-end Premier was debt-free with net cash balances ofUS$19.6 million (2003: US$12.7 million). We are therefore currently fullyfunding our capital expenditure on fields, developments and exploration/appraisal from operating cashflow, keeping the balance sheet strong in order topreserve financial flexibility. Production for the year, on a working interest basis, was broadly flat at 34,700barrels of oil equivalent per day (boepd) (2003: ongoing operations 35,100boepd). Our producing fields are performing well and have exceeded plannedlevels in the first quarter of 2005. We continue to focus on maintaining worldclass health, safety and environmental performance and, in Indonesia ouroperated West Natuna gas facility passed a milestone in June 2004 of three yearscontinuous operation without a lost time incident. Field development work onWest Natuna, and the Chinguetti field in Mauritania has progressed well. Oil and gas proven and probable booked reserves at year-end amounted to 177million barrels of oil equivalent (mmboe) on a working interest basis. Thesereserves have been confirmed by independent review. Total recoverableresources, including discoveries not yet booked pending appraisal/commercialisation, have increased by 10 mmboe to an estimated 210 mmboe. On the exploration front, participation in 11 exploration and appraisal wellsyielded a good success ratio of 50% or more for the second year running. Sixsuccesses were recorded in 2004, comprising Gajah Baru in Indonesia, Sinapa-2 inGuinea Bissau, the Tevet discovery and three Tiof appraisal wells in Mauritania.Further appraisal and commercialisation work is planned in respect of thesediscoveries. Board Following the implementation in the revised Combined Code of the Higgs report onthe role and effectiveness of non-executive directors, which is effective for2004, the Board has undertaken its first formal independent evaluation, theoutcome of which was extremely satisfactory. A major focus for the non-executive directors in 2003 and 2004 has been theappointment of a successor to Chief Executive, Charles Jamieson. A thoroughselection process was carried out looking at both external and internalcandidates. I am delighted that the decision taken was to promote SimonLockett, whose appointment was announced in September 2004. Simon has been withPremier for ten years, fulfilling a number of roles, most recently as OperationsDirector, and he takes over as Chief Executive with effect from today. Charlesremains an executive director and will retire in June 2005 after twenty-fiveyears with the Company, the last thirteen years as Chief Executive. On behalfof the Board, employees and shareholders, I would like to take this opportunityto thank him for his outstanding contribution to the successful development ofyour Company, which has never been in better shape. I wish Charles the best ofgood fortune for the future. Shareholder Returns I am pleased to report that Premier shares have increased in value by 350% overthe five years to 22 March 2005, making the Company a top ten performer in theFTSE 250. Our objective remains to reward shareholders principally throughshare price growth, and to consider returns via share buy-backs or specialdividends, when appropriate. In December 2004, the Board authorised a share buy-back programme of up to £10million. In our view the then prevailing share price was significantly belowour valuation of net assets per share, and the Company has benefited from acashflow surplus above the needs of the business, due to the high oil price. Asuccessful programme was carried out at an average price of £5.32 per share,adding to remaining shareholders' value per share. Further share purchases willbe considered in the appropriate market conditions. Outlook At the end of 2004, the Board carried out a review of the Company's strategy.The existing policy of growing net asset value per share, and hence share price,through exploration success and commercial deal-making, was endorsed withrenewed emphasis on the commercial front. An ungeared balance sheet and strongcashflow from production give us an excellent foundation for investments in ourfocus countries in Asia and Africa. In 2005 we are undertaking an excitingexploration programme of up to 16 wells in 8 countries, and will continue oursearch for attractive new commercial opportunities. Sir David John KCMGChairman FINANCIAL REVIEW Economic Environment In 2004, sustained strong economic growth, particularly in Asia, has driven thedemand for crude oil. This was compounded by disruptions to supply andpolitical uncertainty in the Middle East, as a result of which prices continueto remain supported at historically high nominal levels into 2005. The Brentoil price commenced the year at US$29.9 per barrel and grew steadily throughoutthe period, peaked at US$49.6 per barrel in October, and fell to US$39.5 perbarrel in December, averaging US$38.3 per barrel for the year (2003: US$28.8per barrel). Following US dollar weakness against the pound in 2002 and 2003, the US dollar/pound rate opened 2004 at US$1.79 and remained broadly stable into the fourthquarter of the year, following which the dollar weakened markedly against thepound to end the year at US$1.92. Profit and Loss Account In October, Premier announced its intention to adopt the US dollar as thereporting currency of the group going forward, with the accounts for the yearended 31 December 2004 being the first to be published in US dollars. Themajority of Premier's revenue and expenditure is transacted in US dollars as itis the functional currency of the upstream oil and gas industry. By adoptingthe US dollar for reporting purposes, the Board believes that the accounts willgive a clearer picture of performance of the group's business, minimising theimpact of US dollar exchange rate fluctuations. Comparative numbers for 2003 provided in these results were originally reportedin sterling, and have been translated at the appropriate US dollar/pound ratesprevailing during the period. The rates used are an average rate of US$1.63 forprofit and loss items and a year-end rate of US$1.79 for balance sheet items. As explained in the 2003 results, the profit and loss account for that year hasbeen analysed to show profit relating to 'ongoing operations', i.e. those assetsretained after the restructuring. This provides the most comparable referencefor the 2004 results. Profit after tax for 2004 was US$43.8 million (2003: US$66.5 million), whichcompares with US$27.9 million from 2003 ongoing operations, an increase of 57%.As foreshadowed in the interim results announced in September 2004, net profitin the second half was somewhat lower than in the first half due to thetransition in 2004 in Indonesia from cost recovery to profit oil/gas on the Anoafield. Production levels in 2004, on a working interest basis, averaged 34,700 boepdcompared with 35,100 boepd in 2003. On an entitlement basis, production was31,500 boepd (2003: 33,200 boepd). Realised oil prices averaged US$29.92 perbarrel (bbl) compared with US$27.2 per bbl the previous year. Gas prices averaged US$3.24 per thousand standard cubic feet (mscf) (2003:US$3.28 per mscf). The average gas price has not risen in line with oil pricesdue to there being a greater proportion of lower unit price gas production fromPakistan. Additionally gas prices in Indonesia, indexed to high sulphur fueloil, have not increased in line with the Brent oil price. Turnover, including the group's share of the joint venture in Pakistan, was 7%lower than 2003 ongoing operations at US$251.8 million (2003: US$420.0 millionand ongoing operations US$270.4 million), mainly as a result of lower levels ofentitlement production. Cost of sales was down from 2003 ongoing operations by US$12.7 million atUS$108.4 million. Including the joint venture, total cost of sales was US$129.0million (2003: US$182.8 million and ongoing operations US$136.9 million).Based on total cost of sales, underlying unit operating costs amounted toUS$5.80 per barrel of oil equivalent (boe) (2003: US$5.52 per boe), an increasefrom the previous year mainly due to the impact of fixed costs as productiondeclines in the UK, together with sterling costs in the UK being translated at ahigher US dollar exchange rate. Underlying unit amortisation amounted toUS$4.90 per boe, the same as in the previous year. Exploration expenditures written-off for the year amounted to US$14.3 million(2003: US$19.9 million), representing final costs incurred in respect of Albania(US$1.5 million) from where we have withdrawn, and various new business expensesin other areas (US$12.8 million). Administrative costs have fallen by US$3.6 million to US$15.5 million,reflecting lower overheads post the restructuring and costs associated with thelong term incentive plan in 2003. Operating profits, including the jointventure, were US$93.0 million (2003: US$94.5 million ongoing operations) withthe fall from 2003 ongoing operations resulting from the lower turnover, partlyoffset by the lower cost of sales and exploration write-off. Net interest expenses totalled US$2.8 million, down from US$20.0 million for2003 ongoing operations, due to lower levels of debt as a result of therestructuring. In addition foreign exchange losses of US$3.0 million arose fromthe translation of sterling liabilities (2003: loss US$1.3 million). Consequently, pre-tax profits were 19% higher at US$87.2 million (2003:US$73.2million) as compared with 2003 ongoing operations. The taxation charge totalledUS$43.4 million (2003: US$45.3 million), broadly the same as the correspondingperiod. Earnings per share amounted to 53 cents, an increase of 8.4% on the previousyear. Cashflow Cashflow from operating activities, as reported in the cashflow statement whichexcludes the joint venture in Pakistan, amounted to US$124.4 million, down fromUS$224.9 million in 2003 due to lower production following the restructuring.After deducting interest and taxes, operating cashflow was US$70.5 million, adecrease of US$43.1 million. Including the cashflows from the joint venture,operating cashflows after interest and taxes were US$109.6 million, whichcompares with US$135.8 million from ongoing operations in 2003. The reductionreflects the lower level of cashflow as UK production has declined together withpayments in 2004 relating to the long term incentive plan liabilities at the endof 2003. There was a net inflow of US$32.2 million in the period from the jointventure in Pakistan. Capital expenditure in the period was US$95.6 million (2003: US$52.6 million),with total capital expenditure at US$104.5 million including the joint venture(2003: US$70.1 million). The increase is due to the inclusion of costs on theChinguetti development project and an increase in exploration expenditure.Total capital expenditure comprised US$34.4 million on fields/developments,US$57.3 million on exploration and appraisal activities, with other expenditureof US$2.6 million. In addition, expenditure of US$10.2 million was incurred inthe acquisition of an additional share in our Mauritanian acreage includingChinguetti. Net cashflow, including the joint venture but before movements relating toshort-term deposits and financing, amounted to US$4.9 million. Net Cash At the start of the year, net cash, including the Pakistan joint venture netcash of US$4.8 million, was US$12.7 million. At the end of 2004 the benefit ofnet cashflows from operations resulted in an increased net cash balance ofUS$19.6 million, including balances in the Pakistan joint venture. Thiscomprised US$59.6 million of cash balances and investments and drawdown of US$40million from the bank revolving credit facility of US$150 million. The balancesheet of the group at the end of 2004 therefore remained ungeared. Hedging and Risk Management It is group policy that all transactions involving derivatives must be directlyrelated to the underlying business of the group. No speculative transactions areundertaken. Premier has undertaken oil and gas hedging periodically within Boardapproved limits, to protect operating cashflow against weak prices. Hedging for 2004 has been undertaken almost exclusively with zero cost collars,with oil price floors at US$20.0 per barrel and a ceiling price averagingUS$29.4 per barrel. Approximately one third of Indonesian gas production wasalso covered using zero cost collars at a floor price of US$118 per metric tonneof high sulphur fuel oil (HSFO) and a ceiling price of US$181.3 per metrictonne. These hedges produced a combined opportunity loss of US$23.0 million forthe year (2003: loss US$6.5 million), resulting from the unexpectedly high oilprices in 2004. This amount has been deducted in turnover. Hedges for 2005 are in place for the first half of the year only. These havebeen entered into using zero cost collars covering 900,000 barrels of oilrepresenting 49% of anticipated liquids production in the first half of 2005 ata floor price of US$21.0 per barrel and a ceiling price of US$34.5 per barrel.In addition 60,000 metric tonnes of HSFO, representing the equivalent of 45% ofIndonesian gas production for the first half of 2005, has been covered at a HSFOfloor price of US$121.0 per metric tonne and a ceiling price of US$196.7 permetric tonne. No hedges have been undertaken covering the period beyond theend of June 2005, and no hedges have been put in place since March 2004. The change to reporting of the group's results in US dollars considerablyreduces the group's exposure to unexpected currency movements. Exchange rateexposures now relate almost exclusively to sterling receipts and expendituresand these have not been hedged during the year. Cash balances are invested in a range of floating rate bank deposits, managedliquidity funds and commercial paper, subject to Board approved limits. Thegroup undertakes an insurance programme to reduce the potential impact of thephysical risks associated with the exploration and production activities. Inaddition, business interruption cover is purchased for a proportion of thecashflow from producing fields. Adoption of International Financial Reporting Standards The Council of the European Union requires all EU listed companies to reportconsolidated results using endorsed International Financial Reporting Standards(IFRS) with effect from 1 January 2005 (including comparatives for 2004). Premier has established a project team that is managing the transition to IFRS.The project team is working alongside the UK Oil Industry Accounting Committeeto ensure that it has an approach to adoption consistent with the industry, andis looking at all aspects of the requirement, including the wider businessissues that may arise from such a major change. We expect the group to be fullyprepared for adoption of IFRS by the required dates in 2005. Differences between our current accounting practices and IFRS are likely to bein respect of fixed assets, deferred tax, joint ventures, employee costs(including pension benefits), oil and gas hedges and any other areas affected byrelevant developments in the International Accounting Standards Board's standardsetting process and final endorsement by the EU. The process of transition is well advanced, although not complete. We arecurrently preparing reconciliations of the results for 2003 and 2004 and we willrelease this information to the stock market and on the Premier web site(www.premier-oil.com), before the announcement of the 2005 interim results inSeptember 2005. OPERATIONAL REVIEW Exploration and Appraisal Premier is committed to a strategy for growth in shareholder value throughinvesting in an extensive and high quality exploration programme. Each year weelect to drill the best of our large portfolio of exploration opportunities,choosing to drill a varied and exciting suite of wells. We believe it isimportant to spread investment over a number of high potential opportunitiesrather than focussing too narrowly. Premier participated in 11 exploration and appraisal wells in 2004, the same as2003. This was a slightly lower number than the plan for 12 - 18 wells, due toa greater focus on development drilling by the operator in Mauritania, andoperational delays in Gabon and India where drilling is now scheduled for 2005.However, the programme yielded six successes - Gajah Baru-2 in Indonesia, theTevet and Tiof 3, 4 and 5 wells in Mauritania and Sinapa-2 offshore GuineaBissau. Overall the programme has yielded a 50%, or better, success rate foreach of the two successive years since our restructuring was announced. The programme for 2005 includes drilling in West Africa, South and South EastAsia. Up to five wells are under consideration in Mauritania, with other WestAfrican wells offshore Gabon (Iris, Themis) and Guinea Bissau on the Esperancablock. Exploration wells are in progress in India (Lakkhi-1) and Egypt (AlAmir-1), and later in the year we expect to commence drilling up to 2 wellsoffshore Vietnam and at least one (Macan Tutul) in block A offshore Indonesia. Production and Reserves Working interest production for 2004 averaged 34,700 boepd. Comparableproduction from 2003 from ongoing operations post the restructuring was 35,100boepd, and total annualised production (including assets disposed in therestructuring) amounted to 53,600 boepd in that year. Whilst in the first twomonths of 2005 production of 36,600 boepd has out-performed our budget, wecurrently estimate 2005 annual production at an average of about 32,000 boepd. Production comprised one third liquids and two thirds gas, with the UK andIndonesia each accounting for 35% of the total, with Pakistan the remainder.Working interest production in Indonesia is allocated between the government andPremier in accordance with the relevant production sharing agreements. On anentitlement basis, group production for the year was 31,500 boepd. Working Interest Entitlement Production 2005 2004 2003 2004 2003 (boepd) Year to date Ongoing Ongoing (End Feb.) Operations Operations UK 12,700 11,900 15,300 11,900 15,300Pakistan 12,600 10,300 8,100 10,300 8,100Indonesia 11,300 12,500 11,700 9,300 9,800Total 36,600 34,700 35,100 31,500 33,200 Proven and probable reserves, on a working interest basis, based on Premier andoperator estimates, increased slightly to 177 mmboe, as follows: Reserves (mmboe) Start of 2004 175 Production (12) Revisions 6 Acquisition 8 End of 2004 177 At year end reserves comprised 20% liquids and 80% gas, and the equivalentvolume on an entitlement basis amounted to 157 mmboe (2003: 155 mmboe). Revisions represent increases mainly in the Wytch Farm, Kyle, Bhit and IndonesiaBlock A fields, partly offset by minor downgrades to the Scott and Kakap fields.The increases result from better than expected reservoir performance and theimpact of new field data. The acquisition volume reflects the completion of thepurchase of our interest in the Chinguetti field. There has been considerable discussion recently over the disclosure of oil andgas reserves by upstream companies, particularly under SEC definitionsapplicable for reporting in the US, relating to the narrower proved category.Premier reports its reserves on the proven and probable basis in accordance withthe UK Statement of Recommended Practice (SORP) issued by the Oil IndustryAccounting Committee dated July 2001. It has been the Premier Board's practice in finalising its annual results tocompare its reported reserve estimates with those estimated by independentreporting engineers DeGolyer and MacNaughton, to provide additional support forour public disclosures and financial statements. In view of the current focuson reserve disclosures, the Board has decided for this year to publish theDeGolyer and MacNaughton proven and probable reserve estimate for fields whichhave been booked as at the end of 2004. This amounted to working interestreserves of 179 mmboe on a comparable basis. It is not intended to publish anindependent reserve estimate each year. Discoveries made in the year in Indonesia and West Africa have not been recordedin booked reserves pending completion of ongoing appraisal and commercialisationwork. Including these discoveries, unbooked reserves in the process of beingcommercialised in respect of uncontracted gas in Indonesia, together with theTevet and Tiof discoveries in Mauritania, gives increased total working interestresources of approximately 210 mmboe. Europe Premier's production base in the UK is mainly oil from several mature fields andrepresents a valuable cashflow source. It also provides an opportunity tocapture upside potential from incremental investment which reduces the rate ofdecline, and by managing costs. Production in the UK amounted to 11,900 boepd(15,300 boepd in 2003). This represents a decrease of some 22% on last year'slevel due to natural declines. However, in the year to date, 2005 productionhas risen to 12,700 boepd as incremental investments in the second half of 2004have been brought onstream. The Wytch Farm oil field contributed net production of 4,700 boepd to Premier,down 16% on last year. Following the planned rig upgrade completed in the firstquarter 2005, the infill drilling campaign has successfully arrested productiondecline in the offshore area under Poole Bay. A further three new infill wellsin the offshore area are planned to be drilled in 2005, and a project to enhanceoil recovery by injection of low salinity water is being progressed towardssanction in 2006. Premier's net production from Kyle was 4,200 boepd, down 24% on 2003. This wasprimarily due to natural decline and the planned shut-in of the Kyle 14 wellfrom early June to October. This well produces from the Paleocene reservoir andhas now been successfully tied back to the nearby Ramform Banff floatingproduction, storage and offtake vessel (FPSO). The well was brought backon-stream at a rate of in excess of 4,000 barrels of oil per day (bopd) gross,ahead of expectation, and is currently producing at a gross rate of around 3,700bopd of dry oil. Following negotiation with the Banff operator in 2004, the Kyle partners furtheragreed to tie-back the remaining Kyle wells to the Banff FPSO, and this isexpected to take place this summer. As a result of this negotiation an allinclusive processing and transportation tariff has been agreed which willsubstantially reduce operating costs and allow the extension of field life to upto end 2015. Plans for a compression upgrade at Banff, gas lift of wells andfurther infill drilling are also under consideration. Gross field rates arecurrently around 6,500 bopd and 35 mmscfd of gas. In the Fife Area, Premier's net production was 2100 boepd from the Fife, Fergus,Flora and Angus fields with natural decline successfully managed by optimisationof existing water injection and gas lift facilities. Scott and Telford (700boepd) accounted for the majority of the remainder of net UK production. On the exploration front, Premier operated the Criollo-1 well on block 21/10b-5in the Outer Moray Firth. This high risk well did not find the targeted Buzzardsands but encountered good quality thick sands of an older age. These sands havenow been mapped in another area of the same block and a prospect has beengenerated for potential future drilling. Premier was successful in acquiring new acreage in the UKCS 22nd Licence Roundwith 11 blocks awarded, four of which we operate. The blocks are located in thecentral and southern North Sea. Technical work is underway to see if attractiveprospects for drilling in 2006 and beyond can be generated. In Albania, early in the year, Premier concluded its withdrawal from the PatosMarinze project. South Asia Premier's interests in South Asia are in Pakistan, where we are well establishedhaving been active for 15 years, with production from four gas fields and a longterm exploration programme, and in India where we are at the early stages ofexploring in the North East of the country. In Pakistan, 2004 was another successful year for Premier with net productionaveraging 10,300 boepd, an increase of 28% over the prior year (2003: 8,100boepd). The increase in production was due to 2004 being the first full year ofproduction from the Bhit and Zamzama fields commissioned in 2003 and expansionof Qadirpur plant capacity from 400 to 500 mmscfd completed in March 2004, whereaverage net production rose to 3,100 (2003: 2,500 boepd). Zamzama produced a net average of 3,500 boepd during the year (2003: 2,400boepd). For the Zamzama phase 2 development, a term sheet for the sale of 150mmscfd has been initialled by the gas buyer Sui Southern Gas Company Limited(SSGCL) and joint venture partners. The term sheet has been approved by SSGCLand sent to the Oil and Gas Regulatory Authority for approval. First gas isexpected in mid 2007. Following the successful appraisal of the Badhra field in the Kirthar licencesouth east of Bhit, a Development and Production Lease was awarded in 2004.Development of Badhra reserves is now planned along with Bhit phase 2, withexpected gas production in mid 2007. Studies for the Bhit plant capacityenhancement are also underway. The Bhit field produced 2,700 boepd during theyear (2003: 2,000 boepd). The Zarghun South Development and Production Lease has been signed with theGovernment of Pakistan. Premier's interest of 3.75% is to be carried by theoperator during the development and production phases of the field. A draft gassales agreement for the supply of 22 mmscfd has also been initialled by SSGCLand the joint venture and is in the process of formal approval. Production isexpected in mid 2007. During 2004, the Kadanwari field production continued to decline to 1,000 boepd(2003: 1,200 boepd). However, with the tie-in of the successful explorationwell Kadanwari West-1 at the start of 2005, and another well planned in theKadanwari West area, this declining trend will be arrested. Exploration in the Dumbar licence area was completed with the drilling of ourlast committed exploration well Chung-1. The well was declared a dry hole andthe licence has been relinquished. The Company was awarded a new explorationlicence, Jhangara, in mid 2004. The licence is due to be signed in April 2005and preparations to drill the Maliri well, a prospect close to the Badhra field,are underway. Elsewhere in Pakistan, Premier is participating in the Shell operated IndusOffshore block 2365-1. Interpretation of the 3D suggests that a number of largeoil-prone prospects lie in the western portion of the block, comprising Tertiarysand channels draped over 4-way dip closed structures. The acreage is locatedin deep water and, to mitigate the likely high well cost, all parties in thegroup are farming down their working interests in the block, leaving Premierholding a 12.5% equity stake. Plans are underway to drill a well in 2005/2006. In India, in Assam, Premier has deployed pioneering seismic techniques toprocess data from such environments which are well known to present imagingdifficulties. This technology is not widely shared across the industry and wasdeveloped as part of our programme looking at thrust belts in other similarexploration areas. In our operated Cachar block in Southern Assam, a 230km 2D seismic survey wascompleted in difficult jungle terrain. The survey was undertaken over a fourmonth period, with a workforce of some 1600 personnel at its peak, and wassuccessfully completed without a lost time incident. Interpretation of this new seismic, together with existing geological andgeophysical data, has confirmed our view that the block is prospective for largeaccumulations of hydrocarbons. A decision has recently been taken to drill anexploration well on the Masimpur prospect. Road and site construction willcommence after the monsoon season, and the well is expected to spud in the firstquarter of 2006. Premier believes that the target has the potential to be charged with gas and ifsuccessful could represent a playmaker well - proving the presence ofsignificant gas reserves east of Bangladesh. This would have a strong influenceon the proposed development of inter-country gas pipeline infrastructure in theregion. The farm-out of 35% equity in the Cachar block to Indian Oil Corporation wasalso completed following government approval, and Premier's interest in theblock has been reduced to 49%. In the Jaipur block in Upper Assam, construction of the road and well site forour first exploration well, Lakkhi-1, was completed and drilling is due tocommence imminently. In addition, geological field studies have revealed furtherleads which may mature into drillable prospects during 2005. The Company is continuing to seek opportunities to expand its portfolio inIndia. South East Asia The backbone of our business in South East Asia is our interest in the WestNatuna gas project in Indonesia, supplying gas under a long term sales contractto Singapore. This is through our interests in the Natuna Sea block A and Kakapproduction sharing contracts (PSCs) from which we also produced some 2,400 bopdin 2004. Gas export from the operated block A Anoa Gas Export facility has reached recordlevels, with average gross gas production of 140.3 mmscfd. In the fourthquarter, offtake by the gas buyer SembGas reached such high levels that at timesgas was supplied above the contract maximum rate. Oil production from Anoa averaged 3,079 boepd gross, down on the prior year asthe oil reservoir continues to deplete. Overall, net production from Indonesiaamounted to 12,500 boepd, up 8% from the prior year on a comparable basis,excluding production attributable to the share of block A sold as part of therestructuring which completed in 2003. During the year, three work-over wells were drilled and successfullyre-completed as gas producers which have since been brought on-line. Thesewells have under-pinned our deliverability capability. In addition engineeringwork has commenced on the West Lobe Wellhead Platform, which is planned toaccess gas reserves in the West Lobe area of the Anoa field. Front-endengineering and design was completed and followed by the award of anengineering, procurement, construction and installation contract. Developmentdrilling is scheduled for 2006 with production from the new facility now plannedto commence later in that year. Our focus on maintaining world class health, safety and environmentalperformance continues, and in June 2004 a further milestone was reached withthree years of continuous operation of the Anoa facilities without a lost timeincident. Discussions with SembGas on a further gas sales contract continued in 2004 asgas demand and supply has increased above existing contractual maximum rates. Wecurrently believe that Singapore will continue to take gas at these higher ratesunder the existing contract into the medium term. On this basis we havecommenced discussions with Malaysia, and are looking at the domestic market inIndonesia, to develop further opportunities for long term gas sales. The Gajah Baru-2 appraisal well was successfully completed in October 2004. TheGajah Baru field is located 25km from Anoa. The well encountered the targetMiocene reservoirs in the Arang formation, following the identification of athick sand channel using state of the art seismic processing techniques.Subsequent to this well, the reserves were independently certified at anincreased 372 billion standard cubic feet of gas, equivalent to 67 mmboe. Thesereserves, being the lowest cost developable gas in the area, will either formpart of deliveries under the existing sales contracts or be developed to fulfilfuture gas sales contracts, when agreed. Premier's drilling operation established a new world record depth interval forthe 'drilling with casing' technique when13-3/8 inch casing was drilledfrom the seabed to a depth of 2214 feet below the rig floor, thereby makingsignificant cost savings on drilling. In 2005, it is intended to drill theMacan Tutul exploration prospect of block A, and a second well on the block isunder discussion with joint venture partners. Elsewhere in the region, in May 2004 Premier announced the acquisition of twolarge tracts of acreage offshore Vietnam, in the South Nam Con Son basin, closeto the maritime border with Indonesia. The first, blocks 12E & 12W, gave Premier an equity share of 75% andoperatorship of two blocks which already have the Dua oil and gas discovery anda number of undrilled prospects. The geology of the blocks is very similar tothat of the Indonesian block A area. Premier acquired an extensive 1500km 2Dseismic programme on the block during 2004 to develop candidates for 2005drilling. Premier is currently acquiring 3D seismic over the Dua field in 2005in advance of field appraisal drilling. The second tract acquired was an interest in adjacent block 7 & 8/97 in the oilprone area south east of the Dua discovery. Unlike exploration areas furthersouth, this area has not been explored for some three decades owing to a borderdelineation negotiation with Indonesia. Following a recent 2D seismic survey weare in the process of identifying prospects for future drilling. In January 2004, Premier signed a service contract (SC43) covering the RagayGulf and adjacent land areas in the Philippines. A work programme of geologicalstudies has identified a prospective trend of pinnacle carbonate reefs close tothe shoreline and onshore hydrocarbon seeps in the western part of the acreage.Premier is currently preparing to acquire transition zone seismic data in 2005to delineate structures better. The area is considered very under-explored,frontier acreage. It has been accessed at very low commitment cost and has theplaymaking potential for a material number of moderate, but economic, oilprospects as drilling candidates. Africa Premier's interests in Africa are concentrated offshore West Africa -Mauritania, Guinea Bissau and Gabon, with a position acquired in 2004 onshoreEgypt. During the year, development of the Chinguetti oil field in Mauritania, wascommenced. The Woodside led joint venture sanctioned the field development inPSC Area B, some 90 km west of the Mauritanian capital Nouakchott, in May,following Government of Mauritania approval. Currently the project is just over 50% complete and on schedule to meet plannedfirst oil at the end of the first quarter 2006, although an earlier start dateis possible. The field has proven and probable reserves estimated at around 120million barrels of oil and the initial gross production rate is expected to beabout 75,000 barrels of oil per day (6,100 bopd net Premier). Followinggovernment back-in our equity interest is 8.12%. The capital cost of theproject is currently estimated to be approximately US$630 million (US$51millionnet to Premier). Initial field development includes 6 sub-sea production wells and 5 waterinjection wells for pressure support with flow-lines to a permanently mooredFPSO, Berge Helene, in 800m water depth with storage capacity of 1.6 millionbarrels. Surplus gas not required for the field will be re-injected into anearby reservoir via a single gas injection well. Drilling began on schedule inSeptember 2004. Exploration and appraisal drilling in Mauritania commenced in the second half ofthe year with three exploration wells - Tevet, Capitaine and Merou, and threeappraisal wells - Tiof 3, 4 and 5. The West Navigator and Stena Tay drillingrigs are engaged on a combination of exploration, appraisal and Chinguettidevelopment wells in an intensive drilling programme which continues through2005. The first exploration well, Tevet-1, was a success, discovering oil in astructure close to, and in shallower water than, the Chinguetti field. Thepotential of a valuable early tie-back to Chinguetti is under evaluation, and itis likely that the discovery will be appraised in 2005. Following Tevet-1, the Capitaine and Merou wells were drilled in a deepwatersetting of 1500-1700m, further west. The first, Capitaine-1, was drilled at alocation where the thick sand-filled channel that deposited the Chinguetti fieldsands has run onto a deeper water salt dome structure. This well encounteredthick target reservoir sands but was water wet. This is now considered to bedue to the lack of hydrocarbon charge at this location. The second well, Merou-1, was drilled on another deepwater salt dome feature,this time down-dip of the Tiof field. Merou-1 failed to find thick reservoirsands at the selected well location. This structure may still have furtherpotential at a different location and is being evaluated as a candidate for apossible future follow-up well. All of the exploration and appraisal wells have given us valuable informationboth on reservoir distribution and on the hydrocarbon source for this acreage.This is being integrated with new seismic data and information from a newelectromagnetic technology survey acquired in the area, to develop a number oftargets for future drilling. Candidates are currently being evaluated and areturn to exploration drilling is planned for later in 2005. The appraisal wells at Tiof have provided significant control on thedistribution of oil and gas within the Tiof channel area. By the end of 2003,we had encountered three reservoir units in Tiof, revealed on 3D seismic by thevariations in reflector amplitude response encountered in Tiof-1 and Tiof West.Tiof-4 proved the presence of oil bearing sands in the low-amplitude areas ofthe field and also the occurrence of a fourth reservoir zone beneath these.This has allowed the operator Woodside to estimate gross recoverable resourcesof some 287 million barrels of oil (corresponding to approximately 1 billionbarrels of oil in place). More recently, the Tiof-6 well was also a success with production testingcompleted in February 2005, and was suspended as a potential future oilproduction well after flowing at a stable rate of approximately 9,150 barrelsper day. Further appraisal work is expected in 2005 prior to considering adecision to sanction a development project later in the year. In Guinea Bissau, Premier commenced drilling the offshore Sinapa salt diapirprospect in February 2004. The significance of this well is that it proves thehydrocarbon play in the basin, reducing the risk of prospects identified in thisarea by showing that they can be charged and can trap oil. The wellsuccessfully penetrated the target reservoir and found oil on the flank of thediapir. A thicker and even more mature than expected source rock interval wasfound overlying oil bearing sandstone. Uniquely for this area, a 300m thickAlbian reservoir interval that was encountered comprising an upper, lowpermeability oil bearing sandstone from which oil samples were recovered, abovea good quality water wet sandstone. Future studies are planned to determine ifoil can be recovered commercially from the upper unit, utilising modernreservoir stimulation and extended reach drilling techniques. The 2005 programme is focussed on testing the remaining potential on the block.Geological studies undertaken in 2004 indicate that reservoir quality shouldimprove in the south where we are undertaking 3D seismic acquisition over theEirozes prospect on the Esperanca block. This will be followed by one or moreexploration wells later in 2005. In Gabon, Premier announced entry into the Iris Marin and Themis Marin PSCs.These blocks cover two shallow water exploration concessions offshore Gabon of902km(2) and 607km(2) respectively. Both the Themis Marin and Iris Marinconcessions are surrounded by proven oilfields and are close to pipelines andproduction infrastructure. Since these concessions were awarded in 1999, a 3Dseismic survey has been acquired over the southern part of the Themis block, andfrom these results a number of drilling locations have been identified. Thedrilling of the first of two wells is being considered for summer 2005.Elsewhere in Gabon the Dussafu prospect was drilled in the year by operatorSasol, and was plugged and abandoned. Opportunities in North Africa have been under review, and in May 2004 Premierfarmed in to the Egypt North West Gemsa block which is on the onshore westernside of the prolific Gulf of Suez oil basin. The Al-Amir-1 well was spudded inDecember 2004 following the acquisition of 3D seismic data earlier in the year.The well is currently in progress. Consolidated profit and loss account Ongoing Total Operations Total 2004 2003 2003 $ million $ million $ million TurnoverGroup and share of joint ventures 251.8 270.4 420.0Less: share of joint ventures' turnover (55.8) (41.4) (121.4) Group turnover 196.0 229.0 298.6Cost of sales (108.4) (121.1) (141.8)Exploration expenditure written off (14.3) (19.9) (19.9) Gross profit 73.3 88.0 136.9Administrative costs (15.5) (19.1) (19.1) Group operating profit 57.8 68.9 117.8Share of joint ventures' operating profit 35.2 25.6 80.4 Total operating profit: Group and share of joint 93.0 94.5 198.2ventures Profit on disposal of investment 2.3Exceptional make-whole payment* (37.5)Net interest payable: Group (2.7) (20.0) (20.0) Joint ventures (0.1) (9.5) Exchange losses (3.0) (1.3) (1.3) Profit on ordinary activities before tax 87.2 73.2 132.2Tax: Group** (31.9) (36.5) (45.2) Joint ventures (11.5) (8.8) (20.5) Profit after tax 43.8 27.9 66.5 Earnings per share (cent): basic 53.0 48.9 diluted 52.1 48.1 * The payment was made to the holders of the long-term loan notes of the groupunder the terms of agreement which stipulated a 'make-whole' to be paid if suchloan notes were to become repayable before maturity. The earlier repayment wasrequired due to the Restructuring of the group in 2003. ** The group tax includes overseas tax charge of $24.6 million (2003: $22.0million) Consolidated statement of total recognised gains and losses 2004 2003 $ million $ million Net profit for the year excluding share of profits of joint ventures 20.2 16.1Share of joint ventures' profits for the year 23.6 50.4 Net profit for the year attributable to members of the parent company 43.8 66.5 Exchange difference on retranslation of net assets of subsidiaryundertakings (0.4) 5.0 Total recognised gains 43.4 71.5 Group reconciliation of movements in shareholders' funds 2004 2003 $ million $ millionTotal recognised gains relating to the year 43.4 71.5Restructuring adjustment (1.2) (98.9)New shares issued 5.2 4.4Shares repurchased (5.9) Total movements during the year 41.5 (23.0)Shareholders' funds at 1 January 388.8 411.8 Shareholders' funds at 31 December 430.3 388.8 Results relating to joint ventures are those of Premier-Kufpec Pakistan BV and Global Resources Ltd. Balance sheet Group Group 2004 2003 $ million $ millionFixed assetsIntangible assets 72.0 35.8Tangible assets 403.3 368.2Investments 1.1 11.5Investments in joint ventures: Share of gross assets 142.0 141.9 Share of gross liabilities (49.1) (40.3) Total fixed assets 569.3 517.1 Current assetsStocks 10.8 10.9Debtors 103.5 112.9Cash and short-term deposits 56.8 109.0 Total current assets 171.1 232.8Creditors: amount falling due within one year (142.3) (141.7) Net current assets 28.8 91.1 Total assets less current liabilities 598.1 608.2Creditors: amounts falling due after one year (38.8) (99.5)Provisions for liabilities and charges (129.0) (119.9) Net assets 430.3 388.8 Capital and reservesShare capital 74.6 73.0Share premium account 7.0 3.4Profit and loss account 348.7 312.4 Total equity shareholders' funds 430.3 388.8 Approved by the Board on 23 March 2005. Consolidated cash flow statement 2004 2003 $ million $ millionNet cash inflow from operating activities 124.4 224.9Returns on investment and servicing of financeInterest received 2.1 5.4Interest paid (2.3) (34.2)Exceptional make-whole payment (37.5)Loan issue costs (1.6) (0.2) (67.9)TaxationUK corporation tax paid (5.3) (8.2)UK petroleum revenue tax paid (23.8) (21.8)Overseas taxes paid (24.6) (13.4) (53.7) (43.4)Capital expenditure and financial investmentsPayments to acquire fixed assets (95.6) (52.6)Receipts from sale of fixed assets 8.2Sale of listed investment 21.5Inflow of funds from joint venture - net 32.2 3.3 (63.4) (19.6)Acquisitions and disposalsRestructuring proceeds 251.5Investment of funds in the disposed joint venture (10.9)Transfer of cash with disposed entities (16.3)Restructuring costs (21.7)Investment in associated undertakings (10.4) - 192.2 Cash inflow before management of liquid resources and financing 7.1 286.2 Management of liquid resourcesNet change in short-term deposits 50.7 112.6 50.7 112.6 FinancingIssue of Ordinary Share capital 5.2 10.3 Repurchase of shares (3.3) Repayment of loans (61.2) (681.2) New loans 251.2 Net cash from financing (59.3) (419.7) Decrease in cash (1.5) (20.9) Notes to the accounts 1 Geographical analysis Turnover represents amounts invoiced exclusive of sales related taxes for thegroup's share of oil and gas sales. 2004 2003 $ million $ millionGroup turnover by origin and destination UK 95.6 133.0Indonesia - destination Singapore 100.4 165.6 196.0 298.6Joint venture turnover by origin and destinationPakistan 55.8 41.4 Myanmar - destination Thailand (discontinued operations) 80.0 Total group turnover including share of joint ventures 251.8 420.0 Group operating profit/(loss) before exceptional items North West Europe 11.7 34.4 Far East 60.9 103.0South Asia (0.8)West Africa (4.6) (7.3) Other overseas (9.4) (12.3) Group operating profit 57.8 117.8 Share of operating profit in joint ventures - Pakistan 35.2 25.6 - Myanmar (discontinued operations) 54.8 Profit on disposal of investment 2.3Net interest (2.8) (29.5)Exceptional make-whole payment (37.5)Exchange losses (3.0) (1.3) Profit on ordinary activities before tax 87.2 132.2 Net assets 65.8 76.5North West Europe Far East 150.0 156.3South Asia 17.4 10.2West Africa 84.8 39.0Other overseas 2.6 (2.6)Related Shares:
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