23rd Mar 2006 07:03
Premier Oil PLC23 March 2006 Premier Oil Preliminary Results for the year ended 31 December 2005 Premier is a leading FTSE 250 independent exploration and production companywith gas and oil interests principally in the North Sea, Asia and West Africa.Our strategy is to add significant value per share through exploration andappraisal success, astute commercial deals and asset management. Highlights Operational • Production ahead of budget - 33,300 boepd (2004: 34,700 boepd) • Record gas sales from projects in Indonesia and Pakistan • Exploration and appraisal success in Mauritania and Egypt • Reserves and contingent resources 10 per cent higher at 232 mmboe • Strong 2P reserve base - 164 mmboe (2004: 176 mmboe) • New acreage acquired in Norway, Congo and SADR Financial • Profit after tax and EPS up 75 per cent to US$38.6 million, 47.0 cents per share • Healthy operating cash flow amounting to US$118.9 million (2004: US$109.6 million) • Operating costs stable under US$6 per boe • Strong balance sheet and improved credit facility • Low-cost, long-term hedging in place 2006 Outlook • Announcement of Lembu Peteng discovery today giving Premier two exploration successes this year to date • Up to 17 exploration and appraisal wells currently planned, with four high impact wells • Significant programme of development drilling • Development projects on stream in Mauritania and Indonesia Simon Lockett, Chief Executive, commented: "Premier performed strongly in 2005 producing solid financial results andexploration success. This progress has continued into this year with our secondexploration discovery announced today. "Our refocused strategy is on track to deliver in 2006 with a rising productionprofile and a high impact exploration programme. We also have the financialstrength to continue to build our core-areas as opportunities arise." 23 March 2006 ENQUIRIESPremier Oil plc Tel: 020 7730 1111Simon LockettTony Durrant Pelham PRJames Henderson Tel: 020 7743 6673Gavin Davis Tel: 020 7743 6677 CHAIRMAN'S STATEMENT Premier's results for 2005 reflect the high quality of our producing fields andour strong financial position. We have an excellent base from which to meet ourstrategic growth objectives. Financial and operating performance The financial statements for 2005 have been prepared under InternationalFinancial Reporting Standards (IFRS), including the adoption of the successfulefforts method of accounting for oil and gas assets. Strong oil and gas prices, especially in the second half of the year led tosignificantly increased turnover of US$359.4 million in 2005 (2004: US$251.8million). Increased gas demand in Pakistan and Indonesia led to increasedproduction balanced by natural decline in the UK. Production is set to grow in2006 with first oil achieved in Mauritania. Profits after tax for the year were US$38.6 million (2004: US$22.1 million),reflecting increased oil prices and gas realisations, offset by higher taxes.Operating cash flow after taxes and interest was US$118.9 million (2004:US$109.6 million). Net debt at 31 December 2005 was US$26.2 million (2004: Net cash US$19.6million) before taking into account cash received in January 2006 of US$35.2million from a crude oil cargo lifted on Wytch Farm in late December. Wecontinue to fund our planned exploration and development activities fromoperational cash flow, and retain our strong balance sheet flexibility foracquisitions. Production for the year was ahead of expectations at 33,300 barrel of oilequivalent per day (boepd) (2004: 34,700 boepd). Our producing fields areperforming well and with higher oil prices and strong gas demand we have anexciting programme of incremental projects to exploit further our high qualityreservoirs. The Chinguetti field in Mauritania was successfully brought onstream in February 2006 and is expected to produce 5,700 boepd net to Premier bythe end of 2006. Oil and gas proven and probable booked reserves at year-end amounted to 164million barrels of oil equivalent (mmboe) on a working interest basis (2004: 177mmboe). These reserves have been confirmed by independent review. Totalreserves and contingent resources, which include discoveries not yet bookedpending commercialisation, have increased to an estimated 232 mmboe (2004: 210mmboe). Our exploration and appraisal programme delivered discoveries at Labeidna inMauritania and Al Amir in Egypt. We also successfully appraised the Tiof, Bandaand Tevet discoveries in Mauritania. Work to evaluate development optionsduring 2006 continues on all of these projects. We are also very pleased that despite strong international competition for goodquality acreage, we have been able to add to our licence portfolio in Norway andWest Africa. The Norwegian awards include a 50 per cent interest in the Froyredevelopment project. These new licences will form the basis for a continuingprogramme of exciting exploration and development work. We continue to focus on improving our world class health, safety andenvironmental performance with the organisation beating its targets forimprovement for the sixth year in a row. Shareholder returns During 2005 Premier shares increased in value by 54 per cent. Over the fiveyears to 31 December 2005, Premier's share price has increased by 443 per cent.The company continues to be a top ten performer in the FTSE 250 over the period.This exceptional performance has reinforced our policy to reward shareholdersprincipally through share price growth. A £10 million share buy-back programme was implemented during the course of 2005with an average purchase cost of £5.55 per share against a year-end share priceof £8.14. Further share purchases will be considered in appropriate marketconditions. Board addition I am pleased to announce the appointment of Neil Hawkings to the Board ofPremier as an Executive Director effective 23 March 2006. Neil was appointedGeneral Manager of Operations in May 2005 and since then has been a key memberof Premier's management team. Prior to joining Premier, Neil had over twentyyears international experience with Conoco in a variety of roles and locationsaround the world. Outlook A number of new strategic targets were set out at our interim resultspresentation in September. In particular we announced a medium-term productiontarget of 50,000 boepd and the intention to drill at least four high impactexploration wells per year. 2006 promises to be an exciting year for Premier as we pursue these targets.The drilling campaign has commenced with a gas discovery on the Macan Tutulprospect and an oil and gas discovery on the Lembu Peteng prospect in Indonesiaannounced today. Exploration wells are planned in Vietnam and Guinea Bissaueach with the potential to add significantly to reserves and shareholder value.New acreage in Norway, Congo, and the Saharawi Arab Democratic Republic (SADR)has significantly added to Premier's portfolio of exploration opportunities forfuture exploration drilling. At the same time, Premier continues to build its production portfolio towardsits target of 50,000 boepd. In Indonesia, the West Lobe extension project onthe Anoa field is within budget and on schedule, with first gas targeted for thethird quarter of 2006. In Pakistan and Indonesia gas sales negotiations areprogressing well. Additionally, new oil developments are planned including theredevelopment of the Froy field in Norway. Premier's 2005 results reflect strong progress on all fronts. Our strategy ofgrowing the production base and focusing on high impact exploration, backed by asolid financial position will add significant value for shareholders. Sir David John KCMGChairman FINANCIAL REVIEW Economic environment 2005 has seen significant changes in both oil and gas pricing worldwide drivenby strong economic growth in Asia as well as a series of disruptions on thesupply side. The Brent oil price, which began the year at US$39.5 per barrel,averaged US$54.5 per barrel (bbl), reaching a peak of US$67.49 per barrel at theend of August. Gas prices worldwide were also strong. Strong commodity prices with increased industry activity levels have led torising operating costs with higher fuel, material and wage pressures. On theexploration side of the business, rig rates rose with renewed appetite fordrilling activity and a shortage of available rigs. The UK Government took the opportunity of higher oil prices to double thesupplementary corporate tax for the upstream sector from 10 per cent to 20 percent. Other governments, for example in Norway, sought to encourage investmentin future energy supplies by providing greater incentives for explorationactivity. Income statement Premier previously announced its restated financial results for 2004 inaccordance with International Financial Reporting Standards (IFRS). We alsopublished a new set of group accounting policies which included the adoption ofthe successful efforts method of accounting for oil and gas assets which theBoard believes provide a more transparent view of the performance of the group'sproducing assets and exploration activities. Profit after tax for 2005 was US$38.6 million (2004: US$22.1 million) anincrease of 75 per cent. Following the change to the successful efforts methodthis profit takes into account a write off of US$20.6 million for unsuccessfulwells drilled in India (Lakkhi-1), Pakistan (Maliri-1), Gabon (Iboga-1), Egypt(Al-Fagr) and Mauritania (Espadon and Sotto). In addition, we charged US$17.0million of pre-licence exploration expenditure to the income statement. Thecorresponding figures in 2004 under the same successful efforts policy wereUS$28.7 million and US$12.2 million respectively. Production levels in 2005, on a working interest basis, averaged 33,300 boepdcompared to 34,700 boepd in 2004. On an entitlement basis, production was28,700 boepd (2004: 31,500 boepd). Realised oil prices averaged US$48.38/bblcompared with US$29.92/bbl the previous year. Gas prices averaged US$3.82 per thousand standard cubic feet (mscf) (2004:US$3.24 per mscf). The average gas price has risen more slowly than oil pricesdue to the terms of our gas price escalation clauses for our production inPakistan. Gas prices in Indonesia, which are linked to high sulphur fuel oil,have risen broadly in line with the oil price over a two-year period andaveraged a US$7.90 per mscf during the year (2004: US$4.96 per mscf). Sales revenue was 43 per cent higher than 2004 at US$359.4 million (2004:US$251.8 million) as a result of these higher commodity prices and timing ofliftings in the UK. Cost of sales increased to US$176.5 million compared to US$134.6 million in2004. The major change in the cost of sales is attributed to a significantchange in the stock underlift/overlift position, which resulted in a charge tocost of sales of US$25.9 million, (2004: credit of US$16.8 million), to offsetoverlifted volumes included in revenues. After excluding the effect of overlifton cost of sales, underlying unit operating costs amounted to US$5.90 per barrelof oil equivalent (boe) (2004: US$5.80 per boe). This reflected a general risein the cost environment faced by the industry, offset by specific actions takento reduce costs, notably in the Kyle field in the UK. Underlying unitamortisation amounted to US$5.50 per boe compared to US$5.60 in the previousyear. Administrative costs rose by US$2.6 million to US$19.6 million reflectingcertain one-off charges in respect of pensions and provisions for long-termincentive plans. Operating profits were US$125.7 million, a 112 per centincrease from the prior year. Net interest and other finance expenses totalled US$1.1 million (2004:US$5.8million) reflecting the continuing low level of debt and hence strongbalance sheet. Pre-tax profits were 130 per cent higher at US$124.6 million(2004: US$53.5 million). The taxation charge totalled US$86.0 million (2004:US$31.4 million) as a result of higher operating profits, the first full year ofprofit oil and gas in Indonesia and a higher effective tax rate in Pakistanfollowing the full utilisation of previous tax losses. Basic earnings per share amounted to 47.0 cents, an increase of 75 per cent onthe previous year. Cash flow Cash flow from operating activities amounted to US$118.9 million, up fromUS$109.6 million in 2004. These cash flows include payments received from thejoint venture in Pakistan of US$47.1 million (2004: US$35.2 million). Capital expenditure and pre-licence exploration expenditure in the period wasUS$149.6 million (2004: US$104.5 million) relating principally to thedevelopment programme (US$80.5 million). US$21.0 million was utilised for theshare buy back programme and the purchase of shares for the Employee ShareOwnership Plan. Net cash outflow, before movements relating to financing amounted to US$26.7million (2004: cash inflow US$5.1 million). Net debt position At the start of the year, net cash amounted to US$19.6 million. At year-endthis had become a net debt position of US$26.2 million comprising US$38.8million of cash balances and short-term investments and a drawdown from bankcredit facilities of US$65.0 million. On 24 December Premier lifted a crudecargo of 630,000 barrels from the Wytch Farm field the cash proceeds from which(amounting to US$35.2 million) were received in January, allowing us to repaysome US$20.0 million of our bank debt. In September the company entered into a new US$275 million credit facility, onimproved terms, with a syndicate of thirteen international lending banks led byBarclays Bank plc and Royal Bank of Scotland plc. Together with positive cashflow from producing assets this facility puts the company in a strong positionto fund its ongoing exploration and development programme and to financeacquisitions. Hedging and risk management A review of hedging policy was undertaken during the year given the significantvolatility in current commodity prices. Following the expiry of previous hedgesat 30 June 2005 no hedges were in place for the second half of 2005. The Board's policy is to consider hedging where it is attractive economically tolock-in oil and gas prices at a level which protects the cash flow of thecompany and the business plan. All transactions are related directly toexpected cash flows; no speculative transactions are undertaken. Hedges utilising collars were entered into for the period 1 January 2006 to 31December 2010 covering 9 million barrels of oil (mmbbls) representingapproximately 50 per cent of anticipated liquids production for the period. Thefloor price, which averaged US$37.42 per barrel, was funded by a cash payment ofUS$3.6 million yielding a ceiling price of US$100 per barrel. In addition,384,000 metric tonnes of High Sulphur Fuel Oil (HSFO), representing theequivalent of around 33 per cent of Indonesian gas production for the period 1January 2006 to 31 December 2009 have been covered on a zero cost basis at anHSFO floor price of US$200 per metric tonne and a ceiling price of US$480 permetric tonne. Historic hedges produced a loss of US$15.7 million during the first half of 2005expiring on 30 June. This amount has been deducted from sales revenue for theyear. The adoption of IFRS, with effect from 1 January 2005, requires thathedges put in place during the second half of the year should be valued and anychanges in market value should be reflected in the income statement. The netgains or losses on such hedges, after taking into account the premium paid, isrecorded as a US$2.0 million charge in other finance expenses. Since the group now reports in US dollars, exchange rate exposures relate onlyto sterling receipts and expenditures which are hedged in dollar terms on ashort-term basis. The group recorded a gain of US$0.1 million on such hedgingat year-end. Cash balances are invested in short-term bank deposits, managed liquidity fundsand commercial paper, subject to Board approved limits. The group undertakes aninsurance programme to reduce the potential impact of the physical risksassociated with the exploration and production activities. In addition,business interruption cover is purchased for a proportion of the cash flow fromproducing fields. Adoption of International Financial Reporting Standards (IFRS) As announced on 25 August 2005, Premier is reporting its financial results inaccordance with IFRS with effect from 1 January 2005. Comparative numbers for2004 were restated at that time in accordance with the group's new accountingpolicies. Details of the new accounting policies and the restatement of theprior year accounts are available on Premier's website (www.premier-oil.com). OPERATIONAL REVIEW The strategy of the company combines the delivery of new production projects andasset management with a focus on high impact exploration. In the medium term,these will provide material growth in our reserves base and a target productionlevel of 50,000 boepd. Each of the four regional businesses (North Sea, Asia,Middle East-Pakistan and West Africa) will contribute to these growthobjectives. Production and reserves Working interest production for 2005 averaged 33,300 boepd. Comparableproduction from 2004 was 34,700 boepd. Production comprised 31 per cent liquidsand 69 per cent gas, with Pakistan and Indonesia each accounting for around 35per cent of the total and the UK the remainder. On an entitlement basis, groupproduction for the year was 28,700 boepd. Following the start-up of productionin Mauritania in February 2006, group production for the first two weeks ofMarch averaged 36,400 boepd (working interest basis). Production Working Interest Entitlement (boepd) 2005 2004 2005 2004 North Sea 9,750 11,900 9,750 11,900 Pakistan 11,500 10,300 11,500 10,300 Asia 12,050 12,500 7,450 9,300 Total 33,300 34,700 28,700 31,500 Proven and probable reserves, on a working interest basis, based on Premier andoperator estimates are now 164 mmboe. Reserves and Reserves Contingent Resources (mmboe) (mmboe)Start of 2005 176 210Production (12) (12)Net revisions 0 34End of 2005 164 232 At year-end, reserves comprised 19 per cent liquids and 81 per cent gas, and theequivalent volume on an entitlement basis amounted to 146 mmboe (2004: 157mmboe). Reserve revisions represent increases in various fields (particularly Kadanwariin Pakistan) offset by a decrease in the Kakap field in Indonesia. Netrevisions also reflect the completion of the sale of our interest in the Galahadand Mordred fields in the UK. Discoveries made in the year in West Africa and Egypt have not been recorded inbooked reserves pending completion of ongoing appraisal and commercialisationwork. Unbooked reserves in the process of being commercialised (includingunsold gas in Indonesia together with discoveries that have not yet receiveddevelopment sanction elsewhere) give increased total reserves and contingentresources of 232 mmboe (2004: 210 mmboe). This figure does not include thepotentially large resources associated with the Banda (Mauritania) or Swan(Vietnam) gas fields where commercialisation is at an early stage. Exploration and appraisal A core part of Premier's business growth strategy is the exploration programme.Each year at least four high-impact wells are targeted from a portfolio ofprospects around the world. Success on any of these prospects is capable ofbringing significant and rapid growth. The portfolio of exploration propertiesalso has the potential to add incremental value to existing production, to openup new plays and to provide large prospects for the future. The annual targetspend for this programme is US$50 million. The cost of the current plannedprogramme for 2006 is in excess of this target and a number of good qualityfarm-in proposals have been received. These are actively under consideration aspart of Premier's portfolio management. Over the last five years, Premier has had a 50 per cent success rate on itsexploration and appraisal wells, and a 30 per cent success rate on explorationwells alone. 13 exploration and appraisal wells were drilled in 2005, similarto 2004 and 2003. The 2005 programme provided five successes, on Al Amir-1 inEgypt, and the Labeidna-1, Tevet Deep-2, Tiof-6 and Banda-2 wells in Mauritania. For 2006, final plans are in place for all the key wells in the programme of upto 17 exploration and appraisal targets. Exploration wells currently planned inWest Africa include two high impact shallow water wells in Guinea Bissau,testing Premier's high-potential acreage; up to three further wells inMauritania exploring the acreage around Chinguetti and Tiof fields; and oneplay-testing well in Gabon. In Pakistan the high potential Indus Delta offshorewill be tested and in Indonesia very low cost wells adding incremental value toexisting production will be drilled. In the second quarter there will be twohigh impact wells in Vietnam. NORTH SEA In the North Sea, Premier will build on its new position in Norway by seekingout high impact exploration while maximising the value from its existing UKproducing assets. UK Production in the UK in 2005 amounted to 9,750 boepd (2004: 11,900 boepd)representing 29 per cent of the group total (34 per cent in 2004). Thisrepresents a decrease of some 18 per cent on last year's level due to acombination of natural decline and configuration changes which impact productionrates but lead to considerable savings on operating costs. The Wytch Farm oil field contributed 4,000 boepd net production to Premier, down16 per cent on last year. This year, the successful infill drilling campaignhas focused on the offshore area under Poole Bay drilling four wells, comparedto the two wells drilled in 2004, and has continued to successfully limitproduction decline. A further three new infill wells are planned to be drilledin 2006 and an enhanced oil recovery project is expected to be brought tosanction. Net production from Kyle was 3,600 boepd, down 14 per cent on last yearfollowing a change to the oil offtake configuration. This was a result ofnegotiation with Banff and Curlew infrastructure owners in 2004 whereby the Kyleowners agreed to tie-back remaining Kyle Chalk wells to the Banff FloatingProduction Storage and Offtake vessel (FPSO) and to cease utilisation of theMaersk Curlew FPSO. The work was completed in the third quarter of 2005, ontime and on budget. An all-inclusive processing and transportation tariff hasbeen agreed with the Banff Group which will substantially reduce operating costsand allow the extension of field life up to the end of 2015. Gross field ratesare currently around 4,000 barrels of oil per day (bopd) and 8 million standardcubic feet of gas per day (mmscfd). Gas lift for the wells and a water shut-offand re-perforation of Kyle-15 well are budgeted for in 2006, with further plansfor compression upgrade at Banff, and infill drilling under consideration. In the Fife area, Premier's net production amounted to 1,600 bopd from the Fife,Fergus, Flora and Angus fields with natural decline successfully managed byoptimisation of existing water injection and gas lift facilities. The Fife FPSOcontract was amended in 2005 to further incentivise oil production which willlead to improved vessel uptime and increased production. Scott, Telford andGalahad, which was disposed of as a non-core asset, accounted for the remainderof net production. Detailed evaluations of the UK blocks awarded in December 2004 are now under wayto identify prospects for drilling during 2007/8. 3D seismic purchase andreprocessing was conducted across blocks 23/22b (P1181) and 21/7b (P1177) in theCentral North Sea and 44/21c, 44/26b (P1184) in the Southern North Sea. Seismicreprocessing of 2D seismic data has also been conducted over blocks 42/10, 42/15(P1229) in the Southern North Sea. This licence contains the Agincourt gasaccumulations and studies of this acreage were also conducted during 2005 toexamine the technical and commercial case for development. Elsewhere in theSouthern North Sea, 2D seismic reprocessing and 3D data purchase was conductedover 43/22b, 43/23, 43/27b, 43/28 & 43/29 (P1235) and a detailed evaluation ofthe gas prospects is currently under way. Licence P1048 in the Central North Sea was re-evaluated following completion ofthe 20/10b-5 (Criollo) well during 2004. The 21/6a-7 well targeting thePalomino prospect was spudded on 23 December (and has subsequently been pluggedand abandoned dry on 20 January 2006). Premier did not contribute to the costof this well, which had been farmed out to Oilexco in a deal that resulted inPremier's equity being reduced to 18.75 per cent. Re-interpretation of the4-block P1048 licence is now under way to fully evaluate remaining prospects andleads. Premier agreed to assume a 100 per cent stake in the Fife area blocks 39/1c & 39/2c with the aim of drilling the 39/2c-Peveril prospect in late 2006. This areahas good potential for oil within the Upper Jurassic Fife (Fulmar) sands and isclose to the existing Fife area facilities. Follow-on potential is provided byblocks 39/1b & 39/7 (P1152) blocks where prospects have also been identified asa result of 3D seismic reprocessing completed during 2005. Norway Premier was awarded five licences in the APA licensing round in December 2005,the company's first move into the Norwegian sector. The licence interestsobtained to date, all of which are in the central area of the Norwegian NorthSea, are as follows: Block no. (or part block no.) Working Interest Operator34/2, 34/5 15% BG34/4, 34/5 30% PetroCanada35/12, 36/10 40% Revus16/1, 16/4 30% Lundin25/2, 3, 5 & 6 (Froy area) 50% Pertra These licences offer a spectrum of redevelopment, appraisal and explorationopportunities which have the potential to meet objectives for both earlyproduction and high impact exploration. A number of seismic programmes areanticipated during 2006 aimed at confirming a subsequent significant drillingprogramme. Our quadrant 25 licence includes the Froy field. This field was abandoned in2001 by the previous operator in a much lower oil price environment and due tothe imminent abandonment of the Frigg field to which it was tied back. The Froyarea is now the subject of redevelopment studies with plans to seek developmentapproval in the first quarter of 2007. Premier has also submitted a further application in the 19th Round, the resultsof which are expected to be announced by the end of the first quarter of 2006. MIDDLE EAST-PAKISTAN Premier continues to build the value of its strong asset portfolio in Pakistan.Business development efforts in the Middle East region are focused on producingasset opportunities in partnership with government and local companies. Pakistan Record production levels achieved in 2004 were surpassed in 2005. Productionnet to Premier amounted to 11,480 boepd, an increase of 11.3 per cent over 2004(2004:10,312 boepd). The increase in production was mainly due to higher sales from the Qadirpur gasfield which amounted to 3,807 boepd (2004: 3,055 boepd). The sustained highergas sales from Qadirpur were possible due to the enhancement of plant capacityto 500 mmscfd achieved in 2004. Negotiations are now under way with the plantcontractor to increase plant capacity to 600 mmscfd and with the gas buyer toincrease sales volumes to 550 mmscfd. Two further development wells and,following the 3D seismic programme conducted in 2005, a Qadirpur deep well isplanned for 2006. On Premier's Kadanwari acreage, the K-14 well was tied back to the existing gasproduction facilities. This additional production compensated for the naturaldecline of the field and successfully increased the production level to 1,228boepd (2004: 1,039 boepd). To further exploit the reserves in the KadanwariWest, K-15 is to be drilled in the first quarter of 2006. Evaluation of 3Dseismic shows further reservoir prospectivity within the acreage. A drillingprogramme is being firmed up to test these prospects. The Zamzama gas field produced an average of 3,658 boepd, net to Premier, during2005 (2004: 3,472 boepd). Negotiations on the Gas Sales Agreement (GSA) forZamzama Phase-2 development and the sale of an additional 150 mmscfd highcalorific value gas, were successfully concluded. Subsequent to the approval ofthe Oil and Gas Regulatory Authority, the GSA was signed by the gas buyer SuiSouthern Gas Company Limited (SSGCL), the President of Pakistan and the jointventure partners. First gas is expected in the third quarter of 2007. The production levels in the Bhit gas field were sustained during 2005 andproduction of 2,788 boepd was achieved during the year (2004: 2,746 boepd). ABhit Phase II Term Sheet to increase the Bhit Annual Contract Quantity (ACQ)from 270 mmscfd to 300 mmscfd has been initialled by the gas buyer SSGCL andjoint venture partners. A supplemental GSA is being negotiated with the buyer.The Bhit plant capacity will be increased to 315 mmscfd to allow acceleratedproduction from Bhit field and production of Badhra reserves with expected gasproduction in the third or fourth quarter of 2007. During the year, Premier was awarded the Jhangara exploration block and drilledthe Maliri-1 well. This prospect was adjacent to Premier's interests in theBhit and Badhra gas fields, and though high-risk, could have providedsignificant incremental value to these projects. However the well was found tobe dry at the target Pab Sandstone level, and subsequently plugged andabandoned. Premier has subsequently withdrawn from this exploration block. Plans to drill the offshore Indus E block progressed, and despite the tight rigmarket, a drilling-unit has been contracted to drill this deep-water well in thethird quarter of 2006. Premier currently holds a 12.5 per cent interest in thisblock. Egypt Premier's first well in Egypt, the Al Amir-1 well, was an encouraging oildiscovery. The well, in which Premier holds a 37.5 per cent interest, flowed upto 750 bopd production test from a new reservoir play-system. The full size ofthis discovery is not yet known and this is to be the target of an appraisalwell will be spudded shortly. A second wildcat exploration well, Al Fagr-1, wasdrilled to the west of the concession in 2005 and found to have hydrocarbonshows. It was plugged and abandoned in early 2006. ASIA In Asia, Premier continues to grow its business using technical and commercialexpertise from its operations in the Natuna Sea to deliver new explorationopportunities and production projects across the region. Indonesia Premier's core asset in Indonesia is its interest in the West Natuna gasproject, supplying gas under a long-term sales contract to Singapore. This isheld through its equity interests in the Natuna Sea block A and Kakap productionsharing contracts. In 2005, Premier-operated block A sold an overall average of 142 billion Britishthermal units per day (Bbtud) gross from its gas export facility. This highfigure reflects increased demand in Singapore frequently exceeding the gascontract maximum rate of 145 BBtud. There was a further 57 BBtud (gross)average sold from the non-operated Kakap field under the same contract. Oil production from Anoa averaged 3,023 bopd gross (2004: 3,079 bopd), onlyslightly down on the prior year as a result of natural depletion of the oilreservoirs. Oil production from Kakap averaged 7,263 bopd gross (2004: 8,533bopd). Overall, net production from Indonesia amounted to 12,032 boepd, down 4 per centfrom the prior year, with Anoa and Kakap contributing 8,593 boepd and 3,439boepd respectively. World class health, safety and environmental performance remains a keyobjective, and there were no lost time incidents in Indonesia throughout theyear. We also achieved the ISO 14001 certification and Indonesia's "PROPER Blue" rating for environmental performance. The West Lobe Wellhead Platform progressed on schedule. Fabrication of thejacket and deck commenced mid-year and by the end of 2005 the jacket assemblywas nearing completion and the deck structure and equipment installation wasessentially complete. The facilities will be loaded out and installed in April2006, and be hooked up and ready for development drilling by the end of May2006. Production is planned to commence in late August 2006. Planning alsocontinued for the 2006 West Lobe drilling campaign with orders being placed forall long lead equipment and another jack-up drilling rig has been secured. Negotiations continued over the sale of further gas from block A withprospective buyers in Malaysia, Indonesia and Singapore. We currently assessSingapore to be the optimal market for additional gas sales volumes withopportunities existing in both the petrochemical and power generation sectors. Technical studies during 2005 focused on maturing prospects for an explorationdrilling campaign in 2006. On 31 January 2006 Premier announced a successfulgas discovery from its Macan Tutul-1 exploration well. The second well LembuPeteng -1, part of the same drilling campaign, has also encountered hydrocarbonsin a number of different zones. These zones are currently being tested. The 2006drilling campaign may include an appraisal well to be drilled on one of thesediscoveries. Vietnam Offshore Vietnam, Premier operates two Production Sharing Contracts (PSC):Blocks 12E and 12W with 75 per cent working interest in each. Subject toGovernment approvals, Premier also has an option to acquire operatorship and upto 67.5 per cent working interest in an adjacent block 7&8/97. During 2005 we acquired and interpreted a 3D seismic survey over the Duadiscovery. The interpretation confirms the potential for commercial oilreserves, and a well is planned for the second quarter of 2006. Followingevaluation of the three 2D seismic programmes acquired over blocks 12E, 12W andblock 7&8/97, Premier will drill a second exploration well targeting theBlackbird prospect on Block 12E. Premier also considers block 7&8/97 to have good prospectivity, but theinternational boundary with Indonesia, which defines the southern extent of theblocks, has not been ratified and therefore operations on this block are onhold. During the third quarter of 2006, Premier will acquire further 2D marineseismic data over blocks 12E and 12W. This will be designed to improve ourunderstanding of the existing Swan gas discovery in block 12W as well asadjacent exploration leads. India In India during 2005, Premier drilled the Lakkhi-1 well in its Jaipur block.The well tested the oil prone acreage beneath the thrusts south east of theAssam oil and gas trend, encountering several oil bearing horizons, includingone that was tested providing a limited flow of gas. However, although thehydrocarbon system proved valid the reservoir quality was poorer thananticipated precluding the production of oil from this acreage. Premier are inthe process of withdrawing from this acreage. In the Cachar block there are a number of large structures which are relativelyunder-explored. Premier has acquired seismic data and better defined the mostpromising prospect known as Masimpur which will be drilled later in 2006. During the year discussions on the Ratna oil field re-development project werere-opened. Most of the issues which have delayed the project in the past havenow been resolved. Under the terms of the draft Production Sharing Contract,Premier is the Operator and has a 10 per cent carried stake in this offshoreproject. After redevelopment it is envisaged that production from the fieldwill be in excess of 20,000 bopd. Philippines Premier operates Service Contract 43 in the Ragay Gulf with a 42.5 per centworking interest. During 2005 Premier acquired 150 line kilometres of TransitionZone seismic data in the shallow waters of the eastern Bondoc Peninsula. Thissurvey has confirmed the presence of carbonate build-ups, and Premier isconsidering a well to target these structures in 2007. WEST AFRICA Premier's objective in West Africa is to deliver a series of high impactexploration opportunities, which offer exposure us to significant reserveadditions, while building the value of the producing asset base in Mauritania. Mauritania The development of the first phase of the 120 million barrel Chinguetti oilfield in Mauritania is now complete at a cost of approximately US$720 million(US$58 million net to Premier). Production commenced on 24 February 2006. TheWoodside-led joint venture sanctioned the field development in June 2004 andbrought the field on stream in less than 21 months. The field is located in 800metres of water, some 90km west of the Mauritanian capital Nouakchott. The Phase 1 development includes six sub-sea production wells and five waterinjection wells for pressure support with flow-lines to a permanently mooredFPSO, Berge Helene, with storage capacity of 1.6 million barrels. Surplus gasnot required for fuel will be re-injected into the nearby Banda reservoir via asingle gas injection well. The drilling of further production and injectionwells (Phase 2) is planned for early 2007. During 2005, three successful appraisal wells were drilled. The Tiof-6 wellintersected a Miocene reservoir sequence which flowed 9,600 bopd on test. Adecision on development strategy is expected in the second quarter of 2006.Tiof-6 was followed by a successful test of the Banda gas discovery, Banda-2.This well was drilled to allow excess-gas injection from the Chinguetti field, apreferred alternative to flaring. This well was successful and proved thepresence of a thick, high quality gas reservoir in Banda. The Tevet structure,located up-channel of the Chinguetti field was also successfully appraised. Thewell successfully found oil in the Miocene sequence, and extended the provenlimits of the Tevet accumulation. Tevet-2 was deepened to the Cretaceous, totest a new play, and encountered an oil column. This is very significant as itis the first Cretaceous oil to be found on this acreage and opens up theCretaceous play system for further exploration. These reserves also may bedeveloped back into the Chinguetti field in due course. Three exploration wells were also drilled during the year. Sotto-1, similar intrap style to the Banda discovery, encountered no sands in the target interval.However, the knowledge gained increase confidence in the presence of sands inprospects such as Colin and Kibaro which lie in a similar geological setting andwill be targeted in 2006. The Espadon well, down dip to the west from the Tioffield, failed to find oil due to lack of sandstone reservoir at that location.The final well of the sequence was a test of the Labeidna prospect, locatedclose to Chinguetti. An oil bearing sandstone was encountered, and is beingevaluated for possible development and tie-back to Chinguetti in the future. The Chinguetti field operator Woodside Petroleum has been notified by theMauritanian government that it disputes amendments to the relevant ProductionSharing Contracts (PSC). The Operator on behalf of the joint venture iscurrently exploring ways to resolve these disputes under the procedures set outin the PSC. Guinea Bissau In Guinea Bissau, following on from the earlier drilling campaign, Premier hasacquired a 400km2 3D seismic survey and reprocessed 800km2 of existing 3D overthe Eirozes and Espinafre salt-diapirs. This has greatly improved the abilityto image the steeply dipping flanks of these large prospects. The 500m oilcolumn in the models are working ahead of expectations around these features.In 2006, Premier will operate wells back-to-back on the Eirozes and Espinafreprospects. Timing of these wells is dependent upon arrival of the rig followingthird party drilling operations, currently expected in late 2006. Success witheither of the two wells would add significant value and increase theprospectivity on a number of look-alike prospects on the block. Gabon In Gabon in 2005, Premier drilled the high-risk Eboga-1 wildcat well on the Irispermit. Premier entered this acreage as part of the 2003 Mauritania acreageacquisition. The well failed and Premier has subsequently withdrawn from thisacreage. In 2006, Premier will drill on the adjacent Themis acreage using 3Dseismic acquired in late 2005 to locate a suitable target. Congo Premier has agreed, subject to parliamentary ratification to take on a 58.5 percent interest (including operatorship) in the Marine IX offshore block in theRepublic of Congo. The block contains the large Frida prospect and a variety oftertiary and cretaceous leads. 2D and 3D seismic programmes are planned for2006. SADR Premier was a successful applicant in the Saharawi Arab Democratic Republic's(SADR) offer of Production Sharing Contracts for four offshore blocks, in whichPremier's interest will be 50 per cent. These contracts were signed in March2006. The licence terms will come into effect on admittance of the SADR tomembership of the United Nations. Consolidated income statement 2005 2004 Note $ million $ millionSales revenues 1 359.4 251.8Cost of sales 2 (176.5) (134.6)Exploration expense (20.6) (28.7)Pre licence exploration costs (17.0) (12.2)General and administration costs (19.6) (17.0)Operating profit 125.7 59.3Interest revenue and finance gains 5.9 2.0Finance costs and other finance expenses (7.0) (7.8)Profit before taxation 124.6 53.5 Taxation (86.0) (31.4)Profit after taxation 38.6 22.1Earnings per share (cent) Basic 8 47.0 26.8 Diluted 8 46.6 26.1 The results relate entirely to continuing operations. Statement of recognised income and expenses 2005 2004 $ million $ millionCurrency translation differences (0.4)Pension costs - actuarial losses (2.2)Net losses recognised directly in equity (2.2) (0.4)Profit for period 38.6 22.1 Total recognised income 36.4 21.7 Reconciliation to net assets 2005 2004 $ million $ millionNet assets at 1 January 354.1 337.5Total recognised income 36.4 21.7Adjustments relating to past restructuring 3.1 (1.2)Purchase of shares for ESOP trust (8.5) (3.2)Provision for share based payments 2.9Issue of ordinary shares 1.3 5.2Repurchase of ordinary share capital (13.2) (5.9)Net assets at the year end 376.1 354.1 Consolidated balance sheet 2005 2004 Note $ million $ millionNon current assetsIntangible exploration and evaluation assets 3 67.4 41.4Property, plant and equipment 4 576.6 565.2Investments in associates 1.1 1.1Deferred tax asset 0.8 645.9 607.7Current assets Inventories 13.3 12.3Trade and other receivables 144.7 117.5Cash and cash equivalents 38.8 59.6 196.8 189.4Total assets 842.7 797.1 Current liabilities Trade and other payables (113.7) (108.4)Current tax payable (38.8) (40.1) (152.5) (148.5) Non current liabilitiesLong term debt (63.6) (38.8)Deferred tax liabilities (198.3) (203.6)Long term provisions (41.0) (41.6)Long term employee benefit plans deficits (11.2) (10.5) (314.1) (294.5)Total liabilities (466.6) (443.0) Net assets 376.1 354.1 Equity and reserves Share capital 73.2 74.6Share premium account 8.0 7.0Revenue reserves 293.6 272.9Capital redemption reserve 1.7Translation reserves (0.4) (0.4) 376.1 354.1 The financial statements were approved by the board of directors and authorisedfor issue on 22 March 2006. Consolidated cash flow statement 2005 2004 Note $ million $ millionOperating activitiesProfit before taxation 124.6 53.5Depreciation, depletion and amortisation 68.0 72.2Exploration expense 20.6 28.7Pre licence exploration costs 17.0 12.2(Increase)/decrease in inventories (1.0) 0.4Increase in trade and other receivables (29.3) (10.0)Decrease in trade and other payables 5.4Interest received 1.0 2.2Interest revenue (1.0) (2.0)Interest paid (3.5) (2.5)Finance costs 2.0 2.3Other finance expense 0.1 5.8Net operating charge for long term employee benefit plans less contributions (1.5) 1.5Income taxes paid (86.4) (54.9)Share based payment provision 2.9Loss on sale of fixed asset 0.2Net cash provided by operating activities 118.9 109.6 Investing activities Capital expenditure (132.6) (92.3)Pre licence exploration costs (17.0) (12.2)Disposal of intangible exploration and evaluation assets 4.0Net cash used in investing activities (145.6) (104.5) Financing activities Issue of ordinary shares 1.1 5.2Repurchase of ordinary shares (21.0) (3.3)Repayment of long term financing (61.2)Loan drawdowns 25.0Arrangement fee for the new loan facility (1.4)Net cash from/(used) in financing activities 3.7 (59.3) Currency translation differences relating to cash and cash equivalents 2.2 (0.1)(Decrease)/increase in cash and cash equivalents (20.8) (54.3)Cash and cash equivalents at the beginning of the period 59.6 113.9Cash and cash equivalents at the end of the period 5 38.8 59.6 Notes to the accounts 1 Geographical segments The group's operations are located in the North Sea, Asia, Middle East-Pakistanand West Africa. These geographical segments are the basis on which the groupreports its primary segment information (the only basis on which it can reportsuch information). Revenue represents amounts invoiced exclusive of salesrelated taxes for the group's share of oil and gas sales. 2005 2004 $ million $ millionRevenue North Sea 169.6 95.6Asia 121.5 100.4Middle East-Pakistan 68.3 55.8 Total group sales revenue 359.4 251.8Interest revenue 1.0 2.0Total group revenue 360.4 253.8Results Group operating profit/(loss) North Sea 32.2 0.7Asia 66.2 55.0 Middle East-Pakistan 41.9 31.0West Africa (6.0) (18.0) Other (8.6) (9.4)Group operating profit 125.7 59.3Interest revenue and finance gains 5.9 2.0Finance costs and other finance expenses (7.0) (7.8)Profit before tax 124.6 53.5Tax (86.0) (31.4)Profit after tax 38.6 22.1 Balance sheetSegment assetsNorth Sea 268.9 298.2Asia 350.6 340.1Middle East-Pakistan 95.7 93.6West Africa 123.1 64.1Unallocated 3.3Investment in associatesWest Africa 1.1 1.1Total assets 842.7 797.1 LiabilitiesNorth Sea (154.5) (167.5)Asia (160.3) (154.3)Middle East-Pakistan (30.8) (26.3)West Africa (16.9) (16.0)Unallocated (104.1) (78.9)Total liabilities (466.6) (443.0) Other informationCapital additionsNorth Sea 14.5 36.3Asia 37.9 31.0Middle East-Pakistan 13.3 6.2West Africa 65.8 61.2 131.5 134.7 Depreciation and amortisationNorth Sea 36.5 40.6Asia 22.3 24.8Middle East-Pakistan 9.2 6.8 68.0 72.2 2 Cost of sales 2005 2004 $ million $ millionOperating costs 100.7 56.3Royalties 7.8 6.1Amortisation and depreciation of property, plant and equipment Oil and gas properties 66.6 70.9 Other 1.4 1.3 176.5 134.6 3 Intangible exploration and evaluation (E&E) assets Oil and gas properties North Asia Middle West Total Sea East-Pakistan Africa $ million $ million $ million $ million $ millionCost At 1 January 2004 0.8 4.4 7.1 2.2 14.5 Exchange movements 0.5 0.5Additions during the year 4.9 16.5 6.2 27.5 55.1Exploration expenditure written off (5.5) (3.3) (4.3) (15.6) (28.7)At 31 December 2004 0.2 17.6 9.0 14.6 41.4 Additions during the year 1.6 24.5 8.3 16.6 51.0Disposals (3.4) (1.0) (4.4)Exploration expenditure written off (12.5) (3.1) (5.0) (20.6)At 31 December 2005 1.8 26.2 13.2 26.2 67.4 4 Property, plant and equipment Oil and gas properties _________________________________________ Other Total North Asia Middle East West fixed Sea -Pakistan Africa assets $ million $ million $ million $ million $ million $ millionCostAt 1 January 2004 200.8 289.2 110.3 17.2 617.5Exchange movements 1.1 1.1Additions during the year 28.5 12.7 33.3 2.6 77.1Disposal of fully written down (1.9) (1.9)assetsAt 31 December 2004 229.3 301.9 110.3 33.3 19.0 693.8 Exchange movements (2.0) (2.0)Additions during the year 12.3 13.4 5.0 49.2 0.6 80.5Disposals (1.0) (1.0)Disposal of fully written down (12.2) (12.2)assetsAt 31 December 2005 240.6 315.3 115.3 82.5 5.4 759.1 Amortisation and depreciation At 1 January 2004* 41.3 16.1 57.4Exchange movements 0.9 0.9Charge for the year 39.3 24.8 6.8 1.3 72.2Disposal of fully written down (1.9) (1.9)assetsAt 31 December 2004 39.3 24.8 48.1 - 16.4 128.6 Exchange movements (1.7) (1.7)Charge for the year 35.1 22.3 9.2 1.4 68.0Disposals (0.2) (0.2)Disposal of fully written down (12.2) (12.2)assetsAt 31 December 2005 74.2 47.1 57.3 - 3.9 182.5 Net book value At 31 December 2004 190.0 277.1 62.2 33.3 2.6 565.2 At 31 December 2005 166.4 268.2 58.0 82.5 1.5 576.6 * The group's Indonesian and UK fields were fair valued under IFRS 1 rules on 1January 2004. Therefore there are no opening balances for amortisation. 5 Analysis of changes in net (debt)/cash 2005 2004a) Reconciliation of net cash flow to movement in net (debt)/cash $ million $ millionMovement in cash and cash equivalents (20.8) (54.3)Proceeds from long term loans (25.0)Repayment of long term loans 61.2(Decrease)/increase in net cash in the period (45.8) 6.9Opening net cash 19.6 12.7Closing net (debt)/cash (26.2) 19.6 2005 2004b) Analysis of net (debt)/cash $ million $ millionCash and cash equivalents 38.8 59.6Long term debt (65.0) (40.0)Total net (debt)/cash (26.2) 19.6 The carrying value of long term debt on the balance sheet is stated net ofunamortised debt arrangement fees of US$1.4 million (2004: US$ 1.2 million). Basis of preparation The above financial information does not represent statutory accounts within themeaning of section 240 of the Companies Act 1985. For all periods up to and including the year ended 31 December 2004, Premier Oilplc (Premier) prepared its financial statements in accordance with UK generallyaccepted accounting practice (UK GAAP). From 1 January 2005 Premier is requiredto prepare consolidated financial statements in accordance with InternationalFinancial Reporting Standards (IFRS) as endorsed by the European Commission('EC'). Consequently, financial information for preliminary results for the year ended2005 must be prepared on the basis of IFRS. The general principle that should beapplied on first-time adoption of IFRS is that standards in force at the firstreporting date (for Premier that is 31 December 2005) should be appliedretrospectively. However, IFRS 1 - 'First time Adoption of International Financial ReportingStandards' contains a number of exemptions which companies are permitted toapply. Premier has elected: • not to present comparative information in accordance with IAS 32 - 'Financial Instruments: Disclosure an Presentation' and IAS 39 - 'Financial Instruments: Recognition and Measurement'. • not to restate its financial information for acquisitions, disposal and restructuring occurring before 1 January 2004. • to deem cumulative translation differences to be zero at 1 January 2004. • to recognize all actuarial gains and losses on pensions and other post- retirement benefits directly in shareholders' equity at 1 January 2004. • to apply IFRS 2 'Share-based Payment' on share-based payments from 1 January 2004. As a result of the above exemptions certain changes apply from 1 January 2004followed by further changes (due to IAS 32 and IAS 39) to apply from 1 January2005. Premier has produced an 'IFRS Restatement' document setting out its accountingpolicies under IFRS, the major differences between UK GAAP and IFRS, andreconciliations of UK GAAP to IFRS for its 2004 full year Income and Cash FlowStatements, its Balance Sheets at 1 January 2004 and 31 December 2004. Thisinformation can be found at www.premier-oil.com. These results are preparedunder the accounting policies contained in the IFRS Restatement document. The principal differences for the group between reporting on the basis of UKGAAP and IFRS are as follows: • Accounting for exploration and evaluation costs under successful efforts method of accounting • Accounting for all development and production assets on an asset by asset basis which necessitated fair valuation of certain properties in the North Sea and Asia Segment • Reporting results of its Pakistan Joint Venture on a proportional consolidation basis • Setting up deferred taxation on - All fair value adjustments - Petroleum Revenue Tax • Recognising pension fund deficits on its balance sheet • Recognising impact of share based payments and related provisions Whilst the financial information included in this preliminary announcement hasbeen computed in accordance with International Financial Reporting Standards(IFRSs), this announcement does not itself contain sufficient information tocomply with IFRSs. The company will publish full financial statements thatcomply with IFRSs on 19 April 2006. 6 Dividends The directors do not propose any dividend. 7 Earnings per share The calculation of basic earnings per share is based on the profit after tax andon the weighted average number of ordinary shares in issue during the year. Thediluted earnings per share allows for the full exercise of outstanding sharepurchase options and adjusted earnings. Basic and diluted earnings per share are calculated as follows: Profit after tax Weighted average number Earnings per share of shares 2005 2004 2005 2004 2005 2004 $ million $ million million million cent cent Basic 38.6 22.1 82.1 82.7 47.0 26.8Outstanding share options 0.7 1.8 * *Diluted 38.6 22.1 82.8 84.5 46.6 26.1 \* The inclusion of the outstanding share options in the 2005 and 2004calculations produce a diluted earnings per share. 8 External Audit This Preliminary Announcement is consistent with the audited financialstatements of the group for the year ended 31 December 2005. 9 A full set of financial statements will be posted to shareholderson 19 April 2006 and will be available at the company's head office, 23 LowerBelgrave Street, London SW1W 0NR, from that date. 10 The Annual General Meeting will be held at Clothworkers Hall, DunsterCourt, Mincing Lane, London, EC3R 7AH on Friday 19 May 2006 at 11.00am. 11 The full accounts for the year ended 31 December 2004, which receivedan unqualified report from the auditors, had been filed with the registrar ofthe companies. Oil and gas reserves (unaudited) Group proved plus probable reserves Working interest basis North Sea Asia Middle West Total East-Pakistan Africa Oil and Gas Oil and Gas Oil and Gas Oil and Oil and Gas Oil, NGL's NGL's NGL's NGL's NGL's NGL's and Gas mmbbls Bcf mmbbls Bcf mmbbls Bcf mmbbls mmbbls Bcf mmboeGroupAt 1 January 2005 19.1 24 4.7 379 9.7 33.5 403 112.9Revisions 0.3 2 1.8 (24) 2.1 (22) (2.7)Acquisitions and (1) (1) (0.1)divestmentsProduction (2.9) (3) (0.8) (18) (3.7) (21) (7.9)At 31 December 2005 16.5 22 5.7 337 - - 9.7 31.9 359 102.2Joint ventures - groupshareAt 1 January 2005 1.1 408 1.1 408 63.6Revisions 0.6 7 0.6 7 1.9Production (0.1) (26) (0.1) (26) (4.2)At 31 December 2005 - - - - 1.6 389 - 1.6 389 61.3Total group and group shareof joint venturesAt 1 January 2005 19.1 24 4.7 379 1.1 408 9.7 34.6 811 176.5Revisions 0.3 2 1.8 (24) 0.6 7 2.7 (15) (0.8)Acquisitions and (1) (1) (0.1)DivestmentsProduction (2.9) (3) (0.8) (18) (0.1) (26) (3.8) (47) (12.1)At 31 December 2005 16.5 22 5.7 337 1.6 389 9.7 33.5 748 163.5Total group and group shareof joint venturesProved developed 9.6 10 2.2 163 1.3 242 13.1 415 83.8Proved undeveloped 1.0 1.9 110 5 6.5 9.4 115 31.7Probable developed 2.3 6 0.9 32 0.3 113 3.5 151 28.0Probable undeveloped 3.6 6 0.7 32 29 3.2 7.5 67 20.0At 31 December 2005 16.5 22 5.7 337 1.6 389 9.7 33.5 748 163.5 Notes: 1. Revisions include upgrades on Wytch Farm, Kyle, Fife, Telford, Angus,Fergus and Flora, together with minor downgrades on Scott. Revisions have alsobeen made to block A (Anoa), and Kakap in Indonesia and the Bhit field in thePKP joint venture. Proved and probable reserves are based on operator or third-party reports andare defined in accordance with the 'Statement of Recommended Practice' (SORP)issued by the Oil Industry Accounting Committee (OIAC) dated July 2001. The group provides for amortisation of costs relating to evaluated propertiesbased on direct interests on an entitlement basis, which incorporates the termsof the Production Sharing Contracts in Indonesia and Mauritania. On anentitlement basis, reserves decreased by 10.7 mmboe mainly due to 2005production, giving total entitlement reserves of 145.9 mmboe as at 31 December2005 (2004: 156.6 mmboe). This information is provided by RNS The company news service from the London Stock ExchangeRelated Shares:
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