22nd Mar 2007 07:03
Premier Oil PLC22 March 2007 Premier Oil Preliminary Results for the year ended 31 December 2006 Premier is a leading FTSE 250 independent exploration and production companywith gas and oil interests in Asia, Middle East and Pakistan, the North Sea andWest Africa. Our strategy is to add significant value through exploration andappraisal success, astute commercial deals and asset management. Highlights Operational • Excellent exploration results in Indonesia and Vietnam with seven out of 11 successful wells; • Good progress on development projects including gas sales agreements in Indonesia; • Three successful acquisitions adding low cost barrels; • Production maintained at 33kboepd; • Reserves and contingent resources increased by 25 per cent to 289 mmboe; • New acreage acquired in Indonesia, Norway, Congo, UK and Vietnam. Financial • Profit after tax and EPS up 75 per cent to US$67.6 million, 82.6 cents per share; • Operating cash flow up 102 per cent to US$244.8 million (2005: US$121.2 million); • Field operating costs stable at US$6.0 per barrel (2005: US$5.9 per barrel); • Strong balance sheet with net cash of US$40.9 million (2005: net debt of US$26.2 million). 2007 Outlook • Significant programme of high impact wells under way; up to 15 exploration wells planned; • Key milestones on nine development projects during the year; • Production expected above 35kboepd, on track to achieve 50kboepd in medium-term; • New joint venture company in Middle East expected to build on opportunities in the region; • Encountered hydrocarbons in Pakistan (Qadirpur deep) and Indonesia (Ibu Lembu), work ongoing. "2006 was a year of very good progress for Premier with exploration success,development projects moving forward and good quality acquisitions at reasonableprices. All of these steps demonstrate successful execution of our statedstrategy and are supported by improving financial results." 22 March 2007 Sir David John, Chairman Simon Lockett, Chief Executive ENQUIRIESPremier Oil plc Tel: 020 7730 1111Simon LockettTony Durrant Pelham PRJames Henderson Tel: 020 7743 6673Gavin Davis Tel: 020 7743 6677 Premier will be making a presentation to equity analysts at 10.00am. A livewebcast of this presentation will be available via Premier's website atwww.premier-oil.com. CHAIRMAN'S STATEMENT Premier's results for 2006 reflect on the impact of our quality producing assetsat higher oil and gas prices. Our commercial and operating successes during theyear have significantly added to this strong base. Financial and operating performance Continuing strength in oil and gas prices, especially in the first half of theyear, supported sales revenues from continuing operations of US$358.8 million in2006 (2005: US$359.4 million). Of particular note was the high gas demand inPakistan which led to record gas production. Profit after tax for the year was US$67.6 million (2005: US$38.6 million)reflecting higher realised oil and gas prices. Operating cash flow after taxand interest was US$244.8 million (2005: US$121.2 million) which fully fundedour investments in exploration and development activities and our acquisitionactivity in the year. Net cash at 31 December 2006 was US$40.9 million (2005:net debt of US$26.2 million). Average production for the year was stable at 33,000 barrels of oil equivalentper day (boepd) (2005: 33,300 boepd) and finished the year with a finalproduction rate of 34,300 boepd through increased gas volumes in Pakistan. TheChinguetti field in Mauritania was successfully brought on-stream in February2006 but subsequently produced below expectations as a result of reservoircomplexities. Following a review and third party approaches, it has beendecided to pursue sale discussions with a limited number of parties for ourMauritanian assets. Therefore the financial results of our activities inMauritania are reported separately from all continuing operations in theattached financial statements. Subsequent to year-end we exercised a pre-emptive right to acquire a furtherinterest in the Scott field. On completion, this interest will addapproximately 5,000 boepd to our current year production. In addition to this increased interest in the Scott field, we are pleased tohave completed two separate purchases of interests in North Sumatra Block A inIndonesia. Together, these take our equity in the block to 41.66 per cent. Theblock contains several undeveloped gas fields which will be developed to supplyexisting local fertiliser plants. A Memorandum of Understanding (MoU) for thesale of this gas has already been signed. There is much further prospectivityon the block and in North Sumatra generally. Oil and gas proven and probable booked reserves amount to 165 million barrels ofoil equivalent (mmboe), including 13 mmboe acquired with the Scott fieldinterest subsequent to year-end (2005: 164 mmboe). Following our successfulexploration activity during the year, and the completion of the two acquisitionsin North Sumatra, total reserves and resources, which include discoveries notyet booked pending commercialisation, have increased to an estimated 289 mmboe(2005: 232 mmboe). Our exploration programme in 2006 delivered seven successes out of 11 wells(including two sidetracks) at less than the planned spend of US$50 million. Ofparticular encouragement were the two discoveries in Vietnam, Dua and Blackbird.Our teams in Ho Chi Minh City and elsewhere are now moving rapidly intoplanning the development of these discoveries. The continuing success inIndonesia, where as operator we have drilled 13 out of 15 successful wells inthe last seven years, is also pleasing and we are following up with an extensiveprogramme of exploration, appraisal and development in 2007. Beyond the significant current year plans, it is important to build a futureprogramme of drilling opportunities. To this end, we have added good qualitynew acreage in Congo, UK, Vietnam and Indonesia and, in early 2007 received fivenew awards in the 2006 Norwegian APA round. During the year we qualified as anoperator on the Norwegian Continental Shelf and the new awards include our firstoperated block. We continue to focus on improving our consistent health, safety andenvironmental performance and yet again are pleased to state that we have beatenour own targets in this area. Shareholder returns During 2006 Premier shares increased in value by 52 per cent. Over the fiveyears to 31 December 2006, Premier's share price has increased by 645 per cent.The company continues to be a top ten performer in the FTSE 250 over the sameperiod. This exceptional performance has reinforced our policy to rewardshareholders principally through share price growth and to utilise cash flowwithin the business. The Board announced on 7 December 2006, that it had terminated all discussionsregarding a possible offer for the company following the earlier receipt of apreliminary and conditional proposal. The Board remains extremely confidentthat the pursuit of the company's strategy of high impact exploration and itsgrowing portfolio of development projects will continue to be of long-termbenefit to shareholders. Board changes During the year we were pleased to announce the appointment of Professor DavidRoberts as a non-executive director. David has over 30 years experience in allaspects of exploration worldwide and will provide invaluable technical input atBoard level. Two non-executive directors, Azam Alizai and Ian Gray, retired after 10 years onthe Board. We are enormously grateful for their contributions over a long periodof time. Outlook It is pleasing to report early successes in delivering on the strategic targetsset out by the Board in September 2005. In particular, with good progress onour development projects we feel increasingly confident that our production willexceed the medium-term target level of 50,000 boepd. In addition, thediscoveries in Vietnam are early evidence that our exploration strategy -focusing our efforts on at least four high impact wells per year - is bearingfruit. 2007 promises to be another exciting year for Premier as we continue to pursueour strategy. We have already acquired interests in existing fields such asNorth Sumatra Block A in Indonesia, and the Scott field in the UK. Our drillingcampaign for the year is under way with early success in Pakistan and Indonesiaand with current activity in Guinea Bissau, India and the UK. Additional wellswill follow later in the year in Pakistan, Indonesia and Gabon. We will bereturning for a further programme in Vietnam during 2008. I am confident thatwe will achieve further significant milestones during the year in ourdevelopment projects in Norway, Indonesia, Pakistan and Vietnam. The strength of our performance has generated an excellent set of financialresults and maintained our solid balance sheet position. We will maintain thisdisciplined approach as we enter a period of significant growth. Sir David John KCMG Chairman FINANCIAL REVIEW Economic environment 2006 saw further strength in oil and gas commodity prices reaching a peak earlyin the second half of the year. The Brent oil price, which began the year atUS$58.9 per barrel (bbl), averaged US$65.4/bbl reaching a peak of US$78.6/bblduring August. Gas prices worldwide were also boosted according to the degreeof linkage with crude pricing. The early part of 2007 has seen some weakness inspot pricing with a relatively warm start to the year. Forward prices haveremained above US$60/bbl. Strong commodity prices and increased industry activity levels have continued toput pressure on both operating and development costs. Rig rates and otherdrilling service costs remain at historically high levels and shortages of keyvessels and equipment are contributing to project delays. The industry isresponding to cost and availability issues by seeking out new engineering andcommercial approaches to optimise use of available resources. Income statement Production levels in 2006, on a working interest basis, averaged 33,000 boepdcompared to 33,300 boepd in 2005. In 2006 this included an average of 2,400boepd from the Chinguetti field in Mauritania. On an entitlement basis, whichallows for additional government take under the terms of our Production SharingContracts (PSC), production was 28,900 boepd (2005: 28,700 boepd). Realised oilprices averaged US$64.90/bbl compared with US$48.38 in the previous year. Gas production averaged 127 million standard cubic feet per day (mmscfd) (22,000boepd) during the year or approximately 67 per cent of total production.Average gas prices for the group were US$5.11 per thousand standard cubic feet(mscf) (2005: US$3.82/mscf). Gas prices in Singapore, which are linked to HighSulphur Fuel Oil (HSFO), have moved broadly in line with crude pricing,averaging US$9.43/mscf (2005: US$7.90/mscf) during the year. Total sales revenue from all operations was 12 per cent higher than 2005 atUS$402.2 million (2005: US$359.4 million) as a result of the higher averagecommodity prices. Excluding revenues of US$43.4 million from the Chinguettifield, sales revenue for continuing operations was US$358.8 million. Cost of sales decreased to US$126.6 million compared to US$176.5 million in2005. The year-end inventory position moved from a stock overlift to anunderlift position, driven by the timing of liftings around each year-end, andresulting in a credit to cost of sales of US$22.3 million (2005: charge ofUS$25.9 million). After excluding this stock effect, underlying unit operatingcosts were stable at US$6.0 per barrel of oil equivalent (boe) (2005: US5.9/boe)despite the general rise in the cost environment faced by the industry in fuel,material and wage costs. Underlying unit amortisation amounted to US$6.3 perboe (2005: US$5.5/boe). The cost of sales and operating cost figures exclude those relating toMauritania, which are separately reported in the balance sheet and incomestatement as assets held for sale. The results of the Mauritanian operationinclude a one-off adjustment for a bonus of US$9.2 million paid to theMauritanian authorities on renegotiation of the PSC documentation and a loss onreclassification as assets held for sales of US$8.1 million.. Administrative costs fell by US$3.0 million to US$16.6 million. This includes acharge of US$5.7 million in respect of current year and future provisions forlong-term incentive plans. Operating profits were US$178.5 million, a 41 per cent increase from the prioryear. Finance charges net of interest income totalled US$5.7 million (2005:US$1.1 million). Pre-tax profits were 37 per cent higher at US$172.8 million(2005: US$125.8 million). The taxation charge totalled US$86.7 million (2005:US$86.3 million) despite higher profits benefiting from the favourableresolution of certain outstanding prior year provisions. Basic earnings pershare from continuing operations amounted to 105.3 cents, an increase of 119 percent on the previous year. Cash flow Cash flow from operating activities, including the assets held for sale,amounted to US$244.8 million, up from US$121.2 million in 2005. These cashflows include payments of US$31.9 million received from the joint venture inPakistan (2005: US$47.1 million). Capital expenditure and pre-licence exploration expenditure in the period wasUS$175.7 million (2005: US$144.4 million). This spend includes the US$17million cost of our first acquisition in North Sumatra Block A (an equityinterest of 16.67 per cent) which was completed in March 2006. Explorationspending was US$46.9 million in line with our stated target. Net cash inflow, before movements related to financing, amounted to US$69.1million (2005: US$23.2 million outflow). Net cash position Net cash at 31 December 2006 amounted to US$40.9 million against a net debtposition of US$26.2 million at the previous year-end. This comprised cashbalances and short-term investments. As a result of this strong cash position,the US$275 million credit facility was undrawn at year-end. Together with itsstrong cash flow from producing assets, the company is in an excellent positionto fund an increased exploration and development programme over the next fewyears. Hedging and risk management The Board's policy remains to lock in oil and gas price floors at a level whichprotects the cash flow of the company and the business plan. Such floors arepurchased for cash or by selling puts at a ceiling price where market conditionsare considered favourable. All transactions are matched as closely as possiblewith expected cash flows to the company; no speculative transactions areundertaken. Hedges utilising collars were previously entered into for the period 1 January2006 to 31 December 2010 covering nine million barrels of oil (mmbbls). Theaverage floor price was US$37.42/bbl with a ceiling price of US$100/bbl. Inaddition, 384,000 metric tonnes of HSFO, representing the equivalent of around athird of Indonesian gas production for the period 1 January 2006 to 31 December2009 were covered at a floor price of US$200 per metric tonne and a ceilingprice of US$480 per metric tonne. During the course of 2006 the volume, pricing and maturity of these transactionswas kept under review and changes made where market conditions were favourable.As at 31 December 2006, hedges covered 7.2 million barrels of liquids for theperiod to 31 December 2010 at an average floor price of US$38.55/bbl and aceiling price of US$100/bbl. A further 1.2 million barrels are covered for theperiod 1 January 2011 to 31 December 2012 at a floor of US$41/bbl and a cap ofUS$100/bbl. On the gas side, 612,000 metric tonnes (mt) of HSFO are hedged forthe period 1 January 2007 to 30 June 2012 at a floor level of US$245/mt andceiling price of US$500/mt. Under International Financial Reporting Standards(IFRS) IAS 39, these hedges are required to be marked to market at the balancesheet date. The aggregate valuation is a US$0.3 million liability (2005: US$1.6million asset) generating at US$1.9 million charge in the 2006 income statement. 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 its exploration and production activities. In addition,business interruption cover is purchased for a proportion of the cash flow fromproducing fields. OPERATIONAL REVIEW Production and reserves 2006 has seen key milestones in a number of our development projects and initialsuccess in our high impact exploration programme. These are material stepsforward in achieving our medium-term production target of 50,000 boepd and ingrowing our portfolio of four regional businesses. Working interest production for 2006 averaged 33,000 boepd. Comparableproduction from 2005 was 33,300 boepd. Production comprised 33 per cent liquidsand 67 per cent gas, with Pakistan and Indonesia each accounting for around 37per cent and 35 per cent of the total respectively, the UK 21 per cent and WestAfrica the remainder. On an entitlement basis, group production for the year was28,900 boepd (2005:.28,700 boepd). Working interest EntitlementProduction (boepd) 2006 2005 2006 2005North Sea 6,850 9,750 6,850 9,750Middle East-Pakistan 12,150 11,500 12,150 11,500Asia 11,550 12,050 7,800 7,450West Africa 2,450 - 2,100 -Total 33,000 33,300 28,900 28,700 As at 31 December 2006 proven and probable reserves, on a working interestbasis, based on Premier and operator estimates, were 152 mmboe. On a pro formabasis the Scott field acquisition would increase reserve estimates to 165 mmboe. Reserves (mmboe) Reserves and contingent resources (mmboe)Start of 2006 164 232Production (12) (12)Net additions and revisions - 69End of 2006 152 289Scott acquisition* 13 13Pro forma total 165 302 * Expected to be completed in the first half of 2007. At year-end, pro forma reserves comprised 18 per cent liquids and 82 per centgas, and the equivalent volume on an entitlement basis amounted to 146 mmboe(2005: 146 mmboe). Reserve revisions represent the write-down of 5 mmboe from the Chinguetti fieldin Mauritania, offset by an increase in booked reserves from the Anoa fieldfollowing strong offtake volumes by the buyers under the existing Gas SalesAgreement (GSA). Discoveries made in the year in Vietnam have not been recordedin booked reserves, pending completion of ongoing appraisal andcommercialisation work. These volumes, together with others in the process ofbeing commercialised (including unsold gas in Indonesia and other discoverieswhich have not yet received development sanction elsewhere) give increased totalreserves and contingent resources of 289 mmboe (2005: 232 mmboe). Exploration and appraisal Premier's achievement in growing its exploration portfolio in recent yearsyielded a series of exploration successes in 2006 and the opening up ofsignificant follow-on opportunities. The company has also continued to seek andsign-up new prospective areas in its North Sea, West Africa and Asian businessunits. In 2006 Premier drilled 11 exploration and appraisal wells with a success rateof over 60 per cent. In Vietnam we drilled three wells resulting in a successfulappraisal well and two new exploration discoveries. In our Indonesian Natuna ABlock we made three discoveries. Five of these six wells were Premier-operated,and Premier's E&A success rate has continued to exceed 50 per cent since 2000.In Indonesia we have now drilled 13 out of 15 successful operated explorationwells since 2000. In Vietnam the Blackbird oil discoveries are the first in thevicinity, and open up substantial future opportunities across two large tranchesof mostly unexplored acreage in Vietnam (Block 12 and Block 7&8/97) and anotherlarge tranche in Indonesia (the Tuna Block), awarded early in 2007. These successes in Asia have confirmed the validity of our strategy of extendingthe knowledge we have gained over many years from our interests in theIndonesian Natuna Sea area into the neighbouring Vietnamese waters. In addingacreage around the world during 2006 - in Vietnam, in Indonesia, in Congo and inNorway we have been mindful of staying within our areas of competency. Premier planned to spend no more than US$50 million on seismic and drilling in2006. In order to ensure a broad exposure to high reward prospects and, at thesame time, keep its cost exposure down, we undertook several farmouts reducingour equity in projects in return for funding current exploration on favourableterms. These projects include farmouts for the 2006 wells in Vietnam Block 12Eand W, and for the 2007 wells in Guinea Bissau, the UKCS Peveril well and thePhilippines Ragay Gulf SC-43 licence. 2007 sees a very active exploration programme, with Espinafre-1 and Eirozes-1being drilled offshore Guinea Bissau, Peveril-1 in the UKCS, Masimpur-3targeting a large structure in NE India, several exploration wells in Indonesia,a deep-water well in Indus offshore Pakistan, a well on our Themis Block inGabon, and programmes unfolding in Vietnam for 3D acquisition and more wellsdrilling in late 2007 and through 2008. The 2007 programme will include up to15 wells at an estimated pre-tax cost of US$100 million (post-tax andrecoveries: US$70 million). ASIA Indonesia Premier's core asset in Indonesia is its interest in the West Natuna Gasproject, which supplies gas under a long-term gas sales contract to Singapore.This is held through equity interests in Natuna Sea Block A and the KakapProduction Sharing Contracts (PSCs). In 2006, Premier-operated Block A sold an overall average of 130 billion Britishthermal units per day (BBtud) (gross) with a further 66 BBtud (gross) averagesold from the non-operated Kakap fields under the same agreement. Oilproduction from Anoa averaged 2,581 barrels of oil per day (bopd) gross (2005:3,023 bopd) with the reduction due to natural depletion of the oil reservoirs.Oil production from Kakap averaged 6,998 bopd gross (2005: 7,263 bopd). Overall, net production from Indonesia amounted to 11,550 boepd (2005: 12,050boepd) with Anoa and Kakap contributing 7,890 boepd and 3,660 boepdrespectively. Premier's commitment to health, safety and environmental performance wasdemonstrated with the award of OHSAS 18001 and retention of the ISO 14001certification and Indonesia's 'PROPER Blue' rating. The West Lobe Wellhead platform was installed in April 2006 with hook up takingplace in May 2006. The Seadrill-5 jack-up drilling rig arrived on location atthe platform in August 2006 to drill four gas production wells into the WestLobe of the Anoa field. All wells achieved their objectives with first gasflowing from the platform in December 2006. During the drilling campaign anopportunity was taken to appraise an un-drilled potential oil reservoir in thecentral area of the Anoa field. The well successfully encountered and evaluateda 67ft oil column before being sidetracked to the planned gas developmentlocation for the well. Planning is now under way for the development of the oildiscovery with a well expected to be drilled in the first half of 2007 which isexpected to add initially up to 2,000 bopd (gross) to Anoa production. Negotiations for further gas sales from Block A continue with prospective buyersin the region and we are targeting sales of gas from 2010 to the Singaporepetrochemical sector. Discussions have also been held with PLN, the Indonesiannational power company, to sell gas domestically to Batam. We expect to move todefinitive gas sales agreements on these projects during the second half of2007. The 2006 Indonesia exploration drilling campaign resulted in a 100 per centsuccess rate with a gas discovery in Macan Tutul-1 and the discovery and testingof oil and condensate rich gas at Lembu Peteng-1. Lembu Peteng forms part of atrend of structures that stretches east to the existing Lembu-1 discovery,dating from 1984. Further exploration and appraisal wells on the trend areplanned for 2007 to establish the significance and development potential of thisarea as part of the drive to ensure maximum value is extracted from the NatunaBlock A asset. Technical studies were also carried out across other areas onBlock A to identify additional potential drilling targets for the 2007 drillingcampaign. A number of prospects have been highlighted for further assessmentwith the final programme dependent on ongoing work and results of the earlywells. During the year, Premier acquired a 16.67 per cent stake in the North SumatraBlock A PSC. Initially Premier partnered with Japex and Medco holding equalinterests. After year-end Premier increased its stake in the PSC to 41.67 percent by jointly purchasing the ConocoPhillips share of the PSC with Medco. Theacquisition cost for the two transactions was US$53 million. The acreage contains undeveloped discoveries on the Alur Siwah, Alur Rambong,and July Rayeu fields, with certified reserves of over 650 billion cubic feet(bcf) of gas. There is substantial upside from around 20 identified explorationprospects with total prognosed unrisked potential reserves of 1.5 trillion cubicfeet (tcf) gross, Enhanced Oil Recovery (EOR) opportunities throughredevelopment of old abandoned oil fields, as well as from the possibledevelopment of the giant Kuala Langsa gas field. Subject to completing a GasSales Agreement, first gas is expected to commence in early 2010, supplying feedgas to two fertiliser plants in North Sumatra. In December, Premier was awarded an interest in the Buton PSC in South EasternSulawesi. The Buton PSC covers 3,396km2 and lies on the south-eastern side ofButon Island, Sulawesi, Indonesia. It is an underexplored block in an onshorefrontier area. Oil seeps are prolific over the island and volumes of expelledoil are sufficient to underpin the commercial asphalt mining operations thathave been ongoing on the island since colonial times. The acreage has potentialfor multiple targets on structures that are known to exist from satellite imageanalysis. Our initial work programme will focus on identifying prospects tosupport a high impact drilling opportunity in 2009. Premier is partnered byJapex and Kufpec in this PSC, and holds a 30 per cent non-operated interest. Vietnam Premier Oil drilled three successful exploration wells as operator and acquiredover 1,500km of 2D marine seismic data on Block 12. The first discovery, Dua-4X,drilled in the north of the Dua field, confirmed the extent of an oilaccumulation first discovered in 1974 with the Dua-1X well. Dua-4X was thensidetracked to delineate the northern half of the Dua field. The rig was thenmoved to drill the Dua-5X well which intersected oil in multiple reservoirs inthe southern part of the Dua field, two reservoir zones were tested and flowedat a combined rate of 6,947 boepd. Dua-5X was then suspended as a potentialproducer. The second exploration structure to be drilled was 20km to the southwest atBlackbird, where well 12E-CS-1X discovered oil in multiple reservoir zones, twoof which were tested at a combined rate of 6,569 boepd. This well wassidetracked to delineate the extent of the hydrocarbon bearing reservoir.Following this exploration success, Premier has commenced appraisal anddevelopment studies for each of the Blackbird and Dua discoveries. Oil in placeacross the two discoveries is currently estimated to be in the range of 180 to620 mmbbls, of which approximately 80 mmbbls represents most likely recoverablevolumes. With first oil currently scheduled for 2010, Premier has commencedpre-development studies for both fields and a programme of 3D seismicacquisition will commence in early April 2007 to clarify the volumetricuncertainty on the Blackbird field. The Dua field is already covered by 3Dseismic data acquired in 2005. The 3D area will be extended beyond theBlackbird field to define other prospects ahead of the next phase of explorationdrilling likely to be in 2008. Premier holds a 37.5 per cent exploration workinginterest in Block 12, with partners Santos (37.5 per cent) and Delek (25 percent). In December, Premier exercised an option to acquire from VAMEX a 45 per centworking interest in, and operatorship of, Block 7&8/97. Block 7&8/97 is locatedimmediately to the southeast of Block 12 in the Nam Con Son Basin.Interpretation of 2D marine seismic data from Block 7&8/97 has demonstrated theexistence of the same play elements which create petroleum prospectivity inBlock 12 and the potential for numerous large structures suitable for highimpact well locations. India Drilling commenced on the high impact Masimpur prospect in Assam on 21 January2007. Work is under way to prepare for drilling of two follow-up wells toMasimpur on the large Hailakandi and Kanchampur gas prospects and road and siteconstruction has begun at Hailakandi following environmental approvals. Premieris operator of the Cachar Block and holds a 14.5 per cent working interest. All outstanding issues have been resolved between the partners regarding thedevelopment of the Ratna oil fields, offshore Mumbai and documentation leadingto the formal signature of the PSC is being progressed through the ministriesconcerned. Premier holds a 10 per cent (carried) working interest in the Ratnafields, estimated to contain around 80 mmbbls. Philippines During 2006 Premier operated the SC43 licence in the Ragay Gulf of SE Luzonprovince with a 42.5 per cent working interest. During 2006 Premier carried outseismic reprocessing, geological studies and preparatory work for a well on theMonte Cristo prospect. Geological work led to the identification of a newprospective trend in the Panaon Limestone formation and marine seismicacquisition is planned in 2007 to pursue this promising lead. Subsequent toyear-end, Premier has farmed out 21.5 per cent of its 42.5 per cent interest toPearl Energy and PNOC in exchange for a carry in the forthcoming well nowexpected in the first half of 2008. MIDDLE EAST PAKISTAN Pakistan The record production level achieved in 2005 was exceeded during 2006.Production net to Premier in 2006 was 12,150 boepd, an increase of 6 per centover 2005 (11,500 boepd). The increase in production was mainly due to highersales from Zamzama field, on exceptionally high gas demand. Qadirpur produced an average of 3,866 boepd, for Premier's net interest of 4.75per cent (2005: 3,807 boepd). The project to enhance Qadirpur plant capacityfrom 500 mmscfd to 600 mmscfd was ongoing through 2006 and first gas from thatincreased capacity is expected by end of December 2007. A Term Sheet has beensigned with the gas buyer, Sui Northern Gas Pipelines Limited, to increase theAnnual Contract Quantity (ACQ) from the existing 450 mmscfd to 550 mmscfd.Qadirpur Deep-1 well has been drilled to a depth of 4,681 metres. The wellencountered hydrocarbons in several zones and was suspended when higher thananticipated temperatures were encountered. Specialist equipment has now beenordered and testing on the well will be resumed later in 2007. On Kadanwari, the K-15 well was tied back to the processing plant. Theadditional production from it compensated for the natural decline of the fieldand also provided some production redundancy. The field produced an average of1,200 boepd during 2006 (2005: 1,228 boepd) for Premier's interest of 15.79 percent. To exploit additional reserves in Kadanwari, two wells (K-16 and 18) areplanned to be drilled in the first half of 2007. Zamzama produced an average of 4,140 boepd, net to Premier, during 2006 from its9.375 per cent interest. This was some 13 per cent higher than the previous year(2005: 3,677 boepd). Work continued in 2006 on the Zamzama Phase 2 development- to make available gross 150 mmscfd high calorific value sale gas in the thirdquarter of 2007. The production level in the Bhit field from Premier's 6 per cent workinginterest was 2,944 boepd in 2006 (2005: 2,788 boepd). A supplemental GSA toincrease the Bhit ACQ from 270 mmscfd to 300 mmscfd has been signed by the gasbuyer Sui Southern Gas Company Limited (SSGCL) and by joint venture partners.The Bhit plant capacity is being enhanced to 315 mmscfd to allow acceleratedBhit field production and production of Badhra reserves starting by the end ofthe fourth quarter of 2007. In Zarghun South, negotiations on the GSA were successfully concluded with thegas buyer, SSGCL, for the sale of 22 mmscfd gas from the field. The fielddevelopment has commenced and first gas is planned for the first quarter of2009. Premier's interest of 3.75 per cent is carried by the operator (other thanfor government commitments) during the development and production phases of thefield. Egypt In Egypt, the Al Amir-2 well was drilled to appraise the 2005 Al Amir discoveryon the onshore North West Gemsa Concession in Egypt. The discovery well, AlAmir-1, had flowed oil at over 750 bopd from the South Gharib Formation. The AlAmir-2 well confirmed oil at the same reservoir level. However, on test, thewell flowed water and oil at sub-commercial rates and was plugged and abandoned.The Al-Fagr wildcat well was plugged and abandoned after MDT tests were run.Although shows were recorded while drilling and logs displayed possiblehydrocarbon saturations in the target section, no hydrocarbons were recovered ontest. Subsequent to year-end, Premier has exercised an option with the operator,Vegas, to reduce its interest to 10 per cent in the block which entitles Premierto a partial refund of past costs. Premier continues to participate inexploration licensing rounds and farm-in discussions with a view to building onits position in Egypt. Our new business efforts continue to be focussed on building existingrelationships in the region. In January we signed an MoU with EmiratesInternational Investment Corporation (EIIC), an Abu Dhabi investment company,with a view to acquiring new interests in Abu Dhabi and elsewhere in the region. NORTH SEA In the North Sea, Premier is continuing to pursue the established strategy ofseeking out high impact exploration while maximising the value from its existingproducing assets. UK Production in the UK in 2006 amounted to 6,850 boepd (2005: 9,750 boepd)representing 21 per cent of the group total (29 per cent in 2005). Thisrepresents a decrease of some 30 per cent on last year's level due to acombination of natural decline and specific operational problems. The Wytch Farm oil field contributed 3,205 boepd net production to Premier, down20 per cent on last year. In 2006, the production performance was severelyimpacted by a number of serious well failures. In January, the F05 well,producing 3,000 bopd gross, failed and required a workover. The well was broughtback onstream in March. The M07 well was completed and brought on production inFebruary but was suspended due to a suspected collapsed hole. The subsequentintervention was unsuccessful and the well was redrilled and productionre-established in June. Year-end production recovered to 27,000 boepd gross(3,300 boepd net). BP, the operator, is planning to complete two new wells andfour workovers during 2007, together with various plant upgrades and a newoffice facility. Net production from Kyle was 1,962 boepd, down 46 per cent on last year. Gasproduction remained below the annual target for most of the year however thiswas compensated by higher oil production that enabled Kyle to deliver in linewith the annual composite production budget. The re-perforation of the Kyle-15well was delayed until October and when completed produced disappointingresults. The K16 well that was scheduled to be drilled in 2006 has beenrescheduled to 2008. The gas lift project that was originally planned tocommence in 2006 has now slipped and is expected to be completed in May 2007.Concurrently facility upgrades are being undertaken on the Petrojarl Banff hostprocessing facility. In the Fife area, Premier's net production amounted to 1,156 bopd from the Fife,Fergus, Flora and Angus fields. The Angus field was suspended in September afteran intervention failed and remains suspended subject to the joint venturedetermining the forward strategy for this asset. The Fife FPSO fixed contractterm ends in December 2007 with discussions currently under way with Bluewaterto exercise the contract extension option. Scott and Telford accounted for the remainder of net UK production. In December,the company received notification of Hess' intention to sell its 20.05 per centequity interest in the Scott field to Nexen Petroleum UK. Premier has sinceadvised Hess that it is pre-empting the proposed transaction. Upon completionof the relevant Sale and Purchase Agreement Premier's working interest willbecome 21.83 per cent effective 1 January 2007, representing an average 2007entitlement of 5,000 bopd at expected production rates. Detailed evaluation of the UK exploration portfolio continued throughout 2006working on developing the prospects to drillable candidates for 2007 and 2008,specifically in Blocks 23/22b (P1181) and 21/7b (P1177) in the Central NorthSea. Further geological and geophysical work integrated with a comprehensivecommercial evaluation on the Southern North Sea portfolio of Blocks 44/21c, 44/26b (P1184), Blocks 42/10, 42/15 (P1229) and Blocks 43/22b, 43/23, 43/27b, 43/28, and 43/29 (P1235) resulted in Premier having fulfilled the work obligationsfor these licences, relinquishing them in December as no commercial viablehydrocarbon prospects were identified. Integration of the results from the 21/6a-7 well on the Palomino prospect in licence P1048, which was plugged andabandoned dry in January 2006, are being integrated into the adjacent licenceP1177 evaluation to assess the remaining prospectivity. Premier's 100 per cent equity in the Fife area Blocks 39/1c and 39/2c wassuccessfully farmed down to a 30 per cent equity level carried through theforecast costs of the Peveril prospect well, due to spud in March 2007 to testthe Jurassic Fulmar sands in a similar setting to the Angus field. Significantfollow on potential is provided by Blocks 39/1b & 39/7 (P1152) where additionalprospects have been identified on the reprocessed 3D seismic. Two licence applications were made by Premier in the UK 24th Licensing roundcovering Blocks 15/24a, 15/25f, 15/29e and 15/23c. As of the 31 December nolicence round announcement had been made by the DTI. Subsequently, in Februaryit was announced that Premier had been awarded a split portion of the 15/24aapplication area excluding the Bowmore accumulation. This offer is currentlybeing evaluated for response to the DTI. Norway The five licences awarded to Premier in the APA 2005 licence round are beingprogressed through the work programmes tendered to reach critical decisionpoints: drill or drop for three of the licences by the end of 2007; accelerationof a possible well on one licence and development approval for the Froypotential redevelopment. These licences offer a spectrum of redevelopment,appraisal and exploration opportunities which have the potential for both earlyproduction and high impact exploration. The five APA 2005 licences consist ofBlocks 35/12 and 36/10 licence PL378; Blocks 16/1 and 16/4 licence PL359, Blocks34/2 and 34/5 licence PL374(s), Blocks 34/5 and 34/5 licence PL375, and Blocks25/3, 25/5, and 25/6 PL364 Froy. The Froy field was abandoned in 2001 by a previous operator in a much lower oilprice environment and due to the imminent abandonment of the nearby Frigg fieldto which it was tied back. The Froy field is the subject of extensiveredevelopment studies with plans to seek early development approvals. Premier was very active in the APA 2006 licensing round submitting applicationsfor five potential licences. The licence round announcement in January 2007confirmed that we had been successful in securing five new licences, includingtwo licences in the very competitive Bream discovery area. The licence interestsobtained in the APA 2006 round are as follows: Block no. (or part block no.) Working interest Operator17/8,9,11,12 & 18/7,10 (Bream appraisal) 20 British Gas7/12, 18/10, 18/11, 8/3 & 9/1 (Bream exploration) 40 Premier Oil31/3, 32/1, 36/10 40 Revus35/9 (part) 25 Nexen35/8, 35/9 15 Nexen The Bream appraisal area contains the Bream discovery which is to be appraisedby a well with a declaration of development by the end of 2008. Contingent upona successful appraisal of the Bream structure, the partnership group will drilla further exploration well to target additional resources identified in thishighly prospective area. Premier successfully qualified as an operator in Norway in 2006 and the award asoperator for the Bream exploration acreage reflects Premiers commitment todevelop a business in Norway. The licence has a five-year first term durationrequiring 3D seismic acquisition and a firm well. Blocks 31/3, 32/1, and 36/10 are adjacent to the PL378 licence and help in thedevelopment of a core area around the Tampen Spur for Premier. The remaining twolicence awards are adjacent to the Gjoa field which is currently being developedand offer some interesting stratigraphic potential. WEST AFRICA Mauritania The Chinguetti oil field came on production in Woodside operated PSC B on 24February 2006 at an initial rate of 70,000 bopd (5,600 bopd net to Premier).The field is located in 800 metres of water some 90km west of the capitalNouakchott. The initial development of six production wells and three water injectors didnot perform to initial expectations in 2006. This is the result of more thanexpected reservoir compartmentalisation due to reservoir geometry and complexstructure. Production at the end of 2006 was in the region of 22,000 bopd(1,780 bopd net Premier). Remedial action to increase production commenced inlate December 2006 with drilling of the Chinguetti-18 well. This wellencountered 35 metres of net oil pay, close to expectations, and was beingcompleted at the end of the reported period. Additional development drilling isplanned in the third and fourth quarter of 2007, with up to six wells beingconsidered, which would extend the drilling campaign in to 2008. The performance of the initial development wells has an impact on the expectedreserves of the field, with the operator's proven and probable reserves beingreduced from the pre-development expectation of 123 million barrels of oil(mmbo) to 62 mmbo. Further revisions are expected as a result of a 3Dhigh-resolution and 3D seismic survey that is to commence in the first half of2007 over the field. Premier expects that, as a result, the 2P reserves will berevised upwards in the course of the year. The reserves are also expected toincrease with further phases of development drilling, if commercially viable. In 2006, the Mauritanian government challenged certain amendments (avenants) toWoodside operated concessions, including those in which Premier has an interest(PSCs A and B). This resulted in the joint ventures signing revised PSCs withthe Mauritanian government in June 2006, under which the fiscal provisions inthe contracts were altered to reflect the higher oil prices prevailing at thattime at a net cost to Premier of US$9.2 million. One exploration well was drilled in Premier's Mauritanian acreage, Colin-1 inPSC A. The well encountered good quality sand reservoirs but was dry. A secondwell, Kibaro-1, which had been planned to test a Cretaceous objective in PSC A,was deferred to 2008 due to rig scheduling necessitated to drill theChinguetti-18 well. In December following a number of approaches, the Board determined that ourinterests in Mauritania were unlikely to generate high impact explorationopportunities which are our key targets in the region. Accordingly we havedecided to conduct an auction with a view to the sale of the asset. The resultsof the Mauritanian operation have, therefore, been classified separately in thefinancial statements under 'assets held for sale'. Guinea Bissau During 2006 processing of the 2005 3D seismic data over the Eirozes prospect,and re-processing of the existing 3D seismic over the Espinafre prospect, werecompleted. The two data sets were interpreted to mature the Espinafre andEirozes prospects for drilling. The Global Santa Fe jack-up rig 'Baltic' was contracted for a two well programmecommencing in the first quarter of 2007, and the rig was under tow to ouracreage at the end of the reported period. The Espinafre-1 well was spudded inFebruary. Success on either of these two wells will lead to a significant increase invalue and enhance the prospectivity of a number of lookalike prospects on theblock. Gabon In 2006 both existing 2D and 3D seismic data on the Sterling Energy operatedThemis Permit were re-processed. The results of the interpretation of thisreprocessed data have been incorporated into a block-wide understanding of theprospectivity to mature a prospect for drilling. Premier, as drilling operatorfor the joint venture, has contracted the Global Santa Fe 'Adriatic 6', to drillthis exploration well, which will take place during the third quarter of 2007. Data interpretation and studies on the Dussafu Permit have been carried outduring 2006 leading to development of a leads and prospects portfolio. Thiswill be used to find potential targets for drilling in the fourth quarter of2007 or the first quarter of 2008. Congo During 2006, Premier was awarded a 58.5 per cent operated working interest inBlock IX, with its joint venture partners Ophir Energy Company Limited and theCongo national oil company, SNPC. The Production Sharing Contract was ratifiedby the Congolese Parliament on 5 October 2006. The block contains severalprospects with high impact exploration potential. Technical evaluation isongoing with the expectation that the first well on the block could commence in2008. SADR The company's exploration assets in the Saharawi Arab Democratic Republic (SADR)remain under force majeure, awaiting resolution of sovereignty under a UnitedNations mandated process. CONSOLIDATED INCOME STATEMENT 2006 2005 $ million $ millionContinuing operations: Sales revenues 358.8 359.4Cost of sales (126.6) (176.5)Exploration expense (15.3) (20.6)Pre-licence exploration costs (21.8) (15.8)General and administration costs (16.6) (19.6)Operating profit 178.5 126.9 Interest revenue and finance gains 2.0 5.9Finance costs and other finance expenses (7.7) (7.0)Profit before tax 172.8 125.8 Tax (86.7) (86.3)Profit for the year from continuing operations 86.1 39.5Discontinued operationsLoss for the year from assets held for sale (18.5) (0.9)Profit for the year 67.6 38.6Earnings per share (cent):From continuing operations Basic 105.3 48.1 Diluted 104.1 47.7From continuing and discontinued operations Basic 82.6 47.0 Diluted 81.7 46.6 STATEMENT OF TOTAL RECOGNISED INCOME AND EXPENSES 2006 2005 $ million $ millionCurrency translation differences 0.3 -Pension costs - actuarial gains/(losses) 1.4 (2.2)Net gains/(losses) recognised directly in equity 1.7 (2.2)Profit for the year 67.6 38.6 Total recognised income 69.3 36.4 RECONCILIATION TO NET ASSETS 2006 2005 $ million $ millionNet assets at 1 January 376.1 354.1Total recognised income 69.3 36.4Adjustments relating to past restructuring - 3.1Purchase of shares for ESOP Trust - (8.5)Provision for share-based payments 3.0 2.9Issue of ordinary shares 0.7 1.3Repurchase of ordinary share capital - (13.2)Net assets at the year-end 449.1 376.1 CONSOLIDATED BALANCE SHEET 2006 2005 $ million $ millionNon-current assets:Intangible exploration and evaluation assets 114.7 67.4Property, plant and equipment 502.6 576.6Investments in associates - 1.1Deferred tax asset - 0.8 617.3 645.9Current assets: Inventories 14.8 13.3Trade and other receivables 174.4 144.7Cash and cash equivalents 40.9 38.8Assets held for sale 90.4 - 320.5 196.8Total assets 937.8 842.7 Current liabilities: Trade and other payables (169.6) (113.7)Current tax payable (52.4) (38.8)Liabilities directly associated with assets held for sale (14.2) - (236.2) (152.5)Non-current liabilities: Long-term debt - (63.6)Deferred tax liabilities (194.1) (198.3)Long-term provisions (49.6) (41.0)Long-term employee benefit plan deficits (8.8) (11.2) (252.5) (314.1)Total liabilities (488.7) (466.6) Net assets 449.1 376.1 Equity and reserves: Share capital 73.3 73.2Share premium account 8.6 8.0Revenue reserves 365.6 293.6Capital redemption reserve 1.7 1.7Translation reserves (0.1) (0.4) 449.1 376.1 The financial statements were approved by the Board of Directors and authorisedfor issue on 21 March 2007. CONSOLIDATED CASH FLOW STATEMENT 2006 2005 $ million $ millionNet cash from operating activities 244.8 121.2Investing activities:Capital expenditure (156.5) (132.6)Pre-licence exploration costs (21.8) (15.8)Proceeds from disposal of intangible exploration and evaluation assets 2.6 4.0Net cash used in investing activities (175.7) (144.4) Financing activities:Issue of ordinary shares 0.7 1.1Repurchase of ordinary shares - (21.0)Repayment of long-term financing (65.0) -Loan drawdowns - 25.0Arrangement fee for the loan facility - (1.4)Interest paid (2.7) (3.5)Net cash (used) in/from financing activities (67.0) 0.2 Currency translation differences relating to cash and cash equivalents - 2.2Net increase/(decrease) in cash and cash equivalents 2.1 (20.8) Cash and cash equivalents at the beginning of the year 38.8 59.6Cash and cash equivalents at the end of the year 40.9 38.8 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 segmental information (the only basis on which it can reportsuch information). Sales revenue represents amounts invoiced, exclusive ofsales-related taxes, for the group's share of oil and gas sales. 2006 2005 $ million $ millionContinuing operationsRevenue:North Sea 119.3 169.6Asia 149.9 121.5Middle East-Pakistan 89.6 68.3Total group sales revenue 358.8 359.4Interest revenue 2.0 1.0 360.8 360.4Discontinued operations:Revenue:West Africa 43.4 -Total group revenue 404.2 360.4ResultsContinuing operationsGroup operating profit/(loss):North Sea 54.3 32.2Asia 91.4 66.2Middle East-Pakistan 50.2 41.9West Africa (1.6) (4.8)Other (15.8) (8.6)Group operating profit 178.5 126.9Interest revenue and finance gains 2.0 5.9Finance costs and other finance expenses (7.7) (7.0)Profit before tax 172.8 125.8Tax (86.7) (86.3)Profit after tax 86.1 39.5Discontinued operations:Loss for the year from discontinued operations (18.5) (0.9)Profit for the year 67.6 38.6Balance sheetSegment assets:North Sea 261.5 268.9Asia 454.4 350.6Middle East-Pakistan 114.1 95.7West Africa 107.2 123.1Unallocated 0.5 3.3Investment in associates:West Africa 0.1 1.1Total assets 937.8 842.7Liabilities:North Sea (178.7) (154.5)Asia (206.8) (160.3)Middle East-Pakistan (28.4) (30.8)West Africa (21.5) (16.9)Unallocated (53.3) (104.1)Total liabilities (488.7) (466.6) 1 Geographical segments continued 2006 2005 $ million $ millionOther informationCapital additions:North Sea 46.7 14.5Asia 90.8 37.9Middle East-Pakistan 22.9 13.3West Africa 26.0 65.8Total capital additions 186.4 131.5 Depreciation and amortisationContinuing operations:North Sea 36.4 36.5Asia 25.1 22.3Middle East-Pakistan 9.8 9.2Discontinued operations:West Africa 24.6 -Total depreciation and amortisation 95.9 68.0 2 Cost of sales 2006 2005 $ million $ millionOperating costs 44.7 100.7Royalties 10.6 7.8Amortisation and depreciation of property, plant and equipment: Oil and gas properties 70.0 66.6 Other 1.3 1.4 126.6 176.5 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 2005 0.2 17.6 9.0 14.6 41.4Additions 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 1 January 2006 1.8 26.2 13.2 26.2 67.4Additions during the year 11.5 65.3 4.3 11.5 92.6Disposals - (6.9) - - (6.9)Transfer to tangible fixed assets (0.4) - - - (0.4)Exploration expenditure written off (2.2) (0.1) (11.2) (8.3) (21.8)Reclassified as held for sale - - - (16.2) (16.2)At 31 December 2006 10.7 84.5 6.3 13.2 114.7 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 $ millionCost:At 1 January 2005 229.3 301.9 110.3 33.3 19.0 693.8Exchange 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 1 January 2006 240.6 315.3 115.3 82.5 5.4 759.1Exchange movements - - - - 0.2 0.2Additions during the year 34.5 25.0 18.6 14.5 1.2 93.8Transfer from intangible fixed 0.4 - - - - 0.4assetsReclassified as held for sale - - - (97.0) - (97.0)At 31 December 2006 275.5 340.3 133.9 - 6.8 756.5Amortisation and depreciation:At 1 January 2005 39.3 24.8 48.1 - 16.4 128.6Exchange 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 1 January 2006 74.2 47.1 57.3 - 3.9 182.5Exchange movements - - - - 0.1 0.1Charge for the year 35.3 24.9 9.8 24.6 1.3 95.9On assets reclassified as held for - - - (24.6) - (24.6)saleAt 31 December 2006 109.5 72.0 67.1 - 5.3 253.9Net book value:At 31 December 2005 166.4 268.2 58.0 82.5 1.5 576.6At 31 December 2006 166.0 268.3 66.8 - 1.5 502.6 5 Notes to the cash flow statement 2006 2005 $ million $ millionProfit before tax for the year 172.8 125.8Adjustments for:Depreciation, depletion and amortisation 95.9 68.0Exploration expense 15.3 20.6Pre-licence exploration costs 21.8 15.8Net operating charge for long-term employee benefit plans less contributions (1.9) (1.5)Share-based payment provision 3.0 2.9Release of warranty provision (2.5) -Discontinued operations (1.3) (1.2)Operating cash flows before movements in working capital 303.1 230.4Increase in inventories (1.5) (1.0)Increase in receivables (32.4) (29.3)Increase in payables 84.1 5.4Cash generated by operations 353.3 205.5Income taxes paid (116.2) (86.4)Interest payable and other finance expense 7.7 2.1Net cash from operating activities 244.8 121.2 5. Notes to the cash flow statement continued Analysis of changes in net cash/(debt) 2006 2005a) Reconciliation of net cash flow to movement in net cash/(debt): $ million $ millionMovement in cash and cash equivalents 2.1 (20.8)Proceeds from long-term loans - (25.0)Repayment of long-term loans 65.0 -Increase/(decrease) in net cash in the period 67.1 (45.8)Opening net (debt)/cash (26.2) 19.6Closing net cash/(debt) 40.9 (26.2) 2006 2005b) Analysis of net cash/(debt): $ million $ millionCash and cash equivalents 40.9 38.8Long-term debt - (65.0)Total net cash/(debt) 40.9 (26.2) 6 Basis of preparation The above financial information does not represent statutory accounts within themeaning of Section 240 of the Companies Act 1985. A copy of the statutoryaccounts for 2005 has been delivered to the Registrar of Companies and those for2006 will be delivered following the Company's Annual General Meeting. Theauditors' report on those accounts was unqualified and did not containstatements under Section 237(2) or (3) of the Act. The financial information has been prepared in accordance with the recognitionand measurement criteria of International Financial Reporting Standards (IFRS)and with IFRS adopted for use in the European Union. However, this announcementdoes not itself contain sufficient information to comply with IFRS. Theannouncement is prepared on the basis of accounting policies as stated in the2005 financial statements. The company will publish full financial statementsthat comply with IFRS on 18 April 2007. The financial information has been prepared under the historical cost basisexcept for the revaluation of financial instruments and certain properties atthe transition date to IFRS. These financial statements are presented in US$since that is the currency in which the majority of the group's transactions aredenominated. This preliminary announcement was approved by the Board on 21 March 2007. 7 Dividends The directors do not propose any dividend. 8 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 Earnings per number of shares share 2006 2005 2006 2005 2006 2005 $ $ million million million million cents centsFrom continuing operations:Basic 86.1 39.5 81.8 82.1 105.3 48.1Outstanding share options - - 0.9 0.7 * *Diluted 86.1 39.5 82.7 82.8 104.1 47.7From continuing and discontinuedoperations:Basic 67.6 38.6 81.8 82.1 82.6 47.0Outstanding share options - - 0.9 0.7 * *Diluted 67.6 38.6 82.7 82.8 81.7 46.6 \* The inclusion of the outstanding share options in the 2006 and 2005calculations produce a diluted earnings per share. The outstanding share optionsnumber includes any expected additional share issues due to future share-basedpayments. 9 Share-based payments The company currently operates an Asset and Equity plan to reward employees forimprovement in the asset value of the business and the market value of thecompany over a three-year period. The plan has two bonus pools, an equity bonuspool and an asset bonus pool. The asset bonus pool is created by reference tothe increase in the net asset value per share of the company over a three-yearperiod and the equity bonus pool is created by reference to the increase in theequity market value per share of the company over a three-year period. For the year-ended 31 December 2006, the total cost recognised by Premier forshare-based payments is US$26.4m (2005: US$6.4m). Part of this cost iscapitalised as projects and part charged to the income statement as explorationwrite off, operating costs, pre-licence expenditure or general andadministration costs. 10 External Audit This Preliminary Announcement is consistent with the audited financialstatements of the group for the year-ended 31 December 2006. 11 A full set of financial statements will be posted to shareholders on 18April 2007 and will be available at the company's head office, 23 Lower BelgraveStreet, London SW1W 0NR, from that date. 12 The Annual General Meeting will be held at Clothworkers' Hall, DunsterCourt, Mincing Lane, London, EC3R 7AH on Friday 18 May 2007 at 11.00am. Oil and gas reserves (unaudited) Group proved plus probable reserves Working interest basis North Sea Asia Middle West Total East-Pakistan Africa2 Oil and Gas Oil and Gas Oil and Gas Oil and Oil and Gas Oil, NGLs NGLs NGLs NGLs NGLs NGLs and gas mmbbls bcf mmbbls bcf mmbbls bcf mmbbls mmbbls bcf mmboeGroup:At 1 January 2006 16.5 22 5.7 337 - - 9.7 31.9 359 102.2Revisions1 1.7 (7) 0.4 24 - - (5.0) (2.9) 17 0.1Acquisitions and - - - - - - - - - -divestmentsProduction (2.3) (1) (0.7) (18) - - (0.9) (3.9) (19) (7.6)At 31 December 2006 15.9 14 5.4 343 - - 3.8 25.1 357 94.7Joint venture - groupshare:At 1 January 2006 - - - - 1.6 389 - 1.6 389 61.3Revisions1 - - - - - 4 - - 4 0.5Production - - - - (0.1) (28) - (0.1) (28) (4.4)At 31 December 2006 - - - - 1.5 365 - 1.5 365 57.4Total group and groupshare of joint ventures:At 1 January 2006 16.5 22 5.7 337 1.6 389 9.7 33.5 748 163.5Revisions1 1.7 (7) 0.4 24 - 4 (5.0) (2.9) 21 0.6Acquisitions and - - - - - - - - - -divestmentsProduction (2.3) (1) (0.7) (18) (0.1) (28) (0.9) (4.0) (47) (12.0)At 31 December 2006 15.9 14 5.4 343 1.5 365 3.8 26.6 722 152.1Total group and groupshare of joint ventures:Proved developed 8.1 10 1.5 145 1.2 214 1.5 12.3 369 74.9Proved undeveloped 1.0 - 1.9 110 - 8 0.5 3.4 118 26.1Probable developed 2.8 2 0.9 32 0.3 114 0.4 4.4 148 28.4Probable undeveloped 4.0 2 1.1 56 - 29 1.4 6.5 87 22.7At 31 December 2006 15.9 14 5.4 343 1.5 365 3.8 26.6 722 152.1 Notes: 1. Revisions include upgrades on Block A, Zarghun South, Scott andTelford fields, together with downgrades on Chinguetti and the Fife area fields. 2. The West Africa reserves relate entirely to a disposal group held forsale. 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 13.5 mmboe giving total entitlementreserves of 132.4 mmboe as at 31 December 2006 (2005: 145.9 mmboe). This wascalculated in 2006 using an oil price assumption of US$50/bbl (2005: US$40/bbl). This information is provided by RNS The company news service from the London Stock ExchangeRelated Shares:
PMO.L