13th Mar 2008 07:01
Premier Oil PLC13 March 2008 Premier Oil plc Preliminary Results for the year ended 31 December 2007 Premier is a leading FTSE 250 independent exploration and production companywith gas and oil interests in Asia, Middle East-Pakistan, the North Sea and WestAfrica. Our strategy is to add significant value through exploration andappraisal success, astute commercial deals, and asset management. Highlights Operational • Production up 8 per cent to 35.8 kboepd (2006: 33.0 kboepd) • Reserves increased by 39 per cent to 212 mmboe. Reserves and resources up 28 per cent to 369 mmboe. Reserve replacement of 460 per cent • Material progress on major development projects commercialising past exploration successes and adding value to recent acquisitions • New gas sales agreements in Singapore and Indonesia • Successful acquisitions in the UK and Indonesia adding low cost barrels at around US$2 per barrel; Scott field acquisition achieved payback by year-end • New exploration and appraisal acreage awarded in Norway and Vietnam • Significant joint venture established with Emirates International Investment Company for opportunities in the Middle East and North Africa Financial • Operating cash flow up 10 per cent to US$269.5 million (2006: US$244.8 million) • Operating profit up 35 per cent to US$219.4 million (2006: US$162.6 million) • Profit after tax of US$39.0 million (2006: US$67.6 million), after deducting non-cash hedging charges • Low cost financing in place to fund development programme of US$ 1 billion in 2008-2011 • Strong balance sheet with cash resources of US$332.0 million and net cash of US$79.0 million (2006: US$40.9 million). Undrawn facilities at year-end were US$223.8 million 2008 Outlook • Development approvals expected on three major projects during 2008 • Increasing production to meet 50,000 boepd target by end 2010 • Extensive drilling programme in Vietnam for up to 24 months • 13 well exploration and appraisal programme "Premier is extremely well placed to meet its stated production target of 50,000boepd by end 2010 from existing assets. Our focus is turning to the next phaseof growth through exploration, appraisal and acquisition." Sir David John, Chairman Simon Lockett, Chief Executive 13 March 2008ENQUIRIESPremier Oil plc Tel: 020 7730 1111Simon LockettTony DurrantJamie Bassett 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 operating results for 2007 reflect rising production and strong oiland gas prices. With success in commercialising undeveloped reserves,confidence in our growth profile is increasing. Financial and operating performance Rising oil and gas prices, notably in the second half of the year, generatedsales revenues of US$578.2 million in 2007 (2006: US$402.2 million) furtherbenefiting from strong gas demand in both Singapore and Pakistan. Average production for the year rose 8 per cent to 35,750 barrels of oilequivalent per day (boepd) (2006: 33,000 boepd). Production from the Scott field, where we increased our interest during the year to 21.8 per cent, boosted our UK production and paid back our acquisition consideration during the first six months of ownership. Operating cash flow after tax was US$269.5 million (2006: US$244.8 million) forthe year, funding all of our investments in exploration, development projectsand acquisitions completed during the year. In May 2007, a convertible debt offering of US$250 million was heavilyover-subscribed and provides seven year funding at a coupon rate of only 2.875per cent. Cash resources at 31 December 2007 were US$332.0 million (2006:US$40.9 million). Undrawn facilities at year-end were US$223.8 million. Operating profit for the year rose 35 per cent to US$219.4 million (2006:US$162.6 million). Profit before tax for the year was US$147.0 million (2006: US$156.6 million)after recognising a US$64.9 million charge representing a mark to marketrevaluation of our existing hedging arrangements. This is a non-cash chargewhich is expected to reverse out over the life of the hedges. Profit after taxand mark to market valuation charge was US$39.0 million (2006: US$67.6 million). Oil and gas proven and probable booked reserves increased to 212 million barrelsof oil equivalent (mmboe) (2006: 152 mmboe). We also increased our contingentresources by a net 20 mmboe bringing total reserves and resources to 369 mmboe(2006: 289 mmboe). Significant reserve additions included the acquisition ofthe Scott field interest and an additional 25 per cent equity in North SumatraBlock A. Reserves associated with our development project in the Natuna Sea(Gajah Baru) which commercialises previous exploration successes have beenbooked for the first time. A major achievement in 2007 was the progress made in advancing new projects bothtechnically and commercially. Agreement with gas customers in Singapore, Batamand North Sumatra has been reached on attractive terms. These projects arescheduled for final investment approvals during 2008, together with our oildevelopment in Vietnam. Our exploration programme in 2007 delivered four successes from 11 explorationand appraisal wells. The Chim Sao (formerly Blackbird) sidetrack, drilled earlyin 2007, encouraged us to move into the development stage for that project. Weare returning to Vietnam to drill the Chim Sao North appraisal well in March2008 and continue a potentially high impact programme for a further three wells.Altogether we plan around 13 exploration and appraisal wells and 18development wells in 2008. We also continue to build our programmes for futureyears with new licence awards in Norway and Vietnam, seismic surveys under wayin Norway, Vietnam and Indonesia and a two-well programme planned for Congo inlate 2008 or early 2009. Our efforts on improving our health, safety and environmental performancestandards have again resulted in us beating our internal targets. We seekcontinued improvements year-on-year in this area. For the first time ourpolicies will include a focus on carbon emission targets. Our 2007Sustainability Report will be published in April 2008. Shareholder returns During 2007, Premier shares increased in value by 6 per cent, contributing to anincrease of 352 per cent over the five year period to 31 December 2007. Thisstrong performance and the attractive returns expected from our investmentprogramme have reinforced our policy to reward shareholders principally throughshare price growth and to utilise cash flows within the business. Board changes We were pleased to announce the appointments of Michel Romieu and David Lindsellas non-executive directors in January 2008. Both have had distinguished careersin their respective fields and will provide invaluable input to the Board. Two non-executive directors, Scott Dobbie and Ron Emerson, will retire in June2008 after combined service of 15 years on the Board. We are enormouslygrateful for their outstanding contributions over a long period of time. Outlook Current production has exceeded 40,000 boepd during the early months of 2008.Significant milestones have already been achieved on our key developmentprojects. We have commercialised previous exploration successes and added toour booked reserve base. This gives us increasing confidence that ourproduction target of 50,000 boepd by the end of 2010 will be achieved. Furthersignificant progress will be made on these projects during 2008. 2008 also offers potential to add a new generation of projects with drillingcampaigns in Vietnam, Norway and Congo being planned and executed. This combination of exploration, appraisal and development projects offersshareholders a wide portfolio of growth opportunities which our strong financialposition allows us to pursue. Sir David John KCMG Chairman CHIEF EXECUTIVE'S REVIEW Production and reserves 2007 has seen key milestones in a number of our development projects. These arematerial steps forward in achieving, at a minimum, our production target of50,000 boepd by end 2010 and in growing our portfolio of four regionalbusinesses. Working interest production for 2007 averaged 35,750 boepd. Comparableproduction from 2006 was 33,000 boepd. Production comprised 34 per cent liquidsand 66 per cent gas, with Pakistan and Indonesia accounting for 36 per cent and34 per cent of the total respectively, the UK 28 per cent and West Africa theremainder. On an entitlement basis, group production for the year was 31,450boepd (2006: 28,900 boepd). Production (boepd) Working interest Entitlement 2007 2006 2007 2006Asia 12,000 11,550 7,900 7,800Middle East-Pakistan 12,700 12,150 12,700 12,150North Sea 9,850 6,850 9,850 6,850West Africa 1,200 2,450 1,000 2,100Total 35,750 33,000 31,450 28,900 As at 31 December 2007 proven and probable reserves, on a working interestbasis, based on Premier and operator estimates, were 212 mmboe. This representsa 39 per cent increase in net proven and probable reserves since 31 December2006. Proven and probable reserves Reserves and contingent resources (mmboe) (mmboe)Start of 2007 152 289Production (13) (13)Net additions and revisions 73 93End of 2007 212 369 At year-end, reserves comprised 18 per cent liquids and 82 per cent gas. Theequivalent volume on an entitlement basis amounted to 183 mmboe (2006: 132mmboe). Booked reserve additions and revisions include an increase in booked reserves inIndonesia West Natuna Sea Block A resulting from an additional Gas SalesAgreement (GSA), and the North Sumatra Block A gas development for which a GSAhas been signed with the PIM Fertilizer Plant. Significant reserve additionsalso included the acquisition of the Scott field interest. There were reservesincreases on the Kakap field in Indonesia and the Zamzama field in Pakistan. Inthe UK, a reduction in Wytch Farm reserves was offset by increased reserves onthe Kyle field. Contingent resource bookings have increased to include theBanda gas discovery in Mauritania, the Kuala Langsa gas discovery in NorthSumatra Block A, and the Bream discovery in Norway and include the Chim Sao oilfield in Vietnam where an Outline Development Plan was submitted. Thesevolumes, together with others in the process of being commercialised, giveincreased total reserves and contingent resources of 369 mmboe (2006: 289mmboe). Exploration and appraisal Premier has continued to drill up and expand its exploration portfolio during2007. It has participated in 11 exploration and appraisal wells giving foursuccesses; eight of these wells have been drilled by Premier's operations team.It has acquired new seismic data, and reprocessed old data, to generate newprospects for 2008 and subsequent drilling, and it has sought out and signed newlicences in Norway and Vietnam. Exploration spend on drilling and seismic in 2007 was US$104.7 million pre-tax(post-tax and recoveries: US$77.5 million). Costs of the exploration programmewere reduced from original estimates by prudent farmouts in the UK, India andGuinea Bissau. A focus of exploration effort in 2007 was in Vietnam on our Block 12W ProductionSharing Contract (PSC); our Chim Sao (formerly Blackbird) sidetrack, drilledearly in 2007, confirmed the down-dip extent of the 2006 Chim Sao discovery.Subsequently a large 3D survey (1600km(2)) was acquired over the block, enablingus to confirm several other prospects that are to be drilled in our 2008programme. Premier's farm-in to the adjacent block, the 07/03 PSC, was ratifiedby the Vietnamese authorities during the year, allowing us to assumeoperatorship and to accelerate the exploration of this large, under-exploredblock; a 2D survey is planned in 2008 with drilling planned for 2009. We havebeen busily building up our Vietnamese knowledge and have been granted another,previously under-explored licence, Block 104-109/05, formally signed in February2008. Premier also had an active year in Indonesia, with two discoveries, Pancing andIbu Lembu, the signing of two new blocks, the Tuna and Buton PSCs, and thepurchase of additional equity in our North Sumatra Block A acreage. These newblocks provide an exciting set of exploration prospects, and in the case of theNorth Sumatra acreage will in addition include appraisal of earlier discoveries. In Pakistan we participated in the successful Qadirpur Deep-1 well, targetinghitherto undrilled reservoir zones below the Qadirpur field. A similar well,targeting sands below the Badhra field was spudded in January 2008. Premier also drilled some high-potential but high-risk exploration wells duringthe year; in advance of drilling we prudently reduced our financial exposure byfarming out the well costs on favourable terms. These wells included Masimpurin India, Peveril in the UKCS, two wells offshore Guinea Bissau and the Annewell offshore Pakistan. In the North Sea region we evaluated new opportunities and subsequently acquirednew exploration licences: five in Norway and one in the UK. Looking ahead to 2008, the exploration focus will be in southeast Asia, where weplan to drill several exploration wells in Vietnam Block 12W that, ifsuccessful, will enhance and extend our Chim Sao development hub. We willacquire 2D seismic surveys in the contiguous Block 07/03 in Vietnam and Tuna inIndonesia, defining prospects for a 2009 drilling campaign. We will be active with the drill-bit in the North Sea where we will be targetinga shallow oil prospect in Block 23/22b in the UK having farmed out the wellcosts on favourable terms, and in Norway where an appraisal well will be drilledon the Bream oil discovery in Norway. In West Africa we have firmed up large prospects in the Congo Marine IX permitand are in the early stages of planning our first well to be drilled in late2008 or early 2009 depending on rig availability. Planned spend on exploration and appraisal drilling and seismic in 2008 isUS$110.0 million pre-tax (post-tax and recoveries: US$75.0 million). ASIA Indonesia Premier's core asset in Indonesia is in the West Natuna Sea, where it operatesthe Anoa field in Block A (28.6667 per cent interest) and is a partner in theKakap field (18.750 per cent interest). These fields supply gas under along-term sales contract to Singapore. In 2007, Premier sold an average of 137British thermal units per day (BBtud) (gross) from the Anoa field and a further66 BBtud (gross) from the non-operated Kakap field, under this agreement. Gross oil and condensate production from these two fields averaged 2,498 barrelsof oil per day (bopd) for Anoa (2006: 2,581 bopd) and 7,977 bopd for Kakap(2006: 6,998 bopd). Anoa is showing a slow natural oil decline as it matures,but with the potential for further drilling in 2009 to reverse this trend. Kakapmeanwhile has benefitted from the drilling of the Jangkar well in 2006, whichenjoyed improved performance and a full year's net production in 2007 of 1,495bopd (2006: 1,312 bopd). Overall net production from Indonesia increased to 12,000 boepd in 2007 (Anoacontributing 8,190 boepd and Kakap 3,810 boepd), compared with 11,550 boepd in2006. The improvement is attributable to increased gas demand from Singapore andincreased oil production on Kakap. On the Gajah Baru development, Premier met its 2007 goal to have definitiveagreements in place for further gas sales from Natuna Sea Block A and retainsits target to start producing this gas in 2010. Heads of Agreements were signedwith Sembcorp Gas Pte Ltd for supply of gas to Singapore and with PT PalayananListrik Nasional Batam and PT Universal Batam Energy for domestic supply of gasto Batam. Engineering work confirmed the development concept for the threefields supplying the gas, (Gajah Baru, Naga and Iguana) and a draft Plan ofDevelopment was submitted to the government. Negotiations with the Singaporebuyer were completed on 29 February 2008 and the current focus is on conclusionof ancillary agreements. Formal government approval of field development plansand award of major construction contracts are expected later in 2008. 2007 saw three exploration wells drilled in Indonesia. In Natuna Sea Block A,the Ibu Lembu-1 well was drilled to prove the hydrocarbon potential in theadjacent up-dip structure to the 2006 Lembu Peteng-1 discovery. The wellencountered gas in the primary target but following the running of an extensivedata acquisition programme was plugged and abandoned as sub-economic. Thesecond well, Gajah Sumatera-1 was drilled to appraise a potential extension tothe Gajah Puteri field in Natuna Sea Block A. While the well encountered somegas shows while drilling, wireline logs indicated that no significanthydrocarbons were encountered and the well was plugged and abandoned. Furthertechnical studies are being carried out in the area to define thehydrocarbon-bearing sand distribution proven by adjacent wells. The Pancing-1well was drilled in the Kakap Block to test a deep structure close to existinginfrastructure. The well flowed oil although at sub-economic rates, however thewell's results are significant in encountering hydrocarbons in an under-exploredplay in the area, raising the possibility of further exploration potential. 2008 exploration activities within Natuna Sea Block A will focus on maturing andhigh grading the existing prospects and leads for an anticipated 2009 drillingprogramme. Premier completed the joint acquisition with Medco of ConocoPhillips' 50 percent share of North Sumatra Block A in January 2007, bringing our interest to41.667 per cent. Negotiations to sell gas from the undeveloped Alur Siwah, AlurRambong and Julu Rayeu fields progressed well through the year culminating in aDecember signing of a Gas Sales and Purchase Agreement to two fertilizer plantsowned by PT Pupuk Iskandar Muda (PIM), a state-owned entity, for the delivery of110 BBtud for seven years. A second gas sale to Palayanan Listrik Nasional (PLN)for local electricity generation is progressing well with an expectation ofcompleting agreements in the first quarter of 2008. Development studies wereongoing through the year with a Plan of Development submitted in December.Project sanction is anticipated by mid-2008. Technical studies including field mapping and sampling took place on the ButonPSC on the south-eastern side of Buton Island, Sulawesi, with the aim of firmingup multiple leads originally identified from satellite imagery. Towards the endof the year a contract was awarded for the acquisition of 265km of 2D seismicdata across the block. The survey commenced in January 2008 and is expected totake approximately six months to complete. The data will help to high grade theacreage and focus on identifying a high impact drilling opportunity for 2009.Premier has a non-operated 30 per cent equity interest in the block. In March Premier was awarded a 65 per cent operating equity interest in the TunaPSC in the North East Natuna Sea. The block covers 4,992km2 and lies south ofPremier's operated Block 07/03 and Block 12W in Vietnam and to the east of theNatuna Sea Block A and Kakap PSCs in Indonesia. The Tuna PSC represents anunderexplored area in the middle of a region in which Premier has a strongtechnical understanding. Multiple leads have been identified which will befollowed up in 2008 with the acquisition of new seismic data leading to thedrilling of two wells on the block. Vietnam Following the discovery of the Chim Sao (Blackbird) and Dua oil fields in 2006,Premier acquired and interpreted 3D seismic data in the first half of 2007. Thedevelopment plan is to produce first oil in 2010 from two wellhead platforms onthe Chim Sao field with production from a third wellhead platform on the Duafield following in 2011. Oil will be processed and stored on a leased FPSOfacility located between the fields. During December, Premier submitted reservereports and development plans for these fields to the Government of Vietnam. TheReserve Assessment Report was approved on 4 March 2008. Approval of thedevelopment plan is targeted for mid-2008. During 2007 Premier and the Government of Vietnam agreed the merger of Block 12Einto Block 12W and extension of the exploration period of the merged PSC untillate 2009. Detailed interpretation of the 3D seismic data acquired in 2007defined several exploration prospects. These will be drilled with the Wilbossjack-up rig; drilling commencing in mid-March 2008 with a well in the northernpart of the Chim Sao field. The rig will then drill three exploration wellsincluding the Chim Ung (Falcon) well which will test a prospect on trend withChim Sao and the high impact Chim Cong (Peacock) prospect. The programme willtarget reserves in excess of 200 mmbbls with the ability to tie-back discoveriesinto the core Chim Sao development. Premier operates a 37.5 per cent explorationworking interest in Block 12W. During 2007 Premier assumed the operatorship of Block 07/03 (formerly Block 7&8/97) with a 45 per cent exploration working interest. A comprehensiveinterpretation of the existing seismic data identified several potentiallyhigh-impact prospects over which further seismic will be acquired in 2008.Premier is actively seeking a drilling unit to drill exploration wells in Block07/03 during 2009. India In India, discussions continue with the Government of India to resolveoutstanding issues with respect to the Ratna field development. The Ratna fieldslie in shallow water offshore Mumbai and are estimated to contain around 80million barrels (mmbbls). Premier has a 10 per cent carried interest and is theoperator. The Masimpur-3 well in Cachar was successfully drilled with costs being carriedin part. The well did not flow commercial gas or oil volumes during testing andwas plugged and abandoned. The PSC will now terminate since no commercialdiscovery has been made during the Exploration Period. Philippines Premier entered 2007 holding a 42.5 per cent operated participating interest inPhilippines licence SC43 located in the Ragay Gulf area of SE Luzon. During thecourse of the year Premier farmed-out the operatorship of SC43 and a 21.5 percent participating interest, leaving Premier with a 21 per cent participatinginterest. In exchange for this consideration all of Premier's costs relating tothe Monte Cristo-1 exploration well, which is expected to be drilled in thefirst half of 2008, will be carried. In the fourth quarter of 2007 a 371km 2Dmarine seismic survey was carried out on the same licence over a prospectivetrend in the Panaon Limestone formation. This data is currently beingprocessed. MIDDLE EAST-PAKISTAN Pakistan Production in 2007 surpassed the previous record levels achieved in 2006.Production net to Premier in 2007 was 12,700 boepd, an increase of 5 per cent onlast year (2006: 12,150 boepd). This additional volume was due to increased gasdemand and was primarily met through additional supply from the Zamzama field. Qadirpur produced an average of 3,980 boepd from Premier's net interest of 4.75per cent (2006: 3,870 boepd). The project to enhance Qadirpur plant capacityfrom 500 million standard cubic feet per day (mmscfd) to 600 mmscfd continuedduring 2007 and first gas from that increased capacity is expected by the end ofApril 2008. In addition to the above, negotiations are ongoing with the existinggas buyer for an additional supply of 75 mmscfd permeate gas (equivalent to 40mmscfd processed gas) for subsequent use in power generation. First gas isexpected in 2010. The Qadirpur Deep-1 well was drilled to a depth of 4,681metres in 2007 encountering hydrocarbons in several zones. The well wassuspended following higher than anticipated temperatures and pressures.Specialised equipment has since been ordered and testing of the well is expectedto resume in the second quarter of 2008. On Kadanwari, the K-18 well was drilled and tested successfully during 2007, andbrought onstream in February 2008. Additional production from K-18 will morethan compensate for the natural field decline in 2008. In 2007 the fieldproduced an average of 1,260 boepd (2006: 1,200 boepd) from Premier's 15.79 percent net interest. An additional well is planned to be drilled in the secondhalf of 2008. Zamzama produced an average of 4,620 boepd in 2007 (2006: 4,140 boepd), fromPremier's 9.375 per cent interest. Work continued in 2007 on the Zamzama Phase 2development project, to produce gross 150 mmscfd High Calorific Value (HCV) gasfor sale, but plant problems mean that only Medium Calorific Value (MCV) gas cancurrently be supplied. HCV deliveries are expected to be achieved later in 2008. Bhit production was 2,840 boepd in 2007 (2006: 2,940 boepd) from Premier's 6 percent working interest. The slight fall in production in 2007 was due to anextended shut down for Phase 2 tie-in work. Work on the Phase 2 project toenhance Bhit plant capacity to 315 mmscfd is now complete allowing acceleratedBhit field production and delivery of first gas from Badhra reserves. The Badhra South-1 well spudded in January 2008 to prove additional reserves inthe Mughalkot reservoir. In the event of success, the well will be deepened totest three identified sand lobes. The well is expected to complete in the thirdquarter of 2008. On Zarghun South, negotiations on the Pipeline Tariff Agreement were concludedwith the gas buyer (a condition precedent for the already agreed GSA). First gasis planned for the first quarter of 2010. Premier's interest of 3.75 per cent inthis asset is carried by the operator during the development and productionphases of the field. Egypt In October 2007 Premier reduced its equity in the Northwest Gemsa Concessionfrom 37.5 per cent to 10.0 per cent resulting in a reimbursement of someprevious costs from the operator. During the latter part of the year, theoperator conducted geological studies to define the SE Al Amir prospect which isscheduled for drilling in March 2008. Abu Dhabi Shareholder agreements were executed in December with Emirates InternationalInvestment Company LLC (EIIC), forming two new joint venture companies. Thesecompanies will pursue the acquisition of upstream oil and gas assets across theMiddle East and North Africa, and will be headquartered in Abu Dhabi. The first joint venture, to be known as PREMCO, will be owned 49 per cent byPremier and 51 per cent by EIIC and will hold all joint venture assets which areacquired in the U.A.E. In the event of a change of control of Premier, EIICwill have a pre-emptive right to purchase Premier's 49 per cent of this jointventure at fair market value. The second joint venture, to be known as PREMBV, will be owned 50 per cent byPremier, 50 per cent by EIIC, and will hold all joint venture assets which areacquired in the Middle East and North Africa (excluding the U.A.E). At the formation of the joint ventures, there will be no assets or profitsattributable to these new entities. Future acquisitions of new assets by eachjoint venture will be funded by Premier and EIIC in accordance with theirrelevant percentage holding. This joint venture partnership will enable Premier to access acquisitionopportunities across the Middle East and North Africa via EIIC's relationshipnetworks, whilst EIIC will benefit from Premier's industry expertise andoperating capabilities. NORTH SEA During 2007, Premier continued with its stated strategy of building the NorthSea exploration portfolio to seek high-impact exploration drilling opportunitieswhile maximising the value from existing production and development assets. UK Production in the UK amounted to 9,850 boepd (2006: 6,850 boepd) representing 28per cent of the group total (21 per cent in 2006). The increase, compared to2007, is due to a combination of improved field performance across most of theproducing assets and the impact of the Scott field acquisition completed on 17May 2007. The Wytch Farm oil field contributed 2,960 boepd net production to Premier, down8 per cent on last year. Production was adversely impacted by problems with theM19 well, offset by an A08 sidetrack well which was drilled and completed inSeptember. Drilling is continuing on the M20 water injection well, to becompleted in 2008 as part of the Phase 1 water handling project. Seawaterinjection service was also reinstated after a prolonged outage. The shortfall inproduction due to the drilling problems was partly compensated by better thanexpected production rates from the remaining wells and successful workoveractivities. Net production from Kyle was 2,470 boepd, an improvement of 26 per cent on lastyear from better well performance. The gas lift project was completed for allfour production wells resulting in a substantial boost in production withinitial gross rates around 9,000 boepd. The K-16 well has been delayed to atleast 2009 pending further evaluation. Premier completed the purchase of an additional 20.05 per cent equity in theScott field in May 2007 adding an average of 5,240 boepd net over the remainderof the year. As a result of this transaction, Premier's working interest hasbecome 21.83 per cent. The Scott field gross production for the year was 27,750boepd; this amounted to a full year average of 3,630 boepd net to Premier at thecombined equity levels. Telford produced slightly below expectations during 2007 following disappointingresults from the Marmion well; gross field production averaged 9,560 boepd (70boepd net to Premier). 2007 saw the completion of a substantial infill drillingprogramme consisting of six wells on Scott and one well on Telford. Futuretargets are being evaluated for a further campaign starting in the fourthquarter of 2008. In the Fife Area, Premier's net production amounted to 720 bopd, belowexpectation due to major integrity issues with the flexible risers. Theoperator has made a recommendation to suspend production in May 2008 and removethe Uisge Gorm floating production unit. Premier has retained the right toredevelop the area with an alternative facility. Premier operated the Peveril prospect well, located only 10km south of the Fifefield, which was completed within AFE at no cost to Premier. The Peveril wellencountered an unexpectedly thick interval Kimmeridge Clay and no target Fifereservoir sands. In the UK 24th Licensing Round, Premier was awarded a split portion of 15/24a.The firm work programme includes seismic reprocessing and study work. In February 2008, agreement was reached with Oilexco for a well to be drilled onthe Sparrow prospect, on P1181. This will be spudded imminently. Oilexco willcarry Premier through the well and Premier will retain a 25 per cent interestpost completion. Norway On the Froy field in Norway, development planning is progressing. Followingconcept selection in September, lease/purchase bids were sought for the jack-upproduction drilling storage and offtake unit. These show significant increaseson previous budgetary estimates submitted by suppliers; the operator has beenrequested to implement a major cost reduction exercise to bring investment downto an acceptable level. The operator is also investigating third-party businessopportunities and exploration upside to improve the robustness of the project aswell as tackling other key issues such as contract guarantees. The partnership issued a Declaration of Continuation at the beginning ofJanuary; submission of the Plan of Development is expected during 2008 providedviability of the chosen concept can be confirmed. Premier was awarded a further five licences in the APA Licensing Round inJanuary 2007. Building on the APA 2005 portfolio Premier was successful incapturing two of the most sought after blocks in the 2006 APA round: the Breamappraisal licence and the adjacent Bream exploration licence, PL407 and PL406respectively. The Bream field was initially discovered in 1971 but nodevelopment decision was reached. Interpretation of the 2005 PGS 3D datasetacross the structure suggests that between 60-80 mmbbls reserves may be present.The planning for the commitment appraisal well is at an advanced stage and isscheduled to be drilled in the first half of 2008. The exploration licence adjacent to Bream is Premier's first operated licence inNorway. This has potential to add between 100-250 mmbbls reserves to the provenBream accumulation. Premier will be acquiring 500km2 of new 3D across the PL406licence in March 2008 using PGS's Ramform Sovereign vessel with a firm well onPL406 planned for mid-2009. The three other licences Premier was awarded were PL418 and PL419, down dip fromthe Gjoa discovery and PL417 adjacent to our existing licence PL378. WEST AFRICA Mauritania Chinguetti production averaged 14,800 boepd (1,200 boepd net to Premier) in2007. Drilling of the Chinguetti-18 well was completed in the first quarter of2007, in line with expectations, and a work-over was conducted on Chinguetti-14.Operational planning was progressed for Phase 2B development of Chinguetti in2008 comprising two new production wells and three work-overs. High resolution 3D seismic surveys were recorded over the Chinguetti and Tiofareas in 2007. Integration of newly acquired data into existing field models iscurrently being finalised. A 4D seismic survey was also recorded over theChinguetti field, which greatly assists selection of production well locationsfor the Phase 2B development programme. In 2007, Premier terminated discussions with a preferred bidder for itsMauritanian operations. In late 2007, Petronas acquired Woodside Energy'sassets, and operatorship, in Mauritania PSC A, PSC B and Chinguetti.Opportunities and development options on PSCs A and B continue to be evaluatedwith the new operator. The PSC B joint venture plans to drill the Banda-NW wellin April 2008 with the objective of further defining Banda gas and oilresources, and to assess its commercial viability. In addition Tiof will bere-evaluated with integration of 2007 high resolution 3D seismic data with anexpectation of progressing this discovery to a development decision. The jointventure will re-assess the exploration potential of the blocks during 2008. The Atwood Hunter drilling rig has been contracted for the Chinguetti Phase 2Band Banda-NW appraisal programme, which is expected to commence in April 2008and to be concluded by August 2008. Guinea Bissau Premier operated a two-well exploration programme during the first half of theyear, using the Global SantaFe jack-up rig 'Baltic'. The wells were completedwithin budget and without incident. Premier reduced its exposure to thedrilling costs by farming-out some of its interests. The Espinafre-1 well was plugged and abandoned on 23 March 2007 afterencountering hole stability problems. The Eirozes-1 well was plugged andabandoned on 24 April 2007. This well encountered a significant reservoirsection but no hydrocarbons. Following post-well analyses and re-assessment of the remaining prospectivity ofthe Sinapa and Esperanca Permits, Premier effectively withdrew from bothconcessions in Guinea Bissau in December 2007. Gabon The Themis Permit (non-operated) is located in the Gamba play fairway, offshoresouthern Gabon. The Themis PSC joint venture commenced drilling the ThemisAdmiral Marin-1 (THAM-1) well in December 2007; the well was plugged andabandoned with hydrocarbon shows on 13 January 2008. The Dussafu Permit (non-operated) is located south of Themis, adjacent to theCongolese border. The PSC was extended in to a Second Exploration Termeffective May 2007, with a 2D seismic commitment. In December 2007, Premiersigned a Sales and Purchase Agreement with a qualified party to acquirePremier's 25 per cent participating interest in the Dussafu PSC. Thetransaction was completed on 8 March 2008. Congo Significant progress has been made in the evaluation of the deep water MarineBlock IX exploration acreage. Premier, as operator, has conducted a detailedevaluation of Albian 'raft' prospectivity, the characteristic proven play in thearea. This has identified the Frida and Ida prospects, both in excess of 250mmbbls gross potential. The joint venture is also mapping the potential ofTertiary channel sands that have proven productive in the adjacent Haute Merconcession. Premier and its joint venture partner are actively progressing planning for adiscretionary drilling programme of up to two wells in late 2008 or early 2009.Completion of this programme is subject, among other issues, to rigavailability. Premier is in advanced discussions with a party to farm-in toPremier's equity interest in Marine Block IX in return for a carry of its costs. 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. FINANCIAL REVIEW Economic environment 2007 was another year of record oil and gas commodity prices approaching US$100per barrel (bbl) towards the end of the year. The Brent oil price, which beganthe year at US$60.1/bbl, averaged US$72.7/bbl reaching a peak of US$95.8/bblduring November. Gas prices worldwide were also boosted according to the degreeof linkage with crude oil. The early part of 2008 has seen increased volatilityin commodity prices. The fragile health of the global economy has put downwardpressure on average 2008 prices but this has been more than offset by supplyconcerns and average 2008 prices are currently above US$90/bbl. The sustained period of stronger commodity prices and increased industryactivity levels has put further pressure on both operating and developmentcosts. Rig rates and other drilling service costs are at historically highlevels. Shortages of experienced staff and longer lead times for developmentequipment added further cost pressures on the industry. The industry isresponding to cost and availability issues by optimising the use of availableresources, innovative resource-sharing and focussing on fast track developmentsolutions. Income statement Production levels in 2007, on a working interest basis, averaged 35,750 boepdcompared to 33,000 boepd in 2006. On an entitlement basis, which allows foradditional government take under the terms of our PSCs, production was 31,450boepd (2006: 28,900 boepd). Realised oil prices averaged US$72.3/bbl comparedwith US$64.9/bbl in the previous year. Gas production averaged 135 mmscfd (23,500 boepd) during the year orapproximately 66 per cent of total production. Average gas prices for the groupwere US$5.60 per thousand standard cubic feet (mscf) (2006: US$5.11/mscf). Gasprices in Singapore, which are linked to High Sulphur Fuel Oil (HSFO), havemoved broadly in line with crude pricing, averaging US$11.30/mscf (2006: US$9.43/mscf) during the year. Following the group's decision to terminate discussions with a preferred bidder,the financial results for Mauritanian operations are no longer required to bepresented separately. The corresponding amounts for 2006 have been re-presentedaccordingly. During the year, the group also restructured its business inPakistan by de-merging interests from the Premier-Kufpec Pakistan joint ventureand now fully consolidates its share of operations in Pakistan. Thisrestructuring had no impact on the consolidated financial statements. Total sales revenue from all operations was 44 per cent higher than 2006 atUS$578.2 million (2006: US$402.2 million) as a result of higher production andcommodity prices. Cost of sales was US$267.5 million (2006: US$179.2 million) after including acost of US$26.8 million for inventory acquired with the Scott field acquisition.The year-end inventory position moved from a stock overlift to an underliftposition, driven by the timing of liftings around each year-end, and resultingin a charge to cost of sales of US$27.3 million (2006: credit of US$22.4million). After excluding the effect of inventory movements, underlying unitoperating costs were higher at US$9.0 per barrel of oil equivalent (boe) (2006:US$7.1/boe) due to one-off cost increases in Indonesia and increased productionfrom the Scott field in the North Sea. Unit amortisation amounted to US$8.2/boe(2006: US$7.9/boe). Exploration expense and pre-licence exploration costsamounted to US$65.3 million (2006: US$21.8 million) and US$8.3 million (2006:US$21.8 million) respectively, after taking into account a US$25.7 millionwrite-down of costs in Guinea Bissau. Administrative costs were stable at US$17.7 million (2006: US$16.8 million).This includes a charge of US$4.7 million (2006: US$5.7 million) in respect ofcurrent year and future provisions for long-term incentive plans. Operating profits were US$219.4 million, a 35 per cent increase from the prioryear. Finance charges net of interest income totalled US$7.5 million (2006:US$4.0 million). Pre-tax profits were US$147.0 million (2006: US$156.6million). This included a significant non-cash item relating to mark to marketrevaluation of the group's oil and gas hedges totalling US$64.9 million (pretax). Such accounting losses arise as oil and gas prices increase. However,given the current range of spot and forward prices, it is not expected that thehedging programme will have any material cash flow impact on the group. Thetaxation charge totalled US$108.0 million (2006: US$89.0 million) due tounderlying higher taxable profits. Basic earnings per share amounted to 47.6cents (2006: 82.6 cents). Cash flow Cash flow from operating activities, before movements in working capital,amounted to US$408.1 million (2006: US$310.8 million). After working capitalitems and tax payments, cash flow from operating activities amounted to US$269.5million (2006: US$244.8 million). Capital expenditure was US$261.2 millionafter inclusion of asset acquisition costs of US$88.6 million. Capital Expenditure (US$ million) 2007 2006Fields/developments 65.7 88.7Exploration 104.7 49.6Acquisitions 88.6 17.0Other 2.2 1.2Total 261.2 156.5 The principal development projects were the Kyle gas lift project in the UK, theWest Lobe development in Indonesia and the Zamzama Phase 2 development inPakistan. Exploration costs of US$104.7 million take into account savings ofUS$30.9 million due to farm-outs in Guinea Bissau, the UK and India. Net cash position Net cash at 31 December 2007 amounted to US$79.0 million (2006: net cash ofUS$40.9 million) following the successful completion of a US$250 millionconvertible bonds issue in June. This funding provides seven-year fixed ratedebt at a cash coupon of 2.875 per cent and, together with our undrawn bankfacilities, contributes substantially towards the financing of Premier'ssignificant development programme over the next three years. Net cash (US$ million) 2007 2006Cash and cash equivalents 332.0 40.9Convertible bonds* (200.0) -Other long-term debt** (53.0) -Net (debt)/cash 79.0 40.9 * Excluding unamortised issue costs and allocation to equity ** Excluding unamortised issue costs Hedging and risk management The Board's policy remains to lock in oil and gas price floors for a portion ofexpected future production at a level which protects the cash flow of the groupand the business plan. Such floors are purchased for cash or by selling callsat a ceiling price when market conditions are considered favourable. Alltransactions are matched as closely as possible with expected cash flows to thegroup; no speculative transactions are undertaken. During 2007 zero cost collar oil hedges for a further 2.4 mmbbls were enteredinto by extending the maturity of the collars to the end of 2012. This increasedthe average floor price from US$38.55/bbl to US$39.3/bbl whilst maintaining thecap at US$100/bbl. During 2007 hedges for 1.8 mmbbls matured for which no cashsettlement under the terms of the collars was made. At the end of 2007 a fourand a half-year physical offtake agreement for the sale of certain oilproduction was entered into with effect from 1 July 2008. This agreement for 8.1mmbbls incorporates the parameters of existing oil collars and effectivelyreplaces the equivalent amount of hedging. In addition, zero cost collars for a further 150,000 metric tonnes of HSFO wereentered into which raised the average floor price from US$245 to US$250 permetric tonne whilst maintaining the cap at US$500 per metric tonne. During 2007hedges for 120,000 metric tonnes matured for which a small payment under theterms of the hedges was made during the year. At the end of 2007 a total of642,000 metric tonnes of HSFO was hedged (approximately 120,000 metric tonnesper annum) representing approximately one third of Indonesian gas production,until June 2013. Under International Financial Reporting Standards (IFRS) IAS 39, zero costcollar hedges are required to be marked to market at the balance sheet date.The aggregate valuation is a US$65.2 million liability (2006: US$0.3 millionliability) generating a US$64.9 million non-cash pre-tax charge in the 2007income statement. The entry into the physical offtake agreement for oilproduction from 1 July 2008 will reduce the volatility of mark to marketrevaluations on the income statement. The existing US$37.8 million provision inrespect of oil hedges will be written back to the income statement over the lifeof these hedges. 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 loss of US$0.4 million on such hedgingat year-end. Cash balances are invested in short-term bank deposits, AAA managed liquidityfunds and A1/P1 commercial paper subject to Board approved limits. The group undertakes an insurance programme to reduce the potential impact ofthe physical risks associated with its exploration and production activities.In addition, business interruption cover is purchased for a proportion of thecash flow from producing fields. CONSOLIDATED INCOME STATEMENT 2007 2006 $ million $ millionSales revenues 578.2 402.2Cost of sales (267.5) (179.2)Exploration expense (65.3) (21.8)Pre-licence exploration costs (8.3) (21.8)General and administration costs (17.7) (16.8)Operating profit 219.4 162.6 Interest revenue, finance and other gains 10.7 2.0Finance costs and other finance expenses (18.2) (6.0)Mark to market revaluation on commodity hedges (64.9) (2.0)Profit before tax 147.0 156.6 Tax (108.0) (89.0)Profit after tax 39.0 67.6 Earnings per share (cent): Basic 47.6 82.6 Diluted 46.9 81.7 These results relate entirely to continuing operations. Certain operationspreviously presented as discontinuing in 2006 have been re-presented ascontinuing operations and 2006 comparatives have been restated accordingly. STATEMENT OF TOTAL RECOGNISED INCOME AND EXPENSES 2007 2006 $ million $ millionCurrency translation differences 4.1 0.3Pension costs - actuarial gains 0.1 1.4Net gains recognised directly in equity 4.2 1.7Profit for the year 39.0 67.6Total recognised income 43.2 69.3 RECONCILIATION TO NET ASSETS 2007 2006 $ million $ millionNet assets at 1 January 449.1 376.1Total recognised income 43.2 69.3Provision for share-based payments 7.8 3.0Issue of Ordinary Shares 1.0 0.7Equity component of convertible bonds issued 48.8 -Transfer between reserves 3.0 -Net assets at 31 December 552.9 449.1 CONSOLIDATED BALANCE SHEET 2007 2006 $ million $ millionNon-current assets:Intangible exploration and evaluation assets 153.3 114.7Property, plant and equipment 739.5 502.6Investments in associates 0.1 - 892.9 617.3Current assets: Inventories 22.5 14.8Trade and other receivables 266.7 174.4Cash and cash equivalents 332.0 40.9Assets held for sale - 90.4 621.2 320.5Total assets 1,514.1 937.8 Current liabilities:Trade and other payables (252.6) (169.6)Current tax payable (73.1) (52.4)Liabilities directly associated with assets held for sale - (14.2) (325.7) (236.2)Net current assets 295.5 84.3Non-current liabilities:Convertible bonds (195.6) -Other long-term debt (52.1) -Deferred tax liabilities (194.5) (194.1)Long-term provisions (147.2) (49.6)Long-term employee benefit plan deficits (8.2) (8.8)Deferred revenue (37.9) - (635.5) (252.5)Total liabilities (961.2) (488.7) Net assets 552.9 449.1 Equity and reserves: Share capital 73.5 73.3Share premium account 9.4 8.6Revenue reserves 415.5 365.6Capital redemption reserve 1.7 1.7Translation reserves 4.0 (0.1)Equity reserve 48.8 - 552.9 449.1 The financial statements were approved by the Board of Directors and authorisedfor issue on 12 March 2008. CONSOLIDATED CASH FLOW STATEMENT 2007 2006 $ million $ millionNet cash from operating activities 269.5 244.8Investing activities:Capital expenditure (261.2) (156.5)Pre-licence exploration costs (8.3) (21.8)Proceeds from disposal of intangible exploration and evaluation assets 1.0 2.6Net cash used in investing activities (268.5) (175.7) Financing activities:Issue of Ordinary Shares 1.0 0.7Issue of convertible bonds 250.0 -Issue costs for the convertible bonds (5.9) -Loan drawdowns 53.0 -Repayment of long-term financing - (65.0)Interest paid (9.3) (2.7)Net cash from/(used in) financing activities 288.8 (67.0) Currency translation differences relating to cash and cash equivalents 1.3 -Net increase in cash and cash equivalents 291.1 2.1 Cash and cash equivalents at the beginning of the year 40.9 38.8Cash and cash equivalents at the end of the year 332.0 40.9 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. Sales revenue represents amountsinvoiced, exclusive of sales-related taxes, for the group's share of oil and gassales. 2007 2006 $ million $ millionRevenue: North Sea 280.5 119.3Asia 180.2 149.9 Middle East-Pakistan 91.8 89.6West Africa 25.7 43.4Total group sales revenue 578.2 402.2Interest and other finance revenue 10.0 2.0Total group revenue 588.2 404.2ResultsGroup operating profit/(loss):North Sea 105.2 54.3Asia 101.6 91.4Middle East-Pakistan 47.1 50.2West Africa (26.5) (17.5)Unallocated* (8.0) (15.8)Group operating profit 219.4 162.6Interest revenue, finance and other gains 10.7 2.0Finance costs and other finance expenses (18.2) (6.0)Mark to market revaluation on commodity hedges (64.9) (2.0)Profit before tax 147.0 156.6Tax (108.0) (89.0)Profit after tax 39.0 67.6Balance sheetSegment assets:North Sea 404.4 234.1Asia 514.8 450.4Middle East-Pakistan 123.4 108.9West Africa 101.5 102.9Unallocated* 369.9 41.4Investment in associates:West Africa 0.1 0.1Total assets 1,514.1 937.8 Liabilities:North Sea (282.6) (178.7)Asia (187.9) (206.8)Middle East-Pakistan (46.3) (28.4)West Africa (20.4) (21.5)Unallocated* (424.0) (53.3)Total liabilities (961.2) (488.7) Other information Capital additions:North Sea 203.1 46.7Asia 107.7 90.8Middle East-Pakistan 19.9 22.9West Africa 37.8 26.0Total capital additions 368.5 186.4 1 Geographical segments continued 2007 2006 $ million $ millionDepreciation and amortisation:North Sea 53.2 36.4Asia 30.3 25.1Middle East-Pakistan 12.3 9.8West Africa 12.1 24.6Total depreciation and amortisation 107.9 95.9 * Unallocated expenditure, assets and liabilities include amounts of a corporatenature and not specifically attributable to a geographical segment. These itemsinclude cash, hedging, tax, convertible bonds, and other long-term debt. 2 Cost of sales 2007 2006 $ million $ millionOperating costs 116.8 83.2Stock overlift/underlift movement* 27.3 (22.4)Royalties 15.5 14.4Amortisation and depreciation of property, plant and equipment:Oil and gas properties 106.9 94.6Other 1.0 1.3Impairment of property, plant and equipment - 8.1 267.5 179.2 * Includes US$26.8 million of stock acquired with the Scott field acquisition. 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 2006 1.8 26.2 13.2 26.2 67.4 Additions 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 1 January 2007 10.7 84.5 6.3 13.2 114.7 Reclassified as no longer held for sale - - - 16.2 16.2Exchange movements 1.0 - - - 1.0Additions during the year 31.1 90.2 6.8 28.3 156.4Disposals - - - (2.5) (2.5)Transfer to tangible fixed assets - (67.2) - - (67.2)Exploration expenditure written off (6.6) (18.5) (13.1) (27.1) (65.3)At 31 December 2007 36.2 89.0 - 28.1 153.3 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 2006 240.6 315.3 115.3 82.5 5.4 759.1 Exchange 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 1 January 2007 275.5 340.3 133.9 - 6.8 756.5 Reclassified as no longer held for - - - 97.0 - 97.0saleExchange movements - - - - 0.1 0.1Additions during the year 170.4 17.1 12.9 9.5 2.2 212.1Disposals - - - - (0.1) (0.1)Transfer from intangible fixed - 67.2 - - - 67.2assetsAt 31 December 2007 445.9 424.6 146.8 106.5 9.0 1,132.8 Amortisation and depreciation: At 1 January 2006 74.2 47.1 57.3 - 3.9 182.5 Exchange movements - - - - 0.1 0.1Charge for the year 35.3 24.9 9.8 24.6 1.3 95.9Reclassified as held for sale - - - (24.6) - (24.6)At 1 January 2007 109.5 72.0 67.1 - 5.3 253.9 Reclassified as no longer held for - - - 31.7 - 31.7saleExchange movements - - - - (0.1) (0.1)Charge for the year 52.4 30.1 12.3 12.1 1.0 107.9Disposals - - - - (0.1) (0.1)At 31 December 2007 161.9 102.1 79.4 43.8 6.1 393.3 Net book value: At 31 December 2006 166.0 268.3 66.8 - 1.5 502.6 At 31 December 2007 284.0 322.5 67.4 62.7 2.9 739.5 5 Convertible bonds In June 2007, the group issued bonds at a par value of US$250 million which areconvertible into Ordinary Shares of the company at any time from 6 August 2007until six days before their maturity date of 27 June 2014. At the initialconversion price of £15.82 per share there are 8,003,434 Ordinary Shares of thecompany underlying the bonds. If the bonds have not been previously purchasedand cancelled, redeemed or converted, they will be redeemed at par value on 27June 2014. Interest of 2.875 per cent per annum will be paid semi-annually inarrears up to that date. The net proceeds received from the issue of the convertible bonds were splitbetween a liability element and an equity component at the date of issue. Thefair value of the liability component was estimated using the prevailing marketinterest rate for similar non-convertible debt. The difference between theproceeds of issue of the convertible bonds and the fair value assigned to theliability component, representing the embedded option to convert the liabilityinto equity of the group, was included in equity reserves. Issue costs were apportioned between the liability and equity components of theconvertible bonds based on their relative carrying amounts at the date of issue.The portion relating to the equity component was charged directly againstequity. $ millionNominal value of convertible bonds issued net of issue costs 244.0Equity component (51.8)Liability component at date of issue 192.2Interest charged 7.0Interest paid (3.6)Total liability component as at 31 December 2007 195.6 5 Convertible bonds continued The total interest charged for the year has been calculated by applying aneffective annual interest rate of 6.73 per cent to the liability component forthe period since the bonds were issued. The non-cash accrual of interest willincrease the liability component (as the cash interest is only paid at 2.875 percent) to US$250 million at maturity. There is no material difference between the carrying amount of the liabilitycomponent of the convertible bonds and their fair value. This fair value iscalculated by discounting the future cash flows at the market rate. 6 Notes to the cash flow statement 2007 2006 $ million $ millionProfit before tax for the year 147.0 156.6Adjustments for:Depreciation, depletion, amortisation and impairment 107.9 104.0Exploration expense 65.3 21.8Pre-licence exploration costs 8.3 21.8Net operating charge for long-term employee benefit plans less contributions (0.6) (1.9)Share-based payment provision 7.8 3.0Interest payable and other finance expenses 83.1 8.0Interest revenue, finance and other gains (10.7) -Release of warranty provision - (2.5)Operating cash flows before movements in working capital 408.1 310.8Increase in inventories (7.1) (1.5)Increase in receivables (43.7) (32.4)(Decrease)/increase in payables (4.5) 84.1Cash generated by operations 352.8 361.0Income taxes paid (90.3) (116.2)Interest income received 7.0 -Net cash from operating activities 269.5 244.8 Analysis of changes in net cash 2007 2006a) Reconciliation of net cash flow to movement in net cash: $ million $ millionMovement in cash and cash equivalents 291.1 2.1Proceeds from long-term loans (53.0) -Repayment of long-term loans - 65.0Proceeds on issue of convertible bonds - debt portion (200.0) -Increase in net cash in the period 38.1 67.1Opening net cash/(debt) 40.9 (26.2)Closing net cash 79.0 40.9 2007 2006b) Analysis of net cash: $ million $ millionCash and cash equivalents 332.0 40.9Long-term debt* (253.0) -Total net cash 79.0 40.9 * The carrying value of the convertible bonds and the other long-term debt onthe balance sheet are stated net of the unamortised portion of the issue costs(US$4.4 million) and debt arrangement fees (US$0.9 million) respectively. 7 Basis of preparation The above financial information does not represent statutory accounts within themeaning of Section 240 of the Companies Act 1985. A copy of the statutoryaccounts for 2006 has been delivered to the Registrar of Companies and those for2007 will be delivered following the Company's Annual General Meeting (AGM). Theauditors' report on those accounts was unqualified and did not containstatements under Section 237(2) or (3) of the Act. The financial information has been prepared in accordance with the recognitionand measurement criteria of International Financial Reporting Standards (IFRS)and with IFRS adopted for use in the European Union. However, this announcementdoes not itself contain sufficient information to comply with IFRS. Theannouncement is prepared on the basis of accounting policies as stated in the2006 financial statements. The company will publish full financial statementsthat comply with IFRS on 25 April 2008. The financial information has been prepared under the historical cost basisexcept for the revaluation of financial instruments and certain properties atthe transition date to IFRS. These financial statements are presented in US$since that is the currency in which the majority of the group's transactions aredenominated. This preliminary announcement was approved by the Board on 12 March 2008. 8 Dividends The directors do not propose any dividend. 9 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 2007 2006 2007 2006 2007 2006 $ $ million million cent cent million millionBasic 39.0 67.6 82.0 81.8 47.6 82.6Outstanding share options - - 1.2 0.9 * *Diluted 39.0 67.6 83.2 82.7 46.9 81.7 \* The inclusion of the outstanding share options in the 2007 and 2006calculations produces a diluted earnings per share. The outstanding shareoptions number includes any expected additional share issues due to futureshare-based payments. At 31 December 2007 8,003,434 (2006: nil) potentialOrdinary Shares in the company that are underlying the company's convertiblebonds and that may dilute earnings per share in the future have not beenincluded in the calculation of diluted earnings per share because they are anti-dilutive for the year to 31 December 2007. 10 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 2007, the total cost recognised by Premier forshare-based payments is US$15.7 million (2006: US$26.4 million). Part of thiscost is capitalised as projects and part charged to the income statement asexploration expense, operating costs, pre-licence expenditure or general andadministration costs. 11 External Audit This Preliminary Announcement is consistent with the audited financialstatements of the group for the year-ended 31 December 2007. 12 A full set of financial statements will be published on or before 25April 2008. Copies will be available at the company's head office, 23 LowerBelgrave Street, London SW1W 0NR, and on the company's website(www.premier-oil.com) from that date. 13 The Annual General Meeting will be held at Clothworkers' Hall, DunsterCourt, Mincing Lane, London, EC3R 7AH on Friday 6 June 2008 at 11.00am. Working Interest Reserves at 31 December 2007 Working interest basis North Sea Middle Asia West Total East-Pakistan* Africa Oil and Gas Oil and Gas Oil and Gas Oil and Oil and Gas Oil, NGLs NGLs NGLs NGLs NGLs NGLs and gas mmbbl bcf mmbbl bcf mmbbl bcf mmbbl mmbbl bcf mmboeGroup proved plus probablereserves:At 1 January 2007 15.9 14 1.5 365 5.4 343 3.8 26.6 722 152.1Revisions1 (0.1) - 0.1 16 1.3 106 (0.1) 1.2 122 24.1Discoveries and - - - - - - - - - -extensionsAcquisitions and 10.1 10 - - - - - 10.1 10 11.9divestments2Others3 - - - - 4.6 193 - 4.6 193 36.4Production (3.1) (2) (0.1) (29) (0.8) (18) (0.4) (4.4) (49) (13.0)At 31 December 2007 22.8 22 1.5 352 10.5 624 3.3 38.1 998 211.5Total group developed andundeveloped reserves:Proved developed 12.1 17 1.0 210 3.4 145 0.6 17.1 372 81.4Proved undeveloped 1.0 - - 22 3.5 289 1.0 5.5 311 60.1Probable developed 5.1 5 0.4 94 1.3 16 0.4 7.2 115 26.5Probable undeveloped 4.6 - 0.1 26 2.3 174 1.3 8.3 200 43.5At 31 December 2007 22.8 22 1.5 352 10.5 624 3.3 38.1 998 211.5 Notes: 1. Revisions include upgrades on Block A (resulting from additional gassales agreements) and Kakap fields in West Natuna Sea, and Qadirpur and Zamzamafields in Pakistan. 2. Acquired additional 20.05 per cent equity in Scott field (completed 17May 2007). 3. Reserves include North Sumatra Block A gas development (Alur Siwah,Alur Rambong and Julu Rayeu fields) for which a gas sales agreement was signedin December 2007. * During 2007 the group entered into an agreement with Kuwait ForeignPetroleum Company KSC (KUFPEC) to de-merge their respective interest in Pakistanfrom the Premier-KUFPEC Pakistan joint venture. All reserves which werepreviously categorised as held through joint venture at the end of 2006 havebeen reclassified as group reserves. 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 increased by 55.3 mmboe giving total entitlementreserves of 187.7 mmboe as at 31 December 2007 (2006: 132.4 mmboe). This wascalculated in 2007 using an oil price assumption of US$60/bbl (2006: US$50/bbl).The entitlement reserves if calculated on an oil price assumption of US$94/bblwould be 182.8 mmboe. This information is provided by RNS The company news service from the London Stock ExchangeRelated Shares:
PMO.L