Management Resource Solutions Regulatory News (MRS)

31 Mar 2006 07:03

Melrose Resources PLC31 March 2006 FOR IMMEDIATE RELEASE 31 March 2006 Melrose Resources plc Preliminary Announcement of Results for the year ended 31 December 2005 Melrose Resources plc, the oil and gas exploration and production company withinterests in Bulgaria, Egypt, France and USA, today announces its preliminaryresults for the year ended 31 December 2005: 2005 HIGHLIGHTS Financial Highlights • 60% increase in revenue to US$94.5 million (2004: US$59.1 million); • 61% increase in EBITDAX to US$76.1 million (2004: US$47.4 million); • Profit from operations of US$32.2 million (2004: loss US$6.6 million) • Profits after taxation of US$22.4 million (2004: loss US$8.0 million); • EPS of US$0.29/share (2004: loss US$0.11/share); • 50% increase in proposed final dividend of 1.5p (2004: 1.0p); • Adoption of IFRS and "successful efforts" accounting; Operational • 54% increase in average daily production: O 26.9 Bcfe output during year (2004: 17.5 Bcfe); O stable production from Galata gas field at 51 MMcfepd (2004: 31 MMcfepd); O 48% increase in production in Egypt; O 15% increase in production in US; • 158% replacement of proved reserves in year; • 30% increase in discounted present value of oil and gas reserves; • Significant exploration success in Egypt: O El Tamad - first oil discovery in Nile Delta; O new multi-prospect Sidi Salim play established; O West Khilala and West Dikirnis discoveries; • Exploration interests expanded and extended in core areas: O El Mansoura Concession extended for 6 years O South East El Mansoura Concession awarded; O Emine and Rezovska licences acquired in Bulgaria; O Rhone Maritime Exploration Permit, France, acquired; • High impact exploration drilling programme scheduled for 2006: O semi-submersible drilling rig contracted for Black Sea, Bulgaria; O 16 exploration wells planned in Egypt; O US$64 million exploration budget; Commenting on this, Robert Adair, Chairman, said: "2005 was another year of strong growth for Melrose with significantly increasedproduction, profitability and reserve replacement. Looking to the future, in2005 we laid down some strong markers for the Company's continued near-termgrowth. In Egypt we made the first oil discovery in the Nile Delta andidentified an oil-bearing trend that may extend across our acreage. InBulgaria, the early stage exploration drilling programme identified a number ofpositive indicators that give us confidence that the exploration potential inour acreage will be realised. Our exploration portfolio now has considerable diversity and prospectivity andour 2006 drilling programme includes a number of high impact exploration wells.Our value is underpinned by existing production and cashflow yet we are highlygeared to exploration success and so the opportunities to significantly increaseshareholder value are considerable." For further information please contact Melrose Resources plc 0207 466 5000 (today)Robert Adair, Chairman 0184 553 7037 (thereafter)David Curry, Chief Executive 0131 221 3360 (thereafter)Munro Sutherland, Finance Director 0131 221 3360 (thereafter)Chris Thomas, Corporate Development Director 0207 462 1603 (thereafter) Buchanan CommunicationsBen Willey 0207 466 5000Eric Burns 0194 388 3990 or visit our website at www.melroseresources.com. Chairman's statement In 2005 Melrose achieved a further improvement in financial performance withsubstantial increases in production, revenue, earnings and cash flow. The secondhalf of the year also brought significant exploration success in Egypt. Inaddition, we extended our exploration portfolio through the addition of newconcessions in Bulgaria and Egypt. Our exploration portfolio now has greaterdiversity and prospectivity which we expect to bear fruit in 2006 and beyond. In Egypt, we have established an impressive exploration and development recordwith three main plays now successfully being exploited commercially. Theextension of the El Mansoura Exploration Concession for a further six years andthe award of the new South East El Mansoura Concession during 2005 were veryimportant in giving us additional time and increased acreage to exploit thepotential which we see in this area of the Nile Delta. The final processing ofthe new 3-D seismic data over most of the El Mansoura Concession has transformedour exploration effort and two potentially large discoveries late in the year atWest Khilala and West Dikirnis are an immediate result of the new 3-D. To date,the exploration effort has been focused on the western side of the Concessionbut the extension of the 3-D seismic coverage over the eastern side has recentlybeen completed and we are confident that further large discoveries will followlater in 2006. The El Tamad No.1 oil discovery in June 2005 was an important achievement as itwas the first commercial black oil discovery in the Nile Delta. The subsequentTurbay and Al Rawda discoveries have confirmed the potential of this Sidi Salimtrend and many more good prospects have been identified. This play also extendsinto the new South East El Mansoura Concession, along with the other establishedAbu Madi and Pliocene plays. Further prospectivity is also seen on the newConcession in the deeper Oligocene and Cretaceous horizons. The acquisition of3-D seismic in the northwest of the new Concession area will be completed byApril with processed data available by mid-year. Appraisal drilling in the South Batra field has confirmed that there are threeseparate channel trends within the Abu Madi system with good reservoir quality.However, the areas in between these north-south channel sequences arenon-productive in spite of being structurally high. While some reserves havebeen lost in these intervening highs in the South Batra field area, thepotentially-productive areas of the extended and extensive channel systems arenow being identified more clearly on the 3-D seismic and there is significantupside both in the South Batra area and elsewhere over the concession areas. TheNPV10 of our net proved and probable reserves in Egypt is $240 million but theidentified exploration potential of existing "plays" on the concessions isaround two times the reserves established to date with a greater emphasis onoil; there is further upside in deeper horizons. We also see value upside inEgypt in the possibility of achieving a higher gas price through gas export forLNG. In Bulgaria, the performance of the Galata Field has continued to be verysatisfactory and the first phase of the onshore compression has beensuccessfully installed. Two exploration wells were drilled in the shallowinshore area of Block Kaliakra 99 targeting stratigraphic channel plays. Bothencountered significant residual oil and gas shows and good reservoir but werenot commercial as a result of seal failure. The wells provided furtherconfirmation of an active petroleum system and have maintained our belief in theprospectivity of the area. Further evaluation work continues over the contiguousKaliakra 99, Emine and Rezovska areas and a number of new prospects have beendeveloped. The Black Sea area offshore Bulgaria is an underexplored hydrocarbonprovince but we are seeing a number of encouraging indicators that give usconfidence to expect some significant discoveries from our drilling programme in2006. A semi-submersible rig is under contract for later this year and ajack-up rig is also being considered. The sharp increase in gas pricesthroughout Europe adds to the potential of our assets in Bulgaria. On the Rhone Maritime Concession, offshore France, work on a number of studiesincluding thermal modelling, seismic depth conversion and basin stratigraphy,has greatly increased our knowledge of this frontier area. A strong case can nowbe made to demonstrate the potential for oil and gas to have been generatedwithin the target horizons and huge structures can be mapped. We anticipatecommencing farm-out discussions in the summer prior to committing to acquire 3-Dseismic and drilling the first well in the basin. Operations on our US properties have made steady progress although developmentactivity in 2005 was slightly delayed by the tight rig market. All three mainproduction units now have active water injection programmes with the Jalmatproject being the most advanced. Production in the year was affected as someproducing wells were converted to water injection wells but production is now onan increasing trend. Net production in the US of 2,500-3,000 boepd remains ourtarget once the waterflood projects take full effect. As set out in the Financial Review, Melrose has changed from a full cost to asuccessful efforts accounting policy which we have been advised is morecompatible with International Financial Reporting Standards. Under thesuccessful efforts policy the results of unsuccessful exploration activity arereflected immediately in the income statement. This tends to increase thevolatility of the results from year-to-year in a way which may not reflect theunderlying trend in value addition. Under the new policy we report a profitafter tax for 2005 of $22.4 million. I am pleased to announce that we are proposing that the dividend for the yearshould increase from 1.0p to 1.5p which reflects our confidence in Melrose'sproduction base and future prospects. I should like to thank Melrose'smanagement and staff for their hard work and achievement in 2005 and I lookforward to the results of their efforts in the current year. R F M AdairChairman Financial review Adoption of IFRS and successful efforts accounting policy Melrose has adopted IFRS in preparation of this financial information includinga restatement of opening balances and comparative figures. In view of doubtregarding the compatibility of certain aspects of full cost accounting with IFRSMelrose has changed its oil and gas accounting policy from a full cost policy toa successful efforts policy. The comparative figures for 2004 have been restatedunder this policy. Under the successful efforts accounting policy the costs of unsuccessful wellsare expensed in the income statement in the period they are determined to beunsuccessful. Depletion of development and production assets is calculated on afield or a concession basis, as appropriate. As required by IAS 36, Impairmentof Assets, impairment testing is performed on each individual cash-generatingunit which is either on a field basis or a concession basis, as appropriate. In addition, following the refinancing of all Group debt, the US dollar has beenadopted as the functional currency of the Company with effect from 1 January2004. Results for the year Turnover for the year was $94.5 million which compares with turnover of $59.1million in 2004. Turnover derived from Egypt was $26.1 million (2004: $17.6million), Bulgaria $51.9 million (2004: $30.8 million) and the USA $16.5 million(2004: $10.7 million). Financial income includes a realised gain on the sale of investments of $5.3million (2004: nil) and an unrealised gain following the revaluation offinancial assets of $4.1 million (2004: nil). Profit after tax amounted to $22,407,000 (2004: loss of $8,010,000) after takinginto account a tax charge of $9,350,000 (2004: credit of $3,079,000). A final dividend of 1.5 pence (2004: 1 penny) per share is being proposed. Ifapproved, the dividend of $2,058,000 (2004: $1,333,000) will be deducted fromthe profits of $22,407,000 which have been transferred to reserves. EBITDAX for the year of $76.1 million compares with $47.4 million for theprevious year: 2005 2004 $000 $000Profit/(loss) before taxation 31,757 (11,089)Add back:Depreciation 204 101Depletion 33,378 18,954Decommissioning charge 1,144 600Unsuccessful exploration costs 9,255 34,355Net financing cost 407 4,442EBITAX 76,145 47,363 Profit and cashflow per unit of production Bulgaria Egypt USA 2005 2004 2005 2004 2005 2004 $ $ $ $ $ $Prices receivedOil/condensate (bbl) - - 52.37 37.27 49.72 36.68Gas (Mcf) 2.81 2.71 2.67 2.64 7.52 5.88 Unit of production (Mcfe)Revenue 2.81 2.71 2.99 2.79 8.13 6.06Royalties and production taxes (0.07) (0.07) - - (0.63) (0.46)Operating costs (0.14) (0.07) (0.15) (0.17) (2.10) (1.60)Net cashflow 2.60 2.57 2.84 2.62 5.40 4.00Depletion (1.44) (1.28) (0.66) (0.63) (1.27) (0.91)Abandonment (0.06) (0.05) - - (0.03) (0.03)Net profit 1.10 1.24 2.18 1.99 4.10 3.06 Additions to the oil and gas assets of the Group during the year totalled $73.7million (2004: $83.6 million). This was split, geographically, $20.9 million(2004: $39.5 million) in respect of properties in Bulgaria, $37.1 million (2004:$33.2 million) in Egypt, $14.3 million (2004: $10.9 million) in the USA, and$1.4 million in France. Financial assets The Group holds options to purchase shares in a company which is a member of theAIM. Under UK GAAP these options were held at cost to the Company, which wasnil. Under IAS 39 these options are held at fair value. At 1 January 2004 and31 December 2004 these options had a fair value of nil. Financial instruments The Group's use of financial instruments is mainly restricted to borrowings,cash deposits, short-term deposits and various items such as trade debtors andtrade creditors which derive from its operations. In general it is not theGroup's policy to hedge the prices at which its products are sold other than asa result of the structure of contracts which are entered into for the sale ofthe Group's production. As such, there were no hedging contracts in place as at31 December 2005. Risk management The main risks from the Group's financial instruments are interest rate risk,liquidity risk and foreign currency risk. The Group's exposure to interest raterisk derives from its borrowings which are at variable interest rates. It hasbeen the Group's policy to borrow for short term periods at variable interestrates in order to reduce the interest rate charged and to allow flexibility overearly repayment of borrowings. This policy exposes the Group to a risk thatinterest rates will rise. Group interest charged at variable rates in 2005 was$7.5 million. Currency risk The Group has limited exposure to foreign currency risk as the majority of itsrevenue and expenditures are denominated in US dollars. A commercial riskarises to the extent that overhead costs and an element of capital expendituresare incurred in currencies other than US dollars. In order to minimize currency risk, it is Group policy that borrowings incurredin relation to development projects should be denominated in the same currencyas the anticipated cash flows from the project. Similarly, it is Group policythat corporate borrowings should be denominated in US dollars. Repayment of theSterling debt in November 2004 has aligned the currency of all Groupindebtedness with the Group's main functional currency. Pricing risk At this time, the Group has no long-term contracts under which the price for thesale of its production is fixed. Gas production from the El Mansoura Concessionin Egypt is sold under a long-term contract under which the gas price is linkedto the oil price but with the oil price in a collar between $10 per bbl and $22per bbl. With the oil price at its current level, the gas price is at the top ofthe permitted range and is effectively fixed. Capital expenditure budget The budget for 2006 capital expenditures in Egypt is approximately $49.5million, of which approximately $37.3 million is for exploration and $12.2million is for appraisal and development. In Bulgaria, budgeted explorationexpenditures are approximately $26.7 million and budgeted developmentexpenditures are approximately $6.2 million. Budgeted capital expenditures, alldevelopment, in the USA are approximately $20.7 million. Loan facilities In November 2004 the Group signed four-year corporate loan facilities amountingto $75 million in aggregate. These loan facilities remain in place as at 31December 2005 with the initial repayment on the facility due in June 2006. TheGroup is currently arranging an increase in the total amount of the loanfacilities. Equity financing The Company completed a placing of 1.7 million new Ordinary Shares at 240 pencein May 2005, which raised $7.4 million net of expenses. A further 0.9 millionnew Ordinary Shares were issued following the exercise of share options. At 31 December 2005, the Group had cash balances of approximately $8.0 millionand bank and other loans totalling $91.0 million. Available borrowing capacityunder bank loans totalled $5.0 million. Financial Reporting The financial information has been prepared in accordance with IFRS as adoptedfor use by the European Union. This is the first annual financial informationprepared in accordance with IFRS and the comparative information for the yearended 31 December 2004 has been restated and is disclosed in note 6 to thefinancial information. Going concern After making enquiries, the directors have a reasonable expectation that theGroup has adequate resources to continue to operate for the foreseeable future.For this reason, the financial information has been prepared on the goingconcern basis. Operational review EGYPT During the year Melrose enlarged and extended its concession acreage position inEgypt. The El Mansoura Concession was extended, adding a further six years intwo three-year exploration periods, commencing on the expiry of the originalconcession term in June 2006. In addition, the South East El Mansoura Concessionwas awarded with an exploration period of eight years. 2005 also saw aresumption of exploration drilling with a number of significant discoveries inthe second half of the year. The initial interpretation of the final processed3-D seismic data over most of the El Mansoura Concession has confirmed furthersignificant exploration potential in the area. El Mansoura Concession Drilling activity early in the year concentrated on the delineation of thePliocene Mansouriya Channel play and the continuation of the appraisal of SouthBatra Field, Miocene Abu Madi play. Success on the existing South Batra area wasmixed but the availability of large contiguous 3-D seismic data is transforminginterpretation of the deeper Miocene plays and significant exploration successhas been achieved. While the Pliocene provided success and low risk productionin the early stages of the concession, this will be a lower priority in future. Four wells were drilled on the Mansouriya trend and all four were put onproduction after good initial flow rates on test. There have subsequently beenproduction difficulties with two of the wells, with significant reservesremaining behind casing as a result of poor cement. The zone of interest is setwithin sensitive shales and the problem of drilling through these shales andcementing the casing is being addressed. In the Pliocene play outwith the South Batra field area, four exploration wellswere drilled in the South Mansoura area. Three of these wells have beensuccessfully completed as producers. One further Pliocene well was drilled onthe Abu Arida structure to the north of Mansouriya. This well is already onproduction through the existing South Bilqas facilities. The South Batra Abu Madi appraisal programme produced mixed drilling resultswith some valuable lessons learned during the year. The delineation drillingprogramme confirmed that there are three separate channel trends within the AbuMadi channel system with good reservoir quality. The areas in between thesenorth-south channel sequences have been non-productive in the wells drilled inspite of being structurally high. While reserves attributed to these interveninghighs have been excluded from this year's reserve review, it is expected thatthe intervening channels can be followed to the north and to the south. Thesepotential field extensions will be tested in 2006. Further South Batra fieldappraisal and extension drilling will benefit from the experience gained. Intotal, six wells were drilled over the year of which three were completed as AbuMadi producers and a Pliocene interval will be tested in a fourth. One of thewells was deepened to the Sidi Salim and a pressure kick required installationof a 10,000 psi rated BOP. The hole was open for an extended period and,probably as a result of this, no flow from the Sidi Salim zone was achieved ontest. This well did, however, suggest the potential of the middle Miocene playson the eastern side of the South Batra Field which was later confirmed by theWest Dikirnis discovery. A very significant development during the year was the discovery of oil in theMiocene Sidi Salim formation. The El Tamad No.1 well successfully tested blackoil and gas at a rate of 2,000 bopd plus 1.5 MMcfpd. A follow-up well, El TamadNo.2, established the water contact and was tested at the more modest rate of1,041 bopd and 780 Mcfpd. Following fast track development, the two wells werebrought on production in February 2006 at a combined rate of 950 bopd and 650Mcfpd with a gradual increase to around 1,500 bopd plus 1 MMcfpd expected.Subsequently, the Turbay No.1 was drilled to test the same Sidi Salim play andthe well tested at 110 bopd plus 1 MMcfpd after initially flowing only gas. Theoil rate is expected to rise as the well is put on production through the ElTamad facilities. A fourth well encountered a residual oil column and wasplugged. As this play is better understood and further 3-D seismic is acquiredgoing into South East El Mansoura, we expect this area to provide a number ofsignificant oil discoveries. Following the acquisition of 1,700 km(2) of 3-D seismic data over the westernand central areas of the Concession, exploration efforts were focussed on thearea covered by this 3-D data. The West Khilala and West Dikirnis wells weredrilled on strong seismic anomalies. The West Khilala well encountered a grossgas column of 122 ft (95 net ft) in a very high quality level II Abu Madi sandwith no water contact. The well was tested at 30.2 MMcfpd plus 60 bcpd withdetailed well test analysis indicating that the structure could holdconsiderably more gas than the pre-spud volumetric GIIP of around 250 Bcf. Thecurrent 2P GIIP estimate is 500 Bcf but this number could well be increasedfurther. It is expected that the 3-D data will highlight further large anomaliesin this area over the coming months. The West Dikirnis well, located to the east of the South Batra Field, tested aseries of sand intervals straddling what is interpreted to be the boundarybetween the Miocene Qawasim and Sidi Salim intervals. A gross gas column of 147ft, with no water contact, was encountered. There are three separate sandintervals, totalling 101 net ft, with the two upper units interpreted as verygood quality Qawasim and the lower unit a poorer Sidi Salim reservoir. Only thelower interval was tested (24 ft gross) and a stabilised flow rate of 21.7MMcfpd and 894 bcpd was achieved, proving much better quality reservoir thanindicated by the logs. The well will be brought on to production from this SidiSalim interval and the other sands will be tested in the proposed appraisal/development wells. Because the main reservoir intervals have not yet beentested, a volumetric GIIP of 206 Bcfe has been calculated giving a conservativefigure for 2P reserves of 165 Bcfe. Here also, analogous seismic anomalies arebeing seen in the area around the West Dikirnis structure. The processed data from the final tranche of the 3-D seismic survey, in the areato the east of the Dikirnis well, should become available by mid-2006 andfurther large prospects are expected to be identified in this eastern area ofthe Concession. The seismic crew was released for six months in March 2005 butreturned in September to complete the acquisition of 3-D seismic over theeastern part of the Concession. This survey was completed recently and the crewhas moved from El Mansoura down to South East El Mansoura. The processed datashould be available by mid-May and it is expected that a number of larger deeperprospects should emerge. South East El Mansoura Concession The South East El Mansoura Concession which is located immediately to the southof the El Mansoura Concession, covers an area of 3,730 km(2). The north-westcorner of the Concession, where it borders on the El Mansoura Concession, isbelieved to have most potential. There is only a small amount of existing 2-Dseismic, mainly in the northwest, and the obvious potential of this area canonly be hinted at using the current data set and extrapolation of the ElMansoura 3-D data. Exploration potential has been identified in the Pliocene,Abu Madi and Sidi Salim plays extending down from El Mansoura. In addition,further potential is seen in the Oligocene and Cretaceous levels with the areabeing thought to be generally more oil prone. The first well to be drilled on the Concession, Al Rawda, targeted the same SidiSalim interval encountered in the Turbay well. Gas and condensate have beenencountered in this small fault block suggesting that black oil, with a gas cap,is more likely to have been trapped in some of the bigger structures. The 3-Dseismic, currently being acquired, will allow more effective interpretation ofthis play. Qantara Concession There has only been minor activity on the Qantara Concession in 2005. Further3-D seismic coverage is required over the northern half of the Concession and itwas decided to complete the seismic acquisition over the other two Concessionsbefore moving the crew to Qantara. Regional evaluation work suggests that the northern area of the QantaraConcession should be more prospective than the south and further work on the old2-D seismic indicates a large shallow Pliocene structure as well as deeperMiocene structures with significant potential. The deeper Miocene and Oligocenereservoirs are expected to be better quality north of the major east-west hingezone that runs through the Concession. Following the planned 3-D acquisition inmid-year a well will be drilled in early 2007. The key goal in Qantara will beto identify and drill a section of good Qantara sand reservoir on the newseismic and then use this example seismic response to re-evaluate the old 3-Dseismic in the southern area. BULGARIA The interests of Melrose in Bulgaria are located offshore in the western BlackSea. During the year, the Galata gas field performed well and the first stage ofcompression was successfully installed at the onshore production facilities. Twoexploration wells were drilled in the shallow waters of Block Kaliakra 99. Whilethe results were not commercial discoveries, residual oil and gas wereencountered in the target formations, further confirming the hydrocarbonpotential of the area. The Group's exploration priorities in Bulgaria arecurrently being formulated in the light of this new well data and a betterunderstanding of the geology of the area. An exploration drilling programmeusing a semi-submersible rig is scheduled to commence in the fourth quarter of2006. Galata Gas Field Production from the Galata field during 2005 totalled 18.5 Bcf meeting 16% ofBulgaria's domestic gas consumption during the year. Contract sales volumes inplace for 2006 are for a similar production level. An appraisal well drilled in the Galata East fault block in 2005 enhancedunderstanding of, and confidence in, the deliverability of the reservoir.Analysis of the results showed that there is connection across the fault and itis, therefore, expected that the reserves can be produced from the present wellsand process facilities. In the light of the well result and productionperformance, proved reserves recoverable over field life have increased from 65to 75 Bcf while proved plus probable reserves were revised downwards slightlyfrom 90 to 85 Bcf. As planned, in order to maintain field deliverability, a compressor was added tothe onshore process facilities during the year. The project was tendered tointernational and local companies with quotes received between $12 and $18million plus local costs. Melrose elected to complete the project with internalproject management and resources. The compression unit was purchased direct fromSolar in San Diego, California; ancillary equipment was sourced in Europe andthe pipe work in Bulgaria. The design was completed by Optimus of Aberdeen andengineering and support was contracted locally in Bulgaria. The project wascompleted at a total cost of $7 million. The entire project was completed in 12months without incident and without disruption to monthly gas sales: theindustry norm for installing a machine of this type is a minimum of 18 months.The compressor has run on demand since it was commissioned and has allowedmonthly nominations for both January and February 2006 despite localtemperatures falling as low as -21 degrees C. The compressor turbine is fitted with SoLoNox technology to ensure that the exhaust gases meet stringent environmental emission limits. In order to maximise field recovery a second compressor will be installed during 2007. Block Kaliakra 99 Block Kaliakra covers an area of 2,601 km(2) in water depths mostly less than500 m. In 2004 Melrose acquired 600 km2 of 3-D seismic in the southern area ofthe block and in 2005 the final processed seismic from this survey was received.Interpretation of the 3-D seismic has been essential in assisting in theevaluation of the prospectivity of the area as it has allowed an enhancedunderstanding of the geological setting and petroleum trapping mechanisms. At the end of 2005 two exploration wells, Samotino Nos.1 and 2, were drilled inthe southern area of the block targeting stratigraphic plays. Both wellsencountered hydrocarbon shows in good potential reservoir sand sections,although they were not considered commercial and subsequently plugged andabandoned. The southern area of Kaliakra is still considered to be veryprospective. During the year Melrose undertook a field trip to the onshore areain conjunction with the Universities of Sofia and Edinburgh to evaluate theonshore outcrop of reservoir formations. All data gathered during drilling andthe field trip is now being evaluated and will be incorporated into futureseismic mapping and prospect evaluation. The northern area of Kaliakra is geologically different from the southern areaand to-date has been evaluated with 2-D seismic only. A 3-D survey that willcover the current leads and prospects is being considered. The plays here areboth structural and stratigraphic. The area lies directly adjacent to theonshore 150 MMbbl Tulenovo oil field and current understanding of the petroleumsystem indicates that the northern area of Block Kaliakra lies on the mostlikely migration pathway for the oil to this field. Current plans for 2006 are to drill two or three wells in the deeper water ofBlock Kaliakra 99 and the adjacent Blocks Emine and Rezovska. A semi-submersiblerig, the Atwood "Southern Cross", has been chartered to drill these wells laterthis year with two further optional wells. In addition, further wells in theshallow shelf area are being considered. Evaluation and prospect risking will becompleted by mid-year when the final well locations will be selected. Severalof the play types identified on the 3-D seismic on Block Kaliakra 99 have neverbeen tested and the acreage remains very prospective. Block Galata The area covered by the former Block 91-III, which was relinquished at the endof 2004, was reapplied for during 2005 as Block Galata. It is hoped that adecision on the award of this Block will be announced by the Ministry of Energybefore mid-year. If Melrose is successful in its application then a drillingprogramme on the Block will be considered for later in the year. Blocks Emine and Rezovska Block Emine is located directly south of Block Kaliakra 99 and extends to thesouthern Bulgarian border, covering an area of 4,495 km2. The smaller BlockRezovska covers 574 km2 and is located at the south-eastern corner of Emine. Thewater depths within the two Blocks range from less than 20 m to just over 750 m.Applications for licence extensions to both blocks are currently beingconsidered by the Ministry of Energy. Original and re-processed 2-D seismic data exists across both Concessions andone well was drilled in 1994 in the north-eastern corner of Block Emine. Thewell encountered gas shows but was never properly completed. Over the last yeara technical analysis of all of the available data has outlined considerableprospectivity in the two blocks with both structural and stratigraphic playsbeing recognised. Most of the prospects exist due to structures formed by compression of the rocksin this region of the Black Sea. Encouraging results from satellite imageryhave identified possible sea-floor oil seeps near the northern border ofRezovska close to many of the recognised prospects. This strongly suggests thatgeneration and migration of hydrocarbons has taken place in the basin andtherefore increases the likelihood that traps have been charged withhydrocarbons. Further evidence for the presence of hydrocarbons has come fromseismic interpretation where bright amplitude anomalies have been identified atthe crests of many structural closures. AVO modelling of seismic data is beingcarried out to try and determine whether or not these anomalies are directindicators of trapped hydrocarbons. The planned exploration programme in Blocks Emine and Rezovska includes theacquisition of 3-D seismic data and a sea floor coring program. Both surveyswill help reduce the exploration risk in the blocks; the former with improvedsubsurface definition and the latter with geochemical sampling for micro-seepageof migrating hydrocarbons. A large structural feature, the Ropotamo prospect, inBlock Rezovska is a possible target for the 2006 drilling campaign.Interpretation of this prospect, which could contain reserves of up to 765 Bcfof gas or 330 MMbbl of oil, is being finalised and will determine if theprospect is ready for drilling. USA The Group's interests in the USA comprise approximately 25,000 gross acres,concentrated in the Permian Basin in New Mexico and Texas. Melrose is theoperator of the majority of these properties. The properties are characterisedby shallow oil production with substantial, low-risk enhanced recovery upsidethrough infill drilling and water injection. Development programme The emphasis during 2005 was on preparing the Group's three principal fields forwidespread water injection after successful implementation of pilot waterinjection programmes. In 2005, 13 new wells were drilled and a further 6 wells have been drilled inthe first three months of 2006. Development activity during 2005 was frustratedto some extent by escalating drilling and service costs and, more significantly,by the tight market for drilling and completion rigs and for other fieldservices. However, despite this and the inevitable initial disruption toproduction when waterflood projects are implemented, average daily productionincreased by 15% compared to 2005 and daily production of 3,000 boepd remainsthe goal. Capital expenditure of $14.2 million comprised $8.0 million on newwells, $4.1 million on waterflood implementation and $2.1 million on workoversand recompletions. Average daily production increased by 15% from 802 boepd in2004 to 925 boepd in 2005 and current production capacity is estimated at 1,200boepd. Jalmat field interests In the Jalmat field, the work programme for 2005 involved completing the infillwell pattern for a "five spot" injection configuration, building new injectionfacilities and laying flowlines, so that water injection rates can be increasedin 2006. In total, 13 new producing wells were successfully drilled andcompleted during 2005 and a further 5 wells were awaiting completion at the yearend. Despite good initial flow rates on these infill wells, the depletedreservoir pressures experienced on a number of the wells has emphasised the needfor the water injection programme in order to re-pressurise the reservoir and tomaximise ultimate oil recoveries. Two new water injection wells were drilledand a further 7 wells were converted to water injection during 2005. There arenow 21 active water injection wells in the Jalmat field and up to 20 are plannedto be activated in 2006. The construction of a second water injection facilityand tank battery on the Cone Jalmat Unit is underway and the drilling of twowater-source wells is scheduled for 2006. Average daily production from theJalmat field increased by 34% from 342 boepd in 2004 to 457 boepd in 2005. Artesia field interests Work on the secondary recovery project on the Artesia Unit continued with theworkover of 17 existing wells to enable water injection to commence in the northwest and south west areas of the Unit. These injection patterns are expected tobe activated during the first half of 2006. There are in excess of 30 drillinglocations to be drilled on the Unit over the next two years as part of thisenhanced recovery project and the drilling rig is scheduled to move to this Unitin April 2006. Average daily production from the Group's interests in theArtesia field increased by 10% during 2005 to 214 boepd in 2005. Turner Gregory Unit The Turner Gregory Unit is on trend with two large secondary recovery projectsto the north east and south west. A line-drive water injection programme wasinitiated on this Unit during 2005, with 3 wells being converted to waterinjection. Average daily production declined by 4% during 2005 to 102 boepd,but since the year end 10 shut-in wells have been put back onto production andcurrent production is in excess of 130 boepd. Full implementation of thiswaterflood over the next three years is expected to increase productionsignificantly. Other interests Average daily production from the Group's other interests in the USA during 2005was unchanged at 152 boepd. The Group is now receiving royalties from itsinterests in the Barnet Shale gas play in Texas, but it has not yet exercisedits right to participate in any wells on a working interest basis. FRANCE Rhone Maritime Concession The Rhone Maritime Concession is located in the north-western part of theProvencal Basin in the French Mediterranean. The basin, which is in a deepwatersetting of up to 2,600 m and includes the Rhone deep-sea fan, is completelyunexplored. Two major play fairways, divided by a thick Messinian salt sequence, have beenidentified from excellent 2-D seismic acquired in 2001. The post-salt Pliocenedeposits have undergone significant structuration due to distortion in theunderlying Messinian salt, resulting in large closures that could accommodatesizeable hydrocarbon accumulations of up to tens of Tcf of gas or a billionbarrels of oil. Abundant AVO anomalies, suggesting the presence of hydrocarbons,have been identified in the seismic dataset and the combination of very largestructures and hydrocarbon indicators is very promising. The second play fairwaylies in the pre-salt turbiditic Miocene deposits and has distinct seismicreflection characteristics that could also indicate the presence ofhydrocarbons. Evaluation of the prospectivity in the Concession is ongoing. The 2-D seismiclines have been reprocessed to remove artefacts caused by the variation inthickness in the salt layer and thereby improve data quality in the pre-saltMiocene interval. The seismic data has been interpreted to provide a globalimage of the area and to identify good leads in the pre-salt and post-saltlayers. A 3-D seismic campaign is being considered for the second half of 2006over a 2,000 km2 area in order to evaluate 2 leads in the Miocene and thePliocene. A review of the regional literature published on the western Mediterranean hasdemonstrated potential source rocks in the Oligocene and the Messinian and a 3-Dthermal modelling study has been undertaken to reconstruct the history ofhydrocarbon maturation, expulsion and migration in the area. On the back ofthese very positive indicators, Melrose will seek to farm-out an interest in theConcession prior to committing to the 3-D seismic acquisition programme and withthe intention of drilling a well in 2007. Oil and gas reserves Proved and Probable Reserves At 31 December 2005 the Group's proved and probable reserves, calculated on anentitlement basis, comprised: Egypt Bulgaria USA Total Oil Gas Gas Oil Gas Oil Gas Mbbl MMcf MMcf Mbbl MMcf Mbbl MMcfProved developed 352 43,897 38,655 2,627 6,289 2,979 88,841Proved undeveloped 175 13,312 8,900 9,387 7,384 9,562 29,596Proved 527 57,209 47,555 12,014 13,673 12,541 118,437 Probable developed 732 31,947 - - - 732 31,947Probable undeveloped - 34,963 7,600 - - - 42,563Probable 732 66,910 7,600 - - 732 74,510 Developed 1,084 75,844 38,655 2,627 6,289 3,711 120,788Undeveloped 175 48,275 16,500 9,387 7,384 9,562 72,159Proved and probable 1,259 124,119 55,155 12,014 13,673 13,273 192,947 Proven and probable reserves are the estimated quantities of crude oil, naturalgas and natural gas liquids which geological, geophysical and engineering datademonstrate with a specified degree of certainty to be recoverable in futureyears from known reservoirs and which are considered commercially producible.The figures are estimated on the basis that there should be a 90% probabilitythat the actual quantity of recoverable reserves will be more than the amountestimated as proven and there should be a 50% probability that the actualquantity of recoverable reserves will be more than the amount estimated asproven and probable. Proved reserves in the USA are as evaluated by independent petroleum engineers.Proved and probable reserves in Bulgaria and Egypt are directors' estimatesbased upon evaluations by Company employees which have been reviewed byindependent petroleum engineers. Movements in the Group's proved and probable reserves during the year were asfollows: Egypt Bulgaria USA Total Oil Gas Gas Oil Gas Mbbl MMcf MMcf Mbbl MMcf Mboe MMcfe At 1 January 2005 759 117,668 78,614 12,078 13,495 47,800 286,800 Extensions and 1,055 75,513 - - - 13,641 81,843 discoveries Revisions (498) (63,009) (5,000) 204 593 (11,530) (69,181) Production (57) (6,053) (18,459) (268) (415) (4,480) (26,877) At 31 December 2005 1,259 124,119 55,155 12,014 13,673 45,431 272,585 Discounted Net Present Value The net present value, discounted at 10% per annum, of the Group's proved andprobable reserves at 31 December 2005 was as follows: Egypt Bulgaria USA TotalDiscounted net present value (NPV10) $000 $000 $000 $000 Proved developed 94,209 82,424 58,351 234,984Proved undeveloped 28,990 12,695 158,122 199,807Proved 123,199 95,119 216,473 434,791 Probable developed 68,016 - - 68,016Probable undeveloped 48,825 14,303 - 63,128Probable 116,841 14,303 - 131,144 Proved and probable 240,040 109,422 216,473 565,935 The discounted net present value is based upon the following pricingassumptions: USA: $52.00 per barrel of oil and $8.00 per Mcf Bulgaria: $2.83 per Mcf Egypt: $55.50 per barrel of condensate, $9.13 per Mcf (Qantara) and $2.50 and $2.65 per Mcf (El Mansoura) The discounted net present value is calculated on the basis of these commodityprices and of estimates of capital and operating costs at current prices withthe resulting net cashflows being discounted at 10% per annum. The discountednet present value is not necessarily an indication of realisable market value. Consolidated income statement for the year ended 31 December 2005 Year ended 31 Year ended 31 December 2005 December 2004 Note $000 $000 Revenue 94,506 59,069 Depletion (33,378) (18,954)Decommissioning charge (1,144) (600)Unsuccessful exploration costs (9,255) (34,355)Other cost of sales (10,429) (5,924)Total cost of sales (54,206) (59,833) Gross profit/(loss) 40,300 (764) Administrative expenses (8,136) (5,883) Profit/(loss) from operations 32,164 (6,647) Financing income 9,897 451Financing costs (10,304) (4,893) Profit/(loss) before tax 31,757 (11,089) Income tax (expense)/credit (9,350) 3,079 Profit/(loss) for the year 22,407 (8,010) Earnings/(loss) per share (cents) Basic 3 28.9 (11.2) Diluted 3 28.1 (11.2) Note: All operations were continuing operations. Consolidated balance sheet for the year ended 31 December 2005 At 31 December At 31 December 2005 2004 $000 $000Non-current assetsIntangible assets 19,281 18,362Property, plant and equipment 196,186 167,181Financial assets 4,132 -Deferred tax asset 17,259 19,081Other receivables - 2,919 236,858 207,543Current assetsInventories 6,847 1,384Trade and other receivables 23,945 19,356Cash and cash equivalents 7,965 4,237 38,757 24,977 Total assets 275,615 232,520 Current liabilitiesBank loans 20,000 -Other loans 3,500 -Trade and other payables 14,298 9,480Provisions 1,099 760 38,897 10,240 Non-current liabilitiesBank loans 47,519 60,340Other loans 17,500 21,000Deferred tax liability 1,338 1,392Provisions 6,797 6,641 73,154 89,373 Total liabilities 112,051 99,613 Net assets 163,564 132,907 Equity attributable to shareholdersIssued capital 14,080 13,606Share premium 8,579 617Special reserve 111,244 111,244Retained earnings 29,661 7,440 Total Equity 163,564 132,907 Consolidated cash flow statementfor the year ended 31 December 2005 Year ended 31 Year ended 31 December 2005 December 2004 $000 $000 Cash flows from operating activitiesProfit/(loss) for the period 22,407 (8,010)Adjustments for:Depreciation 204 101Depletion and decommissioning charge 34,522 19,554Unsuccessful exploration costs 9,255 34,355Loss on disposal of assets 14 -Foreign exchange losses 1,235 811Financial income (9,897) (451)Financial expenses 9,069 4,082Equity-settled share-based payment expenses 737 440Income tax expense/(credit) 9,350 (3,079) Operating profit before changes in working capital 76,896 47,803 Increase in inventory (5,463) (1,384)Increase in trade and other receivables (4,148) (8,686)(Decrease)/increase in trade and other payables (303) 1,755 Cash generated from operations 66,982 39,488 Income taxes paid (6,968) (5,536) Net cash inflow from operating activities 60,014 33,952 Cash flows from investing activitiesProceeds from sale of property, plant and equipment - 1,869Proceeds from sale of investments 5,350 -Interest received 416 451Acquisition of property, plant and equipment and intangibleassets (67,671) (92,448) Net cash outflow from investing activities (61,905) (90,128) Cash flows from financing activitiesProceeds from the issue of share capital 8,435 46,392Interest paid (6,472) (7,517)Borrowings raised 6,000 85,000Repayment of borrowings - (69,293)Dividends paid (1,333) - Net cash inflow from financing activities 6,630 54,582 Net increase/(decrease) in cash and cash equivalents 4,739 (1,594)Cash and cash equivalents at start of period 4,237 6,091Effect of exchange rate fluctuation on cash held (1,011) (260) Cash and cash equivalents at end of period 7,965 4,237 Notes to the financial informationfor the year ended 31 December 2005 1. Accounting policies Melrose Resources plc (the "Company") is a company domiciled in Scotland. Thefinancial information set out above contains the financial information of theCompany and its subsidiaries (together referred to as the "Group") for the yearended 31 December 2005. The financial information is prepared on the historical cost basis and ispresented in US Dollars, rounded to the nearest thousand. The financial information set out above does not constitute the Company'sstatutory accounts for the years ended 31 December 2005 or 2004. Statutoryaccounts for 2004, which were prepared under UK Generally Accepted AccountingPractices ("UK GAAP"), have been delivered to the registrar of companies andthose for 2005, prepared under IFRS as adopted by the EU, will be delivered indue course. The auditors have reported on those accounts; their reports were(i) unqualified, (ii) did not include references to any matters to which theauditors drew attention by way of emphasis without qualifying their reports and(iii) did not contain statements under section 237(2) or (3) of the CompaniesAct 1985. EU law (IAS Regulation EC 1606/2002) requires that the annual financialstatements of the Group for the year ended 31 December 2005 be prepared inaccordance with International Financial Reporting Standards (IFRS) and itsinterpretations as adopted by the European Union ("adopted IFRS"). This financial information has been prepared in accordance with adopted IFRS at31 December 2005, the Group's first annual reporting date at which it isrequired to use adopted IFRS. The impact of the transition to adopted IFRS and the significant accountingpolicies of the Group, which have altered as result of the adoption of IFRS,were included in the interim financial information for the six month periodended 30 June 2005. Following the publication of IFRIC guidance in November 2005 which noted thescope of IFRS 6 'Exploration for and Evaluation of Mineral Resources', the grouphas updated its oil and gas accounting policy from a full cost approach to oneof successful efforts. In addition the functional currency of the company wasrestated to US Dollars to more accurately reflect its operating status. As a consequence, Melrose has updated the restatement information provided inthe interim financial information to reflect the changes resulting from theadoption of a successful efforts approach. This restatement information andrevised accounting policies are presented in this preliminary announcement alongwith reconciliations from UK GAAP to IFRS. Basis of consolidation The Group financial information consolidates the financial information of theCompany and entities controlled by the Company (its subsidiaries). Control isachieved where the Company has the power to govern the financial and operatingpolicies of an investee entity so as to obtain benefits from its activities. Thefinancial information of subsidiaries are included in the consolidated financialinformation from the date that control commences until the date that controlceases. Joint operations are activities where the Group has joint control, establishedby contractual agreement. The consolidated financial information includes theGroup's proportionate share of the entities' assets, liabilities, revenue andexpenses with items of a similar nature on a line by line basis, from the datethat joint control commences until joint control ceases. All intra-group transactions, balances, income and expenses are eliminated onconsolidation. Foreign currencies The currency in which the group entities primarily generate and expend cash isUS dollars. In accordance with IAS 21, The Effects of Changes in ForeignExchange Rates, the group has adopted US dollars as its functional andpresentation currency. Transactions in foreign currencies are converted into US dollars at the rates ofexchange ruling at the transaction date. Gains and losses arising on therevaluation of foreign currency monetary assets and liabilities are recognisedin the income statement. Non-monetary assets and liabilities that are measuredin terms of historical cost in a foreign currency are translated using theexchange rate at the date of the transaction. The Group has taken advantage of the relief available in IFRS 1 to deem thecumulative translation differences for all foreign operations to be zero at thedate of transition to IFRS 1 (1 January 2004). Goodwill All business combinations are accounted for by applying the purchase method.Goodwill arising on consolidation represents the excess of the cost ofacquisition over the Group's interest in the fair value of the identifiableassets and liabilities of a subsidiary at the date of acquisition. Goodwill isstated at cost less any accumulated impairment losses. Goodwill is allocated tocash generating units and is not amortised but is tested annually forimpairment. The transitional relief in IFRS 1 has been applied to goodwill arising onacquisitions before the date of transition to IFRS. It has been retained at theprevious UK GAAP amount which was broadly comparable save that only separableintangibles were recognised and goodwill was not written off immediately toreserves. The classification and accounting treatment of business combinationsthat occurred prior to 1 January 2004 has not been reconsidered in preparing theGroup's opening IFRS balance sheet. Exploration and development costs Pre-licence acquisition expenditures on oil and gas assets are recognised as anexpense in the income statement when incurred. The Group has chosen to adopt IFRS 6, Exploration for and Evaluation of MineralResources, with effect from 1 January 2004, which is earlier than mandatory. Inaccordance with IFRS 6 exploration and evaluation costs are capitalised withinintangible assets until the success or otherwise of the well or project has beenestablished and are subject to an impairment review as described below. The costs of unsuccessful wells in an area are written off to the incomestatement: this is in accordance with the successful efforts accounting policybut is also compatible with IAS 36, Impairment of Assets, on the basis that theasset is impaired. If commercial reserves are established then the relevant cost is transferred(following an impairment review as described below) from intangible explorationand evaluation assets to development and production assets within tangibleassets. Expenditures incurred after the commerciality of the field has beenestablished are capitalised within development and production assets. The optional exemption under IFRS 1 to measure certain development/producingassets at the transition date to IFRS has been taken. This fair value has beenused on deemed cost. As required by IAS 8, Accounting Policies, Changes in Accounting Estimates andErrors, the Group applies established oil industry practice and expendituresrelating to properties or fields with commercial reserves are carried asdevelopment and production assets within tangible assets. Expected decommissioning costs of a property are provided for on the basis ofthe net present value of the liability, discounted at a pre-tax, risk-free rate,and an equivalent amount is added to the tangible cost pool. The gain or loss on disposal of development and production assets are recognisedon the income statement. Depletion and amortisation Depletion of development and production assets is calculated on a field or aconcession basis as appropriate. The calculation is based on proved and probablereserves using the unit of production method. Impairment and ceiling test Exploration and evaluation expenditures which are held as an intangible assetunder IFRS 6 are reviewed for indicators of impairment. If such indicatorsexist then the assets are tested for impairment by allocating the relevant itemto a cash-generating unit or a group of cash-generating units. An impairmenttest is also carried out before the transfer of costs related to assets whichare being transferred to development and production assets following adeclaration of commercial reserves. This impairment test is carried out inaccordance with IAS 36, Impairment of Assets, which requires that the impairmentbe calculated on the basis of a cash-generating unit which is a field or aconcession, as appropriate. A review for impairment indicators is also carried out each year on thecapitalised costs in development and production assets. This is carried out on afield or a concession basis, as appropriate. Under oil industry standardpractice this impairment test is calculated by comparing the net capitalisedcost with the net present value of future pre-tax cash flows which are expectedto be derived from the field or concession discounted at 10% per annum. Thisapproach is considered to be compatible with IAS 36. Plant, property and equipment Fixed assets, other than oil and gas assets noted above, are stated at cost lessaccumulated depreciation and impairment losses. Depreciation is charged to theincome statement on a straight line basis. Annual ratePlant and equipment 10 to 33% Fixed asset investments Investments in subsidiaries held by the Company are carried at cost. Derivative financial instruments Derivative financial instruments (other financial assets) are recognised at fairvalue. The gain or loss arising from the remeasurement in fair value isrecognised immediately in the income statement. Inventories Inventories are stated at the lower of cost and net realisable value. Trade and other receivables Trade and other receivables do not carry any interest and are stated at theirnominal value as reduced by appropriate allowances for estimated irrecoverableamounts. Cash and cash equivalents Cash and cash equivalents comprise cash balances and call deposits. Impairment The carrying amounts of the Group's assets, other than exploration anddevelopment costs and deferred tax assets, are reviewed at each balance sheetdate to determine whether there is any indication of impairment. If any suchindication exists, the asset's recoverable amount is estimated. An impairment loss is recognised whenever the carrying amount of an asset or itscash-generating unit exceeds its recoverable amount. Impairment losses arerecognised in the income statement. Calculation of recoverable amount The recoverable amount is the greater of net selling price and value in use. Inassessing value in use, the estimated future cash flows are discounted to theirpresent value using a pre-tax discount rate that reflects current marketassessments of the time value of money and the risks specific to the asset. Foran asset that does not generate largely independent cash inflows, therecoverable amount is determined for the cash-generating unit to which the assetbelongs. Reversals of impairment An impairment loss is reversed if there has been a change in the estimates usedto determine the recoverable amount. An impairment loss is reversed only to the extent that the asset's carryingamount does not exceed the carrying amount that would have been determined, netof depreciation or amortisation, if no impairment loss had been recognised. Interest bearing borrowings Interest-bearing borrowings are recognised initially at fair value lessattributable transaction costs. Subsequent to initial recognition,interest-bearing borrowings are stated at amortised cost with any differencebetween cost and redemption value being recognised in the income statement overthe period of the borrowings on an effective interest basis. Details of the Group's risk management policies and procedures are given in thefinancial review stated on pages 6 to 7. Trade and other payables Trade and other payables are not interest bearing and are stated at theirnominal value. Provisions A provision is recognised in the balance sheet when the Group has a presentlegal or constructive obligation as a result of a past event, and it is probablethat an outflow of economic benefits will be required to settle the obligation.If the effect is material, provisions are determined by discounting the expectedfuture cash flows at a pre-tax rate that reflects current market assessments ofthe time value of money and, where appropriate, the risks specific to theliability. Employee benefit Retirement benefit costs The group contributes to money-purchase pension schemes. Contributions arecharged to profit and loss as they fall due. Share-based payment transactions The share option programme allows Group employees to acquire shares of theultimate parent company; these awards are granted by the ultimate parent. TheCompany has the option to settle the Phantom Share Options as a cash payment.The fair value of options granted is recognised as an employee expense with acorresponding increase in equity. The fair value is measured at grant date andspread over the period during which the employees become unconditionallyentitled to the options. The fair value of the options granted is measured usingan option valuation model, taking into account the terms and conditions uponwhich the options were granted. The amount recognised as an expense is adjustedto reflect the actual number of share options that vest except where forfeitureis due only to share prices not achieving the threshold for vesting. As permitted by IFRS 1, these recognition and measurement principles have notbeen applied to grants of options prior to 7 November 2002. Revenue recognition Revenue derives from the amounts receivable from sales to third parties of oil,condensate and gas. Turnover is calculated where applicable under the rules ofrelevant production sharing agreements and includes taxation paid on behalf ofthe group. Operating lease payments Payments made under operating leases are recognised in the income statement on astraight-line basis over the term of the lease. Lease incentives received arerecognised in the income statement as an integral part of the total leaseexpense. Financing income and costs Financing income comprises interest receivable, net gain on disposal orremeasurement of the fair value of financial assets or investments and foreignexchange gains which are realised in the income statement. Financing costs comprises interest payable, net loss on disposal orremeasurement of the fair value of financial assets or investments and foreignexchange losses which are realised in the income statement. Interest receivable and interest payable is recognised in the income statementas it accrues, using the effective interest method. Adopted IFRS not yet applied The following IFRS were available for early application but have not beenapplied by the Group in these financial information: • IFRS 7 - Financial Instruments-Disclosure • Amendment to IAS 39 and IFRS 4 Dividends Dividends are reported as a movement in equity in the period in which they areapproved by the shareholders. Taxation Tax on the profit or loss for the year comprises current and deferred tax. Taxis recognised in the income statement except to the extent that it relates toitems recognised directly in equity, in which case it is recognised in equity. Current tax is the expected tax payable on the taxable income for the year,using tax rates enacted or substantively enacted at the balance sheet date, andany adjustment to tax payable in respect of previous years. Deferred tax is provided on temporary differences between the carrying amountsof assets and liabilities for financial reporting purposes and the amounts usedfor taxation purposes. The following temporary differences are not provided for:the initial recognition of assets or liabilities that affect neither accountingnor taxable profit other than in a business combination, and differencesrelating to investments in subsidiaries to the extent that they will probablynot reverse in the foreseeable future. The amount of deferred tax provided isbased on the expected manner of realisation or settlement of the carrying amountof assets and liabilities, using tax rates enacted or substantively enacted atthe balance sheet date. A deferred tax asset is recognised only to the extent that it is probable thatfuture taxable profits will be available against which the asset can beutilised. Deferred tax assets are reduced to the extent that it is no longerprobable that the related tax benefit will be realised. 2. Consolidated statement of recognised income and expenses Year ended 31 Year ended 31 December 2005 December 2004 $000 $000 Cash flow hedges - Effective portion of changes in fair value 13 (13)Net income recognised directly in equity 13 (13) Profit/(loss) for the period 22,407 (8,010) Total recognised income and expense for the year 22,420 (8,023) 3. Earnings/(loss) per share The weighted average number of ordinary shares used in the calculation of basicand diluted earnings per share for each period were calculated as follows: Year ended 31 Year ended 31 December 2005 December 2004 No. of shares No. of shares Issued ordinary shares at start of period 76,021,672 62,596,485Shares issued during the period 2,560,704 13,425,187Shares in issue at end of period 78,582,376 76,021,672 Weighted average number of ordinary shares at end of period 77,540,675 71,514,417Effect of share options in issue 2,251,344 1,809,748 Weighted average number of ordinary share at end of period - for 79,792,019 73,324,165diluted earnings per share 4. Dividends The Company intends to pay a dividend in 2006 of 1.5 pence per ordinary share(2005: 1 penny per ordinary share) amounting to approximately $2.1 million(2005: $1.3 million) which, if approved at the AGM, will be paid on the 13 July2006 to shareholders on the register on 23 June 2006. This proposed dividendhas not been provided for in the financial information in accordance with IAS10, but if approved at the Company's Annual General Meeting it will be deductedfrom retained profit of $22,407,000 which has been transferred to reserves. 5. Financial information and annual report The financial information set out in this preliminary announcement does notconstitute statutory accounts as defined in section 240 of the Companies Act1985. The comparative financial information is based on the statutory accountsfor the year ended 31 December 2004 as adjusted for the transition to IFRS (seenote 6 below). Those accounts, upon which the auditors issued an unqualifiedopinion, have been delivered to the Registrar of Companies. The consolidated balance sheet at 31 December 2005 and the consolidated incomestatement, consolidated cash flow statement and associated notes for the yearthen ended have been extracted from the Group's financial statements. Thosefinancial statements have not yet been delivered to the Registrar, nor have theauditors reported on them. Full accounts are due to be posted to shareholders in late April 2006 and willbe available from the Company's registered office, No. 1 Portland Place, LondonW1B 1PN, or from the Company's website at www.melroseresources.com from thatdate. 6. Explanation of transition to International Financial ReportingStandards As stated in note 1, this is the first annual financial information for theGroup to be prepared in accordance with IFRS. The accounting policies set out in note 1 have been applied in preparing thefinancial information for the year ended 31 December 2005, the comparativeinformation for the year ended 31 December 2004 and in the preparation of anopening IFRS balance sheet at 1 January 2004 (the Group's date of transition). In preparing its opening IFRS balance sheet and comparative information for theyear ended 31 December 2004 the Group has adjusted amounts reported previouslyin financial information prepared in accordance with its old basis of accounting(UK GAAP). An explanation of how the transition from UK GAAP to IFRS has affected theGroup's financial position, financial performance and cash flows is set out inthe following tables and the notes that accompany the tables. Group reconciliation of equity as at 1 January 2004 UK GAAP UK GAAP IFRS 1 IAS 1 IFRS 2 IAS 12 IFRS £000 $000 $000 $000 $000 $000 $000 Non-current assets Intangible assets 6,264 11,141 - - - - 11,141Tangible assets 82,397 146,542 - - - - 146,542Deferred tax 2,832 5,037 - 1,259 - 873 7,169Long-term receivables 1,687 3,000 - - - - 3,000 93,180 165,720 - 1,259 - 873 167,852 Current assetsTrade & other receivables 5,946 10,576 - (1,259) - - 9,317Cash & cash equivalents 3,425 6,091 - - - - 6,091 9,371 16,667 - (1,259) - - 15,408 Total assets 102,551 182,387 - - - 873 183,260 Current liabilities (15,148) (26,941) - - - - (26,941) Non-current liabilities (36,222) (64,421) - - - - (64,421) Total liabilities (51,370) (91,362) - - - - (91,362) Net assets 51,181 91,025 - - - 873 91,898 Equity Share capital 6,260 11,133 - - - - 11,133 Share premium account 48,589 86,416 - - - - 86,416Other reserves (5,091) (8,685) 8,685 - 67 - 67Retained earnings 1,423 2,161 (8,685) - (67) 873 (5,718) Total equity 51,181 91,025 - - - 873 91,898 Group reconciliation of equity as at 31 December 2004 UK GAAP UK 1 IAS 21 IFRS 1 IAS 1 Successful GAAP Efforts £000 $000 $000 $000 $000 $000Non-current assetsIntangible assets 9,545 18,388 - - -Tangible assets 104,417 201,639 114 - (1,384) (33,188)Deferred tax 3,041 5,859 73 - 1,801 9,605Long-term receivables 1,515 2,919 - - - - 118,518 228,805 187 - 417 (23,583) Current assetsInventories - - - - 1,384 -Trade & other receivables 10,984 21,162 (5) - (1,801) -Cash & cash equivalents 2,199 4,237 - - - - 13,183 25,399 (5) - (417) - Total assets 131,701 254,204 182 - - (23,583) Current liabilities (5,672) (10,929) 77 - (760) - Non-current liabilities (48,714) (93,853) - - 760 52 Total liabilities (54,386) (104,782) 77 - - 52 Net assets 77,315 149,422 259 - - (23,531) Equity Share capital 7,602 13,606 - - - -Share premium account 320 617 - - - -Special reserve 61,801 111,244 - - - -Other reserves (10,893) (9,321) 636 8,685 - -Retained earnings 18,485 33,276 (377) (8,685) - (23,531) Total equity 77,315 149,422 259 - - (23,531) Group reconciliation of equity as at 31 December 2004 - continued IFRS 2 IFRS 6 IAS 10 IAS 12 IAS 39 IFRS $000 $000 $000 $000 $000 $000Non-current assets Intangible assets - (26) - - - 18,362Tangible assets - - - - - 167,181Deferred tax - - - 2,841 (1,098) 19,081Long-term receivables - - - - - 2,919 - (26) - 2,841 (1,098) 207,543 Current assetsInventories - - - - - 1,384Trade & other receivables - - - - - 19,356Cash & cash equivalents - - - - - 4,237 - - - - - 24,977 Total assets - (26) - 2,841 (1,098) 232,520 Current liabilities - - 1,393 - (21) (10,240) Non-current liabilities - - - - 3,668 (89,373) Total liabilities - - 1,393 - 3,647 (99,613) Net assets - (26) 1,393 2,841 2,549 132,907 Equity Share capital - - - - - 13,606Share premium account - - - - - 617Special reserve - - - - - 111,244Other reserves 417 - - - (13) 404Retained earnings (417) (26) 1,393 2,841 2,562 7,036 Total equity - (26) 1,393 2,841 2,549 132,907 Group reconciliation of profit for the year ended 31 December 2004 UK GAAP UK GAAP IAS 21 IAS 1 Successful Efforts £000 $000 $000 $000 $000 Revenue 30,660 59,069 - - -Unsuccessful exploration costs - - - - (34,355)Other cost of sales (14,362) (27,669) - - 2,191Gross profit/(loss) 16,298 31,400 - - (32,164) Administrative expenses (2,148) (4,444) 310 (375) (1,024) Operating profit/(loss) before financing costs 14,150 26,956 310 (375) (33,188) Interest receivable 248 457 (6) - -Financing costs (4,043) (7,702) (1,226) 375 -Net financing costs (3,795) (7,245) (1,232) 375 - Profit/(loss) before taxation 10,355 19,711 (922) - (33,188) Taxation (2,677) (5,327) 168 - 9,658 Profit after taxation for the year 7,678 14,384 (754) - (23,530) Proposed dividend (760) (1,393) - - - Profit/(loss) for the year transferred to reserves 6,918 12,991 (754) - (23,530) Group reconciliation of profit for the year ended 31 December 2004 - continued IFRS 2 IAS 10 IAS 39 IAS 12 IFRS $000 $000 $000 $000 $000 Revenue - - - - 59,069Unsuccessful exploration costs - - - - (34,355)Other cost of sales - - - - (25,478)Gross profit/(loss) - - - - (764) Administrative expenses (350) - - - (5,883) Operating profit/(loss) before financing costs (350) - - - (6,647) Interest receivable - - - - 451Financing costs - - 3,660 - (4,893)Net financing costs - - 3,660 - (4,442) Profit/(loss) before taxation (350) - 3,660 - (11,089) Taxation - - (1,098) (322) 3,079 Profit after taxation for the year (350) - 2,562 (322) (8,010) Proposed dividend - 1,393 - - - Profit/(loss) for the year transferred to reserves (350) 1,393 2,562 (322) (8,010) IAS 21 - The Effects of Changes in Foreign Exchange Rates As part of the transition to IFRS the Group reviewed both the appropriateness ofthe existing reporting currency (UK sterling) and the underlying functionalcurrencies of the entities within the Group. Following this review it wasapparent that the functional currencies of all entities within the Group,including the Company, was US dollars and therefore the reporting currency forthe Group and Company should also be US dollars. This required the non USdollar entities books of account to be restated for the year ended 31 December2004. The restated amounts have been incorporated into the IFRS comparativestatements. IFRS 1 - First-time Adoption of International Financial Reporting Standards Elimination of other reserves IFRS 1 allows the inclusion of "other reserves" in "retained reserves" on theopening balance sheet at the date of transition. Under UK GAAP all revaluationand translation reserves were shown separately on the face of the balance sheet.Goodwill written off to reserves under UK GAAP prior to 1998 has not beenreinstated and is not included in determining any subsequent profit or loss ondisposal. The amount of $1,295,000 has been transferred from other reserves toretained reserves as at 1 January 2004. IAS 1 - Presentation of Financial Statements Deferred tax asset balances IFRS requires deferred tax asset balances to be shown as a separate line item onthe face of the balance sheet within non-current assets. Under UK GAAP deferredtax asset balances were included within current assets under the heading "Debtors" and split between amounts falling due after more than one year andamounts falling due within one year. Provisions Under UK GAAP, total provisions were disclosed as a separate line on the face ofthe balance sheet. IFRS requires that provisions are split between current andlong-term which has been disclosed in the restated IFRS balance sheets. Other financing income and costs Realised exchange gains and losses are included in administration expenses underUK GAAP. These have been reclassified as financing costs under IFRS. Successful Efforts Melrose has changed its oil and gas accounting policy from a full cost policy toa successful efforts policy. The comparative figures for 2004 have been restatedunder this policy. Under the full cost policy, all expenditure incurred inconnection with and directly attributable to the Group's oil and gas assets werecapitalised in geographic cost pools. Under the successful efforts accounting policy the costs of unsuccessful wellsare expensed in the income statement in the period they are determined to beunsuccessful. Depletion of development and production assets is calculated on afield or a concession basis, as appropriate. As required by IAS 36, Impairmentof Assets, impairment testing is performed on each individual cash-generatingunit which is either on a field basis or a concession basis, as appropriate. The Group has elected to use the relief available under IFRS 1 and to measureits development/production assets at the transition date to IFRS at fair valueand use this fair value on this deemed cost. IFRS 2 - Share-based Payment The Group applied IFRS 2 to its employee share option schemes at 1 January 2004for all share options granted after 7 November 2002. The Group previously accounted for these share-based payment arrangements atintrinsic value under UK GAAP. The adoption of IFRS 2 is equity-neutral for equity-settled transactions. A taxdeduction for the consumption of employee services received as consideration forshare options granted will be obtained when the share options are exercised.This has been taken into account in the tax calculations. The expense is derived based on the fair-value of the options granted spreadover the vesting period of the option. The transfer to the share option reservefor the year ended 31 December 2004 is $350,000 which was recognised in theincome statement. An amount of $67,000 in respect of the charges prior to thetransition date of 1 January 2004 was taken directly to reserves. IFRS 6 - Exploration for and Evaluation of Mineral Resources Pre-acquisition costs were capitalised under UK GAAP, whereas IFRS 6 specifiesthat all pre-acquisition costs of an asset must be expensed as incurred. IAS 10 - Events after the Balance Sheet Date In accordance with IAS 10, the dividend proposed as at 31 December 2004 wasreversed in the financial information for that period and is included as atransfer in equity following approval by the shareholders in the year ended 31December 2005. IAS 12 - Income taxes In accordance with IAS 12 - Income Taxes, the deferred tax asset in respect ofshare options is re-estimated at each period end to take account of changes inthe intrinsic value of the Company's share price and those share options whichhave been exercised in the period. The deferred tax asset relating to share options granted before 7 November 2002was increased by $1,600,000 in the year ended 31 December 2004. The deferred tax asset relating to share options granted after 7 November 2002was increased by $368,000 in the year ended 31 December 2004. The Group granted share options before 7 November 2002 and some of these vestedbefore 1 January 2005. As at 1 January 2004, the Group's date of transition toIFRS, a deferred tax asset arose in respect of the share options granted before7 November 2002 which had not been exercised by 1 January 2004. This deferredtax asset of $873,000 has been recognised in equity as at 1 January 2004. No deferred tax asset was recognised in respect of these unexercised shareoptions in the consolidated financial information prepared in accordance with UKGAAP. IAS 39 - Financial Instruments: Recognition and Measurement Loan arrangement fees IAS 39 requires loan balances to be carried at amortised costs. Under UK GAAPloan arrangement fees had been written off to profit and loss following receiptof the loans. Loan arrangements fees previously expensed amounting to$3,775,000 have been offset against the loan balances and are being amortised onan effective interest rate basis to the income statement. The Group had a cash flow hedge as at 31 December 2004 which is reflected in thebalance sheet as at 31 December 2004. The hedge expired during 2005. Cashflow statement adjustments The main adjustment to the cash flow statement as a result of the transition toIFRS is the inclusion of income taxes paid of $5,536,000 for the year ended 31December 2004 in the net cash inflow from operating activities. These amountswere included as a separate category of cash outflow in the cash flow statementsreported for those periods in accordance with UK GAAP. Glossary bbl barrel of oil or condensateBcf billion cubic feet of gasBcfe billion cubic feet of gas equivalentbcpd barrel of condensate per dayboe barrel of oil equivalentboepd barrel of oil equivalent per daybopd barrel of oil or condensate per daythe Company Melrose Resources plcEBITDAX earnings before interest, taxation, depletion, depreciation, amortisation and unsuccessful exploration costsGIIP gas initially in placethe Group the Company and its subsidiariesMbbl thousand barrels of oil or condensateMboe thousand barrels of oil equivalentMcf thousand cubic feet of gasMelrose the Company or the Group, as appropriateMMbbl million barrels of oil or condensateMMboe million barrels of oil equivalentMMcf million cubic feet of gasMMcfe million cubic feet of gas equivalentMMcfpd million cubic feet of gas per dayNPV10 net present value discounted at 10% per annumPDP proved developed producingpsi pounds per square inchPUD proved undevelopedTcf trillion cubic feet of gas This information is provided by RNS The company news service from the London Stock Exchange