Management Resource Solutions Regulatory News (MRS)

31 Mar 2005 07:01

Melrose Resources PLC31 March 2005 FOR IMMEDIATE RELEASE 31 March 2005 Melrose Resources plc Preliminary Announcement of Results for the year ended 31 December 2004 Melrose Resources plc, the oil and gas exploration and production company withinterests in Bulgaria, Egypt and USA, today announces its preliminary resultsfor the year ended 31 December 2004: 2004 HIGHLIGHTS Financial Highlights • 341% increase in turnover to £30.7 million (2003: £7.0 million); • 1,059% increase in operating profit to £14.1 million (2003: £1.2 million); • 174% increase in profits after taxation to £7.7 million (2003: £2.8 million); • 70% increase in EPS to 10.7p (2003: 6.3p); • Maiden dividend of 1.0p announced; • $75 million syndicated debt facility agreed in November 2004; Operational • Production commenced on the Galata Gas Field in Bulgaria: - 11.4 Bcf produced in period; - Current production 60MMcfpd; • 258% increase in production in Egypt: - 4.3 Bcfe output during year (2003: 1.2 Bcfe); • 44% increase in discounted present value of oil and gas reserves: - 14% increase in oil and gas reserves; • Exploration now stepped up in Bulgaria and Egypt: - 3-D seismic acquired in Bulgaria during Q3 2004; - new, potentially large, prospects identified in Bulgaria; - new prospects totalling 1Tcf in Egypt; • Production rate in US increased by 26 % over the year: - commencement of water injection on all principal fields; - 23 development wells planned for 2005; • Additional exploration licences secured in core areas: - South East El Mansoura Concession, Egypt, awarded in Q1 2005; - Emine and Rezovska licences acquired in Bulgaria; - Rhone Maritime Exploration Permit, France, acquired in February 2005; Commenting on this, Robert Adair, Chairman, said: "2004 has been a watershed year for Melrose, with the commencement of productionin Bulgaria and the increase in gas output from Egypt. The Company is nowutilising the cash flow from production to increase its exploration activitiesand new prospects in both Egypt and Bulgaria indicate that material reserveadditions are likely over the coming year. "The Board is also pleased to announce that the Company will commence thepayment of a dividend to complement the capital growth of the Company seen overthe past twelve months." 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/Eleanor Williamson 0207 466 5000Eric Burns 0194 388 3990 or visit our website at www.melroseresources.com. CHAIRMAN'S STATEMENT In 2004 Melrose achieved a number of its strategic goals: first production fromthe Galata gas field; successful appraisal and development drilling andincreased production in Egypt; development drilling and increasing production inthe USA; and an expanded shareholder base and a new corporate debt facility. Wemade good progress towards our objective of balancing our production,development and exploration assets. At the same time we have maintained theexposure of the Group to exploration projects which have the potential to addsignificant further value for shareholders. We are now positioned to pursue thisfurther upside potential with the support of our increased production and cashflow. Egypt In Egypt our priority was the continuing appraisal and development of the SouthBatra field area. We confirmed the extension of the proven area of the MioceneAbu Madi channel southwards and also encountered excellent quality Abu Madireservoir in the western part of the field. Recent good drilling results haveshown the benefit of the new 3-D seismic which has been acquired over the fieldarea. In total we now have 10 wells on production in the South Batra field area,6 from the Miocene and 4 from the Pliocene horizon. The exploration play on the western side of the El Mansoura Development Leasearound our Mansouriya discovery well is a Pliocene channel system which overliesthe Miocene. We have now drilled four successful wells on this trend and all areon production. The 3-D seismic has confirmed a number of similar channel trendsand this play type will be tested further in 2005. Exploration activity focused on the acquisition, processing and interpretationof an extensive 3-D seismic programme over the El Mansoura Concession. The 3-Dseismic acquisition covered an area of 1,700km(2), initially over the ElMansoura Development Lease and then over all the central and western areas ofthe El Mansoura Concession. The results of the initial interpretation of the new3-D look extremely promising with the Abu Madi channel system being furtherdelineated and the Pliocene play also throwing up a large number of newprospects across the whole of the survey area. We have now proven threeexploration plays in Egypt on the El Mansoura Concession - the Miocene and thePliocene horizons in the South Batra area and the Pliocene discoveries in theSouth Mansoura area. With our partner in Egypt, Merlon Petroleum, Melrose successfully applied forthe new South East El Mansoura Licence, an area of approximately 3,730km(2), inthe 2004 Licencing Round. We believe that the exploration plays which we havebeen following on El Mansoura extend south into the northern part of the newconcession. Bulgaria In Bulgaria we achieved first production from the Galata gas field in June 2004and I am pleased to report that the field production performance over the firstnine months has been very satisfactory. Gas sales from June to December totalled11 Bcf and production is continuing at a rate of approximately 60 MMcfpd. Fieldperformance and the 3-D seismic are confirming the extent of the structure andthe booked reserves. A development well, the Galata East, is planned formid-year to test a possible extension of the field. In 2004 we also increased our exploration activity in Bulgaria. In the autumn weacquired 1,470km(2) of new 3-D seismic with the main focus of the 3-D surveybeing the area of the "Oligocene Channel" which extends east from the south ofBlock 91-III into Block Kaliakra 99. The 3-D seismic has demonstrated that thechannel system is even more extensive than expected, spilling south into theSamotino More area of Block Kaliakra 99 as well as trending east-southeast intoa well-developed submarine fan system as originally anticipated. In the shortterm, drilling operations will be focused on more obvious prospects in BlockKaliakra 99 and it is expected that following interpretation of the new seismica well to test a structure in the shallow water shelf area of Kaliakra, probablyin the Samotino More area, will be drilled in mid-2005. Also in Bulgaria, we have recently agreed to purchase, subject to governmentapproval, the 100% interests in two further offshore concessions, Emine andRezovska. The northern area of the Emine concession is adjacent to a prospectivearea of Block Kaliakra 99 and we believe that some prospects will overlap intothis area. The Rezovska concession area bounds a prospective channel/fan systemwhich we think will have drilling potential after a programme of 3-D dataacquisition and evaluation. USA We have continued to make good progress with our development plan in the USAwith 16 new wells drilled during 2004 and active water injection now on allthree principal fields. The programme of development drilling will bemaintained over the next two years as we seek to achieve our goal of USproduction of 3,000 boepd. France In December 2004, we agreed to acquire a 100% interest in the Rhone-Maritimeconcession, offshore France in the Mediterranean Rhone Delta. The Frenchauthorities have approved the transfer of the beneficial interest in theconcession and the formal transfer of the licence interest is under way. TheConcession is currently 25,000km(2) in area and we intend initially to acquireinfill 2-D seismic and then 3-D seismic prior to seeking partners forexploration drilling in this deep-water area. A number of very strong and largeleads with huge potential have already been identified on the block. Thestructures already identified in the post-salt play are capable of trapping gasvolumes in excess of 10 Tcf and also have the potential for oil. The capitalinvestment required on the project in the short term is not large and we seethis block as adding further potential for the Group as our current projectsbecome more mature. Finance Increased production in 2004 has been reflected in good financial performancewith a profit after tax of £7.7 million and earnings per share of 10.7 pence. Amaiden dividend of 1 penny per share will be proposed for approval at the AnnualGeneral Meeting in June, to be paid on 13 July. Subject to our capitalrequirements, it will be our intention to increase the level of dividendprogressively as our production increases. Outlook 2005 will be another busy year for Melrose. Until recently we outsourced themajority of our geotechnical work. With the increase in our explorationactivity we have recruited what I believe is a very good team of geoscientists.They are focused on increasing our understanding of our properties and planningthe work programme. I am confident that this approach is already bringingsignificant benefits. This is an important step in helping Melrose to unlockthe upside potential of our asset base. In Egypt, the focus is shifting from development/appraisal of the South Batrafield to exploration. We anticipate drilling around 18 wells, of which at least8 are likely to be exploration, testing prospects with potential typically inthe range 50 - 150 Bcf. In Bulgaria we are likely to drill at least two wells,the Galata East development well and an exploration well on Block Kaliakra 99with 500 Bcf potential offsetting a well in the Samotino More area that testedgas. Our geotechnical team is devoting considerable effort to interpreting the3-D seismic on Block Kaliakra 99 which looks to have several prospects with agreater than 1 Tcf potential each. In the USA we will continue to addsignificant value through our 3 waterflood projects and development drillingwith up to 23 wells planned. I believe that we have an exceptionally attractivedrilling programme which is balanced with growing levels of production. During 2004 we completed two issues of new share capital, raising a total of£24.6 million net of expenses and I welcome new shareholders who joined us. Ithank all of our shareholders for their continuing support and management andstaff for their commitment and achievements. R F M AdairChairman30 March 2005 FINANCIAL REVIEW Results for the year Turnover for the year was £30.7 million which compares with turnover of £7.0million in 2003. Turnover derived from Egypt was £9.1 million (2003: £2.9million), Bulgaria £16.1 million (2003: nil) and the USA £5.5 million (2003:£4.1 million). Profit after tax amounted to £7,678,000 (2003: £2,796,000) after taking intoaccount a tax charge of £2,677,000 (2003: credit of £2,487,000). This taxcharge comprised a charge for overseas corporation tax of £2,832,000 (2003:£835,000) and a net deferred tax credit of £155,000 (2003: credit £3,322,000).The deferred tax credit arises because of the expected use of tax losses in theUK and is net of a deferred tax charge of £1,164,000 which results from areduction in the Bulgarian tax rate from 23% to 15%. Earnings in sterling wereadversely affected by the weakness in the US dollar, which is the Group'sprincipal operating currency and which depreciated by approximately 8% during2004. Realised foreign exchange gains of £258,000 arose during the year (andhave been included in administrative expenses) compared with losses of £535,000in 2003. A maiden dividend of 1 penny per share is being proposed. After the dividend of£760,000, profits of £6,918,000 will be transferred to reserves. EBITDA for the year of £25.5 million compares with £2.4 million for the previousyear: 2004 2003 £000 £000 Operating profit 14,150 1,220Add back:Depreciation 53 29Depletion 10,976 1,161Decommissioning provision 311 - 25,490 2,410 In Egypt, the average condensate price received during the year was $37.27 perbbl (2003: $23.70 per bbl). The average gas price received was $2.64 per Mcf(2003: $2.74). The average price per boe in Egypt was $16.76 (2003: $16.99).Operating costs per boe in Egypt reduced by approximately 48% to $1.04 due tothe effect of increased production on production costs which are partly fixed.Net cash flow per boe increased by 5% to $11.29. The depletion charge was $4.43per boe (2003: $4.24). The average gas price received in Bulgaria was $2.71 per Mcf which is equivalentto $16.23 per boe. This price reflected the fact that a high proportion of thegas was sold at the lower summer price. Operating costs per boe in Bulgaria were$0.40 per boe and the royalty payable was $0.41 per boe giving net cash flow of$15.42 per boe. The depletion charge was $8.68 per boe which reflected theaddition of unsuccessful exploration costs in Bulgaria of $14.7 million to thetangible cost pool for depletion. Average prices received during the year in the USA were $36.68 per bbl (2003:$27.86 per bbl) and $5.88 per Mcf (2003: $4.97) representing a 28% increase inthe average price per boe. Operating costs in the USA increased byapproximately 21% to $12.37 due principally to the increased well count andhigher maintenance and utility costs. Net cash flow per boe increased by 32% to$24.01. The depletion charge increased slightly to $5.02 per boe (2003: $4.59). Additions to the oil and gas assets of the Group during the year totalled £44.4million. This was split, geographically, £18.5 million in respect of propertiesin Egypt, £20.5 million in Bulgaria and £5.4 million in the USA. 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. In November 2004, in connection with the new loanfacilities referred to below, the Group entered into a derivative contract whichhedged part of the Group's oil production in the USA. Under the contract oilproduction of 12,000 barrels per month for the period December 2004 untilNovember 2005 was hedged in a no-cost collar with a put price of $22 per bbl andcall price of $68 per bbl. The mark-to-market value of the hedge as at 31December 2004 was a liability of $21,000. 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 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 2004 was£1.4 million. Currency risk The Group has an exposure to foreign currency risk as all of its revenue and themajority of its expenditures are denominated in US dollars. The majority ofthis risk is a reporting risk due to the reporting currency of the Group.However, a commercial risk arises to the extent that overhead costs and capitalexpenditures are incurred in costs other than US dollars. In addition, untilthey were refinanced in November 2004 interest on the Company's Sterling bankloans was payable in Sterling. 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 only in US dollars or inSterling. Repayment of the Sterling debt in November 2004 has aligned thecurrency of all Group indebtedness with the Group's main functional currency.Reporting in US dollars would remove most of the currency risk from the Group'sresults and consideration will be given to changing the Group's reportingcurrency for 2005 to US dollars. 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 2005 capital expenditures in Egypt is approximately $45.5million, of which approximately $27.9 million is for exploration and $17.6million is for appraisal and development. In Bulgaria, budgeted developmentexpenditures are approximately $14.9 million and budgeted firm explorationexpenditures are approximately $10.9 million. Budgeted capital expenditures in2005 in the USA are approximately $14.2 million. Loan facilities In November 2004 the Group refinanced its bank indebtedness. The Group enteredinto new four-year corporate loan facilities amounting to $75 million inaggregate with Standard Bank London Limited as lead arranger. The facilitiescomprised a $50 million syndicated commercial bank facility and a $25 millionfacility from the International Finance Corporation. Senior project debt for thedevelopment of the Galata field, a revolving credit facility in the USA andcorporate debt of the Company were repaid. At the same time, the Group refinanced and partly repaid the existing mezzaninefinance relating to the development of the Galata field with a new $21 millionunsecured subordinated term loan provided by the same mezzanine lender. As partof this refinancing Melrose also acquired the net profit interest that wasattached to the mezzanine finance and, consequently, Melrose is now the owner of100% of the reserves in the Galata field. The consideration paid for theacquisition was $6.9 million which has been included in capital expendituresduring the year. Equity financing During the year the Company completed two issues of new Ordinary Shares. InFebruary 2004, the Company completed a Placing of 6.25 million Ordinary Sharesat 175 pence per share which raised £10.7 million net of expenses. In July 2004the Company raised £13.9 million net of expenses through a Firm Placing and aPlacing and Open Offer at 210 pence per share. A further 372,282 shares wereissued following the exercise of share options. At 31 December 2004, the Group had cash balances of approximately £2.2 millionand bank and other loans totalling £44.1 million. Available borrowing capacityunder bank loans totalled £5.7 million. 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 accounts have been prepared on the going concern basis. REVIEW OF OPERATIONS BULGARIA The interests of Melrose in Bulgaria are located offshore in the western BlackSea which is an underexplored oil and gas province but where there is clearevidence of an active and extensive petroleum system. In 2004 a significant new3-D seismic programme was undertaken by Melrose over the southern areas of Block91-III and Block Kaliakra 99. The Group's exploration priorities in Bulgaria arecurrently being formulated in the light of this new data and a betterunderstanding of the geology of the area. Galata Gas Field First production from the Galata gas field was achieved in June 2004 andproduction for the seven months to year-end averaged 55 MMcfpd. Production fromthe Galata field is sold to Bulgargaz, the state-owned importer and distributorof gas in Bulgaria, which contracted to purchase 14.1 Bcf of gas per year for aminimum of 3 years. A second gas contract, with a local gas marketing company,provided for sales of 3.5 Bcf in 2004 and 2005 with further commitmentsdependent on the level of proved reserves. The two Galata production wells have both been flowed individually at rates ofapproximately 50 MMcfpd and wellhead pressures are currently holding up well.The proved and proved plus probable field reserves were estimated at 65 Bcf and90 Bcf respectively in 2003 based on pressure data from the development wells.The field pressure response is validating those estimates and year-end reserveshave been maintained at these levels, adjusted for production. Based on theproduction performance and the new pressure data, it is now confirmed that thereis pressure connection between the northern and southern fault blocks of theGalata structure. As expected, the main good quality reservoir has contributedoverwhelmingly to the initial flow but there is now evidence of pressure supportfrom other less permeable or fault separated reservoir intervals. In addition tothe main reservoir section it is thought that gas may be being produced from anunderlying limestone section or that there may be communication with adownthrown fault terrace to the east of the main structure. A development wellwill be drilled in this Galata East fault block during 2005 in order to furtherevaluate its potential and to maintain or enhance the deliverability of theGalata field. Block 91-III The area of Block 91-III, which extends from Kaliakra in the north to Kamchia inthe south, is 1,690km(2). The block encompasses, but does not include, theGalata Production Concession. The evaluation of the remaining hydrocarbonpotential of the block was a priority for the company during 2004. Two wellswere drilled on the concession during the second half of the year. The VarnaWest well was seen as an analogy to the Galata structure, sitting on the edge ofthe Blitznazi fault to the west of Galata and with the expectation of sourcingfrom the Oligocene channel feature identified to the south. The structure wasdry and it appears that the Oligocene channel culminates immediately to thesouth of the Galata field and is breached at the crest adjacent to the field.Biogenic gas from the Oligocene shales is thought to source the Galata field atthis point, via the Blitznazi fault, but gas had not migrated west to fill theVarna West feature. The second well, the Shimanov-A, tested the best of the northern prospects withOligocene clastics as the primary target and Eocene clastics and nummuliticlimestones as secondary targets. Disappointingly, this well was a dry hole.Further seismic will be required to evaluate the potential of the more complexnorthern area and in the short term the exploration focus will not be on thisarea. In September and October, a major 3-D seismic survey was conducted over 1,470km(2) of the southern parts of Block 91-III and Block Kaliakra 99. The unprocesseddata is of excellent quality and the fast-track processing has now beenreceived. Only a broad qualitative assessment of potential has so far been madeand further processing, particularly in the shallower water areas of Block91-III, will be required. In the deeper water area of the survey, particularlytowards the south of Block Kaliakra 99, a number of large leads/prospects arebeing seen as the offshore slope channel fan systems start to develop. It is nowthought that the best prospectivity will lie on Block Kaliakra 99 with lesserpotential on Block 91-III. In view of this new interpretation of the channelsystem through this area, where the orientation of the prospective horizons canbe seen more clearly than on the 2-D seismic dataset, all efforts are now beingconcentrated on the detailed evaluation of the Kaliakra area. The current Block 91-III Licence extension expired in October 2004 and a furtherextension of the term of the Licence was discussed with the Ministry ofEnvironment and Waters. However, a one-year extension was not seen as sufficienttime to allow the comprehensive work programme required to evaluate someinteresting but complex geology and it was decided to relinquish the currentLicence and request the re-tender of the area on the basis of the availabilityof a new exploration licence of up to seven years. This process is now underwayand the work programme required to properly evaluate the new block will beconsidered in the coming months as part of the tendering process. Block Kaliakra 99 Block Kaliakra 99 is contiguous with Block 91-III to the east and south. Theblock covers an area of 2,601km(2) in water depths mostly less than 500m. Allthe work programme obligations for the first 3-year exploration period whichexpired in May 2004 were fulfilled, including the acquisition of 120km ofinfill 2-D seismic over the southern part of the block. A 2-year extension wasapplied for and was granted and a final 2-year extension will be availablethereafter. The new 3-D survey over the southern area of the concession was an importantstep in the evaluation of the hydrocarbon potential of this block. Several leads/prospects have already been identified in the shallow shelf and deeper watercovered by the survey. Current plans for 2005 are to drill an exploration wellin shallower water, probably in the Samotino More area where a well drilled in1986 by the Ministry of Environment and Waters tested gas and condensate. Thiswell is now thought to have just penetrated the edge of a largestratigraphically-defined channel running NW-SE. Further analogous systems occuras channels develop at different levels to the east. Initial indications arethat structures of the order of 1 Tcf or more are present. Full detailedevaluation and prospect risking will be carried out after the receipt of thefinal processing of the 3-D seismic which is expected in April 2005. In the northern area of Block Kaliakra 99, Palaeocene clastics and Late Jurassic/Early Cretaceous carbonates analogous to the producing reservoir in the onshoreTulenovo oil field constitute the primary reservoir objectives. It is thoughtthat this area has significant potential, with oil the most likely hydrocarboncharge for the structures identified. In due course there will be a requirementto acquire additional 2-D seismic in the north-western area of the block. As part of the strategy for exploration in the area, the purchase and exchangeof additional existing regional 2-D seismic data has been agreed. The dataacquired are enhancing understanding of the exploration potential of theacreage, particularly in the northern part of Block Kaliakra 99. In due courseMelrose will consider the possibility of seeking a larger company to jointventure in the exploration plays in deeper water. Emine and Rezovska Concessions Agreement has been reached, subject to Government approval, for the acquisitionof two additional blocks in the Bulgarian Black Sea. Block Emine is locateddirectly south of the Block Kaliakra 99 and extends to the southern Bulgarianborder covering 4,495km(2) of the shallow marine shelf of offshore Bulgaria.Block Rezovska is located on the south-east corner of the Emine concession areaand covers 600km(2) of the slope region. The water depths within the two blocksrange from less than 20m to just over 750m. Reprocessed 2-D data of variousvintages exists across the concessions. The blocks are located within the sub-marine extension of a regionalcompressional system. The prospects and leads located within these blocks areall related to the large folded structures that resulted from this 'crumpling'event. Two play types have been identified. The first of these is produced bythe clastic Lower Tertiary sediments that 'drape' over deeper folds. These largeelongate structural closures have great potential to be charged with significantvolumes of hydrocarbons sourced from three potential oil and gas bearingintervals (mid-Jurassic, Oligocene and Miocene shales). The second of the playtypes is the Palaeocene - Upper Cretaceous calcareous sandstones which sub-cropalong an unconformity into an overlying shale seal. Again these strata have thepotential to be charged by migrating hydrocarbons sourced from the same threesource intervals. From these play concepts a large number of structural leadshave been mapped but no wells have yet been drilled in this area. EGYPT Activity in Egypt in 2004 was concentrated largely on the delineation anddevelopment of the discoveries on the El Mansoura Concession. There has beensome exploration drilling and several smaller discoveries have been made. El Mansoura Concession Following the South Batra and Mansouriya discoveries in 2003 the area of the ElMansoura Development Lease was negotiated and confirmed late that year. Most ofthe drilling in 2004 has been within this Lease area. All of the wells drilledand completed in 2004, 5 Pliocene and 3 Abu Madi wells, are now on production. The Abu Madi channel system delineation programme has demonstrated thatreservoir quality is better on the channel margins (South Batra Nos.4 & 7). Inthe Central field area around the South Batra No.1 discovery well, there is onecompletion in the Level II Abu Madi (South Batra No.2A) and four completions inthe Level III (South Batra Nos.1, 3A, 14 & 17). In the Pliocene play in the South Batra field area, three successful wellsdrilled in 2004 (South Batra Nos.15, 8 & 18) have further delineated theMansouriya Channel. These western area wells, along with the South Batra Nos.4 &7, are all connected to the main South Batra gas plant through a newlyconstructed gas gathering station at the South Batra No.11 location. The sameMansouriya Channel interval at around 7,100ft can be seen on the logs of theSouth Batra Nos.4, 7 & 14 giving behind-pipe reserves in these wells. Thesebehind-pipe intervals are not obvious on the seismic and this suggests that thetotal area of the Mansouriya trend could be much greater than the existingmapping which is based solely on the interpreted amplitude anomalies. This alsomakes evaluation of Pliocene prospects more complicated as prospects may havelarger areas than is apparent from the seismic albeit with thinner or poorerreservoir sections. One further Mansouriya trend well (South Batra No.17) is planned to the south ofNo.18 and this well will also be drilled to the Abu Madi and deeper Miocenehorizons in order to evaluate the extension of the Abu Madi Channel stillfurther to the west. There is a high ratio of Probable to Proven reservesassigned in this area because of the interpretation of the anomalies referred toabove. There is also significant potential for an extension of the area of thereservoir attributable to poorer quality or thinner pay sections which are notobvious from interpretation of the seismic. An example of this is the Aga No.1 discovery well which was drilled in the SouthMansoura area and was completed in the secondary Pliocene objective. The seismicanomaly was relatively small but is possibly connected to a number of othersmaller anomalies by poorer or thinner reservoir. This well has been connectedto the South Mansoura gathering system and is effectively under long-term test.This well was also of interest because it tested condensate with the gas, albeitonly small quantities. This is the first evidence of the presence of condensatein the Pliocene reservoirs in the El Mansoura area. Further smaller discoveriesmade in 2004 in the southern area are Mit Dafir and Al Arab both of which awaithook-up to the facilities and production testing. The 3-D seismic acquisition has now been completed. 1,700km(2) of data have beenacquired and final processing has been received on just over half this area. Itis expected that three drilling rigs will continue to operate on the El MansouraConcession in 2005. Currently two rigs are active on the South Batra developmentand the third rig is available for exploration drilling. Exploration effortswill now be focused on the western side of the Concession but the final data forthe north-east quadrant is awaited with some interest as there are several veryinteresting prospects emerging in both the Abu Madi and the Kafr el Sheikhhorizons in this area. The seismic crew has been released for three months andwill then be available to acquire a further survey over the now-separatedeastern part of the concession. The final 2-year exploration period of the ElMansoura Concession commenced in June 2004 and 25% of the remaining area wasrelinquished at that point. South East El Mansoura Concession The South East El Mansoura Concession is located immediately to the south of theEl Mansoura Concession and covers an area of 3,730km(2). Three important playfairways have been identified within the block. The first of these is theOligocene Dabaa formation, which comprises fluvial sand deposits that infill amajor N-S trending valley system. This fluvial system crosses the entire blockand extends out to the current offshore region of the Nile Delta through the ElMansoura Concession and differs from the marine Tineh sand deposition in theeast of El Mansoura and Qantara. The second of the fairways is the establishedMiocene Abu Madi formation, which is a southerly extension of the Abu Madi playwithin the El Mansoura Concession. The huge canyon systems that developed duringthe Miocene (which include the Abu Madi Canyon) run from south to north acrossthe new block and through the El Mansoura Concession to the north out into theMediterranean Sea. The fill within these canyons, comprising channel sandsfollowed by marine clastics, is the prime exploration target in the new area.Directly above this sequence is the third play, the Pliocene Kafr el Sheikhformation. The entire area lies to the east of the Damietta Branch of the Nile,to the north of Cairo, and it is possible that some of the Western Desert plays(Cretaceous and Jurassic) may extend eastwards into the south-western area ofthe block. Qantara Concession The smaller Qantara Concession area has continued to prove difficult. Thedecision was taken to drill a shallow, low risk and relatively low reservepotential well, Qantara No.9, in order to re-establish commercial productionthrough the gas plant. The seismic indicated a strong amplitude anomaly and highgas saturations were encountered in the target formation but open hole testingof the interval was unsuccessful. The well was plugged and abandoned. Subsequent regional geological work has suggested that the northern area of theConcession should be more prospective than the south and the next step will beto acquire 3-D seismic over this area. Some larger Kafr el Sheikh leads havebeen identified and it is thought that the Qantara formation should be moreprospective north of the major "Hinge Zone" which runs E-W through the middle ofthe concession. Qantara still has considerable upside potential but further workwill be required to unlock it. The Qantara No.1 well still produces intermittently at relatively low rates ofaround 0.2 MMcfpd and a sidetrack of the existing Qantara No.4 well will beconsidered in order to access the remaining proved reserves in the Qantarastructure. USA The Group's interests in the USA comprise three main field areas totallingapproximately 25,000 gross acres concentrated in the Permian Basin in Eddy andLea Counties, New Mexico, and Mitchell County, Texas. Melrose has approximately100% working interests in, and is operator of, the majority of these properties.The properties are mature oilfields which have substantial, low-risk developmentupside with 73% of the proved reserves currently undeveloped. Much of thisupside is accessible through waterflooding, a secondary recovery technique thatis a standard procedure and is widely used throughout the Permian Basin. During 2004, 16 wells were drilled on leases in which Melrose has a 100% workinginterest and the Group also participated in the drilling of a further 10 wellsin which it has a minority working interest. Approximately 750 Mboe of reserveswere developed at a cost of $7.51 per boe. Work on the Group's three principalwaterflood projects was stepped up with 15 water injection wells activated and24 shut-in wells brought back onto production. Total oil and gas reserves attributable to the Group's interests in the USAremained broadly unchanged at 14.3 MMboe (2003: 14.4 MMboe), but proveddeveloped reserves increased by 13% to 3.8 MMboe, which represents reservereplacement of 256% of 2004 production. Overall, production increased by 26%from 797 boepd in December 2003 to 1,004 boepd in December 2004, with fullproduction potential including wells drilled but not on production at year endestimated to be approximately 1,200 boepd. In 2005, Melrose will continue to implement its short-to-medium term developmentplan targeting production of 3,000 boepd. Up to 23 new development wells areplanned along with the ongoing waterflood projects on the Jalmat, Artesia andTurner Gregory field interests. Jalmat field interests Development of the Jalmat field interests is now at an advanced stage with theinfill drilling programme nearing completion and the waterflood programme nowbeing implemented. In total, 11 wells were successfully drilled and completedduring 2004, with 544 Mboe of PUD reserves being converted to PDP reserves.Initial production rates from these wells averaged 85 boepd, significantlyhigher than the projected rate of 50 boepd. In addition, new water injectionfacilities were constructed during 2004 and 6 water injection wells wereactivated. Net daily production from the Jalmat field interests increased by56% during 2004 to 450 boepd by December 2004. As a result of this successfuldrilling programme, a further 9 infill locations have been identified and anadditional 450 Mboe of PUD reserves have been booked. Since the redevelopment of this field commenced in 2001, 26 new wells have beendrilled at a development cost of $6.46 per boe and production has increased from90 boepd to in excess of 400 boepd. Over this period 321 Mboe of reserves havebeen produced and 2,890 Mboe of reserves have been added. This has been achievedby reinvestment of cash flow plus an investment of less than $2 million of newcapital. This demonstrates the potential reserve and value upside which isresulting from successful development of the US assets. Artesia field interests Three new wells were drilled during 2004 in the Artesia field and the Group alsoparticipated in 10 new non-operated wells on the State D lease. Approximately200 Mboe of reserves in total were converted to PDP reserves. Daily productionfrom the Group's interests in the Artesia field increased by 42% during 2004 to280 boepd by December 2004. After some regulatory delays, permits have now beenissued to commence water injection on the Artesia Unit and work is underway.Further development wells are planned after the waterflood support has reachedthe desired level. Turner Gregory field interests Work on the Turner Gregory Unit in 2004 was focused on bringing wellbores intoregulatory compliance, including the abandonment of some old wells, prior towater injection operations commencing. In the meantime, average dailyproduction declined in line with expectations by 10% during 2004 to 106 boepd. Other interests During the year, net proceeds of $2 million were realised from the sale ofmineral rights covering approximately 8,000 acres in Parker, Palo Pinto and JackCounties in the Fort Worth Basin in Texas. This acreage contains the prolificBarnet Shale play which is the largest natural gas play in Texas and is beingaggressively developed by a number of US domestic producers. This is currentlyan exploration play and is non-core to Melrose's US operations, but Melrose hasretained a royalty interest and an option to participate in any wells drilled onthis acreage, with exploration potential of approximately 10 Bcf attributable tothese retained interests. FRANCE In 2004 Melrose reviewed a number of new opportunities in the focus area of theMediterranean Rim and in December 2004 agreement was reached to acquire theRhone-Maritime concession, offshore France in the Mediterranean Rhone Delta.While the Rhone Delta is little explored and, therefore, a frontier area, it isa large river delta system whose potential has been overlooked, largely becauseof its deepwater setting. The Rhone Maritime Exploration Licence is located in the Gulf of Lion off thesouthern Mediterranean coast of France. The licence area covers more than25,000km(2) of this under-explored province and currently only 4,305km of 20012-D seismic data exists across the acreage. Two wells were drilled in theshallow-water shelf in the northern part of the concession in the 1970s whendrilling technology was limited to water depths of around 100m. Water depthsover the area of the concession average around 2,000m. Two major play fairways, divided by a thick salt sequence, have been recognisedacross the basin. The shallower post-salt Pliocene interval pinches out to thenorth before reaching the shallower water of the coastal shelf and has thereforenot been penetrated by either of the old wells. The interval has undergonesignificant structuring over time caused by deformation and flow of the saltlayer beneath. This folding and faulting has resulted in large closures thatcould accommodate sizeable accumulations of hydrocarbons. Within this sectionabundant AVO anomalies, suggesting the presence of hydrocarbons, have beenidentified in the seismic dataset and the combination of very large structuresand hydrocarbon indicators is very promising. The second of the two play fairways is the deeper pre-salt Miocene interval.This thick Miocene sequence directly underlies the salt and has distinct seismicreflection characteristics that could also indicate the presence ofhydrocarbons. As with the post-salt play this succession pinches out beforereaching the shelf area to the north. The sequence is inferred to compriseturbidite deposits with reservoir, seal and source rocks all present. It is thought that this concession has great potential and further 2-D and 3-Ddata will be acquired in the expectation of confirming its prospectivity. Thestructures already identified in the post-salt play are capable of trapping gasvolumes in excess of 10 Tcf and also have the potential for oil. The goal willbe to farm down from the current 100% ownership prior to committing to anexploration drilling programme. Proved and Probable Reserves At 31 December 2004 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 97 24,679 53,614 2,778 6,126 2,875 84,419Proved undeveloped 179 12,188 - 9,300 7,370 9,479 19,558Proved 276 36,867 53,614 12,078 13,496 12,354 103,977 Probable developed 98 23,945 - - - 98 23,945Probable undeveloped 385 56,856 25,000 - - 385 81,856Probable 483 80,801 25,000 - - 483 105,801 Developed 195 48,624 53,614 2,778 6,126 2,973 108,364Undeveloped 564 69,044 25,000 9,300 7,370 9,864 101,414Proved and probable 759 117,668 78,614 12,078 13,496 12,837 209,778 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 independent 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 2004 988 76,098 83,425 11,993 14,304 41,952 251,713Acquisitions - - 6,575 - - 1,096 6,575Extensions and - 45,245 - 409 243 7,990 47,942discoveriesRevisions (198) 484 - (93) (678) (323) (1,940)Production (31) (4,159) (11,386) (231) (373) (2,915) (17,490)At 31 December 2004 759 117,668 78,614 12,078 13,496 47,800 286,800 Discounted Net Present Value The net present value, discounted at 10% per annum, of the Group's proved andprobable reserves at 31 December 2004 was as follows: Egypt Bulgaria USA TotalDiscounted net present value (NPV10) $000 $000 $000 $000 Proved developed 50,415 94,601 44,951 189,967Proved undeveloped 16,746 - 91,881 108,627Proved 67,161 94,601 136,832 298,594 Probable developed 39,369 - - 39,369Probable undeveloped 66,096 31,158 - 97,254Probable 105,465 31,158 - 136,623 Proved and probable 172,626 125,759 136,832 435,217 The discounted net present value is based upon the following pricingassumptions: • USA: $30.0 per barrel of oil and $5.00 per Mcf• Bulgaria: $2.77 per Mcf• Egypt: $30.0 per barrel of condensate, $4.93 per Mcf (Qantara) and $2.50 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 summarised profit and loss accountYear ended 31 December 2004 2004 2003 Note £000 £000 Turnover 30,660 6,955 Cost of sales (3,075) (1,713)Depletion (10,976) (1,161)Decommissioning charge (311) - Gross profit 16,298 4,081Administrative expenses (2,148) (2,861) Operating profit 14,150 1,220Net interest payable (3,795) (911) Profit on ordinary activities before taxation 10,355 309Taxation on profit on ordinary activities 3 (2,677) 2,487 Profit on ordinary activities after taxation 7,678 2,796Proposed dividend (760) - Profit for the year transferred to reserves 6,918 2,796 Earnings per share (p) 4 10.7 6.3 Consolidated summarised balance sheetAs at 31 December 2004 2004 2003 £000 £000Fixed assetsIntangible assets 9,545 6,264Tangible assets 104,417 82,397 113,962 88,661Current assetsDebtors: Amount falling due after more than one year 4,556 4,519Amount falling due within one year 10,984 5,946 15,540 10,465Cash at bank and in hand 2,199 3,425 17,739 13,890 Creditors: amounts falling due within one year (5,672) (15,148) Net current (assets)/liabilities 12,067 (1,258) Total assets less current liabilities 126,029 87,403 Creditors: amounts falling due after morethan one year (44,119) 32,095 Provision for liabilities and charges (4,595) (4,127) 77,315 51,181 Capital and reservesCalled up share capital 7,602 6,260Share premium account 320 48,589Special reserve 61,801 -Other reserves (10,893) (5,091)Profit and loss account 18,485 1,423 Equity shareholders' funds 77,315 51,181 Consolidated summarised cashflow statementYear ended 31 December 2004 Note 2004 2003 £000 £000 Net cash inflow/(outflow) from operating activities 5 20,137 (2,509) Returns on investments and servicing of financeInterest paid (4,724) (1,001)Interest received 248 36 Net cash outflow from returns on investments and (4,476) (965)servicing of finance Tax paid (2,832) (835) Capital expenditure and financial investmentPurchase of intangible fixed assets (13,217) (7,832)Purchase of tangible fixed assets (34,760) (30,305)Cost of decommissioning (234) -Disposal of tangible fixed assets 970 279Disposal of fixed asset investments - 13 Net cash outflow from capital expenditure andfinancial investment (47,241) (37,845) FinancingBorrowings raised 33,611 28,137Repayment of borrowings (25,251) (14,240)Issue of shares 25,555 32,306Issue costs (536) (756) Net cash inflow from financing 33,379 45,447 (Decrease)/increase in cash (1,033) 3,293 Notes to the financial informationYear ended 31 December 2004 1. Statement of total recognised gains and losses 2004 2003 £000 £000 Profit for the year 7,678 2,796Currency translation difference on foreign currency netinvestment (5,802) (5,288) 1,876 (2,492) 2. Reconciliation of movements in shareholders' funds 2004 2003 £000 £000 Total recognised gains and losses 1,876 (2,492)Dividends paid and proposed (760) - 1,116 (2,492)New shares issued 25,018 31,550 Net increase in shareholders' funds 26,134 29,058Opening shareholders' funds 51,181 22,123 Closing shareholders' funds 77,315 51,181 3. Taxation The taxation credit/(charge) is based on the result for the year, after takinginto account losses brought forward from previous periods, and comprises: 2004 2003 £000 £000Current taxOverseas taxes (2,832) (835) Deferred taxTiming differences 2,620 (3,025)Tax losses (2,465) 6,347 155 3,322 Tax on profit on ordinary activities (2,677) 2,487 4. Earnings per share Earnings per share has been calculated by dividing the profit after taxation forthe year ended 31 December 2004 of £7,678,000 (2003: £2,796,000) by the weightedaverage number of shares in issue throughout the year of 71,514,417 (2003:44,371,485). 5. Net cash inflow/(outflow) from operating activities 2004 2003 £000 £000 Operating profit 14,150 1,220Depletion and depreciation 11,029 1,190Decommissioning charge 311 -Loss on disposal of fixed asset investment - (6)Increase in debtors (6,015) (4,435)Increase/(decrease) in creditors 662 (478)Net cash inflow/(outflow) from operating activities 20,137 (2,509) 6. 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 2003. Those accounts, upon which the auditorsissued an unqualified opinion, have been delivered to the Registrar ofCompanies. The statutory accounts for the financial year ended 31 December 2004will be delivered to the Registrar. The summarised balance sheet at 31 December 2004 and the summarised profit andloss account, summarised 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 early May 2005 and will beavailable from the Company's registered office, No. 1 Portland Place, London W1B1PN, or from the Company's website at www.melroseresources.com from that date. Glossary the Adair Trusts certain trusts, the beneficiaries of which are R F M Adair and members of his immediate familybbl 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 Combined the Principles of Good Governance and Code of Best Practice as appended to the ListingCode Rules of the Financial Services Authoritythe Company Melrose Resources plcEBITDA earnings before interest, taxation, depletion, depreciation and amortisationGIIP 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 producingPetreco Petreco S.ar.l. and/or Petreco Bulgaria EOOD as appropriatepsi 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