Management Resource Solutions Regulatory News (MRS)

FOR IMMEDIATE RELEASE

23 March 2011

Annual results for the year ended 31 December 2010

Melrose Resources plc (LSE: MRS) ("Melrose", "the Company" or "the Group"), the oil and gas exploration, development and production company with interests in Egypt, Bulgaria, Romania, France, Turkey and the United States of America, today announces its annual results for the year ended 31 December 2010. 

Operational highlights

§ Working interest production 41.1 Mboepd (2009: 38.6 Mboepd) 

§ Bulgarian Kavarna and Kaliakra developments brought on stream

§ Egyptian West Dikirnis Phase II development completed

§ Two exploration discoveries (South Damas and Kavarna East)

§ Awarded two new high quality Romanian exploration concessions

§ Strategic partner introduced to French deep-water Rhône Maritime block

§ US Permian Basin asset divestment completed

Financial highlights

§ Revenue $240 million (2009: $224 million)

§ EBITDAX $151 million (2009: $178 million)

§ Profit before tax $30 million (2009: profit $31 million)

§ Loss after tax $12 million (2009: loss $24 million)

§ Net debt $419 million (2009: $474 million)

§ Proposed dividend 3.4 pence per share (2009: 3.1 pence per share)

Robert Adair, Executive Chairman, commented:

"Melrose delivered strong operating performance during the year, establishing a new production record and successfully completing the Kaliakra and Kavarna gas field developments offshore Bulgaria. These new fields represent an important addition to our existing asset base, diversifying the portfolio and doubling the Company's expected cash generation over the next few years.

The Company's solid production platform, coupled with a strengthening financial outlook, means that we are well positioned to progress our high potential impact exploration initiatives in Egypt, Turkey, Bulgaria, Romania and France and to selectively pursue other business development opportunities."

For further information please contact:

Chris McMahon

or visit www.melroseresources.com

CHAIRMAN'S STATEMENT

Melrose made significant progress during 2010, delivering strong operating performance and completing a number of initiatives designed to focus the Company on high growth opportunities.

Once again we achieved a new production record, averaging 41.1 Mboepd over the year, and in November we brought on stream the Kavarna and Kaliakra gas fields in Bulgaria. This represents an important milestone for the Company since the new fields have diversified our production base and are expected to double cash from operations over the next few years. We were also awarded two high quality exploration concessions offshore Romania, introduced a strategic partner to our deep-water Rhône Maritime block offshore France and completed the divestment of our US Permian Basin assets.

The Company is reporting good financial results with revenues of $240.4 million and EBITDAX of $150.7 million. Most importantly, the new Bulgarian cash flow coupled with Permian Basin divestment proceeds, provide us with the financial capacity to implement an active exploration work programme whilst reducing gearing towards 100 percent by the end of 2011.

Production and developments

The Group's working interest production averaged 41.1 Mboepd during the year, reflecting an increase of 6 percent compared to 2009. Approximately 83 percent of the production was gas with the balance being oil, condensate and Liquid Petroleum Gas. The majority, some 95 percent, of the production came from Egypt where the Company's core assets continue to perform well and we benefited from a full year contribution from five developments brought on stream in 2009. Late in the year, the production levels were substantially increased by production from Bulgaria. On a net entitlement basis production averaged 17.9 Mboepd compared to 17.0 Mboepd in 2009.

The Company's main producing assets in Egypt are located onshore in the Nile Delta where we currently have eleven fields on stream of which the two most material are the West Dikirnis oil and gas field and the West Khilala gas field. During the first half of the year Melrose completed the Phase II development programme on West Dikirnis involving the installation of a Liquid Petroleum Gas plant and Gas Reinjection facilities to maximise the recovery of oil, condensate and LPG from the field. These facilities have been highly successful and are currently recovering an additional 1,050 bpd of LPG and condensate which otherwise would have been lost. Based on the performance to date, we now plan to expand the LPG plant further with the addition of a refrigeration unit which should be commissioned early in the second quarter 2012. West Khilala continues to perform well and it is planned to install compression for this field to mitigate the onset of a natural production decline as the reservoir pressure depletes.

During the year, the Company added a further low cost development, the 26 Bcf South Damas field, to the Egyptian production portfolio. This field was discovered in February 2010 and placed on production within four months by connecting the discovery well into the existing Damas field export pipeline. The unit development cost was an attractive $1.15 per boe.

Elsewhere, we successfully completed the Kavarna and Kaliakra field developments offshore Bulgaria with first commercial production achieved on 4 November 2010. These fields have combined reserves of 74 Bcf and they have been developed using single subsea well completions tied back to the existing Galata platform. This was a major project for the Company and I am pleased to report that it was executed without incident and came in under budget with a total capital expenditure of $51.8 million. This equates to a unit development cost of $0.70 per Mcf and given the low operating costs of $0.51 per Mcf and strong Bulgarian gas price, the fields should be highly profitable. The fields are now producing at a combined plateau production rate of 45 MMcfpd and the early well performance has confirmed high reservoir productivities.

Exploration and appraisal

Over recent years, Melrose has focused the majority of its capital expenditure on high rate of return development projects and has now established a robust, low cost production base in Egypt and Bulgaria. As such, we consider it timely for the Company to place more emphasis on exploration initiatives and this process started in 2010 when we dedicated 32 percent of our total capital expenditure of $101 million to exploration activities. These included drilling and the acquisition of seismic surveys designed to identify new exploration plays and prospects to drill in 2011 and beyond. This year we expect to continue the trend and have allocated some 47 percent of our $112 million capital budget to exploration activities.

In Egypt, we drilled four exploration wells during 2010 with one success, the 26 Bcf South Damas discovery, which has been placed on production. The recent well results have confirmed that the deltaic Tertiary exploration play on the Mansoura Concession is becoming increasingly mature and we are now focussing our attention on the less explored South Mansoura Concession. This block contains some further Tertiary potential and a new Cretaceous oil play with unrisked mean prospective resources of 70 MMbbl and significant value upside. We intend to test this play with a well in mid 2011 and, in preparation for this, we acquired 3D seismic over the main play fairway in late 2010. The results from this survey should be available in April this year.

Elsewhere in Egypt, we continued to evaluate the Company's large frontier exploration concession called Mesaha, located in southern Egypt on the Sudanese border. During the year we acquired our first regional 2D seismic over the block which contains an unexplored Palaeozoic basin. The initial findings from the survey were difficult to interpret but after advanced data processing we have now confirmed the basin architecture and also identified the potential for fault related structural traps. Given this encouragement, the Joint Venture has decided to conduct an infill 2D seismic programme over the most prospective area of the basin in 2011 and this has recently commenced. The partnership also intends to extend the period of the concession for three years in October 2011 with an anticipated work programme commitment comprising additional 2D seismic and one firm well.

During 2010, we also continued our run of exploration successes on Block Galata in Bulgaria with the discovery of the Kavarna East field on trend with Kavarna and Kaliakra. The discovery has booked reserves of 10 Bcf and is likely to be tied back for production in 2012 to extend the combined fields' production plateau to 3 years. One further prospect, Kaliakra East, lies on the same geologic trend and we plan to drill this in 2011, targeting unrisked prospective resources of 59 Bcf with a 34 percent chance of success. Also this year we plan to acquire 3D seismic in the central area of Block Galata which may contain additional prospects charged from the same gas source as the recent discoveries. To allow time to progress the work programme Melrose has exercised its option to extend the exploration licence to February 2013.

We are also entering an exciting exploration phase in Turkey this year where, following 2D seismic acquisition in 2010, we will be spudding our first well in April. The well will be drilled on a large oil prospect called South West Kanun with unrisked mean prospective resources of 85 MMbbl and a 20 percent chance of success. In the event that the well is successful it will open a new exploration play in the area with substantial follow on potential.

In France, we have made significant progress towards evaluating our deep-water Rhône Maritime Concession. Late in the year, we successfully concluded a farm-out for the acreage and were delighted to announce that Noble is acquiring a 72.5 percent operated interest in the concession with Melrose retaining 27.5 percent. Noble has proven deep-water expertise and a track record of discovering gas reserves in plays similar to those on the Rhône Maritime block. To advance the block evaluation the new Joint Venture has recently acquired a block-wide 2D seismic survey with results due in the third quarter this year.

Portfolio Management

Consistent with the strategy to focus more of the Company's resources on high growth opportunities, during 2010 Melrose bid for and was successfully awarded interests in two exploration concessions in Romanian 10th Licensing Round. Initially, Melrose will hold an 80 percent interest in the blocks with the remaining 20 percent held by Petromar Resources S.A.

The new concessions, called EX-27 (Muridava) and EX-28 (Est Cobalcescu), are located offshore in predominantly shallow water and have a combined area of 2,000 square kilometres. The blocks represent a significant enhancement to the Group's exploration portfolio since they have oil and gas potential, contain multiple exploration plays and are on trend with existing discoveries. The blocks are covered by old regional 2D seismic data and Muridava also contains a known discovery called Olimpiskiyi on which there is limited available data. This will be appraised as part of the planned work programme on the concessions.

Most recently, on 10 March 2011, the Company announced that it has signed the Concession Agreements for the new blocks with the Romanian National Agency of Mineral Resources. The agreements include a three year initial term followed by an optional three year extension, with 2D and 3D seismic data acquisition and three wells expected to be drilled on each block during the initial term. In due course, the Company may consider reducing its working interest in the concessions.

Our other business development initiative in Romania, the proposed farm-in to the Midia and Pelican blocks, did not complete as planned during 2010. Whilst we were initially disappointed at the outcome it has resulted in the Company having the financial flexibility to pursue other growth opportunities.

A second significant portfolio initiative was completed in December 2010 through the divestment of our US Permian Basin assets in West Texas and East New Mexico. These are mature oil fields with long producing lives and material reserves but with low production rates and high operating costs. It was recognised that the Company would have to continue to invest a significant amount of capital in the assets at relatively low return to access the remaining reserves and maintain the ageing facilities and well stock. We therefore took the decision to divest the asset for a cash payment of $80 million, less normal transaction adjustments, to Quantum Resources with the proceeds primarily being used to reduce debt. There was an exceptional post tax loss of $31.9 million associated with the divestment which arose from the unusually long field lives and low depletion rates. We still retain some minor gas interests in East Texas.

Health, safety, environmental and social

The Melrose team regards Health, Safety, Environmental and Social ("HSES") considerations as being of paramount importance and, under the umbrella of our HSES Management System, we continually strive to improve performance in this area.

We were therefore very pleased that our Egyptian operating company recently achieved accreditation under two international standards for safety and environmental management, namely, ISO 14001 and OHSAS 18001. This is a significant achievement and represents the culmination of an 18 month programme during which the Company's HSE commitment, competencies and systems were rigorously assessed by independent advisors and improved where necessary. During 2011 we will be implementing a similar programme for our Bulgarian operations.

We are also delighted to report that during 2010 Melrose managed to make a very significant reduction in the impact which our operations have on the environment. The new West Dikirnis LPG plant has eliminated the need for flaring at the field and, as a result, the Company reduced its green house gas emissions (CO2 and CH4) by 46 percent in 2010 as compared to the previous year. In addition, during the year we have injected all the produced water from the West Dikirnis field into two redundant South Batra production wells reducing the volume of water being treated and disposed by third party contractors by 61 percent.

Our work with local communities has also continued and the Egyptian school which we have funded has been completed and is in the process of being fitted out. The school is located near to the West Dikirnis facilities and it will offer high quality elementary and secondary education to 450 children from the area. We also continue to support a girl's school at Tammeya in Egypt and the Karin Dom Centre in Varna, Bulgaria, which provides rehabilitation and social integration training for children with special needs.

Reserves

Our proved and probable reserves at year end were 105.2 MMboe on a working interest basis, which equates to 45.9 MMboe on a net entitlement basis. These figures reflect the divestment of the Company's US Permian Basin assets (23.5 MMboe) and production volumes (15.0 MMboe) and the positive impacts of the South Damas and Kavarna East discoveries (6.2 MMboe) and Egyptian field revisions (2.9 MMboe). Excluding the effect of the Permian Basin divestment the Company's reserve replacement ratio for the year was 60 percent on a working interest basis or 90 percent viewed on a net entitlement basis.

Board and staff

During 2010 we reviewed the composition and balance of the Melrose Board membership to ensure that it continues to operate effectively with the highest business standards. We concluded that no changes need be made at this time since it has a good blend of experience and insight derived from many disciplines and industries and operates in a very supportive, pragmatic and responsive manner. We will continue to review the Board composition on a regular basis and add further members if we believe there is a clearly defined need.

Beneath the Board, we operate with a Management Committee comprising an experienced group of senior individuals who bring expertise from all the relevant oil and gas industry disciplines to the Group and they are well supported by our technical and financial professional staff. Similar to the Board, we periodically review the make-up of the Management Committee and, cognisant of our increased focus on exploration, recently strengthened it when we welcomed a new Geoscience Manager to the Company. 

In many ways 2010 turned out to be an extremely busy year, with our normal operational workload supplemented by a number of portfolio related transactions. The accomplishments of the past year would not have been possible without the continued support and commitment of our staff and on behalf of the Board I would like to thank the entire Melrose team for their efforts.

Financial results

Melrose achieved good financial results in the year which were underpinned by our production performance. Revenues for the year were $240.4 million, EBITDAX was $150.7 million and the profit before tax was $29.8 million, after taking account of the exceptional write-off for the Permian Basin asset divestment. The revenue figure is 7 percent higher than 2009, reflecting the increased production volumes from Bulgaria. The gross profit margin has increased to $11.59 per boe from $6.64 per boe in 2009. 

Based on the Company's continued progress, I am pleased to announce that we are proposing that the dividend for this year will be 3.4 pence per share (2009: 3.1 pence per share). If approved at the AGM in June, the dividend distribution will be made on 22 July 2011 to those shareholders on the register as at 10 June 2011. We intend to maintain our progressive dividend policy although it will always be subject to Melrose's capital requirements for existing and new business opportunities and the prudent management of cash reserves.

Outlook

Melrose is now seeing the benefits of our development activities over the past few years and we have established two core areas in Egypt and Bulgaria. Production is again at a record high and we are looking forward to a period of very strong cash generation. Our challenge is to deploy the capital wisely, balancing investment in growth opportunities with a planned reduction in the Company's financial gearing.

For the future, we are becoming more exploration focused and our goal is to discover material reserves. As such we have a number of exciting opportunities to pursue in 2011 with wells testing new exploration plays in Turkey and Egypt and near field drilling in Bulgaria. We will also see the results of new seismic surveys acquired over the Block Galata and our frontier Rhône Maritime and Mesaha Concessions which will help us evaluate the potential in these areas. We expect to be supplementing our exploration activities with selective new business development initiatives over the next year in order to broaden the investment opportunity set.

Recently we have witnessed some significant civil unrest in Egypt, which has traditionally been perceived as a country with relatively low political risk. Fortunately, the situation there now appears to be calm and whilst we suffered no business disruption there, we will continue to monitor the situation closely. The recent events have, however, underlined the importance of asset diversification and we are particularly pleased that we brought our new Bulgarian fields on stream last year as part of that process.

In 2010 we started to reposition the Company by reshaping its asset portfolio and strengthening our financial outlook. I have great confidence that we have the team and resources to now build on this sound platform and deliver strong growth over future years.

Robert F M Adair

Chairman

OPERATIONAL REVIEW

EGYPT

Melrose's Egyptian assets comprise 100% operated interests in three concessions in the Nile Delta, namely, Mansoura, South East Mansoura and Qantara. The Company also holds a 40% operated interest in a large frontier exploration concession in southern Egypt called Mesaha.

Throughout 2010, Melrose continued to build on its strong production position in the country through further development of its assets, whilst also undertaking an active exploration campaign. A new production record was set with an average daily rate of 38,944 boepd on a working interest basis (15,724 boepd on a net entitlement basis).

An important expansion of the West Dikirnis field facilities (the Phase II development) was completed during the second quarter of the year. This comprised the installation of a fractionation plant to recover Liquid Petroleum Gas ("LPG") from the field's associated gas production and Gas Re-Injection ("GRI") facilities to maximise the recovery of oil, condensate and LPG from the field. The facilities have been very successful and the LPG plant is producing around 47 tonnes of LPG per day (equivalent to 520 bpd) and an incremental 530 bpd of condensate which would not otherwise be recovered. Based on the plant performance to date it is now planned to expand the facilities further with the addition of a refrigeration unit which should increase the hydrocarbon liquids yields in the second quarter 2012. Since the GRI facilities were commissioned the field's oil production decline rate has been arrested with approximately 24 MMcfpd of gas being re-injected into the reservoir. This gas will be recovered later in the field life when it is converted from oil to gas production.

During the year, the company added a further low cost development, the 25.5 Bcf South Damas field in the South East Mansoura Concession, to its production portfolio. This field was discovered in February 2010 and was put on production within four months by connecting the discovery well to the pipeline connecting the existing Damas fields to the South Mansoura plant. The unit development cost was approximately $0.20 per Mcf ($1.15 per boe).

In order to maintain a strong exploration prospect inventory to drive future growth, Melrose also acquired further 2D and 3D seismic data in the under-explored South East Mansoura and Mesaha Concessions during the year. In South East Mansoura, this programme was designed to evaluate a new oil exploration play in the Cretaceous and Jurassic formations and preliminary results from the survey should be available in April this year. In Mesaha, a 2D seismic acquisition programme was completed early 2010 which provided further insight into the basin architecture and sufficient encouragement to justify an infill seismic survey this year.

PRODUCTION

The average production on a working interest basis in 2010 in Egypt was 189.6 MMcfpd of gas and 6,251 bpd of oil, condensate and LPG. Net entitlement production averaged 76.2 MMcfpd of gas and 2,587 bpd of hydrocarbon liquids. Total average production for the year reached a record level of 38,944 boepd on a working interest basis, representing an increase of 4.6% relative to 2009.

The majority of the production, some 25,256 boepd, was derived from the West Dikirnis and the West/South Khilala fields with the remainder from the El Tamad, South Zarqa, North East Abu Zahra, East Abu Khadra and Salaka in Mansoura, the Al Rawda, South Damas and Damas fields in South East Mansoura and the Qantara field. 

Mansoura Concession

West Khilala field

The West Khilala gas field was discovered in the Abu Madi formation in 2005 and came on stream in February 2007. The field remains a stable and reliable core production asset and is currently being produced by six wells. The average production rate during 2010 was 92.7 MMcfpd of gas and 117 bpd of condensate. By the end of 2010 approximately 40% of the ultimate reserves had been produced from the field and therefore coming of its production plateau. Reservoir studies indicate however that with the planned addition of compression facilities and the potential addition of a new crestal producer, the field decline rate may be limited to around 5% through to mid 2013. The field life is expected to extend until at least 2023.

The field's ultimate gross proved plus probable reserves are unchanged compared to 2009 and are estimated at 308 Bcf. By the end of 2010, some 135 Bcf of gas and 197 Mbbl of condensate had been produced from the field.

South Khilala field

The South Khilala gas field was discovered in May 2009, approximately 10 kilometres to the south of the West Khilala field. The field is estimated to have ultimate gross proved plus probable reserves of 44.3 Bcf reflecting an increase of 5.3 Bcf compared to previous estimates. First production was achieved in October 2009 when the discovery well was tied back to the West Khilala facilities achieving average production of 15.7 MMcfpd of gas and 19 bpd of condensate. By end 2010, approximately 6.6 Bcf of gas and 90 Mbbl of condensate had been produced from the field.

West Dikirnis field

The West Dikirnis oil and gas field was discovered in December 2005 in the Qawasim formation and comprises a 70 foot thick oil reservoir which is overlain by a gas cap. First production commenced in November 2007 and the development plan has to date focused on maximising the hydrocarbon liquids (oil, condensate and LPG) recovery from the field by drilling horizontal wells in the oil rim and installing LPG recovery and GRI facilities. Later in field life, once the hydrocarbon liquids production drops below the economic limit, the field will be converted to gas production. The exact timing of this conversion will depend on a number of factors, including field performance and the prevalent oil price, but it is currently not expected to occur before early 2018.

The field development activity continued in 2010 with the final stages of the construction and commissioning of the LPG recovery and GRI facilities which became operational in April and May 2010, respectively. In addition to the economic return which they generate, one very positive aspect of the LPG facilities is that they eliminate the need for ongoing gas flaring at the West Dikirnis plant, thus significantly reducing the environmental impact of the Company's operations. In a further environmental initiative, during 2010 the Company expanded its produced water injection programme into disposal wells in the South Batra field and currently all the West Dikirnis produced water (currently averaging 3,200 bwpd) is disposed of in this way.

Throughout the year, Melrose continued with its active reservoir management programme to optimise individual well withdrawal rates in the field to prevent premature water breakthrough and minimise gas production volumes. In 2010, the field produced from six wells, three of which are vertical or slightly deviated wells, while the other three are horizontal wells. The average rate was 3,945 bpd of oil and condensate and 12.3 MMcfpd of gas. The cumulative amount of LPG produced from the fractionation plant was 11,978 tonnes representing an average annual daily rate of 32.8 tonnes per day (361 bpd).

The field's ultimate proved and probable reserves are estimated at 20.3 MMbbl of hydrocarbon liquids and 99.4 Bcf of gas based on the latest integrated reservoir studies on the field. The ultimate liquids reserves estimate is unchanged compared to year end 2009 but the gas reserves have been reduced by approximately 13.8 Bcf. By the end of 2010, the field had produced 7.0 MMbbl of hydrocarbon liquids and 16.4 Bcf of gas.

Regarding the field outlook, production in the short to medium terms will be enhanced by two further horizontal wells which are scheduled to be drilled in 2011 and the expansion of the LPG plant to include the refrigeration unit in early 2012. The Company plans, however, to maintain its current reservoir management philosophy and is likely to continue to restrict individual well production rates to maximise hydrocarbon liquids recovery. For planning purposes, the Company currently forecasts a combined oil and condensate rate in 2011 and 2012 of 3,900 bpd and 4,500 bpd, respectively. The LPG yield in 2011 and 2012 is forecast at 550 bpd and 1,200 bpd.

El Tamad field

El Tamad is an oil and gas field located in the Mansoura Concession. Similar to West Dikirnis, the initial development plan is focused on extracting the oil rim reserves prior to converting the field to gas production later in its life.

During 2010, the field's average production rate from three wells was 450 bpd of oil and 4.0 MMcfpd of gas and the performance continues to be stable. The ultimate proved plus probable reserves are estimated at 2.4 MMbbl of oil and 31.5 Bcf of gas and to year end 2010 some 1.9 MMbbl of oil and 3.9 Bcf of gas had been produced.

In 2009, the first horizontal well was drilled in the field with a view to increasing reserves. This well was encouraging from a geologic perspective but experienced completion problems which limited its production capability. The Company is therefore studying the potential for drilling additional horizontal wells in the field and also considering the feasibility of recovering LPG from the El Tamad field gas when it is converted to gas production through the existing West Dikirnis facilities.

East Abu Khadra field

The East Abu Khadra field was discovered and brought on production in 2008 in the Abu Madi formation. The ultimate gross proved plus probable reserves are estimated at 27.0 Bcf of which 5.4 Bcf had been recovered by the end of 2010, at an average rate of 7.7 MMcfpd of gas and 73 bbl of condensate per day.

The ultimate proved plus probable reserves figure reflects a significant increase of 18.8 Bcf compared to year end 2009. This is due to positive results from pressure surveys acquired during the year which indicate that the single development well is in communication with a higher gas in place volume than estimated from the initial geologic reservoir mapping.

South Zarqa field

The South Zarqa field was discovered in the Abu Madi formation in late 2007 and production from this well commenced in April 2009 through the South Batra facilities. In 2010, the average field production rate was 21.3 MMcfpd of gas and 677 bpd of condensate and the year end ultimate reserves estimate was 35.7 Bcf and 1.0 MMbbl of condensate.

North East Abu Zahra field

The North East Abu Zahra field was discovered in the Abu Madi formation in 2007 and production commenced in April 2009. The field was developed in parallel with South Zarqa using a common 35 kilometre flow line tied back to the South Batra plant. The ultimate proved plus probable reserves are estimated at 31.4 Bcf of gas and 0.7 MMbbl of condensate, reflecting a small upgrade of 2.1 Bcf compared to year end 2009. To date some 12.6 Bcf and 0.3 MMbbl have been produced from the field. 

The average production rate during 2010 was 19.9 MMcfpd of gas and 381 bpd of condensate. During December the existing single development well, which is located on the flank of the reservoir, experienced the onset of water production and the Company is actively considering drilling a second producer in the field at a crestal well location.

The North East Abu Zahra field is part of the same gas accumulation as the El Basant field on a neighbouring concession operated by Dana Gas. A commercial arrangement has been put in place between the two companies to allow Melrose to produce the field until its share of the reserves have been depleted.

Salaka field

The Salaka field is located in the Mansoura Concession and is currently producing through the Salaka-1 well. This well was initially completed in the Abu Madi reservoir but this has been depleted and therefore, during 2010, the well was recompleted into the Kafr El Sheik reservoir which was previously untapped. The new interval has a net gas pay of 27 feet and contains ultimate reserves of 2.9 Bcf. The well averaged dry gas production of 4.1 MMcfpd.

South East Mansoura Concession

Damas field

The Damas field was discovered in 2008 and commenced production in 2009. During 2010, the field was only produced for eight months, with average rate based on a full year of 2.4 MMcfpd of gas and 23 bpd of condensate. This was to allow optimal production and recovery from the Damas and neighbouring South Damas field which share a common pipeline connecting them to the South Mansoura processing facilities.

South Damas field

This field was discovered in February 2010 and fast tracked onto production in June 2010. The ultimate proved and probable reserves for the field are estimated at 25.5 Bcf of gas and 0.1 MMbbl of condensate and the average 2010 production rate, based on a full year's production, was 5.6 MMcfpd of gas and 37 bpd of condensate.

Al Rawda field

Al Rawda is a gas and condensate field which was put on production in 2007 through a dedicated pipeline to the South Mansoura plant. In 2010, the average field production rate was around 2.7 MMcfpd of gas and 26 bpd of condensate.

Qantara Concession

Qantara field

Qantara is a relatively small gas field located onshore near the Suez Canal in the Nile Delta. In 2010 the average well rate was 1.2 MMcfpd of gas and 142 bpd of condensate. Production from Qantara is highly profitable since the gas sales price for this concession is linked to oil price rather than the fixed domestic gas price.

The average 2010 working interest production rates for the Company's Egyptian fields are summarised as follows:

Note: average production rates are calculated over the 365 day period, even if a field is brought into production during the year.

EXPLORATION

To complement Melrose's strong Egyptian production platform, the Company has been undertaking a number of exploration initiatives with a view to maintaining an attractive prospect inventory. In the Mansoura Concession, the exploration programme is relatively mature and the primary focus in this licence area is on the development of existing fields. In contrast, the neighbouring South East Mansoura Concession is relatively under-explored and contains both Tertiary deltaic prospects in the northern area of the block and Cretaceous and Jurassic prospectivity in the central and southern areas of the block. In southern Egypt, the large Mesaha Concession is completely unexplored and contains a large sedimentary basin which may be prospective in the Ordovician, Silurian and older formations.

During 2010, Melrose drilled four exploration wells in the Mansoura and South East Mansoura Concessions. The South Damas-1 well in South East Mansoura Concession encountered 76 feet of net gas pay in the Qawasim formation and based on reservoir pressure and production data has estimated reserves of 25.5 Bcf. The three other wells, including Tall Rak and Sakr in South East Mansoura and South East Dikirnis in the Mansoura Concession, did not find commercial hydrocarbon quantities. The well failures were attributed to a number of unusual geologic outcomes including the presence of a major carbonate section in the Tall Rak reservoir interval which gave a seismic response similar to a direct hydrocarbon indicator and a shallow cemented sandstone at South East Dikirnis which had never been encountered before on the Mansoura Concession.

During the second half of 2010, Melrose acquired 370 square kilometres of 3D seismic data and 140 kilometres of 2D seismic data over the South East Mansoura Concession and approximately 40 percent of the block is now covered by 3D data. The seismic survey was focused on the Cretaceous oil play which exists in the central and western area of the concession and which contains a number of leads and prospects. Historically, four wells have been drilled down to the Cretaceous formation on the concession and two of these encountered significant reservoir development (with 380 and 500 feet of net sand, respectively) and one well encountered oil shows. It is not believed, however, that any of the wells tested valid structures due to the lack of good quality seismic data to help position the wells. The interpretation of the new data is ongoing and preliminary results should be available in April this year. These will be used to update the Company's view of the play's resource potential, which is currently estimated at 70 MMbbl mean unrisked, and to select a well location for drilling in mid year.

The Company also continued with its exploration programme in the Mesaha Concession during 2010. Mesaha is a large frontier exploration block located in southern Egypt on the Sudanese border and covers an area of approximately 57,000 square kilometres. Melrose was awarded the block in October 2007 and holds a 40 percent operated interest.

Following the acquisition of ground gravity data in 2009, Melrose embarked on a 2D seismic acquisition programme on the block in early 2010 which was completed in May. In total, 1,040 kilometres of data were acquired over the western area of the concession, which is believed to contain an untested Palaeozoic sedimentary basin. After extensive seismic processing and interpretation studies, the data has revealed stratified basin fill below the Hercynian unconformity and deep rotated fault block trapping geometries. It is not, however, of sufficient quality or line density to select drilling locations and therefore the Joint Venture has decided to acquire at least 700 kilometres of 2D infill seismic over the south-western area of the concession and the survey may be increased to 1,500 kilometres contingent on early acquisition results.

The seismic acquisition crew has been mobilized to the concession area and the survey commenced in early March. Depending on the quantity of data acquired, the programme is expected to complete between May and July and will be followed by a period of data processing and interpretation.

In order to provide time to execute the concession work programme in a technically sound manner, it is planned to enter the second period of the exploration license which will last 3 years commencing in October 2011. The work programme commitment in the second period of the license is anticipated to be one firm well and 1,500 kilometres of 2D seismic.

BULGARIA

2010 proved to be an important year for the development of Melrose's business in Bulgaria. During the year, the Company brought the Kaliakra and Kavarna gas fields on production and drilled a successful exploration well on the Kavarna East structure. The two new producing fields have combined ultimate proved plus probable reserves of 74 Bcf and will generate significant cash flow in the short to medium term. The Kavarna East discovery holds 10 Bcf of reserves and is planned for development in 2012.

Field Developments

The Kavarna and Kaliakra fields were both developed using single subsea well completions, tied back to the existing Melrose operated Galata field production platform. An 8 kilometre, 6 inch flowline was installed for the Kavarna well and 14 kilometre, 10 inch flowline was laid for Kaliakra. Commercial production from the fields started on 4 November when they were officially opened by the Bulgarian Prime Minister.

The early production performance from both fields has confirmed high reservoir productivities and they are currently producing at the planned combined plateau rate of 45 MMcfpd. During the first few weeks of 2011, production from Kavarna was intermittently interrupted due to the failure of a subsea connection on a glycol injection line which resulted in the formation of hydrate blockages in the field's gas flowline. The operational issue was resolved in mid February after the replacement of the suspect connections using the GSP Prince diver support vessel.

To date, less than five percent of the Kaliakra and Kavarna initial gas in place estimates have been produced and it is therefore too early to provide an update to the field reserves. The Company is continuing to monitor the fields' pressure and production performance and it is anticipated that an accurate update will be available by mid year.

The total capital expenditure for the two developments was $51.8 million including historic well completion costs (compared to a budget of $53.7 million) equating to a very attractive unit development cost of $0.70 per Mcf ($4.06 per boe). Given the low operating costs of $0.51 per Mcf ($2.96 per boe) and the strong current Bulgarian gas price of $7.10 per Mcf, these fields will be highly profitable.

EXPLORATION

The Kavarna East field was discovered on the same geologic trend as the Kavarna and Kaliakra fields in July 2010. The exploration well penetrated the top of the Palaeocene reservoir interval at a depth of 2,753 feet and encountered a net gas pay of 89 feet with an average porosity of 29 percent and a gross gas column of approximately 130 feet. 

The post discovery proved plus probable reserves estimate was 12 Bcf and the Company has booked 10 Bcf at year end 2010. Following a period of technical evaluation the Company declared commerciality on Kavarna East in early December and is currently awaiting the production concession award. Given the discovery's proximity to existing infrastructure, it will be tied back for production using a subsea completion in 2012.

Consistent with the other fields which have been discovered on the same geologic trend, the Kavarna East reservoir structure appears to be filled with gas to the spill point. This provides further evidence that the regional biogenic gas source which lies to the south of the trend is substantial suggesting that some gas may have migrated past the discovered fields further north into the central area of the Block Galata. Therefore, in order to extend the exploration play, the Company plans to acquire a 3D seismic survey over this area of the concession in 2011. This survey may reveal further drillable structures and possibly exhibit the same type of hydrocarbon indicators which were used to identify and de-risk the existing discoveries.

To provide time to execute the planned work programme, the Company has opted to enter the second term of the Block Galata exploration licence which will run until February 2013. The work programme commitment includes 500 square kilometres of 3D seismic data, one firm and one contingent well.

Galata Gas Storage

The Company is continuing in its discussions with the Bulgarian authorities to convert the substantially depleted Galata field into a gas storage facility. This represents a strategic infrastructure development which would enable Bulgaria to improve its security of supply since it is largely dependent on Russian imported gas. The Bulgarian authorities have yet to sanction the project and it is currently difficult to predict when and on what terms the project will be progressed. Pending clarification of the situation, the Company has left 5.4 Bcf of gas remaining in the reservoir to protect the technical viability of the project and potentially act as cushion gas.

ROMANIA

In order to ensure continued access to high quality exploration opportunities and broaden the prospect inventory, during 2010 the Company participated in the 10th Romanian Licensing Round. The results of the bid round were announced by the Romanian National Agency for Mineral Resources ("NAMR") on 30 June 2010 and a bidding group comprising Melrose and Petromar Resources was awarded two licences, with Melrose holding operatorship and an 80 percent working interest.

The new licences are called EX-27 (Muridava) and EX-28 (Est Cobalcescu) and they are located in shallow water offshore in the Black Sea. The blocks have a combined area of 2,000 square kilometres and are relatively under-explored as they lie in an area which was historically subject to a maritime boundary dispute between Romania and Ukraine. This dispute was resolved in favour of Romania in February 2009 by the International Court of Justice hence allowing the blocks to be included in the licensing round.

The blocks contain multiple oil and gas exploration plays and are on trend with Pliocene and Miocene gas discoveries which have been made in the area. They are covered by a relatively sparse set of 2D seismic data which was acquired during the 1980s. In addition, Block EX-27 contains an existing discovery called Olimpiskiyi which was drilled by a Ukrainian state company in 2001 and which has a reported resource base of 100 Bcf of gas and 9 MMbbl of oil. However, the Company does not have access to the well data to verify these estimates and the discovery is not proven to be commercial.

The Concession Agreements for the new blocks were signed with NAMR on 8 March 2011 and are currently being circulated to the relevant Government Ministries for formal ratification. The agreements include a three year initial term followed by an optional three year extension. The firm three year work programme for each block comprises 2D and 3D seismic acquisition in Year 1, one well in Year 2 and two wells in Year 3. In due course, the Company may consider reducing its working interest in the blocks and expects to spend a minimum of $60 million on exploration activities during the initial term of the concessions.

In November, Melrose announced that the farm-in agreement which it had entered into with respect of the offshore Pelican and Midia blocks had been terminated by its counter party Sterling Resources. Whilst this was disappointing, it has enabled the Company to dedicate resources to new business development opportunities and accelerate its financial de-gearing plans.

TURKEY

Melrose holds a 66.67% operated interest in eight exploration concessions in the South Mardin basin in southern Turkey on the Syrian border. The concessions have a combined area of 3,910 square kilometres and cover a large Palaeozoic sub-basin on the northern margin of the Arabian plate.

The concessions are under-explored and historically only two wells have been drilled in the area, one in 1965 and one in 1977. Both these wells were drilled using limited 2D seismic data and neither are thought to have tested a valid structural closure. They do, however, provide some encouragement with some oil shows being reported in the Cretaceous and Ordovician reservoir intervals.

In the second quarter of 2010, Melrose acquired 246 kilometres of 2D seismic data over the eastern area of the concessions where a large exploration lead called South West Kanun had been identified on the old regional seismic data. The new survey data confirmed the presence of a robust four-way dip closed structure the structure and which the Company plans to drill in April 2011. The well will target gross mean unrisked reserves of 85 MMbbl (55 MMbbl P50) in the two main reservoir zones with an estimated chance of success of 20%. The main exploration risks pertain to the presence of a mature source rock in the area or an appropriate oil migration path into the prospect.

Following analysis of the well results, the Company will decide whether to conduct another phase of 2D seismic acquisition to evaluate a large structural lead called Ceylanpinar located in the western area of the concessions.

FRANCE

Melrose has a 27.5% non-operated interest in the Rhône Maritime Exploration Concession which is located in the deep water area of the Rhône Delta, offshore France in the Mediterranean Sea. This is a large frontier exploration concession covering an area of 9,375 square kilometres.

During 2010, Melrose took the decision to farm-down its position in the block (which initially comprised a 100% operated interest) and invite a strategic partner with deepwater experience to enter the concession. This resulted in a farm-out transaction being agreed with Noble Energy Inc. ("Noble") under which Noble have acquired a 72.5% working interest and operatorship in return for funding the cost of a block wide 2D seismic acquisition programme. This was a very positive result for the Company as Noble has significant international deep water exploration experience including in the Eastern Mediterranean where it has been successful targeting similar exploration plays to those thought to be present on the Rhône Maritime block.

Shortly after agreeing the terms of the farm-out, Melrose and Noble engaged TGS Nopec ("TGS") to conduct a 7,500 kilometre 2D seismic acquisition programme over the acreage at an average line spacing of 2.5 kilometres. The primary objectives of the survey were to investigate a shallow Pliocene channel sand play and various sub-Messinian salt structural plays which are present in the concession area. The survey commenced in early December 2010 and was completed in mid February 2011. The data is now being processed and interpreted and preliminary results are likely to be available in the third quarter this year.

USA

Permian Basin

In the first half of 2010, Melrose completed a review of its mature oil field leases located in the Permian Basin in West Texas and East New Mexico. These interests had largely been held by the Company since its inception and may be characterised as having long producing lives with relatively material reserves but with low production levels. The combined average field production rate during 2010 was approximately 830 bopd and the remaining reserves as at 31 December 2009 were 20.3 MMbbl of oil and 17.7 Bcf of gas. Approximately 68 percent of the reserves were in the proved undeveloped category.

At the end of the review process, it was recognised that in order to access the undeveloped reserve base and maintain the extensive production well inventory and facilities, a significant amount of additional investment would be required in the assets. It was also concluded that the Company would prefer to allocate its capital resources to more strategic short - medium term and higher growth opportunities in areas where it has, or can create, a competitive advantage. 

Given the above, in June 2010 the Company decided to divest the Permian Basin assets and commissioned Scotia Waterous in Houston to manage a formal sales process for the fields. This process concluded in December when the assets were sold to Quantum Resources Management LLC for a cash consideration of $80 million, subject to normal working capital and transaction adjustments.

The sale proceeds are primarily being used to pay down debt with the balance to fund the capital work programme, consistent with the Company's plan to reduce financial gearing towards 100 percent by the end of 2011.

East Texas

Melrose continues to hold some minor interests in East Texas including the North Raywood and Rankin gas fields which are located in the Harris and Liberty counties, respectively. The assets are relatively mature but still present some exploration and appraisal opportunities mainly on the perimeter of the producing fields. In total there are currently seven wells on production in the area which produced 1.5 MMcfpd of gas and 16 bpd of liquids during 2010 and the remaining proved plus probable reserves are estimated at 7.8 Bcf of gas and 0.1 MMbbl of condensate.

During the year the Company also periodically flow tested the Nunan tight gas discovery but as yet it has not been possible to sustain economic production rates from the field. Technical studies are continuing in an attempt to identify a commercial development solution for the field.

Fort Worth Basin and Other Minor Assets

Melrose has a number of other minor oil and gas interests in Texas and Louisiana which include the operated gas production in the Fort Worth Basin, which are characterized by shallow gas fields with limited exploration upside. The average daily production from these fields in 2010 totalled 0.2 MMcfpd of gas.

KEY PERFORMANCE INDICATORS

The Board assesses the Company's performance through the measurement of specific KPIs which are set out below. Further details of the KPIs can be found within the Operational Review and the Financial Review.

FINANCIAL REVIEW

The Company was pleased to close the year with the completion of the sale of the Permian Basin assets. The cash generated has immediately reduced the gearing of the Group, with net debt reducing to $418.9 million at the year end (2009: $474.3 million) which is before inclusion of the balance of the consideration of $9.1 million which was received in January 2011. In addition, the Company has generated $130.6 million of operating cash flow during 2010 (2009: $113.2 million) and estimates operating cash flow to increase significantly during 2011 when the full impact of the cash flow from the Bulgarian operations will be realised. This positions the Group strongly with its objective of reducing gearing levels towards 100% by the end of 2011.

Results for the year

Revenue for the year was $240.4 million which compares with revenue of $224.4 million in 2009. The increase reflects the completion of the developments of Kavarna and Kaliakra in Bulgaria with production commencing in November 2010. The revenue split by country is Egypt $202.2 million (2009: $204.2 million), Bulgaria $16.9 million (2009: $1.7 million) and the USA $21.3 million (2009: $18.5 million).

Depletion, depreciation and decommissioning charge has reduced from $111.4 million in 2009 to $85.2 million for 2010. In Egypt, the depletion and decommissioning charge has reduced from $16.23 per boe to $13.00 per boe. This is due to adding reserves with a very low cost base, resulting in an overall lower charge for the concessions. In the USA the depletion and decommissioning charge has reduced from $26.24 to $9.87 per boe, which includes the charge for the Permian Basin assets. The charge in Bulgaria has also reduced from $20.86 per boe to $11.87 per boe, which reflects the increased production during 2010.

Unsuccessful efforts of $10.8 million (2009: $5.6 million) are as a result of approximately $3 million in Egypt where we drilled three dry wells, namely, Tall Rak, Sakr and South East Dikirnis with the balance relating to the Nunan-1 well in East Texas, USA.

Group operating costs increased from $26.6 million in 2009 to $28.6 million as a result of increased well workover maintenance costs in the Permian Basin, USA. The operating costs in Bulgaria reflect a partial year's production with a full year's operating expenses. It is expected that the Group operating cost per boe of $4.09 in 2010 will reduce significantly in 2011 to approach $3.00 per boe, reflecting a full year's production in Bulgaria.

The Group generated gross profit of $115.8 million compared with $75.5 million in 2009, an increase of $40.3 million.

Administrative expenses increased from $20.4 million to $23.4 million, which includes $3.2 million of professional fees incurred in relation to the Permian Basin disposal and pursuing new business development initiatives.

The sale of the Permian Basin assets was completed on 23 December 2010 at a consideration of $80 million. After taking account of transaction adjustments and working capital movements an amount of $63.3 million was received in December 2010 with a further $9.1 million remitted on 20 January 2011. The loss on disposal of the assets was $38.2 million and taking account the tax release on disposal of $6.3 million, the net loss on sale was $31.9 million.

Profit before tax, excluding the loss on disposal of the Permian Basin assets, was $68.0 million (2009: 30.9 million), an increase of 120% on the previous year. Group profit before tax was $29.8 million (2009: $30.9 million).

Excluding the tax credit on disposal, the tax charge has reduced from $54.8 million to $47.8 million, representing 70% of profit before tax (2009: 177%). The cash tax payable for the year is $0.1 million (2009: $2.0 million) with the majority of the tax charge relating to Egyptian imputed tax of $53.1 million and the remainder being a net credit for deferred tax in the period.

Loss after tax amounted to $11.7 million (2009: loss of $23.9 million).

EBITDAX, calculated after the deduction of the loss on sale of the Permian Basin Assets, for the year of $150.7 million compares with $177.9 million for the previous year. Excluding the impact of the loss on sale of the Permian Basin assets, adjusted EBITDAX was $188.9 million. The reconciliation of EBITDAX to the IFRS measure of profit before taxation is presented below:

Capital expenditure

Additions to the oil and gas assets of the Group during the year totalled $100.9 million (2009: $161.1 million). This was split geographically as follows; $57.5 million (2009: $21.9 million) in respect of properties in Bulgaria, $36.4 million (2009: $118.4 million) in Egypt, $3.1 million (2009: $19.4 million) in the USA and $3.9 million (2009: $1.4 million) in Turkey, Romania and France. The $100.9 comprises $68.8 million of development and $32.1 million of exploration assets (2009: $139.3 development, $21.8 million exploration).

Loan facilities

As at 31 December 2010, senior loan facilities of $450 million and subordinated facilities of $70 million remain in place with a final repayment date of 2014.

At 31 December 2010, the Group had cash balances of approximately $70.4 million (2009: $6.5 million) and bank loans, net of capitalised arrangement fees, totalling $489.2 million (2009: $480.7 million). The undrawn borrowings totalled $20.0 million.

Dividends

A dividend of 3.4 pence per share is being proposed (2009: 3.1 pence per share total dividend). The estimated total dividend of $6.4 million (2009: $5.6 million) will be deducted from retained reserves. If approved at the AGM in June, the dividend distribution will be made on 22 July 2011 to those shareholders on the register as at 10 June 2011.

Revenue, costs, profit and cash flows per unit of production

The Company strategy is to operate in low cost environments and the Group average operating cost in 2010 was $4.09 per boe (2009: $4.08). The table below summarises the key indicators which reflects this strategy:

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 and trade creditors which derive from its operations.

Group policy allows the Company to enter into short-term derivative transactions for a period of up to two years. Group policy in relation to hedging the selling price of Group production is reviewed periodically. There was no commodity hedge in place as at 31 December 2010.

Financial 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 rate risk derives from its borrowings which are at variable interest rates. It has been the Group's policy to borrow for short term periods, at variable interest rates in order to allow flexibility over early repayment of borrowings. Interest bearing borrowings are subject to floating rates, normally fixed for a period of one to three months. The Group regularly reviews the interest rate policy to reflect the hedging strategy of the Group which allows for the Directors to enter into short to medium term derivative transactions, if economic conditions would suggest that the terms of entering into such a derivative transaction would be in the best interests of the Group and Company.

As at 31 December 2010, the Company had two interest rate cash hedges in place, both of which expired in

February 2011. All realised gains and losses are taken to the Consolidated Income Statement. Unrealised movements to fair value are reflected through the Statement of Other Comprehensive Income. Full disclosure is provided in note 17 to the accounts. The same hedging transactions were place at 31 December 2009. Total Group interest charged including the settlement of interest rate hedging agreements in 2010 was $24.3 million (2009: $24.2 million).

The Group and Company earn interest from bank deposits at floating rates.

Currency risk

Presently, the Group has limited exposure to foreign currency risk as currently the majority of its revenue and expenditure is denominated in US Dollars. A proportion of the Group's Bulgarian receipts are received in Bulgarian Leva, which is directly correlated to the Euro. The Group has no currency hedges in place but continues to review whether the risk associated with Euro receipts is such that a cash hedge should be established to minimise revenue exposure. A limited risk arises to the extent that overhead costs and an element of capital expenditures are incurred in currencies other than US Dollars. The policy with respect to hedging against foreign exchange risk arising from capital expenditures incurred in currencies other than US dollars is reviewed against the capital expenditure budget on an annual basis.

In order to minimise currency risk, it is Group policy that borrowings incurred in relation to development projects should be denominated in the currency in which future cash flows from the development projects will be denominated, currently US Dollars. Similarly, it is Group policy that corporate borrowings should be denominated in US Dollars.

Pricing risk

At this time, the Group has no long-term contracts under which the price for the sale of its production is fixed. In Egypt, liquids realise market prices based on Western Desert pricing, which during 2010 equated to 96% of Brent. Gas production from development leases within the El Mansoura and South East El Mansoura Concessions in Egypt is sold under long-term contracts in which the gas price is linked to the oil price when the oil price lies in the range of between $10 per barrel to $22 per barrel. With the oil price at its current level, significantly above $22 per barrel, the gas price is at the top of the contractual range and is, therefore, effectively fixed. The gas price realised in Bulgaria is at a discount to the local quarterly consumer natural gas price, as published by Bulgargaz EAD (state owned gas company). The quarterly consumer natural gas price has historically tracked the Russian Urals oil price with a nine month time lag.  "Fixed" price Egyptian gas contributed 42% of Group revenue in 2010.

Financial reporting

The Group and the Company's financial statements have been prepared in accordance with IFRS as adopted for use by the European Union.

Diane M V Fraser

Finance Director

22 March 2011

The loss for the year is 100% attributable to equity shareholders of the parent company.

The loss on disposal of oil and gas assets totalled $31,852,000 after tax.

All operations were continuing operations.

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

No income tax arises on the change in fair value of cash flow hedges since the deferred tax asset on these losses is not recognised in the Company.

Consolidated balance sheet

for the year ended 31 December 2010

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

for the year ended 31 December 2010

Attributable to Owners of the Company

Note 1: On 2 March 2011, the High Court of England and Wales passed a Special Resolution to reduce the share capital of the Company by cancelling the Share Premium Account. The total amount was transferred to distributable reserves on 7 March 2011 following registration of cancellation by the Registrar of Companies for England and Wales.

CONSOLIDATED CASH FLOW STATEMENT

for the year ended 31 December 2010

Note 1: Proceeds from the sale of property, plant and equipment exclude $9,068,000 received on 20 January 2011 with respect to the Permian Basin sale transaction.

 SELECTED NOTES TO THE FINANCIAL INFORMATION

for the year ended 31 December 2010

1. Financial information

This press release contains the financial information of Melrose Resources plc (the "Company") and its subsidiaries (together referred to as the "Group") for the year ended 31 December 2010.The financial information set out in this announcement for the years ended 31 December 2010 and 2009 does not constitute the Company's statutory accounts for these periods within the meaning of Section 434 of the Companies Act 2006. Statutory accounts for the year ended 31 December 2009 have been delivered to the Registrar of Companies, and are available on the Company's website at www.melroseresources.com, and those for the year ended 31 December 2010 will be delivered in due course. Both sets of accounts have been prepared in accordance with International Financial Reporting Standards as adopted by the European Union ("adopted IFRS"). The auditors have reported on those financial statements; their reports were (i) unqualified, (ii) did not include references to any matters to which the auditors drew attention by way of emphasis without qualifying their reports and (iii) did not contain a statement under section 498 (2) or (3) of the Companies Act 2006 in respect of the financial statements for 2010. A copy of this press release is available on the Company's website at www.melroseresources.com

Basis of preparation

The financial information set out in this announcement has been prepared on the historical cost convention with the exception of other financial assets which are stated at their fair value at the period end, and in accordance with International Financial Reporting Standards as adopted by the European Union ("adopted IFRS"). The financial information is presented in US dollars rounded to the nearest million. The accounting policies adopted by the Group in this financial information are consistent with those used in the consolidated financial statements for the year ended 31 December 2009, except for the following changes as described below.

Melrose Resources plc (the "Company") is a company domiciled in the United Kingdom and incorporated in England. The financial information set out above contains the financial information of the Company and of the Company and its subsidiaries (together referred to as the "Group") for the year ended 31 December 2010.

This preliminary announcement was authorised by the Directors on 22 March 2011.

Going concern

Further information regarding the Group's business activities, together with the factors likely to affect its future developments, performance and position are set out in the Chairman's statement and the Directors report.

The Directors have prepared cash flow forecasts for the Group and Company for a period covering 12 months from the date of authorisation of these financial statements. The Group's forecasts and projections reflect the Directors' plans for the coming year and include income from the sale of oil, oil liquids and gas, operating expenditure and capital expenditure on exploration and development activity.

The Group has one key customer in Egypt. Should delays in receipt of payment from this customer occur, the Group's position as operator in the majority of its exploration and development activity gives the Group the flexibility to postpone capital expenditure in order to maintain headroom on available facilities.

The Group's forecasts demonstrate that it should be able to operate within the level of its current loan facilities. When performing sensitivities on these projections the Group has taken account of reasonable changes in commodity prices, reasonable delays in the receipt of payment from customers and removed cash inflows from sources which are not yet contractually binding.

The Group's main banking facilities are subject to financial covenants and other conditions which the Group monitors regularly. These covenants and conditions are sensitive to changes in EBITDAX, interest rates and net assets. Whilst the Directors cannot envisage all possible circumstances, they believe that, taking account of reasonably foreseeable adverse movements in oil and gas prices, the Group will continue in compliance with these conditions.

After considering the cash flow forecasts and sensitivities, the Directors have a reasonable expectation that the Company and the Group have adequate resources to continue in operational existence for the foreseeable future. Accordingly, they continue to adopt the going concern basis in preparing the annual report and financial statements.

Accounting judgements and estimation uncertainty

The preparation of the financial statements requires the Directors to make judgements, estimates and assumptions that affect the application of accounting policies and the reported amounts of assets, liabilities, income and expenses. Actual results may differ from these estimates. Information about significant areas of estimation uncertainty that have the most significant effect on the amounts recognised in the financial statements are described within the relevant accounting policies.

Basis of consolidation

The Group financial statements consolidate the financial statements of the Company and entities controlled by the Company (its subsidiaries). Control is achieved where the Company has the power to govern the financial and operating policies of an investee entity so as to obtain benefits from its activities. The financial statements of subsidiaries are included in the consolidated financial statements from the date that control commences until the date that control ceases.

Joint operations are activities where the Group has joint control, established by contractual agreement. The consolidated financial statements include the Group's share of the entities' assets, liabilities, revenue and expenses with items of a similar nature on a line by line basis, from the date that joint control commences until joint control ceases.

All intra-group transactions, balances, income and expenses are eliminated on consolidation.

Presentation of financial statements

The Group applies revised IAS 1, "Presentation of Financial Statements" which became effective as of 1 January 2009. As a result, the Group presents in the consolidated statement of changes in equity all owner changes in equity, whereas all non-owner changes in equity are presented in the consolidated statement of comprehensive income.

Entities are permitted to choose whether to present one performance statement (the statement of comprehensive income) or two statements (the income statement and the statement of comprehensive income). The Group has elected to present two statements.

Foreign currencies

The currency in which the Group entities primarily generate and expend cash is US Dollars. In accordance with IAS 21, "The Effects of Changes in Foreign Exchange Rates", all trading entities within the Group continue to adopt US Dollars as their functional and presentation currency.

Transactions in foreign currencies are converted into US Dollars at the rates of exchange ruling at the transaction date. Gains and losses arising on the revaluation of foreign currency monetary assets and liabilities and financial assets are recognised in the income statement. Non-monetary assets and liabilities that are measured in terms of historical cost in a foreign currency are translated using the exchange rate at the date of the transaction.

Business combinations

Acquisition of subsidiaries and businesses prior to 1 January 2009 are accounted for using the purchase method. The cost of the business combination is measured as the aggregate of the fair values (at the date of exchange) of assets given, liabilities incurred or assumed plus contingent liabilities, plus any costs directly attributable to the business combination. The acquiree's identifiable assets, liabilities and contingent liabilities that meet the conditions for recognition under IFRS 3, "Business Combinations," are recognised at their fair values at the acquisition date.

Goodwill arising on consolidation represents the excess of the cost of acquisition over the Group's interest in the fair value of the identifiable assets, liabilities and contingent liabilities of a subsidiary at the date of acquisition. Goodwill is stated at cost less any accumulated impairment losses. Goodwill is allocated to cash generating units ("CGU") and is not amortised but is tested annually for impairment.

Business combinations which took place prior to the date of transition to IFRS have not been restated.

Exploration and development costs

Pre-acquisition expenditures on oil and gas assets are recognised as an expense in the income statement when incurred.

In accordance with IFRS 6, "Exploration for and Evaluation of Mineral Resources", exploration and evaluation costs are capitalised within intangible assets until the success or otherwise of the well or project has been established and are subject to an impairment review as described below.

The costs of unsuccessful wells in an area are written off to the income statement. This is in accordance with the Group's successful efforts accounting policy but is also compatible with IAS 36, "Impairment of Assets", on the basis that the asset is impaired.

If commercial reserves are established then the relevant cost is transferred (following an impairment review as described below) from intangible exploration and appraisal assets to development and production assets within tangible assets. Expenditures incurred after the commerciality of the field has been established are capitalised within development and production assets.

As required by IAS 8, "Accounting Policies, Change in Accounting Estimates and Errors", the Group applies IAS 16, "Property, Plant and Equipment", and established oil industry practice to expenditures relating to properties or fields with commercial reserves. These are carried as development and production assets within tangible assets.

Expected decommissioning costs of a property are provided for on the basis of the net present value of the liability, discounted at a pre-tax, risk-free rate. An equivalent amount is added to the tangible cost pool, and charged to the income statement in line with the depletion/depreciation of the related asset.

The gain or loss on disposal of development and production assets is recognised in the income statement.

Depletion and amortisation

Depletion of development and production assets is calculated on a field or a concession basis as appropriate. The calculation is based on proved and probable reserves using the unit of production method.

Impairment and ceiling test of oil and gas assets

Exploration and evaluation expenditures which are held as intangible assets under IFRS 6 are reviewed at each reporting date for indicators of impairment. If such indicators exist then the assets are tested for impairment by allocating the relevant item to a CGU or a group of CGUs. An impairment test is also carried out before the transfer of costs related to assets which are being transferred to development and production assets following a declaration of commercial reserves. This impairment test is carried out in accordance with IAS 36, "Impairment of Assets", which requires that the impairment be calculated on the basis of a CGU, a field or a concession, as appropriate.

A review for impairment indicators is also carried out each year on the capitalised costs in development and production assets. This is carried out on a field or a concession basis, as appropriate. Under oil industry standard practice this impairment test is calculated by comparing the net capitalised cost with the net present value of future pre-tax cash flows which are expected to be derived from the field or concession discounted at an appropriate discount rate per annum. Goodwill acquired in a business combination for the purpose of impairment testing is allocated to the CGU expected to benefit from the goodwill.

Impairment of non oil and gas assets

The carrying amounts of the Group's assets, other than exploration and development costs, inventories and deferred tax assets, are reviewed at each balance sheet date to determine whether there is any indication of impairment. If any such indication exists, the asset's recoverable amount is estimated. For goodwill the recoverable amount is estimated at each reporting date.

An impairment loss is recognised whenever the carrying amount of an asset or its CGU exceeds its recoverable amount. Impairment losses are recognised in the income statement. Impairment losses are recognised in respect of CGUs, first to reduce the carrying amount of any goodwill allocated to the unit and then on a pro-rata basis to other assets in the unit.

Calculation of recoverable amount

The recoverable amount is the greater of fair value less cost to sell and its value in use. In assessing value in use, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset. For an asset that does not generate largely independent cash inflows, the recoverable amount is determined for the CGU to which the asset belongs.

Reversals of impairment

An impairment loss is reversed if there has been a change in the estimates used to determine the recoverable amount.

An impairment loss is reversed only to the extent that the asset's carrying amount does not exceed the carrying amount that would have been determined, net of depreciation or amortisation, if no impairment loss had been recognised.

Any impairment loss in respect of goodwill is not reversed.

Plant, property and equipment

Fixed assets, including oil and gas assets, which are not subject to depletion as stated above, are stated at cost less accumulated depreciation and impairment losses. Depreciation is charged to the income statement on a straight line basis.

Annual rate

Plant and equipment 10 to 33%

Oil and gas assets 4 to 5%

Fixed asset investments

Investments in subsidiaries held by the Company are carried at cost less impairment provisions.

Derivative financial instruments/financial assets

Derivative financial instruments (other investments) are recognised at fair value. Other than derivatives qualifying as cash flow hedges, all changes in fair value are recognised as financial income or expense in the period in which they arise. For qualifying cash flow hedges, the element of a change in fair value that is an effective hedge is included in equity, with the remaining ineffective element recognised in financial income or expense.

Inventories

Inventories are stated at the lower of cost and net realisable value. Cost is determined by the weighted average cost formula, where cost is determined from the weighted average of the cost at the beginning of the period and the cost of purchases during the period.

Trade and other receivables

Trade and other receivables do not carry any interest and are stated at their fair value as reduced by appropriate allowances for estimated irrecoverable amounts.

Cash and cash equivalents

Cash comprises cash balances and on-demand deposits. Cash equivalents are short term highly liquid investments that are readily convertible to known amounts of cash.

Interest bearing borrowings

Interest-bearing borrowings are recognised initially at fair value less attributable transaction costs. Subsequent to initial recognition, interest-bearing borrowings are stated at amortised cost with any difference between cost and redemption value being recognised in the income statement over the period of the borrowings on an effective interest basis.

Details of the Group's risk management policies and procedures are given in the Financial review.

Trade and other payables

Trade and other payables are not interest bearing and are stated at their fair value.

Provisions

A provision is recognised in the balance sheet when the Group has a present legal or constructive obligation as a result of a past event, and it is probable that an outflow of economic benefits will be required to settle the obligation. If the effect is material, provisions are determined by discounting the expected future cash flows at a pre-tax rate that reflects current market assessments of the time value of money and, where appropriate, the risks specific to the liability.

Operating segments

In accordance with IFRS 8, the Group determines and presents operating segments based on the information that is provided internally to the executive directors, who are the Group's chief operating decision makers.

An operating segment is a component of the Group that engages in business activities from which it may earn revenues and incur expenses, including revenues and expenses relating to transactions with the other Group's other components. An operating segment's operating results are reviewed regularly by the executive directors to make decisions about resources to be allocated to the segment and assess its performance, and for which discrete financial information is available.

Segment results that are reported to the executive directors include items directly attributable to a segment as well as those that can be allocated on a reasonable basis. Unallocated items comprise mainly corporate assets and head office expenses.

Segment capital expenditure is the total cost incurred during the period to acquire property, plant and equipment, and intangible assets other than goodwill.

Employee benefit

Retirement benefit costs

The Group contributes to money-purchase pension schemes. Contributions are charged to the income statement as they fall due.

Share-based payment transactions

The share option programme allows Group employees to acquire shares of Melrose Resources plc. These awards are granted by Melrose Resources plc. The fair value of options granted is recognised as an employee expense with a corresponding increase in equity. The fair value is measured at grant date and spread over the period during which the employees become unconditionally entitled to the options. The fair value of the options granted is measured using an option valuation model, taking into account the terms and conditions upon which the options were granted. The amount recognised as an expense is adjusted to reflect the actual number of share options that vest except where forfeiture is due only to share prices not achieving the threshold for vesting.

As permitted by IFRS 2 "Share-based Payment", these recognition and measurement principles have not been applied to grants of options prior to 7 November 2002.

Where the Company grants options over its own shares to the employees of its subsidiaries it recognises, in its individual financial statements, an increase in the cost of investment in its subsidiaries equivalent to the equity-settled share-based payment charge recognised in its consolidated financial statements, with the corresponding credit being recognised directly in equity.

The fair value of amounts payable to employees in respect of share appreciation rights, which are settled in cash, is recognised as an expense with a corresponding increase in liabilities, over the period that the employees become unconditionally entitled to payment. The liability is remeasured at each reporting date and at settlement date. Any changes in the fair value of the liability are recognised as a personnel expense in the statement of comprehensive income.

Revenue recognition

Revenue from the sales of oil, oil liquids and gas is recognised at the fair value of consideration received or receivable when the significant risks and rewards of ownership are transferred to the buyer and it can be reliably measured. The revenue of the Group in Egypt is calculated under the terms of production sharing agreements between the Group and its partner (a state owned company). Revenue includes amounts retained by the partner under the terms of these agreements which are used to settle the Group's royalty and income tax liabilities. Realised gains and losses arising from cash flow hedges relating to oil and gas pricing are added to turnover.

Operating lease payments

Payments made under operating leases are recognised in the income statement on a straight-line basis over the term of the lease. Lease incentives received are recognised in the income statement as an integral part of the total lease expense.

Financing income and costs

Financing income comprises interest receivable, net gain on disposal or re-measurement of the fair value of financial assets or investments, and foreign exchange gains which are recognised in the income statement.

Financing costs comprise interest payable, amortisation of loan fees, unwinding the discount on provisions, net loss on disposal or re-measurement of the fair value of financial assets or investments and foreign exchange losses which are recognised in the income statement.

Interest receivable and interest payable is recognised in the income statement as it accrues, using the effective interest method.

In respect of borrowing costs relating to qualifying assets, including exploration costs for which the commencement date for capitalisation is on or after 1 January 2009, the Group capitalises borrowing costs that are directly attributable to the acquisition, construction or production of a qualifying asset as part of the cost of that asset. This accounting policy is in accordance with IAS 23 "Borrowing Costs".

Financial guarantees

The Company has entered into a financial guarantee contract which guarantees the indebtedness of the other companies within its group. The Company considers these to be insurance arrangements, and accounts for them as such. In this respect the Company treats the guarantee contract as a contingent liability until such time as it becomes probable that the Company will be required to make a payment under the guarantee.

Changes in accounting policies

The following new standards, amendments to standards and interpretations which are mandatory for the first time for financial periods commencing on 1 January 2010 have been adopted. None of these have had a significant impact on the reported results.

·; IFRS 3 (revised) 'Business Combinations';

·; IAS 27 (amended) 'Consolidated and Separate Financial Statements'.

New standards and interpretations not yet adopted

A number of new standards, amendments to standards and interpretations are not yet effective for the year ended 31 December 2010, and have not been applied in preparing these financial statements. Those which may have a significant effect on the financial statements are:

·; IFRS 9 'Financial instruments' issued in December 2009. This addresses the classification and measurement of financial assets. The standard is not applicable until 1 January 2013. The impact of this new standard is currently being assessed;

·; Revised IAS 24 'Related party disclosures', issued in November 2009. This standard supersedes IAS 24 'Related party disclosures' issued in 2003. The revised IAS 24 is required to be applied from January 2011. The impact of this new standard is currently being assessed;

·; Improvements to International Financial Reporting Standards 2010 were issued in May 2010. The dates vary standard by standard but most are effective 1 January 2011.

Dividends

Dividends are reported as a movement in equity in the period in which they are approved by the shareholders.

Taxation

Tax on the profit or loss for the year comprises current and deferred tax. Tax is recognised in the income statement except to the extent that it relates to items recognised directly in equity, in which case it is recognised in equity or other comprehensive income.

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, and any adjustment to tax payable in respect of previous years.

Deferred tax is provided on temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for taxation purposes. The following temporary differences are not provided for: the initial recognition of assets or liabilities that affect neither accounting nor taxable profit other than in a business combination, differences relating to investments in subsidiaries to the extent that they will probably not reverse in the foreseeable future and taxable temporary differences arising on the initial recognition of goodwill. The amount of deferred tax provided is based on the expected manner of realisation or settlement of the carrying amount of assets and liabilities, using tax rates enacted or substantively enacted at the balance sheet date.

A deferred tax asset is recognised only to the extent that it is probable that future taxable profits will be available against which the asset can be utilised. 

2. Operating segments

The chief operating decision maker has been identified as the executive directors. The executive directors review the Group's internal reporting in order to assess performance and allocate resources and the Group has determined the operating segments based on this reporting.

The executive directors consider the business from a geographic perspective, and assess the performance of the following regions: Bulgaria, Egypt, USA and other Europe. All of the operating segments derive their revenues from the sale of oil, associated liquids and gas to external customers.

The executive directors consider the performance of the operating segments based on profit from operations. The information provided to the chief operating decision maker is measured in a manner which is consistent with the financial statements.

Other Europe comprises Turkey, France, and Romania.

The Group has one customer who accounted for more than 10% of revenue in both 2009 and 2010. All sales in Egypt in 2009 and 2010 are to a state owned company. The revenue derived from sales to this customer is set out in the table above.

4. Income tax expense

Recognised in the income statement

Tax charge in income statement

Reconciliation of effective tax rate

There is no deferred tax recognised directly in equity.

Deferred tax not recognised in the Company amounts to $32,350,000 (2009: $25,886,000). No deferred tax asset has been recognised as it is not considered probable that future taxable profits will be available in the Company against which a deferred tax asset could be recovered.

5. Loss per share

The calculation of the basic and diluted loss per share is based upon the following data:

The weighted average number of ordinary shares used in the calculation of basic and diluted loss per share for each year was calculated as follows:

6. Cash and cash equivalents

Bank deposits comprise bonds held by the Group on short term deposits with an original maturity of three months or less. Bank balances are held in overnight deposit accounts with immediate access. The carrying amounts of these assets approximate their fair value.

7. Bank loans

This note provides information about the contractual terms of the Group and Company's interest-bearing loans and borrowings.

All borrowings are denominated in US Dollars.

Note:

Proved and probable reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological, geophysical and engineering data demonstrate with a specific degree of certainty to be recoverable in future years from known reservoirs and which are considered commercially producible. The figures are estimated on the basis that there should be a 90% probability that the actual quantity of recoverable reserves will be more than the amount estimated as proven and there should be a 50% probability that the actual quantity of recoverable reserves will be more than the amount estimated as proved and probable. The reserves stated are directors' estimates based upon evaluations by Company employees which have been reviewed by independent petroleum engineers.