Management Resource Solutions Regulatory News (MRS)

FOR RELEASE AT 7AM

28 March 2012

Annual results for the year ended 31 December 2011

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 and Turkey today announces its annual results for the year ended 31 December 2011. 

Operational highlights

·; average production 34.3 Mboepd on a working interest basis (18.7 Mboepd net entitlement)

·; first full year of Kaliakra and Kavarna fields production with 95% uptime

·; Muridava and Est Cobalcescu Concession Agreements signed

·; improved pricing secured for Bulgarian gas production

·; seismic surveys acquired on the Mesaha, Rhône Maritime and Galata concessions

·; East Texan asset divestment completed, concluding the withdrawal from the USA

Financial highlights

·; revenue increased by 21% to $291.0 million (2010: $240.4 million)

·; EBITDAX increased by 65% to $248.2 million (2010: $150.7 million)

·; profit after tax increased to $51.6 million (2010: $11.7 million loss)

·; net debt reduced to $322.6 million (2010: $418.8 million)

·; financial gearing reduced to 89 percent (2010: 133 percent)

Robert Adair, Executive Chairman commented

"2011 was an important year for the Company as we saw the impact of the first full year of production from our new Bulgarian fields supplementing our existing Egyptian producing assets. This has driven some outstanding financial performance, allowing us to retire a significant proportion of the Company's debt and reduce financial gearing. With our positive outlook for 2012, we have recently set a new target to reduce gearing to around 60 percent by the end of this year.

Given the Company's strengthening financial position, we now have increasing capacity to pursue new business opportunities. Our main focus will be on the acquisition of exploration and development assets in the MENA and Black Sea regions where we can leverage our established relationships and operating expertise. We look forward to growing as a diversified and well balanced exploration and production company."

For further information please contact:

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Chairman's Statement

I am pleased to report that Melrose delivered excellent financial results during 2011 with revenues of $291 million and EBITDAX of $248 million. This performance continues a trend of improving cash generation and has allowed the Company to retire a significant proportion of its debt and reduce financial gearing from 133 percent to 89 percent during the year. This is well ahead of our target which was to achieve around 100 percent gearing by year end.

The Company's production averaged 34.3 Mboepd over the year on a working interest basis (or 18.7 Mboepd on a net entitlement basis). The production figures reflect a shift of balance within the portfolio, with increased volumes from the Kaliakra and Kavarna fields offshore Bulgaria, offset by natural declines in some of our Egyptian fields. At 31 December 2011, the Company's year end proved plus probable reserves were 84.4 MMboe on a working interest basis.

The new Bulgarian gas production has helped to diversify and de-risk the Company's production base and provides additional exposure to commodity price upsides. During the year some 40 percent of the Company's revenues were generated in Bulgaria where we benefit from strong local gas prices linked to the oil price. A further 35 percent of the revenues were derived from Egyptian liquids production, for which we receive international market prices, with the remainder from our Egyptian fixed price gas contracts.

During the year, we continued to focus on growth opportunities and were pleased to sign the Concession Agreements for the Muridava and Est Cobalcescu exploration blocks in the western Black Sea, offshore Romania. These exciting new licences have significant oil and gas resource potential and will form a major component of our exploration programme over future years. We also completed three major seismic programmes to enhance the existing prospect inventory including surveys offshore Bulgaria and over our frontier exploration blocks in southern Egypt and offshore southern France.

In Egypt, 2011 marked a period of political change resulting in free parliamentary elections earlier this year with a coalition of Islamist parties now holding the majority. Over the next few months, a new constitution will be formulated and presidential elections are planned for late May. During the period of change, Melrose has not experienced any material operational disruption and we continued to receive payment for our production from EGPC, the responsible government agency. We shall of course continue to monitor the position closely this year and maintain a close dialogue with the Egyptian authorities. We have great confidence in the resilience of the Egyptian people through these times of transition to what we believe will be a better future for the country.

Production and developments

The Group working interest production averaged 34.3 Mboepd during the year, being 18.7 Mboepd on a net entitlement basis. Approximately 86 percent of the production was gas with the balance comprising oil, condensate and Liquid Petroleum Gas ("LPG"). 

2011 represented the first full year of production from the Kaliakra and Kavarna gas fields which came on stream in November 2010. These fields were developed using single subsea well completions tied back to the existing Melrose operated Galata platform and, throughout the year, the facilities and well performance has proved to be highly reliable. The combined average production rate during the year was 42 MMcfpd. With these two fields safely on stream, the Company has turned its attention to developing the Kavarna East field which will share the same subsea flow line as Kavarna and is due on stream in mid 2013.

In Bulgaria, Melrose sells its gas to Bulgargaz EAD (a state-owned gas utility company) and Agropolychim (an independent industrial purchaser) and during 2011 received a weighted average price of $7.35 per Mcf. At the start of 2012, the gas price was amended by contract to reflect strong oil prices and for this year should average at least $8.50 per Mcf, assuming the current exchange rate. This represents a material improvement and, coupled with the competitive local operating costs of $0.35 per Mcf, will help underpin the Company's cash flow.

The Bulgarian production was supplemented by the ongoing contribution from Melrose's eleven producing fields onshore in the Nile Delta, Egypt. The underlying performance of the majority of these fields has been strong although two of these fields, North East Abu Zahra and South Zarqa, experienced water breakthrough early in 2011 prompting some remedial operations and adjustments to our annual production forecast.

The Company's two most material Egyptian assets, the West Dikirnis oil and gas field and the West Khilala gas field, performed well during the year and they provide a solid, long term production platform. On West Dikirnis, the hydrocarbon liquids rate effectively stabilised during the year at around 3,600 bpd in response to the gas re-injection scheme introduced in 2010. Early in 2011 we completed two new development wells in the field and this year a refrigeration unit will be added to the existing LPG plant to recover an incremental 750 bpd of hydrocarbon liquids. On West Khilala, we recently brought on stream a successful new well, which has helped to confirm the field reserves estimate, and we are now investing in compression facilities to mitigate the natural field decline. 

Exploration and appraisal

The primary focus of the Company's exploration programme during 2011 was on seismic data acquisition and we completed surveys in Egypt, Bulgaria and offshore southern France. We also drilled two unsuccessful exploration wells, namely, Kaliakra East, offshore Bulgaria, and South West Kanun-1 in southern Turkey. Approximately 47 percent, or $30 million of the Company's capital expenditure was dedicated to exploration activities which is comparable with the current forecast for 2012.

In Egypt, the Company has completed the interpretation of the South East Mansoura 3D seismic survey acquired in 2010 and this has confirmed the presence of multiple prospects and leads in the Cretaceous oil play. Individually, each structure is relatively modest in scale but on a combined basis the play resource potential is estimated at 54 MMbbl. One of the prospects, Al Hajarisah, with prospective resources of 6 MMbbl and a chance of success of 21 percent, has been selected for drilling in 2013. 

Elsewhere, in southern Egypt we acquired 1,844 kilometres of 2D seismic data over the southern area of the Mesaha frontier exploration concession. The data quality is significantly improved compared to previous surveys and has enabled the joint venture partners to select a well location which will be drilled in the second half of this year. This will be the first wildcat exploration well to be drilled in this untested sedimentary basin and, whilst the risks are understandably high, so is the potential.

During 2011, the Company also sidetracked the West Zahayra-1 well, which was drilled in 2008, seven kilometres west of the West Dikirnis field. The sidetrack encountered 25 feet of net oil pay and flowed at a stabilised rate of 100 bopd during a long term test. This result effectively extended the area of the Mansoura concession known to be oil prone and we now plan to drill an adjacent exploration prospect, North West Zahayra-1, in mid 2012. This has prospective resources of 1.4 MMbbl with a 35 percent chance of success and could potentially be developed in tandem with the West Zahayra accumulation. 

In Bulgaria, we have recently completed a 3D seismic acquisition programme on the Galata block to evaluate an area to the north of the existing Galata-Kaliakra field trend. This area of the block contains the Chaika structure which was previously identified on 2D data and the new survey will be used to confirm the prospective resource estimate and optimise the future drilling plans for the block. Earlier in the year, the Company drilled the Kaliakra East exploration well to test a structure near the Kaliakra field but the main Palaeocene reservoir interval was found to be eroded and the well was plugged and abandoned. 

We continue to be excited by the exploration potential offshore Romania and will be moving forward at pace with the work programmes on our new Muridava and Est Cobalcescu concessions. These shallow water blocks are under-explored and contain multiple oil and gas exploration plays which lie on trend with existing discoveries in neighbouring licences. Our current estimate of the resource potential is between 1 Tcfe and 2 Tcfe. The forward plan for the licences involves the acquisition of 3D seismic this year to be followed by a six well programme and to share the exploration costs and risks we are farming down our interests in both blocks to around 40 percent.

We also continued with our frontier exploration initiatives in Turkey and France during 2011. Our first well in Turkey, South West Kanun-1, was drilled to test the Cretaceous and Ordovician intervals but failed to encounter hydrocarbons due to the absence of mature source rock in the region. Given the results from the well we are unlikely to pursue further exploration in the area. In France, alongside our partner Noble Energy, we completed a 7,500 kilometre 2D seismic acquisition covering the entire area of the Rhône Maritime concession. The interpretation of the data is ongoing and we are planning to meet with Noble Energy in the coming months to agree on future work plans. 

Portfolio Management

The Company continues to actively manage its asset portfolio and, most notably, in March this year announced the signature of the Concession Agreements for the Muridava and Est Cobalcescu blocks offshore Romania. This was followed by their formal ratification by the Romanian Council of Ministers and the agreements came into force on the 24 October 2011. The new concessions offer some very exciting and potentially material exploration upside, particularly in the light of recent drilling results offshore Romania. It is prudent, however, for the Company to share some of the investment risks on the planned seismic and multi-well drilling programme and in line with previously stated strategy we plan to farm down a proportion of our equity in the concessions whilst retaining operatorship.

Elsewhere, we have also extended the terms of several of our existing exploration licences to ensure we have sufficient time to optimise the technical work programmes on the blocks. In Bulgaria, we secured an extension to the Galata concession until February 2013, when the Company may apply for a further two year extension period. In Egypt, Melrose has entered the second period of the Mesaha concession which will run until October 2014, and in France, in conjunction with our partner Noble Energy, we have applied to extend the Rhône Maritime licence to November 2015.

Our portfolio initiatives are designed to ensure that the Company's resources remain focussed on material opportunities in areas where we have competitive advantage. As part of this process, we have continued to rationalise the portfolio and last year announced the sale of our minor gas leases in South East Texas, USA, for a consideration of $5.9 million. Following the Permian Basin divestment the previous year, this effectively concludes Melrose's withdrawal from the USA.

The Company is also continually evaluating business development opportunities, with a primary focus on exploration and development assets located in the MENA and western Black Sea regions. We are seeking to acquire strategic, material, high quality and value accretive growth opportunities to leverage the Company's regional relationships and operating skills.

Health, safety, environmental and social

Health, Safety, Environmental and Social ("HSES") considerations are fundamentally important to the Company and we continually seek ways to improve our performance in these areas. Our aim is to keep safe all those involved in or affected by our operations, to minimise our impact on the environment and to have a positive impact on the people and communities affected by our activities. To help guide us in this regard we have in place a well developed HSES Management System, which is regularly updated, and we systematically report on HSES matters at Management Committee and Board meetings.

During 2011, our Bulgarian operating company achieved accreditation under the ISO 14001 and OHSAS 18001 international standards for safety and environmental management. This represents an expansion of a programme introduced in 2010 when our Egyptian operations became accredited and Melrose is as a result fully compliant with the international standards across its drilling and production operations.

Whilst there is always room for improvement, our safety and environmental performance during 2011 has compared well with the industry as a whole. We experienced no Lost Time Incidents during the year and continued to minimise green house gas emissions by ensuring that no waste gas is flared at any of our facilities. The Company has also increased the capacity of its Egyptian produced water sequestration scheme.

We were pleased to see the school Melrose has supported near the West Dikirnis facilities in Egypt become operational during the year. The Company was hugely instrumental in driving the project through from conception to completion and made a substantial financial contribution to the construction costs. Further support was provided to our other educational initiatives, including the Karim Dom Centre in Varna, Bulgaria, for children with special needs, and a girl's school in Tammeya, Egypt.

Reserves

The Company's proved and probable reserves at year end were 84.4 MMboe on a working interest basis, which equates to 35.6 MMboe on a net entitlement basis. These figures reflect the annual production volume, the divestment of the Company's East Texan gas fields in the USA and previously reported reserves adjustments in the Kaliakra field in Bulgaria and the North East Abu Zahra, West Khilala and South Damas fields in Egypt.

Board and staff

During 2011, the Melrose Board continued to operate in a very effective and supportive manner, maintaining a clear focus on material business and governance related matters. Our Board members have a complementary blend of skills and experience, gained from both within and outside the oil and gas industry, which provides a strong platform for discussions at a strategic and tactical level. Notwithstanding this, we review the Board composition on a regular basis and will add further members, if appropriate, as the Company evolves. 

Melrose manages its business on a day to day basis through an executive Management Committee, which operates at a level beneath the Board. This committee comprises the Executive Directors plus a group of senior oil and gas industry managers with a depth of experience across many disciplines and international regions. The committee is ably supported by our technical, financial and administrative personnel.

I would like to take this opportunity to thank the Melrose Board and all our staff for their valuable collective and individual contributions. Everyone has an important role to play in the development of the business and the level of support and commitment we have seen from the Melrose team over the years has now translated into some impressive financial results. 

Financial results

Melrose achieved excellent financial results in 2011, underpinned by production from the new Bulgarian and existing Egyptian fields and strong commodity prices. Revenues for the year were $291 million, reflecting a 21 percent increase over 2010, and EBITDAX was $248 million, some 65 percent higher than the previous year. Profit after tax was $51.6 million as compared to a loss of $11.7 million in 2010.

The financial performance has enabled us to accelerate the planned reduction in the Company's debt and I am pleased to report that, at the year end, our net debt stood at $323 million. Financial gearing has been reduced from 133 percent to 89 percent during the year.

Based on the Company's continued progress, I am pleased to announce that we are proposing that the dividend for this year will be 3.6 pence per share (2010: 3.4 pence per share). If approved at the AGM in June, the dividend distribution will be made on 20 July 2012. We intend to maintain our progressive dividend policy although it will as always be subject to Melrose's capital requirements for existing and new business opportunities and the prudent management of cash reserves.

Outlook

The Company's strong financial results reflect the investment we have made over recent years to establish a robust production platform in our core areas in Egypt and Bulgaria.

This year we expect production to average approximately 28.0 Mboepd and, given the increased gas price in Bulgaria and strong current oil prices, we are confident we can deliver another good year of financial performance. This will allow us to continue to aggressively pay down debt and we have recently set a new target to achieve financial gearing around 60 percent by the end of 2012, assuming normal trading conditions.

In parallel with the de-gearing process, we have the capacity to pursue exploration projects in all our operating areas with two wells planned for Egypt, including our first wildcat well on the large Mesaha frontier concession, and a contingent well in Bulgaria. We are particularly pleased to be starting seismic operations on our new concessions offshore Romania this year since the region is fundamentally under-explored and has significant resource potential. We also continue to look for growth opportunities in the MENA region and elsewhere but are intent on only acquiring high quality assets.

We made good progress in a number of areas last year and in particular, with our solid production base, have delivered some excellent financial results. Looking forward, as the Company's financial capacity continues to improve, I am confident we have the team and resources to generate significant shareholder value over future years.

Robert F M Adair

Chairman

27 March 2012

OPERATIONAL REVIEW

EGYPT

Melrose holds interests in four concessions in Egypt; Mansoura, South East Mansoura, Qantara and Mesaha. The Mansoura, South East Mansoura and Qantara concessions are located onshore in the Nile Delta and are 100 percent operated interests, providing a balance of established production and exploration potential. Mesaha, in which Melrose holds a 40 percent operated interest, is a large frontier exploration block located in southern Egypt.

The political changes which have occurred in Egypt during 2011 have been well documented. In January, a civil uprising led to the ousting of former President Hosni Mubarak, ending his 30 years in power. A path to political reform commenced in March and this culminated in free parliamentary elections in which 67 percent of the seats were won by Islamist parties, including 44 percent held by the Muslim Brotherhood. The new Parliament convened on 23 January 2012. Presidential elections are now scheduled to occur on 23 May with the newly elected President expected to take up office on 30 June. In parallel with this process, a Commission comprising 100 elected individuals is being formed to draw up a revised constitution for the country.

Although the political changes and civil unrest continue to cause some social instability, Melrose has experienced no material operational disruption as a result of these events and continues to receive payments for its oil and gas sales from EGPC, the relevant government agency. The Company will, however, continue to monitor the situation closely and is well positioned to adjust its operations in response to changes in the country if appropriate.

Throughout 2011, the Company continued to invest in its existing fields through an ongoing development programme. At West Dikirnis two additional wells have been drilled to maximise hydrocarbon liquids recovery and in 2012 the Company will commence the construction of a Refrigeration Unit to expand the existing LPG facilities. At West Khilala, one new well has recently been completed and compression facilities will be installed to mitigate the natural field decline and maximise the gas reserves.

The majority of the exploration prospectivity in Egypt is located in the South East Mansoura and Mesaha concessions and in order to prepare for drilling activity on these blocks, a significant amount of seismic data has been acquired over the past two years. In South East Mansoura, the 3D seismic data set acquired in 2010 has been fully interpreted and confirmed the presence of multiple prospects and leads in the Cretaceous oil play and we plan to drill our first well there in 2013. On Mesaha, the results from the 2D seismic acquisition programmes are now available and a location for the first wildcat well in this frontier exploration area has been identified for drilling in the second half of 2012. 

Production

In 2011, the Company's daily production from Egypt averaged 26,805 boepd on a working interest basis, which is equivalent to 11,158 boepd on a net entitlement basis.

The production stream comprised 128.9 MMcfpd of gas and 4,587 bpd of oil, condensate and LPG on a working interest basis. Net entitlement production averaged 53.4 MMcfpd of gas and 1,956 bpd of hydrocarbon liquids.

Approximately 70 percent of the production volumes were derived from the West Dikirnis and the West and South Khilala fields, with the remainder from nine smaller fields located in the Mansoura, South East Mansoura and Qantara concessions. 

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 one of the Company's core assets and the average production rate during 2011 was 69 MMcfpd of gas and 81 bpd of condensate from six wells.

The field continues to perform well. Early in the year, a standard well integrity work-over programme was conducted on three of the producing wells and some minor water production has been observed in the completions. Most importantly, however, the field pressure history and open hole log results from the recently completed West Khilala-8 well indicate very limited aquifer movement across the field which helps to confirm the field reserves estimate.

The field's ultimate gross proved plus probable reserves have recently been re-estimated at 291 Bcfe and by year end 2011 approximately 55 percent of this volume had been produced. Reservoir studies indicate that with the planned addition of compression facilities, which should be available late in the second quarter 2013, and one new producer drilled next year, the field life is expected to extend until at least 2023.

South Khilala field

The South Khilala gas field was discovered in May 2009 and is being produced through the West Khilala facilities. First production was achieved in October 2009 and the average production rate in 2011 was 13.9 MMcfpd of gas and 17 bpd of condensate. A second development well, South Khilala-2, is planned to be drilled in 2012 to fully access the gas reserves contained in the southern lobe of the field.

The field is estimated to have ultimate gross proved plus probable reserves of 47 Bcfe and by the end of 2011 approximately 12 Bcfe had been produced. 

West Dikirnis field

The West Dikirnis oil and gas field was discovered in December 2005 and brought on production in November 2007. The field comprises a 70 foot thick oil reservoir which is overlain by a thick gas cap in the Qawasim formation. Since the field came on stream, Melrose has focused on maximising the hydrocarbon liquids recovery from the field by drilling horizontal wells and installing LPG recovery and Gas Reinjection ("GRI") facilities.

The Company has an active reservoir management programme in place for the field and individual well withdrawal rates are being restricted to maximise reserves by preventing premature water breakthrough or excess gas production. In 2011, two new wells were drilled in the field and there are now seven active production wells, four horizontal and three vertical, and one gas injection well. The average annual production rate was 3,543 bpd of oil, condensate and LPG and 2.9 MMcfpd of gas and approximately 29 MMcfpd of gas is being injected into the reservoir.

The field development activity will continue in 2012 with the expansion of the LPG plant with the addition of a refrigeration unit, which is expected to be on stream at the end of the year. This will add approximately 50 tonnes per day of LPG production (equivalent to 553 bpd) and about 200 bpd of condensate. Further horizontal development wells are also being planned for 2013.

In the medium to long term, once the maximum economic volume of hydrocarbon liquids has been produced from the oil rim, the field will be converted to gas production. Until recently, the Company had been planning to implement this conversion in 2018, however, the performance of the GRI scheme has been very positive and suggests that the gas blow-down phase may be deferred for up to a further five years. This is because gas cycling through the reservoir appears to be highly effective at stripping liquids from the oil rim, which will push back the conversion date and may possibly lead to reserves upgrades in future.

The field's ultimate proved and probable reserves are currently estimated at 19.5 MMbbl of hydrocarbon liquids and 93 Bcf of gas and by the end of 2011, the field had produced 8.3 MMbbl of liquids and 17.4 Bcf of gas.

El Tamad field

El Tamad is a small oil and gas field located in the Mansoura Concession which, similar to West Dikirnis, comprises an oil rim overlain by a gas cap. The Company is currently analysing the possibility of drilling additional horizontal wells in the field to enhance its production rate and to help produce the remaining recoverable reserves.

The field's production in 2011 averaged 218 bpd of oil and 4.2 MMcfpd of gas. The ultimate gross proved plus probable reserves are estimated at 2.1 MMbbl of oil and 31.2 Bcf of gas and to year end 2011 some 1.7 MMbbl of oil and 5.1 Bcf of gas had been produced.

East Abu Khadra field

The East Abu Khadra field is an Abu Madi formation discovery which was made in 2008, and brought on stream later that year. The field has a single production well, which has continued to perform well during the year with an average rate of 8.9 MMcfpd of gas and 73 bbl of condensate per day. The ultimate gross proved plus probable reserves are estimated at 31.4 Bcfe of which 9.1 Bcfe had been recovered by the end of 2011.

South Zarqa field

The South Zarqa field is also an Abu Madi formation discovery, which was brought on production in April 2009 through a tie back to the South Batra facilities. During the year the average field production rate was 11.2 MMcfpd of gas and 392 bpd of condensate.

This field has a very active aquifer underlying the gas reservoir and in April 2011 the production well experienced the onset of early water break though and associated sand production. Following a water shut-off treatment and the introduction of surface sand control equipment the well is back on production but at a reduced rate to prevent a re-occurrence of the issue. The year-end ultimate gross reserves estimate was 35.4 Bcf of gas and 1.2 MMbbl of condensate.

North East Abu Zahra field

North East Abu Zahra is an Abu Madi field which was tied back for production to the South Batra facilities in April 2009. The field was initially produced using the original discovery well which was located on the flank of the structure and this experienced water breakthrough and ceased to flow in April 2011. A replacement well, NEAZ-2, was completed in December and this is currently being produced at a restricted rate of 4 MMcfpd of gas and 70 bpd of condensate to reduce the risk of water production.

As a result of the water production and incorporating the geologic results from the NEAZ-2 well, the field's ultimate proved plus probable reserves estimate has been reduced to 16.3 Bcf of gas and 0.3 MMbbl of condensate.

South East Mansoura Concession

Damas and South Damas fields

The Damas and South Damas fields were discovered in 2008 and 2010 respectively. Damas was first brought on production during 2009 but was temporarily shut in to enable the South Damas field to flow through a common pipeline to the South Mansoura facilities during 2010. 

The South Damas field has performed exceptionally well since inception and the reserves were upgraded by 24 Bcf at year end, giving gross ultimate proved plus probable reserves of 50 Bcf of gas and 0.2 MMbbl of condensate. The average production rate for the year from the field was 12.2 MMcfpd of gas and 95 bpd of condensate.

Qantara Development Lease

Qantara field

Qantara is a relatively small gas condensate field located near the Suez Canal. The field has its own standalone processing plant for the gas and in 2011 the average rate was 0.9 MMcfpd of gas and 99 bpd of condensate. Production from Qantara is highly profitable as the gas sales price for this concession is linked to oil price rather than the fixed domestic gas price.

The average 2011 working interest production rates for the Company's Egyptian fields are summarised as follows:

Exploration

A core strategy of Melrose is the maintenance of a balanced portfolio of production, development and exploration assets. During 2011, the Company continued to de-risk its exploration portfolio primarily through further seismic data acquisition and interpretation.

The concessions operated by Melrose contain a diverse range of exploration opportunities. The Mansoura concession is relatively mature and so the primary focus is on the development of existing fields. Meanwhile, the neighbouring South East Mansoura concession is 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. The large Mesaha concession, which is located in southern Egypt, is completely unexplored and contains a large sedimentary basin which may be prospective in the Ordovician, Silurian and older formations and Cambro-Ordovician sediments.

In the Mansoura concession, Melrose re-entered and sidetracked the old West Zahayra-1 discovery well during the year. The sidetrack encountered an oil column with 25 feet of net pay and an average porosity of 19%. The sandstone reservoir is fairly tight but the well was flowed at a stable rate of 100 bopd, with 44° API gravity oil, during a long term flow test. A field development plan is currently being prepared for the accumulation.

The test results extended the area of the Mansoura concession which is known to be oil prone and the Company has identified another exploration prospect in the vicinity of the well. The prospect, which will be drilled in mid 2012, is called North West Zahayra and contains prospective resources of 1.4 MMbbl with a 35 percent chance of success. 

During the second half of 2011, Melrose completed the interpretation of the 370 square kilometres 3D seismic survey acquired in South East Mansoura in 2010. The interpretation focused on the Cretaceous oil play which exists in the central and western area of the concession and confirmed the presence of several prospects and leads. The Company estimates the unrisked play potential at 54 MMbbl of oil and one prospect, Al Hajarisah, has been selected for drilling in 2013 following completion of the drilling operations in Mesaha.

The Company continued its exploration programme in the Mesaha Concession during 2011 and entered into the second 3 year period of the licence term in October. The work programme includes one commitment well, which had been carried forward from the initial term, and a further 1,500 kilometres of 2D seismic. 

To complement the regional 2D seismic survey acquired in 2010, Melrose shot an additional 1,844 kilometres of 2D infill seismic over the south-western area of the concession in the first half of the year. The data confirmed the presence of large rotated fault block geometries and intra-basinal highs and it is believed that the basin may be deep enough to generate hydrocarbons. Very little is known, however, about the stratigraphy in the basin and it is not clear at this stage whether it is primarily Palaeozoic or infra-Cambrian in origin.

Based on the seismic data a location has been selected for the first well to be drilled in the basin and this is scheduled to spud in Q3 2012. The gross well cost is estimated at $8.0 million ($3.2 million net to Melrose).

BULGARIA

Melrose continued to build on its position in the Bulgarian waters of the western Black Sea during 2011, delivering solid production performance whilst commencing an exploration programme in the under-explored central area of the Galata block. In addition, the Company successfully attained formal accreditation under the international Environmental Management (ISO 14001) and Occupational Health and Safety (OHSAS 18001) standards. 

Production and Development

The Kavarna and Kaliakra gas fields were brought on-stream in late 2010 using single subsea well completions tied back to the existing Melrose operated Galata production platform. In their first full year of production, the fields have produced at an average rate of 42 MMcfpd, which represents approximately 18 percent of the Bulgarian domestic gas requirements. 

Based on the initial reservoir performance trends, the reserves for both fields were revised in 2011 and the ultimate proved plus probable reserves are now estimated at 33 Bcf and 27 Bcf for Kaliakra and Kavarna, respectively.

With the two new fields on stream, Melrose is currently focused on progressing the Kavarna East development and during 2011 received the Commerciality Certificate for the field. Subsequently, the Company has applied for the Production Concession which is expected to be granted by mid 2012. The field has proved plus probable reserves of 9.8 Bcf and will be developed in 2013 using a shared subsea flow line with Kavarna field.

In December, Melrose signed amendments to its existing gas sales contracts to confirm the nominations and pricing for the Kavarna and Kaliakra 2012 production volumes. Under the contracts Bulgargaz, the Bulgarian state-owned gas utility company, has nominated 285 million cubic metres of gas and Agripolychim, an industrial consumer, a further 75 million cubic metres. The nominations can be increased and are expected to cover the full field production for the year which is forecast at an average of 38 MMcfpd.

The gas price received is calculated in Bulgarian Leva, which is linked to the Euro, and therefore the average reported price for the year will vary according to Euro to US Dollar exchange rate fluctuations. Based on the current exchange rate the minimum weighted average price for 2012 is forecast to be $8.50 per Mcf, representing a 16% increase compared to 2011.

Exploration

During 2011, Melrose received approval to enter the first extension period for the Galata block exploration licence, which will run until February 2013. The work programme commitment included one firm and one contingent well and the acquisition of 500 square kilometres of 3D seismic data. 

In July, as part of the work programme commitment, the Company drilled the Kaliakra East exploration well. The principal target was the Palaeocene formation, which represents the main reservoir interval in Melrose's other discoveries in the region, but unfortunately the target zone was found to be eroded in the well. There were some gas shows in the Oligocene section with some petrophysical interpretation of pay, however, MDT pressure sampling confirmed this interval to be tight and as a result the well was plugged and abandoned.

The Company has recently acquired a total of 512 square kilometres 3D seismic data over the Galata block to the north of the existing fields. The data quality is very good and following completion of the interpretation the Company will revise its prospective resources assessment for the block. The data will also be used to optimise the future drilling programme, with a focus on the area around the Chaika prospect, which was previously identified on old vintage 2D data.

ROMANIA

In 2010, Melrose and its partner, Petromar Resources SA, successfully bid for two new licences in the 10th Romanian Licensing Round. The new licenses, Muridava and Est Cobalcescu, are located in the shallow waters of the western Black Sea, to the north of the Company's Bulgarian assets. Melrose is the operator of both licences and holds a 40 percent interest in Muridava and a 70 percent interest in Est Cobalcescu.

The Concession Agreements for the licences were signed in March 2011 and, subsequently, the Romanian National Agency of Mineral Resources confirmed that the Romanian Council of Ministers had formally ratified the agreements on 24 October 2011. This date effectively marks the beginning of the first three year licence term.

Muridava and Est Cobalcescu have a combined area of approximately 2,000 square kilometres and are located in an area formerly subject to a maritime boundary dispute between Romania and the Ukraine. As such, both licences are under-explored and our analysis indicates that they contain multiple oil and gas exploration plays in the Cretaceous, Eocene, Miocene and Pliocene formations, They are also on trend with other discoveries in the area and one undeveloped discovery, Olimpiskiyi, lies within the Muridava licence. Needless to say, The Company is excited by the blocks' resource potential which it places in the range of 1 Tcfe to 2 Tcfe.

In a more general sense, Melrose expects the activity levels offshore Romania to increase over the next few years with various other operators planning seismic and drilling programmes. The Company was also encouraged by the recent announcement of the deep-water Domino gas discovery which it interprets to be in the Miocene formation, one of the primary targets on the Est Cobalcescu block.

The licences have a three year initial term which may be followed by an optional three year extension. The firm three year work programme for each block comprises seismic acquisition and three wells and the Company is planning to acquire 3D seismic surveys on both blocks in the summer of 2012.

FRANCE

The Rhône Maritime concession is a large frontier exploration block, located in deep water offshore southern France and covering an area of 9,375 square kilometres. Melrose holds a 27.5 percent non-operated interest in the licence having farmed down the majority of its stake to a strategic partner, Noble Energy Inc ("Noble"), in late 2010. 

Following Noble's entry into the concession, the joint venture commissioned TGS Nopec to undertake a block-wide 7,500 kilometre 2D seismic survey which was completed in early 2011. The seismic data quality is excellent and the interpretation, the majority of which is being performed by Noble, is approaching a conclusion.

The two primary exploration objectives are pre-salt Miocene and post-salt Pliocene plays which may be analogous to similar plays found in the eastern Mediterranean region offshore Egypt, Israel and Cyprus. The forward work programme, which may comprise 3D seismic and/or drilling activity, will be defined once the seismic interpretation has been completed. 

In parallel with the technical evaluation, the Company has applied to enter the second term of the exploration licence which will expire in November 2015 and this is currently being processed by the French authorities.

TURKEY

Melrose operates and holds a 66.7 percent working interest in five frontier exploration concessions in the South Mardin basin in southern Turkey. The concessions have a combined area of 2,487 square kilometres and cover a large Palaeozoic sub-basin in the northern Arabian plate. 

During the year Melrose drilled its first wildcat well on the concessions to test a structure called South West Kanun. The well was drilled to a total depth of 9,203 feet and cost $6.1 million gross ($4.9 million net to Melrose).

The well was designed to test the Cretaceous and Ordovician formations but failed to encounter hydrocarbons and was therefore plugged and abandoned. The post well analysis indicates that no mature source rock was encountered in the well and long distance migration paths would need to be established to make the region prospective. Based on this analysis, the Company is unlikely to pursue further exploration activities in the area.

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 has delivered very strong financial results for the year ended 31 December 2011, with profit after tax of $51.6 million and cashflow from operations of $196.0 million, enabling the Company to reduce its net debt and gearing levels significantly during the period. Net debt as at 31 December 2011 was $322.7 million (2010: $418.9 million) resulting in gearing of 89% (2010: 133%), well below the Company's target of 100%. The Group expects operating cash flow to remain strong during 2012 supported by revenues from both Bulgaria and Egypt resulting in the Company reducing its target gearing level to around 60 percent by the end of 2012.

The Company also completed the disposal of its East Texas gas assets, concluding the Company's exit from the US, for a consideration of $5.9 million. As such, the results of the US are presented as discontinued in 2011 and for clarity, all information disclosed in the following Financial Review relates to total operations, both continuing and discontinued, unless stated otherwise.

Results for the year

Revenue for the year was $291.0 million which compares with revenue of $240.4 million in 2010. The increase primarily reflects the full year contribution from the Bulgarian fields, Kavarna and Kaliakra, offset by reduced revenue in Egypt. Revenue split by country is Egypt $175.0 million (2010: $202.2 million), Bulgaria $113.6 million (2010: $16.9 million) and the USA $2.4 million (2010: $21.3 million).

Depletion, depreciation and decommissioning charge has increased from $85.2 million in 2010 to $110.5 million for 2011. This charge includes the ceiling test write-down of $12.3 million taken in June 2011 with respect to the non-developed fields in East Texas, USA.

Unsuccessful efforts of $17.4 million (2010: $10.8 million) are a total of $9.4 million in Bulgaria where we drilled the Kaliakra East well and the drilling of the South West Kanun-1 well in Turkey at a cost of $8.0 million.

Group operating costs reduced to $24.4 million in 2011 from $28.6 million in 2010 following the disposal of the Permian Basin assets in the USA, which were high operating cost assets. This reduction was offset in part by increased operating costs in Bulgaria as a result of the full year's production during 2011. The Group operating costs in 2011 were $3.14 per boe, previously $4.09 per boe in 2010, a reduction of 23% per boe.

The Group generated gross profit of $138.8 million compared with $115.8 million in 2010, an increase of $23.0 million.

Administrative expenses have reduced to $22.0 million from $23.4 million.

The sale of the remaining US gas assets was completed on 1 December 2011 at a consideration of $5.9 million. After taking account of transaction adjustments and working capital movements, $5.6 million was received in December 2011. The gain on disposal of the assets was $3.2 million. The Group has no remaining oil and gas assets in the US.

Profit before tax was $97.2 million (2010: $29.8 million), an increase of 226% on the previous year.

Excluding the tax credit on the US disposals in 2010, the tax charge has reduced from $47.8 million to $45.6 million, representing 47% of profit before tax (2010: 70%). The cash tax payable for the year is $1.5 million (2010: $0.1 million) with the majority of the current tax charge relating to Egyptian imputed tax of $45.1 million and the remainder being a net credit for deferred tax in the period.

Profit after tax amounted to $51.6 million (2010: loss of $11.7 million). 

Operating cashflow has increased to $196.0 million (2010: $130.6 million) an increase of 50%.

EBITDAX, calculated after the deduction of the gain / loss on disposal of US assets, for the year of $248.2 million compares with $150.7 million for the previous year. Excluding the impact of the gain / loss on disposal of the US assets, adjusted EBITDAX was $245.0 million (2010: $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 $64.4 million (2010: $100.9 million). This was split geographically as follows; $18.6 million (2010: $57.5 million) in respect of properties in Bulgaria, $40.2 million (2010: $36.4 million) in Egypt, $nil (2010: $3.1 million) in the USA and $5.6 million (2010: $3.9 million) in Turkey, Romania and France. The $64.4 comprises $34.4 million of development and $30.0 million of exploration assets (2010: $68.8 million development, $32.1 million exploration).

Loan facilities

As at 31 December 2011, senior loan facilities of $375 million and subordinated facilities of $70 million remain in place with a final repayment date of 2014.

At 31 December 2011, the Group had cash balances of approximately $53.4 million (2010: $70.4 million) and bank loans, net of capitalised arrangement fees, totalling $376.0 million (2010: $489.2 million).

Dividends

A dividend of 3.6 pence per share is being proposed (2010: 3.4 pence per share total dividend). The estimated total dividend of $6.5 million (2010: $6.3 million) will be deducted from retained reserves. If approved at the AGM in June, the dividend distribution will be made on 20 July 2012 to those shareholders on the register as at 8 June 2012.

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 2011 was $3.14 per boe (2010: $4.09). The table below summarises the key indicators which reflect 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 2011.

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 2011, the Company had no interest rate cash hedges in place.

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

Currency risk

Presently, the Group has exposure to foreign currency risk as a significant proportion of its revenue and expenditure is denominated in local currency. A proportion of the Group's Bulgarian receipts are received in Bulgarian Leva, which is directly linked 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 adopted to minimise revenue exposure. Currency risk is limited to the extent that overhead costs and a proportion 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, although this is reviewed periodically to ensure the policy reflects ongoing material contracts.

Pricing risk

In Egypt, liquids realise market prices based on Western Desert pricing, which during 2011 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. In Bulgaria, the price for the majority of the gas sales is fixed until the end of 2012, with the remainder calculated quarterly at a discount to the local quarterly consumer natural gas price, as published by Bulgargaz EAD (the 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 22% of Group revenue in 2011.

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

27 March 2011

CONSOLIDATED INCOME STATEMENT

for the year ended 31 December 2011

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

Discontinued operations relate to the Group's US asset portfolio, the final assets of which were disposed of in December 2011. 

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

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

Consolidated balance sheet

for the year ended 31 December 2011

The Board of Directors approved the financial statements on 27 March 2012.

R F M Adair Director 

D M V Fraser Director

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

for the year ended 31 December 2011

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 2011

 SELECTED NOTES TO THE FINANCIAL INFORMATION

for the year ended 31 December 2011

This regulatory announcement 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 2011. The financial information set out in this announcement for the years ended 31 December 2011 and 2010 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 2010 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 2011 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 2011. A copy of this regulatory announcement is available on the Company's website at www.melroseresources.com

1. Accounting policies

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 2011.

Statement of compliance

Both the parent company financial statements and the Group financial statements have been prepared and approved by the Directors in accordance with International Financial Reporting Standards and their interpretation as adopted by the EU ("adopted IFRS").

Basis of preparation

The financial statements are prepared on the historical cost basis with the exception of other financial assets which are stated at their fair value at the period end. They are presented in US Dollars rounded to the nearest thousand.

The accounting policies set out below refer to both the Group and Company where applicable and have, unless otherwise stated, been applied consistently to all periods presented in these consolidated financial statements and the parent company financial statements.

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.

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.

All Egyptian production is sold to a state owned company. The majority of Bulgarian production is sold to the Bulgarian state gas company, with the balance sold to an industrial customer. Should delays in receipt of payment from the Egyptian 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 two Bulgarian customers have historically paid invoices by their due date (15 days following the end of the month to which the production relates).

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.

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.

Jointly controlled operations are activities where the Group has joint control, established by contractual agreement. Where the Group's activity is conducted through a jointly controlled operation, 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.

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". 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.

Foreign currencies

The currency in which Group entities primarily generate and expend cash and are funded 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 intoUS 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

Business combinations are accounted for using the acquisition method on the date on which control is transferred to the Group.

Goodwill arising on a business combination comprises the fair value of the consideration transferred; plus the recognised amount of any non-controlling interests in the acquiree and the fair value of the existing equity interest in the acquiree; less the net recognised amount (generally fair value) of the identifiable assets acquired and liabilities assumed. Any contingent consideration payable is recognised at fair value at the acquisition date with subsequent changes recognised in profit or loss. Costs related to the acquisition, other than those associated with the issue of debt or equity securities, are expensed as incurred.

For acquisitions prior to 1 January 2009, transaction costs incurred by the Group in connection with business combinations, other than those associated with the issue of debt or equity securities, were capitalised as part of the cost of the acquisition. Business combinations which took place prior to the transition to IFRS have not been restated.

Goodwill is allocated to cash generating units ('CGU') and is not amortised but is tested annually for impairment.

Discontinued operations

Classification as a discontinued operation occurs on disposal of a major separate line of business or geographical region. When an operation is classified as a discontinued operation, the comparative statement of comprehensive income is re-presented as if the operation had been discontinued from the start of the comparative year.

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.

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 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 benefits

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 equity settled 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.

Employee benefit trust

Transactions of the Company-sponsored employee benefit trust are treated as being those of the Company and are therefore reflected in the parent company and group financial statements. In particular, the trust's purchases and sales of shares in the Company are debited and credited direct to equity.

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 or deleted from 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 are recognised in the income statement as they accrue, 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.

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. 

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 2011 have been adopted. None of these have had a significant impact on the reported results or financial position.

·; Revised IAS 24 'Related party disclosures', issued in November 2009;

·; Improvements to International Financial Reporting Standards 2010, issued in May 2010.

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 2011, and have not been applied in preparing these financial statements. None of these are expected to have a significant effect on the financial statements of the Group, with the exception of IFRS 9 'Financial Instruments' which, once endorsed, will become mandatory for the Group's financial statements for the year ended 31 December 2015. Pending endorsement, the standard is not available for early adoption and its potential impact is being assessed.

2. Discontinued operation

The Group completed the sale of its gas assets in South East Texas in December 2011. This disposal concluded the divestment of the Group's US asset portfolio which began with the sale of the Permian Basin assets in December 2010.

The loss from the discontinued operation is 100% attributable to equity shareholders of the parent company.

Gain / (loss) on disposal of discontinued operation

As at 31 December 2011, other receivables included a balance of $0.5 million (2010: $9.6 million) and other payables included a balance of nil (2010: $0.3 million) relating to the disposals.

3. 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. The USA region is classified as a discontinued operation at 31 December 2011. Other Europe comprises Turkey, France, and Romania. 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.

Two of the Group's customers accounted for more than 10% of revenue in 2011, and one customer accounted for more than 10% of revenue in 2010. All Egyptian revenue in 2010 and 2011, as set out in the tables above, is generated from a state owned company. Revenue in 2011 included $105.3 million from a Bulgarian state owned company.

4. Net financing income / (cost)

5. Income tax expense

Recognised in the income statement

Reconciliation of effective tax rate

There is no deferred tax recognised directly in equity.

Factors which may affect the future tax charge include the mix of jurisdictions with different tax rates in which profits and losses arise and changes in tax rates.

6. Earnings per share

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

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

7. 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.

8. Bank loans

At 31 December 2011, senior loan facilities of $375 million and subordinated facilities of $70 million remain in place with a final repayment date of 2014. 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.