24 Mar 2010 07:00
FOR IMMEDIATE RELEASE
24 March 2010
MELROSE RESOURCES PLC
Annual results for the year ended 31 December 2009
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 the United States of America, France and Turkey, today announces its annual results for the year ended 31 December 2009.
Operational highlights
§ 9% increase in working interest production to 38,595 boepd (2008: 35,554 boepd)
§ 131% reserves replacement ratio achieved.
§ Net entitlement reserves at year end of 68.5 MMboe (2008: 66.6 MMboe)
§ Five new Egyptian fields brought on production
§ Two Egyptian exploration discoveries
§ Successful appraisal drilling in Bulgaria confirming Kaliakra field commerciality
§ Romanian farm-in agreement signed and resources upgrade
Financial highlights
§ Turnover of $224 million (2008: $373 million)
§ EBITDAX of $178 million (2008: $330 million)
§ Profit before tax of $30.9 million (2008: $143.3 million)
§ Proposed dividend 3.1 pence per share (increase by 10% relative to 2008)
§ Enhanced debt facilities to $520 million and strengthened bank syndicate
§ Successful equity placing of £11.2 million ($18.5 million)
Robert Adair, Executive Chairman, commented:
"Melrose has again delivered a strong set of operating results in 2009 and we achieved a record level of production, underpinned by our core Egyptian fields and five new developments coming on stream. We also had success with our exploration and appraisal drilling programme in Egypt and Bulgaria and it is very pleasing that we achieved a good reserves replacement ratio during a period when capital expenditures were somewhat reduced in response to the low oil prices experienced early in the year. Our financial performance also proved resilient with strong levels of turnover and EBITDAX.
We now look forward to 2010 when we plan to bring two new Bulgarian gas fields on stream and to progress our other gas developments in the Western Black Sea towards project sanction. These new investments will add significant value to the Company and help rebalance the portfolio by diversifying the Company's production and revenue streams. We will also be dedicating an increased proportion of our capital budget, around 30%, to exploration initiatives and have an active seismic and drilling programme planned in our core and frontier exploration areas."
For further information please contact:
| Melrose Resources plc David Thomas, Chief Executive Robert Adair, Executive Chairman Diane Fraser, Finance Director
|
0131 221 3360 |
| Buchanan Communications Tim Thompson Ben Romney |
0207 466 5000
|
Chris McMahon
or visit www.melroseresources.com
CHAIRMAN'S STATEMENT
I am pleased to report that Melrose has again delivered strong operating results in 2009. The Group achieved a record production level of 38.6 Mboepd, ahead of expectations, and successfully brought five new field developments on stream in Egypt. The Company also achieved a net entitlement reserves replacement ratio of 131 percent for the year and it is encouraging that we more than replaced annual production volumes during a period when our exploration and appraisal activities were somewhat reduced in response to the low oil prices experienced in late 2008 and early 2009. The Group's proved plus probable reserves now stand at 68.5 MMboe on a net entitlement basis.
The Company is also reporting good financial results with turnover of $224 million and EBITDAX of $178 million. Although these figures are lower than last year, this is largely attributed to the fact that the average oil price we received in 2009 was significantly less than in 2008. The Group also strengthened its balance sheet during the year through a successful equity placing, which raised £11.2 million, and enhanced its existing debt facilities.
Production and developments
The Group's production averaged 38.6 Mboepd during 2009 on a working interest basis, which represents an increase of 9 percent over 2008 and exceeded our initial expectations for the year. On a net entitlement basis our production averaged 17.0 Mboepd. Approximately 74 percent of the production was gas and the remaining 26 percent was oil and condensate. The majority of the production during the year came from Egypt with a small contribution from the USA although the production portfolio will rebalance during 2010 when we bring on-stream two new gas field developments offshore Bulgaria.
The Group's production was underpinned by a strong performance from our main Egyptian fields, West Dikirnis and West Khilala, both of which are situated in the Mansoura Concession onshore in the Nile Delta. The West Khilala gas field continues to produce on a steady plateau and has proved itself to be a very high quality asset requiring minimal ongoing investment. Phase II of the West Dikirnis oil field development was significantly progressed during the year and is rapidly approaching completion. Three horizontal wells were drilled and we also installed new Liquid Petroleum Gas ("LPG") and gas re-injection facilities which are currently being commissioned. These investments will maximise the recovery of hydrocarbon liquids from the field as well as reducing the environmental impact by removing the need for flaring.
During 2009, five new fields were brought on to production in Egypt, namely North East Abu Zahra, South Zarqa, North Dikirnis, Damas and the South Khilala discovery which was made in May. These fields have added significant production and reserves and were tied back to existing infrastructure quickly, simply and at low cost. Indeed the average unit development cost was less than $1.60 per boe which is exceptionally low in today's industrial environment.
In Bulgaria, we are currently developing two gas fields, Kavarna and Kaliakra, which we have recently discovered on the same geologic trend as the Melrose operated Galata field. Both fields, which have combined reserves of 74 Bcf, will be developed using simple, single well subsea tiebacks to the Galata platform and should be brought on stream during 2010. The combined production rate from these fields is forecast to be around 45 MMcfpd and, given the strong Bulgarian gas pricing, the fields will have a significant impact on the Group's cash flow.
We are also progressing our plans to convert the Galata field to a strategic gas storage scheme to help guarantee a secure gas supply for the state of Bulgaria. Discussions with the authorities on the storage scheme have been progressing a little slower than we would have liked, primarily due to a change of Government in mid 2009. However, the discussions are still ongoing and we remain well positioned to commence injection in the summer of 2010 if required.
Production in the United States was steady during the year and the secondary recovery programme in the Permian Basin, incorporating a major infill drilling and waterflood campaign, progressed as planned. We have now established a 20 acre well spacing pattern waterflood over the Jalmat field and central area of the Turner Gregory field and our focus is on increasing the water injection rates which in turn will increase the oil production.
Exploration and appraisal
At the start of 2009, against a backdrop of low commodity prices, Melrose adopted a strategy of focusing its capital expenditure on near term revenue generating projects and material growth opportunities. As a result we reduced the proportion of our capital budget being spent on exploration from approximately 40% in 2008 to around 19% in 2009. In 2010 this figure should rise again to approach 30% which represents a reasonable short to medium term guide for the Company.
In Egypt, the Company drilled three exploration wells during the year with two successes. These include the South Khilala discovery, which has estimated reserves of 39 Bcf, and was rapidly tied back for production across the existing West Khilala facilities. The East Dikirnis-1 well was also a discovery with reserves estimated in the range of 10 to 12 Bcfe and this field is expected to be developed when additional low risk prospects have been drilled in its immediate vicinity. In 2010, we have already drilled two exploration wells with one success at South Damas where we found 30 Bcf of gas. This discovery will be rapidly tied back to the existing Damas field and should be on production in the third quarter of the year. Our latest well, Tall Rak, penetrated an unusually thick sequence of limestone in the target reservoir horizon and did not find hydrocarbons.
In Bulgaria, we continued our recent record of drilling success with the Kaliakra No.2 appraisal well which firmed up the field reserves estimate at 49 Bcf and also supported an increase to the Kavarna field reserves to 25 Bcf. The success of this well has also increased our appetite to drill two other follow-on prospects on the same Galata trend and one well is planned to be drilled on the concession in 2010.
In the United States in East Texas we drilled our first deep gas well on the Nunan prospect and the well encountered a significant high pressure gas column with an estimated gas in place of 73 Bcf. However, the formation has very low permeability and the well results are currently being independently evaluated to determine whether the discovery can be commercialised using advanced horizontal well completion technology.
In order to ensure that the Company's prospect inventory is continually refreshed, Melrose has also progressed seismic acquisition programmes over a number of its concessions. A 2D seismic acquisition programme is currently ongoing on both the Mesaha block in southern Egypt and on the South Mardin blocks in southern Turkey and it is hoped that these surveys will identify drillable prospects in at least one of these frontier exploration areas. Meanwhile, further 3D seismic data acquisition is also planned for 2010 in the South East Mansoura Concession in the Nile Delta where we are expecting to identify additional prospects to drill in 2011 and beyond.
New business development
During the year we announced that we had entered a farm-in agreement to acquire a 32.5% interest in the Midia and Pelican blocks, offshore Romania in the Black Sea. These blocks offer Melrose access to two significant gas developments, the Ana and Doina fields, and a number of exciting oil and gas exploration prospects with significant potential.
Following the farm-in agreement, Melrose has reprocessed and interpreted the close-spaced 2D seismic data which was acquired over the Ana and Doina trend in 2008 and re-analysed the available well data. This work has supported an upgrade to the fields' potential and the gross probable resources have been independently audited at a combined figure of 345 Bcf, as compared to Melrose's previous figure of 288 Bcf. The new estimate corresponds on a net basis to 18.7 MMboe and this volume has not yet been included in the Company's probable reserves bookings. We are currently planning for the field development consents to be obtained by the end of 2010 with first gas forecast in late 2012 at a combined gross rate of 110 MMcfpd.
The Company also plans to participate in an exploration well to be drilled on the Pelican concession in the third quarter 2010 to test the Eugenia South oil prospect. This has gross unrisked reserves of 45 MMbbl contained in two potential reservoir targets in the Eocene and Cretaceous formations. Both of these formations are productive in the nearby Lebada fields and the Eocene is oil bearing in an offset discovery called Olimpiskiyi.
The completion of the farm-in transaction remains subject to Romanian government approval and the approvals process has been somewhat delayed due to the change of government in the country in the fourth quarter of 2009. Melrose has, however, received formal approval to act as the field operator from the relevant authorities and we are cautiously optimistic that the farm-in interest will be assigned to the Company shortly. Once this process is complete, we will be in a position to secure the financing required to progress the field developments and discussions on this subject are well advanced with a number of leading banks.
We look forward to establishing a significant position in the Romanian oil and gas industry, utilising the knowledge and experience gained in our Bulgarian exploration and development assets to the south.
Health, safety, environmental and social
As the Company has evolved and grown, we have placed an increased emphasis on our health, safety, environmental and social ("HSE&S") responsibilities and in 2009 we continued the implementation of the HSE&S Management System launched in early 2008.
Within the framework of this Management System, during 2009 we have particularly focused on reducing the environmental impact of our operations in Egypt through a number of initiatives. These include the installation of the West Dikirnis LPG facilities which will eliminate the need for gas flaring and reduce our greenhouse gas emissions significantly and the completion of two water injection wells in the South Batra field which are being used to dispose of all the produced water from the West Dikirnis field, removing the need to use third party contractors to process and dispose of the water in the local water system.
Melrose has an established track record of helping to develop the local communities where we operate and we are very pleased with our latest social initiative. This involves the Company making a significant financial contribution towards the building of a new secondary school near the West Dikirnis field in Egypt. Substantial progress has already been made in its construction and we are hoping to see it open by the start of the school year in autumn 2010.
Reserves
Our proved and probable reserves on a net entitlement basis at the year end totalled 68.5 MMboe, which compares with 66.6 MMboe as at 31 December 2008. This represents a reserve replacement ratio of 131%, equivalent to an absolute increase of 1.9 MMboe. The increase is largely due to exploration discoveries of 2.3 MMboe, appraisal asset revisions of 6.4 MMboe and producing field revisions of 1.2 MMboe. These changes were partially offset by production of 6.2 MMboe and a reduction in the Egyptian net entitlement volumes of 1.8 MMboe due to changing oil price assumptions. On a working interest basis the Company's total proved plus probable reserves were 131.4 MMboe.
The above figures do not include reserves associated with the Romanian farm-in of 18.7 MMboe net which cannot be booked until the transaction formally completes.
Board and staff
After a period of nine years as an independent non-executive Director, Jimmy Hay stood down from the Board at the AGM in June 2009. Jimmy provided tremendous support and wise counsel during a period of significant growth for the Company and on behalf of the Board I would like to thank him for his contribution and wish him all the best in his retirement.
During 2009 the Board demonstrated that it has a good balance of experience, independence and insight across many disciplines and industries and it operates in a very supportive, pragmatic and responsive manner. Whilst we intend to review the composition of the Board on a regular basis it is our intention that we shall only add further members where we believe there is a clearly defined need.
Beneath the Board we operate with a Management Committee which comprises an experienced group of senior management individuals who bring expertise from all disciplines of the Group and they are ably supported by our technical and financial professional staff. The combined team is very strong and on behalf of the Board I would like to thank all the Melrose staff for the hard work and commitment which helped make 2009 a success.
Financial results
Melrose achieved good financial results in the year which were underpinned by our production performance. Our turnover for the year was $224 million, EBITDAX was $178 million and the profit before tax was $31 million. Although these numbers are lower than 2008, this is a reflection of the reduced global commodity prices received in 2009 as opposed to 2008. In July 2009 we successfully completed an equity placing raising £11.2m before expenses. These funds were used to accelerate the drilling of the Kaliakra No.2 well.
Based on the Company's continued progress, I am pleased to announce that we are proposing that the dividend for this year will be 3.1 pence per share, which represents a 10% increase on the total dividend paid in 2008. If approved at the AGM in June, the dividend distribution will be made on 20 July 2010 to those shareholders on the register as at 11 June 2010. We intend to maintain our progressive dividend policy for the future 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
In what has been a difficult year for industry in light of the global economic downturn, Melrose has emerged in a strong position with a solid operating base, high value development and exploration projects to pursue and well supported debt facilities.
Looking forward, we are excited about our Bulgarian gas developments and the addition of Romania to our asset portfolio where we plan to leverage our regional operating experience to successfully bring the Ana and Doina fields to production. We have also built a very strong production platform for the Company in Egypt and this should provide the base for further growth aided by a more stable commodity pricing environment.
We are also pleased to be able to start to refocus on exploration, dedicating an increased proportion of our capital expenditure to seismic and drilling to actively pursue our various exploration initiatives in Egypt, the Western Black Sea and Turkey.
I believe 2010 will represent another period of significant growth for the company and look forward to the future with confidence.
Robert F M Adair
Chairman
OPERATIONAL REVIEW
EGYPT
During 2009, Melrose continued its active exploration and development work programme on its Egyptian acreage which includes the Mansoura, South East Mansoura and Qantara Concessions onshore in the Nile Delta region and the frontier Mesaha Exploration Concession in Southern Egypt.
The Company built on its strong production position in Egypt during the year and achieved a new production record with an average daily rate of 37,237 boepd on a working interest basis (15,633 boepd on a net entitlement basis). The production was underpinned by contributions from Melrose's two main fields in the Mansoura Concession, namely, West Khilala and West Dikirnis, and supplemented by a number of smaller fields in the Mansoura, South East Mansoura and Qantara Concessions.
Development activity focused on the implementation of Phase II of the West Dikirnis development plan which consists of drilling a number of horizontal wells and installing Liquid Petroleum Gas ("LPG") recovery and Gas Re-injection ("GRI") facilities in order to maximise the recovery of hydrocarbon liquids from the field before ultimately converting it to gas production. To date, the LPG plant has been commissioned and the GRI facilities have been completed with commissioning activities ongoing.
Four new low cost field developments were completed in the Mansoura Concession during 2009, namely, South Zarqa, North East Abu Zahra, North Dikirnis and South Khilala. The latter field was discovered in May 2009 and commenced production in October 2009, which is indicative of the short cycle times within which Melrose can bring discoveries on stream in the Nile Delta area using its existing facilities and infrastructure. One further field was put on production during the year, the Damas field in the South East Mansoura Concession. The average unit development cost for these five new fields was approximately 17 US cents per Mcf which underline the low cost nature of the onshore Nile Delta operating environment.
Alongside the development activity, the Company is pursuing an exploration strategy designed to produce a strong inventory of drilling prospects to sustain future growth. During 2008, new 2D and 3D seismic data were acquired on the under-explored South East Mansoura Concession and after processing and interpretation in 2009 this has yielded a number of new prospects for drilling in 2010 and 2011. Further 3D seismic data will be acquired in the Concession in 2010 in order to better evaluate a new exploration play in the Cretaceous and Jurassic formations. In addition, the Company acquired a ground gravity survey over the Mesaha Exploration Concession in 2009 in order to prepare for 2D seismic acquisition in early 2010.
Production
The average production on a working interest basis in 2009 in Egypt was 170.1 MMcfpd of gas and 8,879 bpd of oil and condensate. Net entitlement production averaged 71.4 MMcfpd of gas and 3,725 bpd of oil and condensate. Total average production for the year reached a record level of 37,237 boepd, representing an increase of 22% relative to 2008 on a working interest basis.
The majority of the production, some 27,126 boepd, was derived from the West Dikirnis and the West Khilala fields and the remainder from the El Tamad, South Zarqa, North East Abu Zahra, East Abu Khadra, North Dikirnis, Salaka, South Mansoura, South Batra, Tummay and South Khilala fields in the Mansoura Concession and the Al Rawda and Damas fields in the South East Mansoura Concession and the Qantara field.
Mansoura Concession
West Khilala field
The West Khilala field, which was discovered in the Abu Madi formation in October 2005, remains one of the Company's core assets and continues to perform exceptionally well. First production was achieved from the field in February 2007 and the field has been producing on plateau since January 2008 at a rate of approximately 100 MMcfpd. The field is currently being produced by six wells and their performance to date has been excellent with no water or sand production. Field evaluation and reservoir modelling work indicate that with some compression facilities the field should be capable of maintaining the plateau rate until mid 2011.
Based on reservoir production and pressure performance, the field's ultimate gross proved plus probable reserves are currently estimated at 307 Bcf, which represents an increase of 12 Bcf compared to year end 2008 figures. By year end 2009, approximately 101 Bcf of gas had been produced from the field.
South Khilala field
The South Khilala-1 well was drilled to test a Qawasim prospect approximately 10 kilometres south of the West Khilala field and resulted in a successful discovery which was announced in May 2009. The well encountered 62 feet of net pay and the ultimate gross proved plus probable reserves estimate is 39 Bcf on a working interest basis as booked at year end 2009. The well was fast tracked on to production using a 6 inch flow line to tie it back to the West Khilala facilities and came on stream in October 2009. The well is currently producing at a rate of 13.2 MMcfpd of gas and 30 bpd of condensate.
West Dikirnis field
This field was originally discovered in December 2005 in the Qawasim formation and subsequently brought on production in November 2007. The field comprises a 70 foot thick oil reservoir which is overlain by a gas cap. During the first few years of the development, Melrose is focussing on maximising the oil and hydrocarbon liquids recoveries prior to producing the gas cap later in the field life. In 2009, the field produced oil from eight wells, four of which are vertical or slightly deviated wells and four of which are horizontal wells. During 2009, this field flowed at an average rate of 6,765 bpd of oil and condensate and 19.5 MMcfpd of gas.
In order to maximise the oil and hydrocarbon liquid recoveries, the Company has been pursuing an integrated "Phase II" investment programme for the field. During 2009, this programme included the drilling of three new horizontal wells to supplement the first horizontal well which was brought on stream in late 2008. The three new wells have been completed with an average horizontal wellbore length of 1,400 feet drilled in the reservoir formation and an average initial rate of 2,400 bopd. The horizontal well programme, which represents the first use of this technology in the onshore Nile Delta, has been very successful and further wells of this type are expected to be drilled in the field in the forthcoming years.
The Phase II programme also includes the installation of an LPG plant to extract propane and butane in liquid form from the gas which is produced from the field. Installation of the new LPG facilities has been completed and the facilities were commissioned in 2009. In tandem with the LPG plant construction, the Company has installed GRI facilities which will be used while the oil rim is being produced to re-inject the dry gas which has been stripped of the LPG back into the reservoir gas cap to maintain reservoir pressure and maximise oil recoveries. The GRI facilities are currently being commissioned and are expected to be fully operational by the end of the first quarter 2010.
Melrose has been actively managing the individual well withdrawal rates in the field to minimise premature water and gas production and hence maximise reserves. The field's ultimate gross proved plus probable reserves are estimated at 20 MMbbl of hydrocarbon liquids and 113 Bcf of gas and have been broadly unchanged for the last two years. By the end of 2009, the West Dikirnis field has produced approximately 5.4 MMbbl of oil and condensate and 11.9 Bcf of gas.
The North Dikirnis-1 discovery well has been tied back to the West Dikirnis production manifold and was put on production in April 2009. The initial production rate of this well was 6 MMcfpd of gas and 12 bpd of condensate and although the well declined relatively rapidly and was shut-in in September it generated positive cash flow and an attractive IRR due to the low development costs.
The GRI facilities will remove the need for any ongoing gas flaring at the West Dikirnis plant which will significantly reduce the impact of the Company's operations on the environment. In another environmental initiative, during 2009 the Company recompleted two South Batra field production wells as water injection wells and these are currently being used to sequester all the produced water from the West Dikirnis field (currently averaging 3,200 bwpd) thus avoiding the need for processing and subsequent disposal in the local water system.
El Tamad field
El Tamad is the second of Melrose's oil producing fields in the Mansoura Concession. In 2009, the field's average production rate was 760 bpd of oil and 1.9 MMcfpd of gas and the field performance continues to be encouraging. The ultimate proved plus probable reserves are 2.4 MMbbl of oil and 31.5 Bcf of gas and to year end 2009 some 1.7 MMbbl and 2.6 Bcf had been recovered.
In order to enhance the field's ultimate reserves, a horizontal well was drilled and completed in the reservoir in 2009 and brought on production in April at an initial rate of 600 bpd. A 3D reservoir model is being built for this field in order to evaluate the potential for drilling additional horizontal wells to optimise the oil development prior to converting the field to gas production.
East Abu Khadra field
The East Abu Khadra field was discovered in 2008 in the Abu Madi formation approximately 14 kilometres south east of the West Khilala field. The field was fast-tracked for development via the South Batra facilities using a 6 inch flow line and came on production in December 2008. The ultimate gross proved plus probable reserves are estimated at 8.2 Bcf of which 32 percent have been recovered and the field is flowing at 7.9 MMcfpd of gas and 125 bpd of condensate.
North East Abu Zahra
The North East Abu Zahra field was discovered in the Abu Madi formation in 2007 and was developed in parallel with the South Zarqa field using a common 35 kilometre, 10 inch flow line tied back to the South Batra plant. Production from the single well development commenced in April 2009 and the average rate during 2009 (post start-up) was 21.1 MMcfpd of gas and 566 bpd of condensate. The well performance has been very positive and the ultimate field proved plus probable reserves were upgraded by 10 Bcfe at year end 2009 to 34 Bcfe.
The North East Abu Zahra field is part of the same gas accumulation as the El Basant field on a neighbouring Concession, which is operated by Dana Gas, and 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.
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 2009, the average field production rate was 16.6 MMcfpd of gas and 595 bpd of condensate and the ultimate reserves estimate was materially unchanged at 46 Bcfe at year end 2009.
South Mansoura and Salaka Fields
These fields are located in the Mansoura Concession and are currently producing through wells South Mansoura-1 and Salaka-1. In 2009, the average production rate of South Mansoura-1 and Salaka-1 combined was 3.6 MMcfpd of gas and 22 bpd of condensate.
As of the end of 2009, the recovered gas from the South Mansoura field reached 13 Bcf representing 58% of the original gas in-place and the field is expected to be abandoned in the near future.
The Salaka-1 well is also approaching depletion in the Abu Madi reservoir and will shortly be recompleted into a new untapped interval in the Kafr El Sheik reservoir. The new interval has a net gas pay of 27 feet and contains estimated reserves of approximately 3 Bcf. It is anticipated that the well will produce at an average rate of around 6 MMcfpd during its first year on production and reach payback on a net basis within 4 months.
South East Mansoura Concession
Al Rawda field
Al Rawda-1 was the first exploration well drilled by Melrose in the South East Mansoura Concession and was a gas and condensate discovery in the Sidi Salim formation. The well was put on production in August 2007 through a dedicated pipeline to the South Mansoura plant. In 2009, the average field production rate was around 2.7 MMcfpd of gas and 30 bpd of condensate.
Damas Field
The Damas field was discovered in 2008, and was tied back to the South Mansoura facilities using a 19 kilometre, 6 inch pipeline with first gas production in July 2009. In 2009, the average field production rate was approximately 5.2 MMcfpd of gas and 49 bpd of condensate.
Qantara Concession
Qantara field
Following a period where the Qantara field lay dormant the Qantara-4 well was sidetracked and completed as producer in 2008 and a facilities refurbishment programme was initiated. Production re-commenced in October 2008 and in 2009, the average well rate was 1.5 MMcfpd of gas and 252 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.
Melrose currently has an interest in an area of 47km² in this Concession with no further commitments required to be satisfied. This interest is due to expire in October 2010 and negotiations with the Egyptian authorities are ongoing as to the extent of the relinquishment at that time, which is likely to include much of the exploration acreage.
In summary, the average working interest production rates for 2009 of the fields in Egypt are as follows:
| Field | Production - average 2009 rate | ||
|
| Gas (MMcfpd) | Liquids (bpd) | Total (Mboepd) |
| West & South Khilala | 104.2 | 144 | 17.5 |
| West & North Dikirnis | 21.4 | 6,790 | 10.4 |
| El Tamad & Tummay | 2.4 | 760 | 1.2 |
| South Mansoura, South Batra | 3.6 | 25 | 0.6 |
| South Zarqa | 10.1 | 362 | 2.0 |
| N.E.Abu Zahra | 14.7 | 394 | 2.8 |
| East Abu Khadra | 7.0 | 98 | 1.3 |
| Damas | 2.5 | 24 | 0.4 |
| Al Rawda | 2.7 | 30 | 0.5 |
| Qantara | 1.5 | 252 | 0.5 |
| Total | 170.1 | 8,879 | 37.2 |
Note: average production rates are calculated over the full 12 month period even if a field is brought into production during the year.
Exploration
Melrose holds a balanced exploration portfolio in Egypt and strives to maintain a range of prospects and play types offering the potential for significant exploration upside. In the Mansoura Concession, the exploration is relatively mature but the remaining acreage still offers potential, particularly in the young Tertiary deltaic sequence. In contrast, the neighbouring South East Mansoura Concession is relatively under-explored and contains both Tertiary deltaic prospects in its northern area and Cretaceous and Jurassic prospectivity in the central and southern areas of the block. The giant Mesaha block in Upper Egypt potentially contains an unexplored sedimentary basin which may be prospective in the Ordovician, Silurian and older formations and whilst high risk it could potentially be high reward.
In 2009, Melrose drilled three exploration wells on the Mansoura Concession and in early 2010 has drilled two further wells in the South East Mansoura Concession. Two of the exploration wells, South Khilala-1 and South Damas-1, yielded commercial discoveries with combined proved plus probable reserves estimated at 69 Bcfe. Another of the wells, East Dikirnis-1, yielded a discovery with estimated reserves in the range 10 to 12 Bcfe and is expected to be developed once other low risk prospects in its vicinity have been drilled. North West Nabourah-1 and Tall Rak-1 well did not discover commercial quantities of hydrocarbons.
During 2010, the Company plans to acquire a further 500 square kilometres of 3D seismic data over the South East Mansoura Concession, increasing the 3D coverage up to 45 percent of the block area. The seismic will be focussed on the Cretaceous and Jurassic exploration play which exists in the central area of the Concession and which contains a number of oil leads requiring additional seismic to mature them into drillable prospects.
Mansoura Concession
During 2009, three exploration wells were drilled on the Mansoura Concession.
The East Dikirnis No.1 well was drilled approximately 11 kilometres east of the West Dikirnis field to test a Qawasim prospect and the well encountered 38 feet of gas overlying an 11 foot thick oil rim. The estimated discovery volume is in the range of 10 to 12 Bcfe and the well has been temporarily suspended for future use as a production well. The well has established that the area of the Concession in the vicinity of the well may be oil prone and a number of similar low risk prospects near the discovery are currently being evaluated for potential inclusion in the drilling programme.
The South Khilala No.1 exploration well was drilled 10 kilometres to the south of the West Khilala field and encountered 62 feet of net pay in the Qawasim Formation. The ultimate reserve estimate for the discovery is 39 Bcf and the well was tied back for production through the West Khilala facilities in October 2009.
More recently in 2009, North West Nabourah No.1 was drilled approximately 10 kilometres to the south of the South Khilala field. The well is located in the same Qawasim play trend as the South Khilala field but did not encounter commercial hydrocarbons, possibly due to a cross fault lateral seal failure.
In line with the terms of the Concession agreement, Melrose relinquished 25 percent of the Mansoura Concession area on the 25 June 2009. The relinquishment area was selected using Melrose's extensive 3D seismic and well data base and it has limited further prospectivity.
South East Mansoura Concession
In late 2008, Melrose completed a significant seismic acquisition programme in the South East Mansoura Concession. Approximately 925 square kilometres of 3D seismic data was acquired over the north western part of the Concession and 712 kilometres of 2D seismic data over the central and the eastern parts of the Concession. The processing and interpretation of this survey was completed during 2009 and Melrose has drilled two exploration wells generated from the data in early 2010.
The South Damas-1 exploration well was drilled to test a prospect in the Sidi Salim formation close to the Damas field. The well encountered the top reservoir at a depth of 4,345 feet and penetrated 76 feet of net gas pay with good reservoir properties. The preliminary estimate of the discovered reserves is 30 Bcfe, which is in line with the pre-drill analysis. The discovery well has been completed and flow tested at 14 MMcfpd and is being tied-back for production to the existing Damas field facilities. It is expected to be on stream by August 2010 at an initial rate in excess of 12 MMcfepd. The capital cost, including the well completion and flow line, is estimated at $3.3 million giving an attractive unit development cost of 11 US cents per Mcf.
The Tall Rak-1 well was drilled to test a Sidi Salim prospect in trend with the Tamad oil field and other historical discoveries. The well location was picked to correspond to a low frequency seismic anomaly which, in certain circumstances, can indicate gas bearing sandstones. Unfortunately, however, the well encountered an unusually thick limestone formation in the reservoir interval with no indications of hydrocarbons.
Melrose relinquished 25 percent of the South East Mansoura Concession area on 25 January 2009 as required under the terms of the Concession agreement. The selection of the relinquishment area was based on the available seismic and well data, coupled with a local geographic survey, and it had low prospectivity and/or poor inaccessibility due to urbanisation.
Mesaha Concession
The Mesaha Exploration Concession is located in Southern Egypt on the Sudanese border and covers a large area of approximately 57,000 square kilometres. Melrose was awarded the block in October 2007 and holds a 40 percent operated interest. The award was for a four year initial exploration term with a 2D seismic survey and one well commitment.
During 2009, Melrose acquired a 1,600 kilometre ground gravity survey over the Concession to correlate to the aeromagnetic surveys which had historically been acquired over the area. Both sets of data indicated the potential existence of an unexplored sedimentary basin on the western side of the block and Melrose is in the process of acquiring a 2D seismic survey over the area of greatest interest.
To date, some 575 kilometres of seismic have been acquired and the preliminary processing and interpretation indicates the presence of a strong shallow seismic reflector, with some deeper reflectors that will require further processing to improve the image in order to define a possible basin. Meanwhile, the survey will continue to the north-west of the Concession.
BULGARIA
In 2007 Melrose made the strategic decision to refocus its exploration activities offshore Bulgaria on shallower water prospects along the same geologic trend as the existing Melrose operated Galata gas field. In addition, following extensive feasibility studies, a strategy was formulated to convert the Galata gas field into a gas storage facility to leverage the offshore and onshore infrastructure value.
Since these decisions were taken, the Company has had some considerable exploration and appraisal success in Bulgaria and is currently pursuing the development of two recent offshore gas discoveries, Kavarna and Kaliakra, over the Galata platform. Progress is also being made with the Bulgarian government with discussions aimed at initiating the Galata gas storage scheme.
Development
The Kaliakra gas field was discovered in late 2007, approximately 15 kilometres east of the Galata field. Whilst the discovery well results appeared very positive it was not possible to accurately determine the field's reserves from the well data and the Company published a reserves estimate with a wide range of 7 Bcf to 47 Bcf. In order to resolve the technical uncertainties the Kaliakra No.2 appraisal well was drilled in August 2009 and this successfully encountered 67 feet of net gas pay which was substantially thicker than the 31 feet found in the original discovery well. The open hole logs and gas samples confirmed that the reservoir has excellent properties and the booked reserves for the field have increased from 16 Bcf to 49 Bcf at year end 2009.
The Kaliakra No.2 results also had a positive impact on the Kavarna field, which was discovered in 2008 and is situated in between Kaliakra and the Galata platform. The booked reserves for Kavarna have been increased from 20 Bcf to 25 Bcf.
Following the successful drilling programme, the Bulgarian Government issued a Certificate of Commerciality for the Kavarna gas field and the Company has submitted an application for a similar Certificate of Commerciality for the Kaliakra field which is expected to be issued at the end of the first quarter 2010.
The Company now intends to develop both the Kavarna and Kaliakra fields during 2010 using a single subsea well completion for each field tied back to the Galata facilities. Kavarna will require an 8 kilometre 6 inch flow line and is expected to be on stream by early July 2010 and Kaliakra will be developed using a dedicated 10 inch flow line to allow for future expansion. First gas is expected from this field by early October 2010. The combined flow rate from the two fields is expected to be 45 MMcfpd.
The two field flow lines will be laid by Grup Servicii Petroliere, a Black Sea based drilling and oil field services company, using the Bigfoot lay barge and the same company will be responsible for the subsea completion activity. The total capital expenditure for the two developments is expected to be $59 million (including historical well completion costs) equating to a very attractive unit development cost of $0.73/Mcf.
To help part finance the developments, Melrose has signed a letter of intent with a Bulgarian gas trading entity, under which the Company will sell 4.24 Bcf of gas from the Kavarna field during the first year of the development. A proportion of the gas will be purchased in advance, with a cash payment of $10.2 million due prior to first production, and the remaining volume will attract the Published State price less adjustments. The Company expects to achieve an average gas sales price well in excess of $6.50 per Mcf for the first year of production from the field, assuming that the Brent oil price averages over $70 per bbl in the near term.
Exploration
The success of these two discoveries has confirmed the prospectivity of the Galata / Kaliakra geologic trend and two other prospects represent good short term drilling candidates, namely Kavarna East and Kaliakra East. The first of these prospects has unrisked reserves of 12 Bcf and a very high chance of success of 80 percent and the second, unrisked reserves of 59 Bcf and a chance of success of 34 percent. One of the two prospects is scheduled to be drilled in the summer of 2010 when a rig is on location to complete the Kaliakra development well and the final well selection will be based on operational considerations.
The Galata block may also be prospective further to the north of the existing discoveries since they appear to be full to spill and the gas that has charged the structures may also have migrated in this direction. Additional seismic surveys are being planned to evaluate this area of the block.
Galata gas storage
In 2008, Melrose concluded a feasibility study which evaluated the suitability of converting the depleting Galata field into a gas storage facility. The study concluded that the field was suitable for conversion to a low cost storage scheme and would benefit from being already linked to the main Bulgarian gas transmission lines and could potentially be integrated with planned regional gas infrastructure development such as the South Stream pipeline project which may cross the Black Sea from Russia.
The strategic rationale for the storage facility remains strong since Bulgaria is dependent on Russian gas imports and only has one existing storage facility, at the Chiren field, which is insufficient to guarantee security of supply. This was demonstrated in early 2009 when gas imports ceased during an international commercial dispute causing major disruption to district heating plants and the local chemical and steel industries.
In preparation for the storage project, the Galata field was shut-in on 31 January 2009 and some low cost modifications were made including onshore and offshore pipe work bypasses and metering reconfiguration. Some 9.2 Bcf of gas has been left in the field to act as cushion gas.
The works completed to date would allow the Company to store approximately 0.3 Bcm of gas in the field. To expand the capacity further to 0.7 Bcm and then to 1.2 Bcm and potentially to 1.8 Bcm three main phases of capital investment are envisaged over the next few years, each costing approximately $30 million. Before, commencing the project, however, Melrose needs to receive approvals from the relevant Government agencies and discussions in this regard are ongoing.
ROMANIA
In keeping with its strategy to build a sustainable business presence in the Western Black Sea, in March 2009 Melrose entered into a Farm-in Agreement with Sterling Resources Ltd ("Sterling") under which it would acquire a 32.5% interest in the Pelican XIII and Midia XV Blocks (the "Blocks") offshore Romania. The Blocks contain the undeveloped Ana and Doina gas fields and significant exploration potential.
Following the farm-in agreement, Melrose has reprocessed and interpreted the close-spaced 2D seismic data which were acquired over the Ana and Doina trend in 2008 and re-analysed the available well data. This work has supported an upgrade to the fields' potential and the gross probable resources have been independently audited at a combined figure of 345 Bcf, as compared to Melrose's previous figure of 288 Bcf. Of this revised figure, 247 Bcf is attributed to the Ana field and 98 Bcf to Doina. The new combined estimate corresponds on a net basis to 18.7 MMboe and this volume has not yet been included in the Company's probable reserves bookings.
Under the terms of the Farm-in Agreement and consistent with the Company's strategy, Melrose will assume operatorship of the two gas field developments. Depending on the exact timing of the equity assignment, these are expected to be sanctioned for development by the end of 2010 with first gas planned late 2012. The production rate is expected to plateau at around 110 MMcfpd for the first 3 years of production. The field development plans include the installation of two minimum facilities offshore platforms which will be connected to an onshore processing plant via a 110 kilometre 20 inch subsea export pipeline. The facilities cost is estimated to be $402 million.
Melrose will also assume operatorship of the two exploration Blocks at the end of 2011, approximately two years before the end of the licence term in November 2013. The Blocks are relatively under-explored and contain a number of prospects and leads with significant exploration potential. The prospects and leads are contained in four main exploration plays and a number of them will require additional seismic data before they can be matured for drilling.
Three of the prospects are, however, sufficiently well defined to represent firm, short term drilling candidates. On Midia these include a gas prospect in the Pliocene formation on the same trend as the Ana and Doina fields called Clara and a Miocene gas prospect called Ioana. On Pelican there is an attractive Eocene and Lower Cretaceous oil prospect, Eugenia South, which contains gross unrisked reserves of 45 MMbbl is adjacent to an existing oil discovery called Olympiskiyi. Eugenia South is included in the 2010 drilling programme.
In October 2009, the Company received approval from the Romanian National Agency of Mineral Resources to conduct petroleum operations in the country under new administrative guidelines. The formal completion of the Farm-in Agreement remains contingent on the approval of the new Romanian Government which came into power in December 2009. The Company is cautiously optimistic that this will be forthcoming within the next month or two and on this basis has prepared the various engineering studies and plans required to initiate the developments.
The Romanian farm-in is of strategic importance to the Company since it will add significant value and create a new core area with economic upside which may be realised from the exploration portfolio and the new development infrastructure.
USA
Melrose owns and operates two primary sets of assets in the USA, namely, a number of mature oil fields in the Permian Basin in West Texas and East New Mexico and gas fields in East Texas close to Houston. The Permian Basin oil fields are relatively mature and cover three main lease areas called Jalmat, Turner-Gregory and Artesia. These fields hold significant reserves and have a long projected field life with further infill drilling, waterflood and tertiary recovery potential. The East Texas assets consist of a number of small gas fields, with peripheral exploration potential, and a more modest reserves base.
Permian Basin
During 2009 Melrose continued with the implementation of its infill drilling and waterflood plans in the Permian Basin, where new water injection facilities and flowlines are being installed in tandem with a drilling and well work-over programme.
The investment programme represents a long term multi-year initiative under which each of the three main field areas will be converted to a 20 acre well spacing pattern waterflood. Assuming the programme is fully completed the oil production rate is expected to increase from its current level of 600 bopd to approach 1,500 bopd. At year end 2009, Melrose's net proved reserves in the Permian Basin were 23.3 MMboe with a further 15.9 MMboe categorised as possible reserves.
Jalmat field
During the year, the primary focus of the development activity was on the Jalmat/Cone field in Lea County, New Mexico. One new well was drilled and 42 oil production wells were converted mostly from oil production to water injection. The field is now covered by a "5 spot" well pattern drilled at a 20 acre well spacing and there are a total of 121 producers and 75 injectors.
The water injection rate was increased from 4,000 bwpd to 7,000 bwpd during the course of the year and further increases are planned contingent on regulatory approvals. The field oil production rate during 2009 averaged 352 bopd, slightly lower than 2008 due to the water injection well conversions, and should start to respond to the water injection programme later this year. The total 2009 investment was $9.4 million.
Turner-Gregory field
The focus for activity in 2010 will be the Turner-Gregory field which is located in Mitchell County, Texas. The waterflood development plan for this field differs from that in Jalmat in that it requires a "line drive" well pattern as opposed to a "5 spot" pattern in order to maximise oil recoveries. In 2009 "line drives" were installed across the central area of the field and this year twelve water injection well and nine production well completions are planned to commence the injection programme at a capital cost of approximately $3.5 million. The well patterns and injection programmes will be extended to the north and south of the field in later years, contingent on the performance of the initial scheme.
Artesia field
The Artesia field is located next to the Jalmat field in eastern New Mexico. The facilities have been upgraded over the course of 2008 and 2009 and new injection plant has been installed. The field currently has 152 active producing wells and 36 active injectors and no further infill drilling or waterflood activity is planned before 2011 at the earliest.
Technical Study Plans
Given the importance of the Permian Basin reserves, the Company has commissioned an independent consultant who specialises in Permian Basin assets to perform a major technical study aimed at defining the ultimate reserves potential for each of the main field areas. This study will cover not only the infill drilling and waterflood potential but will also address the tertiary recovery potential in Jalmat. This field is thought to be a good candidate for the application of a tertiary recovery scheme involving the injection of CO2 into the reservoir and the field is located only 20 kilometres from a local CO2 distribution line.
East Texas
Melrose also holds interests in a number of gas properties in East Texas, near Houston. The principal fields are the North Raywood and Rankin fields located in Harris and Liberty Counties, respectively. In total there are currently eight wells on production which produced 2.5 MMcfpd of gas and 28 bpd of liquids during 2009 and the proved plus probable reserves are estimated at 2.4 MMboe.
Melrose owns proprietary 3D seismic data over many of the leases in East Texas and these indicate that the area has reserves upside potential through the drilling of appraisal wells near to the existing producing field areas and exploration wells in deeper reservoir horizons.
The Nunan-1 exploration well was drilled in early 2009 to test the deep Reklaw formation and the well encountered a significant gas column with a gas in place estimate of around 73 Bcf. However, the reservoir pay section comprised a very low permeability sequence of thinly layered sandstones and siltstones. The well was completed and a fracture stimulation treatment was performed on the well to enhance the flow rate. Two long term production tests have subsequently been conducted which produced at sustained rates of 0.3 MMcfpd with 10 bpd of oil and condensate. These rates are considered to be sub-economic and independent specialist consultants have been commissioned to analyse the well results with a view to developing a completion design for future wells which may prove commercial. This is likely to involve the use of horizontal drilling and multiple fracture technology.
Other interests
Melrose also has a number of other minor oil and gas interests in Texas which include operated gas production in the Fort Worth Basin, a minor overriding royalty interest in the Barnett Shale underlying certain areas of the Fort Worth Basin and a small working interest in the offshore block Main Pass 139. Average daily production from these fields in 2009 totalled 0.4 MMcfpd of gas. There were no capital expenditures on these properties in 2009.
TURKEY
Melrose holds a 66.67% working 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 have not been extensively explored although the results of two old wells drilled in the area indicated the presence of potential source rocks and reservoirs within the Palaeozoic sequence. There is also existing regional 2D seismic data available which indicates the presence of potentially large structural closures. Furthermore, an oil discovery has recently been made on a neighbouring block, some 40 kilometres to the north-east of the Melrose Concessions, which has the same source rock and reservoir system which the Company is targeting on the Concessions.
Melrose is currently acquiring its first 2D seismic survey on the Concessions and this survey, which comprises 250 kilometres of data, should complete in May 2010. The survey will cover an area containing a large structural exploration lead called Kanun defined on the regional seismic data. Following the processing and interpretation of the data, the Company will either select a well location to be drilled in 2011 or conduct another phase of seismic acquisition over other structural leads in the area.
FRANCE
Melrose has a 100% 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 Concession covering an area of 12,500 square kilometres and has a minimal work programme. The initial term of the licence is due to expire in November 2010 and the Company is in discussion with the French Government regarding the possibility of a licence extension.
FINANCIAL REVIEW
Results for the year
Revenue for the year was $224.4 million which compares with revenue of $373.3 million in 2008. The reduction was due to reduced commodity prices partly offset by increased production in Egypt. Turnover derived from Egypt was $204.2 million (2008: $290.8 million), Bulgaria $1.7 million (2008: $39.6 million) and the USA $18.5 million (2008: $42.9 million).
Profit before tax amounted to $30.9 million (2008: $143.3 million). Loss after tax amounted to $23.9 million (2008: profit of $68.3 million).
A dividend of 3.1 pence per share is being proposed (2008: 2.8 pence per share total dividend). If approved, the estimated total dividend of $5.3 million (2008: $4.8 million) will be deducted from retained reserves.
EBITDAX for the year of $177.9 million compares with $330.3 million for the previous year. The reconciliation of EBITDAX to the IFRS measure of profit before taxation is presented below:
| EBITDAX | 2009 | 2008 |
|
| $000 | $000 |
| Profit before taxation | 30,942 | 143,278 |
| Add back: |
|
|
| Depreciation | 486 | 750 |
| Depletion and depreciation | 105,467 | 112,325 |
| Decommissioning charge | 5,967 | 1,713 |
| Unsuccessful exploration costs | 5,637 | 32,711 |
| Impairment to goodwill | 5,185 | 8,012 |
| Net financing cost | 24,175 | 31,534 |
| EBITDAX | 177,859 | 330,323 |
Ceiling test write-down and impairment of goodwill
The Company has reviewed the exploration potential in the Qantara concession in the Nile Delta and is of the opinion that no further exploration drilling will be undertaken. This has resulted in a impairment of $5.1 million (included within depletion). Following the lower gas prices realised in the US a review of the carrying value of the acquired East Texas assets and associated goodwill has been undertaken. This has resulted in a write-off of the remaining goodwill on acquisition at a charge of $5.2 million and a further impairment of $1.0 million (included within depletion).
Taxation
The tax charge for the year was $54.8 million (2008: $75.0 million), representing 177% of profit before tax (2008: 52%). The effective tax rate in 2009 is unusually high due to derecognition of the deferred tax assets previously recognised in Egypt. In addition, the Group tax charge is adversely impacted by the non-deductibility for tax purposes of financing costs and administrative expenses in Egypt. Similarly, administrative costs in the UK (net of intra-group management fees) are not deductible for tax purposes against other Group income. It is noted that only $2.0 million of the 2009 tax charge is payable in cash (2008: $5.8 million).
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 2009 was $4.04 per boe (2008: $3.38). The table below summarises the key indicators which reflects this strategy:
|
| Bulgaria | Egypt | USA | Group | |||||
|
| 2009 $ | 2008 $ | 2009 $ | 2008 $ | 2009 $ | 2008 $ | 2009 $ | 2008 $ | |
|
|
|
|
|
|
|
|
|
| |
| Prices received |
|
|
|
|
|
|
|
| |
| Oil/condensate (bbl) | - | - | 58.51 | 97.55 | 55.37 | 93.21 | 58.05 | 96.88 | |
| Gas (Mcf) | 5.66 | 5.35 | 2.82 | 2.71 | 4.37 | 9.13 | 2.92 | 3.74 | |
|
|
|
|
|
|
|
|
|
| |
| Per boe |
|
|
|
|
|
|
|
| |
| Revenue | 33.98 | 32.10 | 26.81 | 40.74 | 41.51 | 73.28 | 27.93 | 41.89 | |
| Royalties & production taxes | (2.40) | (1.08) | - | (0.20) | (2.91) | (5.16) | (0.22) | (0.73) | |
| Operating costs | (42.89) | (2.43) | (2.07) | (1.61) | (22.34) | (20.37) | (4.08) | (3.38) | |
| Net cashflow | (11.31) | 28.59 | 24.74 | 38.93 | 16.26 | 47.75 | 23.63 | 37.78 | |
| Depletion | (20.86) | (9.36) | (15.59) | (14.12) | (21.04) | (28.13) | (16.03) | (14.43) | |
| Abandonment | - | - | (0.64) | (0.04) | (5.20) | (2.70) | (0.96) | (0.25) | |
| Net profit | (32.17) | 19.23 | 8.51 | 24.77 | (9.98) | 16.92 | 6.64 | 23.10 | |
Additions to the oil and gas assets of the Group during the year totalled $161.1 million (2008: $212.8 million). This was split, geographically, $21.9 million (2008: $28.2 million) in respect of properties in Bulgaria, $118.4 million (2008: $137.0 million) in Egypt, $19.4 million (2008: $46.3 million) in the USA, $1.4 million (2008: $1.3 million) in Turkey and France.
Financial assets
The Group holds no financial assets at 31 December 2009 (2008: nil).
Financial instruments
The Group's use of financial instruments is mainly restricted to borrowings, cash deposits, short-term deposits and various items such as trade debtors 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 2009.
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 2009, the Company had two interest rate cash hedges in place, both of which expire in February 2011. All realised gains and losses are taken to the Consolidated Income. Unrealised movements to fair value are reflected through the Statement of other comprehensive income. Full disclosure is provided in note 17 to the accounts. There were no hedging transactions in place at 31 December 2008. Total Group interest charged, including the settlement of interest rate hedging rates in 2009 was $24.2 million (2008: $26.8 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 the majority of its revenue and expenditure is denominated in US Dollars. 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 US Dollars as cash flows from the development projects are denominated in 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. However, 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.
Loan facilities
In September 2009, the Group increased its long-term senior loan facilities from $440 million to $450 million. As at 31 December 2009, the loan facilities remain in place with a final repayment date of 2014. In addition, subordinated facilities of $70 million remain in place with a final repayment date of 2014. The Group is currently reviewing the funding requirements arising from the Romanian Farm-in and will either extend existing facilities or restructure funding to accommodate the new project.
At 31 December 2009, the Group had cash balances of approximately $6.5 million and bank loans totalling $491.1 million. Available borrowing capacity under bank loans totalled $23.2 million.
Equity financing
In July 2009 the Company completed an equity placing of 4,485,365 ordinary shares issued at a price of 250p per share, which raised £11.2 million before expenses.
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
23 March 2010
CONSOLIDATED INCOME STATEMENT
for the year ended 31 December 2009
|
| Year ended 31.12.09 | Year ended 31.12.08 | ||
|
|
| $000 |
| $000 |
| Revenue |
| 224,398 |
| 373,349 |
|
|
|
|
|
|
| Depletion and depreciation |
| (105,467) |
| (112,325) |
| Decommissioning charge |
| (5,967) |
| (1,713) |
| Unsuccessful exploration costs |
| (5,637) |
| (32,711) |
| Impairment of goodwill |
| (5,185) |
| (8,012) |
| Other cost of sales |
| (26,642) |
| (27,803) |
| Total cost of sales |
| (148,898) |
| (182,564) |
| Gross profit |
| 75,500 |
| 190,785 |
| Administrative expenses |
| (20,383) |
| (15,973) |
| Profit from operations |
| 55,117 |
| 174,812 |
| Financing income |
| 73 |
| 925 |
| Financing costs |
| (24,248) |
| (32,459) |
| Profit before tax |
| 30,942 |
| 143,278 |
| Income tax expense |
| (54,828) |
| (74,974) |
| (Loss)/profit for the year |
| (23,886) |
| 68,304 |
|
(Loss)/earnings per share (cents) |
|
|
|
|
| Basic |
| (21.3) |
| 62.1 |
| Diluted |
| (21.3) |
| 61.8 |
The (loss)/profit for the year is 100% attributable to equity shareholders of the parent company.
Note: All operations were continuing operations.
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
for the year ended 31 December 2009
|
|
| Year ended 31.12.09 | Year ended 31.12.08 | ||
|
|
|
| $000 |
| $000 |
| (Loss)/profit for the year |
|
| (23,886) |
| 68,304 |
| Changes in fair value of cash flow hedges |
|
| (2,158) |
| - |
| Income tax on other comprehensive income |
|
| - |
| - |
| Total other comprehensive loss |
|
| (2,158) |
| - |
| Total comprehensive (loss)/income for the year |
|
| (26,044) |
| 68,304 |
No income tax arises on the change in fair value of cash flow hedges since these losses are recorded in the Company, which has significant tax losses carried forward. It is not considered probable that future taxable profits would be available in the Company against which a deferred tax asset could be recovered
CONSOLIDATED BALANCE SHEET
as at 31 December 2009
|
| At 31.12.09 | At 31.12.08 | ||
|
| $000 | $000 | ||
| Non-current assets |
|
| ||
| Goodwill |
| 52,976 |
| 58,161 |
| Intangible assets |
| 87,476 |
| 83,251 |
| Property, plant and equipment |
| 621,849 |
| 576,681 |
| Deferred tax asset |
| 2,414 |
| 17,620 |
|
|
| 764,715 |
| 735,713 |
| Current assets |
|
|
|
|
| Inventories |
| 32,495 |
| 33,255 |
| Trade and other receivables |
| 133,664 |
| 119,206 |
| Cash and cash equivalents |
| 6,467 |
| 14,990 |
|
|
| 172,626 |
| 167,451 |
| Total assets |
| 937,341 |
| 903,164 |
| Current liabilities |
|
|
|
|
| Trade and other payables |
| (62,284) |
| (48,624) |
| Provisions |
| (783) |
| (1,437) |
|
|
| (63,067) |
| (50,061) |
| Non-current liabilities |
|
|
|
|
| Other payables |
| (180) |
| - |
| Bank loans |
| (480,722) |
| (440,905) |
| Deferred tax liability |
| (45,004) |
| (58,642) |
| Provisions |
| (19,295) |
| (14,561) |
|
|
| (545,201) |
| (514,108) |
| Total liabilities |
| (608,268) |
| (564,169) |
| Net assets |
| 329,073 |
| 338,995 |
| Equity attributable to shareholders of the parent |
|
|
|
|
| Issued capital |
| 20,699 |
| 19,946 |
| Share premium |
| 209,225 |
| 192,087 |
| Special reserve |
| - |
| 31,244 |
| Hedging reserve |
| (2,158) |
| - |
| Retained earnings |
| 101,307 |
| 95,718 |
| Total Equity |
| 329,073 |
| 338,995 |
The Board of Directors approved the financial statements on 23 March 2010.
R F M Adair Director
D M V Fraser Director
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
for the year ended 31 December 2009
Attributable to Owners of the Company
|
| Share capital $000 | Share premium $000 | Special reserve $000 | Hedging reserve $000 | Retained earnings $000 | Total equity $000 |
| At 1 January 2009 | 19,946 | 192,087 | 31,244 | - | 95,718 | 338,995 |
| Loss for the year | - | - | - | - | (23,886) | (23,886) |
| Change in fair value of cash flow hedges |
- |
- |
- |
(2,158) |
- |
(2,158) |
| Share issues | 738 | 17,718 | - | - | - | 18,456 |
| Share issue costs | - | (580) | - | - | - | (580) |
| Share options exercised | 15 | - | - | - | - | 15 |
| Dividends to equity shareholders |
- |
- |
- |
- |
(2,884) |
(2,884) |
| Equity settled transactions | - | - | - | - | 1,343 | 1,343 |
| Investment in own shares | - | - | - | - | (228) | (228) |
| Transfer from special reserve to retained earnings |
- |
- |
(31,244) |
- |
31,244 |
- |
| At 31 December 2009 | 20,699 | 209,225 | - | (2,158) | 101,307 | 329,073 |
| Balance at 1 January 2008 | 19,925 | 191,945 | 61,244 | - | 7,582 | 280,696 |
| Profit for the year | - | - | - | - | 68,304 | 68,304 |
| Share issues | 21 | 142 | - | - | - | 163 |
| Dividends to equity shareholders | - | - | - | - | (6,873) | (6,873) |
| Equity settled transactions | - | - | - | - | (1,746) | (1,746) |
| Investment in own shares | - | - | - | - | (1,549) | (1,549) |
| Transfer from special reserve to retained earnings |
- |
- |
(30,000) |
- |
30,000 |
- |
| At 31 December 2008 | 19,946 | 192,087 | 31,244 | - | 95,718 | 338,995 |
CONSOLIDATED CASH FLOW STATEMENT
for the year ended 31 December 2009
|
| Year ended 31.12.09 $000 | Year ended 31.12.08 $000 | ||
| Cash flow from operating activities |
|
|
|
|
| Profit from operations |
| 55,117 |
| 174,812 |
| Adjustments for: |
|
|
|
|
| Depreciation of other assets |
| 486 |
| 750 |
| Depletion, depreciation and decommissioning charge |
| 111,434 |
| 114,038 |
| Unsuccessful exploration costs |
| 5,637 |
| 32,711 |
| Impairment of goodwill |
| 5,185 |
| 8,012 |
| Excess cost of decommissioning |
| (2,209) |
| (4,178) |
| Non-cash expense/(release) relating to share-based payment |
| 1,456 |
| (1,465) |
| Income tax charge on Egyptian revenue |
| (51,219) |
| (88,244) |
| Operating cash flow before changes in working capital |
| 125,887 |
| 236,436 |
| Decrease in inventory |
| 760 |
| 624 |
| Increase in trade and other receivables |
| (12,952) |
| (60,979) |
| Decrease in trade and other payables |
| (481) |
| (7,744) |
| Cash generated from operations |
| 113,214 |
| 168,337 |
| Income taxes paid |
| (7,179) |
| (2,963) |
| Net cash inflow from operating activities |
| 106,035 |
| 165,374 |
| Cash flows from investing activities |
|
|
|
|
| Proceeds from sale of property, plant and equipment |
| - |
| 329 |
| Interest received |
| 73 |
| 710 |
| Acquisition of property, plant and equipment and intangible assets |
| (149,963) |
| (192,963) |
| Net cash outflow from investing activities |
| (149,890) |
| (191,924) |
| Cash flows from financing activities |
|
|
|
|
| Proceeds from the issue of share capital |
| 18,456 |
| - |
| Proceeds from issue of share options |
| 15 |
| 163 |
| Costs of issue |
| (580) |
| - |
| Purchase of own shares |
| (228) |
| (1,549) |
| Net inflow/(outflow) from share capital |
| 17,663 |
| (1,386) |
| Interest paid |
| (17,618) |
| (27,867) |
| Loan arrangement fees |
| (3,988) |
| (5,132) |
| Borrowings raised |
| 57,000 |
| 235,976 |
| Repayment of borrowings |
| (15,203) |
| (175,000) |
| Dividends paid |
| (2,884) |
| (6,873) |
| Net cash inflow from financing activities |
| 34,970 |
| 19,718 |
| Net decrease in cash and cash equivalents |
| (8,885) |
| (6,832) |
| Cash and cash equivalents at start of year |
| 14,990 |
| 22,676 |
| Effect of exchange rate fluctuation on cash held |
| 362 |
| (854) |
| Cash and cash equivalents at end of year |
| 6,467 |
| 14,990 |
SELECTED NOTES TO THE FINANCIAL INFORMATION
for the year ended 31 December 2009
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 2009.
The financial information set out in this announcement for the years ended 31 December 2009 and 2008 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 2008 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 2009 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 statements under section 237 (2) or (3) of the Companies Act 1985 in respect of the financial statements for 2008 nor a statement under section 498 (2) or (3) of the Companies Act 2006 in respect of the financial statements for 2009. This preliminary announcement was authorised by the Board on 23 March 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 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 2008, 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 2009.
The Group financial statements consolidate those of the Company and its subsidiaries. The parent company financial statements present, in addition, information about the Company as a separate entity. In publishing the parent company financial statements together with the Group financial statements, the Company has taken advantage of the exemption in Section 408(4) of the Companies Act 2006 not to present its individual income statement and related notes that form a part of these approved financial statements.
The financial statements were authorised for issue by the directors on 23 March 2010.
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 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 all 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 and also in note 28.
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 proportionate 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. This presentation has been applied in these consolidated financial statements as of and for the year ended 31 December 2009.
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.
Comparative information has been re-presented so that it is also in conformity with the revised standard. Since the change in accounting policy only impacts presentation aspects, there is no impact on earnings per share.
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 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 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
As of 1 January 2009 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. This change in accounting policy is due to the adoption of IFRS 8. Previously, operating segments were determined and presented in accordance with IAS 14, "Operating Segments".
Comparative segment information has been re-presented in conformity with the transitional arrangements of IFRS 8. Since the change in accounting policy only impacts presentation and disclosure aspects, there is no impact on earnings per share. As a result of the implementation of IFRS 8, there has been no change to the segments currently or previously reported by the Group.
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 statement of comprehensive income 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 statement of comprehensive income 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. Previously the Group recognised all borrowing costs as an expense. The change in accounting policy is in accordance with the prospective adoption of IAS 23 "Borrowing Costs". In accordance with the transitional provision of the standard, comparative figures have not been restated. The change in accounting policy had no material impact on assets, profit or earnings per share in the year ended 31 December 2009.
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 are mandatory for the first time for financial periods commencing on 1 January 2009 have been adopted. None of these have had a significant impact on the reported results.
·; ISA 23 (amendment) 'Borrowing costs';
·; IFRS 2 (amendment) 'Amendments to IFRS 2 share-based Payment - Vesting Conditions and cancellations';
·; IAS 1 (amended) IAS 1 Presentation on Financial Statements;
·; IAS 32 'Financial instruments: Presentation', IAS 39 'Financial instruments: Recognition and Measurement', and IFRS 7 (amended) 'Financial instruments: Disclosures'.
·; IFRS 8 "Operating Segments"
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 2009, and have not been applied in preparing these financial statements. Those which may have a significant effect on the financial statements are:
·; Revised IFRS 3 Business Combinations (2008), incorporates the following changes that may be relevant to the Group's operations:
- Contingent consideration will be measured at fair value, with subsequent changes therein recognised in profit or loss.
- Transaction costs, other than share and debt issue costs, will be expensed as incurred.
- Any non-controlling (minority) interest will be measured at either fair value, or at its proportionate interest in the identifiable assets and liabilities of the acquiree, on a transaction by transaction basis.
Revised IFRS 3, which becomes mandatory for the Group's 2010 consolidated financial statements, will be applied prospectively and there will be no impact on prior periods in the Group's 2010 consolidated financial statements.
·; Amended IAS 27 Consolidated and Separate Financial Statements (2008), requires accounting for changes in ownership interests by the Group in a subsidiary, while maintaining control, to be recognised as an equity transaction. When the Group loses control of a subsidiary, any interest retained in the former subsidiary will be measured at fair value with a gain or loss recognised in the statement of comprehensive income. The amendments to IAS 27, which become mandatory for the Group's 2010 consolidated financial statements, are not expected to have a significant impact on the consolidated financial statements.
·; IFRIC 17 Distributions of non-cash assets to owners effective for annual periods beginning on or after 1 November 2009. This is not currently applicable to the Group as it has not made any non-cash distributions.
·; IFRIC 18 Transfers of assets from customers is effective for transfers of assets received on or after 1 November 2009. This is not relevant to the Group, as it has not received any assets from customers.
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.
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.
| Operating segment | Bulgaria | Egypt | USA | Other Europe | Total | ||
|
|
| 2009 | 2009 |
| 2009 | 2009 | 2009 |
|
|
| $000 | $000 |
| $000 | $000 | $000 |
| Revenue |
| 1,741 | 204,219 |
| 18,438 | - | 224,398 |
| Depletion and depreciation | (1,069) | (94,035) |
| (10,363) | - | (105,467) | |
| Decommissioning charge | - | (3,658) |
| (2,309) | - | (5,967) | |
| Unsuccessful exploration costs | - | (5,637) |
| - | - | (5,637) | |
| Impairment of goodwill | - | - |
| (5,185) | - | (5,185) | |
| Other cost of sales | (2,320) | (11,812) |
| (12,510) | - | (26,642) | |
| Administrative expenses | (1,001) | (5,556) |
| (3,271) | (1,129) | (10,957) | |
| Segment result |
| (2,649) | 83,521 |
| (15,200) | (1,129) | 64,543 |
| Unallocated corporate expenses |
|
|
|
| (9,426) | ||
| Profit from operations |
|
|
|
|
|
| 55,117 |
| Financing income |
|
|
|
|
|
| 73 |
| Financing cost |
|
|
|
|
|
| (24,248) |
| Profit before income tax |
|
|
|
|
| 30,942 | |
| Income tax expense |
|
|
|
|
|
| (54,828) |
| Loss for the year |
|
|
|
|
| (23,886) | |
| Operating segment | Bulgaria | Egypt | USA | Other Europe | Total | ||
|
| 2008 | 2008 | 2008 | 2008 | 2008 | ||
|
| $000 | $000 | $000 | $000 | $000 | ||
| Revenue | 39,643 | 290,818 | 42,888 | - | 373,349 | ||
| Depletion and depreciation | (11,563) | (76,291) | (24,471) | - | (112,325) | ||
| Decommissioning charge | - | (184) | (1,529) | - | (1,713) | ||
| Unsuccessful exploration costs | (93) | (23,741) | (1,542) | (7,335) | (32,711) | ||
| Impairment of goodwill | - | (5,629) | (2,383) | - | (8,012) | ||
| Other cost of sales | (4,332) | (9,016) | (14,455) | - | (27,803) | ||
| Administrative expenses | (1,557) | (5,076) | (3,484) | - | (10,117) | ||
| Segment result | 22,098 | 170,881 | (4,976) | (7,335) | 180,668 | ||
| Unallocated corporate expenses |
|
|
| (5,856) | |||
| Profit from operations |
|
|
|
|
| 174,812 | |
| Financing income |
|
|
|
| 925 | ||
| Financing cost |
|
|
|
| (32,459) | ||
| Profit before income tax |
|
|
|
| 143,278 | ||
| Income tax expense |
|
|
|
| (74,974) | ||
| Profit for the year |
|
|
|
| 68,304 | ||
Other Europe comprises Turkey, France, and Romania.
| Revenue by product | Year ended 31.12.09 | Year ended 31.12.08 | ||||
|
| Gas $000 | Oil/liquids/ condensate $000 |
Total $000 | Gas $000 | Oil/liquids/ condensate $000 |
Total $000 |
| Bulgaria | 1,741 | - | 1,741 | 39,643 | - | 39,643 |
| Egypt | 97,552 | 106,667 | 204,219 | 80,759 | 210,059 | 290,818 |
| USA | 5,541 | 12,897 | 18,438 | 16,078 | 26,810 | 42,888 |
| Total | 104,834 | 119,564 | 224,398 | 136,480 | 236,869 | 373,349 |
The Group has one customer who accounted for more than 10% of revenue in both 2008 and 2009. All sales in Egypt in 2008 and 2009 are to a state owned company. The revenue derived from sales to this customer is set out in the table above.
|
As at 31 December 2009 |
Bulgaria $000 |
Egypt $000 |
USA $000 |
Other Europe $000 | Unallocated corporate balances $000 |
Total $000 | ||
| Total segment assets | 96,298 | 690,398 | 144,293 | 1,843 | 4,509 | 937,341 | ||
| Total segment liabilities | (152,552) | (90,290) | (202,056) | (4) | (163,366) | (608,268) | ||
| As at 31 December 2008 | Bulgaria $000 | Egypt $000 | USA $000 | Other Europe $000 | Unallocated corporate balances $000 | Total $000 | ||
| Total segment assets | 87,640 | 675,360 | 136,516 | 290 | 3,358 | 903,164 | ||
| Total segment liabilities | (160,959) | (74,448) | (215,767) | - | (112,995) | (564,169) | ||
3. Net financing income/(cost)
|
| 2009 $000 |
| 2008 $000 |
| Bank interest receivable | 73 |
| 710 |
| Exchange gains | - |
| 215 |
| Total financing income | 73 |
| 925 |
|
|
|
|
|
| Bank interest payable | (20,194) |
| (26,770) |
| Other financing charges | (741) |
| (2,846) |
| Amortisation of loan fees | (2,008) |
| (1,797) |
| Unwinding of discount on decommissioning provision | (510) |
| (456) |
| Exchange losses | (795) |
| (590) |
| Total financing cost | (24,248) |
| (32,459) |
|
|
|
|
|
| Net financing cost | (24,175) |
| (31,534) |
4. Income tax expense
Recognised in the income statement
|
| 2009 $000 |
| 2008 $000 |
| Current tax expense: |
|
|
|
| Current year | 51,404 |
| 94,037 |
| Adjustments for prior years - current tax | 1,857 |
| (969) |
| Deferred tax expense: |
|
|
|
| Origination and reversal of temporary differences | (13,930) |
| (10,765) |
| Benefit of tax losses recognised | - |
| (7,329) |
| Adjustments for prior years - deferred tax | 15,497 |
| - |
| Total tax charge in income statement |
|
|
|
|
| 54,828 |
| 74,974 |
In prior years, a deferred tax asset in relation to Egyptian taxes had been recognised in respect of temporary timing differences arising from the treatment of unsuccessful exploration activity. Following re-assessment of the amounts the directors have concluded that, in accordance with the related concession arrangements, these impairments do not result in taxable temporary differences. Accordingly, the deferred tax asset, which at 31 December 2008 amounted to $15,497,000 (31 December 2007: $9,525,000), has no longer been recognised. The directors have concluded that the adjustment is insufficiently large to warrant adjustment in prior periods and have included the write off of $15,497,000 in the tax expense in the current period.
Reconciliation of effective tax rate
|
| 2009 $000 |
| 2008 $000 |
| Profit before tax | 30,942 |
| 143,278 |
| Tax using the UK corporation tax rate of 28% (2008: 28%) | 8,663 |
| 40,118 |
| Non-deductible expenses | 14,469 |
| 11,185 |
| Effect of tax rate in foreign jurisdictions | 15,095 |
| 20,958 |
| Deferred tax not recognised in relation to tax losses | 6,854 |
| 4,821 |
| Under/(over) provided in prior years - current tax | 1,857 |
| (969) |
| Over provided in prior years - deferred tax | 15,497 |
| - |
| Reversal of deferred tax on fair value | (7,607) |
| (6,478) |
| Other | - |
| 5,339 |
| Total tax charge in income statement | 54,828 |
| 74,974 |
There is no deferred tax recognised directly in equity.
5. (Loss)/earnings per share
The calculation of the basic and diluted earnings per share is based upon the following data:
|
| Year ended 31.12.09 $000 |
| Year ended 31.12.08 $000 |
| (Loss)/profit for the year attributable to ordinary shareholders | (23,886) |
| 68,304 |
| Basic (loss)/earnings per share (cents) | (21.3) |
| 62.1 |
| Diluted (loss)/earnings per share (cents) | (21.3) |
| 61.8 |
The weighted average number of ordinary shares used in the calculation of basic and diluted earnings per share for each year was calculated as follows:
|
| Year ended 31.12.09 No. of shares |
| Year ended 31.12.08 No. of shares |
| Issued ordinary shares at start of year | 110,086,888 |
| 109,972,891 |
| Shares issued during the year | 4,581,175 |
| 113,997 |
| Shares in issue at end of year | 114,668,063 |
| 110,086,888 |
| Weighted average number of ordinary shares at end of year | 112,151,102 |
| 110,034,937 |
| Effect of share options | - |
| 486,684 |
| Weighted average number of ordinary shares at end of year - for diluted earnings per share | 112,151,102 |
| 110,521,621 |
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 approximates their fair value.
|
| Group |
| Company | ||||
|
| 2009 |
| 2008 |
| 2009 |
| 2008 |
|
| $000 |
| $000 |
| $000 |
| $000 |
| Bank balances | 6,367 |
| 14,890 |
| 3,120 |
| 2,147 |
| Bank deposits | 100 |
| 100 |
| - |
| - |
| Cash and cash equivalents | 6,467 |
| 14,990 |
| 3,120 |
| 2,147 |
7. Bank loans
This note provides information about the contractual terms of the Group and Company's interest-bearing loans and borrowings.
|
| Group |
| Company | ||||
|
| 2009 |
| 2008 |
| 2009 |
| 2008 |
|
| $000 |
| $000 |
| $000 |
| $000 |
| Current liabilities |
|
|
|
|
|
|
|
| Bank loans | - |
| - |
| - |
| - |
| Non-current liabilities |
|
|
|
|
|
|
|
| Bank loans | 480,722 |
| 440,905 |
| 148,234 |
| 106,738 |
|
| 480,722 |
| 440,905 |
| 148,234 |
| 106,738 |
All borrowings are denominated in US Dollars.
| Glossary | |
|
| |
| ABI | the Association of British Insurers |
| the Adair Trusts | certain trusts, the beneficiaries of which are R F M Adair and members of his immediate family |
| bbl | barrel of oil, condensate or natural gas liquids |
| Bcf | billion cubic feet of gas |
| Bcfe | billion cubic feet of gas equivalent |
| bcpd | barrel of condensate per day |
| the Board | the Board of directors of the Company |
| boe | barrel of oil equivalent |
| boepd | barrel of oil equivalent per day |
| BOP | blow-out preventer |
| bopd | barrel of oil, condensate or natural gas liquids per day |
| bpd | barrels per day |
| bwpd | barrels water per day |
| the Combined Code | the Principles of Good Governance and Code of Best Practice as appended to the Listing Rules of the Financial Services Authority |
| the Company | Melrose Resources plc |
| EBITDAX | earnings before interest, taxation, depletion, depreciation and amortisation |
| GIIP | gas initially in place |
| the Group | the Company and its subsidiaries |
| IRR | internal rate of return |
| LPG | liquid petroleum Gas |
| Mbbl | thousand barrels of oil, condensate or natural gas liquids |
| IFRS | International Financial Reporting Standard(s) |
| Mboe | thousand barrels of oil equivalent |
| Mcf | thousand cubic feet of gas |
| Mcfe | thousand cubic feet of gas equivalent |
| Mcfpd | thousand cubic feet of gas per day |
| Melrose | the Company or the Group, as appropriate |
| Merlon | Merlon Petroleum Company |
| MMbbl | million barrels of oil, condensate or natural gas liquids |
| MMboe | million barrels of oil equivalent |
| MMcf | million cubic feet of gas |
| MMcfe | million cubic feet of gas equivalent |
| MMcfpd | million cubic feet of gas per day |
| MMcfepd | million cubic feet of gas equivalent per day |
| NPV10 | net present value discounted at 10% per annum |
| PDP | proved developed producing |
| Petreco | Melrose Resources S.à r.l. and/or Petreco Bulgaria EOOD, (as appropriate) |
| psi | pounds per square inch |
| PSP | Performance Share Plan |
| PUD | proved undeveloped |
| STOIIP | stock tank oil initially in place |
| Tcf | trillion cubic feet of gas |
| Tcfe | trillion cubic feet equivalent |
| UKLA | United Kingdom Listing Authority |
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.