31 Aug 2010 07:00
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Afren Plc
2010 Half-yearly Results
Afren plc ("Afren" or the "Company") (LSE: AFR), the African independent oil and gas exploration and production Group, announces its half-yearly results for the six months ended 30 June 2010.
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• Ebok development progressing; Phase 1 drilling approaching final stages and facilities upgrade at an advanced stage.
• Ebok 8 water injection well has encountered an additional 100ft of oil pay in the LD1E sand.
• Acquisition of OML 115 in Nigeria, expanding the core Ebok/Okwok area.
• Strategic entry into East Africa, following the proposed acquisition of Black Marlin Energy Holdings Limited ("Black Marlin").
• Exploration drilling on Ebok deep establishes a working hydrocarbon system in the Biafra and Isonga reservoirs and confirms positive up dip potential on OML 115.
• Strong financial position, with net debt of US$12.2 million - gearing of 2%.
| Osman Shahenshah, Chief Executive of Afren plc, commented: "Afren has recorded strong financial results in the first half of 2010. The Ebok development is progressing with first phase drilling nearing completion and facilities upgrade at an advanced stage. We continued our inorganic portfolio expansion with the acquisition of OML 115 in Nigeria and have made a material strategic entry into East Africa with the proposed acquisition of Black Marlin, furthering our pan African ambitions. Our financial position is strong, underpinned by continued expected production and cashflow growth."
31 August 2010
Enquiries:
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Analyst Presentation
There will be a presentation to analysts at 9am BST in The Auditorium, Bank of America Merrill Lynch, 2 King Edward Street, London, EC1A 1HQ.
The presentation will also be broadcast live at www.afren.com where the accompanying presentation will be available, and on playback from 12:00 pm.
| Operations Review
In the first half of 2010 Afren continued to make good progress on the Ebok development offshore South East Nigeria. During the period, two strategic acquisitions were also announced. In Nigeria, the acquisition of an interest in OML 115 secured a position in acreage contiguous with the Ebok and Okwok fields, where substantial resource potential has been identified. The proposed acquisition of Black Marlin representing Afren's entry into East Africa, immediately establishes a complementary multi country platform that offers high impact growth opportunities, to leverage the Company's significant production growth. Production during the period was in line with expectations at 20,397 boepd (1H 2009: 22,964 boepd), reflecting natural reservoir depletion. Infill drilling at the Okoro field and production start up at Ebok will augment current production significantly during the second half of the year and beyond.
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| Nigeria | ||
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| 1H 2010 Production* | Reserves and Resources** | 1H 2010 Turnover |
| 17,841 bopd | 712 mmboe | US$197.1 mm |
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| * Gross production ** Net working interest; Independently certified net working interest reserves and resources at 30 June 2010, includes management estimates for Okwok and OPL 907/917 not yet independently certified
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Okoro Setu Project
A proven development and operating track record
Production at Okoro for the period averaged 17,841 bopd, consistent with our current field reservoir model. During Q4 2009 a change in the export process was implemented, whereby exports are now routed via the nearby Ima terminal. Increased storage capacity of over 1 mmbbls allows the lifting of increased parcel sizes which in turn has enhanced shipping and sales economics. As at 30 June 2010, a total of 48 export liftings had been successfully executed with the average parcel size increasing to 812,000 bbls in 2010 from 169,000 bbls in 2009, as a result of the Ima terminal utilisation. Total gross cumulative production from the field (since start-up) at 30 June 2010 was 11.4 mmbbls. During the period a process uptime of 99.6% was maintained, reflecting the excellent operational efficiency that has been achieved in the Company's maiden greenfield development project.
Continuing sub-surface and reservoir management work identified two attractive infill drilling locations that will access incremental reserves and production, utilising existing well slots available at the Okoro wellhead platform. It is intended that these wells will be drilled during Q4 2010 and will increase gross field production once completed. We continue to evaluate options that will potentially increase ultimate recovery of the oil reserves in the field area and nearby Setu field.
Ebok - Okwok - OML 115 area
Establishing a core production hub offshore South East Nigeria
Having secured participation in the Ebok field in 2008 and the Okwok field in 2009, the Company announced in January 2010 that it had farmed into the highly prospective surrounding OML 115 acreage and in July increased its interest further.
As a result, Afren now has a contiguous acreage position of 310 km2 (gross) in a prolific oil producing part of the Niger Delta, delivered material reserves growth through appraisal drilling and commenced development at Ebok with further exposure to Ebok-type potential at the Okwok field and OML 115.
Ebok Phase 1 development
All of the key elements in respect of the Ebok Phase 1 development, targeting the Central Fault Block area of the field, remain on schedule. By mid July all five D2 production wells and the water injection well had been drilled to intermediate depths as part of a batch drilling operation. Drilling operations in the field continue in readiness for hook up and commissioning upon arrival of the production facilities at the field location, with first oil expected in Q4 2010.
As part of the Phase 1 development, the Ebok-8 well was drilled as a water injection well but was also placed to serve both an appraisal and exploration purpose. The well encountered an additional 100 ft of oil pay in the LD1E sand, which was full to base and not predicted pre-drill. The exploration "tail" of the well was drilled to below D2 reservoir level, where it also encountered oil pay in additional reservoir intervals. The decision was also taken to core the well at the LD1A and D2 reservoir intervals to assist with future development work.
Facilities conversion and upgrade work for the project is at an advanced stage. The wellhead support structure (WSS) was successfully installed at the field in March. The Virini Prem Floating, Storage and Offloading Vessel (FSO), a 267 metre and 174,917 ton vessel, has been refurbished at the Yulian shipyard in China. The vessel will store and offload for export stabilised crude oil that will be produced and processed at a dedicated Mobile Offshore Production Unit (MOPU) at the field location. The Virini Prem has a storage capacity of 1.2 million barrels and will accommodate regular crude oil offtake by tankers up to VLCC size. Refurbishment work included steel replacement in certain sections of the hull, existing equipment on the vessel (such as export pumps), installation of a helideck and accommodation modules for up to 50 crew. The fiscal metering package successfully underwent acceptance testing to DPR approved standards. The successful execution of the upgrade work on the FSO is a major milestone for the Ebok project.
In readiness for the arrival of the FSO, all 12 mooring lines have been successfully pre-installed at the field location. Additionally, fabrication of all flowlines required to transfer produced crude oil from the MOPU to the FSO is complete, with the flowlines now stowed on the FSO for transport to the field.
The selected pre-existing MOPU will have an initial oil production capacity of 50,000 bopd, an initial water injection capacity of 25,000 bwpd and an initial gas lift/injection capacity of 9/6 mmcfd. Refurbishment and integration work on the MOPU, incorporating refurbishment to full American Bureau of Shipping (ABS) class requirements and the installation of production processing and accommodation modules, is nearing completion at the Gulf Copper yard in Galveston, Texas in readiness for mobilisation to Nigeria. The FSO and MOPU will be leased to the Ebok development at a day rate of US$98,092 for an initial seven year period, with an option to extend.
Ebok Phase 2 development
Development Phase 2 is focused on the West Fault Block area of the Ebok field, and was prioritised by the Company following materially better than expected results from the Ebok-5 appraisal well drilled in Q4 2009. Fabrication of a dedicated wellhead platform (WHP) is underway at the Upstream yard in Galveston, Texas. The West Fault Block will initially be developed via six development wells that will be tied back to the central Ebok MOPU and FSO facilities, and are expected to come onstream at an initial production rate of 20,000 bopd.
Four pilot holes have been drilled at the West Fault Block area of the field. This included one additional well into the LD1E reservoir, where the decision was also taken to obtain core samples. This initial phase of pilot drilling has also identified additional oil pay in the LD1F reservoir, which was logged and pressure data obtained.
Rig capacity
The Transocean Adriatic lX jack up drilling rig was contracted by Afren in August 2009 and remains under contract with the Company until January 2011 at a current day rate of US$94,762. The rig was used to drill the Ebok-4, Ebok-5, Ebok-6 and Ebok-8 appraisal wells and also the Phase 1 development drilling.
In March 2010, it was announced that Afren had secured a second jack up rig from Transocean to undertake planned drilling offshore South East Nigeria. The GSF High Island Vll drilling unit was contracted for an initial period of 210 days at a day rate of US$84,000, which has been extended for a further 90 days at a day rate of US$91,875 and remains under contract with the Company until January 2011. The rig was used to drill the Ebok Deep exploration well, and was subsequently relocated to the West Fault Block area of the field to initiate the early pilot hole drilling before spudding the Okwok-9 appraisal well in late August 2010.
Exploration and appraisal drilling
Ebok Deep
The Ebok Deep exploration well was drilled in Q2 2010 and intersected two sandstone intervals of 370 ft combined gross thickness in the targeted Biafra and Isonga formations, with oil shows providing positive indications of oil migration pointing to good potential for oil trapped up-dip from the well location. The well was temporarily abandoned and is available to use for further drilling in the area in the future. Importantly the well established a working hydrocarbon system and excellent quality sands at the deeper levels, the results of which have been incorporated into the subsurface model and will assist in future exploration of the significant potential that exists at Ebok, Okwok and OML 115.
Work undertaken at the Ebok field and data obtained from drilling results to date has allowed Afren to gain an advanced understanding of the regional geology offshore South East Nigeria and its hydrocarbon potential. This enabled the Company to recognise the significant potential that exists at both the Okwok field and OML 115 and subsequently acquire participating interests in each.
Okwok and OML 115
The greater Ebok/Okwok complex offers significant development synergies, providing scope for cost reduction and savings in the areas of joint storage and export operations and sharing of services (supply vessel, helicopter, drilling rig).
Okwok is a discovered but undeveloped oil field located approximately 15 km East of the Ebok development, where oil has been proved in the same 'D' series reservoirs as at Ebok with significant potential also identified in the deeper Qua Iboe, Biafra and Isonga formations. Based on the work undertaken on the Ebok field, Afren believes that the Okwok field has the potential to deliver significant reserves growth for fast track development.
Drilling of the Okwok-9 appraisal well commenced on 25 August 2010 using the GSF High Island Vll rig, and is expected to take 30 days to drill. The well has been optimally placed to confirm and define development requirements for the field, where its proximity to the Ebok central processing and storage facilities provides scope to leverage synergies and maximise cost efficiency of any future field development. The well will appraise the same 'D' series reservoirs on the eastern portion of the field that have already been established as oil bearing through previous drilling at Okwok, and are under development at the Ebok field. Afren management estimates STOIIP at the Okwok field of 225 mmbbls of which an estimated 70 mmbbls could be recoverable assuming a 32% recovery factor.
The OML 115 license surrounds the Okwok field and extends to within 2 km South of the Ebok development. Similarly, Afren sees the extension of the same 'D' series reservoir intervals that have successfully been proven at both Ebok and Okwok with further potential in the same corresponding deeper intervals. The planned exploration well on OML 115 will again target the 'D' series reservoirs in the Ufon prospect where nearby well control has indicated the presence of hydrocarbons in these sands. This well is expected be drilled in Q4 2010 and is targeting an estimated 60 mmbbls.
OPL 310
OPL 310 is located offshore South West Nigeria, adjacent to the significant and recently declared commercial Chevron operated Aje discovery. An electromagnetic survey was acquired and completed in the first half of the year, the results of which are being integrated into seismic data which is being reprocessed into Pre Stack Depth Migration (PSDM) format. Both electromagnetic and seismic techniques have been deployed successfully in the adjacent block that contains Aje and used to good effect in other parts of Nigeria too. The intention is to use the integrated data set to reduce the exploration risk associated with the prospects and leads that have already been defined on the block. The field partners will shortly look for an additional partner before commencing drilling on the block.
OPL 907 / OPL 917
Afren as operator has completed an environmental baseline study ahead of planned future 2D seismic acquisition across both blocks. Additional 2D seismic data has also been obtained from the Department of Petroleum Resources, which will supplement the existing data and optimise the acquisition of new seismic. The blocks are both located within the highly prospective, under explored Anambra Basin (30 wells drilled to date), covering a gross area of 3,500 km2.
OPL 907 and OPL 917 contain potentially attractive Cretaceous opportunities. OPL 917 contains the Igbarium discovery with an estimated in place volume of 300 bcf and 80 mmbbls condensate within the Turonian - Maastrichtian deltaic to shallow marine Nkporo formation. Afren believes that OPL 907 and OPL 917 are capable of yielding up to ten drillable prospects of similar size to Igbarium with a probability of success ranging between 30% to 40%. The main hydrocarbon plays consist of late Cretaceous deltaic to shallow marine clastics in fault related traps. Drilling is likely to commence on the two blocks in 2012, with one well initially on OPL 907 and two wells on OPL 917.
First HydrocarbonNigeria (FHN)
FHN fulfils the Nigerian government's criteria for indigenous operators and has been set up as a vehicle to acquire substantial oil and gas assets in Nigeria, both as part of a process in relation to existing negotiations and acquiring assets that may become available that are currently held by the joint ventures between the Nigerian government and international oil companies.
| West Africa (non Nigeria) | ||
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| H1 2010 Production* | Reserves and Resources** | 1H 2010 Turnover |
| 6,481 boepd | 548 mmboe | US$17.7 mm |
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| * Gross production ** Independently certified net working interest reserves and resources at 30 June 2010 | ||
Côte d'Ivoire
CI-11 and Lion Gas Plant
Average production during the period at CI-11 was 1,219 bopd and 26.7 mmcfd, with 654 boepd of NGL production at the Lion Gas Plant. Gas production over Q1 2010 was impacted due to maintenance work involving the low pressure compressor on the Gulftide production platform and turbo expander at the Lion Gas Plant. Following completion of necessary work, gas production was restored to a gross rate of approximately 30 mmcfd from April onwards. The Lion Gas Plant has also received significantly reduced third party inlet volumes over the period as a result of work on the gas compression systems at the CNR operated Espoir and Baobab fields.
A wireline workover programme has been undertaken to clear any potential wax accumulations in the well bores, the next step being to optimise the gas lift system and potentially perform water shut-offs and perforate bypassed oil and gas pay zones. The results of a major subsurface re-evaluation exercise have now been incorporated into geological models that have been up-scaled to reservoir simulation models and production history matched since 1995. This work has defined potential new hydrocarbon bearing reservoirs in addition to infill drilling opportunities. Side-tracks of existing wells are also being considered as a means of addressing low recovery factors in some parts of the field. Pressure maintenance via water injection as a means of enhancing production from current wells is also under consideration.
CI-01
Block CI-01 borders the maritime boundary with Ghana, and lies adjacent to the major Jubilee and Tweneboa discoveries that have been made in recent years. Out of 16 wells drilled to date on the block, 10 have found hydrocarbons (63% technical success rate) with five fields defined (Kudu, Eland, Ibex, Impala and Assinie). The last well drilled on the block was in 1998 by Ocean Energy. Consequently, the block has not yet benefited from the latest sub-surface understanding of the Cretaceous depositional systems.
Recent work has focused on the application of current understanding of the Cretaceous systems to the existing well and seismic data set to redefine the distribution of oil and gas in the discovered accumulations on the block, leading Afren to believe that the discoveries made to date have the potential to be significantly larger than originally mapped. Additional exploration prospectivity is also being identified as a result of this work. To aid this process, the field partners may acquire new 3D seismic and electromagnetic data over the block ahead of future appraisal drilling.
Ghana
The Keta block is a potentially high impact, deep water exploration asset in easternmost Ghana, along the highly prospective but under explored West African Transform Margin. Multiple play types offer diverse hydrocarbon potential, with the primary targets being Cretaceous deep water clastics in combined structural / stratigraphic traps that offer giant field potential. The play concept is similar to that proved successfully in the recent Jubilee and Odum discoveries, reported to have been made in Campanian sands which is extremely promising for the Keta block. Several Upper Cretaceous closures have been identified on the block, which covers an area of 4,400 km2, ranging in size from 100 mmbbls to 600 mmbbls. Stratigraphic upside potential offers gross resources in excess of 1.5 billion bbls, making the Keta block world class acreage in an under explored fairway.
Additional on-block 2D seismic data was purchased in 2009 and interpreted, identifying new leads which have been incorporated into the current block inventory. Work during 2010 is focused on prospect selection and planning of drilling operations for an exploration well in early 2011. The field partners have commenced a process to secure an additional partner ahead of drilling.
Congo Brazzaville
The Tie Tie NE exploration well was completed in February. Targeting the Djeno clastics and Toca limestones, the well reached a total depth of 2,550 m. Hydrocarbon indications were recorded between depths of 1,775 m and 1,875 m, with measurements performed on location identifying the hydrocarbon type to be mainly gas which does not suggest viable commercial development is possible given its distance from prospective markets. The well was subsequently plugged and abandoned. The partners still plan to test a number of other attractive prospects on the block.
Nigeria - São Tóme & Príncipe Joint Development Zone
The Block 1 participants (Afren 4.41%) have agreed to enter the next exploration period. One commitment well will be required during this phase. In 2006, Chevron made the Obo-1 discovery which contained 150 feet of net pay and proved a working oil and gas system in the JDZ. In the neighbouring blocks Sinopec (Addax) recently completed a multi well drilling campaign. The drilling results, once available, will assist in determining the next steps in this area.
Total announced on 15 July 2010 the signature of an agreement to acquire Chevron's 45.9% interest in Block 1. Subject to approvals of the transaction by the relevant authorities, Total will operate the block. The proximity of Total's operated licenses and production facilities in Nigeria creates strong synergies, lowers the commercial threshold for discoveries in the area and will enable cost reductions in developing the license's resources.
| East Africa |
Acquisition of Black Marlin Energy Holdings Limited.
Strategic entry into East Africa - a complementary expansion
In June 2010, Afren announced that it had reached an agreement with Black Marlin to acquire all of the issued and to be issued share capital of Black Marlin.
Black Marlin is an independent exploration and appraisal company listed on the Canadian TSX Venture Exchange. The Company holds exploration blocks located across Ethiopia, Kenya, Madagascar and the Seychelles. The proposed acquisition provides an entry position of critical mass in East Africa and is consistent with Afren's founding mandate to establish a pan African presence. The acquisition expands Afren's exploration inventory by adding several exploration targets across multiple geological basins, play types and geographies that will allow the Company to leverage its profitable cash generative production base in West Africa.
An emerging exploration province of global interest
East Africa's profile as an exploration province of global interest has risen following recent major discoveries across the region and a number of high profile international companies acquiring acreage positions, in what is recognised as an under explored area of extremely high potential.
Mesozoic rifting phases associated with the break up of Gondwanaland created several prolific hydrocarbon basins that are productive today, notably the Mughlad Basin (Southern Sudan), Bombay and Cambay Highs (India), Yemen, Tanzania, Madagascar and Mozambique. Black Marlin's assets cover a surface area of 127,776 km2 on a gross basis and are all located in basins with proven petroleum systems or strong evidence of working petroleum systems, all sharing a common origin and many characteristics (including source rocks and reservoirs) with these already productive areas. A number of exciting prospects and leads have already been defined to date across the acreage.
Enhancing Afren's pan African presence
The proposed acquisition will add an estimated 1.2 billion boe to Afren's current net prospective resource base and at least six high impact exploration wells to be drilled through to 2012 in the four countries, augmenting Afren's existing near term exploration drilling programme. Seismic acquisition is currently underway on parts of the Kenyan and Ethiopian assets with additional seismic acquisition planned for 2011 in Kenya and the Seychelles.
Afren estimates the net cost of the expected seismic acquisition and drilling work programme associated with Black Marlin's portfolio to be US$98 million over the period 2010 to 2012, of which US$14 million is expected in 2010 and US$46 million in 2011, which will be internally funded from future production revenues generated by the Company's existing asset base.
Transaction terms and expected timeline
The proposed acquisition will be implemented by means of a scheme of arrangement ("Arrangement") such that Black Marlin will become a wholly owned subsidiary of Afren. The terms of the transaction value Black Marlin at approximately C$0.51 per share, based on the Afren volume weighted average price for the 20 trading days prior to and including 1 June 2010 of 90 pence per share. On this basis, Black Marlin shareholders will receive 0.3647 Afren shares for each Black Marlin share, approximately 76.8 million Afren shares on aggregate. At the time of announcement, Afren had received irrevocable undertakings to support and vote in favour of the Arrangement from the Directors of Black Marlin and senior officers and certain other shareholders in respect of a total of 111.9 million Black Marlin shares representing approximately 55% of the existing issued share capital of Black Marlin. These irrevocable undertakings can be terminated upon the termination of the Arrangement Agreement in accordance with its terms.
The announced acquisition is conditional on, among other things, the sanction of the Arrangement by the BVI Court which is expected to occur in early October 2010. The Arrangement must also be approved by a majority in number of Black Marlin shareholders voting, representing at least three-fourths in value of the Black Marlin shares that are voted, at a special meeting of Black Marlin shareholders to be convened in accordance with the order of the BVI Court on 10 September 2010.
On 25 August 2010 Afren mailed a shareholder circular setting out further details on this acquisition. The announced acquisition is also conditional on the approval by the holders of a majority of Afren shares attending and entitled to vote at a shareholder general meeting which is scheduled for 21 September 2010. On this basis it is expected that de-listing of Black Marlin shares from the TSX Venture Exchange and admission to trading of new Afren shares will be effected on or around 8 October 2010.
Finance Review
Afren reported its first profit after tax of US$50.7 million in the first six months of 2010 (1H 2009: loss of US$38.5 million). Normalised profit after tax was US$54.5 million (see note 3) compared with US$0.6 million in 1H 2009. This was achieved by a combination of higher realised oil prices, and continued cost management on the Okoro field.
Revenue in the first half of the year was US$214.8 million, representing a 38.4% increase on the same period in 2009. This increase reflects an average price of US$77.8 per bbl achieved in the period compared with US$50.3 per bbl in 1H 2009. Total sales were approximately 3.3 mmboe (1H 2009: 3.7 mmboe).
Cost of sales, at US$117.8 million (1H 2009: US$134.6 million), comprised of US$63.0 million (1H 2009: US$83.5 million) of depreciation, and field operating costs of US$54.7 million (1H 2009: US$51.1 million). The cost efficiencies generated at Okoro in 2009 have been maintained and rolled into the current year, keeping operating costs relatively flat. The lower depreciation charge in the first half of 2010 is a result of the increased reserves estimate at the Okoro field.
Total administrative expenses were US$14.9 million (1H 2009: US$10.2 million), the increase being largely due to the write off of expenses related to the announced acquisition of Black Marlin. Following an amendment to IFRS 3, "Business Combinations" such expenses are now required to be expensed as incurred. The impairment of assets amounting to US$1.1 million; (1H 2009: US$2.6 million) primarily relates to residual costs of the Tie Tie NE well drilled in Congo Brazzaville in late 2009; the bulk of the costs of this well were expensed in the 2009 financial statements.
Profit before tax for the period was US$75.4 million (1H 2009: loss of US$37.4 million); with a tax charge of US$24.7 million, profit after tax of US$50.7 million was recorded (1H 2009: tax of US$1.2 million and a loss after tax of US$38.5 million).
The Company generated operating cashflows before movements in working capital in the period of US$149.1 million (1H 2009: US$111.6 million). In addition, US$83.7 million (1H 2009: US$62.1 million) of debt was repaid over the period and the first draw down under the Ebok facility of US$25 million occurred in June 2010. Capital expenditure was US$135.6 million of which US$110.6 million related to development of the Ebok field. Net debt was US$12.2 million at the end of the period (30 June 2009: US$194.9 million; 31 December 2009 net cash of US$54.2 million).
Derivative financial instruments
The small profit of US$0.2 million (1H 2009: US$22.9 million loss) on the derivative financial instruments relates to the revaluation of the hedge position taken out by Afren, as required by the lenders to protect against low oil prices for a proportion of its oil production on Okoro and CI-11. In cash terms, Afren has made a loss of US$0.9 million (1H 2009 gain of US$11.9 million) as a result of a stronger oil price environment and higher realisations year on year.
Financing costs and currency gains
Net finance costs were US$6.2 million compared with US$21.9 million in the first half of 2009. The large decrease reflects the repayment of debt and the effect of lower interest rates as USD Libor has fallen.
Foreign currency gains of US$0.5 million (1H 2009: US$1.5 million) reflects the increase in value of some Sterling deposits as the exchange rate moved over the period between year end 2009 and when the Sterling was swapped into US dollar to remove any further exposure.
Associated company investment and taxes
Afren has accounted for Gasol as an associated company from the time of its increase in investment in February 2009. The loss reflected in the period of US$0.6 million reflects the full write off of the remaining value of the investment in Gasol and as such no further losses will be recognised.
Tax
The tax charge for the period of US$24.7 million (1H 2009: US$1.2 million) arises from the Group's operations in Nigeria and Côte d'Ivoire. The charge reflects the current and deferred tax expense for the Okoro field and the current tax expense for the CI-11 operations.
Balance sheet
Total non-current assets stood at US$789.1million as at 30 June 2010, compared with US$670.3 million as at 30 June 2009, and US$684.0 million as at 31 December 2009. The increase largely reflecting the expenditure related to development of the Ebok field during the period.
Intangible assets
Since 31 December 2009 intangible assets have increased from US$184.2 million to US$209.4 million. This predominantly reflects the costs related to OPL310, Okwok and OML 115, new licenses entered into during late 2009 and early 2010, totalling US$19.5 million.
Other major components of the period end balance include CI-01 (US$103.2 million), La Noumbi (US$30.1 million), the Keta block (US$19.8 million) and JDZ block 1 (US$17.6 million).
Property, plant and equipment (PP&E)
PP&E includes oil and gas assets of US$568.4 million compared with US$486.7 million at the year end and US$395.8 million at 30 June 2009. The large movement reflects the transfer of the balance from intangibles relating to Ebok and the subsequent development expenditure on Ebok in the period.
Current assets
Total current assets of US$347.7 million compare with US$416.0 million at year end and US$253.9 million as at 30 June 2009. Of this, cash and cash equivalents amounted to US$194.0 million (31 December 2009: US$321.3 million).
The movement in cash and cash equivalents in the period reflects the net cash receipts from operations of US$91.4 million (1H 2009: US$98.0 million) offset by the further investment in assets of US$145.7 million (1H 2009: US$104.3 million) and the repayments of loans and associated financing costs US$99.6 million (1H 2009: US$77.7 million). New loans in the period totalled US$25.0 million.
The increase in trade and other receivables in the period to US$103.9 million (US$55.6 million at 31 December 2009, US$74.1 million at 30 June 2009) reflects the timing of liftings in both Nigeria and Côte d'Ivoire with US$78 million of this balance received in the first week of July 2010.
Current liabilities
Total current liabilities have reduced in the period (US$223.8 million as at 30 June 2010 compared with US$257.6 million as at 31 December 2009). This reflects an increase in trade and other payables (from $134.7 million at 31 December 2009 to US$148.6 million as at 30 June 2010), offset by a reduction in the short term element of the borrowings (from US$117.6 million as at 31 December 2009 to US$72.0 million as at 30 June 2010). The latter decrease is a reflection of the repayment of the Okoro loan facility where only US$21 million out of a total original facility of US$200 million remains to be repaid. In addition, US$21.7 million was repaid in the period relating to the Côte d'Ivoire facility and a repayment on the FCMB US$50 million loan of US$8.3 was paid in the first quarter of 2010.
Non current liabilities and net debt
Non-current liabilities have increased from US$184.1 million at the beginning of the period to US$199.1 million mostly reflecting the deferred tax liability recognised in Nigeria partly offset by the reduction in the long term portion of the debt facilities. In addition, a decommissioning provision of US$7.8 million has been made during the period in respect of the Ebok field.
Net debt has fallen from US$194.9 million at 30 June 2009 to US$12.2 million as at 30 June 2010 and gearing is now at 2% compared with 45% at 30 June 2009.
In March, the Company signed a reserves based lending ("RBL") debt facility agreement secured against Afren's share of production from the Ebok field, with the borrowing base determined by the Project reserves, based on the assessment of Netherland, Sewell & Associates, Inc. and the Technical Banks' assessments. The facility has a maturity of maximum five years, is repayable semi annually and has a margin of between 4% and 5.5% over LIBOR. The facility will be available for development funding of the Ebok/Okwok/OML 115 area, offshore South East Nigeria. The facility provides Afren with added financial flexibility to execute its planned work programme. At 30 June 2010 a total of US$25.0 million has been drawn on this facility and is being used to fund the development of Ebok.
Going concern
The Group typically uses its cash resources to fund its exploration and appraisal programme and administrative expenses. Expenditure on developing a field to production is typically also funded by debt facilities. At present the Group is funding the initial development of the Ebok field from debt facilities and its own resources and the Company's assessment is that this can be continued until Ebok produces first oil, after which it will contribute cash to the Group.
The Directors have a reasonable expectation that the Company and Group have adequate resources to continue in operational existence for the foreseeable future. Thus they continue to adopt the going concern basis of accounting in preparing the interim financial statements.
Principal risks to 2010 performance
The principal risks and uncertainties that could impact the Group for the remainder of the current financial year remain largely unchanged from those detailed on pages 62-63 of the Group's Annual Report and Accounts 2009. In common with other companies in the oil and gas sector, Afren is exposed to commodity price risk, the delivery of major projects and ensuring safe operations in all locations. The Board determines key risks for the company and required mitigation plans and reviews delivery on a regular basis. Key specific risks for 2010 include the successful execution of the phased Ebok development.
Financial strategy and outlook
Afren's financial strategy is to preserve financial flexibility in order to execute the Company's significant development, appraisal and exploration work programmes and deploy capital across the business effectively to generate maximum returns. With a strong balance sheet and enhanced financial flexibility the Company has the necessary resources and capital structure in place to undertake its forward acquisitions and development programme.
The outlook for the remainder of 2010 and beyond is positive for Afren. Production performance has been in line with expectations for the period and is expected to rise sharply into the foreseeable future. Excellent progress has been made at the Ebok development as we move towards first oil in Q4 2010, and seek to further build on the core production hub we are establishing offshore South East Nigeria. The announced Black Marlin acquisition meets our strategic objective for balanced pan African growth and adds an exciting dimension to the business. In Nigeria our growth strategy remains on track and we will continue to pursue and deliver materially accretive acquisitions through targeting the large number of discovered but un-developed fields that exist in the country, whilst also capitalising on opportunities that may arise out of the incumbent major IOC's portfolios through the established indigenous framework of FHN.
In addition to the numerous planned appraisal and development wells, over the period to 2012 we currently envisage drilling at least 10 firm exploration wells in Nigeria, Ghana, Ethiopia, Kenya, Madagascar and the Seychelles which have the potential to add material reserves to the Company. Overall, we are well placed to deliver significant shareholder value over the coming years.
Responsibility statement
The Directors confirm that to the best of their knowledge:
a) the condensed set of financial statements has been prepared in accordance with lAS 34 'Interim Financial Reporting' as adopted by the EU;
b) the interim management report includes a fair review of the information required by DTR 4.2.7R (indication of important events during the first six months and description of principal risks and uncertainties for the remaining six months of the year); and
c) the interim management report includes a fair review of the information required by DTR 4.2.8R (disclosure of related parties' transactions and changes therein).
The Directors of Afren plc are as listed in the Group's 2009 Annual Report and Accounts. A list of the current Directors is maintained on the Afren plc website: www.afren.com.
By order of the Board,
Osman Shahenshah Darra Comyn
Chief Executive Group Finance Director
31 August 2010 31 August 2010
Disclaimer
This statement contains certain forward-looking statements that are subject to the usual risk factors and uncertainties associated with the oil and gas exploration and production business. Whilst the Group believes the expectations reflected herein to be reasonable in light of the information available to them at this time, the actual outcome may be materially different owing to factors beyond the Group's control or within the Group's control where, for example, the Group decides on a change of plan or strategy. Accordingly no reliance may be placed on the figures contained in such forward-looking statements.
Independent review report to Afren plc
We have been engaged by the company to review the condensed set of financial statements in the half-yearly financial report for the six months ended 30 June 2010 which comprises the income statement, the balance sheet, the statement of changes in equity, the cash flow statement, the statement of comprehensive income and related notes 1 to 9. We have read the other information contained in the half-yearly financial report and considered whether it contains any apparent misstatements or material inconsistencies with the information in the condensed set of financial statements.
This report is made solely to the company in accordance with International Standard on Review Engagements (UK and Ireland) 2410 "Review of Interim Financial Information Performed by the Independent Auditor of the Entity" issued by the Auditing Practices Board. Our work has been undertaken so that we might state to the company those matters we are required to state to them in an independent review report and for no other purpose. To the fullest extent permitted by law, we do not accept or assume responsibility to anyone other than the company, for our review work, for this report, or for the conclusions we have formed.
Directors' responsibilities
The half-yearly financial report is the responsibility of, and has been approved by, the directors. The directors are responsible for preparing the half-yearly financial report in accordance with the Disclosure and Transparency Rules of the United Kingdom's Financial Services Authority.
As disclosed in note 1, the annual financial statements of the group are prepared in accordance with IFRSs as adopted by the European Union. The condensed set of financial statements included in this half-yearly financial report has been prepared in accordance with International Accounting Standard 34, "Interim Financial Reporting," as adopted by the European Union.
Our responsibility
Our responsibility is to express to the Company a conclusion on the condensed set of financial statements in the half-yearly financial report based on our review.
Scope of Review
We conducted our review in accordance with International Standard on Review Engagements (UK and Ireland) 2410 "Review of Interim Financial Information Performed by the Independent Auditor of the Entity" issued by the Auditing Practices Board for use in the United Kingdom. A review of interim financial information consists of making inquiries, primarily of persons responsible for financial and accounting matters, and applying analytical and other review procedures. A review is substantially less in scope than an audit conducted in accordance with International Standards on Auditing (UK and Ireland) and consequently does not enable us to obtain assurance that we would become aware of all significant matters that might be identified in an audit. Accordingly, we do not express an audit opinion.
Conclusion
Based on our review, nothing has come to our attention that causes us to believe that the condensed set of financial statements in the half-yearly financial report for the six months ended 30 June 2010 is not prepared, in all material respects, in accordance with International Accounting Standard 34 as adopted by the European Union and the Disclosure and Transparency Rules of the United Kingdom's Financial Services Authority.
Deloitte LLP
Chartered Accountants and Statutory Auditors
London, United Kingdom
31 August 2010
|
Condensed Group Income Statement | ||||
| for the six months to 30 June 2010 | ||||
|
| Notes | 6 months to 30 June 2010 Unaudited $000's | 6 months to 30 June 2009 Unaudited $000's | Year to 31 December 2009 Audited $000's |
| Revenue |
| 214,750 | 155,162 | 335,818 |
| Cost of sales |
| (117,755) | (134,630) | (230,036) |
| Gross profit |
| 96,995 | 20,532 | 105,782 |
|
|
|
|
|
|
| Administrative expenses |
| (14,871) | (10,247) | (27,215) |
| Other operating income/(expenses) |
|
|
|
|
| - impairment of oil and gas assets |
| (1,143) | (2,552) | 859 |
| - derivative financial instruments |
| 153 | (22,894) | (33,635) |
|
|
|
|
|
|
| Operating profit/(loss) | 3 | 81,134 | (15,161) | 45,791 |
| Investment revenue |
| 237 | 301 | 626 |
| Finance costs |
| (6,185) | (21,916) | (36,950) |
| Other gains and (losses) |
|
|
|
|
| - foreign currency gains/(losses) |
| 524 | 1,486 | (2,770) |
| - fair value of financial liabilities and financial assets |
| 280 | (1,656) | (5,034) |
| - impairment reversal/(charge) on available for sale investments |
| - | 97 | 97 |
| Share of loss of an associate |
| (604) | (520) | (1,277) |
| Profit/(loss) before tax |
| 75,386 | (37,369) | 483 |
| Income tax expense |
| (24,662) | (1,162) | (17,261) |
| Profit/(loss) after tax |
| 50,724 | (38,531) | (16,778) |
|
|
|
|
|
|
| Profit/(loss) per share |
|
|
|
|
| Basic | 2 | 5.7c | (7.3)c | (2.6)c |
| Diluted | 2 | 5.2c | (7.3)c | (2.6)c |
|
|
|
|
|
|
All operations were continuing throughout all periods. There are no items of comprehensive income not included in the income statement.
| Condensed Group Balance Sheet | |||
| as at 30 June 2010 |
|
|
|
|
| 30 June 2010 Unaudited US$000's | 30 June 2009 Unaudited US$000's |
31 December 2009 Audited US$000's |
| Assets |
|
|
|
| Non-current assets |
|
|
|
| Intangible oil and gas assets | 209,409 | 257,394 | 184,161 |
| Property, plant and equipment |
|
|
|
| - Oil and gas assets | 568,423 | 395,797 | 486,672 |
| - Other | 6,764 | 5,154 | 6,996 |
| Prepayments | 2,683 | 4,083 | 3,383 |
| Derivative financial instruments | 1,818 | 6,551 | 2,153 |
| Investment in associate | - | 1,361 | 604 |
|
| 789,097 | 670,340 | 683,969 |
| Current assets |
|
|
|
| Inventories | 46,020 | 14,527 | 34,564 |
| Trade and other receivables | 103,934 | 74,091 | 55,614 |
| Derivative financial instruments | 3,733 | 12,052 | 4,523 |
| Cash and cash equivalents | 194,019 | 153,276 | 321,312 |
|
| 347,706 | 253,946 | 416,013 |
| Total assets | 1,136,803 | 924,286 | 1,099,982 |
|
|
|
|
|
| Liabilities |
|
|
|
| Current liabilities |
|
|
|
| Derivative financial instruments | (3,277) | (3,526) | (5,240) |
| Borrowings | (72,000) | (148,771) | (117,634) |
| Trade and other payables | (148,562) | (113,623) | (134,739) |
|
| (223,839) | (265,920) | (257,613) |
| Net current assets/(liabilities) | 123,867 | (11,974) | 158,400 |
|
|
|
|
|
| Non-current liabilities |
|
|
|
| Deferred tax liabilities | (34,430) | - | (12,460) |
| Provision for decommissioning | (30,341) | (21,298) | (21,836) |
| Borrowings | (134,238) | (199,357) | (149,446) |
| Derivative financial instruments | (135) | (363) | (379) |
|
| (199,144) | (221,018) | (184,121) |
| Total liabilities | (422,983) | (486,938) | (441,734) |
| Net assets | 713,820 | 437,348 | 658,248 |
|
|
|
|
|
| Equity |
|
|
|
| Share capital | 15,734 | 12,785 | 15,702 |
| Share premium | 756,469 | 561,182 | 755,169 |
| Other reserves | 17,674 | 20,669 | 17,272 |
| Accumulated losses | (76,057) | (157,288) | (129,895) |
| Total equity | 713,820 | 437,348 | 658,248 |
| Condensed Group Cash Flow Statement | |||
| for the six months to 30 June 2010 | |||
|
| 6 months to 30 June 2010 Unaudited US$000's | 6 months to 30 June 2009 Unaudited US$000's |
Year to 31 December 2009 Audited US$000's |
| Operating profit/(loss) for the period | 81,134 | (15,161) | 45,791 |
| Depreciation, depletion and amortisation | 64,736 | 84,727 | 154,783 |
| Derivative financial instruments losses/(gains) | (1,082) | 34,801 | 48,458 |
| Impairment of oil and gas assets | 1,143 | 2,552 | (859) |
| Share based payments charge | 3,125 | 4,675 | 9,292 |
| Operating cashflows before movements in working capital | 149,056 | 111,594 | 257,465 |
| (Increase)/decrease in trade and other operating receivables |
(53,665) |
(31,768) |
533 |
| (Decrease)/Increase in trade and other operating payables | (2,770) | 17,916 | 31,761 |
| Increase in inventory (crude oil) | (1,061) | - | (11,588) |
| Currency translation adjustments | (200) | 211 | 117 |
| Net cash generated/(used) in operating activities | 91,360 | 97,953 | 278,288 |
|
|
|
|
|
| Purchases of property, plant and equipment |
|
|
|
| - Other | (1,477) | (585) | (3,770) |
| - Oil and gas assets | (110,802) | (44,161) | (97,810) |
| Exploration and evaluation expenditure | (23,292) | (50,457) | (90,365) |
| Increase in inventories - spare parts | (10,394) | (1,250) | (9,700) |
| Purchase of investments | - | (1,815) | (1,815) |
| Investment revenue | 237 | 204 | 599 |
| Completion payment on 2008 acquired subsidiaries | - | (6,198) | (6,198) |
| Net cash used in investing activities | (145,728) | (104,262) | (209,059) |
|
|
|
|
|
| Issue of ordinary share capital | 1,332 | 126,664 | 326,969 |
| Costs of share issues | - | (8,461) | (14,236) |
| Proceeds from borrowings | 25,000 | - | - |
| Borrowing costs | (6,030) | - | - |
| Repayment of borrowings | (83,711) | (62,072) | (148,447) |
| Interest and financing fees paid | (9,906) | (15,631) | (26,870) |
| Net cash provided by financing activities | (73,315) | 40,500 | 137,416 |
|
|
|
|
|
| Net (decrease)/increase in cash and cash equivalents | (127,683) | 34,191 | 206,645 |
| Cash and cash equivalents at beginning of year/period | 321,312 | 117,719 | 117,719 |
| Effect of foreign exchange rate changes | 390 | 1,366 | (3,052) |
| Cash and cash equivalents at end of year/period | 194,019 | 153,276 | 321,312 |
| Condensed Group Statement of Changes in Equity | |||||
| for the six months ended 30 June 2010 (unaudited) | |||||
|
| Share capital $000's | Share premium account $000's | Other reserves $000's | Accumulated losses $000's | Total equity $000's |
| Group |
|
|
|
|
|
| At 1 January 2009 | 8,806 | 446,958 | 18,173 | (122,991) | 350,946 |
| Issue of share capital | 3,979 | 122,685 | - | - | 126,664 |
| Deductible costs of share issues | - | (8,461) | - | - | (8,461) |
| Shares to be issued | - | - | 2,055 | - | 2,055 |
| Share based payments for services | - | - | 4,618 | - | 4,618 |
| Other share based payments | - | - | 57 | - | 57 |
| Reserves transfer relating to loan notes | - | - | (1,136) | 1,136 | - |
| Reserves transfer on exercise of options, awards and LTIP |
- |
- |
(3,098) |
3,098 |
- |
| Net loss for the period | - | - | - | (38,531) | (38,531) |
| Balance at 30 June 2009 | 12,785 | 561,182 | 20,669 | (157,288) | 437,348 |
|
|
|
|
|
|
|
| Issue of share capital | 2,876 | 197,748 | - | - | 200,624 |
| Deductible costs of share issues | - | (5,775) | - | - | (5,775) |
| Share based payments for services | - | - | 4,579 | - | 4,579 |
| Other share based payments | - | - | 38 | - | 38 |
| Reserves transfer relating to loan notes | - | - | (1,176) | 1,176 | - |
| Reserves transfer on exercise of options, awards and LTIP | - | - | (1,694) | 1,694 | - |
| Shares to be issued | 41 | 2,014 | (2,055) | - | - |
| Reserves transfer on exercise of warrants | - | - | (2,770) | 2,770 | - |
| Other movements | - | - | (319) | - | (319) |
| Net profit for the period | - | - | - | 21,753 | 21,753 |
| Balance at 1 January 2010 | 15,702 | 755,169 | 17,272 | (129,895) | 658,248 |
|
|
|
|
|
|
|
| Issue of share capital | 32 | 1,300 | - | - | 1,332 |
| Cost of shares to be issued | - | - | (1,000) | - | (1,000) |
| Share based payments for services | - | - | 4,464 | - | 4,464 |
| Other share based payments | - | - | 52 | - | 52 |
| Reserves transfer relating to loan notes | - | - | (1,216) | 1,216 | - |
| Reserves transfer on exercise of options, awards and LTIP | - | - | (1,898) | 1,898 | - |
| Net profit for the period | - | - | - | 50,724 | 50,724 |
| Balance at 30 June 2010 | 15,734 | 756,469 | 17,674 | (76,057) | 713,820 |
1. Basis of accounting and presentation of financial information
These condensed interim consolidated financial statements are for the six months ended 30 June 2010. The interim financial report, which is unaudited and does not constitute statutory accounts as defined by the Companies Act, has been prepared in accordance with the International Accounting Standard 34 'Interim Financial Reporting', as adopted for use in the European Union. The annual financial statements of Afren plc are prepared in accordance with IFRSs as adopted by the European Union.
The financial information for the year ended 31 December 2009 does not constitute statutory accounts as defined in section 434 of the Companies Act 2006. A copy of the statutory accounts for that year has been delivered to the Registrar of Companies. The auditors report on these accounts was not qualified, did not draw attention to any matters by way of emphasis and did not contain statements under section 498(2) or (3) of the Companies Act 2006.
Changes in accounting policy
The same accounting policies, presentation and methods of computation are followed in the condensed set of financial
statements as applied in the Group's latest annual audited financial statements, except as described below.
In the current financial year. the Group has adopted International Financial Reporting Standard 3 "Business Combinations" (revised 2008) and International Accounting Standard 27 "Consolidated and Separate Financial Statements" (revised 2008).
The most significant changes to the Group's previous accounting policies for business combinations are as follows:
• acquisition related costs which previously would have been included in the cost of a business combination are included in administrative expenses as they are incurred;
• any pre-existing equity interest in the entity acquired is re-measured to fair value at the date of obtaining control, with any resulting gain or loss recognised in profit or loss;
• any changes in the Group's ownership interest subsequent to the date of obtaining control are recognised directly in equity. with no adjustment to goodwill; and
• any changes to the cost of an acquisition, including contingent consideration, resulting from events after the date of acquisition are recognised in profit or loss. Previously. such changes resulted in an adjustment to goodwill.
The revised standards will be applied to the announced acquisition of Black Marlin Energy Holdings Limited as described in note 5.
Going concern
The directors are satisfied that the Group has sufficient resources to continue in operation for the foreseeable future, a period of not less than 12 months from the date of this report. Accordingly, they continue to adopt the going concern basis in preparing the financial statements.
2. Profit per share
The calculation of the basic profit/(loss) per share is based on the profit for the period after taxation of US$50,724,000 (1H 2009: US$38,531,000 loss) and a weighted average number of shares in issue of 890,227,484 (1H 2009: 529,433,254). The weighted average number of shares for the purposes of fully diluted calculation is 977,994,256 (1H 2009: 529,433,254).
3. Reconciliation of normalised profit/(loss) after tax to the profit/(loss) after tax
|
| 1H 2010 $000's | 1H 2009 $000's |
| Profit/(loss) after tax | 50,724 | (38,531) |
| Unrealised (gains)/losses on derivative financial instruments | (1,082) | 34,801 |
| Cost of acquisition of Black Marlin incurred in the period | 1,929 | - |
| Cost of move to the main market of the London Stock Exchange | - | 108 |
| Share based payment charge | 3,125 | 3,655 |
| Foreign exchange (gains)/losses | (524) | (1,486) |
| Fair value financial liabilities | (280) | 1,656 |
| Impairment reversal on available for sale investments | - | (97) |
| Share of loss of associate | 604 | 520 |
| Normalised profit after tax | 54,496 | 626 |
4. Operating Segments
For management purposes, the Group currently operates in three geographical markets: Nigeria, Côte d'Ivoire and other West Africa. Unallocated operating expenses, assets and liabilities relate to the general management, financing and administration of the Group.
|
| Nigeria $000's | Côte d'Ivoire $000's | Other West Africa $000's | Unallocated $000's | Consolidated $000's |
| Six months to June 2010 | |||||
| Sales revenue by origin | 197,100 | 17,650 | - | - | 214,750 |
|
|
|
|
|
|
|
| Operating profit/(loss) before derivative financial instruments | 93,394 | (107) | (1,214) | (11,092) | 80,981 |
| Derivative financial instruments (losses)/gains | (1,538) | 1,691 | - | - | 153 |
| Segment result | 91,856 | 1,584 | (1,214) | (11,092) | 81,134 |
| Investment revenue |
|
|
|
| 237 |
| Finance costs |
|
|
|
| (6,185) |
| Other gains and losses - impairment reversal on available for sale investment | - | ||||
| Other gains and losses - fair value of financial assets & liabilities | 280 | ||||
| Other gains and losses - foreign currency gains | 524 | ||||
| Share of loss of an associate | (604) | ||||
| Profit before tax | 75,386 | ||||
| Income tax expense | (24,662) | ||||
| Profit after tax | 50,724 | ||||
|
|
|
|
|
|
|
| Segment assets - non current | 557,003 | 161,277 | 67,614 | 3,203 | 789,097 |
| Segment assets - current | 201,155 | 26,826 | 8,546 | 111,179 | 347,706 |
| Segment liabilities | (244,598) | (119,623) | (5,293) | (53,469) | (422,983) |
| Capital additions - oil and gas assets | 144,602 | 191 | - | - | 144,793 |
| Capital additions - exploration and evaluation | 19,734 | 785 | 4,729 | - | 25,248 |
| Capital additions - other | - | 22 | - | 305 | 327 |
| Capital disposal - other | (559) | - | - | - | (559) |
| Depletion, depreciation and amortisation | (55,672) | (8,325) |
| (740) | (64,737) |
| Impairment reversal / (charge) on oil and gas assets | 25 | - | (1,168) | - | (1,143) |
|
| Nigeria $000's | Côte d'Ivoire $000's | Other West Africa $000's | Unallocated $000's | Consolidated $000's |
| Year to December 2009 |
|
|
|
|
|
| Sales revenue by origin | 292,111 | 43,707 | - | - | 335,818 |
|
|
|
|
|
|
|
| Operating profit/(loss) before derivative financial instruments | 93,157 | 7,554 | 3,576 | (24,861) | 79,426 |
| Derivative financial instruments losses | (15,346) | (18,289) | - | - | (33,635) |
| Segment result | 77,811 | (10,735) | 3,576 | (24,861) | 45,791 |
| Investment revenue |
|
|
|
| 626 |
| Finance costs |
|
|
|
| (36,950) |
| Other gains and losses - impairment charge on available for sale investment | 97 | ||||
| Other gains and losses - fair value of financial liabilities | (5,034) | ||||
| Other gains and losses - foreign currency losses | (2,770) | ||||
| Share of loss of an associate |
|
|
|
| (1,277) |
| Profit before tax |
|
|
|
| 483 |
| Income tax expense |
|
|
|
| (17,261) |
| Loss after tax |
|
|
|
| (16,778) |
|
|
|
|
|
|
|
| Segment assets-non-current | 448,785 | 168,796 | 62,884 | 3,504 | 683,969 |
| Segment assets - current | 158,764 | 27,940 | 21,373 | 207,936 | 416,013 |
| Segment liabilities | (233,027) | (139,795) | (8,824) | (60,088) | (441,734) |
| Capital additions - oil and gas assets | 76,502 | 6,406 | - | - | 82,908 |
| Capital additions - exploration and evaluation | 59,135 | 1,447 | 6,683 | - | 67,265 |
| Capital additions - other | 2,352 | 123 | - | 1,333 | 3,808 |
| Depletion, depreciation and amortisation | (135,595) | (18,226) | - | (962) | (154,783) |
| Impairment of oil and gas assets | (2,705) | - | 3,564 | - | 859 |
| Impairment of available for sale investments | - | - | - | 97 | 97 |
|
| Nigeria $000's | Côte d'Ivoire $000's | Other West Africa $000's | Unallocated $000's | Consolidated $000's |
| Six months to June 2009 |
|
|
|
|
|
| Sales revenue by origin | 137,655 | 17,507 | - | - | 155,162 |
|
|
|
|
|
|
|
| Operating profit/(loss) before derivative financial instruments | 21,910 | (2,396) | (2,560) | (9,221) | 7,733 |
| Derivative financial instruments losses | (9,817) | (13,077) | - | - | (22,894) |
| Segment result | 12,093 | (15,473) | (2,560) | (9,221) | (15,161) |
| Investment revenue |
|
|
|
| 301 |
| Finance costs |
|
|
|
| (21,916) |
| Other gains and losses - impairment reversal on available for sale investment |
|
| 97 | ||
| Other gains and losses - fair value of financial assets & liabilities |
|
| (1,656) | ||
| Other gains and losses - foreign currency gains |
|
| 1,486 | ||
| Share of loss of an associate |
|
|
|
| (520) |
| Loss before tax |
|
|
|
| (37,369) |
| Income tax expense |
|
|
|
| (1,162) |
| Loss after tax |
|
|
|
| (38,531) |
|
|
|
|
|
|
|
| Segment assets - non-current | 427,649 | 168,863 | 63,691 | 3,586 | 663,789 |
| Segment assets - current | 93,035 | 38,892 | 12,411 | 116,159 | 260,497 |
| Segment liabilities | (280,871) | (153,312) | (10,653) | (42,102) | (486,938) |
| Capital additions - oil and gas assets | 10,550 | 214 | - | - | 10,764 |
| Capital additions - exploration and evaluation | 39,736 | 448 | 5,181 | - | 45,365 |
| Capital additions - other | 423 | 13 | - | 129 | 565 |
| Depletion, depreciation and amortization | (75,068) | (9,215) | - | (444) | (84,727) |
| Impairment of oil and gas assets | - | - | (2,552) | - | (2,552) |
| Impairment reversal of available for sale investments | - | - | - | 97 | 97 |
5. Subsequent events
In June, Afren announced that it had reached an agreement with Black Marlin Energy Holdings Limited (Black Marlin) to acquire all of the issued and to be issued share capital of Black Marlin. The acquisition will be implemented by means of a scheme of arrangement ("Arrangement") such that Black marlin will become a wholly owned subsidiary of Afren. Afren will issue 76.8 million shares to holders of Black Marlin shares. The acquisition is conditional on, among other things, the sanction of the Arrangement by the BVI court which is expected to occur in early October 2010. On 25 August 2010 Afren mailed a shareholder circular setting further details on this acquisition. The acquisition is conditional on the approval by the shareholders of Afren at a general meeting which is to be held on 21 September 2010. Afren will account for the transaction as a business combination under IFRS3. US$1.9 million incurred during the period relating to the transaction has been charged to the profit and loss account.
On 15 July 2010 Afren announced that terms had been agreed to acquire the 7.5% outstanding interest of Energy Equity Resources Oil and Gas in block OML 115, offshore South East Nigeria. Afren's netlicenceinterest in OML 115 increased from 32.5% to 40%.
6. Related party transactions
The following table provides the total amount of transactions which have been entered into with related parties during the six months ended 30 June 2010 and 2009:
Trading transactions
|
| Purchase of goods/services | Amounts owed to related parties | ||
|
| Six months ended 30 June 2010 US$000's | Six months ended 30 June 2009 US$000's | As at 30 June 2010 US$000's | As at 30 June 2009 US$000's |
| Energy Investment Holdings Ltd | 244 | 2,887 | (97) | (6) |
| St. John Advisors | 150 | 506 | - | 28 |
| Tzell Travel Group | 143 | 123 | 16 | (28) |
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Energy Investment Holdings Ltd is the contractor company for the consulting services of Bert Cooper, a Special Adviser to Afren plc. The majority of the payments in 2009 related to success fees for acquisitions and financing arrangements. Of this total, US$nil (2009: US$2.1 million) was paid in shares.
St. John Advisors is the contractor company for the consulting services of John St. John, a Non-executive Director. The majority of the payments in 2009 related to success fees for equity financing. St. John Advisors also receive a monthly retainer of £15,000 for equity consulting advice. This contract is for 12 months from 27 June 2008 and automatically continues thereafter unless terminated by either party.
Tzell Travel Group operates as a franchise. The franchisee utilised by Afren for some of its travel needs is a close family member of the Chief Executive Officer and Tzell Travel Group is therefore considered a related party. Afren uses several travel agents as there is a significant travel element to its operations and Tzell competes on an even basis with these. Tzell provided approximately 8% (2009: 12%) of the travel arrangements by value.
7. Contingent liabilities
There has been no change to the contingencies reported in the annual report for the year ended 31 December 2009. In addition, in March 2010 a stand by letter of credit for $6 million was issued by a bank in respect of the Ebok field's contractual arrangements. A cash deposit of the same amount was placed by Afren with the bank.
8. Dividend
The directors do not recommend the payment of a dividend.
9. Approval of accounts
These interim accounts (unaudited) were approved by the Board of Directors on 31 August 2010.