2011 Full Year Results

Afren plc

2011 Full Year Results

Record financial results; 2P reserves up 132% to 185 mmboe; exploration success in Nigeria

27 March 2012 - The Board of Afren plc ("Afren" or "the Company") announces results for the year ended 31 December 2011.

In 2011, we achieved the major milestone of first oil on the Ebok field development and progressed our Nigerian growth strategy. We also expanded our geographical footprint through the acquisition of assets in Nigeria, East Africa and the Kurdistan region of Iraq. Looking forward, we have a balanced portfolio combining production and development assets that we can leverage to internally fund our high impact exploration activities, underpinned by a capital structure that will support long term inorganic growth.

Key highlights

·; Record turnover of US$597 million (up 87%, 2010: US$319 million) and profit after tax of US$125 million(up 172%, 2010: US$46 million)

·; Group exit production rate achieved; Group firmly on track for 2012 production of 42,000 - 46,000 boepd

·; Net working interest 2P reserves increased by 132% to 185 mmboe

- Net 2P/2C reserves and resources increased by 633% to 995 mmboe

·; Multi-well exploration campaign underway; early success with significant oil discovery at Okoro East

- First phase of Okoro East to be fast tracked to H2 2012

- Currently participating in high impact wells offshore Ghana and onshore Kurdistan region of Iraq

·; Cash at bank US$292 million - mature capital structure with 75% of debt now long dated (2016 - 2019)

Osman Shahenshah, Chief Executive of Afren plc, commented:-

"The 2011 results reflect the growing maturity of our business, with record net profit of US$125 million, up 172% on 2010 and an increase of 2P reserves by 132% to 185 mmboe. We have a made a successful start to our multi-well exploration campaign for 2012 with a significant new discovery offshore Nigeria. We have a visible production trajectory to 100,000 boepd by 2017 and a mature capital structure that will internally fund both organic and inorganic opportunities.

Since the Company was listed in 2005, we have demonstrated strategic foresight and taken significant positions in Nigeria, East Africa and the Kurdistan region of Iraq, at a cost of entry highly accretive to our shareholders, coupled with a strong track record of operational delivery."

Analyst Presentation

There will be a presentation to analysts at 09.00 BST at the Lincoln Centre, 18 Lincoln's Inn Fields, London, WC2A 3ED.

The presentation will also be broadcast live at www.afren.com where the accompanying slides will be available. The presentation will be available on playback from 14.00 BST (09.00 EST).

2011 Full Year Results Summary

Record financial results

During the period turnover increased by 87% to US$597 million (2010: US$319 million), reflecting increased production volumes year-on-year and the effect of higher realised oil prices. Profit before tax increased by 180% to US$221 million (2010: US$79 million) with profits after tax increasing by 172% to US$125 million (2010: US$46 million). Cash flow from operations during the period increased by 62% to US$338 million (2010: US$209 million), reflecting the underlying profitability of the Group's production base.

Higher average production and a strong growth outlook

Net average working interest production in 2011 averaged 19,154 boepd (increase of 34% on 2010: 14,333 boepd) as a result of the successful commissioning of the initial phases of the Ebok field development. However, longer than anticipated periods of facilities related downtime at the Ebok field owing to simultaneous operations and other logistical related delays meant that average production during the period was lower that expected. Independently assessed recoverable reserve estimates at the Ebok field have remained unchanged, and the Group was able to increase output at the field sharply during the fourth quarter, to achieve an exit production rate ahead of guidance. Production at the Okoro field during the period was in line with guidance with incremental volumes being added following the commissioning of two infill wells during the first quarter, and in Côte d'Ivoire the Group continues to manage mature production in line with expectations. Taking into account ongoing development work at Ebok, and necessary management of simultaneous operations, the Group expects full year 2012 net production to average between 42,000 and 46,000 boepd. Longer term, Afren has a pipeline of large scale development projects from known 2P and 2C reserves and resources today that is capable of delivering net production growth to 100,000 boepd by 2017.

Significant growth in net 2P reserves and contingent resources

Total net working interest 2P reserves at 31 December 2011 have been independently estimated by Netherland, Sewell & Associates and RPS Energy at 185 mmboe (2010: 79.8 mmboe), representing sector leading growth of 132%. The increase represents the start of a progressive transitioning of the Group's 2C resource base into the independently certified 2P reserves category as it matures the Barda Rash field development in particular, and excludes any contribution from OML 26 through Afren's 45% shareholding in First Hydrocarbon Nigeria and also the newly discovered Okoro East oil field. During the period net working interest 2P/2C reserves and resources have increased by 633% to 995 mmboe. Of this figure, only 7% has been developed and brought into production to date, indicating the scale of growth that the Group's portfolio is capable of yielding in the future.

Acquisition and entry into the Kurdistan region of Iraq

During the year, Afren announced that it had completed the acquisition of a 60% participating interest in the Barda Rash PSC and a 20% participating interest in the Ain Sifni PSC, both located in the Kurdistan region of Iraq. The acquisition is consistent with Afren's strategy of acquiring low cost barrels in areas where the Group is competitively advantaged - the transaction increasing Afren's net recoverable 2P/2C reserves and resource base by 869 mmbbls at a cost of under US$1.0/bbl. With an approved field development plan in place, the Group expects first oil at the Barda Rash field by August this year, and has line-of-sight on a five year target of delivering 75,000 bopd net to Afren's working interest. At the same time, the Group is actively pursuing high volume/low risk exploration upside at the Ain Sifni block, with a high impact exploration well currently drilling ahead.

Completion of OML 26 acquisition by First Hydrocarbon Nigeria - a landmark transaction

In December 2011, First Hydrocarbon Nigeria (FHN), in which Afren is a 45% shareholder, completed the acquisition of a 45% interest in the onshore OML 26 license from Shell Petroleum Development Company of Nigeria Ltd ("SPDC"), Total E&P Nigeria Ltd ("Total") and Nigeria Agip Oil Company ("Agip"), together the SPDC Joint Venture. FHN also announced it had completed financing facilities totallingUS$280 million, enabling it to fully fund the acquisition cost and its share of future capital requirements. FHN is partnering in the re-development of the Block with Nigerian Petroleum Development Company (NPDC), the oil and gas exploration and production subsidiary of Nigerian National Petroleum Company (NNPC), with Afren acting as Technical Services Provider to FHN.

Multi-well exploration campaign underway - early success at Okoro East

Post period end, the Group announced that the Okoro East exploration well had made a significant new oil discovery. The well successfully encountered oil in Tertiary reservoir sands equivalent to those that have been developed and are in production at the Okoro main field, in addition to deeper, previously unexplored reservoirs. The discovery of significant pay in the new deeper zones opens up further prospectivity at similar levels on the main Okoro field and elsewhere on the Block. The Group is now firmly engaged in the most active phase of exploration activity in its history, with multiple high impact wells spanning the risk spectrum planned across each of Afren's core areas, all of which have the potential to materially transform the Group's discovered resource base.

Strong financial position and mature capital structure

Afren transformed its capital structure in 2011. Cash flow from operations, strengthened with start up of the Ebok project and the January 2011 bond issue, enabled the Group to increase the maturity of its debt profile, better aligning the investment requirements and future profile of the asset base. An equity placing in July 2011 plus a second bond issue in February 2012, both of which were heavily oversubscribed, funded Afren's expansion into the Kurdistan region of Iraq with the latter allowing Afren to repay shorter term facilities and further reduce any potential over-reliance in the future on a relatively limited number of lending banks, in times of economic uncertainty. Afren is well positioned with considerable financial resources at its disposal to internally fund its future activities and accelerate organic growth, whilst retaining discretion over the majority of its forward capital expenditures.

Outlook

Afren has made good progress in 2011 and continues to grow in strength. The Group has assembled a world class portfolio of assets that offers significant potential across the full cycle E&P value chain. Through clear strategic foresight and capitalising on an early mover advantage in Nigeria, East Africa and the Kurdistan region of Iraq, Afren secured attractive acreage positions in some of the world's most prolific and emerging oil and gas basins. Combined with a good track record of operational delivery and a mature capital structure, means that Afren is well positioned for further exponential growth.

Review of Operations

Production and development

An established and growing production base.In 2011, we achieved first oil at the Ebok field and successfully completed infill drilling at the Okoro field. The Group is well placed to achieve 100,000 boepd of production by 2017 from known 2P reserves and contingent resources (on Field Development Plan approval where appropriate) from the Ebok, Okoro, Okoro East, CI-11, OML 26, Okwok and Barda Rash projects.

* Gross remaining 2P reserves at 31 December 2011.

Strong production performance

In 2011, Afren and its partner Amni International Petroleum Development Company Limited (Amni) successfully completed two infill wells, Okoro-11 and Okoro-12, taking the total number of producing wells at the field to nine. As a result, output at the field during the year averaged 15,801 bopd on a gross basis (9,000 bopd net to Afren) in line with guidance. In 2012 the partners are aiming to sustain production from existing well stock between 14,000 bopd and 16,000 bopd. By the end of 2011 the Okoro field had produced 19.8 million barrels of oil.

New oil discovery made at Okoro East

Post period end, Afren and Amni announced that the Okoro East exploration well had made a new oil discovery. The well was spudded on 18 December 2011 with the Transocean Adriatic lX jack-up drilling rig, the objective being to explore a separate, previously undrilled structure located approximately 2 km east of the Okoro main field. Okoro East is in a similar structural setting to the main field, with a fault sealed three-way dip closure in Tertiary reservoir sands at equivalent intervals to the Okoro main field.

In addition, the Okoro East exploration well was targeting a deeper horst block structure, a play concept that had not been previously explored on the block. The well was drilled to a total measured depth of 8,751 ft (8,016 ft true vertical depth) and successfully encountered good quality oil in both the Tertiary reservoir sands equivalent to those that have been developed and are in production at the Okoro main field, and the deeper, previously unexplored reservoirs. The well encountered 549 ft true vertical thickness of net oil pay (580 ft gross) and 41 ft of net gas pay. The discovery of pay in the deeper zones has opened up further prospectivity at similar levels on the Okoro main field and elsewhere on the block. The partners subsequently undertook and completed logging and testing operations, confirming the presence of a high quality 38° to 40° API oil in excellent reservoir sands. Pressure data that was also obtained has assisted with the Group's structural understanding of the field and will be used to help determine the optimal development solution for this significant new discovery.

2012 Outlook

The year ahead will see ongoing management of existing production at the Okoro field with the objective of optimising the oil recovery factor from the developed reservoir zones. There are two available well slots at the existing Okoro wellhead platform, from which Afren and its partner Amni plan to drill new production wells targeting the Okoro East reservoirs, in order to establish early production whilst also deciding upon the most appropriate long-term development solution for the new field.

Production start-up

In 2011, Afren and its local partner Oriental successfully commenced production at the Ebok field. By year end the partners had commissioned all 14 production wells associated with the initial phases of the field development. The project is Afren's second major greenfield development offshore south-east Nigeria, following the Okoro field development, and first oil was achieved in record time of little over two years following the first appraisal well drilled by the partners. By the end of 2011 the Ebok field had produced approximately 3.0 million barrels of oil.

Innovative development solution

The development configuration at Ebok consists of two unmanned wellhead platforms at the Central Fault Block and West Fault Block locations. Both are tied back to a Mobile Offshore Production Unit (MOPU) where the produced crude oil is processed. From there it is piped to a 1.2 million barrel capacity Floating Storage Offloading vessel (FSO) spread-moored nearby, prior to offtake and direct sale on the international market.

The MOPU is a former jack-up drilling unit that was specially converted into a production facility. The FSO was likewise converted, from a pre-existing tanker vessel. Both of these initiatives significantly reduced lead times to delivery compared to if new build facilities had been fabricated. The MOPU is designed to allow for future on-site expansion to accommodate higher production rates, and the FSO can quickly and efficiently be changed out for a larger capacity vessel should greater storage capacity be required. Furthermore, the MOPU and FSO development solution has enabled the Group to save an estimated US$51 million in upfront costs and day rate charges compared to alternative FPSO-based development concepts also considered.

Creating a new production hub offshore south-east Nigeria

Our development strategy is to systematically bring each proven area of the Ebok field onstream, and, through ongoing drilling, continue to increase the reserves base and production from the field over the coming months and years. We plan for the MOPU and FSO to become a central facility, not just for the immediately surrounding Ebok structure, but also for the broader Ebok/Okwok/OML 115 area. This will facilitate the economical and rapid tie-back of production from potential future developments on the acreage.

2012 Outlook

Afren and Oriental plan to drill a further four horizontal production wells from the West Fault Block location in 2012. These will target proved oil bearing zones that were not captured by the initial phases of field development work. The field partners also plan to drill an exploration well on the Ebok North Fault Block during the first half of the year.

Overview

Okwok is an undeveloped oil field located in OML 67, 50 km offshore in 132 ft of water and in close proximity to the Afren/Oriental-owned Ebok development. The field was discovered by the ExxonMobil/NNPC JV in 1967 (Okwok-1), and two subsequent appraisal wells were drilled in 1968 (Okwok-2 and Okwok-3), but not production tested. The Okwok-1 and Okwok-2 wells encountered over 150 ft of oil pay. The Okwok-9 appraisal well was spudded during August 2010 by Afren and Oriental, and reached a total measured depth of 8,083 ft. The well was completed over a 35 ft interval with average porosity of 30% and flowed 31° API crude oil. This confirmed the field as a commercial development project.

The Group completed an Ocean Bottom Cable 3D seismic survey over the whole Ebok/Okwok/OML 115 area in November 2011, acquiring in total 348 km2 of new, high quality data. Processing of the new data is under way and expected to be completed by the second quarter of 2012. One of the primary purposes of the new data is to assist in development planning for the Okwok field, alongside determining the optimal placement of one further appraisal well.

2012 Outlook

Afren and its partner Oriental intend to drill one further appraisal well at the Okwok field during the second half of 2012, ahead of formal submission of a Field Development Plan to the Nigerian authorities. The most likely development scenario for Okwok comprises the installation of a separate dedicated production processing platform tied back to and sharing the existing 1.2 mmbbls capacity Ebok Floating Storage Offloading vessel (FSO) located approximately 13 km to the west.

Completion of a landmark transaction by FHN

On 1 December 2011, First Hydrocarbon Nigeria (FHN), in which Afren is a 45% shareholder, announced that it had completed the acquisition of a 45% interest in the OML 26 licence onshore Nigeria from the Shell Petroleum Development Company of Nigeria Ltd (SPDC), Total E&P Nigeria Ltd (Total) and Nigeria Agip Oil Company (Agip), together with the SPDC Joint Venture. FHN also announced that it had reached completion on financing facilities totalling US$280 million enabling it to fully fund the acquisition cost and its share of future capital requirements associated with the initial development of the block. FHN is partnered in the re-development of the block with Nigerian Petroleum Development Company (NPDC), the oil and gas exploration and production subsidiary of Nigerian National Petroleum Company (NNPC).

A major redevelopment opportunity with substantial upside

The Ogini and Isoko fields are currently producing from a limited number of currently active drainage points. Several wells are currently shut in and there is significant potential for further redevelopment. Under the proposed development plan, initial work is focused on certain 'quick-win' opportunities including low-cost workovers of existing wells and re-activation of gas lift to existing wells. From the existing wells, the Block attained production of 10,500 bopd with optimised compressor uptime in December 2011, which the partners will seek to sustain going forward. The partners will next seek to mobilise a land rig to the field location in order to commence drilling new development wells and undertake de‑bottlenecking work of surface facilities.

Significant upside potential also exists at the undeveloped Aboh, Ovo and Ozoro discoveries, together with an estimated 615 mmboe gross unrisked prospective resources defined across multiple prospects that will continue to be worked up in parallel to, and integrated with, future development plans.

2012 Outlook

The proposed forward work programme (including facilities upgrade) is expected to sustain optimised production in 2012 and increase production to more than 40,000 bopd through phased development over the next four years.

Kurdistan Region of Iraq - a world class petroleum play

2011 saw the Group expand its geographic footprint to encompass the Kurdistan region of Iraq, through the acquisition of a 60% participating interest in the Barda Rash PSC and 20% participating interest in the Ain Sifni PSC. The Kurdistan region of Iraq represents an attractive upstream opportunity set for Afren. The region is geologically, part of the world's most prolific petroleum system, the Zagros Fold Belt trend. This extends across all of the Middle East's most productive regions and accounts for 60% of the world's proved oil and gas reserves.

The Kurdistan region of Iraq is a heavily under-explored component of this play, with only a small portion of licensed acreage and limited number of mapped prospects having been drilled to date. Despite this, drilling results so far have yielded exploration success rates in excess of 70% and discovery rates of over 200 million barrels per well. This justifies its status as a fast emerging region of global oil and gas importance. Estimates for 'yet to find' resources in the region are substantial, ranging from 40 billion to 70 billion barrels. This potential has not gone unnoticed, with the region continuing to attract the attention of the global oil Majors as competition for acreage intensifies.

A large scale development project

The Barda Rash PSC is located 55 km north west of Erbil, and holds the 14,015 mmbbls STOIIP/1,433 mmbbls gross recoverable Barda Rash oil field (split approximately 471 mmbbls light oil and 962 mmbbls heavier oil). The field is defined as an elongated anticline with surface expression of 20 km length and up to 7 km width. The reservoirs are fracture carbonates of various depositional settings.

In 2009, the BR-1 discovery well was drilled to 3,300 m and successfully encountered oil in Cretaceous to Jurassic reservoirs. Well tests were carried out on the Jurassic Mus and Adaiyah formations, each yielding rates of around 3,200 bopd, with a subsequent extended test of the BR-1 well producing 440,000 barrels of 30° to 32° API oil over a three-month period. During this time, oil was trucked from onsite storage and sent to local refineries. Export pipeline infrastructure is located approximately 55 km from the field location and has capacity available. Two further wells were drilled at the field in 2010 - BR-2 and BR-3 - both encountering oil full-to-base in all reservoirs. No oil water contact has yet been established. The field is defined by 330 km of good quality 2D seismic data.

2012 Outlook

In December, Afren received all necessary approvals of the Field Development Plan (FDP) for Barda Rash. The Group plans to undertake a phased development of the field with production start-up scheduled in 2012. Work is now focused on the development of the light oil reserves, the first stage of which comprises re-entering the three existing wells that have been drilled at the field to date, completing them as production wells and commissioning a modular early production system. Production will be trucked to nearby pipeline export points and ultimately in the third phase, be exported via the planned Taq Taq to the Ceyhan export pipeline. The Group will then commence the drilling and completion of multiple new development wells with the intention of increasing production to a planned trucking capacity of 35,000 bopd and ultimately to a targeted 125,000 bopd by 2017. Following this, the Group will focus on the development and production of the heavier oil resources, which will offer further large scale production growth.

Production at Block CI-11

Full year 2011 gross production at Block CI-11 was approximately 3,200 boepd, comprising an oil rate of 831 bopd and natural gas rate of 14 mmcfd. Production levels were below expectation during the year due to the impact of political and social unrest. This delayed importation of equipment and resources required for routine maintenance of the compressor unit during the first quarter of 2011.

2012 outlook

We continue to evaluate our strategic and operational options.

Overview

Afren is the sole owner of the Lion Gas Plant, which processes gas from the CI-11 and adjacent CI-26 and CI-40 blocks operated by Canadian Natural Resources. The plant has an inlet capacity of 75 mmcfd and strips gasoline and butane from the rich gas stream it receives. The butane is sold into the local market (meeting approximately 35% of domestic butane demand) and gasoline is spiked into the CI-11 crude stream and sold on the international market. The LGP plant benefits from tax-exempt status, delivering 618 boepd average NGL production in 2011. Production levels were below expectations during the year, due to the impact of political and social unrest in the first half of the year.

2012 outlook

The Group continues to evaluate methods to extract propane at the plant, which could be sold locally to industrial customers.

Exploration

Low risk, quick to monetise

Overview

OML 115 surrounds the Ebok and Okwok development area, where Afren is also partnered with Oriental, and is close to the giant Zafiro Complex in Equatorial Guinea. The block offers us an attractive opportunity to further capitalise on our extensive knowledge of the area, exploring the same reservoirs that have already been proved as oil bearing and productive at Ebok and Okwok. The southern portion of the Okwok structure (Okwok South) extends into OML 115 and additional prospectivity has already been defined within the deeper Que Iboe, Biafra and Isonga formations. With production processing, storage and export infrastructure in place at the Ebok field, we have a readily available export route for any potential future development in the area. At the same time, we will be able to benefit from cost synergies, lowering the economic threshold for new barrels.

2012 Outlook

Following the completion of the Ocean Bottom Cable 3D seismic over the whole Ebok/Okwok/OML 115 area on 4 November 2011, the partners plan to drill an exploration well on the block during the second half of 2012, potentially targeting the Ufon prospect. The Ufon prospect is a three-way dip closed structure that is interpreted to have oil prospectivity in the same D Series reservoirs that have proven to be oil bearing at the nearby Ebok and Okwok fields among other intervals.

Overview

The Ain Sifni PSC is located 70 km north-west of Erbil, and operated by Hunt Oil Middle East. Drilled on the crest of the Simrit anticline in 2010, the JS-1 discovery well logged continuous oil pay from 1,110 m to 3,070 m in Cretaceous and Jurassic reservoirs. Triassic reservoir targets were not penetrated by the well and no oil water contact was established.

The PSC has substantial upside over and above the volumes discovered to date at the Simrit structure, with prospective resources independently estimated at 7,493 mmbbls STOIIP and 917 mmbbls recoverable on a gross unrisked basis. This is primarily attributed to as yet undrilled parts of the Simrit structure and the Maqlub prospect that is interpreted to be the Westerly extension of the proven Barda Rash anticline.

2012 Outlook

The operator, Hunt Oil, spudded the Simrit-2 exploration well at the end of October 2011. The well is seeking to prove and test Cretaceous, Jurassic and Triassic reservoirs at the western extent of the Simrit anticline structure and is drilling ahead in accordance with the planned schedule. Once this is completed, the partners intend to proceed with drilling further exploration wells targeting the East Simrit, Maqlub and Betnaar structures.

Exploration

Moderate risk, proven play concepts

Overview - prime acreage in an exciting exploration fairway

The Keta Block is located in the Volta River Basin in Eastern Ghana, next to the maritime boundary with Benin. The block has both Tertiary and Cretaceous prospectivity, with the principal exploration focus being the Cretaceous Albian to Campanian sections. The block offers multiple prospects and leads, with a variety of trapping and depositional settings. A number of these show potential for significant stratigraphic trapping and giant field potential.

In October 2011, we announced the formal completion of the farm out of a 35% working interest and transfer of operatorship to Eni. Under the terms of the farm out, Afren will receive a carry through the drilling of one exploration well, back costs and carry through future seismic acquisition. A milestone bonus is payable upon the achievement of first oil on the block.

2012 Outlook

Post period end on 6 February 2012, Afren announced that Eni had commenced drilling of the Nunya-1X (formerly named Cuda-2) exploration well with the Marianas semi-submersible drilling rig. The Nunya prospect is a four-way dip closed structure with a primary reservoir target comprising Upper Cretaceous deep-marine fan sandstones. These are analogous to those that have yielded significant discoveries elsewhere along the West Africa Transform Margin.

Overview

OPL 310 is located in the Upper Cretaceous fairway that runs along the West African Transform Margin and lies next to the Chevron-operated Aje field, which has been declared commercial. Extending from the shallow water continental shelf to deep water, the block represents an exploration opportunity in an under-explored basin with a proven working hydrocarbon system. It is also in close proximity to the recently completed West African Gas Pipeline (WAGP) which allows future gas discoveries to be readily developed. We have good seismic coverage of the block in the form of a 307 km2 3D survey and 483 km of 2D data, which has been integrated with new electromagnetic gravity data that the partners acquired in 2011.

Afren has identified several prospects that lie in the same Senonian, Turonian and Albian sandstone intervals that have yielded significant discoveries along with the West African Transform Margin in Ghana and Côte d'Ivoire.

2012 Outlook

The Group intends to drill an exploration well in 2012 and has plans in place to acquire additional seismic data.

Overview

The JDZ Block 1 extends over approximately 700 km² in water depths ranging from 1,600 m to 1,800 m. One discovery has been made on the block with the sole exploration well that has been drilled to date. In 2006, the Obo-1 exploration well encountered 150 ft of net pay and importantly proved a working hydrocarbon system in the JDZ. The proximity of Total's operated licences and production facilities in Nigeria creates strong synergies and will enable cost reductions in any potential future development of the licence's resources.

2012 Outlook

Total is seeking to reprocess existing seismic data and has proposed the drilling of one appraisal well on the Obo discovery and one exploration well in 2012. Afren has a 4.41% interest. The first well in this campaign was spudded during March 2012 with the West Polaris drill ship.

Overview

The La Noumbi permit is located onshore Congo Brazzaville, to the north and on trend with the large producing M'Boundi oil field. The partners have entered the next exploration phase on the block.

2012 outlook

Following interpretation of depth processed 2D data on the block, two prospects have been identified and the operator has proposed drilling these in 2012.

* With rights over an additional 15%.

** Source: NSAI.

Overview

CI-01 has a proven petroleum system in multiple reservoirs within the Cretaceous. Both oil and gas have been found and tested in the Ibex and Kudu fields, while only gas has been found in the Eland field. Most of the oil and gas encountered is in reservoirs that are younger than the Albian structural closures targeted in the past. There are 3D seismic surveys covering Ibex, Kudu and Eland, and a 2D seismic grid covers the rest of the block. CI-01 borders the maritime boundary with Ghana, and lies adjacent to the major Jubilee and Tweneboa oil and gas discoveries made in recent years.

By applying the latest understanding of Cretaceous depositional systems to the existing well and seismic dataset, to redefine the distribution of oil and gas in existing discoveries on the block, we believe that the potential exists for these accumulations to be significantly larger than originally mapped.

2012 outlook

The partners plan to acquire more 3D seismic over the block.

* Subject to customary approvals; working interest increases to 50% and operatorship transferred to Afren upon completion of seismic acquisition programme.

Overview

Block 2B is located in the Orange River Basin, an offshore shallow water area lying between the Ibhubesi gas field and the Namaqualand coast. The block covers an area of approximately 5,000 km2 with water depths ranging from shore line to 250 m. The main reservoir objectives are the fluvial and lacustrine sands of the AJ Graben of Lower Cretaceous age, which occur in three sequences. The A-J1 exploration well, drilled in 1989, successfully encountered oil in these sequences and tested good quality 36° API oil. Reprocessing of 2D seismic data has since defined several other Lower Cretaceous rift graben prospects, genetically analogous to the prolific Lake Albert play in Uganda. Further prospectivity has also been identified within a fractured basement play (analogous to Yemen), which could form a secondary exploration play on the acreage.

2012 outlook

The partners' near-term work programme involves the acquisition of 600 km2 of new 3D seismic data, with reprocessing of existing 2D seismic and ongoing seismic inversion and regional biostratigraphy studies ahead of expected exploration drilling in 2014.

OPL 907 and 917 offer potentially attractive Cretaceous opportunities. The main hydrocarbon plays consist of late Cretaceous deltaic to shallow marine clastics in fault related traps. Having acquired the original seismic tapes and reprocessed the data, Afren is continuing to evaluate the potential of the blocks in order to identify areas for future seismic acquisition that could ultimately lead to future exploration drilling.

2012 Outlook

Having acquired the original seismic tapes and reprocessed the data, Afren is continuing to evaluate the potential of the blocks in order to identify areas for future seismic acquisition that could ultimately lead to future exploration drilling.

Exploration

Frontier areas with major play opening potential

East Africa

Our portfolio of 11 East African assets covers an extensive surface area of 111,460 km2 on a gross basis, and all are located in basins with strong evidence of working hydrocarbon systems being present. Afren East Africa Exploration is focused on onshore rift basins and the deepwater Cretaceous/Tertiary play systems which are geological settings that have yielded significant discoveries in Uganda, Sudan, Tanzania, Madagascar and Mozambique. A number of prospects have already been defined to date across the acreage, where the potential also exists to establish new hydrocarbon plays and additional prospectivity.

* EAX is a wholly owned subsidiary of Afren Plc.

Overview

Block 1 is located on the western margin of the Mandera-Lugh basin in north-eastern Kenya bordering both Somalia and Ethiopia, where it is connected to the Ogaden basin. The Upper Triassic and Jurassic formations that have been identified are considered to be the primary zones of oil prospectivity. An oil seep close to the Tarbaj-1 well in the south-west corner of the block confirms the presence of hydrocarbons. Analogous data with the Ogaden basin also suggests there may be other potential source rocks and reservoirs. The Bur Mayo and the Kalicha-Seir formations in the Mandera-Lugh basin appear comparable to the Lower and Upper Hamanlei (Jurassic) formations in the Ogaden basin. If analogous, these formations should have high total organic content (TOC) source rocks and good quality reservoirs.

Several major structures have already been mapped on the block, that currently has 850 km of existing 2D seismic coverage. During the first half of 2011, the partners successfully acquired airborne gravity and magnetic data, the results of which have been encouraging and have been used to target an additional 1,800 km of 2D seismic data on the block.

2012 outlook

The partners on Block 1 have commenced the acquisition of the planned 1,800 km of 2D seismic data and are targeting completion of this and further seismic interpretation during 2012.

Overview

Block 10A is located in the Anza Basin onshore northern Kenya, which is part of the Central African Mesozoic rift system that also includes the Muglad Graben in Southern Sudan, and the Lamu Graben in Kenya. The block covers a total of 14,747 km2. Three exploration wells were drilled by Amoco in Block 10A (Sirius-1, Bellatrix-1 and Chalbi-3) throughout 1988 and 1989, in the southern part of the block. The presence of oil and gas shows and the high maturity level of organic rocks in wells Bellatrix-1 and Sirius-1 are evidence of a working hydrocarbon system on the block. The latter well notably established the presence of an Upper Cretaceous lacustrine source rock that may have generated low-sulphur/paraffinic oil.

2012 outlook

Having satisfied all seismic work commitments with the acquisition of 750 km of 2D seismic over the block in 2011, the operator (Tullow Oil) will commence the drilling of one exploration well on the Paipai prospect. The drilling rig is now scheduled to arrive at the field location later than planned, which means that the well is expected to spud in mid-2012.

* EAX is a wholly owned subsidiary of Afren Plc

Overview

Blocks L17 and L18 are located in the Lamu Coastal Basin, offshore south-east Kenya, covering an area of approximately 1,275 km2 and 3,630 km2 respectively. They are situated in water depths varying from a few metres along the shoreline to up to around 500 m.

There are several potential source rocks for the Cretaceous plays in the southern areas of the basin including the Premo-Triassic Karoo interval and sections within the Lower to Middle Jurassic. There are oil seeps in the Lamu Basin and Pemba Island linked to a Jurassic source which implies that the structures in Blocks L17/L18 are most likely oil bearing. Although there may be additional potential in clastic reservoirs within the Tertiary, the main reservoir targets are in the Upper Cretaceous. The hydrocarbons are expected to have been generated in the deep Pemba trough south of Block L18.

Following completion in 2010 of a 400 km short offset shallow 2D seismic acquisition programme in the Shimoni area of Block L18 and in the Mombasa area of Block L17, a number of newly defined prospects and leads have been identified on the acreage.

2012 outlook

The Group has completed the acquisition of additional 2D seismic data targeting the deepwater region of the block and plans to drill one exploration well targeting the coastal play in the second half of the year, and is currently trying to source an appropriate rig.

Overview

On 24 March 2011, Afren expanded its East African footprint with the acquisition of a 74% operated working interest in the Tanga Block, located offshore and onshore north-east Tanzania. The block lies south of, and is contiguous with, Afren's 100% owned and operated blocks L17 and L18 in Kenya. It contains a southerly extension of the same coastal high and basin trough plays allowing us to leverage our regional expertise and knowledge.

The block is covered by 200 km of legacy 2D seismic data, and 1,200 km of good quality new 2D seismic data. Immediately post completion, Afren undertook and completed a 751 km shallow water 2D seismic programme. The results of this survey have been encouraging, and provide excellent definition of several large scale prospects and leads that have been identified to date, together with new zones of additional potential.

During Q4 2011, over 900 km of deepwater 2D seismic was acquired. This is currently being processed with final results expected at the end of the Q1 2012.

2012 outlook

The Group plans to acquire 3D seismic data in the deepwater and to drill the Orpheus prospect in 2012 from a shallow water offshore location and is in the process of securing a jack up drilling rig capable of this work.

* EAX is a wholly owned subsidiary of Afren Plc

Areas A,B,C

Areas A, B and C are located in the Seychelles micro-continent and cover a combined area of approximately 14,964 km2. Areas A and B are located in shallow to deep water in the northern half of the Seychelles plateau while Area C is in shallow water to the south. The main exploration targets are the Permo-Triassic Karoo interval which comprises non-marine sands inter-bedded with shales and a Cretaceous marine rift basin underlain by Jurassic platform source rocks. The Karoo formation contains both the source rock and the reservoir. Over 1980 - 1981, three exploration wells were drilled, all of which encountered oil shows and confirmed the presence of a working hydrocarbon system. Over 3,500 line of km of 2D seismic data was acquired over areas A and B in the fourth quarter of 2012 and is currently being processed.

2012 outlook

Seismic data acquired to date by the partners has revealed the presence of several large scale structures in all three licence areas, in addition to new basins that could also contain significant Jurassic and Cretaceous sedimentary sections.

Overview

Block 1101 is located on the eastern flank of the Ambilobe basin onshore northern Madagascar. The block encompasses an area of approximately 14,900 km2. Some 220 km of 2D seismic has been acquired over the block to date. The main exploration targets are sands of the Isalo formation. There are proven heavy oil accumulations in the Isalo formation in Central Madagascar such as Bemolanga and Tsimiroro, indicating good reservoir conditions.

Having increased its working interest to 90% through the reassignment of a 50% from partner Candax Energy, the Group has agreed with state oil and gas agency OMNIS an expanded work programme that combines the first two exploration phases on the block and requires the drilling of one exploration well to a minimum depth of 1,600 metres. The partners have also agreed to acquire an additional 150 km of new 2D seismic and airborne gravity and magnetics. The airborne gravity and magnetic acquisition has been undertaken and is currently being processed.

2012 outlook

The expanded work programme combines the first two exploration phases on the block and requires the drilling of one exploration well. The partners have also agreed to acquire an additional 150 km of new 2D seismic. Drilling is expected in 2013.

Overview

In 2011, Afren and its partners decided to relinquish Blocks 2 and 6 in order to focus future exploration activities on Block 7 and 8.

Blocks 7 and 8 are located in the Ogaden Basin and are both part of the same PSC covering an overall area of 23,162 km2. Exploration in the Ethiopia area began in the 1970s with Tenneco discovering the Calub and Hilal gas fields approximately 200 km to the east of Block 6. Exploration continued throughout the 1980s. Three wells, El Kuran-1, El Kuran-2 and Bodle-1, have been drilled on the blocks. Both of the El Kuran wells encountered hydrocarbons and oil was recovered from the Jurassic Hamanlei formation. The main potential reservoirs in the basin are clastic sediments of the Carboniferous age Calub formation and the Triassic age Adigrat formation. In addition, some permeable Jurassic carbonate rocks in the Hamanlei formation can be considered potential reservoirs.

2012 outlook

Work is ongoing to further interpret the prospectivity of Blocks 7 and 8 ahead of expected drilling in mid 2012.

Financial Review

Record financial results

During the period turnover increased by 87% to US$597 million (2010: US$319 million), reflecting increased production volumes year-on-year and the effect of higher realised oil prices. Profit before tax increased by 180% to US$221 million (2010: US$79 million) with profits after tax increasing by 172% to US$125 million (2010: US$46 million). Cash flow from operations during the period increased by 62% to US$338 million (2010: US$209 million), emphasising reflecting the underlying profitability of the Group's production base.

Financial highlights

Turnover of US$597 million, an increase of 87% from the previous year (2010: US$319 million)

Realised oil price of US$109.0 per barrel and gas price of US$8.8 per mcf (2010: US$79.7 per barrel and US$5.7 per barrel)

Gross profit for the year of US$302 million, an increase of 134% on the previous year (2010: US$129 million)

Profit after tax for the year from continuing operations of US$125 million, an increaseof 172% on the previous year (2010: US$46 million)

Normalised profit after tax* of US$125 million, an increase of 100% on the previous year(2010: US$62 million)

Cash flow from operations of US$338 million, an increase of 62% from the previous year(2010: US$209 million)

Oil and gas additions in the year of US$576 million, an increase of 31% from the previous year (2010: US$437 million) (excluding finance leases and the acquisition of the interests in Barda Rash and Ain Sifni in 2011 and of Black Marlin in 2010, and including capitalised interest)

Debt repayments of US$182 million, with outstanding principal at US$868 million(excluding amortised issue costs)

Cash position of US$292 million, net debt (excluding finance leases) of $548 million(2010: cash of $140 million, net debt of $128 million)

Gearing at year end of 45% (2010: 15%)

* Excluding the effect of unrealised hedge movements, share related charges, finance costs, fair value gains and losses on financial instruments and foreign exchange movements. See note 9 of the attached financial information for a full reconciliation of this figure.

1. Result for the year

Revenues

Revenue for 2011 was US$596.6 million an increase of 87% from 2010. The increase in revenue arises from the start of production from the Ebok field in the year (US$272.0 million) partly offset by the reduced working interest on the Okoro field. Working interest production for the year increased to 19,154 boepd from 14,333 boepd in 2010 due to the start of production from the Ebok field in 2011, offset by the Group reaching payback on the Okoro field which, as expected, saw our interest reduced from 95% to 50% in mid 2010.

The Group realised in 2011 an average oil price of US$109.0/bbl and an average gas price of US$8.8/mcf (2010: US$79.7/bbl and US$5.7/mcf), before all royalties. The average price for Brent in the period was US$109.0/bbl (2010: US$79.5/bbl).

Gross profit

Gross profit for the year was US$302.3 million, an increase of 134% on the prior year (2010: US$129.0 million), largely related to the commencement of production at Ebok and higher realised prices at the Okoro field. The DD&A charge for oil and gas assets in 2011 was US$155.4 million, an increase of 71% on the prior year (2010: US$90.5 million). The increased charge relates to the start of production at Ebok.

The increase in crude oil stock at the year end resulted in a credit for stock adjustment of US$25.4 million, compared with a charge of US$9.5 million in 2010.

The Group achieved a normalised operating cost of US$17.9/boe, a decrease of 1% over 2010 (2010: US$18.1/boe). This was largely due to: efficiencies generated in reaching full production at Ebok being offset by; a decrease in gross production at Okoro and an increase in operating expenditure following the completion of initial development in mid-2010. Normalised cost per barrel includes costs and production from Ebok from Q4 onwards. All other field costs are included on an annualised basis.

Profit for the year

Profit after tax on continuing activities for the year ended 31 December 2011 was US$125.4 million (2010: US$45.9 million). Normalised profit after tax was US$125.1 million. See note 9 to the attached financial information for a full reconciliation of this figure (2010: US$62.4 million).

The impairment charge on oil and gas assets was US$1.1 million (2010: charge US$1.6 million) largely reflecting the relinquishment by Afren of its interest in Ethiopia Blocks 2 and 6. The low level of impairment reflects the ongoing success of the Group's exploration and appraisal programme.

Finance costs for 2011 were US$57.1 million (2010: US$11.3 million). The increase in finance costs relates to the issue of a new Bond in January 2011; and early redemption fees of US$2.5 million arising from the settlement of the Group's historical facilities, as well as increased interest charges relating to the Bond issue and further drawdowns on our Ebok facility during the year. The Group capitalised US$46.9 million of finance charges in the year, largely as part of the Ebok project financing (2010: US$13.6 million).

During the year we recognised a loss from derivative financial instruments of US$12.5 million (2010: US$8.9 million) relating to crude oil hedging contracts. This reflects a realised loss of US$9.3 million (2010: US$2.4 million loss) as the oil price realised averaged consistently above the hedged price during the year. There was a further mark to market loss of US$3.2 million (2010: loss of US$6.5 million) on the unrealised positions due to further strengthening in the oil price from around US$90 per barrel at the start of the year to over US$108 per barrel at year end.

Associate investment in FHN

In 2010, a gain of US$10.0 million arose as a result of new funding raised by FHN's other shareholders increasing the equity share attributable to Afren. Similar gains totalling US$14.7 million have arisen during 2011, as well as a gain of US$8.0 million relating to the increase in value of certain equity options in FHN held by Afren, driven by an increase in the underlying value of FHN.

Afren's share of FHN's loss for the year was US$14.0 million (2010: US$1.3 million loss), reflecting costs incurred in the development of FHN's interest in OML 26 during the year. This loss is offset by income received from FHN of US$6.3 million (2010: US$nil) in relation to various management and support services provided by Afren.

Taxes paid in the year

The income tax charge for the year is US$96.0 million (2010: US$32.9 million). The increase reflects the increased profitability of the Group in 2011. Of this, US$8.1 million (2010: US$0.9 million) has been paid locally in Nigeria in respect of income from Okoro. The balance of current tax will be paid in 2012 with the deferred tax liability spread over the life of the field.

In addition, the Group pays other taxes in the form of royalties, withholding taxes, and non-recoverable VAT locally in Africa. In 2011 these amounted to US$166.5 million (2010: US$83.2 million) - as a percentage of revenue this represents 28% (2009: 26%).

2. Financing the Group's activities

Net cash generated from operating activities in 2011 was US$337.5 million (2010: US$209.3 million), and this cash has been used, alongside financing cash flows primarily to fund the Group's exploration and appraisal activities.

In January 2011, the Company completed a Bond issue, raising US$500 million before issue costs. The coupon on the bonds is 11.5% and they are listed on the Luxembourg Stock Exchange. The Company used part of the funds to repay borrowings amounting to US$171 million of certain pre-existing facilities. In February 2012, the Bond issue was recognised by Euromoney as one of the "2011 Deals of the Year".

A facilities agreement of US$50 million was entered into with Socar Trading S.A. in August 2011, and was fully drawn down at 31 December 2011. The funds received under the Socar loan are used by us for general corporate purposes.

In July 2011, the Company raised US$184.5 million, before commission and expenses by placing 83,679,544 new ordinary one pence shares in the capital of the Company, with institutional investors, at a price of 135 pence per share. The capital was used to acquire a share in the Ain Sifni and Barda Rash licences in the Kurdistan Region of Iraq.

Further payments in connection with the acquisition of the Group's interest in the Ain Sifni block were funded through a US$200 million corporate credit facility provided by BNPP and VTB. US$100 million of this was drawn down in November 2011 and used to fund payments made in December 2011 and March 2012.

Loan repayments in the year, excluding payments in respect of finance leases, were US$182.3 million reflecting early settlement of historical facilities using the proceeds of the Bond issue in February 2011 and periodic payments due under other facilities. Cash at bank at 31 December 2011 was US$291.7 million, resulting in net debt, excluding finance leases, of US$548.3 million (2010: net debt, US$127.5 million).

In 2011 the Group recognised a finance lease in respect of the arrangements with Mercator Offshore Nigeria (Pte) Limited for the production facilities on the Ebok field. This resulted in a finance lease liability at 31 December 2011 of US$135.5 million (2010: US$nil) to be settled in monthly payments of US$2.4 million (including interest) over a seven-year period.

3. Development, appraisal and exploration activities

The Group's investment in appraisal and exploration activities has continued during 2011, with expenditure of US$107 million, excluding the acquisition of the Group's interest in the Ain Sifni PSC of US$164 million (2010: US$74 million, excluding the acquisition of the Black Marlin exploration assets).

The main areas of expenditure were on Okoro East (US$7 million), Okwok (US$10 million), OML115 (US$45 million), OPL310 (US$10 million), the acquisition of a 74% interest in the Tanga block in Tanzania and seismic on the area (US$7 million) and expenditure, largely seismic, on the Group's East African exploration assets (US$18 million).

Development expenditure was US$469 million, excluding the acquisition of the Group's interest in the Barda Rash PSC, largely comprising US$380 million on the Ebok field and US$40 million on the Okoro infill well drilling programme.

The Group's 2P and 2C reserves and resources have increased by 859 mmboe, or 633% as at 31 December 2011 compared to 31 December 2010, largely achieved by the acquisition of the Ain Sifni and Barda Rash PSCs and the continued investment in African assets such as Ebok and Okoro.

There has been minimal write-off of unsuccessful exploration costs (2011: charge of US$1.1 million, 2010: charge of US$1.6 million) following the relinquishment of the Ethiopia Blocks 2 and 6.

4. Acquisitions in the year

In July 2011 the Group acquired interests in two contiguous PSCs located in the Kurdistan region of Iraq. The total amount payable for the acquisition is US$588.4 million (before the discounting of deferred consideration). In parallel the Company announced the successful placement of 83,679,544 ordinary shares, raising a total of £113.0 million (US$184.5 million) before fees which has been used, together with cash and debt resources, to fund the acquisition. Final settlement of the acquisition costs was made in March 2012. The Company also acquired interests in two exploration licenses during the period; the Tanga Block in Tanzania and Block 2B in South Africa.

The Company increased its equity investment in FHN in 2011 through additional investments of US$9.8 million.

5. Our commitments

The Group has operating and capital commitments as at 31 December 2011 of US$537.7 million (2010: US$482.6 million), largely in respect of the lease of rig and field equipment and the ongoing exploration and evaluation programmes. 

6. Bond issue to fund future growth

In February 2012, the Company completed a second Bond issue, proceeds of which were US$300 million before issue costs. The coupon on the bonds is 10.25% and they are listed on the Luxembourg Stock Exchange. The proceeds from the issue of the new Bond have been used to repay and cancel the US$200 million VTB/BNPP facility and for general corporate purposes.

7. Review of our hedging arrangements

In the context of volatile oil prices and with the imminent first oil at Ebok, the Group reviewed its hedging arrangements in early 2011.

The Group previously had taken hedging positions associated with its operations in Okoro and Côte d'Ivoire. These arrangements were synthetic puts which allowed the Group to protect itself from the downside movements in prices while also benefiting from most of the upside. In early 2011 the Group purchased a number of deferred put options. These options allow the Group to sell approximately 5.9 million barrels in the period to 31 December 2013 at an average price of US$82.54/bbl. The average cost of the hedge is US$4.08/bbl giving effective protection to the Group at a price of US$78.46/bbl. The new instruments have been classified as cash flow hedges. Each period the portion of the gains and losses on the hedging instrument that is determined to be an effective hedge are taken to equity and the ineffective portion, as well as any change in time value, is recognised in the income statement. In 2011, a loss of US$9.3 million (realised) and US$3.2 million (unrealised) was taken to the income statement, as a result of realised oil prices in the period and forward curve being higher than the hedged price.

Existing hedges covering 248,000 barrels at a price of US$60/bbl and 339,000 barrels at a price of US$81/bbl expired during 2011. These instruments were not designated as cash flow hedges and gains or losses were taken directly to the income statement in the period.

Since the year end, to take advantage of recent record oil prices, further deferred put options have been acquired. These allow the Group to sell a further 600,000 barrels at US$90 in 2012. In addition the Group has acquired deferred put spreads at US$90 and US$60 covering 1.44 million barrels guaranteeing US$90 per barrel if the oil price is between US$60 and US$90 and a US$30 per barrel benefit if the oil price falls below US$60.

The policy of the Group is to protect its minimum cash flow requirement in the context of a sustained downturn in oil prices. As such the maximum amount of our working interest we would seek to protect with these arrangements is between 20-30% of estimated production for a rolling period of 24 months forward. Our current outlook including the most recent hedge is that we have 28% of 2012 oil barrels hedged and 23% of 2013.

8. Outlook

The operational cash flows achieved from Ebok and Okoro in 2011, together with the proceeds of the January 2011 bond issue and July 2011 equity placing, have remodelled Afren's capital structure and provided the basis for further financial flexibility in 2012. This flexibility has been enhanced by the completion of a second bond issue in February 2012.

Afren has made good progress in 2011 and continues to grow in strength. The Group has assembled a world class portfolio of assets that offers significant potential across the full cycle E&P value chain. Through clear strategic foresight and capitalising on anearly mover advantage in Nigeria, East Africa and the Kurdistan region of Iraq, Afren secured attractive acreage positions in some of the world's most prolific and emerging oil and gas basins. Combined with a good track record of operational delivery and a mature capital structure, this means that Afren is well positioned for further exponential growth.

-

Continued

Notes to the Accounts

For the year ended 31 December 2011

1. Basis of accounting

Whilst the financial information in this preliminary announcement has been prepared in accordance with International Financial Reporting Standards (IFRS) and International Financial Reporting Interpretation Committee (IFRIC) interpretations adopted for use by the European Union, with those parts of the Companies Act 2006 applicable to companies reporting under IFRS and with the requirements of the United Kingdom Listing Authority (UKLA) Listing Rules, this announcement does not contain sufficient information to comply with IFRS. The Group will publish full financial statements that comply with IFRS in April 2012.

The financial information for the year ended 31 December 2011 does not constitute statutory accounts as defined in sections 435 (1) and (2) of the Companies Act 2006. Statutory accounts for the year ended 31 December 2010 have been delivered to the Registrar of Companies and those for 2011 will be delivered following the Company's annual general meeting. The auditor has reported on these accounts; their reports were unqualified, did not include a reference to any matters to which the auditors drew attention by way of emphasis of matter and did not contain a statement under section 498 (2) or (3) of the Companies Act 2006.

The financial statements have been prepared in accordance with International Financial Reporting Standards (IFRS) as adopted by the European Union and therefore the Group financial statements comply with Article 4 of the EU IAS Regulation. The financial statements have been prepared on the historical cost basis, except for the revaluation of certain financial instruments and oil inventory which is subject to certain commodity swap arrangements that have been measured at fair value.

The accounting policies applied are consistent with those adopted and disclosed in the Group's financial statements for the year ended 31 December 2010.

Afren's net production at the 2011 exit rate of approximately 50,000 boepd, together with expected production start-up in Kurdistan in mid-2012 and the fact that exploration expenditure in 2012 will be funded via planned operational cashflows, provides confidence that the Group will continue to generate sufficient working capital for the foreseeable future.

On the basis of the above, the Directors have a reasonable expectation that the Company and Group have adequate resources to continue in operational existence for the foreseeable future. They therefore continue to adopt the going concern basis of accounting in preparing the annual financial statements.

2. Earnings per ordinary share

In 2010, 9.9 million potential ordinary shares were anti-dilutive and were therefore excluded from the weighted average number of ordinary shares for the purposes of diluted earnings per share in 2010. There were no significant anti-dilutive potential ordinary shares in 2011.

3. 2011 Annual Report and Accounts

The Annual Report and Accounts will be mailed on 26 April 2012 only to those shareholders who have elected to receive it.Otherwise, shareholders will be notified that the Annual Report and Accounts is available on the website (www.afren.com).

Copies of the Annual Report and Accounts will also be available from the Company's registered office at 3rd Floor, Kinnaird House,1 Pall Mall East, London, SW1Y 5AU.

4. Annual General Meeting

The Annual General Meeting is due to be held at the offices of White & Case LLP, 5 Old Broad Street, London, EC2N 1DW on

Wednesday, 6 June 2011 at 11.00 am.

5. Segmental reporting

Geographical segments

For management purposes, the Group currently operates in five geographical markets which form the basis of the information evaluated by the Group's chief operating decision maker: Nigeria, Cote d'Ivoire, Other West Africa, Eastern Africa and Middle East and North Africa. Unallocated operating expenses, assets and liabilities relate to the general management, financing and administration of the Group.

* During the year, Exploration and evaluation additions of US$415.4 million in respect of the Barda Rash licence were transferred to oil and gas assets in the Middle East and North Africa segment.

Operating Segments continued

Business segments

The operations of the Group comprise one class of business, being oil and gas exploration, development and production.

Included in revenues for Nigeria for the year ended 31 December 2011 are US$546.5 million (2010: US$286.5 million) which arose from the Group's largest customer.

Non-current assets held in the UK at 31 December 2011 totalled US$3.2 million (2010: US$2.4 million). Non-current assets held in Other West Africa at 31 December 2011 included US$21.7 million (2010: US$20.3 million) relating to Keta Block, Ghana, US$31.1 million (2010: US$30.1 million) relating to the La Noumbi permit in Congo (Brazzaville) and US$18.7 million (2010: US$18.1 million) relating to JDZ Block One in São Tomé & Príncipe. Non-current assets held in East Africa at 31 December 2011 included US$72.7 million (2010: US$62.1 million) related to Block L17/L18, Block 1 and Block 10A in Kenya, US$59.0 million (2010: US$58.4 million) relating to the Ethiopean Blocks 2 & 6 and 7 & 8, US$37.8 million (2010: US$35.6 million) related to the Madagascar Block 1101, US$40.2 million (2010: US$36.2 million) relating to Seychelles Block A, B, C and US$6.8 million (US$nil) relating to Tanga Block in Tanzania.

6. Taxation

The current tax can be reconciled to the overall tax charge as follows:

The detailed mechanics of the Group's tax filing arrangements for certain subsidiaries are subject to agreement with the local tax authorities and while the Group is satisfied that the 2011 and 2010 charge is its best estimate of its tax position, adjustments may be required once these discussions have been finalised.

7. Deferred consideration and payables on acquisitions

US$196.7 million (US$200 million, undiscounted) relating to the acquisition of the 60% participating interest in Barda Rash PSC, Kurdistan Region of Iraq was paid on 7 March 2012 and therefore reported as deferred consideration in the balance sheet as at 31 December 2011. In addition, US$20 million relating to the 20% participating interest on Ain Sifni PSC, Kurdistan Region of Iraq, was outstanding as at 31 December 2011. 

8. Share capital, share premium and merger reserve