Full Year Results

AFREN plc 2010 FULL YEAR RESULTS

Results summary, 29 March 2011 - The Board of Afren plc ("Afren" or "the Company") announces results for the year ended31 December 2010.

In 2010 we made significant progress on the Ebok development, progressed our Nigerian growth strategy and made a strategic exploration-led entry into East Africa. Looking forward, we have a balanced portfolio combining production and development assets that we can leverage to internally fund high impact exploration and appraisal activities, underpinned by a capital structure that will

support a strong acquisition opportunity set.

Osman Shahenshah, Chief Executive of Afren plc, commented:

"2010 was a year of operational delivery and we are delighted to report our first full year profit of US$45.9 million. Looking ahead we are extremely well positioned for the next phase of our growth story. With a 180% growth in production to 40,000 boepd expected in 2011, we will leverage our West African production base to pursue multiple high impact exploration targets in both East and West Africa. In addition, we have the capital structure in place to capitalise on our strategic position in key markets and expect to deliver further accretive acquisitions in 2011."

Analyst Presentation

There will be a presentation to analysts at 09.00 am BST at The London Stock Exchange.

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.

2010 Full Year Results Summary

First full year profit after tax

Full year profit after tax of US$45.9 million. Strong realised oil prices during the period benefited revenues which, together with reduced depreciation, depletion and amortisation (DD&A) and finance charges, substantially offset lower net volumes, having reached payback on Okoro. Afren's financial profile will be further strengthened in 2011, with ramp up of production at the Ebok field.

Strong production growth outlook

2010 production reflects both the earlier than anticipated achievement of cost recovery at the Okoro field, due to strengthening oil prices during the period and natural reservoir depletion. Net production is expected to average 40,000 boepd during 2011, through production ramp up at the Ebok field and the impact of two infill wells at the Okoro field, where we are moving towards the 3P recovery case. OML 26 has the potential to add significantly to volumes as First Hydrocarbon Nigeria (FHN) moves towards completion and seeks to progress with re-development of the Ogini and Isoko fields.

Net reserves and contingent resources

Total net working interest 2P reserves and contingent resources at 31 December 2010 have been independently estimated by NSAI at 135.7 mmboe, representing an increase of 23 mmboe (20%) year-on-year. This increase is due predominantly to the successful Okwok-9 appraisal well, confirming commercial gross recoverable volumes of 51.8 mmbbls at the field.

Acquisition of a major onshore Nigerian portfolio

The acquisition of OML 26 by FHN, with Afren acting as FHN's technical partner, represents a key milestone for our long term Nigerian growth strategy. Transitioning of operational handover to FHN and Afren is almost complete and customary approvals are anticipated shortly. We are well positioned to implement a phased re-development plan to ramp up production at the Ogini and Isoko fields to 50,000 boepd, and rapidly monetise the significant E&A upside potential that also exists on the block.

Portfolio growth focused on high quality acreage

During the period from January 2010 to March 2011 the Company acquired 16 assets and entered 6 new countries. We will continue to seek under-developed or overlooked opportunities where Afren is competitively and strategically advantaged, and can leverage its track record and expertise to access and monetise reserves and resources at a low unit cost.

Portfolio management

In Ghana, we farmed down a 35% interest and operatorship in the Keta Block to ENI in return for a full carry through the drilling of one exploration well, contribution to back costs and future seismic acquisition. Post farm down, Afren will retain a 35% interest in the block. Other partners on the block are GNPC (10%) and Mitsui E&P Ghana Limited (20%). The farm down is subject to customary government and partner approvals.

Exploration and appraisal upside

Following a period of significant expansion to our exploration portfolio, we now have an established presence in three core exploration fairways - the West African Transform Margin where we are focused on large scale potential in the Upper Cretaceous; the Niger Delta where we are particularly focused on low risk, amplitude supported upside around the core Ebok/Okwok/OML 115 area; and the East African rift systems and coastal basins where we have identified major prospectivity across Permo-Triassic to Tertiary aged sequences and have multiple potentially play-opening drilling targets. In 2011, Afren will participate in up to 10 exploration and appraisal wells targeting a total net mean prospective resource base in excess of 630 mmbbls (1,150 mmbbls gross).

Capital structure in place to pursue M&A growth opportunities

Afren became the first UK listed independent E&P company to access the bond market in 2011, raising a total of US$500 million and in the process diversified its sources of capital. With forward E&A capex internally funded, and significant additional working capital available, the Company's ability to capitalise on M&A growth opportunities has been greatly enhanced.

Outlook

Afren has achieved significant portfolio growth, and shown innovation in accessing new sources of capital. We expect 2011 to be another defining year in the history of Afren, characterised by strong production growth and an internally funded E&A drilling campaign, whilst continuing to capitalise on a strong acquisitions pipeline.

Review of Operations

Production

An established platform in place

Afren produces oil, natural gas and natural gas liquids from its upstream and midstream operations in Nigeria (Okoro and Ebok) and Côte d'Ivoire (CI-11 and Lion Gas Plant). We have undertaken infill drilling at Okoro to deliver incremental production volumes in 2011, commenced production operations at the Ebok field where we will continue to grow production and announced the acquisition of an onshore portfolio at OML 26 in Nigeria with our indigenous partner FHN.

Delivering new production

In February 2011, we successfully installed the production processing and storage facilities and commenced production operations at the Ebok field, located offshore south east Nigeria. We have adopted a phased approach to the field development. Phase 1 is targeting the Central Area of the field, and Phase 2 the West Fault Block area of the field. Together, these initial phases will access around only 60% of the 2P reserves base established to date, with a rolling development programme planned for the outstanding 2P reserves, in addition to testing the significant upside potential that exists on as yet un-drilled parts of the field.

In December, we successfully tested three out of five horizontal production wells that were drilled throughout 2010 as part of Phase 1. A combined aggregate rate of 12,500 bopd 24° API oil was achieved with excellent reservoir properties of 30% to 35% porosity and multi-Darcy permeability also established. The results provide a strong indication that, together with the remaining production wells, our expectation of Phase 1 production plateau at 15,000 bopd should be exceeded. Phase 2 development drilling consists initially of four horizontal production wells and up to two water injection wells. The wells are being sequentially drilled, completed and bought onstream over the course of the second quarter and are expected on aggregate to boost field output by 20,000 bopd, taking total field production to in excess of 35,000 bopd. Ongoing development beyond Phase 2 is expected to add further incremental volumes.

Fast track development solution

The selected development solution for the field incorporated two un-manned wellhead platforms, one positioned in the Central Area and one at the West Fault Block, tied back to a Mobile Offshore Production Unit (MOPU) where crude oil is processed, from where it is then piped to a Floating Storage Offloading vessel (FSO) spread-moored nearby, where it is stored prior to sale directly into the international market.

The MOPU is a former jack-up drilling rig that has been converted to a production facility by removing the drilling package and replacing it with a processing unit. The facility has the initial capacity to handle oil production of 50,000 bopd, and has been designed to allow for onsite expansion and upgrade to accommodate production from future additional development phases. The advantages of utilising a converted jack-up were many; the installation of the unit did not require a derrick barge, and it could be installed whilst drilling operations were in progress, allowing for simultaneous installation and drilling with minimal interruptions to work.

The FSO provides a storage volume in excess of 1.2 mmbbls, which allows for the sale of million-barrel cargoes that in turn provide us with maximum flexibility to optimise shipping and crude marketing economics. Similarly, the vessel was converted from a pre-existing tanker, greatly reducing lead times to delivery compared to if a new build vessel was commissioned. Furthermore, opting for the MOPU and FSO development configuration has provided an estimated total cost saving of US$51 million in upfront costs and day rate charges compared to alternative FPSO development solutions that were considered.

Progressive de-risking of upside potential

The Ebok Deep exploration well was drilled in Q2 2010 and intersected two sandstone intervals of 370ft 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.

Creating a new production hub offshore south east Nigeria

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

2011 activity

The year ahead will see ongoing development beyond Phase 2 aimed at the proved undeveloped reservoirs in the Central Fault Block and Southern Lobe of the West Fault Block. We are also planning further exploration and appraisal drilling at Ebok North, an untested fault block in the northern area of the field, where we believe the same reservoirs that have been proved to be oil bearing elsewhere at the field are also present.

Strong production performance

By the end of 2010, the Okoro field had produced 13.9 mmbbls of oil. Production averaged 16,055 bopd throughout the year. There was a planned shutdown in the fourth quarter in order to undertake routine maintenance work which resulted in a modest impact on gross output at the field during that period of 252,045 bbls. Field performance remained ahead of pre start-up expectations and is due to:

• water breakthrough from the existing production wells occurring much later and at lower levels than predicted;

• better reservoir quality than incorporated into the original field simulation model; and

• good aquifer support, evidenced by production history to date.

Infill drilling to access incremental oil volumes

By constantly monitoring the production performance of each well and reservoir conditions, and maintaining a dynamic reservoir simulation model, we have been able to identify particular zones in the Lower Sand where sweep efficiency could be further improved upon and additional incremental oil volumes accessed. In order to achieve this we commenced an infill drilling campaign in November 2010 utilising the GSF High Island Vll jack up drilling unit. Two infill wells are currently being drilled up-dip from the existing Okoro-4 and Okoro-5 production wells.

Taking all of this and production during the period into account, NSAI has estimated gross remaining 2P reserves at the Okoro field to be 19.5 mmbbls as at 31 December 2010.

Operational efficiency

The off-take and export of the crude oil produced at Okoro continues to run smoothly and without interruption. Having implemented a change in our export process in November 2009, whereby we are now using a shuttle tanker to transport the processed Okoro crude to the Amni operated Ima terminal, we have continued to benefit from the increased flexibility and storage capacity of over 1 mmbbls which translated into improved shipping and sales economics.

To date, production uptime has been maintained at 95.3%. During November a security breach occurred on the GSF High Island Vll drilling rig, as it prepared to spud the infill wells, and also at a support vessel. Seven hostages were taken for a period of ten days, after which they were released unharmed. Following the incident a full review of security measures and procedures was undertaken at the field, the results of which have been incorporated into our broader risk management process. Production at the field was uninterrupted by the incident.

2011 activity

Having successfully drilled two infill wells, work in 2011 is firmly focused on ensuring optimal oil recovery from the existing nine wells, whilst also continuing to identify and work up other in or near field opportunities that could potentially add further oil volumes.

Stable production at Block CI-11

Full year 2010 production at Block CI-11 was approximately 5,088 boepd, comprising an oil rate of 1,086 bopd and natural gas rate of 23.2 mmcfd. A wireline workover programme to remove wellbore wax build up and obtain down hole pressure data was also completed. A detailed reservoir simulation model has also been constructed and history matched, with model iterations and updates using the newly acquired data undertaken and ongoing in order to enable evaluation of the impact of potential new infill wells and/or pressure maintenance on field productivity.

The outcome of this work is that a number of potential new reservoirs have been defined in addition to infill drilling opportunities in existing reservoirs. We are also focused on ways to best address low recovery factors in some field reservoirs via sidetracks of current wells. Furthermore, we are also looking at pressure maintenance via water injection as a means of enhancing the productivity of current production wells.

2011 outlook

Production has continued uninterrupted in 2011 to date, notwithstanding the recent political situation in Côte d'Ivoire and the EU sanctions regime. However, Afren and its partners are aware of disruption to other parts of the economic and financial system and are continuing to monitor events closely. 2011 will see a continuation of the detailed geoscience work undertaken in 2010 in order to firm-up a work programme that will potentially increase the reserve base and production levels at CI-11.

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 mmscfd and strips gasoline and butane from the rich gas stream it receives. The butane is sold into the local market (meeting approximately 35% of the domestic butane demand) and gasoline is spiked into the CI-11 crude stream and sold on the international market. The plant benefits from tax-exempt status and the average NGL production at the LGP in 2010 was 721 boepd. We are also exploring ways to extract propane at the plant, which we would sell locally to industrial customers.

Review of Operations

Appraisal and development

Replicating our success at Ebok

Having achieved a 100% appraisal drilling success rate and more than quadrupling reserves at the Ebok field, we were quick to recognise the potential of the surrounding area and secure interests in the Okwok oil field and surrounding OML 115 acreage. We have been able to deploy the subsurface knowledge gained from work on the Ebok field to identify Okwok as a high-potential opportunity. There are many similarities between the two fields. The same reservoirs are present in both fields, as is the relationship of seismic amplitude to reservoir and hydrocarbon distribution. Consequently, we believe there are larger in-place oil volumes than have been previously and independently quoted. Additionally, we have also identified significant potential in the deeper formations at Okwok.

Commercial viability established

The Okwok-9 appraisal well was spudded during August 2010, and reached a total measured depth of 8,083 ft. The well was completed over a 35 ft interval of good quality D2 reservoir with average porosity of 30%, and flowed 31° API crude oil. The well was flowed for 48 hours and shut in for a 54 hour build-up. The final build-up pressure was equal to the initial reservoir pressure, very encouragingly indicating no depletion. The 48 hour flow test was designed to establish a connected reservoir volume, and also to quantify reservoir permeability and heterogeneity.

Analysis of the log and test data acquired from the Okwok-9 well, and together with the seismic data, indicated that the primary objective of establishing the minimum economic field size in order to commercially develop the Okwok field, estimated by management at 25 million barrels, was fulfilled. Furthermore, information obtained from the well is consistent with, and supports, our subsurface model for the field. The results suggest that well productivity under a development completion scenario from a horizontal well would be consistent with production rates typically expected in the area of between 2,000 bopd to 4,000 bopd per well. Work is now focused on defining the next steps in the ongoing evaluation of the field, and in particular working up conceptual development solutions that may include standalone options and also development as a satellite to the nearby Ebok field.

2011 outlook

Having established the field as a commercial development project, with NSAI ascribing 51.8 mmbbls of gross recoverable resources to the field, we are now focusing efforts on defining the precise requirements and optimal development concepts that could be utilised. These include development as a satellite tie back to the central Ebok MOPU and FSO, or alternatively installation of a separate dedicated production processing facility with shared usage of the Ebok FSO. In order to assist with this process we plan to drill an additional appraisal well at the field in 2011 and acquire new 3D seismic over the area.

High grade exposure to west Africa's prolific Upper Cretaceous systems

CI-01 has a proven petroleum system in multiple reservoirs within the Cretaceous. Oil and gas has 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 originally 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.

The block borders the maritime boundary with Ghana, and lies adjacent to the major Jubilee and Tweneboa oil and gas discoveries that have been made in recent years. We have applied the latest understanding of the Cretaceous depositional systems to the existing well and seismic dataset to redefine the distribution of oil and gas in Kudu and Ibex, as well as other accumulations on the block. Consequently, we believe that the discoveries made to date on the block have the potential to be significantly larger than originally mapped.

2011 outlook

We are carrying out detailed subsurface work and have defined multiple prospects and leads as we aim to establish the optimal location for a well to test the new Cretaceous interpretation. We are also looking at acquiring more 3D seismic over the block. In addition, we are evaluating other techniques such as electromagnetic surveying to aid our understanding of these complex depositional systems. In order to expedite the appraisal and development of the block in the most efficient way we are also investigating joint development opportunities with the operators of adjacent acreage.

Review of Operations

Exploration - Sub Saharan Africa

We have assembled a balanced portfolio of exploration assets that provide a mix of exploration options across multiple-play types and basins. We are active in some of Sub Saharan Africa's most high profile exploration hot spots; from the Upper Cretaceous plays along the West African Transform Margin, the prolific Tertiary systems of the Niger Delta to the East African rift and coastal basins - each area has proved working hydrocarbon systems in place and has the potential to yield large scale discoveries that could add materially to our proved reserves base.

In January 2010, we announced the signing of a joint venture agreement with Oriental Energy Resources to jointly explore, appraise and develop OML 115. The block surrounds the Ebok and Okwok development area, which we also operate with Oriental, and is close to the giant Zafiro Complex in Equatorial Guinea.

It offers us an attractive opportunity to further capitalise on our extensive knowledge of the area gained to date, and explore 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, and at the same time will be able to benefit from cost synergies, lowering the economic threshold for new barrels in the area.

2011 outlook

We will drill an exploration well on the south western part of OML 115 during 2011, targeting the estimated 60 mmbbls Ufon prospect.

OPL 310 is located in the Upper Cretacous fairway that runs along the West African Transform margin and lies next to the Chevron-operated Aje field, which has recently been declared commercial. The block extends from the shallow water continental shelf to deep water, representing an exploration opportunity in an under explored basin with a proven working hydrocarbon system - in line with our strategy. It is also in close proximity to the recently completed West African Gas Pipeline (WAGP), allowing 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.

Prospective acreage with the potential for large discoveries

Encouragingly, OPL 310 contains several identified prospects. These lie in the same Cenonian, Turonian and Albian sandstone intervals that have yielded significant discoveries along the West African Transform Margin in Ghana and Cote d'Ivoire. The trapping configurations are four-way dip closed structures over basement highs. These have the same characteristics as the Seme, Atacora and Alibori discoveries in neighbouring Benin.

So far work has focused on defining the potential of the area covered by 3D seismic data. The key to our understanding of this is the seismic velocity model used to interpret the depth domain. We have reprocessed the existing seismic data to Prestack Depth Migration (PSDM) format also carried out an Electro-Magnetic (EM) seabed survey over a number of leads identified during the first phase of interpretation work. The EM survey has reduced the exploration risk associated with the opportunities we have already defined. This process was successful in the adjacent block over the Aje field and has been used in many other areas in Nigeria.

2011 outlook

Having undertaken a significant amount of data acquisition and interpretation work, we are in the process of seeking an industry partner to participate in future exploration drilling on the block. It is possible that we will seek to acquire additional seismic data in 2011 ahead of drilling one exploration well.

Having acquired the original seismic tapes and reprocessed the data, we continue to evaluate the potential of the blocks. We are working on the identification of areas for future seismic acquisition that could ultimately lead to future exploration drilling.

In July 2010, Total announced it had agreed to acquire Chevron's 45.9% interest in Block 1. Total now operates the block that extends over an area of 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.

2011 outlook

The new operator 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 2011.

Prime acreage in an exciting exploration fairway

The Keta Block is 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.

Giant field potential - prospectivity upgraded and drilling carry secured

During 2010 we continued with in-depth subsurface studies to further evolve our understanding of the broader prospectivity that the block has to offer. Through this process we identified several large scale prospects in the same Turonian intervals that have proved to be prolific hydrocarbon reservoirs in the eastern offshore zones. As a result of this, NSAI has more than doubled its independent view of gross unrisked prospective resources on the block to 1,412 mmboe.

In March 2011, oil major ENI agreed to farm in to a 35% participating interest in the block. The farm down is subject to customary government and partner approvals. Following such approvals, Afren will retain a 35% participating interest and transfer operatorship to ENI. In consideration for the assignment of the farm out interest, ENI has agreed to carry Afren's share of costs associated with drilling one exploration well during the current exploration period. Afren will also receive non drilling back costs and a carry through a 3D seismic acquisition programme that forms part of the obligation for the next licence phase. ENI is an experienced deep water operator, has an established presence in Ghana where it is already actively engaged in exploration activities and has a drilling unit available that could spud an exploration well on the Keta Block as early as the third quarter of this year. Not only is ENI's participation a strong endorsement of the prospectivity, further demonstrated by NSAI's independent assessment, but we now have in place an ideal partnership to unlock the substantial potential that exists on the block.

2011 outlook

The current exploration period carries the drilling commitment of one exploration well, which the partners intend to drill in 2011.

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.

2011 outlook

The partners are defining a forward work programme having recently entered the next exploration phase on the block.

Block 2B is located in the Orange River Basin, 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 metres. 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.

2011 outlook

The partners near term work programme involves the acquisition of 350 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 2012.

Review of Operations

Exploration - Afren East Africa Exploration

Our portfolio of 13 East African assets cover an extensive surface area of 135,880 km2 on a gross basis, and are all located in basins with strong evidence of working hydrocarbon systems being present. Afren East Africa Exploration is focused on Cretaceous, Jurassic and Tertiary rift basins which are geological settings that have yielded significant discoveries in Uganda, Sudan, Tanzania, Madagascar, Ghana, Nigeria, Angola, Sierra Leone and Brazil. 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.

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. Afren operates the block with a 50% working interest.

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 well Tarbaj-1 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.

2011 outlook

The partners have defined an active work programme that involves the acquisition of up to 1,200 km of 2D seismic data in addition to airborne gravity and magnetic data in 2011. Several major structures have already been mapped on the block that currently has 850 km of 2D seismic coverage, ahead of planned exploration drilling in 2012.

* Source: Gaffney Cline

Block 10A is located in the Anza Basin onshore northern Kenya, which is part of 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 is 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.

2011 outlook

The Tullow Oil operated joint venture will acquire 750 km of 2D seismic over the block during the first quarter of 2011 to supplement the existing 2D coverage of 2,631 km. This work will satisfy seismic obligations for the current exploration period, which also carries a one well commitment (drilling expected in 2012).

The Block L17/L18 area is located in the Lamu Coastal Basin, offshore south east Kenya. The individual blocks L17 and L18 cover an area of approximately 1,275 and 3,630 km2 respectively and are situated in water depths varying from a few meters along the shoreline up to around 500 metres.

There are several potential source rocks for the Cretaceous plays in the southern areas of the basin including the Permo-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 Block L17/L18 are most likely oil bearing. The main reservoir targets are in the Upper Cretaceous although there may be additional potential in clastic reservoirs within the Tertiary. The hydrocarbons are expected to have been generated in the deep Pemba trough south of Block L18.

2011 outlook

A programme of 400 km short offset shallow marine 2D seismic data was acquired in the Shimoni area of Block L18 and in the Mombasa area of Block L17 during 2010. The new data are of a high quality and are presently being interpreted. A number of prospects and leads have been identified elsewhere on the block that represent attractive exploration targets, the main focus being targets in the Upper Cretaceous with additional potential also in clastic Tertiary sequences. We expect to acquire additional 2D seismic over some parts of the blocks in 2011 and drill one exploration well commencing late 2011/early 2012.

* Source: McDaniels

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 southern area of 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.

2011 outlook

An environmental impact assessment (EIA) has been submitted to the Malagasy authorities in preparation for exploration drilling on Block 1101 during 2011. As part of the work commitments associated with the current exploration phase, the partners have carried out interpretation work on the existing 200 km seismic data set acquired in 2008, field mapping, geochemical surveys and analysis.

* Source: Gaffney Cline

Blocks 2, 6, 7 and 8 are located in the Ogaden Basin, onshore south west Ethiopia. Blocks 2 and 6 are part of the same production sharing contract which encompasses a combined area of 24,420 km2. Blocks 7 and 8 are part of a separate 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 kilometers to the east of Block 6. Exploration continued throughout the 1980s. Three wells have been drilled within the blocks: El Kuran-1, El Kuran-2 and Bodle-1. 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.

2011 outlook

Seismic acquisition was completed across the onshore Blocks 2,6,7 and 8 in 2010. During the current exploration period, the partners have obtained 15,000 km of airborne gravity and magnetic data, 551 km of 2D seismic data and are required to drill one exploration well. Work is ongoing to further interpret the prospectivity of the block ahead of expected drilling in 2012.

Areas A, B and C are located in the Seychelles micro-continent covering a combined area of approximately 14,964 km2. Areas A and B are located in mainly shallow 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. The Karoo formation contains both the source rock and the reservoir. Other potential reservoirs in Jurassic clastic sediments may also exist. During the period 1980 to 1981 three exploration wells were drilled, all of which encountered oil shows and confirmed the presence of a working hydrocarbon system.

2011 outlook

The partners fulfilled early work obligations with the acquisition of 3,637 km long offset seismic in 2007, and in 2009 a further 1,271 km of 2D seismic was acquired. This new data revealed the presence of several large scale structures in all three licence areas, in addition to new basins that could also contain significant Jurassic sedimentary sections. The partners intend to acquire new seismic data in 2011 over Blocks A, B and C, ahead of planned exploration drilling in 2012. A one year licence extension has been granted to assist in the completion of this work programme.

The Tanga block lies mainly offshore north east Tanzania in coastal to shallow marine waters, directly south of and adjoining Kenyan blocks L/17 and L/18 in which Afren holds a 74% interest. The block is covered by 200 km of legacy 2D seismic data, and 1,200 km of good quality new 2D seismic data. The Tanga block is well located in that it lies across a deep basin with a very thick sedimentary section that has the potential of hosting several source rock intervals and multiple reservoir/seal pairings. Petroleum plays recognised to date are Lower Cretaceous sands deposited in deltaic to shallow marine environments, Upper Cretaceous submarine fans, Eocene shelf sands and Miocene fluvial and deltaic sands. There are structures, chiefly fault blocks, particularly along the western side of the basin, which are interpreted to form viable traps. Some of these lie in shallow water and could present relatively inexpensive drilling targets. The Tanga block is also a possible source of charge into the southern parts of the adjacent Kenya block L/18. Oil seeps and shows encountered in previous wells drilled on the nearby Pemba Island attest to the oil potential of the block and surrounding area.

2011 outlook

The partners plan to acquire 900 km of 2D seismic over the offshore parts of the block and possibly geochemical work and non-seismic surveying over the onshore areas of the block, after which the partners intend to proceed with the drilling of an exploration well in 2011.

Financial Review

In January 2011 Afren became the first UK exploration and production Company to go to the bond market and raise a substantial amount of capital. This bond issue brings a significant change in the capital structure of Afren, the proceeds of the bond allowing the Company to repay its shorter term facilities. Taken with the positive cashflow from existing operations and the reserve base lending facility for the development of the Ebok field there are considerable financial resources at the Company's disposal.

1. Result for the year

Revenues

Revenue for 2010 was US$319.4 million, a reduction of 5% from 2009. The decrease in revenue arises from the reduced economic interest on the Okoro field offset largely by the effect of higher oil prices. Economic interest production for the year fell to 14,333 boepd from 22,064 boepd in 2009. The fall in economic interest production also arises mainly as a result of reaching payback on the Okoro field which, as expected, saw our interest reduced from 95% to 50% in mid 2010.

The Company realised in 2010 an average oil price of US$79.7/bbl and an average gas price of US$5.7/mcf (2009: US$59.3/bbl and US$5.1/mcf). The average price for Brent in the period was US$79.5/bbl.

Gross profit

Gross profit for the year was US$129.0 million, an increase of 22% on the prior year (2009: US$105.8 million). The DD&A charge for oil and gas assets in 2010 was US$90.5 million, a reduction of 41% on the prior year (2009: US$152.2 million). The reduction was largely due to our lower economic interest production. The reduction in crude oil stock at the year end resulted in a charge for stock adjustment of US$9.5 million, compared with a credit of US$12.8 million in 2009.

Profit for the year

Profit after tax on continuing activities for the year ended 31 December 2010 was US$45.9 million (2009: loss US$16.8 million). Normalised profit after tax, which excludes the effect of unrealised hedge movements and share related charges, was US$63.8 million, see note 9 to the financial statements for a full reconciliation of this figure (2009: US$50.7 million). This is the first full year profit after tax in the history of Afren and an important milestone for the Company.

Impairment charge on oil and gas assets was US$1.6 million (2009: credit US$0.9 million) reflecting residual costs on the La Noumbi licence in Congo arising from the unsucessful Tie-Tie well drilled in 2009. The low level of impairment reflects the ongoing success of the Group's exploration and appraisal programme.

Finance costs for 2010 were US$11.3 million (2009: US$37.0 million). The costs in 2010 were reduced because the Group capitalised US$13.6 million of charges as part of the Ebok project financing (2009: US$1.8 million). Overall charges were also reduced because of the lower overall debt in the period, reflecting the paying down of the debt raised for the development of the Okoro field and the acquisition of the assets in Côte d'Ivoire.

During the year professional fees of US$3.9 million were expensed in connection with the acquisition of Black Marlin Energy Holdings Limited. Following changes to IFRS3, which took effect during the year, professional fees incurred in respect of acquisitions can no longer be capitalised.

During the year we recognised a loss from derivative financial instruments of US$8.9 million (2009: US$33.6 million) relating to crude oil hedging contracts. This reflects a small realised loss of US$2.4 million (2009: US$11.4 million gain) as the oil price realised averaged just above the hedged price during the year. There was a further mark to market loss of US$6.5 million (2009: loss of US$45 million) on the unrealised positions due to further strengthening in the oil price from around US$80 per barrel at the start of the year to over US$90 per barrel at year end.

Taxes paid in the year

The income tax charge for the year is US$32.9 million (2009: US$17.3 million). The increase reflects the increased profitability of the Company in 2010. Of this, US$0.9 million has been paid locally in Nigeria in respect of production on Okoro. The balance of current tax will be paid in 2011 with the deferred tax liability spread over the life of the field.

In addition, the Company pays other taxes in the form of royalties, withholding taxes, and non recoverable VAT locally in Africa. In 2010 these amounted to US$83.2 million (2009: US$72.5 million) - as a percentage of revenue this represents 26%.

2. Financing the Company's activities

Net cash generated from operating activities in 2010 was US$209.3 million (2009: US$278.3 million), and this cash has been used primarily to fund the Company's exploration and appraisal activities.

In March 2010, the Group secured a reserve based lending facility of up to US$450 million to fund ongoing development of the Ebok, Okwok and OML 115 area. To date we have commitments on this facility of US$250 million of which US$107 million had been drawn at 31 December 2010.

In November we refinanced the Okoro facility with a new reserve based lending facility of up to US$80 million to fund the drilling of two infill wells on the field and repay the original facility used to develop the Okoro field.

Gross debt as at 31 December 2010 was US$284.7 million (2009: US$281.1 million), largely comprising US$107 million and US$71 million in respect of Ebok and Côte d'Ivoire respectively.

Loan repayments in the year were US$111.0 million reflecting repayment in full of the Okoro facility and the facilities used to finance the Côte d'Ivoire acquisition and periodic payments due under other facilities. Cash at bank at 31 December 2010 was US$140.2 million, resulting in net debt of US$127.5 million (2009: net cash US$54.2 million).

3. Development, appraisal and exploration activities

The Company's investment in appraisal and exploration activities has continued during 2010, with expenditure of US$74.3 million (2009: US$67.3 million). The main areas of expenditure were on Okwok (US$34.8 million), electromagnetic survey and seismic reprocessing on OPL310 (US$13.5 million), the acquisition of OML115 (US$11.2 million) and expenditure, largely seismic, on the newly acquired Black Marlin exploration assets (US$4.0 million).

Development expenditure was US$362.8 million, comprising US$329.0 million on the Ebok field and US$33.8 million on the Okoro infill programme.

There has been minimal write off of unsuccessful exploration costs (2010: US$1.6 million, 2009: credit US$0.9 million).

4. Acquisitions in the year

In October 2010, the Company completed its acquisition of the share capital of Black Marlin Energy Holdings Limited (Black Marlin). Total consideration for the acquisition was US$140.3 million excluding costs and 76,776,096 ordinary shares in the capital of the Company were issued, allotted and credited as fully paid to the shareholders of Black Marlin as consideration. Subsequent to the acquisition, the Black Marlin Dubai office has been reduced in size and will close in the first half of 2011, with a cost of US$0.9 million including redundancy costs. In accordance with IFRS 3 Revised, professional fees incurred in respect of the acquisition (US$3.9 million) are not capitalised.

5. How we reward our personnel

All staff are eligible to participate in the company bonus scheme and the Company paid an average cash bonus to employees relating to 2010 of 28% of gross salary. During the year 4,425,000 new options were issued to personnel recruited or upon a significant promotion. The average strike price of the options was 107p (2009: 33,315,000 at an average strike price of 65p) representing in each case the market level at the time of issue. The options vest over three years if a target share price of 40% above the strike price has been achieved. In addition, an award of 4,895,609 shares was made under Afren's Performance Share Plan (PSP) to all eligible staff excluding directors (2009: 15,552,824, of which 3,865,953 were awarded to the directors). The number of shares awarded varied dependent on seniority and the amount that vest after three years depends on total shareholder return when compared with our peers.

6. Our commitments

The Company has operating and capital commitments as at 31 December 2010 of US$482.6 million (2009: US$258.9 million), largely in respect of the ongoing development of Ebok, and the infill well programme on Okoro and operations on the Okoro field.

In 2011 the Group will recognise a liability as a finance lease in respect of the arrangements with Mercator Offshore Nigeria (Pte) Limited for the production facilities on the Ebok field. This will result in the recognition of a finance lease liability of approximately US$163.0 million to be settled in monthly payments of approximately US$2.4 million. These amounts are included in the capital commitments figures stated above.

7. Bond issue to fund future growth

In January 2011, the Company completed a Bond issue, initially raising US$450 million with a subsequent tap issue on 16 February raising an additional US$50 million. The coupon on the bonds is 11.5% and they are listed on the Luxembourg Stock Exchange.

The bonds are secured with a first-ranking security interest over substantially all of the Company's assets related to the Okoro field, and a second-ranking security interest over substantially all of the Company's assets related to the Ebok field.

The Company used part of the funds to repay borrowings amounting to US$169 million (net of issue costs) and accrued interest of US$2.4 million from the Okoro reserve based lending facility, the facilities used to acquire the Côte d'Ivoire assets and other outstanding facilities. The remaining funds raised by the bonds will be used to fund further development of the Group's assets and for acquisitions/other corporate purposes.

8. Review of our hedging arrangements

In the context of volatile oil prices and with the imminent first oil at Ebok, the Company reviewed its hedging arrangements. The Company previously had taken hedging positions associated with its operations in Okoro and Côte d'Ivoire. These arrangements were synthetic puts which allowed the Company to protect itself from the downside movements in prices while also benefiting from most of the upside. In early 2011 the Company purchased a number of put options. These options allow the Company to sell approximately 3 million barrels in the period to 31 December 2012 at a price of US$80/bbl. The average cost of the hedge is US$4/bbl giving effective protection to the Company at a price of US$76/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 will be taken to equity and the ineffective portion, as well as any change in time value, will be recognised in the income statement.

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

The policy of the Company is to protect its minimum cashflow 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.

9. Outlook

In 2011 the Company will carry out an extensive programme of exploration and development across its assets. With substantial increased cashflow from operations combined with its debt facilities and cash resources, the Company is well positioned to fund its next stage of growth and deliver value to shareholders.

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 2011.

The financial information for the year ended 31 December 2010 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 2009 have been delivered to the Registrar of Companies and those for 2010 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 accounting policies applied are consistent with those adopted and disclosed in the Group's financial statements for the year ended 31 December 2009, with the exception of the adoption of IFRS 3 (Revised) Business Combinations which applied prospectively from 1 January 2010.The adoption of the revised IFRS 3 continues to apply the acquisition method to business combinations but with some significant amendments to the measurement of goodwill and non-controlling interests and the treatment of transaction costs.

2. Profit/(Loss) per ordinary share

9.9 million potential ordinary shares are anti-dilutive and are therefore excluded from the weighted average number of ordinary shares for the purposes of diluted earnings per share in 2010. In 2009 all potential ordinary shares were anti-dilutive because of the loss in that year.

3. 2010 annual report and accounts

The Annual Report and Accounts will be mailed on 29 April 2011 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 Monday, 6 June 2011 at 11.00 am.

5. Operating Segments

For management purposes, the Group currently operates in four geographical markets: Nigeria, Côte d'Ivoire, Other West Africa and Eastern Africa. Unallocated operating expenses, assets and liabilities relate to the general management, financing and administration of the Group.

Operating Segments continued

Included in revenues for Nigeria for the year ended 31 December 2010 are US$286.5 million (2009: US$292.1 million) which arose from the Group's largest customer.

Non-current assets held in the UK at 31 December 2010 totalled US$2.4 million (2009: US$3.3 million). Non-current assets held in Other West Africa at 31 December 2010 included US$20.3 million (2009: US$16.0 million) relating to Keta Block, Ghana, US$30.1 million (2009: US$29.2 million) relating to La Noumbi permit in Congo (Brazzaville) and US$18.1 million (2009: US$17.6 million) relating to JDZ Block One in São Tomé & Príncipe. Non-current assets held in East Africa at 31 December 2010 included US$62.1 million (2009: US$nil) related to Block L17/L18, Block 1 and Block 10A in Kenya, US$58.4 million (2009: US$nil relating to the Ethiopian Blocks 2&6 and 7&8). US$35.6 million (2009: US$nil) related to the Madsgascar Block 1101 and US$36.2 million (2009: US$nil) relating to Seychelles Block A,B,C.

6. Taxation

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

The Group's tax charge for the year includes current and deferred tax in Nigeria of US$18.5 million (2009:US$0.8 million) and US$11.2 million (2009:US$12.5 million) respectively. The detailed mechanics of the Group's tax filing arrangements in Nigeria are subject to agreement with the local tax authorities and while the Group is satisfied that the 2010 and 2009 charge is its best estimate of its tax position, adjustments may be required once these discussions have been finalised.

7. Acquisition of subsidiaries

On 7 October 2010, the Company completed the acquisition of Black Marlin Energy Holdings Limited (Black Marlin) having received all necessary approvals. The acquisition comprised exploration acreage covering 12 assets in Kenya, Madagascar, Ethiopia and Seychelles. Afren issued 76,776,096 ordinary shares to holders of Black Marlin shares in return for 100% of the issued share capital. Afren's closing share price on completion was 114.5 pence. In addition, 1 million outstanding options to acquire Black Marlin shares were converted to acquire Afren shares on substantially equivalent terms and conditions.

The book values of identifiable assets and liabilities acquired and their provisional fair value to the Group is as follows:

* Non-cash consideration relates to shares and options issued as described above.

Technical evaluation and assessment of the oil and gas assets acquired is ongoing and therefore the fair values assigned are provisional pending the completion of the evaluation.

The acquired business recorded a loss after taxation of US$30.8 million in the year ended 31 December 2010 of which US$29.4 million was made during the period from the beginning of the year to the acquisition date and a US$1.4 million loss was recorded after acquisition, which included US$0.6 million attributable to discontinued operations. The revenue for the year ended 31 December 2010 was US$7.1 million of which US$6.6 million arose from the discontinued operations.

Acquisition related costs amounting to US$3.9 million have been recognised as an expense in the current year and are included in administrative expenses in the consolidated income statement.

If the acquistion had completed on 1 January 2010, the total Group revenues would have been US$324.7 million of which US$319.5 million is from continuing activities. The total Group profit for the year would have been US$14.9 million and that from continuing activities US$28.6 million. This proforma information is for illustrative purposes only and is not necessarily an indication of the revenues and results of the Group that actually would have been achieved had the acquisition been completed on 1 January 2010, nor is it intended to be a projection of future results.

8. Share capital and share premium

Share premium figure is shown net of issue costs of US$2.4 million (2009: US$14.2 million).

** Non-cash shares issued were primarily in respect of the Black Marlin acquisition described in note 7.

9. Reconciliation of Normalised Profit

* Excludes realised losses on derivative financial instruments of US$2.4 million (2009: US$11.4 million gain).

Normalised profit after tax is a non-IFRS measure of financial performance of the Company, which in management's view more accurately reflects the Company's underlying financial performance. This may not be comparable to similarly titled measures reported by other companies.

On 27 January 2011, Afren announced the successful pricing of its offering of U$$450 million aggregate principal amount of its 11.5% senior secured notes due 2016 (the Notes). The Notes will be guaranteed on a senior basis by certain subsidiaries of Afren plc and on a subordinate basis by Afren Resources Limited. Interest will be paid semi-annually. Part of the proceeds of the offering were used to settle borrowings amounting to US$169 million (net of issue costs) and accrued interest of US$2.4 million recorded in the balance sheet as at 31 December 2010.

On 11 February 2011, Afren announced offering of an additional US$50 million of its 11.5% senior secured notes due 2016.

On 24 March 2011, Afren announced acquisition of a 74% operated interest in Tanga block, located onshore and offshore Tanzania, from Petrodel Resources Limited (''Petrodel''). Afren reimbursed Petrodel a percentage of back costs (US$2.8 million) in relation to the block, and will fund costs of seismic survey and supported by the seismic, carry Petrodel through the drilling of one shallow water exploration well subject to a cumulative cap on gross costs of US$40 million.

In 2011 to date the political situation in Côte d'Ivoire deteriorated significantly which also resulted in disruption to the local financial system. At 31 December 2010, Afren had no material financial assets that were exposed, and its production assets have continued in operation without interruption to date. Afren is monitoring the situation closely, including the impact of the sanctions regime, imposed by the EU.